2017 has been a big year for energy storage projects — Aliso Canyon, California’s six month rapid-fire deployment of 100 MW of storage in response to gas leaks, Tesla’s record breaking big battery bet in South Australia. Utilities across the globe are commissioning more and larger energy storage installations, from backup power supplies in island locations like Nantucket to E.ON’s most recent large project in Texas.
These big projects have been making big waves — but big profits are proving trickier. UK battery energy storage investors Foresight calculate that battery storage costs need to fall a further 30% to be truly competitive. Forging ahead, energy storage developers have had to seek other ways to make their projects economically viable.
The Rocky Mountain Institute in their 2015 white paper “The Economics of Battery Energy Storage” identify 13 value drivers in the sector — but the fast-paced nature of new developments and rapidly falling costs of technology mean the figures are already out of date. So how are developers making bankable projects in practice?
Solar developers SunRun in California have been seeing both profit and growth, using energy storage to add value to their rooftop solar systems. Anesco’s Clay Hill development in the UK, the first to forgo subsidies, also credits its success to energy storage. Leasing solar-plus-storage systems allows for both an ongoing income stream from consumer contracts and grid-balancing opportunities — Germany (SonnenFlat), Australia (GridCredits) and the UK (GridShare) are seeing promising early results.
Adding energy storage to existing generation sites (such as with Tesla’s South Australia installation) is another way to reduce overall costs. By taking advantage of existing transmission and distribution infrastructure, initial capital expenditure is reduced and revenue generating activities can start on an accelerated timeline.
Utilities are finding that the cost of energy storage is measured as much in what you don’t spend as what you do. Energy storage can be used to defer or avoid upgrading electrical transmission and distribution equipment (T&D deferral), as in the aforementioned Nantucket example. This value proposition is especially interesting for remote sites or emerging markets where reliable grid connections are not or cannot be established.
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