Too late for gas to save a looming power deficit?

September 30th, 2019, Published in Articles: EE Publishers, Articles: Energize

It is already too late to hope that the introduction of gas generation in the new energy mix would contribute to avoiding the projected power deficit from about 2023, according to panelists at a recent gas forum. The consensus was that to implement such a project would require at least six years, if everything was in place, which it is not, and there are only four years to 2023. This article summarises the discussions held at the forum.

Nedbank and EE Publishers recently hosted a gas forum to explore the possibility of establishing a viable gas sector in South Africa. The panel comprised a number of high-level speakers including Advocate Sandra Coetzee, from the government’s IPP Office; Andy (Andries) Calitz, a former Eskom and Shell executive; John Smelcer, of Globeleq; and Jaco Human, from the Industrial Gas Users Association (IGUA).

Click here to download the presentations

The gas energy crunch is already a reality, and the worst is yet to come on top of electricity insecurity and cost. Eskom’s energy availability factor (EAF) is currently at 65% and time is of the essence. No entity currently has concrete plans to meet South Africa’s gas energy challenge in time. The state, through various entities and legislation, is in control of energy and gas economy but has no policy on the development of a gas economy. Simply put, the government is not aligned to industrial requirements for gas energy availability and cost efficiency.

National development and integrated resource planning

South Africa’s national development plan (NDP) incorporates constructing infrastructure to import liquid natural gas (LNG) and use viable domestic gas feedstock, mainly for power production, to diversify the energy mix and reduce carbon emissions. The establishment of a gas industry in accordance with the NDP is inexorably linked to gas-to-power (GtP) projects incorporated in the integrated resource plan (IRP), which would provide an anchor market and allow third party offtake.

The implementation of aspects of energy planning, regulatory and market structure reforms is incomplete and/or in transition. The initial IRP was issued in 2010, with proposed, but unincorporated updates in 2016 and 2018.Much has changed since the initial IRP, but what has not changed is a compelling case for including gas in the energy mix. There have been four rounds of independent power producer (IPP) bids but no LNG projects to date. Gas-to-power procurement is dependent upon the promulgated IRP 2018. Gas procurement will be determined by the final IRP once policy is adjusted, gazetted and effected through ministerial determinations and the medium-term system adequacy outlook (MTSAO). The latest iteration of the IRP (March 2019) indicates 1000 MW of gas in 2024 and 2000 MW in 2027. Gas utilisation in the draft IRP is less than previous IRP iterations, with more than one project but low load factors ranging between 12 and 50%.

The development of new gas infrastructure (ports, pipelines, regasification and storage) and power plants based on such sub-optimal gas volumes (IRP 2018) is not considered viable. The future use of gas is affected by the inclusion of electricity storage systems (ESS) in the draft IRP. ESS is displacing gas in IRP iterations (IRP 2018). Gas is still needed for long duration capacity (>4 to 8 hours), until ESS and other technologies with renewable energy (RE) can provide a continual supply of power. Despite this, gas is seen as a transition fuel in the energy transition and as an essential flexible option which will be used for many years in the future. Gas may still play a part until new technology matures.

Gas-fired power complements an energy mix increasingly focused on renewable, and is a flexible and relatively green solution for addressing the intermittency of renewables while providing grid stability. Gas-fired power will play a critical role in decarbonisation, and offers significant decarbonisation benefits relative to coal, oil and wood burning. Gas plays a unique role as a flexible option and as a transition fuel to provide the long bridge between fossil fuel and non-fossil fuel resources and will play a fundamental role in the energy mix for years to come.

The market structure for gas is in a transition – but this should not hold back the procurement process. The power purchase (PP) environment is not fully in place and there is a need to move forward in a coordinated and cohesive fashion.

Establishing a viable gas sector

In a viable gas sector, customers have choice of gas as an energy driver, the gas market holds a 10 to 25% of primary energy share, gas is sourced from a combination of domestic, regional and international sources, and the gas network reaches major cities and industrial areas.

A natural gas (NG) market will contribute to energy security, diversity and stability, and become a source for the re-industrialisation of SA economy. NG can contribute to a higher and inclusive economic growth path and job creation in South Africa, as well as assisting the country in its journey towards achieving commitments to a lower carbon and a more carbon resilient future. This is, however, a long-term agenda for the next 25 or more years, but will only take place if there is commitment now to the development of enabling policies and for decisive action to be taken. We have to follow a pro-active rather than a reactive approach.

