The last couple of months have seen some interesting newsflow in relation to electricity storage. Storage projects are increasingly popular, with developments occurring at every level of the system from grid-connected utility-scale projects to behind-the-meter domestic storage, and the Government together with Ofgem is keen to remove barriers to entry to allow storage assets to access the market more competitively.
In its recent Future Energy Scenarios report, National Grid outlined that it expects storage growth to continue at a high rate to the early 2020s in each of its four future scenarios, driven by a fall in the cost of relevant technologies, ICT advances allowing better communication and control of assets, the growth in EVs, and the emergence of commercial opportunities.
In common with most market participants, National Grid assumes that storage needs multiple sources of revenue in order to be viable, including balancing and ancillary services revenues, asset services for Distribution Network Operators and Transmission Owners, and wholesale arbitrage opportunities. Storage is expected to often be co-located with renewable generation, to minimise capital and network costs and reduce the need for buying from the grid for charging.
Market saturation for storage is predicted to occur at different times in each scenario, beyond which cannibalisation occurs, meaning that projects are less likely to be economically viable.
Last year, National Grid was predicting storage levels of 18.3 GW of storage by 2040 in its highest-storage scenario. Marcus Stewart, National Grid’s head of energy insights explained the reduction is down to improved modelling in this year’s analysis:
“Last year was the first year we included battery storage in the scenario modelling and we had a reasonably simplistic approach. This year we’ve built on that and improved the modelling in that area, so the values we’ve calculated this year are lower because we’ve looked at the arbitrage value and if you go to a theoretical maximum, you start to see the cannibalisation of revenues.”
The regulatory landscape for storage is changing
Introducing a regulatory definition of storage
Ofgem has confirmed plans to clarify the licensing regime for electricity storage by classifying it solely as a form of generation, launching a consultation on its plans, saying:
“We consider that the existing electricity generation licence is best placed to clarify the regulatory framework for storage. This is because generation and storage share similar characteristics and perform similar functions in terms of generating and exporting electricity to the grid, and because a modified generation licence is the most practical way of providing regulatory clarity.”
Ofgem intends to introduce a new licence condition into the generation licence requiring storage providers to ensure that they do not have self-consumption as the primary function when operating a storage facility.
One of the regulatory challenges faced by storage has been the lack of a legislative or regulatory definition of electricity storage, resulting in a lack of clarity when storage interacts with other legislation and regulations. The Government plans to amend the Electricity Act to include a definition of storage as a distinct subset of the generation asset class. In the meantime, Ofgem is using the following definition in a modified generation licence for storage:
- Electricity Storage in the electricity system is the conversion of electrical energy into a form of energy which can be stored, the storing of that energy, and the subsequent reconversion of that energy back into electrical energy.
- Electricity Storage Facility in the electricity system means a facility where Electricity Storage occurs.
Ofgem proposes adding these two definitions to the electricity generation licence and to make relevant changes throughout the licence adding “electricity storage” or “electricity storage facility” where appropriate, and is consulting on whether the phrase “in a controllable manner” should be added to the definition of electricity storage.
Double-counting of final consumption levies
Another barrier storage facilities face is having to pay the cost of final consumption levies – specifically the Renewables Obligation, Feed-in Tariffs, Contracts for Difference and the Capacity Market. Storage providers are charges these levies when the storage facility consumes electricity in the charging phase, however, when the electricity is discharged for delivery to consumers, they are also charged levies on the same electricity – a double counting which reduces the competitiveness of storage.
Ofgem wants to ensure that the cost of final consumption levies are allocated fairly and proposes introducing a new licence condition – Condition E1 – that requires the primary function of the storage facility to export electricity back to the distribution system or to the national electricity transmission system, ie not to have net internal electricity consumption as its primary function.
This would prevent the storage facility from being an end consumer, thereby avoiding paying the final consumption levy costs. If the storage facility’s primary function is not to export to the distribution or transmission system, then such facility will not be classified as storage for regulatory purposes and would be subject to final consumption levies.
Restrictions on DNOs operating storage
Ofgem has also launched a consultation on its plans to prevent distribution network operators (“DNOs”) from operating electricity storage, because they believe that as DNOs are local monopolies, the ownership of storage would represent a conflict of interest that could result in market distortions:
“In the case of networks owning and operating storage, distortions or foreclosure have the potential to affect not just the uptake of storage by third party providers, but also the uptake of other forms of flexibility – such as demand side response (DSR) or other flexible generators – that provide the same or similar services in the same markets. This in turn has the potential to impact on other markets, including that for aggregation.”
Ofgem is proposing to introduce a new condition in the electricity distribution licence to ensure that DNOs cannot operate storage, however, it accepts here may be a small number of activities or specific circumstances, where a DNO operating a storage asset may be acceptable, including uninterruptible power supplies and emergency response and maintenance fleets:
- Uninterruptible power supplies are devices used at substations and other DNO sites to ensure critical equipment remains energised in the event of a system outage. These devices do not export electricity to the network and are necessary for the safe, efficient and reliable operation of the DNOs’ networks;
- Each DNO owns a fleet of small, mobile generator units of between 50 kW and 1.5 MW which are used in outage situations to keep customers on supply – storage units may be used for similar purposes. Ofgem considers that customers benefit from these applications through improved reliability and security of supply, and does not believe that these applications give rise to market distortions.
