By Matt Rennie and Ian Wood on 18 May 2017
In a series of tweets in early March, Tesla founder, CEO and Chairman Elon Musk made a dramatic offer to help address the issues bedeviling South Australia’s electricity grid: he offered to install 100MW of battery storage within 100 days — or the system would be free. This led to talks between Musk and South Australia’s Premier, and with Australia’s Prime Minister Malcolm Turnbull.
At the time of writing, it was unclear whether the offer would be taken up, and there are serious questions as to whether such a system would be an appropriate solution to the blackouts plaguing the Australian state. But the attention that Musk’s offer generated is testament to the increasingly important role that battery storage, at scale, is playing in modern electricity systems.
Storage technology is the vital missing element in the struggle to enable the transition to clean energy, allowing grids to accommodate ever-growing volumes of intermittent generation and transforming the economics of renewable energy systems. But, along the way, the growth of battery storage promises to transform power markets, accelerate disruption of the utility business model and challenge regulators to rethink how they oversee generation, transmission and distribution.
The growing penetration of batteries is, essentially, a solution to a problem that dates back to the construction of the first electricity grids. “The electricity supply chain is the longest supply chain in the world with almost no ability to store the product,” says Matt Roberts, Executive Director of the Washington, DC-based Energy Storage Association (ESA). “That means we have scaled everything to meet the absolute peak of demand — it’s an incredibly costly and inefficient way to build a network.”
The inability to store surplus power (beyond the limited capacity of older storage technologies such as pumped hydro systems) is becoming a more pressing problem with the greater penetration of wind and solar technologies. Solar output, while relatively predictable, dips in cloudy conditions, while local wind speeds are hard to predict with confidence more than a few days into the future.
In addition, thermal power plants currently play an important role in balancing generation and load to maintain the frequency of power grids within a constant range, which protects electric equipment. Renewable energy generation is unable to provide the on-demand balancing power needed for grid stability.
This means that battery systems — predominantly, to date, using the lithium-ion technology seen in electric vehicles — have multiple uses, and multiple market needs they can address.
“The opportunity for battery storage exists in all areas of the utilities value chain — in generation, transmission and distribution, as well as on the consumer side, behind the meter,” says Manish Kumar, Managing Director of Arlington, Virginia-based AES Energy Storage, an arm of power company AES Corporation.
Thomas Christiansen, Associate Director at EY in Stuttgart, Germany, describes a hierarchy of applications that will become progressively more commercially attractive as battery costs fall:
- Islanding uses batteries alongside renewables in isolated grids, displacing expensive small-scale fossil fuel generation using diesel or fuel oil.
- Grid balancing provides short-term supply (or demand) to keep electricity grids in equilibrium, and helps to reduce the need for investment in transmission and distribution networks.
- Peak shaving reduces demand for expensive power from the grid at peak times. As batteries get cheaper, Leading the charge Battery storage is set to jump-start the clean energy transition while at the same time disrupting the traditional utility business model. it becomes economical to use them for energy load shifting, charging the batteries when grid power is cheap and discharging them when it is expensive. These techniques become economic first for commercial users with high peak charges but moderate overall use, followed by large industrial users with high energy demand.
- The behind-the-meter market pairs on-site batteries and renewable systems, allowing both commercial and industrial (C&I) and domestic users to consume more of the power they generate by, for example, using stored solar power into the evening.
Around the world, battery storage capacity is rising fast: according to figures from Bloomberg New Energy Finance (BNEF) installed capacity will grow at a cumulative average rate of 44%, leaping from just 6GWh in 2015 to more than 81GWh by 2024 (see the chart on page 5). At present, its main applications are to provide balancing services for transmission and distribution systems, and for integrating renewable energy. However, according to BNEF the use of batteries behind the meter, paired with photovoltaic (PV) systems, is set to overtake after 2020.
There are two factors behind this rapid growth.
First, the cost of batteries has been falling dramatically, driven by enormous increases in manufacturing capacity and expertise. Lithium-ion batteries have fallen in price by some 80% over the last five years, according to BNEF figures. The construction of “gigafactories” is forecast to triple production capacity between 2015 and 2020 to almost 125GWh according to RBC Capital Markets. Lazard estimates that this will help to reduce battery costs by nearly 50% by 2021.
Second, the services provided by batteries — especially around fast frequency response — are being recognized by regulators. “The cost of energy storage systems could fall to zero and they still wouldn’t be viable in many markets,” argues Roberts at the ESA. “You need to recognize their value, and that’s what has been accelerating. Frequency response and system reliability have been the gateway, illustrating the value that energy offers.”