Enabling a viable gas sector encompasses more than just natural gas and can also be interpreted to include shale gas, coalbed methane gas, underground coal gasification, liquid petroleum gas (LPG) and even biomass and landfill gas. Demand is estimated to possibly be 870 PJ, including non-electricity demand. Gas price uncertainty is a major inhibiting factor in the establishment of a non-electricity market.

The LNG to power IPP is currently on hold. A bundling approach is required, anchored on a GtP programme, but not forgetting alternate use. Currently the IRP/IPPPP capacity is insufficient to drive third party uptake.

South Africa’s need for gas is driven by system flexibility requirements as RE penetration rises, industrial development potential, climate change mitigation imperatives and gradual diversification away from carbon-intensive sources (coal and diesel) through gas turbine fuel conversion.

Previous studies have estimated total potential demand for gas in South Africa can be up to 870 PJ (25 Bcm) by 2032. Potential developmental impacts for the country’s industrialisation could be large. Gas fired power generation alone could use 100 PJ and add around R140-billion to GDP. Industrial demand could be 1200 PJ, transport 148 PJ and residential/commercial demand 40 PJ per annum.

At the right price, gas-based downstream industries (e.g. steel and petrochemicals) could add R110-billion to GDP and create 230 000 jobs. Uncertainty about demand remains as estimates vary widely among different studies. ESS could also improve energy security in a country reliant on gas imports. LNG can improve energy security in the absence of alternatives, but also increase the energy security risk and affordability given country reliance on imported gas under fluctuating exchange rates.

Gas prices are volatile and US-dollar denominated gas supply agreements can risk electricity price affordability and energy security. Gas is nonetheless cheaper than diesel. The lower load factor suggests greater dispatch flexibility, which comes at a price and which includes the cost of a flexible fuel supply/logistics, which may require cargo diversions/alternative buyers, and the cost of keeping capacity available. If coordinated, greater volumes of domestic offtake entail significant cost reductions.  GtP tariffs are generally made up of capacity payment based on available capacity and variable energy payment based on dispatched energy volumes.

Potential for gas outside the power sector

There is a considerable market for gas outside of the power sector. The large gas-users market is worth R159-billion a year and requires approximately 50 GJ per annum. There are also about 8000 small gas users. This number could increase significantly if a national gas network was established. A clear gas usage master plan (GUMP) is required to convince investors and other stakeholder to put their weight behind the country’s energy plans.

The LNG to power IPPPP is currently on hold until IRP 2018 has been gazetted. The initial programme targeted 3126 MW from LNG in alignment with IRP 2010 and related ministerial determination. A PIM, released October 2016 envisaged procurement to be undertaken within context of wider objective of developing a gas industry in SA, including gas exploration and production from indigenous resources, encouragement of imports by pipeline from SADC and development of gas use in industrial, commercial, transportation and residential sectors. According to PIM, the first phase of the programme would have focused on Richards Bay in Kwa-Zulu Natal and Ngqura Coega in the Eastern Cape to anchor initial gas demand as well as infrastructure.

Initial assumptions for gas to power was for higher load factors (power plant economies) than required by current IRP capacity allocations, thus limiting gas demand for power as an anchor for broader economy use This means that the gas to power programme design will have to be reviewed, including unbundled vs. bundled approach. Lower gas volumes will be required for electrical power generation as indicated through lower load factors and installed MW in the NEDLAC version of the IRP vs. previous iterations, as well as earlier gas requirements (2024 vs. 2026 IRP, August 2018). The gas IPP capacity is likely to be insufficient to justify a bundled gas infrastructure procurement approach due to tariff concerns.

The key physical challenge to establishing a gas sector in South Africa is the constraints on gas supply. The PetroSA offshore block is depleted. The Rompco pipeline supply is limited in the absence of additional upstream discoveries /alternative sources of supply.

Recent delays to LNG import initiatives (IPP office-led procurement, Western Cape exploration of alternative model, Transnet initiative, etc.,) are hindering development and providing a challenging regulatory (and oil price) environment for development of South Africa’s upstream potential. There is an overall energy planning challenge in South Africa, particularly given viability concerns around key energy entities such as Eskom.

Lacking any significant near-future development of local gas source development, the development of a gas industry will to have to rely on gas imports in the short term. Fortunately, the international LNG market remains favourable for new importers, and recent regional and local game-changing upstream discoveries (Mozambique, etc.,) hold much potential to make the development of a local gas industry possible.

