Energy storage is increasingly being included in utilities’ chief planning tool: the integrated resource plans (IRP). That inclusion is a sign that utilities are beginning to see the value and benefits that energy storage brings.

“Utilities are becoming more active players in the energy storage market,” Brett Simon, energy storage analyst at GTM Research, told Utility Dive in an email.

A significant number of utilities now include energy storage in their IRPs, including Arizona Public Service, Tucson Electric Power, Florida Power and Light and Puget Sound Energy.

PG&E’s contract with EDF RE does not come as a surprise, Simon said. Like California’s other two investor owned utilities, PG&E is required to procure energy storage under AB 2514 that was passed in 2010.

Some foreign utilities have also shown an increased interest in the storage market over the last 12 to 24 months, Simon says, citing ENGIE and Enel.

ENGIE North America and Holyoke Gas & Electric in October said they plan to build a 3 MW, 6 MWh storage project at a Massachusetts solar farm that used to house a coal plant. Also in October, Enel told Bloomberg that the company is looking for energy storage acquisitions.

“This is a trend I’d expect to continue as storage economics continue to improve and utilities begin to explore new technologies to ensure effective system operations in the face of a changing grid,” Simon said

In the PG&E deal, EDF RE will build, own and operate a portfolio for PG&E that will include behind-the-meter battery storage projects for commercial and industrial customers in PG&E’s service territory.

The aim of the projects is to help C&I customers to lower their electric bills by reducing their demand charges and maximizing consumption during off-peak hours, as well as bringing in revenue by using storage to provide services to California’s wholesale power market.

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Massachusetts’ Baker-Polito administration hasawarded $20 million in grants to 26 energy storage projects in the state.

Recognizing the benefits energy storage holds for the commonwealth, as well as the strength of the submitted projects, the administration says it doubled the available funding from the initial $10 million commitment. The awarded projects will benefit 25 communities and draw in $32 million in matching funds, helping to grow the state’s energy storage economy.

The grants were awarded as part of the Baker-Polito administration’s Energy Storage Initiative (ESI) Advancing Commonwealth Energy Storage (ACES) program, funded by the Department of Energy Resources (DOER) through Alternative Compliance Payments (ACP) and administered by the Massachusetts Clean Energy Center.

The awardees are EnerNOC; UMass-Amherst; Massachusetts Municipal Wholesale Electric Co. (two projects); UMass-Boston; GE; Boston Medical Center; Borrego Solar Systems (two projects); Advanced Microgrid Solutions; Greenlots; Martha’s Vineyard Transit Authority; Tesla (two projects); Solect Energy; NuGen Capital; UMass Memorial-Marlborough Hospital; Reading Municipal Light Department; NextEra Energy; National Grid; Ameresco; Taunton Municipal Light Plant; Sunrun; Constellation; WH Bennett; and West Boylston Municipal Light Plant.

The announcement was made by Gov. Charlie Baker, R-Mass., during an event at UMass Memorial – Marlborough Hospital. The critical-care facility will use funding received under the grant program to integrate a 400 kW solar canopy and energy storage system.

“The development and deployment of energy storage projects will be vital to the commonwealth’s ability to continue leading the nation in energy efficiency,” says Baker. “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.”

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The mega industrial lithium-ion energy storage system (ESS) has been ordered by Korea Zinc, a metal smelting company at a cost of 50 billion won, or around $45 million, reports Inhabitat.

Hyundai also points out their ESS will be nearly 50 percent bigger than Tesla’s 129 megawatt-hour grid storage battery in South Australia. Hyundai says their ESS will be operational sometime in February 2018.

Bloomberg New Energy Finance senior associate Ali Asghar said, “Musk has set a benchmark on how quickly you can install and commission a battery of this size,” and that plummeting costs are “making them a compelling mainstream option for energy storage applications in many areas around the world.”

And despite the growing competition to install mega-industrial ESSs, this is not the story. For as Asghar notes, the battery-storage industry has become increasingly important, not only for places that have less access to traditional fossil fuel energy sources but to industries that are heavily energy-intensive, like a metal smelting plant.

