Battery storage projects are taking off in the US, with a substantial leap expected in the coming years, as the country could triple its utility-scale battery storage power operating capacity by 2023.

According to an update from the US Energy Information Administration, 1623 MW of new utility-scale battery storage capacity is set to come online by 2023, up from a current total of 899 MW. Total capacity is expected to be around 2.5 GW of utility-scale battery storage by that year, nearly tripling the current capacity.

Considering other battery projects that may be currently unreported, or projects that may still be introduced and come online during that timeframe, it’s easy to see how storage could go beyond 3x the current capacity.

Utility-scale battery storage power capacity more than quadrupled from the end of 2014 (214 MW) through March 2019 (899 MW), so a similar rise through 2023 shouldn’t come as a surprise.

Renewable energy and battery costs are both falling — the EIA notes “pairing utility-scale battery storage with intermittent renewable resources, such as wind and solar, has become increasingly competitive compared with traditional generation options” — and the adminstration also points to agreeable state policies and a Federal Energy Regulatory Commission order as major factors in the rise.

The two largest operating utility-scale battery storage sites at the moment both provide 40 MW of power capacity, though a number of much larger projects are set to come online in the next few years, including the Manatee Energy Storage Center in Florida, which should open in 2021.

While the EIA says FPL’s 409 MW/900 MWh Manatee center will be the largest battery in the US — and the world — there’s going to be plenty of competition for that title. For instance, the Gemini Solar Project in Nevada is awaiting approval, and that 531 MW/2125 MWh battery system would top Florida’s effort.

California, Illinois, and Texas alone make up nearly half of the total installed battery storage in the US thus far. The EIA revealed the top ten states in utility-scale storage, and a few others may come as a surprise:

It can be hard to keep up with the steady drumbeat of energy storage policy updates emanating from the Northeast, and New York in particular, but last week’s announcement of $55 million allocated for Long Island deserves a second look.

The specifics of the incentive — $250 per kilowatt-hour for residential storage or commercial systems up to 5 megawatts — parallel similar opportunities offered to customers elsewhere in New York as part of a $280 million package launched in April. The earlier tranche was funded by a systems benefit charge that Long Islanders don’t pay; instead, their storage dollars are coming from the Regional Greenhouse Gas Initiative.

Besides a separate funding structure, Long Island’s geography and grid infrastructure make it a valuable test case for energy storage, as part of Gov. Andrew Cuomo’s ambitious decarbonization program.

“Long Island strikes me as one of the best and earliest locations to reach a completely carbon-free grid, given its solar, storage and offshore wind capabilities,” said Jason Doling, assistant director for distributed energy resources at the New York State Energy Research and Development Agency.

NYSERDA hopes to disburse the storage funds in the next three to five years, with the goal of establishing a local installer base and a sustainable and growing market by the end of that period.

Island limits create storage opportunities
The water separating Long Island from the mainland imposes obvious constraints on delivering electricity to a population that totaled 7.5 million as of the last census. Summer tourism season brings extra stress, regularly forcing the Long Island Power Authority, which owns the grid infrastructure, to truck in portable diesel generators to meet demand.

Storage can defer distribution upgrades, ensuring power supply during peak hours in place of more capital-intensive investments. LIPA tested out this vision when it powered up a 5-megawatt/40-megawatt-hour battery last summer at a substation in East Hampton.

Separately, Cuomo’s administration has developed more stringent nitrogen oxide emissions regulations to target the worst-polluting peaker plants. Plants have until mid-2020 to come into compliance. Emissions reductions are possible by replacing fossil-fueled generators with storage, or adding storage to hybridize the plant.

This month, officials in Los Angeles, California, are expected to approve a deal that would make solar power cheaper than ever while also addressing its chief flaw: It works only when the sun shines. The deal calls for a huge solar farm backed up by one of the world’s largest batteries. It would provide 7% of the city’s electricity beginning in 2023 at a cost of 1.997 cents per kilowatt hour (kWh) for the solar power and 1.3 cents per kWh for the battery. That’s cheaper than any power generated with fossil fuel.

“Goodnight #naturalgas, goodnight #coal, goodnight #nuclear,” Mark Jacobson, an atmospheric scientist at Stanford University in Palo Alto, California, tweeted after news of the deal surfaced late last month. “Because of growing economies of scale, prices for renewables and batteries keep coming down,” adds Jacobson, who has advised countries around the world on how to shift to 100% renewable electricity. As if on cue, last week a major U.S. coal company—West Virginia–based Revelation Energy LLC—filed for bankruptcy, the second in as many weeks.

