In partnership with State of the System – 2025/26 Summer Outlook Briefing 5 Sept 2025 Summer 2025 Outlook briefing Dr. Mteto Nyati 1 Opening remarks Chairperson Dan Marokane 2 Key takeaways and reflections Group Chief Executive Officer Bheki Nxumalo 3 Generation performance overview Group Executive - Gx Demand management initiatives and load Agnes Mlambo 4 reduction overview Group Executive – Dx (interim) Monde Bala 5 NTCSA focus areas NTCSA Chief Executive Officer (interim) Dan Marokane 6 Closing remarks Group Chief Executive Officer In partnership with 2 Eskom has made significant progress in addressing electricity supply constraints – and is building on this momentum for a sustainable and competitive company ▪ Reduced loadshedding from 329 days in FY24 to 13 days in FY25 (17 days Jan – Aug 2025 vs 84 days in 20241) Progress made in ▪ Improved EAF from 55% in FY23 to 60.6% EAF in FY25 recovering ▪ Diesel generator spend reduced from R30bn for FY23 to R17.7bn in FY25, and still within budget for the this FY generation capacity since 2023 ▪ Recovered >7.8GW generation capacity through long term outage completions and new build ▪ Increased IPP capacity by 385MW between FY23 and FY25 ▪ Ensuring sustained recovery of the Generation performance towards achieving 70% EAF (achieved ~66% for Aug2 Sustaining the 2025, average monthly improvement of 2.6% points between Apr and Aug 2025) gains and ▪ Addressing electricity theft - illegal connections and illicit tokens undermine service delivery, intensification of OVS addressing the leakage correction distribution sector ▪ While DAA and prepaid mechanisms are gaining traction, municipal debt remains at unsustainably high levels ▪ Focussed attention on NTCSA’s roll out of the Transmission Development Plan Long term ▪ Containing tariff increases through cost optimisation and correctly structured tariffs sustainability will ▪ Adopting risk based transition into a low carbon energy mix, considering system risks and transparent trade-offs require (managing energy trilemma) coordination and ▪ Ensuring appropriate rules are in place to enable a controlled market transition while protecting all stakeholders careful planning (including consumers) In partnership with 1: Jan to Aug 2024; 2: As of 25 Aug 2025 EAF: Energy Availability Factor; FY: Financial year; IPP: Independent Power Producer; OVS: Online Vending Server; DAA: Distribution Agency Agreement 3 Summer 2025 Outlook briefing Dr. Mteto Nyati 1 Opening remarks Chairperson Dan Marokane 2 Key takeaways and reflections Group Chief Executive Officer Bheki Nxumalo 3 Generation performance overview Group Executive - Gx Demand management initiatives and load Agnes Mlambo 4 reduction overview Group Executive – Dx (interim) Monde Bala 5 NTCSA focus areas NTCSA Chief Executive Officer (interim) Dan Marokane 6 Closing remarks Group Chief Executive Officer In partnership with 4 Reflections: Eskom’s performance has improved across several areas over the winter outlook period (April – Aug 2025) 149 10.47% Dx energy 794MW1 153 losses1 Loadshedding free days Compared to 11.33% Capacity added through the between 1 April 2025 target. Amounts to completion of Medupi U4 and 31 August 2025 5.5TWh energy lost in repairs FY26 Q1 (equivalent to running Kriel Power Station at an EAF of 91%) ~66% EAF2 135721 380MW3 For Aug 2025, 10% point Total electrification Renewable energy capacity improvement since April connections against a target added through IPP 2025, with y-o-y increase of 6201, driving universal programmes (total REIPPP in planned maintenance access to electricity installed capacity is currently 730MW below target for FY26 YTD) In partnership with Sources: FY26 Q1 Shareholders report; Divisional inputs 1: FY26 YTD/Q1, 2: Aug MTD 3: Mar 2025 – Jun 2025; Dx: Distribution; EAF: Energy Availability Factor; PCLF: Planned Capability Loss Factor; MVA: 5 Megavolt-Amperes Reflections: Minimal loadshedding levels experienced as a result of improved plant reliability and increased generating capacity Overview of loadshedding intensity and frequency between Winter 2023 and