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Electricity Regulation Act, 2006 (Act No. 4 of 2006)


Integrated Resource Plan 2019

5. IRP Update

5.3 Key Considerations and Actions


After due consideration of the modelling and simulation outcomes, and taking into account the plan in Table 5 above, the following key considerations emerge which require actions to be taken for a credible IRP 2019.


5.3.1 Immediate Term Security Supply


In the short-term supply and demand side interventions will have to be deployed to minimise the risk of load shedding and/or extensive usage of diesel peaking plant due to Eskom’s plant low EAF. The short-term gap is estimated to be between 2 000 – 3 000 MW. It generally takes about 36 months minimum for a green field utility scale projects to produce first power. A medium-term power purchase programme (MTPPP) similar to that adopted following the IRP 2010 must be considered. Under the MTPPP power was purchased from already existing facilities such as co-generation and small hydro which are generally not run as it is cheaper to buy power from Eskom. The development of generation for own use must also be encouraged through the enactment of policies and regulations that eliminate red tape without compromising security of supply.


Decision 1: Undertake a power purchase programme to assist with the acquisition of capacity needed to supplement Eskom’s declining plant performance and to reduce the extensive utilisation of diesel peaking generators in the immediate to medium term. Lead-time is therefore key.


Taking into account supply and demand balance and the impact of load shedding on the economy, shutting down of MES non-compliant power plants and Koeberg power station in 2024 (at the end of its design life) are not recommended. Koeberg is one of the best performing power plants with a low operational cost (it is fully depreciated).


Decision 2: Koeberg power plant design life must be extended by another 20 years by undertaking the necessary technical and regulatory work.


Decision 3: Support Eskom to comply with MES over time, taking into account the energy security imperative and the risk of adverse economic impact.


5.3.2 Energy Mix and Just Transition


Due to the expected decommissioning of approximately 24 100 MW of coal power plants in the period beyond 2030 to 2050, attention must be given to the path adopted to give effect to the energy mix and the preparation work necessary to execute the retirement and replacement of these plants. In order to ensure a socially just transition, the engagement process must commence to put in place the plans and interventions that mitigate against adverse impacts of the plant retirement programme on people and local economies.


In 2015, the International Labour Organisation (ILO) Governing Body convened a panel of experts to develop non-binding guidelines for a just transition towards environmentally sustainable economies and societies for all9. The guideline list the following principles for the development of a just transition:


(i) Social dialogue as an integral part of the institutional framework for policymaking and implementation at all levels, and therefore a strong social consensus on the goal and pathways to sustainability.
(ii) Policies must respect, promote and realize fundamental principles and rights at work.
(iii) Policies and programmes need to take into account the strong gender dimension of many environmental challenges and opportunities. Specific gender policies should be considered in order to promote equitable outcomes.
(iv) Coherent policies across the economic, environmental, social, education/training and labour portfolios need to provide an enabling environment for enterprises, workers, investors and consumers to embrace and drive the transition towards environmentally sustainable and inclusive economies and societies.
(v) These coherent policies also need to provide a just transition framework for all to promote the creation of more decent jobs, including as appropriate: anticipating impacts on employment, adequate and sustainable social protection for job losses and displacement, skills development and social dialogue, including the effective exercise of the right to organize and bargain collectively.
(vi) There is no “one size fits all”. Policies and programmes need to be designed in line with the specific conditions of countries, including their stage of development, economic sectors and types and sizes of enterprises.


Decision 4: For coherent policy development in support of the development of a just transition plan, consolidate into a single team the various initiatives being undertaken on just transition.


5.3.3 Wind and PV


As already stated under modelling observations, the application of annual build limits on renewables does not significantly impact the projected capacity up to the year 2030. The application of renewable build limits “smoothes out” the capacity allocations for wind and solar PV which provides a constant pipeline of projects for investment; this addresses investor confidence.


In the long run and taking into account the policy of a diversified energy mix, the annual build limits will have to be reviewed in line with demand and supply requirement.


Decision 5: Retain the current annual build limits on renewables (wind and PV) pending the finalisation of a just transition plan.


5.3.4 Coal


HELE coal technologies including underground coal gasification, integrated gasification combined cycle, carbon capture utilization and storage, ultra-supercritical, super-critical and similar technologies are preferred for the exploitation of our coal resources. Due consideration must be given to the financing constraints imposed by lenders and the Organization of Economic Cooperation and Development (OECD) countries, insofar as coal power plant development.


