Issue 191, Nov 2025

Roundup of major energy and electricity news and developments: 27 October to 9 November 2025

1. SA’s R2.2-trillion IRP 2025 aims to deliver secure, lower-carbon electricity.

2. Green industrialisation offers SA least-cost path to energy security and net-zero.

3. Risks identified in 2026–2030 system adequacy outlook require critical balancing act.

4. Koeberg Unit 1 returns after major maintenance; Unit 2 gets 20-year licence extension.

5. High court ruling forces transparency in South Africa’s municipal electricity tariffs.

6. Sasol’s methane-rich gas (MRG) plan delays gas cliff to 2030, raises cost questions.

7. SA extends gas-to-power RFP deadline while Mozambique LNG costs surge.

8. Renewables progress manages major growth milestones with robust project pipeline.

9. Mixed fortunes for heavy industry as Eskom CEO questions discount power deals.

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1. SA’s R2.2-trillion IRP 2025 aims to deliver secure, lower-carbon electricity.

South Africa’s updated Integrated Resource Plan for electricity, IRP 2025, published in the Government Gazette on 28 October 2025, signals a shift away from coal towards a diversified renewables, gas, storage and nuclear-driven power system, with the private sector playing a leading role. A presentation to Parliament on 4 November 2025 by Electricity & Energy Minister Kgosientsho Ramokgopa, indicates a base-case plan by 2030 comprising new capacity of 31.8 GW made up of 10.3 GW new solar PV, 7.3 GW wind, 6 GW gas-to-power, 3.7 GW of storage and 4.5 GW of private-sector distributed generation, with no new coal-fired or nuclear power. By 2042, new capacity rises to nearly 109 GW, made up of 28.7 GW new solar PV, 43 GW wind, 18.2 GW gas-to-power, 9.5 GW storage, 9 GW private-sector distributed generation and 5.2 GW nuclear, with no new coal-fired power. The total generation capacity of 158 GW envisaged by 2042 comprises a mix of 48.3 GW (30%) wind, 32.3 GW (20%) solar PV, 22 GW gas (14%), 16 GW (10.1%) private-sector distributed generation; 7 GW (4.4%) nuclear, 12.9 GW (8.1%) storage, 1.6 GW (1%) hydro and 0.6 GW (0.4%) concentrating solar, while coal’s share falls sharply from today’s 41 GW to 18 GW (11%) by 2024. Government estimates R2.2-trillion in investment will be required by 2042 to realise the plan, with policy decisions focusing on mega-renewable energy bid windows, gas-to-power development, storage and a nuclear industrialisation roadmap. Analysts describe the IRP 2025 as very ambitious, with efforts to break from fossil-fuel dependence while maintaining security of supply. However, they caution that success hinges on rapid grid expansion, streamlined procurement and investor certainty, with Minister Ramokgopa telling Parliament: “A reliable power system underpins economic growth. Planning today for tomorrow’s power is not a choice – it’s an imperative.”

2. Green industrialisation offers SA least-cost path to energy security and net-zero.

A landmark study by the National Planning Commission (NPC), Development Bank of Southern Africa (DBSA), Presidential Climate Commission (PCC) and National Treasury’s SA-TIED programme, stands as counterpoint to the Ministry of Energy & Electricity’s recently gazetted Integrated Resource Plan for electricity, IRP 2025. Published on 5 November 2025, the study represents the most comprehensive assessment yet of South Africa’s transition to a low-carbon power system, and combines advanced technical modelling with market analysis, policy review and financial diagnostics. The study’s overriding purpose is to identify how South Africa can achieve energy security at the lowest cost while meeting net-zero commitments by 2050. The study develops three scenarios: Scenario A: "Green Industrialisation"; Scenario B: "Market Forces"; and Scenario C: "Business-As-Usual" – each reflecting different combinations of domestic policy ambition and global climate alignment. Under Scenario A, installed solar PV capacity reaches 99 GW and wind 48 GW, supported by 53 GW of battery-energy storage and 23 GW of flexible gas-to-power. The coal fleet declines from 37 GW in 2025 to 10 GW – all retrofitted with carbon-capture systems by mid-century. These shifts in generation mix translate directly into the emissions trajectory. Across all scenarios, the conclusion is striking: the pathway most closely aligned with the Paris Agreement, Scenario A, also delivers the lowest overall system cost, revealing that economic efficiency and climate ambition are not in conflict but mutually reinforcing. All three scenarios demonstrate that South Africa can meet future electricity demand without building new coal or nuclear capacity, provided renewables, storage and flexible gas-to-power are deployed at scale and on time. The NPC/DBSA/PCC/SA-TIED study delivers a clear message: delaying the transition will cost more – economically, socially and environmentally – than acting decisively today.

