Eskom Revenue Application. Multi-Year Price Determination (MYPD 4) FY2019/ /22

Transcription

1 Eskom Revenue Application Multi-Year Price Determination (MYPD 4) FY2019/ /22 September 2018

2 Contents Contents 1 Executive Summary Structure of the Generation Licensee Context of the Generation Licensee operating environment Operational Environment Generation technical performance parameters Stress test on Production Planning Plant performance benchmarks Production Planning Production Planning Objective Production Planning Process Production Planning Assumptions Eskom Generation Capacity Eskom new build capacity assumptions Energy forecast assumptions Non-Eskom supply assumptions Eskom Plant Performance Indicator Approval and monitoring of Production Plan Production Plan Outcome Conclusion on Production Plan Primary Energy Overall summary of primary energy Independent power producers (IPPs) Section 34 Procurement Eskom programmes International purchases Demand response Introduction to Demand Response Demand response products and rates Assumptions Other Ancillary services Coal burn costs Introduction Coal market overview Key elements of Eskom coal strategy to exploit and mitigate the trends and market Key assumptions underlying the coal sourcing plans and coal forecasts Benchmarking Governance Summary of total coal forecast volumes and cost Coal Burn Cost Logistics Stock management over the MYPD 4 Period Conclusion on coal costs Eskom Holdings Revenue Application FY2019/ /22 September 2018 Page 2 of 131

3 Contents 5.6 Water Introduction Water Assumptions Key drivers affecting the water cost forecast Future Water Demand and Infrastructure Water Risks Conclusion on water costs Limestone Introduction to Limestone Quantities of limestone required The cost of limestone: Conclusion on limestone costs Nuclear fuel burn Introduction Assumptions Nuclear fuel primary energy cost OCGT fuel burn Introduction to OCGT fuel OCGT Specifications OCGT Decision Making Criteria Coal handling Introduction to coal handling Conclusion on coal handling Water treatment Start-up gas & oil Environmental levy Introduction Process Planning Fuel Procurement costs Operating Costs (Opex) Introduction to Operating Expenditure Key drivers of operating costs Capacity expansion Reserve storage stations Ageing fleet and high UCLF impact on maintenance costs Employee benefit costs Insurance costs Once-off abnormal items Once-off decommissioning adjustment in 2017/ Once-off provision raised for Duvha unit 3 insurance refunds in 2017/ Maintenance costs in 2018/19 and 2021/ Opex Benchmarking Benchmark benefits Benchmark Manpower Introduction The headcount planning process Growth in generating capacity and refurbishments required since Assessing the Reasonability of the Headcount Eskom Holdings Revenue Application FY2019/ /22 September 2018 Page 3 of 131

4 Contents Risks associated with headcount reductions Conclusion Maintenance cost Introduction Key drivers of maintenance costs Conclusion on maintenance costs Other Opex Decommissioning provision adjustment Internal electricity usage Other Income Conclusion on Opex RAB, Return and Depreciation Regulated asset base (RAB) Assets (including WUC) comprise the following components: Assets as per the March 2016 asset valuation Work under construction (WUC) Depreciation Return on assets Capital Expenditure Introduction Generation New build and major technical plan projects Overview Key issues impacting the build programme Capex cost elements Environmental compliance Generation Technical Plan Projects Overview of the life of plant plan (LOPP) for a power station TechPlan Capex Outage Capex Overview of outage maintenance strategy Prioritisation of outages: Capacity planning Process of costing an outage Future Fuel Capex Coal future fuel Water future fuel Nuclear future fuel Asset purchases Conclusion on capital expenditure Conclusion Eskom Holdings Revenue Application FY2019/ /22 September 2018 Page 4 of 131