Winter 2025 # of days at various stages Stage 1 Stage 2 Stage 3 Stage 4 Stage 5 Stage 6 -97% Insights 176 16 ▪ Eskom contained loadshedding to 26 hours over 153 6 Winter 2025 – reaching 100 days without No loadshedding No loadshedding loadshedding on 24 August 2025 24 for consecutive 3 for 9 months 39 months Jun -Aug ▪ Higher than expected unplanned losses in the 2025 Winter period resulted in 4 days of loadshedding (April – May 2025) and increased 14 spend on diesel generation (although on a 67 declining trajectory) 42 ▪ Eskom is implementing interventions to address the root causes of the events during April - May 2025 55 59 13 2 4 7 1 4 3 3 Winter 2023 Summer 2023/24 Winter 2024 Summer 2024/25 Winter 2025 In partnership with EAF: Energy Availability Factor 6 Reflections: The reduction in unplanned losses since 2023 has resulted in 6GW additional available capacity (equivalent to adding ~1.5x Kusile stations2) Eskom Gx actual performance on unplanned losses across outlook periods1 August 2025 UCLF weekly performance Actual average unplanned losses (GW) Actual average unplanned losses (GW) Improvement of ~6GW, compared to Last three weeks of August showed unplanned losses in winter 2023 Medupi unit 4 further improvements down to 8GW -6 slippage unplanned losses 69 68 65 EAF % 16,5 14,9 12,4 12,5 13,0 10,1 11,1 9,0 8,4 Winter 2023 Summer Winter 2024 Summer Winter August 17-Aug 24-Aug 31-Aug 2023/24 2024/25 2025 (YTD) 2025 (MTD) Insights • Unplanned losses have been on a downward trajectory since Winter 2023, with setbacks experienced in Winter 2025 • The setbacks were primarily due to delays in returning units from outages. Interventions to address root causes are being implemented • Positive improvements in UCLF in the 3rd week of August, trending around 9GW, noting 38 units which performed with an EAF of above 80% in that week, with further improvements in the 4th week of August (~8GW unplanned losses) – resulting in weekly EAF improvement to over 68% • A notable achievement reached on 23 and 24 August with UCLF dropping to 6.9GW, the first time that performance has been below 7GW since Sept 2020 (9.6GW reduction from Winter 2023 levels, equivalent to ~2.5x Kusile stations2) Source: Eskom GPSS daily report (All stations) MTD as of 1 Sep 2025; 1. UCLF+OCLF, Numbers vary marginally over reports as data is refined. 2: Based on 6x720MW In partnership with 7 nominal capacity units at 90% availability. Acronyms: EAF: Energy Availability Factor; PLL – Partial load losses; Gx – Generation; UCLF – Unplanned Capability Loss Factor; OCLF – Other Capability Loss Factor; MTD – Month-to-date; Weekly figures reflect week end date 7 Reflections: While unplanned outages breached the moderate forecasts, loadshedding was contained to 26 hours across four days As expected Worse than expected Reflection on 2025 Winter – 1 April 2025 to 31 Aug 2025 Base case scenario + 1GW risk expectations Scenarios (14 000MW UCLF) Actual performance Number of LS days 1 Day 4 Days (26 hours) OCGT costs R 2.1bn R5.9bn Highest stage of LS Stage 2 Stage 2 Peak Residual Max Loadshedding Month Loadshedding days Max Loadshedding stage Loadshedding days Forecast - MW stage April 27,739 1 2 1 2 May 29,259 0 0 3 2 June 30,777 0 0 0 0 July 30,872 0 0 0 0 August 29,599 0 0 0 0 • Base case + 1GW risk anticipated 14GW of unplanned losses, however due to temporary plant failures, slightly higher load shedding was required in May 2025 • Diesel spend was higher than expected and exceeded spend in the comparable period for the previous year, as a result of higher unplanned losses In partnership with 8 Key interventions on supply and demand management aspects, have created ~4GW additional levers to meet expected demand over the coming summer period Improvement Neutral 2024/25 Summer Outlook Versus 2025/26 Summer Outlook Operational 1.4GW addition from return of Medupi U4 and 50GW1 dispatchable capacity 51.4GW1 expected commercial operation of Kusile U6 ~1.9GW reduction in peak planned maintenance Planned levels, due to completion of major outages during 9.8GW2 maintenance 7.9GW2 2024 and early 