3. Risks identified in 2026–2030 system adequacy outlook require critical balancing act.

Eskom’s latest Medium-Term System Adequacy Outlook (MTSAO) for 2026–2030, released on 30 October 2025, identifies a critical balance needed between maintaining supply security and integrating accelerating volumes of renewable energy. The study, conducted in terms of the South African Grid Code, assesses the ability of the power system to meet demand over the next five years. The analysis warns that the retirement of 8.4 GW of coal capacity by 2029, combined with the expiry of the 1.15 GW Cahora Bassa hydro import contract by March 2030, will remove nearly 9.5 GW of baseload capacity, creating a potential shortfall if new generation is delayed. The adequacy outlook assumes an average energy availability factor (EAF) of 60 – 65%, with system reliability remaining stable only if this level is sustained. 6 GW of new gas-fired capacity is planned to come online by 2030, but any delay could result in over 4 TWh of load shedding and unserved energy, forcing open-cycle gas turbines (OCGTs) to run at up to 45% utilisation, far above adequacy norms. At the same time, growing solar PV penetration, including private and embedded generation, is projected to create over 5 TWh of excess energy by 2028 in accelerated-build scenarios, increasing grid congestion and curtailment risks. This dual challenge – daytime oversupply and evening shortfalls – places added stress on coal units required to ramp up by as much as 7 GW during peak periods. Eskom’s System Operator concludes that managing this transition will demand tight coordination between generation additions, grid strengthening and demand-side flexibility to avoid renewed system instability and financial strain from excessive OCGT use.​​

4. Koeberg Unit 1 returns after major maintenance; Unit 2 gets 20-year licence extension.

Eskom has confirmed the return-to-service of Unit 1 at its Koeberg nuclear power plant in Western Cape. The unit was synchronised to the national grid on 29 October 2025 after a ten-month outage for extensive maintenance and safety upgrades. The work included over-pressure leak testing of the concrete nuclear reactor containment structure, and detailed inspection of the steam generators where cracks were identified and repaired in the tubing of two of the three new pressurised water-to-steam heat exchangers before commissioning. Eskom said the plant is now gradually ramping up toward full power output of about 930 MW, restoring significant baseload capacity to the grid. The maintenance formed part of Koeberg’s long-term operation (LTO) programme, which aims to extend the plant’s operational life by two decades beyond its original 40-year design limit. On 6 November 2025, the National Nuclear Regulator (NNR) of South Africa granted an extended operating licence for Koeberg Unit 2 until 9 November 2045, following a safety review covering structural integrity, seismic resilience and ageing-management systems. Eskom indicated that Unit 2 will shortly enter its own extended outage, which will include containment building over-pressure testing, inspection of its new steam generators, and additional preventive maintenance. The timing of the two outages has been staggered to ensure continued grid reliability and avoid simultaneous downtime of both 930 MW units. Once both units are fully operational, Koeberg will hopefully provide 1860 MW of steady baseload electricity – around 5 % of South Africa’s total energy supply. Eskom described the progress as a critical step in reinforcing system stability, improving energy security, and preserving nuclear capacity as part of South Africa’s evolving, lower-carbon power mix.

