August 28, 2017

Investment in flexibility: battery storage

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Electricity flexibility investment

We are starting the second half of 2017 with a mini-series on investment in electricity system flexibility.  Today’s article looks at investment in grid scale battery storage.  We then return next week to contrast this with the investment economics of gas-fired peaking generators.  We will come back to investment in alternative sources of flexibility (e.g. CCGTs, interconnectors and DSR/distributed flex) as the year progresses.

Flexibility remains a central challenge in a decarbonising and decentralising energy system. Substantial cost reductions in wind and solar capacity are underpinning a robust pipeline of renewable capacity development across Europe. But this requires major investment in flexibility to facilitate swings from intermittent output.

Until recently, consensus was that this flexibility was going to be dominated by gas-fired generators and improvements in interconnection.  But rapid costs declines and deployment of battery storage is challenging this view.

The UK power market is leading European investment in the deployment of both battery storage and gas peaking assets. This is being driven by a tight UK reserve margin and a relatively supportive regulatory framework for investment in new flexible capacity.  So as we look at investment in batteries vs peakers, we use the UK market as a case study to illustrate the practical challenges facing asset investors.

Batteries: state of play

There is a dazzling array of potential battery storage applications.  But to date, the practical focus for commercial deployment has been investment in lithium-ion batteries to provide system services.

Growth in lithium-ion battery deployment is being driven by very rapid cost reductions. Only 2-3 years ago battery costs were in excess of 1000 $/kWh.  Tesla made headlines this year with a 250 $/kWh ‘pack level’ cost for 129 MWh battery system it is deploying in South Australia (the world’s largest to date).  This headline grabbing price tag excludes some important cost components.  But even accounting for these, grid scale battery costs may decline to under 200 $/kWh by the early 2020s.

The batteries currently being rolled out can provide very fast (sub-second) output response, but only over a short duration (e.g. 1 hour).  This means that they are well suited to servicing an increasing intermittency driven requirement for rapid frequency response services. Batteries can also be used to defer the costs of investment in grid upgrades. But short duration batteries are not designed to provide wholesale market arbitrage or ‘load shifting’ services.

That doesn’t mean that ‘load shifting’ batteries for wholesale market application should be written off.  There are already 4-6 hour duration batteries at the development stage. But the cost structure and cycling limitations of long duration batteries means that load shifting is not yet commercial.

The question looks to be when, rather than if, technology will progress to support broader commercial deployment of load shifting batteries (mid/late 2020s?).  But for now we focus on investment in short duration batteries.

UK focus for battery investment

Back in 2014 a 6MW, 10 MWh battery was developed at Leighton Buzzard in the UK. At the time it was the largest battery storage development in Europe.  Development relied heavily on support from the UK Low Carbon Networks Fund.

It was almost inconceivable that two years later, 500MW of batteries would be successful in the Dec 2016 UK capacity auction. A combination of technology cost declines and a constructive regulatory framework has catapulted the UK into global pole position for grid scale battery investment.

The rapid growth potential for batteries in the UK is illustrated by the system operator (National Grid’s) latest Future Energy Scenarios projections.  Grid projects more than 2GW of growth in UK electricity storage capacity over the next 5 years, in all four of its scenarios for capacity mix evolution.  The driving forces: declining battery costs and an increase in system requirement for rapid frequency response services as wind deployment grows.

UK battery investment case study

Commercial deployment of batteries in the UK is attracting a lot of investor attention. In a world of depressed infrastructure yields, battery developers are targeting double digit project returns.  There is also a compelling story around scalability, both within the UK market and in Continental Europe.

But project yields reflect risks. Battery investment is by no means a one-way bet.  In Table 1 we set out 5 key challenges facing battery investors.

