Eskom Presentation to the Joint Portfolio Committee on Public Enterprises & Mineral Resources and Energy System Status and Outlook System Operator 31 August 2022 Overview Summary of system status Summary of Load shedding and curtailment Power System Outlook 2 Summary of system status IF Financial year-to-date energy sent out from dispatchable plant is 1.4% lower than for the same period last year. (0.67% lower for dispatchable and renewable) IPP OCGT load factor is 9.9%, Eskom OCGT load factor is 16.4% (Financial year to date) There were 24 wind generation curtailment events in the financial year. There were 77 days of load shedding in the financial year. The highest residual demand (demand supplied by dispatchable generation) for 2022 was 33 136 MW The highest contracted peak demand (demand supplied by dispatchable and renewable generation contracted to SBO) for 2022 was 34 666 MW 3 Loadshedding and load curtailment summary IF YTD for Calendar Year 2022 Stage 5; 3 Stage 6; 4 Stage 1; 6 Stage 4; 19 Stage 2; 52 Stage 3; 7 In general, some of the following conditions led to the • For FY2022, there have been a total of 65 days of above load reductions: loadshedding, with 22 days of load curtailment at Stage 1&2 • Shortage of generation; • Since 01 January 2022, there have been 91* days of • Increased unplanned unavailability; loadshedding, with 18 days of load curtailment at Stage 1&2 and • Limited fuel availability at peaking stations; 2 days at Stage 3 • The need to conserve and replenish depleted emergency resources; • Poor coal and compromised emissions performance. Load curtailment is the load reduction obtained from customers who are able to reduce demand on instruction and satisfy the requirements of NRS048-9 for load curtailment * As at 29 Aug 2022 4 Power System Outlook (Summer Plan 2022/23) Planning process IF Capacity 18 month Summer UCLF + plan uses residual Plan uses 10 000 OCLF 13 000 demand MW forecast MW forecast UCLF UCLF Eskom Generation Schedule Include IPP Optimised Plan maintenance maintenance and Optimised Capacity dispatchable with stress requirements for 18 optimise available Plan with UCLF generation and months ahead capacity excluding assumption emergency tested UCLF (Capacity Plan) OCGTs reserves scenarios • Power stations • Gx Production and • IPP dispatchable • Estimated diesel determine their System Ops in generation included requirement maintenance consultation with by System Operator • Estimated stage and requirements other stakeholders • Emergency reserves frequency of load iteratively optimise such as ILS, VPS shedding the plan included by System Operator All reliability maintenance outages are catered for in the 12 month planning period The maintenance outage optimization is done in the Capacity Plan using an unplanned unavailability provision of 10 000 MW. Anything higher than this does not make sense because there would be no room to schedule maintenance. The difference between the Capacity Plan and the System Outlook (Summer Plan) is that the Capacity Plan contains risks in the assumptions while the System Outlook Plan shows the consequences should those risks materialize. Components of the Plan IF • Four critical components make up the Plan and determine the need for OCGT generation usage and load shedding. • Due to the 4 000MW uncertainty in unplanned unavailability, scenario planning is necessary to determine the likely outlook. Installed generation capacity: This includes new build non-commercial generators and dispatchable IPP OCGTs but excludes self-dispatch renewable generation. Demand forecast: The residual demand forecast (total demand less demand supplied by renewable generation) is used. PCLF: Planned generation outages for maintenance. UCLF + OCLF (Unplanned unavailability): Unplanned generation