Need for “peaker” plants solved

Even as the cost of battery storage systems continues to drop globally, one of the biggest advantages in an industrial-sized ESS is the savings realized from not needing to build “peaker” plants that operate just a few hours a day.

Wind and solar power can be considered intermittent power sources because they may not be efficient when the wind is not blowing or the skies are cloudy. This is where storage batteries smooth out the need to have a traditional power plant as a backup.

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The nation’s largest utility holding company and a major lithium supplier are partnering up to create a new company designed to connect investors with well-researched opportunities in the energy storage sector.

Exelon Corp. and Albemarle Corp. announced Wednesday that they were founding investors in Volta Energy Technologies. The new Napierville, Illinois-based firm seeks to connect technical and product development know-how with investment mechanisms.

 “The energy sector is undergoing a transformation,” said Chris Crane, president and CEO of Exelon. “We must help lead the nation through this change by investing in the next big innovations that provide the best commercial and customer solutions. Exelon launched and invested in Volta because we operate at the forefront of energy innovation, and energy storage represents an important next frontier.”

Exelon owns and operates utilities which provide electric and gas service to millions of customers in the Midwest and eastern U.S. Units include Commonwealth Edison, Baltimore Gas & Electric and PECO, among others.

The worldwide advanced battery and storage market is projected to rise to more than $100 billion within a decade, according to some reports. Over the next year, Volta will seek other investors who have energy storage as a key element of their business strategy.

“Investing in Volta is a strategic priority for us,” said Luke Kissam, CEO of Albemarle Corporation. “Many expect that there will be exciting innovations in lithium battery technology in the future, and we want to be a part of any process that might identify new technologies to power the potential of clean energy solutions. We are excited about ultimately creating value in the markets, and for Albemarle, through our partnership with Volta.”

Traditional venture capital funds often lack the expertise and patience required to advance innovations from lab to market, and public research institutions are not charged with commercializing their work. Volta’s model bridges these gaps and offers a solution.

“Volta’s model is built to identify the winning technologies and businesses in the rapidly evolving battery and energy storage sectors. This enables major, market-moving companies and other investors to choose wisely the technologies that will shape our future energy system,” said Volta founder and CEO Jeff Chamberlain.

“During my 24 years in the private sector and at national labs, I saw firsthand how challenging it is for a single entity to develop a new physical technology—or for a single investor to identify the right opportunity, let alone take it to market,” Chamberlain said. “Volta brings together a team of battery storage and investment experts to tap into the unmatched capabilities of the U.S. national laboratory system to identify and overcome deal-killing technical challenges.”

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U.S. energy-storage capacity surged 46 percent in the third quarter, mainly due to a single big project in Texas, the biggest source of wind power.

Power companies and developers added 41.8 megawatts of storage systems, including a 30-megawatt utility-scale project in Texas, according to a report Thursday from GTM Research and the Energy Storage Association. California added 8.4 megawatts of residential and commercial systems. The industry installed 28.6 megawatts in the third quarter of 2016.

Driven by regulatory demands and sharp price declines, energy-storage is becoming more common. Prices for lithium-ion battery packs have fallen 24 percent from 2016 levels, according to Bloomberg New Energy Finance. Utilities including Exelon Corp., Duke Energy Corp. and American Electric Power Co., meanwhile, are increasingly receptive to storage projects, which potentially will facilitate wider adoption of wind and solar power.

GTM forecasts that 295 megawatts will be in operation in the U.S. by year-end, up 28 percent from 2016. And more is coming. GTM projects the U.S. energy-storage market will be worth $3.1 billion in 2022, a seven-fold increase from this year.

“Energy storage is increasingly acknowledged in utilities’ long term resource planning across the country,” Ravi Manghani, GTM Research’s director of energy storage, said in a statement.

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ISO-NE is working to ensure that its wholesale markets can accommodate an expected exponential growth of energy storage resources, an RTO manager said Tuesday.

