Author: Wayne Glossop

Draft IRP2025: Lacking details to critique

The draft IRP2025 is currently undergoing consultation at NEDLAC but herewith are some of FlexED’s views on this important piece of legislation.

Traditionally, an IRP (Integrated Resource Plan) is a deeply technical document which provides a blueprint for new generation projects to be developed over the short to long term for a country. Such projects are often multi-billion-rand investments requiring many millions to be spent on development (i.e. the riskiest phase of the project) years in advance in order to align with the expectations of which technology is to come online as per the infamous IRP table (see main image to this article). Given the high stakes involved, it is prudent that as much detail as reasonably possible is included in the IRP so as to allow key stakeholders, such as IPP’s, sufficient insight into the rationality of the proposed plan thus providing confidence to take those risky development investments forward.

The draft IRP2025 sadly falls short on the necessary crucial detail and instead provides the reader with sweeping statements and broad stroke generalisations coupled with weakly described interventions. This, in our view, is a step back from the previous IRP’s which hosted multiple graphs and tables of information highlighting key information such as “the true cost of not having gas” or “the tariff impact of curtailing renewables” by way of example. The unfortunate part though is that we firmly believe that the detail is there and that in fact, the power system modelling work undertaken by the DEE is of a global standard and accurately portrays what South Africa requires up to 2042. We can, however, only assume though that in an attempt to appease the multitude of “expert” opinions that had to be considered by the DEE, that the authors deemed it safer to simplify and mystify the results thus leaving room for interpretation and obfuscation and side-stepping any meaningful intervention. This lack of robustness in the drafting of the IRP2024 is thus problematic and concerning.

Despite this setback, there is reason to be optimistic as the final recommendation, in FlexED’s view, is a sensible, and directionally sound, one. A recurring theme throughout the report is that the system requires flexibility (as noted by the 50+ occurrences of the words ‘flexibility’ and ‘dispatchability’ and the fact that they have even included a dedicated Annexure called ‘POWER SYSTEM FLEXIBILITY’) to balance the growth in renewables and the technologies of BESS; Gas; and Pump-storage are perfectly aligned to what FlexED’s core focus is. This thought piece attempts, as far as possible, to unpack these results along with highlighting some of the risks/shortfalls we deem to be important in reading this critical report.

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70/20/10: The Golden Ratio?

The mix of new generation proposed in the IRP largely follows FlexED’s view of the ‘new energy equation’ approach, namely, that Energy Security = Renewables + Flexibility (Read Fifty Shades of Flex – Flexed) with a sprinkle of baseload for prudency and risk aversion. By categorizing each technology as either ‘renewable’; ‘flexible’; or ‘baseload’, we can get a sense of where the priorities are in ensuring a stable and cost-effective energy mix into the future. We can categorize the technologies in the following manner:

Renewables Non-dispatchable – Wind, Solar, Embedded Generation

Flexibility – Gas-IPP, BESS (Eskom and IPP), Pump-storage

Baseload – Nuclear, Gas-Eskom*

*Note: We have assumed that for Eskom’s the 3GW gas project (in Richards Bay), whilst it will likely be a mid-merit, due to the anchor gas offtake restrictions (including minimum offtake obligations) from the LNG terminal, there may be limited potential to be a true provider of ‘flexibility’ hence we classify it as ‘baseload’ but in reality, it would contribute some baseload and some flexible characteristics.

Summing the MW’s per category to 2042, we can observe a clear preference to build as much renewable energy (~70%) but supported by flexibility (~20%) to balance the renewable energy and hedged with baseload (~10%) should the renewable+flexible mix deem to be insufficient.

As a side note, we do raise questions about the practical issues of slowing down the renewable builds between 2028 and 2030 as this could have dire effects on the RE industry within South Africa.

Going a step further into the pie chart, within the Flexibility wedge, we notice that Gas is the dominant provider (60%) followed by BESS (36%) and then Pump-Storage (4%). And as per the ‘Optimistic BESS scenario’, should BESS prices fall further than expected, then the ratio of gas to BESS looks the other way around. Interestingly though, pumped storage, a new-comer into the IRP table, is not a technology that appears in the reference case (i.e. the least cost scenario) but has been included as part of the proposed balanced plan in recognition of the high likelihood of needing more flexibility in the system.