Changes to rules governing payments for fast-response assets in the Pennsylvania– New Jersey–Maryland (PJM) electricity market earlier this decade allowed batteries to compete in providing frequency regulation services. This was followed, in 2013, by a mandate from the California Public Utilities Commission (CPUC) requiring that the utilities it regulates build 1.3GW of energy storage capacity by 2020. Similarly, the National Grid in the UK has conducted enhanced frequency response auctions in which batteries provided the bulk of the capacity.
“We were able to convince PJM of the benefits — in terms of the flexibility, precision and speed — that energy storage can provide in improving grid reliability and resilience,” says Kumar at AES. Because fast-responding resources like batteries provide regulation more efficiently, they offer a higher utilization rate and better availability than traditional power plant resources, he says.
Kumar also notes that battery projects were rapidly rolled out in response to the Aliso Canyon methane leak in California, which was discovered in 2015. There, the disaster at the natural gas storage facility left southern California at risk of forced power outages, and the CPUC ordered “expedited procurement” of large-scale, grid-connected energy storage resources. A number of developers and battery makers, including AES, Tesla and Canada’s AltaGas, stepped forward to put in place around 100MW of battery capacity within months of contracts being signed.
According to Kumar, “It shows that batterybased energy storage can compete both technologically and economically against traditional fossil fuel-based resources such as gas-peaking plants,” which, until now, have been favored to provide back-up capacity.
However, increasingly cost-competitive battery storage is set to bring disruption in its wake. By helping to smooth the intermittent supply from renewable resources, wider battery use will continue to reduce the peak power prices on which many natural gas-fired power plants depend.
In addition, by reducing network utilization, batteries reduce the need for additional grid investment on which regulated network operators depend for their revenues. And by increasing the utilization of customers’ renewable energy systems, batteries will accelerate grid defection, and reduce the peak and system charges that utilities can earn.
“The fastest way into the market for batteries is in frequency response, but the higher-revenue opportunity is in avoiding the network peak,” notes Matt Rennie, EY Global Transaction Advisory Services (TAS) Power & Utilities Leader. He points out that around 50% of network capital expenditure is directed toward meeting around 1% of peak demand.
“If you can deploy a solution that alleviates that peak in some other way than building new transformers and new lines, that’s very valuable,” adds Rennie. However, he also notes that the amount of revenue regulated network operators are allowed to collect from network users is partly a function of capital expenditure: “For networks to value that [foregone expenditure], and choose to transfer that value to a new technology company, it’s a big step.”
The growth of behind-the-meter battery storage presents even tougher challenges. The technology becomes most valuable for utilities when they are able to aggregate and control, through smart grid technology, large numbers of their customers’ batteries, creating virtual power plants (VPPs). However, the question remains as to whether they have the appropriate relationships with their customers to control the batteries, argues Rennie.
“Over the last 15 years, energy retailers have taken so much cost out of their businesses and reduced the relationships with their customers to a transactional level. I’m not sure there’s enough trust there to shift the business model to the sort of partnership you’d need for a virtual power plant model to work,” says Rennie.
“It’s likely to be easier for telecoms companies and consumer electronics firms to learn to be energy retailers than the other way around,” he adds.
While it is early in the process, some technology companies are already challenging energy retailers. Logan GoldieScot, who heads up BNEF’s Energy Storage insight team, says that Germany is currently the largest market for residential solar plus storage systems, with about 50,000 installed: sales are now picking up in other markets, such as Italy and Australia, driven by high retail power prices and limited ability to sell surplus power back to the grid.
Combining these systems to provide centralized utility- or grid-scale storage is at the pilot stage, says Goldie-Scot, but notes that companies such as Sonnen in Germany are competing with utilities. “You also have companies such as Sunverge that are targeting the utility as the primary customer, but with a similar model,” where the retail customer receives a discounted system, in exchange for allowing the utility to tap into the battery as required.
On the other hand, utilities do benefit from some incumbency advantages, as well as from typically low costs of capital. A great deal of the value of energy storage is location dependent, says Roberts at the ESA — and utilities have the data that reveals the best places on the grid to install these systems.
Also, utilities often benefit from brownfield sites with existing electrical interconnections, notes Scott Valentino, Vice President Finance at AltaGas Services (U.S.), part of the Canada-based energy infrastructure firm AltaGas. It was one of the successful bidders to meet the CPUC Aliso Canyon resource adequacy call, contracting with Southern California Edison (SCE) to build a 20MW energy storage facility at AltaGas’s existing Pomona natural gas power-generation facility.
Around the world, utilities are responding to the challenges posed by battery technologies with a range of strategies. Some are partnering with or acquiring technology companies. Last year, Innogy in Germany bought Belectric Solar & Battery, and France’s ENGIE took a majority stake in California battery storage company Green Charge Networks. Meanwhile, the Finnish utility Fortum has teamed up with French battery maker Saft to conduct battery storage pilots.
