Battery Energy Storage Key Drivers of Growth

Despite the fact that no two grids are identical, as the proportion of renewables increases in the energy mix of electricity networks around the world, balancing the supply and demand of electricity is emerging as a common challenge for network operators. In recent years many developers have turned to lithium-based batteries. Great Britain (GB) has been at the forefront of deployment of utility-scale battery energy storage systems (BESS) as a potential solution. In this article we set out the three factors that have been key to making BESS projects commercially viable, beyond the decreasing costs of technology: (1) we shine a spotlight on the National Grid ESO¹ 's innovation when it comes to revenue stacking, being the first factor, (2) we explain how the permitting rules were updated to level the playing field for BESS when compared to traditional generation, and (3) we go over the latest changes to the network changes.

1. The ability to stack revenues

For the vast majority of BESS projects, the revenue required to be economically viable can only be achieved through so-called "stacking". In other words, BESS projects need to generate money across different markets or by delivering two or more services simultaneously.  This mixing of revenue streams is possible in GB because of well-developed markets existing alongside each other with clear rules of how they interact. Below, we dive into how the GB frequency response, trading and capacity markets function, as these impact the biggest share of the revenue pie for BESS and go towards the bankability of the projects.

A. Frequency response (aka Ancillary Services)

Fundamentals: Different parts of the world use different terminology when it comes to frequency response but the fundamentals remain the same. Stability of the electricity grid depends on the frequency of the system remaining constant at all times (in GB, the target is 50Hz). This requires a near-perfect real-time balance of supply (generation) and demand (load). If demand is greater than generation, system frequency falls. If generation exceeds demand, frequency rises. Frequency deviation or its rapid change can lead to equipment damage and brownouts or blackouts. Preventing this is one of the ESO's roles. In GB, NGESO procures frequency response services, being one of a number of different ancillary services procured by NGESO. There are two main types of frequency response:

• pre-fault which is a constant fine-tuning that takes place to prevent deviations in frequency, and
• post-fault, actions that take place after major deviations, such a generator tripping off the system.

BESS are well suited to the frequency response market because they are able to provide frequency services very fast with high accuracy that satisfies the stringent technical requirements.
Over the last couple of years NGESO has introduced a new suite of frequency response services. They are made up of Dynamic Containment (DC), Dynamic Regulation (DR) and Dynamic Moderation (DM). These are stackable with other revenue streams, though not yet with each other. The aim is for DC, DR and DM to eventually replace the Firm Frequency Response (FFR) as faster, closer to real time services. FFR relies on a response within 30 seconds and is a monthly tender.

DC service is designed to operate post-fault. It requires participants to provide power in under one second when the frequency deviates from 50Hz by more than 0.2Hz. DC was initially launched as a day-ahead auction with provision over the following 24 hour period. The contract length has since changed to four hour EFA²  blocks. This is true for DR and DM too. This sends more accurate pricing signals and provides the assets with greater flexibility to participate in both frequency response and wholesale trading and balancing mechanism. DC is an unbundled product: assets can separately sign up to provide when the frequency falls too low and when the frequency goes too high. This gives assets different options for generating revenue. The services evolved from pay-as-bid to pay-as-clear³  which minimises the need for forecasting auction results.

Unlike DC, DM and DR require providers to both increase and decrease output to maintain frequency at 50Hz within ±0.2Hz boundary. DM requires response within one second to be sustained for at least 30 minutes. DR requires response within ten seconds to be sustained for at least 60 minutes. Given the high level of energy required for the continuous operation in DR, DM is a better match for batteries as a service. Eventually NGESO intends for the three services to be capable of being stacked together. That is, a single battery being able to deliver different services simultaneously but with each MW partitioned to provide a single service. At the moment, BESS still has to choose one service at a time.

Market backdrop: Increasing reliance on renewable power generation and decreasing use of traditional synchronous generators will result in lower system inertia (i.e. frequency will change more quickly when subject to a shock, like a sudden loss of generation or demand). Therefore, faster post-fault services are needed to ensure that the frequency is contained. Equally, there are challenges to managing imbalance during normal operation that renewables joining the grid bring with them. Any sudden weather changes may affect the supply of renewable generation. The less predictable pattern of supply and demand results in more variable imbalance.

It should be noted that whilst the frequency response markets can provide a steady income stream and are the main source of BESS income for a lot of assets, these markets are not very deep. Their size is dependent on the level of forecast inertia (which itself depends on seasonality) and the largest single generation loss on the system failing. Once frequency markets are oversupplied, BESS projects need to expand into the wholesale markets. This is because saturation of the markets results in lower prices due to the small size of these markets.