“A flexible power system is one that can adapt quickly and reliably to changes in electricity demand or supply. This means being able to ramp power output up or down or switch between different energy sources to make sure the grid is always balanced. A measure of flexibility is assessing how quickly a dispatchable power plant can change its output from zero to maximum when required. South Africa’s power system is dominated by older generations of coal-fired plants that are generally not designed for rapid changes in output or ideally operated below their minimum stable level, thus making them less flexible. As the energy share of variable renewable energy resources increases in the grid, a more flexible type of generation is necessary to ensure a reliable power system.” (Draft IRP2025)

Finally, Nuclear makes an appearance when one restricts the new gas beyond 2030 (excluding the already committed 6GW). We do however challenge the ability to undertake over 6GW of Nuclear in 10-15 years time but this is a separate debate for another day…

So is this exactly the right mix of technology types for South Africa? Based on FlexED’s experience with power system modelling, the 70/20/10 renewables/flexibility/baseload signifies a cost conscious; risk aware; and carbon prudent approach to achieving our energy security objectives.

Under-analysing the biggest risk: Coal EAF

The first observation made under Section 7 ‘OVERALL OBSERVATIONS’ is that the “power system will remain adequate till 2030 if the Eskom Plant Performance remains within forecasted range…”. In addition, there is a 4-line summary in section 5.6 called ‘ANALYSIS OF THE SHORT-TO MEDIUM-TERM PERIOD (2025-2030) which essentially says “don’t worry, we don’t expect load shedding and we not going to be burning excess diesel to keep the lights on”.

Well…. Three months after the publication of the IRP, which was premised on the positive EAF trend still seen in December 2024 which South Africa enjoyed with 300 load shedding free days, load shedding struck with MUT’s (Multiple Unit Trips) experienced in Q1 2025. During this time, South Africa experienced record breaking levels of diesel been burned with up to R300M being spent in a single day as was experienced on the 4^th April when the OCGT’s were running over 60% (keep in mind that the design level is meant to be ~3%!). At the time of writing this, load shedding is still a regular occurrence.

So clearly the system was unable to “absorb shocks from MUT’s” and that the “if” in the observation has failed us dismally. And without any details to interrogate, we will never fully understand what the extent of damage will be resulting from this assumption. How much diesel will we be burning if we have a low coal EAF and how will this impact the final tariff you and I pay? And what exactly are the measures being taken by Eskom in improving the EAF? We do note that a comment is made about studying this sensitivity after the IRP is approved but given that the coal EAF is the biggest driver in whether or not we have energy security or not, should this report not at least seek to unpack this very likely scenario in a little more detail?  

What Case for CCGT?

A new inclusion in the report is a section dubbed ‘6.1 CASE FOR GAS CCGT’ which essentially says that the requirement for Gas CCGT by 2030 is critical in lieu of the impending loss of 8GW of coal plant and that above the 6GW needed before 2030, a further 1GW is required per annum between 2030 and 2040. Now whilst one cannot argue with this logic (in the absence of more details being made available), we do question whether the need to introduce a ‘marginally flexible’ technology was based on quantifiable evidence or is simply wordsmithing to appease certain stakeholders? This is why we challenge the ‘case’….

The promotion of adding of 1GW of mid-merit CCGTs every year is in direct contrast to what the reference case results indicate (i.e. the “least cost” scenario) which calls for no more ‘mid-merit’ gas between 2031 and 2035 (section 5.7). More curious though is that the report remains silent on the need for gas plant for lower dispatch levels (such as OCGT and ICE) as was clearly required in the IRP2019  which called for gas plants of approximately 12% load factor – a number clearly not achievable from a CCGT (Read The Need for Flexible Gas in South Africa).