5. High court ruling forces transparency in South Africa’s municipal electricity tariffs.

The Pretoria High Court ruled on 31 October 2025 that the National Energy Regulator of South Africa (NERSA) acted unlawfully in approving municipal electricity tariff increases without ensuring adequate public participation with proper, open cost-of-supply data. The court found that NERSA routinely authorised tariff hikes within days of receiving municipal applications, denying citizens and businesses opportunity for a meaningful public participation and comment process. The judge also slammed NERSA for denying public access to municipal cost-of-supply studies which it treated as “confidential”. It ruled that such conduct violated the constitutional principles of administrative justice and transparency. Under the judgment, NERSA must now publish Eskom’s bulk-supply tariffs by 31 January each year, require municipalities to submit applications for tariff increases by end-March, and allow a minimum public-comment period with access to municipal cost-of-supply studies before final approvals are issued by early May. This new schedule aims to restore procedural fairness and ensure that tariffs are grounded in open and verifiable costs rather than estimates, averages or precedents. Civil-society organisation AfriForum, which brought the case, hailed the ruling as a major victory for accountability and consumer rights. Energy analysts agree, noting that the decision could reshape how municipal electricity prices are determined. Tariffs will now need to reflect each municipality’s actual cost of supply, potentially preventing unjustified increases and reducing disparities across the country. NERSA acknowledged the judgment and said it is reviewing its implications. The Regulator faces a critical test to align its procedures with constitutional requirements and rebuild public trust. The ruling marks a turning point in South Africa’s municipal electricity pricing landscape, underscoring that regulatory expediency can no longer trump transparency, fairness and public participation.

6. Sasol’s methane-rich gas (MRG) plan delays gas cliff to 2030, raises cost questions.

Sasol has announced a strategic shift to extend its industrial gas supply to South Africa’s market by effectively delaying the anticipated “gas cliff” to June 2030, via a bridging solution using methane-rich gas (MRG) from its Secunda operations. Under the plan, Sasol will supply MRG to customers from July 2028 through June 2030, rather than ending gas supply commitments to industrial gas users in Gauteng, Mpumalanga and KwaZulu-Natal by June 2028 as previously anticipated. The company describes this as a temporary but critical bridge to allow time for longer-term infrastructure solutions such as liquified natural gas (LNG) imports to emerge. However, the cost implications are significant. Sasol is pursuing regulatory approval with the National Energy Regulator of South Africa (NERSA) for a new “maximum gas price” (MGP) to reflect the higher cost of producing MRG compared with conventional natural gas. Analysts caution that redirecting internal methane-rich volumes to external customers may lead to reduced output of Sasol’s chemical and fuel operations and could increase end-user gas prices. Industry stakeholders warn that the extension merely shifts the timing of the supply risk rather than resolving it. The Industrial Gas Users Association of Southern Africa (IGUA-SA) has stated that without clear demand aggregation and infrastructure investment, South Africa could face higher industrial fuel costs and risk job losses. In summary, the move by Sasol offers a short-term breathing space for gas-dependent industry, but it comes with elevated input costs, regulatory dependencies, and a need for effective execution to make the 2030 milestone meaningful.

7. South Africa extends gas-to-power RFP deadline while Mozambique LNG costs surge.

The Department of Electricity and Energy (DEE) in South Africa has amended its inaugural gas-to-power procurement process, pushing the bid submission deadline for the first (Bid Window 1) phase of the Gas Independent Power Producer Procurement Programme (GASIPPPP) to 29 May 2026.  Earlier set for October 2025, the extension reflects complex issues raised by bidders including fuel-supply risk, minimum/maximum load commitments and the gas-pricing mechanism. Under the new national Integrated Resource Plan for electricity, IRP 2025, South Africa aims to introduce 6 GW of new gas-fired generation by 2030 and 18.2 GW by 2042. South Africa’s energy minister, Dr Kgosientsho Ramokgopa, even suggested that gas-to-power generation plant for South Africa could be constructed in Mozambique, with no mention of security-of-supply risks posed by vulnerable, long HVDC links across areas facing disruptive militant attacks. Meanwhile, in northern Mozambique, the LNG project developed by TotalEnergies has reported a cost increase of US $4.5-billion – raising the total from about $20-billion to $24.5-billion – after a four-year suspension of construction prompted by militant attacks in the Cabo Delgado region. The company has requested Mozambican government approval of a revised budget and schedule, while also seeking a 10-year extension to the production licence. The project is now expected to commence first gas in mid-2029, after previously targeting mid-2024. Together these twin developments reflect a regional gas transition entering a critical phase: in South Africa, the pathway to new gas capacity is facing timeline and structural risks; in Mozambique, a flagship LNG export venture must absorb substantial cost escalation and security-driven delays. The ramifications extend to industrial fuel security, electricity-market flexibility and investment-risk profiles across the Southern African region.

