The market for energy storage is poised for rapid growth in New York, but progress could be stymied. A flawed plan from NYISO, the state’s electricity grid operator, threatens to slow the integration of these promising new technologies into the market. The Sustainable FERC Project, Natural Resources Defense Council, Earthjustice, and other groups filed a protest to NYISO’s plan with the Federal Energy Regulatory Commission (FERC) today, urging the nation’s grid regulator to order NYISO to revise its proposal to ensure energy storage resources can participate on even footing in its markets.

With the costs of energy storage technologies like large batteries rapidly falling and their vast potential becoming clear, FERC has made it a top priority for grid operators to update their market rules to eliminate barriers that prevent storage companies from selling their many valuable grid services to utilities and other large energy users. These barriers can slow technological innovation, reduce competition, and increase prices. Markets run by the nation’s regional grid operators were originally set up with power plants and not energy storage resources in mind. Due to operational differences between the technologies, it can be hard for energy storage resources to efficiently participate in those markets.

In February 2018, FERC issued a landmark order (known in the industry as “Order 841”, discussed here) requiring the country’s several regional grid operators to eliminate their market barriers for energy storage resources. Meanwhile, states like New York have taken complementary action to jumpstart the energy storage industry. For example, the New York Public Service Commission (PSC) recently announced a target of 3000 Megawatts of energy storage by 2030, issuing an order that established the regulatory groundwork for a suite of policies designed to galvanize the market. But NYISO’s failure to adequately implement Order 841 now threatens to hinder the state’s plan.

Our coalition is challenging NYISO’s faulty proposal, urging FERC to order NYISO to improve it in three critical areas:

Traditionally, utilities built and operated a portfolio of generation plants consisting of a few large baseload units – typically nuclear or coal – some intermediate plants, and a number of peakers – typically natural gas-fired units with rapid ramping capability. Baseload units ran close to flat out year-round, 24/7; the intermediate units were used to fill the fluctuations in demand; while the peakers were used sparingly to meet occasional surges in demand — say, on hot summer afternoons when air conditioning load would spike for a few hours.

Fast forward to 2019 and beyond and one is likely to encounter a different paradigm, where on many networks an increasing share of generation is provided by renewable resources, most likely wind and solar, neither of which is dispatchable nor totally predictable. In this environment, what the grid operators crave the most is the flexible generation, especially options with a rapid ramping capability to fill in any unexpected shortfalls in renewable generation and to maintain the system’s reliability.

This much is old news. What is new is that recent advances in energy storage technology, especially batteries, coupled with dramatic cost declines is making storage increasingly attractive relative to gas-fired peaking plants, which are not particularly efficient, are highly polluting, and are expensive to maintain. Moreover, since peakers are infrequently used and only for a limited number of hours, they tend to be poor investments, sitting idle most of the time.

A case in point was a decision by San Francisco–based Pacific Gas & Electric Company (PG&E), backed by the regulator the California Public Utilities Commission (CPUC) in Nov 2018, to replace 3 gas peakers with large battery storage units that would be among the world’s largest when completed.

The approved batteries would have a total of 567.5 MW of power capacity with 2,270 MWh of energy storage consisting of a 300 MW, 1,200 MWh project from Vistra Energy and a 182.5 MW, 730 MWh Tesla battery that PG&E would own – all lithium-ion batteries.

Currently, the world’s largest lithium-ion battery is Tesla’s 100 MW, 127 MWh facility in South Australia, followed by Kyushu Electric Power Co. in Japan, which has a 50 MW, 300 MWh sodium-sulfur battery.

The CPUC directed PG&E to proceed with the batteries rather than signing contracts for 3 gas peakers based on analysis that showed that the cost of the batteries is likely to be lower than continuing to operate the gas plants. This, despite the fact that natural gas is plentiful and cheap, is newsworthy.

A megawatt-scale energy storage system will be rented out to power a gold mine in Western Australia by Aggreko, the mobile power solutions company which bought up energy storage provider Younicos last year.

Granny Smith gold mine, open since 1989 and operated by gold producer Gold Fields, will get an 8MWp solar PV array and a 2MW / 1MWh energy storage system which will be integrated with 24.2MW of existing natural gas generation capacity. As with all other Aggreko-Younicos projects since the takeover, the customer will procure the energy storage system under a rental contract.

