Is battery storage commercially viable in the UK today?

My article for November assesses costs, revenues and financing to see whether utility scale lithium-ion batteries are commercially viable in the UK today. The current costs of £100k to £140k per MW per year and revenues (through EFR) of approximately £100k per MW per year suggest that batteries are just about viable. Asset owners are, however, unlikely to be factoring an adequate rate of return on their capital which is exposed to high uncertainty, which would likely be priced at an additional £50k per MW per year. Instead, owners are likely to be making strategic investments in the hope of gaining future advantage in the battery storage market.

1. Batteries are on the rise

The challenge to store electricity rather than consuming it immediately has led to a wide range of technical solutions: pumped hydro, chemical batteries (e.g. lithium ion), flow batteries, compressed air and storage (CAES) and flywheels. Each solution has different technical characteristics which determine its power, capacity and cycling / response time. Commercial viability, however, remains a difficulty for all solutions. The value of today’s storage technical capability is predominantly to:

• alter load profiles – shift the peak load of a system (Figure 1) which reduces a system’s need for generation and network capacity that is only used for a few hours each year; and
• stabilise the grid – increasing quantities of variable supply has created an increasingly unstable grid for system operators to manage. Batteries are well placed to help balance and maintain voltage at very short notice (<1 second).

Figure 1: Shifting system load profile caused by energy storage

Source: The Economics of Battery Energy Storage, Rocky Mountain Institute 2015.

The deployment of storage technologies (excluding pumped hydro) have risen from 0.5GW in 2006, to 4.5GW in 2015 (Figure 2). This trend is primarily driven by reducing costs. Improvements in revenue streams to monetise storage flexibility have also contributed.

Figure 2: Increase in energy storage capacity since 2000 (excluding pumped hydro)

Source: US Department of Energy, Global energy storage database.

2. Costs of battery storage today

At a global scale the costs of lithium-ion batteries has fallen in the past decade at a rate of 10 to 20% per year (Figure 3). Estimates from industry experts expect the cost reduction to continue at 10% per year.

Figure 3: Reduction in battery storage (Lithium-Ion) since 2005

Source – Nykvist and Nilsson, 2015,  Nature Climate Change – Rapidly falling costs of battery packs for electric vehicles.

The UK has built two utility scale (>1MW) lithium-ion battery storage assets. One of these is the Smarter Network Storage (SNS) in Leighton Buzzard built by UK Power Networks with 6MW power / 10MWh of capacity. The other is a 2MW battery built in Orkney built by SSE.

The total project cost of SNS is £16.8 million for an asset that can provide or use 6MW of power at any given time. 70% of these costs correspond to upfront capital expenditure and the remaining 30% are ongoing operating costs. The operators of SNS estimate that the adjustment from a ‘first of a kind’ (FOAK) project to a ‘Nth of a kind’ (NOAK) project reduces lifetime costs to £11.4 million, which corresponds to £1.9 million per MW. In addition, they estimate further cost reduction of the technology since the construction date would correspond to £8.5 million, or £1.4 million per MW.[1]

Translating these costs into an annual charge depends on the expected operating life of an asset. Estimates of technical capability vary between 10 and 15 years. This implies a cost range for utility scale lithium-ion in the UK today of between £100,000 and 140,000 per MW, per year.

3. Revenue sources to deploy battery storage flexibility

There are five key areas where storage flexibility can be monetized:

• Reserves – Capacity available to increase or decrease load for energy balancing, frequency and voltage control. Procured by the System Operator (SO). Annual revenues £25k to 100k per MW, per year depending on the reserve product;
• Capacity – Ensuring a system’s peak load requirements are met. Annual revenues of £20k per MW, per year;
• TRIADs – Avoided consumption during the top 3 half hour peaks during the year (historically between 5-6.30pm between Nov-Feb). Annual revenues of £35 to 50k per MW, per year;
• Networks – Reducing constraints within a distribution or transmission network to delay or avoid investment by altering the peak load profile. Annual revenues vary by location[2]; and
• Energy market – Price responsive load to wholesale market prices. For storage this means charging when prices are low and discharging when prices peak. Limited annual revenue opportunity based on SNS testing.

Creating a profitable storage business model requires the optimum combination of products to maximise revenues. Several products have technical and regulatory barriers to operating in simultaneously (i.e. to ‘stack’ revenues). For example, it is not possible to operate in the energy market while providing services to the frequency reserve market which typically requires 95% availability.