8. Renewables progress manages major growth milestones with robust project pipeline.

South Africa’s renewable-energy sector recorded strong activity in the second quarter of the 2025/26 financial year, with key project milestones and a deepening development pipeline. NERSA registered 181 planned new private sector generation projects during Q2 (July to September 2025), with a combined capacity of 1401 MW and an investment value of around R30-billion. Most of the additions (175 out of 181) were solar-PV projects, with the bulk planned to feed the Eskom grid, and the remainder via municipal networks. Meanwhile, two large-scale solar PV plants reached significant milestones: the 195 MW Springbok Solar Power Project near Virgina in Free State province, achieved commercial operation ahead of schedule, offering more than 430,000 MWh/year of clean energy and supporting corporate off-takers. The 97.5 MW Damlaagte solar PV facility near Parys in Free State was also officially inaugurated, having entered commercial operation in August 2025. The project forms part of a joint renewables procurement programme by Sasol and Air Liquide. On the development-pipeline front, the 2025 South African Renewable Energy Grid Survey (SAREGS), compiled by the National Transmission Company South Africa (NTCSA) alongside wind and PV industry associations, SAPVIA and SAWEA, reveals approximately 220 GW of renewable energy capacity under development. Of that, 121 GW is solar PV. The survey reports more than 72 GW at advanced “Type A” stage (EIA approved, feasibility completed) and the ability to reach commercial operation within three years if a grid connection is available. The combined indicators – strong registration of new facilities, landmark CODs and an expansive pipeline – show South Africa’s renewables sector is gaining structural momentum. The key challenge now lies in grid-integration, transmission capacity and timely offtake to convert potential into delivered generation.

9. Mixed fortunes for heavy industry as Eskom CEO questions discount power deals.

South Africa’s energy-intensive industrial sector is facing mixed fortunes as new foreign-backed investments emerge alongside deepening distress in traditional smelting industries – while Eskom warns against negotiated power discounts that shift costs onto business and households. Eskom Group CEO Dan Marokane told Business Day that Negotiated Pricing Agreements (NPAs) – special tariff arrangements historically offered to large energy-intensive industrial customers – “essentially price electricity below cost, with the shortfall socialised among other customers.” He cautioned that future NPAs must include “clear cost-benefit justification” and measurable national gain to remain defensible within South Africa’s next electricity pricing policy review, due in 2026. His comments come amid conflicting industrial signals. As ArcelorMittal SA ceased long steel production at its Newcastle plant in KwaZulu-Natal, a R25-billion Chinese-backed steel mill is rising in Nigel, Gauteng, promising 1500 direct jobs and annual output exceeding 2-million tonnes of steel, marking rare green-shoots in a sector battered by global oversupply and massively local power costs. Conversely, Samancor Chrome – one of the country’s largest ferrochrome producers – has warned it may shut several smelters, citing unsustainable electricity tariffs and shrinking export margins. The ferrochrome industry, which once processed much of South Africa’s vast chrome ore reserves, is now running below half capacity. Marokane said pricing reform must “protect the poor, support growth in agreed priority sectors, and sustain the utility.” However, analysts note that without affordable, stable power, beneficiation ambitions – such as Government’s planned 25% chrome-export tax – risk becoming symbolic. The contrasting developments indicate South Africa’s industrial policy at the crossroads: new capital inflows on one hand, and eroding competitiveness on the other – all hinging on how the next electricity pricing framework balances equity, cost recovery and industrial policy.

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