When released in October, the Integrated Resource Plan 2019 (IRP 2019) highlighted that South Africa would face an electricity capacity shortfall of between 2 000 and 3 000 MW for the coming three years, as well as relatively modest energy deficits (measured in gigawatt-hours, or GWh) over the period. Subsequent analysis by the Council for Scientific and Industrial Research (CSIR) points to a larger capacity deficit (up to 8 000 MW) and dramatically larger yearly energy shortages over the period, potentially rising from 2 000 GWh in 2020 to 4 500 GWh in 2022.
In other words, the CSIR is cautioning of energy shortages that are materially bigger than those of 2019, when South Africa experienced its worst-ever year of load-shedding. Last year, Eskom declared rotational power cuts equivalent to 1 350 GWh of customer demand shed, which cost the country anywhere between R60-billion and R120-billion, with the higher figure derived using the official cost of unserved energy of R87.50/kWh.
The deterioration in the outlook has arisen because the CSIR model employs a more realistic Eskom-fleet energy availability factor (EAF), of 64.5%, than the 75.5% EAF assumed in the IRP 2019. Eskom’s coal EAF has been declining consistently over the past decade and fell to 67% in 2019. It is highly unlikely that it will recover, unless and until those units in the worst state of disrepair are shut, and Eskom’s maintenance teams have the time and space to salvage those units that can be repaired.
It should also be noted that the CSIR model in no way represents the worst-case scenario, which would arise should the South African economy eventually begin to grow again and electricity demand with it.
The CSIR analysis has implications, though, for the way South Africa approaches the procurement of supply options in the short run that will help close the supply gap and limit the use of load-shedding. The key mitigation options that the CSIR highlights, from a supply-technology perspective, are wind and solar photovoltaic (PV) power generators to be implemented as a matter of urgency.
The good news, from a system-cost perspective, is that adding this additional wind and solar energy to the grid will not result in a massive deviation from the IRP 2019, because it is aligned with what the IRP plans in the long run anyway. The cost-optimal new-build mix as outlined in the IRP consists of predominantly solar PV and wind. In other words, the ‘emergency generator’ (solar PV and wind) is the same generator that needs to be bought in the long run anyway.
Therefore, meeting the objective set in the Department of Mineral Resources and Energy’s request for information (RFI) of adding electricity in the “shortest time and at the least possible cost” will mostly be aligned with the least-cost long-term solutions outlined in the IRP 2019.
In addition, wind and solar PV have the shortest lead times and the lowest risk of time and cost overruns of all available alternatives. So, they combine short-term ability to assist with long-term fit into the optimal energy mix. Even if coal and nuclear were still South Africa’s cheapest new-build options – which they are not – there is simply no way of building such plants in the three-year period dictated by the procurement programmes that will emerge from the RFI.
Solutions such as temporary power barges and temporary diesel generators are certainly technical options. But they mostly provide peaking capacity, and should better not be used for large amounts of energy, as that causes huge fuel bills and, hence, increases costs.
Thus, if South Africa is able to quickly add new primary energy from solar PV and wind to the system, it will arguably be far cheaper to rather seek solutions designed to distribute this fresh bulk energy being injected into the grid in such a way that it meets customer demand at the precise point in time that such demand is arising. Although electricity has to be consumed instantaneously, there are a number of ways to distribute the energy over time. Besides pumped storage, the other levers available to the system operator include adjusting power-station maintenance schedules and contracting with large customers to use their loads in a way that helps balance demand and supply. Only in extreme cases should diesel generators and ultimately load-shedding be used to balance the system.
Without additional fresh bulk energy, the system operator’s ability to reorganise the system will remain extremely limited and the pressure on operating power-station units will remain unrelenting, which will inevitably worsen the EAF position further. Under such conditions, the load-shedding instrument will have to be used and used more frequently and probably at higher levels.
Given that the technological solutions are at hand (dominantly wind and solar PV, combined with the procurement of new flexible plant), the only issue is how to accelerate the entry of those solutions. Without question, the most immediate opportunity lies in allowing private customers to self-generate electricity and to buy directly from private power producers.
In parallel, though, the Independent Power Producer (IPP) Office should be given the authority to proceed with the central procurement of new plant. The IPP Office could simply procure in the same tested way it has done previously, with the only change being to incentivise faster implementation of the wind and solar PV projects than the IRP 2019 envisages.
There are two possible ways of accelerating deployment and to do so without deviating materially from the least-cost, least-regret outcomes that the IRP 2019 mostly incorporates.
First, one could build on the concept of the national auction and introduce regional auctions. The national auction model is a good one, but it incentivises IPPs to chase after the windiest and sunniest sites across the whole country, even if those sites are remote and take time and additional cost to be unlocked from a grid perspective. Regional auctions would implicitly lead to projects closer to existing grid infrastructure that can be implemented in short timeframes. The nine provinces could be clustered into ‘procurement regions’, where the national procurement target is broken down into allocations per procurement region, and then select the cheapest bid in each such region. Even though the tariff for a solar PV project in the theoretical ‘Mpumalanga, Gauteng Procurement Region’ may come in slightly higher than one in the Northern Cape – a differential that would have disqualified the project in a national auction – it is likely that the connection time will be far faster because of Gauteng’s and Mpumalanga’s much larger grid capacity.
A second option, which could also be combined with the first, is to evaluate bidders in a national auction not only on price (the tariff), but also on commercial operation date (COD). Naturally, such a COD commitment would be subject to Eskom being ready to connect. The IPP would then receive a higher tariff for an earlier COD. For example, a 1 c/kWh higher tariff could be granted for every one month of earlier committed COD. So, if two projects are completely similar, but the one project can commit to a COD that is one year ahead of the other’s, that project would receive a 12 c/kWh higher tariff than the slower one.
Both models introduce greater time urgency, without alleviating the pressure on bidders to sharpen their pencils. The process would still be fully competitive, with clear and transparent rules. If complemented by a streamlined Web-based bidding system, with bid documents that outline clear compliance criteria – everything government wants to achieve besides securing more electricity in “the shortest time and at the least possible cost” – procurement can be truly fast-tracked.
The final question then is whether potential bidders have the confidence that the buying party (currently Eskom) has the financial wherewithal to honour the power purchase agreements (PPAs) that will arise. It would probably be best not to burden Eskom with new PPAs, because that would require new government guarantees, resulting from Eskom’s dire financial situation. The current government guarantees for operational renewables projects can remain intact.
But for new PPAs, a new standalone entity should be created with the sole purpose of being the offtaker for new IPP electricity and to channel the regulator-determined, customer- collected money towards those IPPs, without government guarantees. Because this purely transactional entity would simply administer IPP payments and would have no other business, the IPP payments would therefore not be at risk of that entity running into financial problems from non-IPP-related activities. Given the reputation of the IPP Office’s procurement process and of the energy regulator’s decisions to allow full recovery of IPP payments from the electricity customers’ tariffs, no government guarantees would be required to gain sufficient investor confidence in the bankability of the PPAs.
Lots of ‘emergency options’ are on the table with fast implementation timelines that are at the same time the right thing to do in the long run. The cost of emergency procurement can, hence, be kept extremely small, if managed well. South Africa will be able to move out of the current crisis with a strong, future-proof asset base of an ‘IRP-compliant’ mix of new power generators – solar PV, wind and flexible plants.