The UK System Operator, National Grid, recently launched a new product called ‘Enhanced Frequency Response’ (EFR). This product requires immediate load change (<1s) for a short duration (to 9 seconds before primary and secondary reserves start at 10 seconds and 30 seconds respectively) and was expected to be available for 95% or more of the time. Both requirements are well suited to the technical capabilities of battery technology. All EFR contracts last for four years.

The tender results (Figure 4), indicate a wide range in bids from £61k to £380k per MW per year. The winning bids ranged from 61k to £105k per MW per year. Given the stringent availability requirements, the only area possible additional revenue streams was TRIAD avoidance. Bidders had the choice to reduce their availability so that they could operate in TRIAD windows during the winter months. Only two of the eight winning bids chose to stack TRIAD revenue and reduce availability from 100% to 96%.

Figure 4: EFR Tender in Summer 2016 (storage bids for Service 2 (±0.015 deadband) ranked from low to high)

Source – National Grid, Enhanced Frequency Response Full Results.

The revenue streams of the winning EFR bidders (Figure 5) are low relative to estimates of current cost in Section 2, which ranged from £100k to 140k per MW per year. When TRIAD revenues are taken into account, six of the eight bidders are likely to recover costs at the low end of the cost range for the coming four years. There is then significant uncertainty for the achievable revenues for the rest of the asset life in order to recover the remaining costs and potentially achieve a return on capital for their owners.

Figure 5: EFR Tender winners in Summer 2016

Items	Capacity MW	Total revenue £k /year/MW	TRIAD hours exclusion?	Estimated total revenue £k /year/MW
EDF	49	61	FALSE	61
Vattenfall	22	65	FALSE	65
Low Carbon	10	67	TRUE	117
Low Carbon	40	s79	TRUE	129
E.ON UK	10	97	FALSE	97
Element Power	25	101	FALSE	101
RES	35	105	FALSE	105
Belectric	10	105	FALSE	105

Source – National Grid, Enhanced Frequency Response Full Results.

Notes – Estimated total revenue includes an additional £50k/MW/year for TRIAD inclusion.

4. Financing battery storage

Funding battery storage today is a high risk venture, even for winning bidders of the EFR because the infancy of the technology contains a large number of unknowns:

• Revenue – EFR may not be sufficient to cover costs and is only fixed for four years despite the asset operating for 10 to 15 years;
• Capital expenditure – large ‘first of a kind costs’ which SNS estimated was 47% of actual costs. This is potentially mitigated through fixed price EPC contracts, if available;
• Operating expenditure – limited knowledge today of ongoing operating costs to run and maintain battery storage assets. This is potentially mitigated through longer term operation & maintenance contracts, if available;
• Technical delivery and availability – limited / untested asset availability and capability to deliver at very short notice over the long run; and
• Asset life – wide range of asset life estimates and uncertainty surrounding asset degradation over a large number of charge cycles.

Such risks would require a high rate of return on capital in a market funded venture, potentially 10 to 20%. Financing costs at 10% for a 10 year project with capital costs of £850,000 per MW would cost a further £500,000 per MW, or £50,000 per MW per year.

It is important to note that the winning EFR bidders were typically large companies, like EON, EDF and Vattenfall, who were able to fund the projects through their existing balance sheet. These players are likely to be willing and able to incur small losses on initial assets in order to learn and develop internal capabilities. This could provide future strategic advantages to these first movers.

It is unlikely to see players without balance sheet initiate projects of such a scale because of the gap between pilot financing through grants and project finance for fully commercial projects. In the medium to long term finance becomes increasingly viable if:

• Costs continue to fall at coming down 10% per year;
• Uncertainty about operating costs, asset life and technical delivery is reduced because of battery storage learning from FOAK projects; and
• Increasing flexibility value caused by growing variable generation.

In summary, batteries are commercially viable today with costs of £100k to £140k per MW per year and revenues through EFR of approximately £100k per MW per year. Asset owners are, however, unlikely to be factoring an adequate rate of return on their capital which is exposed to high uncertainty, which would likely be priced at an additional £50k per MW per year. Instead, owners are likely to be making strategic investments in the hope of gaining future advantage in the battery storage market.

 

Footnotes:

[1]        Corroborated by a recent estimate of capex of £850,000 per MW (Elexon, 2014, Storage business models in the UK), which corresponds to a total lifetime cost of £1.2 million per MW.

[2]        The SNS avoided a traditional network reinforcement which would cost £5.1 million. Therefore, the avoided cost was 850k per MW which corresponds to 28k per MW per year over a 30 year lifetime of the traditional asset.