Table 1: Challenges with UK battery investment


Consideration Getting comfortable
1. Investment model Scalability. Route to market. Contracting model. Integration with peakers or wind. Define business model & growth options. Benchmark contracting & 3rd party options.
2. Competitive dynamics Battery growth & risk/return vs e.g. CCGTs, peakers, ICs, pump hydro. Cost declines. Analyse (i) UK market rapid flex requirement (ii)  battery economics vs peakers/ CCGT/ICs.
3. Frequency Response FR revenue as capacity mix evolves. Grid ‘SNaPs’ review on buying FR services. Model evolution of FR market revenues & impact of wind, peaker, battery roll out.
4. Capacity Revenue Evolution of UK capacity prices. BEIS review of duration linked derating factors. Model evolution of pricing of 15 yr capacity contracts & overlay of duration derating.
5. Other margin & support Embedded benefit revenues. Impact of new battery policy support measures. Quantify stacked embedded benefit returns & risk/return impact of evolving policy.

Source: Timera Energy

The first challenge for investors is defining a viable business model to support asset risk/return and growth targets.  Most investors are currently looking at batteries as an integrated play with other assets.  There are revenue management and risk diversification synergies from building a portfolio of batteries and peakers (e.g. gas engines).  There are also potential co-locational benefits of integrating batteries with renewables. In all cases the battery business model relies on a route to market, to manage the interaction between stacked revenues (e.g. across balancing services, embedded benefits, wholesale market).

The policy framework to support batteries is more advanced in the UK than most other power markets.  This is underpinned by relatively well defined revenue streams for frequency response, capacity payments and demand charge avoidance.  But UK electricity storage policy is still evolving rapidly, causing inherent investment risks, for example:

  1. Frequency Response: Grid launched a comprehensive System Needs and Product Strategy (SNaPS) review of the way it procures balancing services in Jun 2016. This will likely result substantial changes to frequency response service procurement (e.g. replacement/aggregation of Firm Frequency Response and Enhanced Frequency Response services).
  2. Capacity Market: BEIS (UK Department for Business, Energy and Industrial Strategy) launched a consultation in Jul 2017, indicating its intention to scale battery capacity payments based on discharge duration. This may significantly reduce revenues under 15 year capacity agreements, particularly for the more cost effective short duration batteries.
  3. Broader policy support: BEIS also provided broad guidance in Jul 2017 of its intention to improve policy measures to support investment in battery technology. This includes cutting ‘double charging’ for system usage, facilitating colocation with renewables and smoothing the connections process, the investment impact of which depends on details yet to be announced.

Ultimately battery investment comes down to numbers.  Quantifying battery project risk/return involves a ‘revenue stacking’ problem.  In other words revenue is aggregated across co-dependent revenue streams.  In the UK there are three key components that make up battery returns (listed in order of importance):

  1. Frequency Response: The UK rapid FR market has historically been dominated by the 2GW First Hydro pump storage assets. This market currently presents a lucrative source of returns for batteries which can provide even faster response than pump hydro.  But the supply & demand dynamics in the FR market are complex and depend on the pace of roll out of batteries vs wind.  Returns are likely to be volatile and there is a risk that battery rollout outpaces system requirements, driving down FR returns.  The policy implications of the SNaPS review are also key.
  2. Capacity Payments: 15 year fixed price capacity agreements were very attractive in the 2016 capacity auction given battery storage derating factors of 96%. However the majority of successful batteries fall into the 0.5-1.5 hour duration categories that are most at risk from BEIS policy changes.  This impact may be partly offset however by rising capacity prices given negative policy impacts on peaker economics (e.g. reduction of the triad benefit).
  3. Other margin: Batteries can access a range of embedded benefits, focused on avoidance of demand side charges. But revenues depend on location and the key triad benefit is set to decline steeply by 2020. Batteries can also have specific opportunities from operation in the wholesale market, although this depends on duration and cycling costs.

Investors are running the numbers as developers raise capital for both existing and planned battery projects. The next UK capacity auction in Feb 2018 will be a key test for batteries under a rapidly evolving policy landscape. And while the UK may have a head start on battery deployment in Europe, other markets are rapidly catching up, particularly Germany.

Investment in flexibility: battery storage