In recent project document meetings with governments and utilities in Sub-Saharan Africa the message has been clear – what we are really interested in is solar PV with battery storage. Solar PV works for relieving pressure on hydropower during the day, but what about our evening peak demand? Whilst there is mild interest in solar photovoltaic (PV), there is a real eagerness to consider hybrid projects which combine solar PV with battery storage.
The dramatic fall in the cost of solar PV has impacted – for good and bad – the Sub-Saharan Africa renewables sector in the last three years. Similarly the recent and predicted cost reductions in energy storage and the wider deployment of battery (particularly lithium-ion) installations will make an increasingly strong impact on the renewables landscape in Sub-Saharan Africa as projects which were previously unviable due to high costs become economic. 2018 has been highlighted as the start of the global roll out of hybrid battery storage and PV systems – the point at which storage makes PV clever. From a financing perspective, it is important to consider hybrid projects as it is likely that a hybrid power plant will be successfully project financed in Africa before a standalone battery installation. This is because the revenue streams of the PV plant support a conservative banking base case, independent of the performance of the battery. This is a common lender risk mitigation strategy when a developer has an assortment of assets with different credit profiles. Lenders will run a sensitivity analysis to determine the cash flow available for debt service if the projected revenues from the battery fall away.
It is predicted that energy storage deployments in emerging markets globally will grow at over 40 percent annually in the next decade1. Grid connected hybrid battery storage and PV projects are in the early development stages in Africa. Those in the public domain are the Madagascar Scaling Solar 25MW PV with battery storage project, which announced six pre-qualified bidders in February 2018, and the 30MW PV and battery storage plant which is being developed by SB Energy Corp and Mara Corporation Limited in Rwanda. The battery storage evolution is happening sooner than anticipated in Africa as this technology forges its own path, responding to a clear demand propelled by technology cost reductions.
In developed markets, battery storage is being introduced retrospectively as flexible capacity, smoothing a high penetration of renewables and enabling the injection of more intermittent renewable generation in future. In Sub-Saharan Africa we have seen grid-connected renewables deployed at a far slower speed than in developed markets, as a result of challenges such as government support, grid stability, political risk, appetite for intermittent renewables, supply - demand dynamics and offtaker creditworthiness. At the same time, we have seen solar PV and battery installations advance rapidly at an off-grid and mini-grid level, meaning that battery storage is not a novel technology to Africa. The upshot of this is that there is potential for the deployment of battery and other forms of energy storage to work hand in hand with increased renewable penetration in Sub-Saharan Africa as the price of renewables continues to fall. If done properly, this would enable the relatively fragile African grid systems to accommodate more renewables, essentially adopting a renewables baseload. However, for battery storage to displace the conventional African forms of baseload generation – particularly distributed diesel generation, large hydro and thermal power – there are key challenges to overcome.
As power sector stakeholders in Sub-Saharan Africa gain awareness of the advantages of battery storage, interest in battery storage will cause more deployment, creating a positive feed-back loop which ultimately results in further battery cost reductions.
Battery storage is quick to be deployed, capable of responding in milliseconds to grid demands and improves the quality of the grid. When combined with solar PV it is capable of smoothing the generation output of the plant (maintaining the solar PV output curve on a daily basis and mitigating against forecasting errors) and providing solar time shifting (storing and releasing the PV plant output during the evening peak hours), alongside the pure battery storage ancillary services such as frequency regulation, voltage support, black start capacity, energy arbitrage and ramp rate control. Furthermore, the installation of battery storage within a transmission system would assist with easing transmission system congestion, which is a key obstacle to trading in the Southern African Power Pool.
Improvement of grid quality and reliability leads to fewer unplanned grid outages. This has two key economic effects on a typical state utility in Sub-Saharan Africa – firstly, the likelihood of a grid related ‘take or pay’ event triggering an obligation on the state utility to provide revenue relief in the form of deemed electricity charges under its power purchase agreements would be reduced, and secondly the propensity for large commercial and industrial customers to install on-site self-generation or captive sources of power could be mitigated. In markets such as Ethiopia and Tanzania where generation capacity is being scaled-up to drive industrial growth, but constraints remain around a fragile grid system, there is a clear role for energy storage technologies.
Outside of Africa there are emerging markets and island state examples highlighting the benefits of batteries and which are relevant in an African context. In Hawaii some islands require developers to couple any new generating facilities with batteries in order to stabilise the local grid. The Dominican Republic recently proved that battery storage assists in the event of an emergency response – as its grid remained operational during two hurricanes in 2017 due to 20MW of lithium-ion battery arrays which remained online whilst most of the generating plant suffered forced outages. Africa is similarly prone to climate change related severe weather – such as the widespread flooding seen in East Africa this year – and consequential grid outages. The effects of these could clearly be mitigated by the strategic installation of battery storage within transmission and distribution systems.
The Inter-American Development Bank has shown in a study in Latin America that, where renewable energy is combined with energy storage in certain emerging markets with high cost of conventional (i.e. diesel or HFO) generation, the cost savings of using increased renewable energy are higher than the cost of installing and maintaining the energy storage system. Sub-Saharan Africa is renowned for suffering from high fuel generation costs, particularly as a result of the installation of emergency power plants or poorly procured conventional power plants, and therefore this analysis could equally apply in Africa, making PV and battery storage plants viable from a pure costs perspective.
Finally, the deployment of battery storage facilitates the achievement of the emissions mitigation targets set under the Paris Agreement. When deployed strategically and used to store solar and other forms of clean energy, battery storage has the potential to reduce net GHG emissions by increasing the proportion of renewable generation injected into the grid system, thereby displacing the thermal plant which has traditionally stabilised African grids.