So what really is the case for CCGT? How was this jump made from the last IRP at 12% to this one presumably at much higher dispatch levels? What were the costs and tariff impacts of this change? And what are the assumptions driving this ‘case’? Given the topical debate around load factors for gas power plants and what constitutes ‘mid-merit’ solutions, we believe that the answer will lie in a divulgence of more dispatch details but preferably even better, in a dedicated analysis especially considering the impact it will have on future gas IPP procurement strategies.

A Leap of faith into the Proposed Balanced Plan

We have already noted that the IRP makes many general observations which lack quantifiable evidence and unfortunately, this trend continues in the definition of the ‘Proposed Balanced Plan’ which seemingly gets divined into existence from the Overall Observations.

Now we appreciate that the proposed mix is based on certain system views and forecasts, and that the proposed mix is deemed sufficient to ensure energy security is maintained, but what happened inside the black box that spat this result out? Was there any probabilistic analysis around the risk of rooftop solar not being rolled out as quickly as envisaged? Or whether there is a reasonable chance that the coal plants life could be extended?

Again, without details, we are left to trust that the proposed balanced plan is indeed the right plan for us…. Whether we like it or not.

Not-so-SMART Interventions

There are five proposed interventions which essentially say the following:

1. Improve coal EAF;
2. Accelerate Gas to power;
3. Delay shutting down coal plants;
4. Develop the transmission grid and;
5. Don’t forget the Koeberg extension risk and MES risk (Read The Final Countdown for Coal? – Flexed).

Once again, while we cannot argue much on the logic employed behind the above proposed interventions, we need however to be more practical here. While objectives need to be SMART, meaning in other words, they needed to be Simple; Measurable; Achievable; Relevant; and Time-bound, in this instance the above proposed interventions talk only to being Relevant.

Perhaps the above proposed interventions could have been accompanied by clearly stated objectives that are achievable until the next IRP iteration is developed, such as for example:

1. Successfully launch the SAWEM by [a certain date];
2. Improve coal EAF to [percentage] by [such a date] by doing [clearly stated and properly sequenced activities];
3. Announce Preferred Bidders on Gas IPP Programme by [a certain date];
4. Launch independent grid operator tender by [a certain date];
5. Confirm Coal Plant MES strategy by [a certain date];
6. Etc ….

These, in FlexED’s respectful view, would be more meaningful milestones which would then have a material impact on whether the ‘Proposed Balanced Plan’ is in fact achievable or not until the next IRP draft is issued.

Conclusion

Renewables are the winners but flexibility steals the limelight in second place and baseload straddles behind in third place. No doubt there will be those in support and those opposed to this result but we believe nonetheless that this is a positive outcome and signifies a clear shift in what the power system of tomorrow will look like.

Having said this, we submit that the current draft IRP2025 has left us, reluctantly so, only marginally satisfied since whilst directionally it is good in as far as an attempt to map out a vision for the medium to long term on the one hand, on the other, we felt cheated out of an opportunity to unpack and analyse the details driving this result. In a way, this approach forces the reader to trust the DEE process and hope that the ultimate objective is achieved from this document which is to ensure energy security is maintained (as per the amended ERA, the IRP plays a role in guiding what needs to be procured (through a determination) in the event of a “failure of a market”, “an emergency”, or “for purposes of ensuring the security of energy supply in the national interest”). Only time will tell if this approach works and if we should trust the DEE to ‘keep the lights on’ up to 2042 but as FlexED, we hope that the next IRP will divulge more graphs and tables to meet the exigencies of a specific instance, in this case a provision of sufficient detail to outline reasons for decisions, stances and assumptions adopted culminating in this final draft IRP 2024 before us.  And lastly, as the saying goes, “the devil is in the detail”, we submit that the DEE’s potentially conscious withholding of this crucial detail has meant that a certain wide ranging stakeholder group, FlexED included in that group, would have a more restrained chance to scrutinise the real science and logic underpinning the DEE’s recommended way forward in the IRP 2024 draft, the nett result of which it may be argued in conclusion by some, as leading to a vague and somewhat ambiguous document.

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The Final Countdown for Coal?