The US commercial and industrial (C&I) market for energy storage, in particular, has started to see this type of “energy storage as-a-service” offering become more common, with the recognition that many businesses are not willing to pay the upfront capital cost for battery storage. Instead, such business models rely on the customer making savings on energy costs and the provider potentially earning some revenues from grid services, with the benefits shared between the two parties.

Aggreko said that the single service contract Gold Fields signed up to required no capital outlay from the customer, which Aggreko said eliminates technology risk, increases flexibility and ensures accountability over performance.

Construction will commence in May and is expected to finish towards the end of 2019. Fuel consumption at the mine could be reduced by 10% to 13%, with nearly all energy demand required for gold processing to be supplied by the hybrid power system.

The solar will reduce the need for thermal generation, while the battery will be used for a variety of applications, such as providing spinning reserve to local networks, ramp rate control for the PV plant and voltage and frequency support.

Currently, there are 177 projects in Massachusetts’ SMART queue that have a statement of qualification and energy storage as part of their design. These projects total 101 MW / 241 megawatt-hour (MWh). When adding in projects that are already operating, the total reaches 232 projects with 190 MW / 470 MWh deployed. The state also has an energy storage goal of approximately 1000 MWh by 2025.

Now, those resources will be paid a bit more of their fair share for the grid services they can provide.

Massachusetts has adjusted state regulations to give energy storage system owners participating in the SMART system the right to gain revenue from selling into the Forward Capacity Market, and has also approved solar+storage as part of the net metering programs. The ruling, DPU 17-146-A (pdf), was part of a broader compromise whose goal was to accelerate energy storage deployment by giving investors an additional source of revenue, but to also lower the costs of energy on the Massachusetts grid by fully making use of energy storage’s value.

Forward Capacity Markets allow power grid managers (ISO New England in this case) to pay electricity generation resources simply for staying available, even if they happen not to be used.

The DOER released an example payout schedule, and other simplified explanations of the rulings (PDF), to help those unfamiliar with these market functions (this pv magazine author) to understand the financials – and potential revenue for customers – surrounding an energy storage project.

In addition to the forward capacity market ruling, it was also ruled that energy storage systems associated with solar power systems, much like a recent ruling in California, can participate in net metering programs. The net metering rules allow for the energy storage system to export the electricity saved in the batteries, and gain revenue from the SMART program, if it can be proven that the system was charged with solar power within the SMART program via UL approved software within the energy storage inverters.

In early 2018, Google proclaimed that it had achieved its 100 percent renewable energy target. The global IT giant has the scale and resources to invest in novel power-purchase agreements for clean energy, tackle energy efficiency projects and leverage its assets in wholesale energy markets.

Within the same year, large corporate customers signed more than 5 gigawatts’ worth of power-purchase agreements (PPAs) for wind and solar in the U.S., nearly doubling the number of gigawatts signed in 2017, according to Wood Mackenzie Power & Renewables.

And then there is everyone else.

Despite the headlines about bold renewable goals and organizations committing to deeper sustainability missions, comprehensive energy strategy continues to be a struggle even for large energy users.

According to a study by Centrica Business Solutions, one in three organizations are thinking about how energy can contribute to business growth, drive deeper efficiencies and reduce risk. And yet, the study found that more than half of businesses identified themselves in the “least advanced” category when it comes to energy strategy, while less than 10 percent considered themselves “most advanced.”

In other words, there’s a pretty sizable disconnect between businesses that would like to approach energy differently and those that actually do.

“It’s not that they don’t have the interest; it’s just that they don’t have the resources and time,” said Dan Svejnar, vice president, head of commercial North America for Centrica Business Solutions.

South Australia, the nation’s traditional renewable energy leader, could welcome two new projects featuring some of Australia’s largest utility-scale solar arrays alongside its largest energy storage facilities.

A new proposal for around 500 MW (AC) of solar PV co-located with 250 MW/1 GWh of battery storage has come from consultants Energy Projects Solar. The project, around 5 km northeast of Robertstown, would be built in stages and probably incorporate synchronous condensers to support security of electricity supply.

The second scheme planned for the same region is the Solar River Project, which received development approval in the middle of last year and is preparing to break ground.

As reported by Adelaide and South Australia newspaper The Advertiser, an “early contractor involvement” deal has been signed with Sydney-based infrastructure company Downer Group, which is already building Australia’s largest solar farm.

Joining the large-scale pipeline

The Solar River Project comprises 200 MW of solar PV generation capacity plus 120 MWh of battery storage, and is likely to add another 200 MW of solar and a further 150 MWh of battery storage in a second stage, provided a proposed high-voltage transmission line to Victoria goes ahead.