Due consideration must also be given to the pace and scale of the coal-to-power programme taking into account the lessons from Medupi and Kusile mega projects. Procurement under the IPP programme has shown that there is a business case for modular and smaller power plants (300MW and 600MW).


Decision 6: South Africa should not sterilise the development of its coal resources for purposes of power generation, instead all new coal power projects must be based on high efficiency, low emission technologies and other cleaner coal technologies.


5.3.5 Gas to Power


Whilst the plan indicates a requirement for 1000 MW in 2023 and 2000 MW in 2027, at a 12% average load factor, this is premised on certain constraints that we have imposed on gas, taking into account the locational issues like ports, environment, transmission etc. This represents low gas utilization, which will not likely justify the development of new gas infrastructure and power plants predicated on such sub-optimal volumes of gas. Consideration must therefore be given to the conversion of the diesel-powered peakers on the east coast of South Africa, as this is taken to be the first location for gas importation infrastructure and the associated gas to power plants. It must be noted that that the unconstrained gas is a ‘no regret option’ because the power system calls for increased gas volumes when there are no constraints imposed.


Decision 7: To support the development of gas infrastructure and in addition to the new gas to power capacity in Table 5, convert existing diesel-fired power plants (Peakers) to gas.


5.3.6 Nuclear


The extension of design life of the Koeberg Power Station is critical for continued energy security in the period beyond 2024, when it reaches the end of its 40-year life. This extension, once all the necessary regulatory approvals have been received, will increase the capacity to its original design capacity of 1926MW.


Whilst the IRP does not assess system dynamic stability, the relative location of Koeberg at the opposite end of the transmission backbone, when compared to the power stations located around Mpumalanga, poses certain advantages that include improved system stability.


Post 2030, the expected decommissioning of 24 100 MW of coal fired power plants supports the need for additional capacity from clean energy technologies including nuclear. Taking into account the existing human resource capacity, skills, technology and the economic potential that nuclear holds, consideration must be given to preparatory work commencing on the development of a clear road map for a future expansion programme. This IRP proposes that the nuclear power programme must be implemented at an affordable pace and modular scale (as opposed to a fleet approach) and taking into account technological developments in the nuclear space.


Taking into account the capacity from coal to be decommissioned post 2030 and the end of design life of Koeberg nuclear power plant, additional nuclear capacity at a pace and scale the country can afford is a no regret option.


Decision 8: Commence preparations for a nuclear build programme to the extent of 2 500 MW at a pace and scale that the country can afford because it is a no-regret option in the long term.


5.3.7 Regional Power Projects


South Africa has entered into a Treaty regarding the Grand Inga Hydropower Project with 2 500 MW offtake. Whereas the draft IRP 2018 was modelled by forcing the 2 500 MW from Inga, the IRP 2019 used the commercial parameters that were submitted by the project developers for Inga, and 2 500 MW (and even more beyond 2030) of hydropower was selected on its own merits. There is a need to finalise the technical solution for the evacuation of this power from the Grand Inga across the transit countries viz. DRC, Zambia, Zimbabwe/Botswana into South Africa. The necessary agreements must be concluded as soon as possible if the hydro option from Grand Inga is to materialize.


Consideration must be given to the form of participation by the transit countries including integration with the regional interconnection projects sponsored under SADC and SAPP.


Decision 9: In support of regional electricity interconnection including hydropower and gas, South Africa will participate in strategic power projects that enable the development of crossborder infrastructure needed for the regional energy trading.


5.3.8 Energy Storage


When energy storage costs were revised to the latest information, and taking into account the longer gas infrastructure lead time, the power system selects more energy storage. This can be expected, given the extent of the wind and solar PV option in the IRP.


It must be noted that Eskom is already preparing to pilot an energy storage-technology project based on batteries. The pilot will enable the assessment and development of the technical applications and benefits, the regulatory matters that relate to a utility-scale energy storage technology and the enhancement of assumptions for future iterations of the IRP.


5.3.9 Distributed Generation


Public inputs suggested that the allocation for distributed generation (also referred to as embedded generation) needed to be increased, taking into account that the DMRE is inundated with requests from companies, municipalities and private individuals for deviation from the IRP in terms of section 10(2)(g) of the Electricity Regulation Act, in order for NERSA to approve their application for a generation licence. Given the observation concerning energy shortage in the immediate term, increasing the embedded generation allocation as reflected in the capacity plan table present the opportunity to address the shortage.


5.3.10 Risk Considerations





Demand Forecast

The risk is that actual demand may turn out to be lower or higher than forecasted. Current indications are that demand is more likely to be lower than forecasted because of grid deflections for various reasons.