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The Need for Flexible Gas in South Africa

In recent years, gas power has often found itself caught in the centre of heated debates as to whether it is needed or not in a power system and if so, what role should it be playing. A topic of high relevance particularly in South Africa whereby the government has recently launched a programme to procure 2GW of 300-1000MW Gas IPP’s across the country. This thought piece seeks to unpack this discussion and shed some light on some of the key issues driving this topical debate.

Horses for Courses

The majority of power system studies publicly available today (NBI/BCG; CSIR; Wartsila; Meridian Economics) indicate that gas power is preferable to contribute system flexibility in ‘small quantities’ in order to maintain system reliability. Typical determined dispatch capacity factors for gas range from 3-30% which effectively translates to gas providing the following primary functions to the system:

• Displacement of costly diesel fired OCGT capacity;
• Help balance renewable energy thus allowing for more renewables to be built; and
• Coal dispatch ‘flattening’ which ensure that the coal plants can operate more reliably.

There are, however, some studies (AIA; S&P) which indicate that gas has a much bigger role to play in replacing the decline in coal capacity thus acting more as a baseload energy provider to the system.
We believe in a ‘horses for courses’ approach whereby there is a mix of low and high-capacity factor gas plants depending on the viability of the proposed gas supply. Broadly speaking, when it comes to gas IPP’s, there are gas supplies from either domestic sources or imported LNG sources.
IPP’s that are dependent on domestic gas sources, assuming that these sources would be more cost effective than imported LNG options, and also recognizing that there may be additional challenges/costs in achieving gas supply flexibility, we believe would be more suited for high mid-merit dispatch ranges (Note: our studies reveal that under no circumstances would a ‘pure baseload’ gas plant ever be required). Technologies may either be CCGT or Gas Engines depending on the project scale/gas price/dispatch requirements.
IPP’s that are dependent on LNG imports, which presumably comes at a higher cost than domestic gas, should be limited to providing low mid-merit dispatch ranges. Technologies may either be OCGT or Gas Engines. There may, however, be an exception to this rule in the event that a policy decision is taken to build a high load factor gas plant to act as an anchor for a new LNG terminal development in an attempt to establish/sustain a downstream gas market. Taking this approach would, in our view, necessitate that such a provision is explicitly stated in the IRP following a thorough analysis of the cost/risk/benefit analysis from a broader economic; social; and energy security perspective. 

What does the IRP say about Gas?

Not enough is probably the honest answer but there is sufficient information to take a confident view on what is expected of gas on the power system. Lets dive into the IRP2019 (the ‘official’ version which the gas IPP programme is aligned to) and try to pick up some signs on what gas is supposed to do for the system….

The opening, and unambiguous, statement on the role of natural gas in the energy mix (Section 2.1) is as follows:

“Gas to power technologies in the form of CCGT, CCGE or ICE provide the flexibility required to complement renewable energy”. 

Another clear indicator that gas is required to support renewables is in the following observation (Section 5.1):

“The results from the simulation also show that in the long term, the system uses the combination of renewable energy, gas and storage to meet demand.”

And again, in the emerging long-term plan we note that there is a need for flexible gas ‘immediately’ but is not built sooner due to the lack of infrastructure (Section 5.2):

“The model is unable to deploy gas to complement renewables as it is assumed gas will only be available from year 2024…”

Furthermore, in Section 5.3.5 which talks about Gas to Power, the message is clear that low load factors are needed for gas but a solution to aggregating volume through diesel replacement was also made: 

“Whilst the plan indicates a requirement for 1000MW in 2023 and 2000MW in 2027, at 12% average load factor, this is premised on certain constraints that we have imposed on gas… This represents low gas utilisation, 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 … 

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 to gas”

Finally, and most importantly, Appendix C ‘Results of Test Cases’ provides a clear breakdown of the capacity factors for each gas technology and how much of each technology is required up to 2030. Just looking at the Base Case results, the direction for what the gas power plant should look like and how it could perform becomes abundantly clear. Flexible gas engines dominate the technology and capacity factors range from 2-41% between all the gas technologies (see image at the bottom).

 

Gas engines dominate the new build requirements for gas (CCGE and ICE) whilst the load factors reflect a peaking/mid-merit role for gas on the system.