Mozambique would likely become one of world’s larger LNG producers with 15-million tonnes per year. The uncertainty, however, is whether Mozambique will be ready to supply required volumes by 2024. Utilising Mozambique as preferred gas source could promote regional integration, be used as another means to support a just energy transition if gas plants are located in Mpumalanga and possibly limit South Africa’s currency exposure through Rand-based gas supply agreements.

Total’s Brulpadda gas find in the Outeniqua basin (estimated between 300-million and 1-billion barrels of oil equivalent) could have significant consequences for the country’s energy security through a reduced reliance on imported gas when production begins. It could take at least eight years before production begins at the Brulpadda block and it has been estimated that the field could produce enough gas to fuel around 1300 MW of baseload power in a 50% efficiency gas to power plant over 20 years.

Regional recent upstream discoveries (Mozambique, etc.) have changed the situation. Natural gas fields, including new discoveries in the region include:

  • Kudu – west coast: Approximately 1,3 tcf anchored on GtP and power exports which are not materialising. Economic feasibility and development is unclear.
  • PetroSA Block 2A: Discovered 1987. ±1,5 tcf. PetroSA holds a 24% stake. Economic feasibility unclear and development unlikely.
  • PetroSA Blocks 9 and 11: Block 9 feedstock for Mossgas since 1992 is virtually depleted. Block 11 has limited gas ±590 mGJ and is unlikely to be developed.
  • Block 11B: Brulpadda is owned by Total (45%) and QP (25%). The find was announced in 2019 with significant gas condensate.
  • Karoo shale gas: Estimates are uncertain and environmentally controversial. Estimated at 485 tcf, but more likely to be 13 tcf.
  • Mamba/Lesedi: Coal bed methane reserves of ±200mGJ anchored on small localised GtP projects.
  • Virginia: Renergen /Tetra4 development. Small quantities of CNG since 2016.
  • Romuva (Mozambique) areas 1 and 4: Area 1, 63 tcf; Area 4, 58 tcf. Pipeline connection to Rompco.
  • Zambesi/Angoshe: 3 to 5 tcf potential. Posible long-term target for SA users.
  • Pande/Temane (Mozambique): Supply since 2004, ±800 mGJ left with reducing pressure.


The question is whether South Africa can anchor development of these new sources of supply to establish a viable gas sector on a sustainable basis. The first step appears to be LNG imports from international markets as a bridge to unlocking regional supply and domestic upstream potential. Historically, a large portion of LNG volumes have been traded under long-term, fixed destination contracts. Security of revenue enables financing of capital-intensive development of new LNG plants and security of supply supported development of new regasification plants.

The current overall trend is towards shorter-term contracts, despite recent downward trends in spot trading. However, long-term LNG sale and purchase agreements (SPAs) remain critical to the industry to underpin the financing of new liquefaction plants (e.g. Russia, Australia, Mozambique) and support the development of new regasification plants (e.g. Pakistan and Bangladesh).

To move gas from source to demand, significant infrastructure is required, be it in the form of pipelines or rail and port capability. Mega pipelines are no longer constructed and sea transport is the preferred method. Gas infrastructure requirements to enable gas to power (i.e. port, pipelines (virtual and regional), regasification and storage (FSRU or inland terminal)) require dedicated broader stakeholder involvement (e g Transnet, iGas, Sasol) to attain readiness for commercial operations before the 1000 MW gas to power IRP requirement in 2024 can be achieved.

The DME plans to import LNG via floating storage regasification units (FSRU) pursuant to a gas IPP procurement programme for 3000 MW of power, spearheaded by the department of Minerals and Energy (DME) with National Treasury support. A portion of the imported gas may be used for non-power utilisation. The minister of DME announced in July 2019 that the port of Ngqura Coega was the preferred for site for LNG to power plants, but Transnet has issued a tender aimed for development of LNG import terminal in Richards Bay. Coega and Saldhana are however seen to be of no consequence to current gas user base, and the industry sees Maputo and Richards Bay as the best options.

Another option is the expansion of the use of the Rompco pipeline, by connection to the new fields in northern Mozambique. The pipeline has excess capacity. The gas network can be extended by the use of virtual pipelines where LNG is transported in bulk to customers, or small-scale gas networks.  This is a popular option where the volume does not justify a physical pipeline but does require LNG bulk storage facilities rather than regasification units.

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