2025, which allows for smoothing out of execution Worst case Unplanned losses assumptions maintained to 15GW unplanned losses 15GW account for unforeseen circumstances Actual unplanned 0.8GW decrease in actual unplanned losses 11GW3 breakdowns trend3 10.1GW3 leading up to 2025/26 Summer Outlook 0.3GW increase in capacity from our demand Demand 2.1GW4 management 2.4 GW4 management programme, leading up to 2025/26 Summer Outlook In partnership with 1: Average between September and March, refers to nominal capacity; 2: Peak daily PCLF over Sept and March 3: Actual unplanned breakdowns in month before respective summer periods (Aug 2024 vs. Aug 2025), OCLF + UCLF; 4: As at start of respective outlooks, further expansion pursued. 9 2025/26 Summer Outlook - No loadshedding expected for unplanned outages below 15GW Summer 2025/26 – 1 September 2025 to 31 March 2026 (212 days) Base Case: Base Case + 1000MW: Base Case + 2000MW: Scenarios 13 000 MW UCLF 14 000 MW UCLF 15 000 MW UCLF Number of LS days 0 Days 0 Days 0 Days OCGT costs R 0.1bn R 0.4bn R 1.3bn Highest stage of LS - - - Month Peak Load shedding Max Load Load shedding Max Load Load shedding Max Load Residual days shedding stage days shedding stage days shedding stage Forecast September 28,537 0 - 0 - 0 - October 27,837 0 - 0 - 0 - November 27,538 0 - 0 - 0 - December 26,563 0 - 0 - 0 - January 26,622 0 - 0 - 0 - February 27,550 0 - 0 - 0 - March 27,841 0 - 0 - 0 - • No loadshedding is expected over the 2025/26 summer period • Limited loadshedding could be required if unplanned losses breach 15GW, the probability is considered low given current trends Note: Based on Capacity Plan 28 August 2025 BEFORE STERF. Acronyms: UCLF – Unplanned Loss Capability Factor; It is important to note that the Weekly System In partnership with Status reports is not a loadshedding forecasts, only reflects potential reserve shortfalls without considering the available short-term reserve and demand side levers; Structural shift of 1GW-2GW reduction in unplanned breakdown assumptions from Winter 2024 levels maintained, due to Gx recovery plan progress 10 Gx performance improvement and expected new capacity indicate electricity will not constrain 2% GDP growth to 2030, delivery on new capacity beyond that is crucial Indicative, will be confirmed by MTSAO in Oct Electricity supply outlook assuming growth in demand (TWh) Insights IRP base demand (~2% GDP growth) Eskom supply potential (including S34 IPP purchases) Assumed additional capacity by FY2031 Private sector supply (Wind and PV) Delivery on expected private sector • ~7GW increase in available Eskom projects becomes critical by FY31 capacity (~1GW EAF improvement, 6GW new capacity)1 350 335 339 330 323 • ~9GW increase in publicly procured 55 59 capacity (S34 IPP programmes) 300 293 50 61 • ~18GW increase in private sector capacity 34 from utility and small-scale renewable energy 250 (primarily Wind and Solar PV) 200 Risks to be managed: 150 • Plant flexibility of coal generators and 272 281 280 269 peaking capacity to accommodate increased 258 VRE 100 • Execution challenges with new capacity 50 • This is indicative and will be confirmed in Eskom’s Medium Term System Adequacy 0 Outlook once completed (Oct 2025) FY27 FY28 FY29 FY30 FY31 1: Despite shutdown of 5 stations by FY30, Eskom’s existing fleet available capacity grows by ~800MW due to improved availability projections; 2GW from RE and BESS, 3.9GW from Richards Bay gas and CCGT conversions In partnership 2: Assumes that all coal with stations operate at 90% energy utilisation factor, includes supply from S34 IPPs and imports/wheeling; 3: IRP 2024 public consultations; 4: Includes production required for network losses and exports/wheeling; 5: Assuming 25% LF for PV plants and 35% LF for Wind (in line with SA actuals over past 5 years); Assumes 1:1 correlation between GDP and electricity growth in short-med term 11 Summer 2025 Outlook briefing Dr. Mteto Nyati 1 Opening remarks Chairperson Dan Marokane 2 Key takeaways and reflections Group Chief Executive Officer Bheki Nxumalo 3 Generation performance