5 Contents List of Tables Table 1: Generation MYPD 4 Revenue Requirement... 8 Table 2: Generation EAF Table 3: Stress Test Energy Forecast and Plant Performance Table 4: Stress Test Eskom new build Commercial Operational dates Table 5: Eskom existing capacity Table 6: Eskom new build capacity Table 7: Net energy forecast as per wheel diagramme Table 8: International Imports and Independent Power Producers (GWh) Table 9: Generation Technical Performance Table 10: Energy production per plant mix (GWh) Table 11: Summary of primary energy costs Table 12: Assumed costs for IPP energy Table 13: Renewable IPP energy costs per technology type Table 14: International Purchases Table 15: Coal strategy FY16 compared to FY08 & FY Table 16: Analysis of annual coal burn variances (Rbn) Table 17: Total raw water costs for all stations Table 18: Energy Sent Out for stations with FGD Table 19: Volume of limestone required Table 20: Forecast purchases cost of limestone (R m Nominal) Table 21: Forecast consumption cost of limestone (R m Nominal) Table 22: Nuclear Fuel Pricing (R million) Table 23: Nuclear Future Fuel Balance Sheet Reconciliation (R million) Table 24: Nuclear fuel stock reconciliation Table 25: Nuclear primary energy costs (R million) Table 26: OCGT Assumptions Table 27: Environmental Levy summary Table 28: Fuel procurement cost per category rand million Table 29: Headcount Assumptions Table 30: Overall summary of operating costs Table 31: Generation headcount Table 32: Reduction in maintenance costs at the reserve storage stations (R m) Table 33: Generation Other Opex R m Table 34: Generation Other Income rand million Table 35: Regulatory Asset Base (RAB) summary Table 36: Extract from Consultant 2016 Asset Valuation Report Table 37: FY2016 RAB values as assumed for purposes of MYPD3 revenue decision Eskom Holdings Revenue Application FY2019/ /22 September 2018 Page 5 of 131

6 Contents Table 38: Depreciation Table 39: Return on Assets Table 40: Generation Capex Summary Table 41: Commercial Operation dates for remaining units Table 42: Medupi overall % complete as at End of August Table 43: Kusile overall % complete as at End of August Table 44: Examples of refurbishment/replacemnt intervals Table 45: Nuclear future fuel Capex (R million) Table 46: Generation asset purchases rand million LIST OF FIGURES Figure 1: Performance of Eskom s fleet Figure 2: Age of Eskom s fleet at 1 April Figure 3: EUF Benchmarking Figure 4: Unplanned Capability Loss Factor (UCLF) Benchmarking Figure 5: Planned Capability Loss Factor (PCLF) Benchmarking Figure 6: Energy Availability Factor (EAF) Benchmarking Figure 7: Overall Production Planning process Figure 8: Generating units reaching 50 years life Figure 9: Eskom production versus Non-Eskom production (GWh) Figure 10: Renewable IPP Energy Costs per Technology type Figure 11: Summary of REIPP costs over life of contracts Figure 12: Coal burn cost (rand million) Figure 13: Coal value chain Figure 14: Challenges facing Eskom coal procurement Figure 15: Main coal suppliers Figure 16: Price of coal comparison Eskom vs Export Figure 17: Purchases and burn volumes (Mt) Figure 18: Mine cost inflation outstrips PPI (Source: SA Chamber of Mines) Figure 19: Challenges in Eskom s environment Figure 20: Average FOT steam coal prices(r/t) Figure 21: Coal burn projections (Mt) Figure 22: Coal procured categorised by contract type (%) Figure 23: Annual coal expenditure per supply source Figure 24: Forecast logistics modes and costs for long and medium term sources Figure 25: Forecast logistics percentages per mode for long and medium term sources Figure 26: Forecast system coal stock days Figure 27: Total raw water costs for coal-fired stations Eskom Holdings Revenue Application FY2019/ /22 September 2018 Page 6 of 131

7 Contents Figure 28: Coal handling costs Rmillion Figure 29: Water treatment costs Figure 30: Start-up gas and oil costs Figure 31: Benchmark compared to real O&M $/kw (coal only) Figure 32: Classification of organisational critical workforce segments Figure 33: Maintenance planning overview Figure 34: Total Maintenance costs R m Figure 35: Process for valuation of existing assets Figure 36: Opportunities for air quality offsets: Reducing local waste burning Figure 37: Codified Asset Management Strategy for generation Eskom Holdings Revenue Application FY2019/ /22 September 2018 Page 7 of 131