The project is notable for being 100% privately funded, with a 60/40 merchant-PPA structure. It is being developed by a company based at the University of Adelaide’s ThincLab accelerator and comes with a price tag of $450 million (US$326 million).

The two projects are among the largest in Australia’s development pipeline, alongside Innogy’s 349 MWp Limondale Solar Farm, Maoneng’s 255 MWp Sunraysia Solar Farm in New South Wales and Total Eren’s 256.5 MWp Kiamal Solar Farm, in Victoria.

The energy storage facilities will also be among the nation’s largest, along with the South Australian Tesla big battery (110 MW/129 MWh) at the Hornsdale Power Reserve, and a 120 MW/140 MWh facility proposed by SIMEC Zen Energy, as part of U.K. steel billionaire Sanjeev Gupta’s 1 GW dispatchable renewable energy program for the South Australian industrial town of Whyalla.

The Solar River project is scheduled to begin generation in the final three months of this year. Once approved, the Robertstown project is expected to be completed within six years.

Tesla will acquire Maxwell Technologies, it was announced this week, although it is not clear yet which of Maxwell’s product lines, including ultracapacitors, are of most interest to the Silicon Valley automaker and new energy company.

Tesla’s acquisition ‘target’, headquartered in the US with offices in Germany, China and South Korea, manufactures and markets solutions and products for energy storage and power delivery. These include ultracapacitors, which offer high power density and rapid charge and discharge functions. Tesla’s Elon Musk has been quoted as having a personal fascination with ultracapacitors according to various interviews.

Maxwell is also developing dry battery electrode technology, which the company said “has the potential to be a revolutionary technology within the battery industry with a substantial market opportunity”, especially suitable for electric vehicles. The company claims it can “create significant performance and cost benefits” compared to wet electrode technology currently used by most manufacturers of lithium batteries.

Tesla: ‘always looking for potential acquisitions’
Maxwell said yesterday in a statement that with shares valued at US$4.75 in the upcoming offer, the company had entered a definitive merger agreement with Tesla, Inc. Tesla will make an all stock exchange offer for all issued and outstanding shares, with Maxwell to become a merged and wholly-owned subsidiary of Tesla. The deal is thought to value Maxwell at around US$218 million.

A Tesla representative did not deny the news when asked by Energy-Storage.news last night. By way of confirmation, the spokesperson issued a fairly nondescript company statement as follows:

“We are always looking for potential acquisitions that make sense for the business and support Tesla’s mission to accelerate the world’s transition to sustainable energy.”

Energy-Storage.news asked whether access to the ultracapacitor technology or to the dry electrode technologies would be of primary interest to Tesla. However, the Tesla representative said the company would not be “sharing further comment at this time”. Similarly, a Maxwell Technologies representative told Energy-Storage.news that the company “will not be conducting interviews or providing additional commentary…at this time”.

Energy storage is poised for rapid growth.

The past 18 months have witnessed an unprecedented number of announcements, many of them in the US.

In 2018 the state of New York announced a 1.5GW energy-storage target by 2025, New Jersey opted for 2GW by 2030, while Arizona expects 3GW is feasible by that date.

BloombergNEF links the fortunes of an energy market with high renewables penetration to cheaper energy storage.

In its 2018 New Energy Outlook, it projects that wind and solar will grow to almost 50% of world generation by 2050, on the back of “precipitous reductions in cost”, but also the “advent of cheaper and cheaper batteries that will enable electricity to be stored and discharged to meet shifts in demand and supply”.

According to European trade association Eurobat, costs of $273/kWh for lithium ion batteries are being reported by some manufacturers.

Focusing on the $/kWh for the battery alone is only helpful to a point, as these costs are just one component of a system that comprises inverter hardware, electronics and software.

Detailed cost breakdowns for battery energy-storage systems are scarce or difficult to nail down as this type of information is confidentially held among suppliers and integrators.

Differences in system design or technology, depending on the application, as well as system sizing and cost boundaries, can all vary, making comparison difficult, according to the International Renewable Energy Agency (Irena).

System and capital costs
Some system integrators, which typically buy in batteries and converters and incorporate them to work out the design and size of storage systems depending on their application, will be able to apply healthy margins for their proprietary software, which deploys advanced data analytics to exploit the dynamic functionality of energy storage within grids.

The contribution of cell costs to the total cost of an energy-storage system varies, depending on system size. In larger systems, power electronics and other costs become more relevant, according to Irena.