overview Group Executive - Gx Demand management initiatives and load Agnes Mlambo 4 reduction overview Group Executive – Dx (interim) Monde Bala 5 NTCSA focus areas NTCSA Chief Executive Officer (interim) Dan Marokane 6 Closing remarks Group Chief Executive Officer In partnership with 12 Generation has completed the majority of its original Recovery Plan objectives, and will move to the next phase focussing on sustainability of recovery Implementation complete Implementation in progress 3 World class performance 70%1 2 Execute excellence 65%1 EAF 1 Set up for success EAF Actions for FY25 onwards Actions for FY24 ▪ Return of Medupi 4 from long term forced ▪ Set-up the enabling structures ❑Successful execution of Koeberg 1 outage ▪ Turnaround plans ❑Sustain excellent Medupi performance ▪ Commercial operation of Kusile 5 ▪ Generation recovery office ❑Embed principles of Operational ▪ Synchronisation of Kusile 6 Excellence ▪ Continuous focus on current and future ▪ Key enablers ▪ Guard performance at current flagship ❑Address internal skills gaps skills stations ❑Prevent outage slips ▪ Ensure successful implementation of Koeberg 2 steam generator and long-term ▪ Medupi, Lethabo, Matimba and Peaking ❑Return of Kusile 1, 2 and 3 operating projects (synchronized to the grid on ▪ Focus on the Priority stations ❑Synchronisation of Kusile 5 30 Dec 2024) ▪ Tutuka, Duvha, Majuba, Matla, Kendal, ❑Review plant shutdown dates based on Generation’s continued focus on improving Arnot, Kriel system requirements Operational Reliability and Sustainability will ▪ Kusile removed from priority list ensure that the principles of operational excellence are embedded, outage slips are ▪ Execution of Koeberg 1 Outage prevented and the number of unit trips are ▪ Source external specialised skills reduced Continuous execution of Culture transformation and Strategic Levers as per the Generation recovery plan In partnership with Note: 1. Month-to-Date for March 2024 and March 2025 13 The outlook is supported by the interventions we are putting in place to drive a plan geared towards Operational Reliability and Sustainability Operational Reliability & Sustainability Plan focus areas 1 2 3 4 Reduce number Improve Outage Execute key Enhance People, of trips planning and strategic Plant, Process execution projects Mindset • Execute projects to resolve • Strategic partnerships (OEMs, • Invest in refurbishment projects • Implement people, plant and inherent trips risks and Utilities) at key mid-life stations process interventions to eliminate single points of failure • Contract Management & • Continue with Koeberg long- address root causes leading to • Root cause analysis training for Assurance term operations refurbishments unreliability station incident investigators. • Technology, Artificial Intelligence • Leadership development focus • Expedite key projects to ensure • Roll out and implementation of • Procurement & availability of compliance to Minimum • Embed Operational excellence Gx Trip Reduction Directive at spares Emissions Standards (MES) principles all power Stations • Enhanced Outage Performance • Improve plant resilience Improvement Center (OPIC) through increased redundancy In partnership with Summer 2025 Outlook briefing Dr. Mteto Nyati 1 Opening remarks Chairperson Dan Marokane 2 Key takeaways and reflections Group Chief Executive Officer Bheki Nxumalo 3 Generation performance overview Group Executive - Gx Demand management initiatives and load Agnes Mlambo 4 reduction overview Group Executive – Dx (interim) Monde Bala 5 NTCSA focus areas NTCSA Chief Executive Officer (interim) Dan Marokane 6 Closing remarks Group Chief Executive Officer In partnership with 15 We will continue to use of our Demand Management Programme as a lever to reduce the risk of load shedding Actual Demand Management Programme results Compared to ~1456MW Available levers over the summer period 1 Apr 2025 – 30 Jun 2025 in previous period 1 Jul 2025 – 31 Mar 2026 2,386 2,093 866 879 437 375 776 1,000 63 83 Energy Supplemental Emergency Instantaneous Total EEDSM Industrial Emergency Instantaneous