outages. Cumulative Monthly Unplanned Outage Levels IF Cumulative Monthly Unplanned Outage Levels Monthly OCLF % Monthly UCLF % UCLF+OCLF % Trend - Jan 2017 to Mar 2020 UCLF+OCLF % Trend - Apr 2020 to-date Monthly OCLF MW Monthly UCLF MW UCLF+OCLF MW Trend - Apr 2020 to-date UCLF+OCLF MW Trend - Jan 2017 to Mar 2020 50,0% 25 000 45,0% 22 500 40,0% 20 000 Average Monthly Outages (MW) 35,0% 17 500 Outage Factors (%) 30,0% 15 000 25,0% 12 500 20,0% 10 000 15,0% 7 500 10,0% 5 000 5,0% 2 500 0,0% 0 May-2017 May-2018 May-2019 May-2020 May-2021 May-2022 Sep-2017 Sep-2018 Jan-2019 Sep-2019 Sep-2020 Sep-2021 Mar-2022 Jan-2017 Jul-2017 Jan-2018 Jul-2018 Jul-2019 Jan-2020 Jul-2020 Jan-2021 Jul-2021 Jan-2022 Jul-2022 Mar-2017 Nov-2017 Mar-2018 Nov-2018 Mar-2019 Nov-2019 Mar-2020 Nov-2020 Mar-2021 Nov-2021 Months Source: Gx Technical Indicators Reports 8 Unplanned Outage Performance: Winter 2022 IF Total view unplanned outages during Winter 42.5% of the time we operated above the maximum assumption for the Winter Plan The average UCLF+OCLF over evening peaks was 14 864 MW over the winter period 9 Summary of the Plan IF All reliability maintenance required in the 12-month planning period has been accommodated in the plan. This has resulted in a “full” plan with little room to move, extend or add outages. This outage plan was stress tested with 3 scenarios by the System Operator to estimate the OCGT usage and level of load shedding. For summer 2022/23, 13 000 MW, 14 500 MW & 16 000 MW of UCLF + OCLF provision was used. For the most part the System Operator will need to source operating reserves from Demand Response (DR) products as well as from emergency reserve sources such as Interruptible Load Shedding (ILS) and OCGTs. The Plan requires OCGT usage over weekdays, and low diesel usage on some weekends. The failure of Medupi 4 has increased the dependency on diesel generation to manage the power system. 10 Risks & uncertainty IF The plan is “tight” and any significant outage slips will have a knock-on effect that will influence the plan from that point forward. The plan does not cater for difficulties that could arise at power stations due to industrial action or other employee protests. There is a ± 2 000 MW variance in UCLF (4 000 MW). This is often the variance in one week (168 hours). This cannot be predicted and makes planning uncertain. This is equivalent to four stages of load shedding. In practical term it mostly means we operate in the range of having 2 000 MW of reserve to needing Stage 2 load shedding to create sufficient reserves. Demand response was added to the plan in anticipation of signing up new customers. The demand forecast was reduced by 150MW for September 2022 – February 2023 and 400MW for the rest of the planning period. The uncertainty of the Plan must be clearly communicated and understood by all stakeholders including government and the public. 11 Critical success factors IF All resources and funding must be made available as needed to execute this plan. Any changes to this will have a knock-on effect that will influence the plan from that point forward. The success of the plan relies on sufficient diesel to support the power system during periods of high UCLF. Without sufficient diesel to power the 3 000 MW of OCGT, 3 additional stages of load shedding could be added to the scenarios shown below. Prolonged diesel usage may result in delays in getting fuel to the OCGT stations (approval of funds, procurement of product & logistics to move fuel). Failure to supply sufficient diesel will lead to further load shedding. Outage 126 (SGR and refuelling) at Koeberg will significantly increase the risk of load shedding for 240 days. 12 System Operator Capacity Outlook for the next 12 Months (Base Case) IF System Operator Capacity