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.