The new solar plus storage effort will be built in Kern County in California by 8minute Solar Energy. The project is expected to create a 400-megawatt solar array, generating roughly 876,000 megawatt hours (MWh) of electricity annually, enough to power more than 65,000 homes during daylight hours. Its 800-MWh battery will store electricity for after the sun sets, reducing the need for natural gas–fired generators.

Precipitous price declines have already driven a shift toward renewables backed by battery storage. In March, an analysis of more than 7000 global storage projects by Bloomberg New Energy Finance reported that the cost of utility-scale lithium-ion batteries had fallen by 76% since 2012, and by 35% in just the past 18 months, to $187 per MWh. Another market watch firm, Navigant, predicts a further halving by 2030, to a price well below what 8minute has committed to.

Large-scale battery storage generally relies on lithium-ion batteries—scaled-up versions of the devices that power laptops and most electric vehicles. But Jane Long, an engineer and energy policy expert who recently retired from Lawrence Livermore National Laboratory in California, says batteries are only part of the energy storage answer, because they typically provide power for only a few hours. “You also need to manage for long periods of cloudy weather, or winter conditions,” she says.

Local commitments to switch to 100% renewables are also propelling the rush toward grid-scale batteries. By Jacobson’s count, 54 countries and eight U.S. states have required a transition to 100% renewable electricity. In 2010, California passed a mandate that the state’s utilities install electricity storage equivalent to 2% of their peak electricity demand by 2024.

Although the Los Angeles project may seem cheap, the costs of a fully renewable–powered grid would add up. Last month, the energy research firm Wood Mackenzie estimated the cost to decarbonize the U.S. grid alone would be $4.5 trillion, about half of which would go to installing 900 billion watts, or 900 gigawatts (GW), of batteries and other energy storage technologies. (Today, the world’s battery storage capacity is just 5.5 GW.) But as other cities follow the example of Los Angeles, that figure is sure to fall.

While software has been described by many as the single most important aspect of how an energy network integrates, manages and then uses energy storage, two industry heavyweights have said that selling software licensing alone was not a viable business model for them.

Rolling out the controls and management software by itself is a perilous business proposition, according to Karim Wazni, MD of Aggreko Microgrids and Storage (formerly Younicos until it was bought out and became part of rental energy solutions group Aggreko).

Having deployed 220MW of battery storage projects worldwide to date across nearly 50 projects, many of which it worked on as a full system integrator including hardware and software provision, Aggreko M&SS-Younicos had found that the value of the software alone could not be divorced from the overall aims of the project.

“It’s [software is] only valuable if you can package it in a system that delivers benefits that the customer can measure. I think it’s been challenging to prove a profitable business model based on software licensing,” Wazni said.

“So, it’s through the realisation of these benefits in a service model that we actually leverage the value of this software, so we’ve ported, we’ve included the software coming from Younicos and we’ve integrated [it] into our overall power management system, so we can then realise the benefits of the combination of thermal, storage and solar.”

Value is in the integrated offering
Andy Tang of the executive team at Greensmith Energy, also the target of a recent successful takeover bid by Wärtsilä, told Energy-Storage.news that he and his team also did not believe “that in this industry, there’s a strong case for a software-only business model”.

Policy in the Commonwealth of Massachusetts favouring the use of clean energy during peak times has brought behind-the-meter energy storage company Stem Inc into the state’s utility-scale solar-plus-storage market.

The commercial and industrial (C&I) system provider has partnered with private equity firm Syncarpha Capital Partnership to develop 28.2MWh of large-scale energy storage projects, co-located with solar PV in the US state.

Stem, which touts AI-driven software platforms aggregating commercial and industrial (C&I) energy storage systems into virtual power plants among its strengths, had met with Energy-Storage.news last September to discuss its wider launch into the solar-plus-storage space. At the time, that had been mostly limited to the Arizona market with earlier projects built in Hawaii, with the announcement this week its first real foray into the front-of-meter.

Thus far, the company is known for delivering energy cost savings to C&I customers by reducing their amount of energy drawn from the grid at peak times, while also using the capabilities of those systems in interconnected networks. The company was profiled in a piece co-written by Energy-Storage.news’ Andy Colthorpe and IHS Markit analyst Julian Jansen for PV Tech Power along with the likes of Green Charge Networks (now Engie Storage) and AMS.