B. Trading in wholesale markets

Fundamentals: Asset optimisation involves buying (charging) and selling electricity (discharging) to capture a spread between the high and low electricity prices on any given day. Since the change to the DC procurement rules to 4-hour blocks, the opportunity to step out of frequency response has increased significantly. Power trading could offer higher payments than ancillary services, depending on market conditions at the time. However, there are also higher costs associated with faster degradation of the battery if it is used for arbitrage. This is because participation in wholesale markets means higher levels of cycling (number of full charges and discharges). Asset owners need to be careful not to invalidate their manufacturer warranties which usually have a daily cycling limit. This risk sometimes makes its way into covenants asked for by lenders because lenders want to limit the number of cycles to ensure battery life and operation and maintenance costs are consistent with the financial model.

Another challenge of wholesale trading for BESS is the battery duration. A longer duration battery is better suited to trading on the wholesale market. However, the longer the duration, the more expensive the battery. The capex margin between short and long duration battery systems is expected to increase in the near-term as raw material prices increase. It will be some time before the supply of these materials will catch-up with demand (demand being driven in large part by electric vehicles). In this context, it is worth mentioning that the supply chains have been getting a lot of focus also in the context of ESG. Increasingly, investors push for robust legal frameworks to require companies to undertake supply chain due diligence to identify and mitigate ESG risks with particular focus on modern slavery. This applies in particular with respect to the supply of lithium which is often mined in countries which are high on the modern slavery watch list. Increasingly, BESS project developers are also required to address issues relating to the recycling of batteries.

Market backdrop: Batteries exploit spikes in pricing and are reliant on the market remaining volatile. As penetration of renewables increases, the wholesale market price becomes more volatile, as price fluctuates between periods of high renewable output (with low prices) and low renewable output (with high prices). This fluctuation occurs because GB wholesale market has one national price and the cost of the most expensive generation asset (usually gas) sets the price. Given the weather patterns, renewables suffer from price cannibalisation. The wholesale market price is then driven down towards their short-run marginal cost. This cost is close to zero, because wind and sun are free. This market design is a familiar sight across Europe. Whether or not it is here to stay will be debated heavily as winter approaches. In a recently launched review known as REMA⁴  the UK government is reviewing all aspects of the design of the GB wholesale electricity market. One of the options under consideration is nodal market design which NGESO is in favour of⁵.

C. Trading in the balancing mechanism

Fundamentals: the GB market is based on bilateral trading between generators, suppliers, customers and traders. It operates on the basis of self-dispatch: generators are responsible for dispatching their portfolio to meet their declared position but are otherwise free to generate in line with their contractual commitment or market conditions. The wholesale day-ahead and intraday markets exist to facilitate changes to the declared positions and generators can change their position up until gate closure (one hour before real time).

After gate closure, the ESO uses the balancing mechanism as the last opportunity to align generation with demand and manage system constraints. This may be necessary, for instance, if suppliers have forecasted their electricity requirements incorrectly, a generator is unable to generate the contracted amount or there are problems with transmitting electricity. The ESO instructs (or dispatches) market participants to increase or decrease their generation or consumption. It does so on the basis of data that participants with additional capacity or an ability to consume more or less power at short notice provide ahead of time, such as a set of available volumes and prices for bids (proposal to buy power) and offers (proposal to sell power), as well as technical data such as ramp rates e.g. how quickly the unit can alter its generation or consumption. This submission is known as Physical Notification. The costs of operating the system incurred by the NGESO are recovered through the balancing services use of system (BSUoS) charges. Currently BSUoS charges are calculated daily as a flat tariff for generators and suppliers, but from 1 April 2023 generators will no longer be liable to pay BSUoS charges.

If a participant is in imbalance of its contracted volume, meaning the volume of generation or demand does not match the position declared, it is subject to imbalance charging at the System Price per MWh, as follows:

• if a participant has generated less power or used more power than it said it would, it has to buy that shortfall at the System Price;
• if a participant has generated more power or used less power than it said it would, it has to sell that extra power at the System Price.

The System Price reflects the cost that the NGESO incurs in balancing the system.

If BESS does not participate in the Balancing Mechanism, it does not have to declare its position in advance. It can charge or discharge at the System Price, once it is clear what the System Price might be, noting that the System Price for a settlement period will only be determined after the event.