So clearly, the IRP2019 calls only for flexible gas, recognises the challenge of aggregating volumes to justify gas supply infrastructure, and proposes a solution to convert diesel to gas to aggregate those volumes. It does not recognize or call for a baseload gas plant hence our view that this approach would require its own policy intervention backed by proper analysis. 

We not out of the woods yet

Whilst South African’s have recently been enjoying 300 consecutive load shedding free days, the litmus test of observing the diesel OCGT capacity factors still revealed that all was not ‘back to normal’ and of course, the re-emergence of load shedding January 2025. With weekly capacity factors in excess of 30% being required and a steady average load factor incline from 5% to 10% during the 300 days of load shedding free days, there is no hiding the fact that there is not enough energy being produced to allow these expensive generators to run at their intended output of 3-5%. The image below is a recent extract from the Eskom OCGT’s which shows that weekly capacity factors are reaching almost 50%!

Diesel reliance is extremely erratic and can range from 0%-50% any given week! This is the degree of flexibility that is ideally required to maintain energy security.

And the break in load shedding due to “several breakdowns that require extended repair times” (Source: Eskom Load shedding risk alert statement, 31st January), coupled to concerning reports about ash issues at Kendal power station, are most certainly precursors to the fact that “all is not yet well” with our coal fleet.
But even if somehow Eskom manage to sustain the coal fleet EAF over the coming years, there is still the inevitable challenge of needing to replace the lost energy from the coal fleet decommissioning cliff due to start early 2030. The draft IRP2023 recognizes by saying the following in respect of observations beyond 2031:

“Pathways comprising of dispatchable technologies with high utilisation factor provide security of supply. Other than delayed shutdown, these technologies include different combinations of nuclear, renewables, clean coal and gas.”

It is therefore clear that at least for the short to medium term, we should not assume that any gas plant that gets built will be operating under ‘ideal circumstances’ but will more likely be called upon to provide high energy levels during these turbulent and unpredictable years ahead for the power system.

Gas Supply Chain Flexibility: Its all about compromise

Limitations surrounding the ability to supply gas in a flexible manner as required by the power system are often touted as a reason to “go baseload”. And whilst there are most certainly challenges in the supply chain being able to provide flexibility, the bottom line is that there are solutions for providing such flexibility but naturally, there would be a premium attached to this benefit. Although this premium we don’t believe is so significant as to make these project unviable or uncompetitive when compared with diesel OCGT’s. 
Allow us to provide some thoughts particularly related to projects reliant on an LNG supply (i.e. projects that should be providing the most flexibility to the system).
The world of LNG supply is designed to, and places the most value on providing large stable, consistent volumes of gas. As soon as one starts to only use gas on an ‘adhoc’ flexible basis, you potentially disrupt that supply chain and there comes the need to purchase capacity within the supply chain even though it may not always be fully utilized. Further to this, one must recognize that there is generally a cost for shorter term LNG supply contracts than longer term predictable supply contract. Annual Delivery Plans are used to define when cargoes will be delivered on an annual basis for long term contracts and even if one relies on spot cargoes, LNG ships take time to pick-up and deliver their cargoes which time frames may exceed those required from the grid. For example, if there is an unplanned coal plant trip, then it is less likely that there will be sufficient gas available to restore this lost energy however, during periods of planned shutdowns, one can plan the LNG cargo deliveries in advance to meet the temporary energy requirements.
This balance essentially becomes an equation of compromising on under-utilized capacity (at a cost) and notification time frames (the shorter the time frame, the higher the cost).
Based on our analysis, we believe that the preferred approach would be to maximise LNG supply chain flexibility as far as reasonably possible as the power system benefits realised from having such flexibility far outweigh the project level benefits of having an optimized gas price.