The 28.2MWh of storage systems will be deployed across five distribution grid-connected sites totalling 26MW of solar PV that Syncarpha Capital is developing and will own once complete. They will comply with both federal tax credit and state SMART (Solar Massachusetts Renewable Target) criteria for eligibility and will participate in New England ISO wholesale markets, all using Stem’s AI software platform, Athena. The partners also expect other revenue opportunities, retail and wholesale, to open up for other services via regulators that the systems could tap into.

Massachusetts policy has opened up to energy storage since introducing 200MW and then 1GW deployment targets by 2025 and standards for using renewable and low carbon energy during peak times. Albeit the standards have been set at a low benchmark to begin with, which dismayed some, it the ‘clean peak’ has nonetheless been described as a ‘historic’ policy standard. In June, Energy-Storage.news reported that NEC had switched on a 3MW / 5MWh system which stores energy to be outputted at times of peak network demand in the local area for utility Ashburnham Municipal Light Plant (AMLP).

The U.S. Department of Energy (DOE) and members of Congress are looking at legislation concerning research and regulation of energy storage. Sen. Lisa Murkowski (R-Alaska), who chairs the Energy and Natural Resources committee, on July 9 said there is bipartisan interest in combining a handful of bills on energy storage, dealing with research and development (R&D) and funding, into one combined bill.

Bruce Walker, assistant secretary for the Office of Electricity, said the DOE supports a number of research efforts into storage, which Walker said could “revolutionize the energy industry.”

Murkowski at Tuesday’s committee hearing in Washington, D.C., said, “My goal, recognizing that we have five different bills out there, is to really evaluate where we are with them and synthesize the various bills and concepts, taking the best provisions that we have in each of them, combining them perhaps into a larger, more comprehensive energy storage package that we will be able to report out of the committee. I would hope we would be able to do that even possibly as early as the end of this month, or more likely in September. I’m optimistic about this space and what we can do.”

‘Holy Grail’
Deployments of energy storage are becoming part of states’ power portfolios, mostly due to storage’s capability to support intermittent renewable power sources such as solar and wind. Energy Secretary Rick Perry has called storage the “holy grail” of U.S. energy and has touted the technology’s ability to make the power grid more resilient.

Storage used in concert with wind and solar farms is just one area of growth. The DOE has said that as of a year ago, there was 23.6 GW of operational pumped-storage capacity in the U.S., accounting for 94% of the country’s energy storage, as storage continues to change the country’s power profile.

Mitsubishi Hitachi Power Systems and Magnum Development, which owns a large underground salt dome in Utah, in May said they have teamed to develop a massive project that could store up to 1,000 MW of renewable energy year-round and provide it to variability-challenged Western power markets. Florida Power & Light earlier this year announced plans to build the world’s largest battery storage system.

Arizona Public Service in February said it plans to add as much as 850 MW of battery storage capacity to its solar power plants by 2025.

Researchers Martin Rüdisüli, Sinan Teske, and Urs Elber of the Swiss Federal Laboratories for Materials Science and Technology (EMPA) have studied what will be needed to make Switzerland able to use only zero carbon energy. Among their main conclusions is that the country can produce more electricity than it needs from renewable sources in the summer but will need to import electricity from its more southerly neighbors in winter.

In a report published in the journal Energies, they used data provided by Swissgrid to determine the current demand for electricity in quarter-hour increments year round. They then posed the question, “How would demand change once most heating and transportation in Switzerland is electrified?” The answer they came up with is that demand will increase by approximately 13.7 terawatt-hours on an annual basis.

That figure further assumes that significant steps are taken to shift to electric vehicles where possible in the transportation sector and to improve the energy efficiency of existing residences and commercial structures. According to a report in Science Daily, the research assumes heating requirements of all buildings will first be reduced by around 42% through renovation measures and that 3/4 of the remaining heating requirements in houses and apartments will be achieved using electric heat pumps. It further assumes about 2/3 of all private car trips will be in electrically-powered automobiles.

The research focuses on five areas. First, replacing conventional furnaces with heat pumps. Second, because Switzerland proposes to end its use of nuclear power, each nuclear power plant must be replaced with about eight times the photovoltaic output. A nuclear plant delivers around 8,000 hours of electricity per year but a solar cell delivers only about 1,000 hours a year. As a result, solar panels will need to be installed on virtually all available surfaces.