8 Executive Summary 1 Executive Summary 1.1 Context of Eskom Generating environment Eskom is operating an ageing Generation fleet, notwithstanding the new power stations under construction. More than half of the stations and more than half of the coal-fired stations will be over 37 years old by the start of the MYPD 4 period. Due to various constraints, most notably inadequate capacity and financial limitations, the mid-life refurbishment and enhancement projects that are required to maintain and improve technical performance as plants age, have generally not been implemented. Together with high utilization that places higher than expected wear and tear on components and systems, in particular since 2008, this has contributed to a steady decline in generating plant availability over the past decade. Due to a combination of performance improvements, additional capacity (both Eskom and IPPs), as well as stagnant demand, the rapid decline in availability post 2010 has been arrested and availability has improved to 78% in 2017/18 from a low point of 72%. The constraints, particularly financial, however, remain and the reversing overall trend to maintain and improve current performance continues to be a challenge. 1.2 Revenue requirement summary TABLE 1: GENERATION MYPD 4 REVENUE REQUIREMENT Allowable Revenue (R'millions) AR Formula Application Application Application Forecast Forecast 2019/ / / / /24 Regulated Asset Base (RAB) RAB WACC % ROA X -1.32% -0.21% 1.45% 1.76% 2.46% Returns Expenditure E Primary energy PE IPPs (local) PE International purchases PE Depreciation D IDM I + Research & Development R&D + Levies & Taxes L&T RCA RCA + Subtotal R'm Not claimed in Application Corporate Social Investment (CSI) Total Allowable Revenue The table above summarises the revenue requirement for the Generation licensee in accordance with the MYPD methodology with a proviso that the return on assets is not applied for as in the methodology, but is gradually phased over the MYPD 4 period. Eskom Holdings Revenue Application FY2019/ /22 September 2018 Page 8 of 131

9 Executive Summary 1.3 Return on assets The ERA and the Electricity Pricing Policy require the recovery of efficient costs and earning a fair return on revalued asset valuations. In accordance with the MYPD methodology, Eskom is allowed to earn a return on the Regulatory Asset Base (RAB) as well as on relevant capital works that are under construction. An asset valuation study was conducted to determine the value of the installed Generation RAB by an independent entity in 2016 and has been submitted to NERSA. The MYPD 4 RAB values are based on this asset valuation study as well as the planned capital expenditure. As summarized in Table 1, the RAB value increases over the MYPD 4 period as new assets are brought into commercial operation and new planned projects investments are incurred. In order to contain the impact of the overall Eskom revenue requirement, a revenue sacrifice with return on assets was included. The return on assets is being phased, as reflected in the table above. Together with the depreciation, a substantial portion of the debt service commitments will be applied for. This is to a contribution towards minimising the impact of the price increase on the consumer. 1.4 Primary energy The CAGR for coal costs is approximately 7.8% over the application period. The compound annual growth rate (CAGR) for water costs over the period 2018/19 to 2021/22 is 8%. Many of the other primary energy components experience a negative annual growth rate. This is due to certain power station units being on reserve storage, as assumed in this application. Increases in IPP costs are in accordance with the contracts that have been finalised. 1.5 Operating expenditure Generation s operating costs forecast is prudent and efficient as reflected in the comparison with international norms. The compound average growth rate (CAGR) for the period 2018/19 to 2021/22 for Generation operating costs including corporate overheads is 4%, which is below inflation. The CAGR for the period 2018/19 to 2021/22 for Generation manpower costs is 3.2%, which is below inflation. The above inflation increases for the bargaining unit employees per the negotiated wage settlement with the trade unions, was offset by the reduction in headcount over the forecasting period. Eskom Holdings Revenue Application FY2019/ /22 September 2018 Page 9 of 131

