Regulatory lessons learned
Approaches to defining energy storage within the regulatory framework
Experience in more mature power markets has highlighted the need for considered inclusion of energy storage within energy and fiscal regulatory frameworks. The nature of storage, in both charging and discharging electricity, may mean that a storage facility is treated both as a consumer and a generator of electricity within the traditional framework of existing energy regulations, which generally have a strict division of licencing into generation, transmission, distribution and supply. In Great Britain for example, this led to unintended consequences. Electricity storage facilities were subject to a double charge under the balancing and settlement code for both import and export of electricity. The stored power was also subject to double charging under levies applied to electricity consumption, as the charges were levied both upon supply to the battery and upon supply to the end user. In emerging markets, robust mechanisms in storage offtake or lease agreements could help to deal with the allocation of such levies or charges, both from day one and upon a change in law or tax occurring. But ultimately, regulators and host governments will benefit by not imposing additional costs on electricity storage through tax and/or regulatory charges that might otherwise distort the cost of stored electricity.
Recognition of the characteristics of an energy storage facility is therefore required in regulatory frameworks, to exempt storage from certain obligations or adjust these to accommodate its unique characteristics. However, in doing so, the definition of energy storage becomes important. In more mature power markets, debate has focused in particular on whether it is necessary to re-convert stored energy into electricity for a facility to constitute ‘energy storage’ for the purposes of electricity regulation, licences and codes. For example, the European Union (EU) Market Design Directive has adopted a wide definition of ‘energy storage,’ encompassing both reconversion to electricity or conversion into another energy carrier. The advantage of this approach is the opportunity for enabling new energy carriers, such as green hydrogen, green ammonia or green ethanol, produced by electrolysis using renewable power, to decarbonise other sectors such as agriculture, the industrial sector and transport. This is a broader definition than that proposed in some EU Member State markets, where the definition foresees only the reconversion to electricity.
Regulators in emerging markets may wish to consider future proofing their regulatory frameworks to enable the opportunity to use abundant solar and other renewable resources in the production of other new energy carriers (such as ‘spilling’ renewable electricity from a solar PV plant to make green hydrogen). However, this future proofing is possibly an unwelcome additional consideration for regulators currently grappling with how to regulate energy storage. Zambia’s Energy Regulation Act 2019 is a very recent example of the inclusion of energy storage as an activity for which a licence is required. But what exactly is meant by storage is not further defined, and in the definition of “licensee,” the Energy Regulation Act specifically refers to a holder of a licence in relation to the storage of ‘renewable energy,’ thereby excluding the storage of non-renewable sources of power from the scope of the licence. This creates doubt as to whether a standalone storage facility, rather than one which is co-located with a renewable source of electricity, would be eligible for, or require, a storage licence.
Ownership, control, revenue models and financing options
Another issue considered in mature power markets has been who should own energy storage assets. Should these be part of the grid network owner’s regulated asset base, or owned independently? In emerging markets, where a vertically integrated parastatal entity owns the majority of generation plants, and has a monopoly on transmission, distribution and supply, the more relevant question is whether energy storage assets should be tendered on an independent power producer (IPP) basis or be directly procured and therefore form part of the state’s transmission system. There is no right answer. Instead, consideration must be given to the function which energy storage system will perform in the market and to the optimal revenue model for the storage system.
In mature markets storage systems have been used to arbitrage price differences in the power trading market. In this function they have traditionally been independent of grid network ownership. This has formed the business case for pumped hydroelectric storage in a number of mature markets for decades. In emerging markets, given the lack of liquidity in power trading markets and reduced price volatility, the often fragile grid infrastructure and increased vulnerability to natural disasters, the role of an energy storage system will more often be to enhance grid stability.
In both emerging and mature markets, storage systems are providing services such as balancing, capacity, frequency response, demand response and black start. Storage systems (both standalone and co-located) may also be used to defer or avoid grid network upgrades, especially where the upgrade is only necessary to relieve constraints at certain times of year. In more mature, liberalised markets, regulators and system operators have, in some cases, designed structures to remunerate these services, with storage assets being paid for providing a number of different services, ‘stacking’ revenues in order to build a viable business case. This can prove more challenging in emerging markets where there is often a lack of remuneration or financial incentives for ancillary services.
Alongside the issue of ownership, is that of control. Usage is directly related to the life-cycle costs of the storage system, particularly for battery storage systems, and manufacturing warranties will often require certain operational parameters are respected. In more mature markets, usage will be determined by the storage operator on the basis of price signals, market mechanisms and technology operating parameters. However, in emerging markets, it is generally appropriate that the risk of how the storage asset is used over time is allocated to the grid system operator because their influence on the storage system (directly or indirectly) is greater. Changes on the grid network dictated by the transmission system operator may significantly change the usage requirements of the storage system. In such instance, for an IPP, it would be necessary to agree a duty cycle with the grid system operator, with deviations leading to changes in the cost of the service.