Total Efficiency and and load limiting response to supplemental, load limiting response to Demand Side interruptible capability support with interruptible capability support with Management load demand enabled by grid frequency and residential enabled by grid frequency incentive response smart meters stability load demand smart meters stability scheme response (EEDSM) Several demand side interventions have been implemented to support the Distribution is increasing its demand management capability through: grid, which results in: • Implementation of additional EEDSM projects • Optimisation of cost of energy through reducing the usage of expensive diesel generators and transfer pricing, especially during evening peak times • Introduction of the Residential Demand Response (RDR) (200MW is included as part of the DR supplemental) – also improves inclusiveness, and enables • Reduction in the severity of load shedding through lowering demand during residential customers to improve utilisation of distributed energy resources supply constrained periods • Smart meter load limiting capability (current 437MW), up to 2000MW • Demand Management levers can be utilised as a balance responsible lever in capability pursued by 31 March 2026 (only available in emergency circumstances) the energy trading market to further reduce overall tariffs • Instantaneous response levers support with grid frequency stability In partnership with 16 Progress is also being made to reduce load reduction, its implementation remains necessary to protect the lives of customers and electrical equipment Geographical overview of load reduction1 Load reduction trends1 % of total load reduction across South Africa Total MW across morning and evening peak Lowest Highest contribution contribution 41.7% -3% 544 546 529 19% 26.8% Load reduction is required 2.6% in areas where distribution network transformers are overloaded, primarily due to 0.3% 8.3% electricity theft and 0.3% illegal connections Apr-25 May-25 Jun-25 0.9% Largest improvement witnessed in Limpopo (-13%) and 0.2% Mpumalanga (-5%) • 529MW of load reduction was required over morning and evening peak during Jun 2025, with LP, MP and GP accounting for >87% of total • Progress has been made to reduce load reduction nationally (3% improvement from 544MW in Apr 2025 to 529MW in Jun 2025), with the largest improvements experienced in Limpopo and Mpumalanga (13% and 5% reductions respectively) • Eskom is committed to reducing load reduction by 15-20% by Mar 2026, and eradicating load reduction within the next 18 months by: • Removing and formalising of 640,000 illegal connections by Mar 2026 • Upgrading infrastructure incl., smart meters, reducing zero buyers and illegal vending • Increasing free basic electricity registrations in key areas 1: Based on MW reduced over April – June 2025 (morning + evening peak) 17 Eliminating load reduction requires an accelerated smart meter roll out, targeting 971 feeders by March 2027 Current status % of total LR across South Africa1 Improvement expected between Sep 2025 and Mar 2027 (compared to current view) Phase 1 accelerated (by Mar ’26) Phase 2 accelerated (by Mar ’27) 41.7% 29% 0% 19% 26.8% 10% 15% 0% 0% 2.6% 0% 0% 0.3% 8.3% 0.3% 5.3% 0% 0% 0.3% 0% 0% 0.9% 0% 0% 0.2% 0% 0% Currently, ~529MW of load ✓ 210 feeders, resolving EC, WC, ✓ Total of 761 feeders, resolving reduction (evening + morning peak) NC and NW Limpopo, Mpumalanga and FS is required due to distribution feeder network overloading – primarily in LP, MP, GP and KZN In addition interventions are being implemented to upgrade metering infrastructure including ~1.5 mil smart meters of the load reduction areas by Mar 2027 Reducing zero-buyers and addressing illegal vending In partnership with 1: Based on MW reduced over April – June 2025 (morning + evening peak); LR: Load Reduction; FBE: Free Basic Electricity 18 Summer 2025 Outlook briefing Dr. Mteto Nyati 1 Opening remarks Chairperson Dan Marokane 2 Key takeaways and reflections Group Chief Executive Officer Bheki Nxumalo 3 Generation performance overview Group Executive - Gx