Others are undertaking their own VPP pilots. In Australia, AGL Energy is building what it says will be world’s largest VPP, connecting 1,000 batteries. In New York, local utility Con Edison is working with the California-based PV manufacturer SunPower to connect some 300 residential PV and storage systems.
Some are exploring even more novel approaches. For example, German utility MVV Energie piloted a service that combined district-level storage with customers’ PV systems, allowing them to store excess solar-generated electricity without the need for batteries on site.
In addition, E.ON has introduced what it calls a solar cloud service, which allows customers with PV systems to “bank” their generation for use at a later time. “It does this virtually, without physically storing the generation on site,” says Goldie-Scot at BNEF. “It’s essentially a local net-metering tariff. It could completely kill the economic driver for storage within the home.”
He says that a year ago he would have been “quite negative on the utility response” to insurgent battery storage business models, adding: “Now, they are raising the bar for these third-party companies.”
But while utilities and insurgents experiment with new battery storage business models, the actions of regulators are likely to dictate their success or failure. “In many cases, regulatory barriers are quite high to utilizing batteries,” says Christiansen at EY.
For example, in Germany, grid operators are forbidden from owning batteries. And, until recently, German users had to pay system fees both when charging and discharging their batteries. This is still the case in the UK, despite industry lobbying. “The lack of a regulatory definition for storage has led to problems in its treatment under current market rules,” says Andrew Horstead, London-based Strategic Market Analyst, EY Global Power & Utilities.
Christiansen says: “There is a role for utilities in lobbying to let the regulators know that, if you lighten up a little bit, there are lots of things we could do that are beneficial for customers, for the economy and for the grid.” On the other hand, Horstead notes that there is a need for strong standards to support consumer confidence at the domestic level.
Regulators should facilitate widespread storage use, says Kumar at AES: “Regulators should encourage utilities to consider storage as an alternative to flexible peaking capacity on the generation side, or as an alternative to transmission or distribution investments.”
But regulators should also aim to provide clarity and consistency in their treatment of battery technology, argues Henrietta Stock, a manager in EY’s Energy Optimisation service in London: “Things are changing very rapidly, and stability in policy would be very helpful.”
Undaunted by the complexities involved, investors and independent power producers are increasingly dipping their toes into battery storage markets, aided by the longer-term contracts they are able to strike with utilities. “Developers typically have financed systems from their own balance sheets, cobbling together revenue from short-term utility contracts or wholesale electricity markets,” says EY’s Horstead. “Storage contracts to date in the US and Canada rarely exceeded 3 years. Now utilities are signing agreements for 3 to 7 years, and sometimes as long as 10 years.”
This, alongside increasing confidence in the technology, is encouraging investors into the sector. Financial institutions including InfraRed, Investec and Prudential Financial have either backed projects or are seeking investments.
However, despite the investment certainty that longer-term contracts with utilities or network operators offer, developers note that it is usually necessary to “stack” revenues from a number of services to make each battery project viable. Valentino at AltaGas notes that the Pomona project supplements revenues from its capacity contract with SCE by supplying energy and ancillary services into day-ahead and realtime markets.
Investors face a range of technology and market risks. Valentino notes recent bankruptcies among start-up battery makers, most recently that of Aquion Energy in March. AltaGas uses Samsung batteries, preferring to go with a wellestablished Tier 1 provider. Ian Wood, Director in EY’s Corporate Finance service, also notes that, in some markets, demandside response programs may prove to be more cost-effective than batteries, challenging the latter’s business case.
There is also the danger that, in fastevolving markets, battery system developers may find that how their systems are configured and contracted for becomes out of date. “There is a lot of regulatory change going on,” says Felicity Jones, Partner – Energy storage, at the UK-based technical and commercial consultancy Everoze Partners. “Developers need to make sure their contracts are designed for agility, to allow them to move between revenue streams.”
For example, warranties may be restrictively worded to allow only for certain types of battery use, she notes. Alternatively, in seeking to stack revenues and sell services to different offtakers, battery owners may find that they are subsequently unable to take advantage of emerging revenue streams. “It’s very complex to anticipate, but the goal is to bake in optionality in contract design,” Jones says.
But, for all the complexity involved, EY’s Wood argues that the market for battery storage is taking off without the need for a high degree of revenue certainty, paid for with large government subsidies, which was required to develop the nascent renewables sector: “Having certainty around a portion of revenues is sufficient to allow investment to happen.”
Nonetheless, the market and technology risks involved suggest that investors and insurgent developers should pursue a different business model to one that worked for renewable energy, Wood suggests: “In renewables, investors would invest in single assets. In battery storage, they are looking to invest in a platform — with a portfolio of assets, and also a management team that will operate, run and trade it, and that is able to adapt to changes in the marketplace.”