“We want to be sure that our wholesale markets are favorable to all resource types equally, so when we think about energy storage, we want to make sure it fits in the box,” Carissa Sedlacek, ISO-NE director of market development, said during a Dec. 5 energy storage seminar hosted by the Northeast Energy and Commerce Association in Boston.

With 20 MW of energy storage already interconnected in ISO-NE and nearly 80 MW in the interconnection queue, the RTO is adjusting some of its market rules to accommodate the new and flexible resources coming online, Sedlacek said. (See ISO-NE Plans for Hybrid Grid, Flat Loads, More Gas.)

“How is that energy storage facility going to operate?” Sedlacek said. “Is it going to operate at full capacity for one hour, or is it going to operate at quarter-capacity for four hours? How is it going to respond if it’s coupled with wind or solar? Is it going to be there for longer durations? Is it going to be used more in the winter than in the summer? These are the types of questions we ask in the planning department as we consider new resources, especially something like energy storage.”

Spreading the Risk

ISO-NE predicts energy storage providers will largely focus participation in the RTO’s ancillary services market because many of them are not prepared to assume the financial burden of qualifying for the Forward Capacity Market (FCM) — or to confront the risk of coming up short on a capacity supply obligation (CSO), Sedlacek said.

“If you get a megawatt CSO that you cannot achieve, there will be a financial penalty,” Sedlacek said, noting that penalties go into effect June 1, 2018, leaving some storage developers “a little gun shy” about offering into the FCM. She noted that solar and wind participants in the FCM don’t typically attempt to qualify for their nameplate capacity, but only a percentage of nameplate (usually 40 to 42%) to ensure their obligation is achievable.

“Because under the [FCM], you’re on the hook to provide those megawatts,” she said.

Sedlacek explained how energy storage developers might hedge their risk by pursuing incentives offered for over-performing in the FCM.

“So you can figure out what your output would be over a four-hour period, because that’s what you have done analysis on and you think might actually last for a shortage of that [capacity amount],” she said. “That’s the megawatts you want to actually take on as the CSO, but be happy to take on additional megawatts or have more output on real shortage events, days or hours, and kind of scoop up the additional revenue.”

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Since its inception, power generation has been notoriously difficult to build. Even once developers sort through regulatory preferences and siting difficulties, they still must construct huge slabs of modern industry on time and on budget — a feat that’s tripped up more than one utility in 2017.

Whether in a regulated or restructured state, building even relatively simple natural gas plants or grid upgrades can take years, and the process for more complex nuclear generators or transmission lines often stretches decades. The long lead times mean utilities must plan for new infrastructure many years in advance and make it difficult to respond to short-term changes on the grid.

But recent developments in California could prove to be a turning point. After the worst methane leak in United States history took the Aliso Canyon gas storage facility offline, California regulators early last year issued a series of mitigation measures, including energy efficiency programs and an expedited approval process for energy storage projects.

It was the opening the energy storage industry was waiting for. A year and a half from the decision, California utilities have deployed multiple long-duration storage applications, including installations from Tesla, AES and Greensmith/AltaGas.

The largest of these facilities is the 30 MW, 120 MWh Escondido energy storage project built by AES, and is one of the biggest lithium ion battery installations in the world. Built in about six months, it and a smaller, 7 MW battery provide daily ramping and peak shaving services for San Diego Gas & Electric — services typically delivered by gas generators.

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Tesla built the world’s biggest lithium-ion battery ahead of schedule. It’s an important milestone for the technology, and for Tesla itself. 

But is it coming at a cost to smaller players in the industry?

This week on The Interchange, we’ll talk about how Tesla’s battery supply constraints are hitting downstream installers and developers. We’ll bring GTM Staff Writer Julian Spector on the show to discuss his recent reporting on Tesla’s delivery delays.

