Among the challenges facing early investors in the growing electricity storage market is understanding and navigating the sheer variety of:
- different market needs that storage addresses
- locations in which it can be built
- business models that can support it.
For those used to the (relative) simplicity and repeatability of mature power generation projects in solar PV and onshore wind (for example), the storage market presents a much more complex picture. Even as costs continue to fall and technologies mature, this market complexity should remain. Indeed, given the flexibility and adaptability of battery technology at multiple scales, it’s likely that new applications, opportunities and business innovations will emerge, diversifying the market even further.
A good way to illustrate this variety within the storage market is to briefly highlight three recent examples. On the face of it, they are all large-scale, grid-connected storage projects: 48MW, 50MW and 100MW. All will use Li-ion batteries and all are within “developed” markets in the midst of transitioning towards more low-carbon systems. But that’s where the similarities end!
Co-locating storage with generation
The Riverland project is being built by Lyon Group, about 125km north east of Adelaide, in South Australia.
It will consist of a 330MW solar farm, using tracked PV, plus a battery storage system with 100MW power capacity, and a likely energy capacity of 400 MWh. The project is 100% equity financed. Construction is due to start in June 2017, with a target of commercial operation by the end of 2017; showing just how quickly large-scale PV and battery infrastructure can be rolled out these days.
This is in a region where the demand for electricity on some days can be more than double the average demand on a typical day. This only occurs a few times each year, happening on extreme (hot) summer days and driven by increased use of air conditioners in homes.
Combined with concerns over a reducing supply of dispatchable generation and a combination of other system inflexibility factors, the result has been spiking peak prices. Even, during the last summer, problems with blackout and load shedding events.
No surprise then, that the rationale of the project has been stated by the company as: “delivering reliable, flexible power to meet South Australia’s summer peak.” In other words, the business case is fairly straightforward: it is looking to take advantage of those high peak wholesale prices, selling into the power market when it is most profitable.
Those prices tend to peak in the late afternoon/early evening, rather than at the time of “peak sun” (you can view them here, selecting “SA”). By adding storage, this large-scale solar farm becomes dispatchable; able to deliver energy not just when the sun determines, but when the economics for the plant operator make most sense.
Locating storage within the grid
Rather than building storage alongside variable generation, a joint venture between Dutch developer Eneco and Japan’s Mitsubishi is building a large battery situated next to a substation in Jardelund, Schleswig-Holstein. That’s close to Germany’s border with Denmark. The power and energy capacities are 48 MW and 50 MWh respectively.
The lower power/energy ratio betrays that this isn’t a system targeting bulk energy shifting. Instead the battery is designed to compete against coal and gas in Germany’s “primary reserve” market. This is where transmission network operators (TNOs) purchase capacity to keep the grid running at 50Hz, when sudden power loss events occur. Battery systems are well suited to these frequency management, power-delivery applications, being able to respond rapidly. (In the UK too, early battery storage systems have found application in markets such as “enhanced frequency response”, EFR; winning competitive bids to do so).
In terms of the German grid system, Schleswig-Holstein lies at a strategic location, one where large amounts of electricity generated by wind farms (including growing offshore wind capacity to the north) is collected and transmitted to the rest of Germany.
A permit for the project is already granted. Similar to the Riverside project, construction is expected to start at the beginning of June 2017, and the plant plans to be quickly up and running by December 2017. Although financial details are (naturally) limited, in contrast to Riverside the financing has been described as being “via bank loans”.
Looking to the future, a pilot project will also begin at the site, involving the connection of nearby wind farms to the battery system. This pilot will enable wind farms to supply their electricity output to the battery system when there is surplus production or an overload on the grid – where otherwise production would be curtailed. As well as reducing load on the grid and offsetting the grid upgrades otherwise required to mitigate this curtailment problem, it should enable owners of the wind farm to maximise the value of their generated electricity too.
Locating storage behind the meter (“BTM”)
Similar in power capacity to the last example, but closer to the first one in terms of application, this final example is nevertheless profoundly different to both in terms of its development and installation model!
Southern California Edison (SCE), California’s second largest utility, is buying services from a 50MW, 200 MWh distributed fleet of battery storage projects. The projects were developed and will be asset managed by Advanced Microgrid Solutions (AMS).
The 50MW is composed of many individual batteries in different buildings. However they are aggregated into “fleets” and can be operated as a single resource. This allows SCE to shift the entire fleet of buildings to use stored energy, rather than drawing it from the grid. In effect, some of the grid operator’s largest energy users become its cleanest, most efficient grid flexibility resource.
The battery hosts range from a large commercial real estate firm to a state university. For these sites, energy service benefits include demand management, back up generation and enhanced power quality. There is no up-front cost to users for the storage installations.
This distributed battery will be used to shed up to 50 MW x 4 hours of peak load within SCE’s West Los Angeles Basin service territory, which is both generating resource and grid-constrained.
SCE will purchase capacity under 10-year capacity contracts. These lengthy terms, along with contracted guarantees with the end-user hosts, meant that the portfolio was financeable in traditional markets, in a structure described by those involved as “much closer to those used for solar energy development projects”.
Aggregating multiple end-user sites together allowed AMS to offer a large enough supply to interest the utility, and provided the economies of scale to drive competitiveness. They describe their business plan as “designing the system for what the utility needs” while providing the host with “a cost-free upgrade to its energy profile, with batteries that are usually discharging during the same afternoon hours that coincide with peaks in commercial building energy use”. For SCE, in addition to the peak load reduction benefits, the system contributes to their obligation to meet California’s storage mandate (“AB 2514”).
Three “utility-scale” storage projects, three different approaches
So, three large-scale battery storage project examples, but each driven by different objectives – and designed and executed in very different ways. While investors and developers alike will look to first-mover projects like these to inform their own strategies, perhaps the key takeaway is this: storage, more than other businesses they may be used to, will be characterised by variety and individualism.
Below, I’ve summarised some key differences between the examples described above:
If you are interested in exploring these project examples a little further, you can find them within the “Project & Market Examples” section of this website. You’ll need to register to access these and the other case studies. But don’t worry, registration is quick – and FREE – and will also open up access to other site extras: such as my “virtual library” of recommended reading, and my free online course covering the “Essentials of Power Generation Markets”. 🙂