The provision of a consistently reliable energy supply inherently requires that the generation, transmission and distribution elements of an electricity supply network are considered and hence also planned, designed, operated and maintained as part of an integrated system.
Whereas we are all aware of the challenges in generation, the capacity constraints and underinvestment over a long period on the South Africa electricity transmission network have also been known and reported on for some time. They particularly came to the fore recently when the wind projects bid under Bid Window 6 of the REIPPPP programme could not be awarded due to grid capacity constraints in the Eastern and Western Cape.
So, what then are the critical constraints on the South Africa transmission grid? They are multi-faceted and include the following examples.
In the first instance, and due to the historical concentration of generation capacity in the coal fields of the north-eastern parts of the country, the resultant geographic layout and capacity of the grid between there and the load centres is not aligned with the new generation centres associated with renewable energy. This is particularly severe in the western part of the country, where there are significant renewable energy resources such as wind and solar, and generation plants already operating and in the pipeline.
There are also congestion bottlenecks at various parts of the network, that limit power flow and lead to stability challenges. Integration of intermittent renewable generation also has implications in respect of grid flexibility and management.
In addition, various aspects and elements of the existing transmission network require significant and expensive upgrades, refurbishment and maintenance.
These grid challenges and constraints have contributed to renewable energy project delays and will continue to constrain new generation development and provision until addressed. This impacts on addressing load shedding and the clean energy transition, and the unreliable power situation in the country generally hinders economic activity, investment and growth, with the concomitant negative effects on employment, social upliftment and general societal well-being.
All of these present funding challenges to Eskom and the newly formed National Transmission Company. They also present, for example, challenges in respect of supplier and industry capacity to execute on the Transmission Development Plan.
To illustrate the scale of the challenges, Eskom’s Transmission Development Plan outlines the key need to add significant capacity to the grid by 2032, expanding the grid and integrating more generation including renewable resources. Amongst other actions, this will entail the building of approximately 14,000 km of new transmission lines. This is a substantial increase when contrasted with the 4,374 km of lines reportedly built over the last 10 years between 2014 and 2023.
So where to now?
Whilst the curtailment framework recently announced will bring some relief in the short term, it is critical and urgent that a sustainable solution be found and implemented.
Other initiatives to enhance and optimise the use of the existing grid have included, for example, the targeted implementation of Battery Energy Storage Systems (BESS), and Eskom’s auctioning off of land parcels around some power stations in Mpumalanga for the establishment of independent power producer (IPP) renewable plants. These are aligned not only with the just energy transition, but also with enabling use of existing spare grid capacity in the area – and although some estimate that spare capacity will be used up in the next 5 or so years unless additional capacity is added, these provide a key opportunity for ‘quick wins’.
Progress has (eventually) been made with the process of breaking up the vertical integration of Eskom into generation, transmission and distribution units, with the establishment of the National Transmission Company of South Africa (NTCSA), the granting of the necessary licences by NERSA and the recent appointment of its Board. The NTCSA will operate the transmission system and perform the integrated roles of Transmission Network Service Provider (TNSP), System Operator (SO), Transmission System Planner (TSP) and Grid Code Secretariat. The NTCSA is also intended to facilitate further opening up access to the network for additional and independent generators.
However, there are significant challenges in achieving these ambitious grid expansion goals. Apart from aspects such as obtaining environmental approvals and navigating land acquisition and/or access approvals, the challenge of securing funding is paramount. This is particularly so given existing debt burdens and financial constraints on the part of Eskom and the state.
An obvious answer is to enable private sector involvement and funding channels, and indications are that the government has come to this realisation as well, although navigating the path to a bankable and effective model requires careful consideration.
This has manifested by government recently announcing their intention to pursue a public-private partnership (PPP) model, such as a Built-Operate-Transfer (BOT) model – with express proviso that the transmission grid is a key state asset and that the state must retain ownership thereof – although this has reportedly not yet (as at early-February 2024) been approved by cabinet.
There are numerous types of implementation models envisaged in the concept of PPPs. It is also important to emphasise that a PPP, as a partnership between the public and private sector, does not inherently mean privatisation of assets (although some PPP models, by design, can retain ownership by the private partner). The so-called BOT type model mentioned recently by the Minister of Electricity, for example, is for the private partner to Build, Operate and then Transfer the assets to the public sector at the end of the contract period. It can also be considered in terms of another acronym, Design, Finance, Build, Operate & Transfer (or DFBOT) which is conceptually self-explanatory in terms of the roles and responsibilities of the private sector partner.
These PPP model concepts can clearly be applied to new-build assets, such as new transmission lines and associated assets. But similar PPP model concepts could also be applied in respect of existing assets (the existing grid assets) and sections thereof, whereby a private partner can take over those assets, refurbish (and upgrade) them and operate and maintain them for a defined PPP contract period, before handing them back – again with the state retaining the ultimate ownership of the assets.
PPPs of this nature are typically implemented through a structure called a special purpose vehicle or SPV, which is a company established for that specific and ringfenced purpose – in other words, that is all it can do. Furthermore, the funding required is typically obtained through what is termed a project finance model, where the bankability of the project is dependent on various factors, including (but not limited to)
- the ringfenced revenue streams of the SPV and how secure, reliable and predictable those revenue streams are, balancing returns, risks and affordability;
- clear, equitable and pragmatic broad-based risk allocation and management, including for example regulatory, political, economic and demand risks as well as implementation, operational and technical risks;
- demand risk allocation and management (and associated revenue models and their security) as a particular risk to be pragmatically addressed and mitigated; and
- governance and transparency, through establishing robust governance structures and transparency in procurement, decision-making and financial management to build trust and attract investors.
For a transmission PPP, a key risk factor is who carries the ‘demand risk’ (and the revenue model around that). Another key risk factor that is related to this demand risk and risk allocation is the maturity of the transmission network operator and energy market and hence the level of confidence in, for example, the predictability of demand and energy flows, and how that in turn translates to the aspect of potential revenue streams. It also impacts the a priori consideration and realisation of transmission agreements.
Pragmatic consideration of the various ways in which the demand risk is allocated and the associated revenue streams can be established and secured will therefore be key factors in determining the bankability of the PPP(s).
What must be emphasised is the urgency of moving forward with getting the approvals and frameworks for such public-private partnership arrangements in place, and fast tracking the procurement process. The expansion target (14,000km by 2032) is very ambitious and challenging. A key constraint will be the state’s will and ability to set this in proper motion – quickly.
Ian McKechnie (CEng, IntPE(SA), PrEng)
CEO & Principal Advisor/Consultant @ Engenamic
At Engenamic, we are focused on enabling successful projects, public-private partnerships (PPPs) and engineering outcomes, through the project, PPP and engineering lifecycle. In our approach, we are firm proponents of coherent and holistic solutions, and of a systematic approach to understanding and addressing project and engineering requirements and challenges.
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