Then, we’ll cover some of Spector’s other big stories this year, including howstorageis suddenly challenging natural-gas peaker plants around the world, and why New York is struggling to put a cohesive energy storage framework in place. (Note: This podcast was recorded on Monday. On Thursday, New York Governor Andrew Cuomo signed the state’s energy storage target into law.)

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Elizabeth Ingram is managing editor of PennWell’s Hydro Group.

Energy storage is undoubtedly a hot topic worldwide. And as more focus is placed on this vital piece of the electricity system puzzle, particularly in the face of the increasing deployment of intermittent wind and solar generating facilities and growing demand for renewable generation, more technologies and approaches are being developed to provide needed storage.

The panel discussion session entitled Recent Energy Storage Project Deployment Around the World that took place on Tuesday, Dec. 5, covered a variety of approaches being implemented worldwide, from hybrid gas turbines to combining steam generation and batteries to compressed air energy storage. Another presentation discussed distributed energy resources at the customer level.

An important point is that this session focused not on size of the energy storage solution but rather on the suitability of each to the unique situation for which they were deployed. Although when you discuss current actual deployed energy storage technology, pumped storage hydropower is at the top of the list, the focus of this discussion was more on smaller, more localized systems that are undoubtedly faster to deploy.

For example, Joe Heinzmann with GE Power Services presented information on a gas turbine-battery hybrid system with up to 50 MW nominal of operating reserve. The example given of application of this technology was Southern California Edison’s Grapeline Peaker project.

Curtis VanWalleghem with Hydrostor discussed the company’s approach to storing compressed air in such a way that the facilities do not need to be sited near a salt mine but instead can be placed at the point of demand. Again, capacities of this technology were small, with systems of 660 kW and 2 MW being developed.

Michael Welch with Siemens AG covered the value of including batteries with steam or gas turbines. He discussed the importance of hybrid solutions to decarbonize power generation.

One unique portion of the presentation discussed locating storage at the customer’s location, with information covered by Matt Owens with Stem and Flavio Dal Lago with Socomec.

Engagement in the content by the audience was robust, with many questions posed. Often I find this portion of a conference session the most valuable and informative, as it indicates their interest in the topic and respect for the panelists as people who can help them get the answers they need. Additionally, audience members who have a special interest in this topic may also have valuable expertise to share with the audience.

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New York has become the latest US state to decide to support energy storage through its legislature and will be setting targets for deployment of the technologies in the coming weeks.

State governor Andrew Cuomo, credited by some in the industry for helping initiate and persevering with the New York Reforming the Energy Vision (NY REV) programme to modernise and add flexibility to the grid, has just approved Assembly Bill A6571 – Establishing the energy storage deployment programme.

First tabled by multiple sponsors in March this year, the bill was delivered to state Assembly and passed through Senate in June. It instructs the regulator, New York Public Service Commission (NYPSC), to develop a programme supporting the deployment of energy storage across the state. As part of that, a procurement target will be established, which is to be reached by 2030. There has been no indication yet of what that target might be. Cuomo signed off on the bill on 29 November.

The bill calls for “commercially available technology” which is cost-effective and can assist in lowering greenhouse gas (GHG) emissions, reducing peak demand, reducing the need for expensive infrastructure upgrades and otherwise improving the reliability of the electrical network, all cornerstones of the NY REV programme. Technologies could include mechanical, chemical or thermal energy storage.

California has in place the mandate AB 2514, which requires the three investor-owned utilities in the state to deploy 1.325GW of energy storage by 2024 in four biennial solicitations, another 500MW was added to that target in May this year. Meanwhile, Massachusetts has set a 200MWh “aspirational” i.e. non-binding target for electric distribution companies by the beginning of the year 2020. More recently in New Mexico, the state Public Regulation Commission (NMPRC) in August unanimously voted to amend its rules governing utilities’ integrated resource planning (IRP) to allow power companies to include energy storage in those IRPs.

As with June’s announcement that the bill was passing through the legislative process, key trade groups NY BEST and the US’ national Energy Storage Association have warmly welcomed Cuomo’s approval of it.

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