Third, a dramatic increase in electrical storage capacity using all available technologies including batteries and pumped hydro as well as geothermal and technologies that convert electricity into chemical energy sources. Fourth, they recommend heat storage technologies so the use of heat pumps can be reduced as much as possible in winter.

Fourth, create seasonal heat storage facilities so that the electricity requirements of the heat pumps can be reduced in winter. Fifth, new HVDC transmission lines that will bring electrical power from sunnier southern countries to Switzerland in the winter when electrical demand is highest. A bright spot in the analysis for electric vehicle advocates is that EVs will not unbalance the grid as they can be charged when electricity is plentiful, assuming a proper charging infrastructure is created.

Although utility scale energy storage has been driven by state-run projects thus far in China, an evolution in the way ancillary grid services are rewarded will pave the way for exponential growth in storage capacity next year.

U.K. consultancy Wood Mackenzie has cited announcements by China’s National Energy Administration that compensation for grid balancing and other services offered by energy storage would change by next year.

The current flat payment system will, according to WoodMac, change “to a market integrated with spot energy prices by 2020” and that change, together with technology advances and cost reductions, will pave the way for China to supplant South Korea as the biggest energy storage market in the Asia Pacific region.

The consultant predicted the 489 MW/843 MWh of installed energy storage in China two years ago would rise to 12.5 GW/32.1 GWh in 2024.

WoodMac highlighted the role the state played in the deployment of energy storage last year with public utility the State Grid Corporation of China deploying 452 MWh of the 1.14 GWh/580 MW of capacity added, to account for 83% of the year’s utility scale storage growth. The state-run storage pilot projects concerned were backed by government research grants.

Grid services hold the key

At current cost levels and under the existing payment system for grid services, there is no business case for utility scale storage, particularly as far as solar project developers are concerned, with the state winding down public solar subsidies in a push for ‘grid parity’ PV.

With China last year reaching a cumulative 1.07 GW/1.98 GWh of energy storage – most of it ‘front of meter’, grid connected capacity, it is the grid services the tech offers that will drive its wider adoption.

WoodMac stated, in a press release yesterday, 60% of the grid ancillary service-targeted energy storage facilities deployed last year were standalone projects, 14% were installed alongside coal power plants and 19% were developed with solar or solar-wind hybrid power generation assets in Qinghai province to reduce curtailment of excess energy.

Private equity firm Energy Capital Partners has bought its way into the energy storage development business with Convergent Energy + Power, the companies announced Wednesday.

New York-based Convergent develops, owns and operates large-scale storage for industrial customers and utilities. It distinguished itself as a rare startup that chose to self-fund its projects, raising $70 million to do so. Convergent also took the title for largest commercial and industrial storage project, with a 10 megawatt/ 20 megawatt-hour system in Ontario, Canada.

Energy Capital Partners owns and invests in a wide portfolio of energy companies, including gas generator Calpine and residential solar company Sunnova, but this marks its first storage acquisition. The firm acquired Convergent as part of its multi-billion dollar Fund IV.

The companies declined to name the sale price, but noted that upfront acquisition payments and ongoing funding for projects will amount to several hundred million dollars of investment. Convergent will put that capital to work in what CEO Johannes Rittershausen calls a “storage IPP,” self-financing projects for customers and owning them for the long haul.

“The model we have now, moving forward with ECP, is much more efficient, and we can offer better value propositions,” Rittershausen said. “Funding is of no issue to us.”

From the buyer’s perspective, Convergent stood out for its track record of operating projects and customer relationships, said ECP principal Andrew Gilbert.

“We’ve been pitched on pipelines, but Johannes and team have actually executed,” Gilbert said. “Convergent delivers real savings to customers almost immediately, in material ways. The returns are quite attractive compared to other things we see in renewables or storage.”

Notably, both parties expressed wariness about competing in the major utility-scale procurements, where big players like NextEra and First Solar compete on tight margins for massive projects. They described that market as more commoditized than the middle ground where Convergent operates, which is bigger than the typical commercial project, but still driven by private customer needs.

That’s not a particularly crowded field right now, and Convergent’s self-funded model differentiates it from the competition. Venture-backed developers typically hand off their projects to project financing funds to own.