Market backdrop: in GB, the Balancing Mechanism in large part is used to manage network constraints. When the network does not have the capacity to physically transfer the power from one region to another, certain generators are asked by the NGESO, via the Balancing Mechanism, to reduce or "curtail" their output, while assets in another part of the network are asked to increase generation to replace this output. The redispatch function performed by the NGESO is getting increasing attention both in the context of rising costs of energy and the Government's target to decarbonise the electricity grid by 2035. A large proportion of renewable generation is located far from demand (offshore in Scotland for instance). Its build-out has outpaced network reinforcement, leading to high costs of the balancing actions undertaken by the NGESO. NGESO reports that annual transmission constraint costs increased eight-fold from £170 million in January 2010 to £1.3bn in January 2022⁶ .

So far batteries have not played a big role in the Balancing Mechanism. Being skipped over in favour of other plants is becoming a controversial topic within the storage space. The ESO's decision making in picking out the plant to deliver in the Balancing Mechanism is complicated but there are a couple of factors that could be at play when it comes to favouring other plants over BESS. Given the smaller sizes of BESS projects, it could be that the NGESO prefers to dispatch one big plant rather than picking a larger number of BESS projects simultaneously to make up the missing generation. The other factor could be location. As mentioned, BM oftentimes is used to solve network constraints meaning locational preference is a factor to consider.

It seems likely that BESS participation in BM will be getting more attention going forward. In part, because batteries could bring the costs down by increasing competition. Beyond the high costs, the current re-dispatching has the issue of carbon intensity. When renewable assets reduce their output because the network is constrained, rather than because demand is low, other assets must increase their output to ensure the system remains balanced. Historically, wind generation has been curtailed and the replacement generation has predominantly come from unabated gas and coal power stations. While it is difficult to determine whether BESS has used a renewable source of energy for charging (unless it's co-located), its operation is "greener" than that of a gas plant.

D. Capacity market

Fundamentals: GB uses the Capacity Market (CM) to ensure there is enough generation to meet peak electricity demand by paying for availability, thereby encouraging investment in new capacity or for existing capacity to remain open. Holders of CM contracts are obliged to stand ready to generate during period when NGESO identifies a risk that there will be insufficient supply to meet demand. The main auction is four years ahead of first service delivery with a smaller auction one year ahead of delivery which aims to plug the gap where more capacity is needed than anticipated. "New-build" projects are able to benefit from index-linked contracts of up to 15 years, whereas existing generation assets or refurbished are only awarded one or three year contracts, respectively.

For a BESS project one of the CM's most important elements is that of de-rated capacity. A technology's de-rating factor is designed to be reflective of the contribution that technology can make to security of supply. Technologies that can be relied on to be on the system when needed receive a much higher de-rating factor than a non-dispatchable intermittent technology. For duration limited storage (i.e. batteries), the de-rating factor applied is directly linked to the duration they are able to dispatch. All CM participants will have their nameplate capacity multiplied by their relevant de-rating factor to give a "de-rated capacity". It is this capacity that is entered into the auction, and that participants' availability payments are based on. This revenue is stackable with other streams.

Market backdrop: The CM T-4 auction for 2025/26 cleared at an all-time high of £30.59/kW/year⁷ , a marked increase on the previous year's result of £18/kW/year. BESS were at over 1GW (or 3.3GW nameplate), an increase of approximately 800MW compared to last year, with an increase in 2-hour-plus batteries participating. The record CM clearing prices can be attributed to the gradual decommissioning of fossil-fuel energy sources, closing nuclear power and global shortage of gas. While CM revenues are a small slice of the pie, for the moment it is the only stable long-term revenue stream for (new build) battery storage. As the focus shifts from shorter one-hour duration systems to closer to four-hour duration BESS with higher derating factors, the CM as a source of revenue may become more important.

E. Concluding thoughts on BESS revenues

As can be seen, a sustainable BESS revenue model requires continuous careful optimisation. The complexity of stacking can be difficult for funders to get comfortable with due to the short-term and unpredictable nature of the revenue streams. Participation in these projects requires understanding of the broader picture of energy transition.

"Renewable projects are traditionally underpinned by fixed contracts, yet the inherent volatility of such renewables leads to an imbalance in the provision of green energy, creating a demand to smooth that volatility curve that batteries are well placed to serve. From a lending perspective it is appropriate to look at non contracted revenue streams in the broader macroeconomic picture of transition finance, whilst understanding the stochastic modelling of forecast income based on the various alternate scenarios that can arise from legislation and speed of transition. It is also important to note that the UK in particular needs to increase battery GW capacity to keep in line with the planned expansion of Solar and Wind. Therefore, understanding the makeup of these non-contracted revenues and structuring debt to appropriately mitigate risks at a sensible leverage level is critical."