Demand management initiatives and load Agnes Mlambo 4 reduction overview Group Executive – Dx (interim) Monde Bala 5 NTCSA focus areas NTCSA Chief Executive Officer (interim) Dan Marokane 6 Closing remarks Group Chief Executive Officer In partnership with 19 NTCSA’s current transmission network expansion plans will unlock 56GW of new generating capacity over the next 10 years Transmission network rollout (TDP 2024) Insights Line km Enabling 56GW of new capacity connections • A total of 292.6km of transmission lines have been 14 494 constructed in the previous financial year (FY25) against 2 122 2 133 2 181 2 183 a target of 286 km 1 895 1 662 • The target for current financial year (FY26) is to 1 058 construct 423.1 km of transmission lines and 108.2 km 423 550 has been constructed to date. 286 • NTCSA has allocated a total capital budget of R133bn 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 Total over the first 5 years of the TDP, ending 31 March 2030. • Considerable progress has been made on key Private sector capacity grid connection status (excluding gov. procured IPPs) enablement initiatives i.e. Owner’s Engineers (OE) panel GW contracts, Engineer, Procure and Construct (EPC) lines 34 4 and substation contracts, 101 transformer contracts, line 1 construction incubation program, steel suppliers etc. 15 14 for the delivery for the TDP. • 34GW of private sector projects for wheeling or own use are currently between CEL and execution phase, CEL issued BQ in progress BQ issued In execution Total with 4GW in execution and expected to be connected (connection by FY2028) to the grid by FY28 The ERAA supports the fast-tracking of this plan by introducing a procurement mechanism that enables the Minister of Electricity and Energy to acquire new transmission infrastructure through ITPs In partnership with Footnote: TDP – Transmission Development Plan, ERAA – Electricity Regulation Amendment Act. CEL: Cost Estimate Letter; BQ: Budget quotation; ITP: Independent Transmission Projects 20 As South Africa’s electricity system incorporates increased variable renewable energy (especially Solar PV), flexibility of the system becomes a key priority Grid demand profile variability driven by increased Solar PV generation GW residual demand across day Insights ~5% average cloud cover at noon (2 Jun 2025) Illustrative 50% increase in Solar PV • South Africa currently has 9.3 GW Solar PV (2.3 ~68% cloud cover at noon (9 Jun 2025) 8GW (38%) ramp up required from Eskom’s fleet GW from government procured renewable IPPs + between midday and 7GW behind the meter) installed across the country 32 +8 evening peak • The variance in demand for grid supplied 30 dispatchable capacity currently varies ~ 5GW at noon across days and ~8GW between noon and 28 evening peak, strongly influenced by Solar PV 26 5GW fluctuation generation in midday • With a 50% increase in Solar PV (conservative 24 +5 production considering expected projects by 2030), these 22 required from variances will increase to up to 10GW, which Eskom’s fleet creates significant flexibility requirements and 20 planning uncertainty 18 • More coordinated planning is a key priority, to 16 ensure system stability and associated variability risks despite increase in available capacity, is 14 managed over the summer period 12 • Understanding geographical distribution of Morning peak Midday Evening peak existing and new Solar PV is a key aspect of improved (06:00-08:00) (12:00-14:00) (18:00-19:00) system operations In partnership with Note: Weather also influences demand between cloudy and sunny days 21 Electricity system reforms are underway to support a rules based competitive electricity sector Market Operator license Application submitted and confirmation of adequacy received from NERSA on 6 Aug 2025 – NERSA public hearings anticipated on 30 Sep 2025 Preparation of market participants South African Market Code The SAWEM school Wholesale Electricity Draft published and open for launched Jul 2025, with Market public input until 18 Sep further events scheduled to run 2025, final market code between