The tariff structure for the IPP (whether under an offtake agreement or a form of lease agreement) is also relevant to influence usage and requires consideration – for example whether the tariff structure should drive the utilisation of the battery which would be otherwise controlled by the IPP, for example, through a time of use tariff structure, or whether a split between an availability/capacity payment and an energy payment would be sufficient remuneration for where the network operator or utility controls the battery utilisation.
The choice of ownership model is also intrinsically linked to the revenue support for storage assets. If a storage asset sits within a network owner’s asset base, it will be incentivised through the network owner’s regulated revenues. This often means a lower cost of capital and allows the network operator full control over the storage asset. However, under this model, price discovery is low and there is a risk that consumers are over-charged for storage services, particularly if there is no institutional experience of procurement of the relevant services. Under an IPP model, as discussed above, the scope of services will need to be more clearly defined.
Ownership and revenue models also have a significant influence on the methods of financing storage systems. Where the storage system is financed through the network owner’s regulated asset base, debt or grant funds will be procured via the network owner (direct corporate loans or bond issuances), or on-lent from the state treasury if the network owner is state-owned. Lenders will look to the credit-worthiness of the network owner (or the state) as the primary means of repayment. Under an IPP model, a project finance model, where lenders look to the future revenues of the project company as the primary source of funds to repay the debt, may be more appropriate. To date, most storage systems globally have been financed using equity and government grants, rather than on a limited or non-recourse basis.
However, project finance may be appropriate in certain circumstances, for example where corporates or utilities are able to monetize cost savings by installing storage systems. A business case which is gaining traction, both in off-grid industrial applications and in island networks, is the combination of solar PV and battery storage to replace fossil-fueled peaking plant. In emerging markets there are compelling grounds for displacing imported diesel generation. Therefore the rationale for the deployment of storage systems is both environmental and economic. However, in many emerging markets, particularly in small island states, that the creditworthiness of the utility and host government may be insufficient to facilitate lower cost, debt funding. These issues need to be addressed using conventional mechanisms, including multilateral and/or development finance support, political risk insurance and similar techniques applied to other forms of emerging market IPP projects.
Mobilising further funding into energy storage is one of the aims of the Climate Investment Funds’ Global Energy Storage Programme, which aims to mobilise over US$2 billion in concessional climate funds for energy storage investments in emerging markets – including through investment in demonstration or first of a kind projects and through regulatory and policy reform. However, whilst development finance institutions may get comfortable with financing storage projects, attracting long term commercial bank financing of energy storage on a limited recourse project finance basis is set to remain challenging in the near term.
Mobilising investment into energy storage businesses and projects will necessarily require the industry to address environmental, social and governance (ESG) issues such as safety, environmental and climate change impacts, supply chains and end of life strategies. ESG factors have long been an area of focus for development finance institutions (who are traditionally the main lenders in emerging markets), but are increasingly rising up the board agenda in every sector. From a commercial lender perspective, the updated Equator Principles, which come into effect in July 2020, are likely to refocus attention of participating financial institutions (for further information please see our article New version of Equator Principles launched).
In emerging markets, particularly, given vulnerability to ESG issues, the replacement of thermal baseload and grid reinforcement with battery storage cannot therefore be viewed in isolation of the battery lifecycle – from extraction of mineral raw materials through to battery demobilisation.
Mineral extraction and end of life issues for lithium-ion technologies are currently receiving scrutiny, as this technology is set to dominate battery deployment in the early 2020s pending the development of alternatives such as solid state batteries. Cobalt is the costly and the most sensitive mineral required for lithium-ion battery production from an ESG perspective. Global demand for cobalt is anticipated to double by 2025 and over 70 per cent of current cobalt supply is mined in the Democratic Republic of Congo3. This gives rise to concerns as to the implications of over-reliance on the DRC and the players in the supply chain from the mine until the materials reach the original equipment manufacturer. This is driving greater disclosure in supply chains and the development of alternative technologies for batteries; for example Tesla are seeking to minimise the usage of cobalt in their batteries4. Additionally attention must be focused on the wider environmental and social impact of cobalt mining and a heavy reliance on the DRC could exacerbate resource nationalism, as has been seen increasingly in resource rich African countries in recent years. Whilst not so extreme as cobalt, certain processes for extraction of nickel and lithium also raise issues from an ESG perspective.
At the other end of a battery life cycle, lithium-ion battery waste is forecast to be between one to four million tonnes per year globally by 2030 and no clear battery recycling supply chain currently exists. This equates to a potential material value of US$6 billion to be recovered from lithium-ion batteries by 20305. But recycling lithium-ion batteries is complex due to the many different components and elements combined in a typical lithium-ion battery and the risk of ‘thermal runaway’ – or rapid excessive battery overheating – that must be carefully controlled even after the battery is demobilised. Battery recycling is therefore both a challenge and an opportunity for industry. With increased pressure from an ESG perspective, we would anticipate seeing an further focus on demobilising and decommissioning of battery storage assets by both debt and equity investors in emerging markets.