The proposals therefore include a mechanism for DNOs to operate storage with explicit permission from Ofgem in very limited circumstances, with the onus being on DNOs to make the case for approval, demonstrating the exemption is in the best interests of customers and would not inhibit competition.
The proposals will not prevent DNOs from owning storage assets, but they will not be able to operate them directly, except in the rare cases described above. In the majority of cases, operation of the storage facility would need to be carried out by an arm’s length subsidiary or affiliate.
Participation in the capacity market
In August, BEIS quietly launched a consultation into what it described as “essentially technical changes to CM Rules”, which nevertheless may have significant commercial implications. The reason for the proposals arises from concerns that the technical characteristics of batteries may be incompatible with the objective of security of supply in situations of system stress:
- Stress events may last longer than the duration of the battery;
- The declining performance of batteries over time reduces their contribution to security of supply;
- Some batteries may be less than fully charged at the start of a stress event if they are simultaneously participating in multiple commercial services.
BEIS therefore proposes breaking down storage technologies into a number of categories based on duration, eg 30min-1hr; 1hr-1.5hr storage; etc. Each class will then be assigned a de-rating factor that is proportionate to how much support they can offer in a system stress event with longer duration storage being rewarded with a higher factor.
Currently storage has a high de-rating factor of around 96% based largely on the good historical performance of pumped hydro. This means that if the proposed changes are adopted, short duration batteries will only achieve a proportion of the revenues they would have otherwise expected.
If confirmed, the changes will be implemented from next auction, scheduled for February 2018.
Use of renewable generation for charging storage
Last month, Ofgem announced that solar farms accredited under the Renewables Obligations (“RO”) scheme, will be able to claim RO Certificates (“ROCs”) for all renewable electricity generated, even if it is used to charge an energy storage system:
“We have determined that the arrangements in place at several commercial scale solar installations allow for ROCs to be claimed on all the renewable electricity generated, including any that is used to charge the storage devices.”
Ofgem expects to receive more applications from developers who have co-located storage alongside generation and wish continue to receive support under the Government’s environmental schemes.
Co-location with renewables
When wind and solar generation were first added to the grid, there was a lot of flexibility in the system in the form of thermal generation, particularly CCGTs. Over time, as the proportion of intermittent generation has grown, traditional sources of flexibility have been forced out by a combination of adverse economics and anti-pollution policies.
Grids are becoming increasingly difficult to manage, leading to renewed interest in co-location of storage projects with renewable generation in order to mitigate their inherent intermittency. Over the past few months a number of significant initiatives have been announced:
- Danish wind turbine producer Vestas Wind Systems has is working on 10 projects that will add storage to wind installations, and is collaborating with Tesla on at least one of those projects;
- Offshore wind developer Deepwater Wind has announced that it would combine a 144 MW wind farm planned for the coast of New Bedford, Massachusetts, with a 40 MWh battery storage system from Tesla;
- Spanish wind power company Acciona recently connected two Samsung lithium-ion batteries to a 3-megawatt experimental wind installation at Barasoain turbine in Spain;
- Dong plans to install a 2 MW battery on the UK coastline close to its 90 MW Burbo Bank Offshore Wind Farm;
- Statoil has announced Batwind – a lithium-ion storage project to sit alongside its new floating windfarm in Scotland;
- E.ON has recently started construction on two 9.9 MW short-duration energy storage projects in the US, co-located with existing windfarms in Texas.
According to this piece by the American Wind Energy Association, storage is helpful but not necessary for the integration of wind, primarily as it is often not cost effective.
“As the penetration of wind energy continues to grow, at some point in the distant future the amount of flexibility currently available on the grid may be fully tapped. However, there are innovative ways to utilise currently untapped sources of flexibility on the existing power grid that are less costly than new storage plants.
Demand response, in which large power consumers like factories briefly reduce their non-essential power consumption in exchange for lower electric rates, is already being used by several grid operators to provide a large amount of flexibility at very low cost. Improved grid operational procedures can make the scheduling and dispatch (or use) of power plants more flexible. The expansion of energy markets, as well as the creation of markets for flexibility itself, can create strong incentives for power plant owners to make their plants more flexible.
The occasional curtailment (reduction) of wind output can also be a very cost-effective source of flexibility. Finally, new flexible generation, particularly natural gas-fired power plants, can be added to the grid at low cost to provide enhanced flexibility. Thus, there appears to be a vast quantity of flexible resources that can provide flexibility at lower cost than energy storage.”
The piece also points out that many types of energy storage are poorly suited to offset the specific type of variability that wind energy introduces to the grid. Wind energy output has relatively low variability over the minute-to-minute timeframe, but can see significant changes in output over time periods of 30 minutes or more. Technologies such as battery storage, with typical durations in the region of 30 minutes, are not well aligned with the variability patterns of wind.
Earlier this year, Greentech Media reported on the new co-location trend, and noted that the benefits are not always clear. It cited a perceived lack of benefit at Bosch’s hybrid energy system at Braderup in Germany, and GE’s Brilliant turbine which came with integrated proprietary Durathon sodium nickel-chloride batteries, which subsequently “faded from the market”.
The speed with which new technologies are entering the system presents significant regulatory challenges. Various business models and revenue streams are available to project developers, but caution needs to be exercised since regulatory change can damage expected returns as well as create new opportunities. Sensible developers will anticipate regulatory change when designing their business plans and not assume that individual income streams will last for the length of the investment cycle.