Aug and Dec 2025 workshop scheduled for 11 Sep 2025 Market platform, systems and processes Internal pilots currently in progress, additional IT systems and processes in development - on track for launch in Apr 2026 Prequalification stage for ITPs (opened 31 July 2025), will play a crucial role in broader reform of the electricity sector In partnership with SAWEM: South African Wholesale Electricity Market; ITP: Independent Transmission Projects 22 Summer 2025 Outlook briefing Dr. Mteto Nyati 1 Opening remarks Chairperson Dan Marokane 2 Key takeaways and reflections Group Chief Executive Officer Bheki Nxumalo 3 Generation performance overview Group Executive - Gx Demand management initiatives and load Agnes Mlambo 4 reduction overview Group Executive – Dx (interim) 2025/26 Summer outlook and NTCSA focus Monde Bala 5 areas NTCSA Chief Executive Officer (interim) Dan Marokane 6 Closing remarks Group Chief Executive Officer In partnership with 23 Through the collective efforts of our internal and external stakeholders, Eskom continues to improve security of electricity supply in South Africa Thank you to all the Eskom No loadshedding is expected over the Summer period from 1 Sep 2025 to 31 Guardians and stakeholders for Mar 2026 - unplanned losses are to be maintained below 15GW the continued commitment to restore security of electricity supply in South Africa Reduction of unplanned breakdowns remains a priority – with Gx capacity now added, continued focus on embedding operational excellence (reducing unit trips and preventing outage slips), will bring us to comfortably meeting demand all the time. Eskom is committed to reducing load reduction through removing and formalising illegal connections, upgrading infrastructure and supporting increased registration for free basic electricity The development of the SAWEM and delivery of transmission capacity expansion to connect new capacity, is important to ensure sufficient electricity supply and accommodate economic growth In partnership with 24 In partnership with Question & Answer session In partnership with A ~30% improvement in UCLF was noted between the first and last week of August 2025 Generation Overview weekly performance FY2026 (%) Insights OCLF UCLF PCLF EAF • EAF was maintained between 61% and 69%, with late August marking peak performance – 0 0 1 0 0 0 1 0 29 25 24 21 25 23 19 17 UCLF in the last week almost ~2GW lower than in 10 12 14 9 10 10 12 11 the same week in the previous year 61 64 65 69 62 65 69 68 • UCLF showed a steady improvement from early July to late August, reflecting enhanced operational control, improved reliability and overall 03-Aug 24-Aug 10-Aug 17-Aug 31-Aug 13-Jul 20-Jul 27-Jul stronger fleet performance • Due to having excess capacity, some units were placed on cold reserve which enabled Weekly Total Unplanned performance comparison in GW additional opportunity maintenance to be Total Unplanned FY2025 Total Unplanned FY2026 conducted 13,8 -29% • The reduction in total unplanned losses from 12,5 11,7 12,1 over ~13 800 MW in early July to under 8 400 11,6 10,2 10,0 11,2 11,9 11,2 11,1 10,9 10,5 10,0 9,0 MW by late August highlights a clear trajectory of 8,4 recovery and consistent improved performance 3-Aug 10-Aug 17-Aug 24-Aug 31-Aug 13-Jul 20-Jul 27-Jul In partnership with 1: The report is based on prelim figures, i.e., subject to verification OCGTs utilisation drastically reduced from the start of July 2025, lower than the comparable period in previous year Eskom Only Weekly OCGTs Usage (GWh) Comparison Jul – Aug1 OCGTs FY2025 OCGTs FY2026 49 35 15 12 12 13 12 5 4 4 5 0 0 2 0 0 7-Jul 14-Jul 21-Jul 28-Jul 11-Aug 4-Aug 18-Aug 25-Aug Eskom OCGTs R’m1 287 203 68 21 74 0 0 0 Key Insights • OCGT utilisation was 0GWh between 8 to 31 August 2025, underscoring efficient base-load performance and reduced reliance on OCGT support • IPP’s were minimally utilized during this period In partnership with 1: The report is based on prelim figures, i.e., Denotes Eskom OCGTs weekly actual costs subject to verification xx Excl. 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