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The energy storage sector has a lot to decide about its future, including which technologies will eventually dominate and how storage will participate in national markets. For an insight into how these issues are playing out in one such market, I attended the recent Future of Gas & Electricity Storage UK seminar given by consultancy Future Energy Strategies.
Fast-cycle gas storage
First on the programme was Keith Budinger, CEO of project developer Halite. The company aims to build a large underground salt cavern gas storage facility, but its planning application was turned down on the first try by former UK energy minister Greg Barker. The firm won a judicial review and has now submitted a revised plan.
“The future is fast-cycle storage (FCS),” said Budinger, which “can be thought of as a rapid charge-and-release gas battery”. While conventional gas storage cycles twice a year, injecting gas in summer for withdrawal in winter, because FCS takes ten days to fill a salt cavern and ten days to empty it, cycling can be performed 12 times per year (factoring in delays due to cooling time). In the UK, a nation with just 14 days’ worth of stored gas supplies (as opposed to 87 days for France, 69 for Germany and 50 for Italy) but good connections to longer-term sources of supply, deliverability is crucial, Budinger said. If built, Halite’s project could extend the UK’s gas storage capacity by three days.
Indeed, Budinger believes that Britain’s growing dependence on fuel imports and its increasing amounts of intermittent renewable power on the grid create a need for growth in the area of short-term gas deliverability (vs longer-term seasonal flexibility). “Rather than measuring UK storage [projects] based on working gas volume, it is more important to focus on deliverability,” he said.
Will Halite’s salt cavern storage facility be built? According to Budinger, in the past five years all new-build gas storage facilities in the UK have been fast-cycle, so a trend exists. Budinger is hopeful that Ed Davey, the current energy secretary, will approve Halite’s plan, which has been revised to show the extent of its environmental impact.
SSE’s battery pilot projects
Moving to electricity storage, utility SSE is looking to the future by testing a number of storage applications for different project locations and types, from kW to multi-MW scale. The firm’s Alistair Steele presented a walk-through of a number of these projects, for which the bidding process was cost-based and technology-neutral.
The utility first installed a flow battery in 2008 in Nairn, Scotland. At 100 kW/150 kWh, the zinc bromine battery provides backup power. Next came a 1 MW/6 MWh sodium sulfur battery, installed in Shetland in 2010. The battery is integrated with diesel generator sets as short-term operating reserve, and the installation also features a lead-acid battery. Steele commented that the sodium sulfur battery had been decommissioned after the news that a similar installation in Japan had caught fire. SSE decided to sideline the battery as it was sited next to a residential area; otherwise, Steele said, “it would still be operating” as the company deemed the risk fairly low.
In 2011, SSE began a low-voltage connected battery project in Slough, England. A 25 kW/25 kWh lithium-ion (li-ion) battery was integrated into a model eco-homes development and is used to smooth demand peaks. Steele said another 25 units destined for this site are still in the research and development stage. Another 2 MW/ 500 MWh li-ion battery was used in 2011’s Orkney Storage Park, a key objective of which was to develop a commercial model for energy storage.
Going forward, Steele told PEi that SSE plans to continue its battery storage projects and is accepting proposals for demand response and storage facilities “as long as the cost is lower than an overhead [transmission] line”. When asked which battery technology the company might eventually prefer for large-scale development, he reiterated that cost and site suitability trump technology.
Storage’s role in the power market
Ayesha Patten of energy management consultancy Poyry next took the floor to discuss the UK’s energy storage market. She emphasized storage’s diverse forms and capabilities, arguing for a new market category rather than storage being categorized by default as power generation. She said larger-scale storage is most suited to managing projects on a national scale, e.g., large-scale renewable energy installations, while smaller-scale storage is best for addressing local needs, e.g., solar photovoltaics (PV) and electric vehicles.
Patten noted that the cost of storage is currently high compared to other flexible technologies such as OCGTs, but in future significant cost economies are expected for storage as the technology develops and large-scale deployment accelerates.
In the UK, she added, storage could be useful in a number of scenarios including displacing higher-carbon power generation capacity, optimizing network reinforcement, providing ancillary services and, on the supply side, wholesale hedging requirements. For storage to be of effective use in these areas, she said, it should be recognized by the market as its own asset class.
Within this class, she suggested a number of potential business models for storage including ownership and/or operation by supplier/generator/PPA providers and aggregators as well as third-party storage operators/developers. These business models aim to allow storage to access multiple revenue streams. However, Patten warned that this possibility depends on UK policy, and that revenues attributable to wider system benefits are currently not accessible to storage system owners. In addition, policies currently being developed, including capacity payments, could adversely affect the development of the storage field depending on their outcomes.
In summary, the seminar would seem to indicate that energy storage has a part to play in the UK power market, but the sector is still beset with uncertainty in the form of both technology and policy risk. As energy storage is gradually deployed in more power projects and scenarios, one or several dominant technologies will likely emerge as operators choose the best storage solutions for their needs, while governments will need to decide how storage will function and be supported in their energy markets.
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