10 Executive Summary The CAGR for the period 2018/19 to 2021/22 for Generation maintenance costs is 3%, which is below inflation. This is mainly due to the reduction in maintenance costs at the reserve storage stations, partially offset by increased maintenance costs at Medupi and Kusile as new units are brought into commercial operation, which will add maintenance costs to the Generation fleet base during the MYPD 4 period. The CAGR for the period 2018/19 to 2021/22 for Generation Other Opex is 11.2%, which is above inflation. This mainly because the 2018/19 other Opex is abnormally low due to liquidity challenges. However, this low level of expenditure on other Opex is not sustainable into the future. Using the 2017/18 actuals (adjusted for abnormal items) as a base, other Opex costs reduce over the forecasting period. This reduction in costs is mainly due to a reduction in costs at the reserve storage stations. 1.6 Environmental compliance The environmental clause in the Bill of Rights sets the context for environmental protection, providing for an environment which is not harmful to health and wellbeing and for ecological sustainable development. The National Environmental Act and several Strategic Environmental Management Acts (SEMA s) give effect to the environmental right in the Constitution. The development of environmental legislation has resulted in new and more stringent requirements which Eskom is obligated to respond to in order to continue operating its power stations. Given the nature of Eskom s activities these requirements are far reaching, they affect all the divisions and subsidiaries in some manner, including air quality, protection of the natural environment and biodiversity, water use and preventing pollution of water resources, general and hazardous waste management, the utilisation of ash and licensing processes. These legislative requirements are enforced through licences and permits. They lead to operational and capital expenses. To retain the licence to continue to operate, these expenses must be allowed for in the tariff, preferably in a manner which separates non-negotiable statutory requirements from refurbishment and maintenance expenses. Eskom Holdings Revenue Application FY2019/ /22 September 2018 Page 10 of 131

11 Structure of the Generation Licensee 2 Structure of the Generation Licensee The role of the Generation Licensee is to manage the full generation value chain from the construction of new generation plant, through to the production of electricity products to the national grid. This includes the sourcing of primary energy, lifecycle management (which incorporates routine and regular maintenance activities as well as major refurbishment and performance improvement projects), production planning, outage planning, engineering services and the operation of the power stations to provide not only the energy to serve daily requirements and capacity to meet the peaks but also ancillary services to assist the grid operator in maintaining grid security. The Generation Licensee includes the Generation Division which operates and maintains the power stations, the Primary Energy Division which sources primary energy for the stations and Technology, which provides technology services to the stations. The various departments that deal with IPPs, Renewables and International purchases also form part of the Generation Licence. The Group Capital Division is responsible for the execution of capital projects. This includes the new build stations, currently Medupi and Kusile, as well as all major capital projects at the existing stations. In addition there are a number of centralised service and strategic functions that provide services to the various Licensees. These include, but are not limited to, Finance, Human Resources, Commercial, Security, Stakeholder Management, and Sustainability which is responsible for both Environmental and Safety Management. The costs of these centralised services are allocated to the Generation Licensee based on various allocation criteria. Eskom Holdings Revenue Application FY2019/ /22 September 2018 Page 11 of 131

12 Context of the Generation Licensee operating environment 3 Context of the Generation Licensee operating environment 3.1 Operational Environment Eskom is operating an ageing Generation fleet, notwithstanding the new power stations under construction. More than half of the stations and more than half of the coal-fired stations will be over 37 years old by the start of the MYPD 4 period. Due to various constraints, most notably inadequate capacity and financial limitations, the mid-life refurbishment and enhancement projects that are required to maintain and improve technical performance as plants age, have generally not been implemented. Together with high utilization that places higher than expected wear and tear on components and systems, in particular since 2008, this has contributed to a steady decline in generating plant availability over the past decade. Due to a combination of performance improvements, additional capacity (both Eskom and IPPs), as well as stagnant demand, the rapid decline in availability post 2010 has been arrested and availability has improved to 78% in 2017/18 from a low point of 72%. The constraints, particularly financial, however, remain and the reversing overall trend to maintain and improve current performance continues to be a challenge. Eskom generally has adequate capacity available to meet demand for most hours of the day. The system is, however, constrained, as during peak hours, especially the evening peak hours, there is often not enough available capacity to meet the demand without the use of OCGTs. By implication, Eskom currently does not have excess capacity. However, as more new units from Medupi and Kusile come online and Generation plant availability improves, the situation will improve. Three Medupi units and one Kusile unit are already commercial and another unit at each station is already supplying energy to the grid and will become commercial during 2018/19. The latest projections show one additional unit from each station in commercial operation per year from 2019, resulting in the last Medupi unit becoming commercial in 2020 and the last Kusile unit in As this additional capacity comes on line, it is anticipated that some of the older and more expensive stations will not be required to meet the electricity demand. Although the planning assumption for the life of coal-fired stations is 50 years, Eskom considers the economic viability of a power station in addition to its age to determine when power stations should be decommissioned. Eskom Holdings Revenue Application FY2019/ /22 September 2018 Page 12 of 131