Jacob Lloyd, Head of Specialist Asset Finance at NatWest

What is clear is that investment in a BESS project is, in part, a bet on the trading capabilities of the asset manager and the optimisation software. It is important to remember that going forward, market volatility will most likely be a key piece of the puzzle, rather than a cherry on top of fixed revenue streams. Understanding how dependable such volatility is, and consequently how bankable, is crucial.

"Automation is now the backbone of trading activity for BESS, as batteries can respond in split second increments that can be harnessed by technology. To make battery projects profitable, it is crucial that asset owners work closely with optimisers to ensure revenues are maximised during the projects’ lifetime. Because batteries can provide services and value in a variety of different scenarios, revenue maximisation can be achieved through a combination of algorithmic intelligence, rapid transitions between services as the grid’s needs change, and competent traders identifying unique opportunities and strategies. Today, much of the revenue for batteries comes from ancillary services but the need for these services is limited, so optimisers and their technology must be capable of participating in in wholesale and real-time markets as they become a key—if not primary—source of revenue."

Rimshah Javed, Business Development Manager at Arenko Group

2. Streamlined planning consent process

In 2020, planning reforms removed electricity storage (except pumped hydro) from the Nationally Significant Infrastructure Projects (NSIP) regime in England and Wales and also removed the requirement for consent under s.36 of the Electricity Act 1989.

This means that developers of electricity storage projects above 50 megawatts (MW) in England and 350 MW in Wales can apply for planning permission for such schemes instead of having to apply to the Secretary of State for a Development Consent Order (DCO). The changes reduced the extra cost and time delays that the NSIP regime can often bring.

Being able to use the well-trodden planning application process incentivised the development of and investment into larger electricity storage projects and we are seeing a material increase in the number of BESS projects being developed in the UK.

3. Getting rid of double-charging

The third factor that we think contributed to the growth of BESS projects was the removal of double-charging when it comes to BSUoS charges. BSUoS is charged for each half-hour settlement period and then billed daily, proportionate to how much a given asset has used the system. Its purpose is to recoup the costs of the day-to-day operations that take place to balance the system.

If an asset declares itself to National Grid as a storage facility, it is exempt from BSUoS charges on its imported volume, both if it is transmission and distribution connected. This is a recent change. The reason this was previously an issue is that BESS projects paid BSUoS twice, both when importing and exporting, whereas generators usually have very low need for importing electricity (as it is only used for initial start-up or emergency scenarios) so only pay once. This change means therefore, that storage is no longer at a competitive disadvantage as compared to generation in having to pay more in BSUoS costs to deliver the same generation. The change also makes sense simply due to the nature of storage. The ability to import, store and discharge power on-demand makes storage the asset to provide help to the NGESO, regardless of whether the system is long or short.

This area is undergoing further reform. As mentioned above, from 1 April 2023 generators will no longer be liable to pay BSUoS charges. BSUoS charges will be recovered only from Final Demand which is defined as "electricity which is consumed other than for the purposes of generation or export onto the electricity network". The relevant Ofgem decision⁸  notes that levelling the field between large generators connected to transmission system and smaller distributed generators is likely to lead to an increase in the number of large generators. It further states that this may come at the expense of smaller distribution-connected battery storage, who do not pay BSUoS charges under the status quo arrangements and therefore do no benefit from the levelling of the playing field.

Conclusion

The fact that a battery storage project market developed without subsidy support meant that its business case is predicated on a mix of revenue streams. The optimal mix is ever-changing with constant shifts in strategy required. Any player in this space must be backed by a capable trading and optimisation team. The speed of decision making means that most rely on automation at least to some extent. GB has done well in allowing BESS to access a variety of markets and removing the obvious obstacles out of the way. This allowed BESS to fill the role of the provider of grid stabilisation services. The next challenge will be for batteries to fill the role of peaking capacity.

<sub>1. National Grid ESO is the system operator of Great Britain.
2. EFA stands for Electricity Forward Agreement. The EFA day runs from 11 pm until 11 pm. The day is split up into six blocks, each with a given number. Each block represents four hours of the day.
3. This means that all participants receive the price of the most expensive accepted bid.
4. The REMA process was kickstarted with the BEIS consultation "Review of electricity market arrangements" in July 2022.
5. Net Zero Market Reform by National Grid ESO, May 2022. In a nodal market, the price in each location in the network, a node, represents the value of energy at that location at that time. Currently, there is single national wholesale price across GB.
6. Net Zero Market Reform by National Grid ESO, May 2022.
7. NGESO's Auction Results published here.
8. CMP308 – Decision and final impact assessment, 25 April 2022.</sub>