Ancillary services such as frequency regulation and voltage support are increasingly seen as high value services, and certainly in developed markets it is in the provision of these ancillary services that flexible baseload generation plants are highly remunerated.
In African independent power projects (IPPs) the monetisation of a PV and battery storage plant by the developer will usually be specified in the power purchase agreement (PPA), and not by reference to a market index or regulatory formula. We have seen various means of documenting the advantages of battery storage in offtake agreements in developed markets, with differing approaches to remunerating the battery storage services.
Certainly, a middle-way should be carefully chosen in the early stages of a PV and battery storage project, between the generator being fully remunerated for the services that the battery storage can perform and adopting a relatively simple revenue model which is fully understood by both generator and offtaker. This applies to the structure of how the battery is charged (purely from the PV plant or also overnight from the grid), to how the output is measured (whether the output of the battery is differentiated from the output of the PV plant and subject to separate interconnection and metering points) and to the tariff structure (whether the tariff is split between battery output and PV plant output). More complex and potentially lucrative tariff structures are likely to follow once familiarity is gained with the technology.
The revenue model will also be looked at closely by lenders as, if the PPA does remunerate the ancillary services that battery is capable of providing, a conflict may arise between the developer’s preference to stack the multiple revenue streams which may be earned from the PV and battery plant and maximise their return on investment (including relying on different income sources at different times of day or seasons) and the project financiers’ requirement for a reliable long term revenue stream to cover debt service (particularly important on earlier stage projects in new jurisdictions). Because battery storage technology is still seen as an early stage technology, it is expected that lenders in the first wave of projects in Sub-Saharan Africa will be development finance institutions, multilaterals and export credit agencies who are likely to take a conservative view. Innovations in the software supporting energy storage will also assist in maintaining a balance between profitability and predictability of revenue for PV with battery storage.
Potential relatively simple structures could involve treating the PV and battery storage plant as a plant which is subject to dispatch by the offtaker (splitting the tariff between a capacity charge and an energy charge). This is a familiar structure on African large hydro or thermal power plants,although the structure has some negative connotations in jurisdictions where state utilities have incurred substantial losses as a result of high capacity payments. This structure is a departure from the traditional PPA single tariff structure for solar PV in Africa as capacity payments are usually not appropriate for intermittent energy. The fundamental premise of a capacity payment is that it compensates a resource for the ability to generate when dispatched. The creation of “dispatchable solar” through co-location with storage can qualify a PV plant to a revenue stream that was once the exclusive purview of conventional plants.
Alternatively, a “time-of-use” pricing structure could be used, whereby the single energy charge of a PV plant could be maintained, with a higher tariff applicable to output exported in the evening peak hours than the daytime hours.
In developed markets the deployment of battery storage has often outpaced policy and regulation creating a ‘new frontier’ environment. For instance, the US Federal Energy Regulatory Commission has been uncertain whether to classify storage as a generating asset, transmission asset or hybrid of the two. Consequently battery storage parameters have often been incorporated in project documentation.
This is not new to Africa, where an absent or uncertain regulatory framework may often result in key risks and structures being documented contractually and in contemplation of a change in law in the future. We have seen this in jurisdictions where the grid code does not encompass renewables. In such instances, derogations from the grid code are documented so as to establish a day one compliant position, with subsequent changes to the grid code or other electricity regulations which affect the power project being governed by a change in law provision in the PPA or government support agreement.
The current regulatory view in Africa is that licensing is strictly split between generation, supply, transmission and distribution, similar to the way in which vertically integrated state utilities are being progressively unbundled. And therefore a conundrum will also arise as to how to regulate and license battery storage – either by adjusting the existing framework and/or creating a new battery storage specific framework. There is therefore a risk of retrospective regulation of battery storage in Africa as utilities and regulators grapple with this new technology, and early stage PV and battery storage plants come online before energy policy fully encompasses battery storage. We have seen this, to some extent, in the off-grid and mini-grid sector where regulation has applied retrospectively to issues such as the main grid subsequently connecting to the mini-grid, the permitting of very small mini-grid projects or a retrospective requirement to register diesel generators. Provided that time and resource are addressed to this issue at the project documents stage, the change in law clause is well drafted, and the regulator and Ministry of Energy are fully engaged with from a regulatory and licensing perspective, the impact of retrospective regulatory changes on grid connected PV and battery storage IPPs should be mitigated.
Aside from the contractual provisions, key to ensuring that regulators and state utilities are informed about battery storage is sharing of knowledge and capacity building. In this regard, both larger initiatives (such as the USTDA Kenya solar power and energy storage reverse trade mission last year) and technical workshops on specific projects play an important role in ensuring that the key business divisions are aligned as to how the PV and battery storage plant will operate.
Most grid scale energy storage systems are less than five years old. And, as with any new technologies, all stakeholders must get comfortable with the technology. Battery risk is increasingly being mitigated by a number of factors, including the increasing availability of extended (up to 10 year) contractual warranties, creditworthy suppliers, and the specialisation of firms in battery storage asset management to which battery performance risk may be passed through under robust operation and maintenance contracts. The strength of the operation and maintenance contract particularly assists with the expectation that the battery will require replacing approximately 10 years after the commercial operations date.
If the PV with battery storage plant is to be dispatched by the state utility, the PPA must contain clear parameters around dispatch so as to ensure that the depth of charge or other performance parameters of the battery are not adversely affected by the method of dispatch with a consequential risk that the warranty is invalidated.
Ultimately, the sizing and usage of the battery plant and the PV plant – both together and separately – must be driven by grid requirements and patterns. If grid studies and consequential plant sizing and modelling are exhaustively carried out on the early stage PV and battery storage projects, this will enhance the replicability of these projects and the trust in this technology.
- 1 IFC, Energy Storage Trends and Opportunities in Emerging Markets