Medium Term System Outlook by NERSA as submitted by system operator (Eskom) in line with their license conditions provides necessary information to monitor actual and projected demand and supply.
This risk will further be mitigated by managing the pace and scale of new capacity implementation in the IRP through acceleration or deceleration of implementation of Ministerial Determinations.

Technology Costs

Continuous improvements in technology driven by research, innovation and innovative project financing will continue to lead to reduction in new generation technology costs.


There is a risk of the cost assumptions to be outdated within a short time period.

As in the case of demand forecast, this risk can be mitigated by managing the pace and scale of new capacity implementation through regular reviews of the IRP.
Undertaking feasibility studies to inform any procurement in line with New Generations Regulations will also help mitigate against this risk.

Existing Plant Performance

The IRP update takes into account the current low average energy availability factor (EAF) of Eskom’s generating units.


If current EAF trends is anything to go by, there is a likelihood of the EAF deteriorating further and resulting in inadequate supply to meet demand.

This can be mitigated by implementing a threshold and monitoring plant performance trends for decisions. In the short term, emergency power will have to be procured, as was the case in the past. In the long run this will imply accelerating or bringing forward capacity proposed in the plan.

Variable Capacity from Renewable Sources impacting on System Security and Stability

There is an inherent risk associated with the intermittency of renewable technologies such as wind and PV as requirement to balance the system increases (energy and ancillary services).

At low levels of penetration, fluctuating renewable energy will have only marginal impact on the system. However, considering the South African energy generation mix and demand profile, there is a point at which an isolated system would have to adjust system and network operations if not configured to cater for the variability of this energy. Indications from the system operator is that at about 20% of renewable energy in the energy mix, ancillary service requirements will start to increase and this is in line with global trends.

This is therefore not an issue for the proposed plan up to the year 2030.

The draft IRP update has recommended further work in this area following the finalisation of the IRP in order to inform the next IRP iteration.

Import Hydro Options

The main risk associated with import hydro options are delays in the construction of both the power plants and the grid to evacuate the power.


There is also generally a cost risk in that the assumptions used may change as the project development is finalised with developers.


There is also a risk of security of supply as the power line may traverse multiple countries or be transmitted through a number of countries networks.

The Treaty spells out the various conditions for the project. Power purchase agreements will also contract the timelines with regard to first power and the associated penalties if either party does not keep its commitments. RSA does not have any payment obligations if there is no energy flowing from the project
The IRP assumed costs are based on feasibility costs provided by the developers. It is the government view that the cost per kWh will be capped at the feasibility study cost, which is very attractive. Any cost above this level will result in ‘no deal’.
As a principle South Africa does not import power from one source beyond its reserve margin, as a mechanism to de-risk the dependency on this generation option.


There is risk of 900 MW of coal

procured not materialising due

to financing and legal

challenges. There is also

likelihood of future coal to power

capacity not being realised due

to financing challenges. The

stance adopted by the

Organization for Economic

Cooperation and Development

(OECD) and financial

institutions concerning financing

coal power plants, limits the use

of coal to power technologies to

High Efficiency Low Emission

(HELE) option.

The Department is monitoring the legal challenge on the environmental approvals issued by DEA and will be guided by the outcome of this process as applicable.
Regarding the financing of the Pulverised Fuel projects, there is a deadline for the projects to reach financial close and commissioning. The Department will be guided by progress as the deadline approaches.
The assumption in the IRP is that all new coal to power capacity beyond the already procured 900 MW will be in the form of clean coal technology, which is still generally financed.

As proposed in the draft IRP update, work to enable implementation and investments in flexible HELE will be undertaken following finalisation of the IRP.


Koeberg Power Station reaches end of life in 2024.

Eskom is at an advanced stage with technical work required for the extension of the life of Koeberg plant. Eskom is also in the process of applying for the necessary approvals from the National Nuclear Regulator.
The Department is monitoring progress with Eskom on a regular basis.


The availability of gas in the short to medium term is a risk as South Africa does not currently have gas resources.


There is also a supply and foreign exchange risk associated with likely increase in gas volumes depending on the energy mix adopted post 2030 when a large number of coal fired power stations are decommissioned.

For the period up to 2030 gas to power capacity in the IRP has realistically taken into account the infrastructure and logistics required around ports/pipelines, electricity transmission infrastructure.

The IRP has therefore adjusted thelead times.


As proposed in the draft IRP update, work to firm up on the gas supply options post 2030 is ongoing. This work will inform in detail the next iteration of the IRP.



9 The guideline can be accessed at: