Connecting the dots – the case for transmission PPPs in Africa
The African power sector has long had an intense focus on increasing generation capacity above other aspects, but in recent years we have begun to see a shift.
The climate for developing grid-connected independent power projects (IPPs) remains challenging and there has also been an increasing debate over supply and demand; the anticipated rise in demand has not materialized, even in jurisdictions where there has been an aggressive electrification drive and industrial growth.
This raises the question: should the development of IPPs be slowed down, or should there be a concurrent focus on how best to deal with the apparent power surplus? The latter has to be the right answer. If so, the question then becomes: how can power best be moved from areas of low demand to high demand, and can these power surpluses also be used to develop regional power pools?
Implementing Transmission PPPs
Transmission and interconnection projects in sub-Saharan Africa have historically been procured directly by governments, through sovereign debt or concessional funding structures. With the demand for these projects increasing, and with the additional pressures on government finances exacerbated by the COVID-19 pandemic, it is an appropriate time to consider how the private sector can participate more efficiently.
One possible approach for African governments is to use a PPP model. Transmission infrastructure PPPs have been successfully implemented on a PPP / project-finance basis in other developing markets, in particular in Latin America and South Asia. In India alone, there have been approximately 56 privately-financed transmission projects in the past 15 years, with a total investment exceeding US$10.5 billion.
The development of transmission PPPs in Africa can accordingly benefit from the structures that have been successful in such markets. A key example of this is the payment structure: each these markets has adopted an availability-based model, where the tariff for the transmission of power is determined by the available capacity of the asset rather than the amount of power carried over the system. This leaves demand risk with the procuring authority and ensures that the project developers are paid for matters largely within their control, namely the design, construction and energization of new transmission assets and maintenance of a reliable operating capacity over a long-term period. Deductions will be made for unscheduled outages within the developer’s control, while appropriate relief can be given for supervening events such as political force majeure events or disruptions arising from the operation of the wider network, creating a fair and balanced risk regime. The use of a DBFM model in a PPP procurement can also allow the design to be optimized to reduce not only construction but also long-term maintenance costs.
Unbundling of transmission operations
In many African jurisdictions the state-owned electricity supply company will also be the holder of the transmission licence or otherwise have the responsibility for operating and maintaining the transmission system (referred to here as the transmission system service provider or TSP). In this case, the costs of operating and maintaining the transmission system and transmitting electricity are usually hidden costs embedded in the overall retail tariff, rather than being separated into a specific transmission system usage charge.
In some countries, transmission has been unbundled to a separate state-owned TSP which is entitled to receive a distinct transmission usage charge set by the power sector regulator, but where the supplier and TSP are both state-owned entities, there may not be a reliable history of payment between the two, and the TSP may in practice fall in priority below the supplier’s more “commercial” payment obligations, such as PPA obligations owed to IPPs. When coupled with budget management decisions being made for political reasons, this can lead to poor and haphazard transmission system management and planning.
In order to support the development of transmission PPPs, it will be necessary for transmission charges and their funding sources to be ring-fenced and carefully regulated, enabling the TSP to have a strong and predictable revenue source. The TSP needs to be seen as a viable contract counterparty, able to satisfy fixed payment obligations on a monthly basis under a long term concession, and therefore capable of being banked by the types of lenders that would usually finance IPPs with limited government support.
As well as focusing on the creditworthiness of the state-owned TSP, there may be an urgent need for improvement of capacity so that the TSP can conduct robust system planning to allow it to identify those transmission assets which are capable of being developed on a sustainable PPP basis, and then confidently develop and implement these projects with the private sector through bilaterally negotiated pilot projects and/or public tenders.
The role of the regulator will also be important in ensuring that the revenue flows into the TSP from suppliers are aligned to the TSP’s obligations under the transmission PPPs, recognizing that these payment obligations may change over time to reflect changes in law or changes in specification.
Risk profile issues on transmission PPPs
On an IPP, the developer’s risks will generally be limited to the boundaries of the project site. On a transmission PPP, there is no single site, and therefore typical project risks such as land rights, environmental and social issues and ground risk are amplified. That said, certain aspects of the risk allocation will align with how such risks are treated on an IPP, for example in respect of interconnection risk and synchronization with the main grid.
Acquisition of suitable land rights is a notoriously difficult part of transmission project development in Africa. The cost and process for acquiring land rights and wayleaves, and the relationship between the land rights secured and the design and optimized route for the transmission assets are one of the key issues to get right on a transmission PPP. Careful thought is required here for the appropriate allocation of risk. There may be some activities that the TSP is mandated to implement (such as compulsory acquisitions) or is able to handle more cost effectively or sensitively (such as dealing with communities), and while a private developer may have deeper pockets to solve wayleave issues more quickly, this may create a bad precedent for other deals. Use of compulsory acquisition laws may take longer to resolve, but the TSP may have more experience of managing this process and be able to do this more cost effectively than a private developer. All of this must be balanced against environmental and social considerations, which will be top of most funders’ concerns.
One issue that this presents for transmission projects is that the development of the design and the process of land rights acquisition may need to proceed in parallel to obtain the most suitable balance between project cost and speed of development. This may mean that a two-stage process is more appropriate, with the first stage involving the selection of a partner to finalize the design and route and allow the price to be finalized, at which point the long-term financing can be confirmed and the full PPP terms can be agreed.
And on to interconnection
If a transmission PPP can be done successfully, then this would pave the way for a successful interconnection PPP. From a systems and market perspective, this would enable an increased flow of electricity across the grid, enabling a well-functioning system operator role and a power surplus that is capable of being traded. From a process and documentation perspective, transmission PPPs could create a robust template for cross-border interconnection projects.