Way forward

The option of not doing gas power soon will be a costly one for South Africa, from both a financial/environmental/and social perspective, as the alternative of continuing our reliance on diesel and coal for our system balancing needs is not sustainable. Studies show that forecasts in the timing for viability of green fuel alternatives (such as Green H2) go beyond 2035 and as of today, battery technology can make a signfiicant contribution to providing flexibility but it cannot extend its reach across the full spectrum of flexibility needs from the system (see article ‘Fifty Shades of Flex’ for more on this topic).
We believe that the key to advancing gas projects in South Africa is to try build in as much flexibility as possible across the gas supply and gas power technology choices as is reasonably possible. And even if there are flexible premiums to be paid to achieve this, this “least regret” approach (gas is even dubbed a ‘no regret option’ in the IRP), the bigger regret we may have is to lock into a baseload gas project which in a few years time may not be required for any number of reasons. We live in a constantly evolving world with our energy landscape changing on a daily basis so lets make sure that our long term infrastructure investments are able to cope with whatever life throws at them.  

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Fifty Shades of Flex

In this article, we highlight the need for flexibility on the grid and discuss some of the flexible technologies available today and in the future.

A New Power Equation

Wind and solar energy (“RE”) are now the cheapest energy sources available to power grids and as a result are being introduced at a rapid rate onto power grids all over the world. However, given the non-dispatchable nature of these technologies, this technological disruption is now forcing system operators (and energy traders) to rethink their approach as to how to maintain a stable and reliable power system. The traditional, and predictable, concepts of baseload; mid-merit; and peaking are now being challenged as we see more and more uncertainty being introduced necessitating the need for more flexibility to accommodate this uncertainty. In essence, we are seeing the following change in the ‘Energy Security equation’: 

Peaking + Mid-Merit + Baseload = Energy Security

Renewable Energy + Flexibility = Energy Security

Herein lies our challenge as today, there is no single dominant flexible technology option that we can use in the formulae but rather, a plethora of both mature and maturing technologies will likely be required to meet the evolving flexibility requirements experienced by power systems worldwide.

The Nature of Nature

“One can’t predict the wind but can adjust the sails” – Indian Proverb

The only certainty we have when it comes to renewable energy is that the sun will rise again tomorrow as it did yesterday and the day before that. That, unfortunately, is where the certainty ends, and the uncertainty begins, as our power systems will constantly be exposed to variability caused by wind and cloud induced RE intermittency.
We can observe this in the South African power system whereby consistent daily generation profiles get distorted and serrated caused by the intermittent wind and cloud cover patterns as in the image at the end.

A typical renewable dispatch curve as experienced by the South African Grid (Eskom data portal – Feb 2025)

Various weather phenomena will impose a different type of system challenge in terms of scale and duration. Such examples may include:

• cirrus cloud pattern moving across solar panels in the Karoo resulting in solar spikes within seconds of each other;
• daily weather pattern changes bringing with it constant hourly and daily supply variations;
• An extended cold front that brings overcast conditions across South Africa resulting in days and even weeks of low solar production profiles;
• Seasonal variations resulting in monthly changes; and
• Long term weather changes such as El Nino which bring about annual variations.

In addition to the direct effects of RE intermittency, there will also be indirect consequences on the legacy generators which will increasing become less reliable as they are pushed beyond their original design expectations to meet the growing variability needs of the system. Examples such as the use of coal plants, designed to operate primarily in a baseload fashion, are pushed to undergo constant ramping which places excessive thermal stresses on the equipment and subjecting them to more frequent failures. And in the rare cases, extreme weather events could result in direct destruction of the power system infrastructure.
The result of all these factors is that we have a power system that requires flexible technologies across the flexibility spectrum as depicted in the image below.

A figurative illustration of how certain weather related events can cause variability of varying duration as plotted along the flexibility spectrum.

Choosing the Right Tool for the Job

There is no single silver bullet answer to addressing all the flexibility needs of the power system. If a stable and secure supply of power is a pre-requisite for sustained economic activity and growth, then it is vital that we recognize that multiple Flexible technologies will be required.
The title of this is article is ’Fifty Shades of Flex’ and we have no doubt that there are more than fifty technology solutions that can bring flexibility into the power system. And whilst we recognize that each technology has a role to play, as FlexED, our view is that the combination of batteries (or “Battery Energy Storage Systems” aka: BESS); flexible gas; and hydro/pump-storage provides a compelling, and proven, mix of grid scale Flexible Technologies spanning across the flexibility spectrum.

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