Outlook (Base Case) MW Available Capacity (Excl Gas) Gas Reserve Requirement Planned Outages 51000 Unplanned Provision Peak Residual Forecast Installed Capacity 49000 47000 45000 UCLF Assumption: 43000 13 000 MW 41000 39000 37000 35000 Operating Reserve 33000 PCLF 31000 29000 27000 25000 Gas 23000 Available Capacity (Excl Gas) 21000 19000 Apr 2023 Oct 2022 Jun 2023 Sep 2022 Feb 2023 Mar 2023 Jan 2023 Jul 2023 Nov 2022 Dec 2022 May 2023 Aug 2023 Month 13 Monthly System Status Outlook to March 2023 IF System Status Including 2200MW Operating Reserves Base Case Base Case + 1500 MW Risk Base Case + 3000 MW Risk Load Max Load Estimated Estimated Gas Load Max Load Estimated Estimated Gas Load Max Load Estimated Estimated Gas Peak Residual Unplanned Reduction Reduction Monthly Gas Generation Reduction Reduction Monthly Gas Generation Reduction Reduction Monthly Gas Generation Month Forecast Provision Days Stage Generation Cost (Rm) Days Stage Generation Cost (Rm) Days Stage Generation Cost (Rm) September 2022 30,109 13,000 0 119,468 R665.43 19 ❷ 354,136 R1,972.54 27 ❸ 831,408 R4,630.94 October 2022 29,325 13,000 0 92,986 R517.93 10 ❷ 293,245 R1,633.37 22 ❸ 716,259 R3,989.56 November 2022 28,959 13,000 4 ❶ 139,976 R779.66 17 ❷ 524,211 R2,919.85 26 ❸ 1,047,261 R5,833.24 December 2022 28,687 13,000 3 ❶ 369,908 R2,060.39 19 ❷ 992,008 R5,525.48 30 ❸ 1,606,074 R8,945.83 January 2023 28,311 13,000 2 ❶ 386,768 R2,154.30 20 ❷ 960,217 R5,348.41 28 ❸ 1,438,280 R8,011.22 February 2023 29,058 13,000 13 ❶ 309,414 R1,723.44 20 ❸ 799,608 R4,453.82 28 ❹ 1,144,764 R6,376.34 March 2023 29,185 13,000 0 217,311 R1,210.42 18 ❷ 737,022 R4,105.21 28 ❸ 1,323,497 R7,371.88 April 2023 31,621 13,000 0 95,376 R531.24 13 ❷ 310,969 R1,732.10 23 ❸ 711,408 R3,962.54 May 2023 34,267 13,000 2 ❶ 135,735 R756.04 19 ❷ 313,830 R1,748.03 30 ❸ 617,546 R3,439.73 June 2023 33,710 13,000 0 103,916 R578.81 16 ❷ 258,355 R1,439.04 28 ❸ 544,987 R3,035.57 July 2023 33,397 13,000 0 107,663 R599.68 17 ❷ 272,627 R1,518.53 29 ❸ 577,283 R3,215.47 August 2023 32,111 13,000 0 95,656 R532.80 15 ❷ 273,460 R1,523.17 27 ❸ 599,437 R3,338.86 Note: The base case unplanned unavailability provision (UCLF+OCLF) has been increased to 13 000 MW for summer based on the performance over the past year. The scenarios stress tested are at 1 500 MW intervals above the base case. History has shown that it is not possible to use more than about R 2.4bn of diesel in a month due to the physical limitations of moving the diesel to the OCGT stations. Where the Plan shows a diesel usage greater than this, additional stages of load shedding should be expected 14 Interventions to contribute to the National Energy Crisis Committee MM Overview of estimated additional capacity over 36 months (MW) Notes • Plant performance is based on Plant performance Eskom JET Generation recovery plan to address load Eskom New build New Generation capacity losses and includes Kusile units currently in operation 8,011 7,389 648 • New build includes commissioning of units 5 and 6 at Kusile, and recovery of 1,075 1,250 unit 4 at Medupi (Aug 2024) 794 • Procurement of new Generation capacity 337 consists of: • Standard offer, emergency 3,514 procurement, imports from the region ~ 2300 MW in the next 12 months. 2,861 6,113 1,814 5,183 • Land leasing initiative and Section 1,401 34 procurement (RMIPPPP, battery 1,474 storage and bid window 5,6 included 800 674 in the latter part of the plan), 24 1,700 660 800 months onwards 6 months 12 months 18 months 24 months 36 months • Additional ~1450MW of demand onwards management interventions over 3 years • Successful implementation of all the initiatives will greatly reduce the risk of load shedding • Timing of new generation capacity is dependent on the market response and regulatory processes 15 Thank you 16