When Regen published its first market insight paper looking at storage – Energy Storage: Towards a commercial model – in 2016, battery storage was still an emerging sector. We were certainly seeing a lot of conferences, but not much real market activity.

Since then the sector has developed rapidly and there is now a pipeline of over 500 MW of projects providing high value grid response services such as Enhanced Frequency Response, as part of a broader move towards providing flexibility to the electricity system.

This is a strong position for an emerging sector. However, grid response is a limited market that is, arguably, already close to saturation. The question we decided to ask ourselves at Regen is what are the business models for the ‘next wave’ of storage projects? The result of that thinking is a follow up paper – Energy Storage: The Next Wave.

 

Thinking about the multiple sources of value that storage can provide to an efficient electricity system, we decided early on to focus the paper on business model of co-locating storage with both generation and high energy users.

Co-location itself can have a number of variations, with storage simply sharing a grid connection but operating independently from generation, to storage being directly connected/co-operated with generation and demand, behind the same metered connection point.

We modelled the business case of storage directly connected and co-located with standalone generation and behind the meter demand. The premise of connected co-location is simple, store energy when it is cheap – when the sun is shining and the wind blowing – and use/supply that energy when demand and costs are high. The reality is that it is difficult to make a pure price arbitrage model work, without including additional revenue or sources of income to supplement the benefit and offset the investment in the storage asset. Our modelling reflected this, with a challenging cost-benefit outcome for both generation co-location and behind the meter models.

The key benefits for the two variants of co-location that we modelled are:

  • Price arbitrage (various market prices)
  • Bypassing export constraints
  • Maximising self-consumption of generation
  • Avoiding peak network charges

Other benefits, such as income from response or reserve services, power quality services or the value of mains back-up provision, were not included in the modelling. As our aim was to assess the near-term viability of storage co-location without the need for i.e. frequency response income, to see how far away we are from a co-location model that that works on its own merits.

The conclusion here was that whilst costs are falling, we are still some way from a viable ‘pure co-location’ model, without the need of additional revenue streams from frequency response. However, with the procurement of frequency response (and associated balancing services) set to be rationalised, simplified and improved by the System Operator, the size of this market will be finite, incumbent providers will respond to increasing competition and there will be a number of new entrants, that will cause fierce competition for these contracted services.

As the storage market develops, the ability to capture price arbitrage is expected to become one of, if not the most important source of revenue and one of the main drivers for storage growth. Volatility in price is traditionally not seen as a favourable thing for a generator or a demand customer, but incorporating storage into the mix opens up a number of benefits, from demand customers avoiding peak retail and network charges to generators and traders ‘time shifting’ the supply of energy into the network at times when prices are high.

An interesting aspect of our modelling of arbitrage, was the variation in results from referencing different electricity market prices. The volatility of a fluid price such as the wholesale index price, is relatively predictable and stable when compared to the highly volatile and less predictable system (imbalance) prices. Defined as “…prices that are used to settle the difference between contracted generation or consumption and the amount that was actually generated or consumed in each half hour trading period”, currently access to this market is limited to those eligible to register under the Balancing Mechanism (BM) as a Balancing Mechanism Unit (BMU). Other than large transmission connected storage assets or those associated to BMU eligible generators, the potential for storage (predominantly set to be connected on the distribution network) will either individually be too small or are restricted by the fact that aggregators are not currently permitted to participate in the BM.

Aside from the modelling the business case, reviewing the market position for storage in this paper, highlighted the pace at which the energy storage sector is evolving. There have been a series of policy and regulatory changes affecting storage in the past few months, ranging from positive changes to remove ‘double charging’ of storage with generation (from the perspective of network residual charges), to more detrimental decisions such as the de-rating of storage in the Capacity Market.

In amongst these mixed policy signals, there are new and emerging opportunities for storage assets developers to turn to. The rationalisation of the balancing services that the System Operator procures, gives rise to potential need for even quicker response times, in the form of the SO’s aspirations to procure services to support the management of ‘system inertia’ or Rate of Change of Frequency (RoCoF), superseding even EFR response times.

In addition, the transition to Distribution System Operator (DSO) for the regional network operators brings with it the potential for flexibility services to be procured locally and at lower thresholds. UK Power Networks (UKPN) issuing an Expression of Interest for flexible capacity at 10 of its substations in August marks the first time a DSO has gone to market for flexibility services, outside of a trial. The results of this EOI will give insight into who and what can deliver the required flexible capacity at the given availability times, voltage level and locations, at a practical price.

Looking beyond the inevitable hype in a rapidly developing technology there are significant challenges for the next wave of storage projects. Cost reduction is inevitably needed, but the capability of storage technology (or a hybrid of different technologies) will adapt to meet market signals. One evident challenge is to develop longer duration storage assets with increased MWh capacity.

Ultimately as technology improves and costs reduce the ‘hand of the market’ and the ‘hand of regulation’ need to be working together to enable energy storage to realise its true value as a ubiquitous part of our electricity system.

Author: Ray Arrell