13 Context of the Generation Licensee operating environment Further analysis of the impact of station closure on employees and the community, a stakeholder engagement plan and the impact on jobs is being conducted. However, when these stations will no longer be required to generate electricity depends on a number of factors which include the performance of the rest of the Generation fleet, the timing of the commercial operation of the new build units at Medupi and Kusile and IPP stations, as well as demand growth. These stations will thus not be decommissioned, but kept in reserve storage as risk mitigation for the above assumptions. This is particularly relevant as current Generation EAF is approximately 75% and latest projections indicate that EAF for 2018/19 will be no more than 75%. Final decisions on decommissioning any stations will be aligned to the Integrated Resource Plan (IRP), which still has to be finalised. 3.2 Generation technical performance parameters Generation s availability energy availability factor (EAF) has improved from a low of 71.1% in 2015/16 to 78.0% in 2017/18. Eskom s aspiration is to drive availability (EAF) to and to maintain 80%. Current EAF for 2018/19, as at August 2018, stands at 75.6%. The current year-end projection for EAF is 75%. PCLF refers to planned capability loss factor, UCLF refers to unplanned capability loss factor and OCLF refers to other capability loss factor where the cause of the energy loss is outside of plant management control. FIGURE 1: PERFORMANCE OF ESKOM S FLEET Eskom Holdings Revenue Application FY2019/ /22 September 2018 Page 13 of 131

14 Context of the Generation Licensee operating environment Eskom operates an ageing Generation fleet, notwithstanding the new stations under construction. More than half of the stations and more than half of the coal-fired stations will be over 37 years old by the beginning of the MYPD 4 period. FIGURE 2: AGE OF ESKOM S FLEET AT 1 APRIL 2019 Due to various constraints, most notably inadequate capacity and financial limitations, the mid-life refurbishment and enhancement project that are required to maintain and improve performance as plants age have generally not been implemented. Together with high utilisation, which places higher than expected wear and tear on components and systems, in particular since 2008, this has contributed to a steady decline in generating plant availability over the past 2 decades. In addition, Medupi and Kusile have not yet been completed and their commercial units are still in the first phase of the bath-tub curve, where reliability is expected to be lower as teething problems reduce availability. Due to a combination of performance improvements, additional capacity, Eskom and IPP, as well as stagnant demand, the rapid decline in availability post 2010 has been arrested and availability improved to 78% by 2017/18. The constraints, particularly financial, however, remain and this, together with the phenomenon of the ageing fleet, has contributed to the current availability of approximately 75% EAF. Eskom s longer term aspiration to achieve and sustain 80% availability for its Generation fleet by reversing the overall trend remains a challenge. Eskom Holdings Revenue Application FY2019/ /22 September 2018 Page 14 of 131

15 Context of the Generation Licensee operating environment To this end, Eskom performed a number of sensitivity studies to show the impact of various scenarios related to generating plant availability. These assumed EAF of 80%, 78% and 75% but kept all other assumption constant. An additional scenario of 75% with increased electricity demand and more conservative dates for the commissioning of the new build units was also studied. The base planning assumption is a 50 year plant life for coal stations. However, Eskom considers the economic viability of a power station, in addition to its age, to determine whether a power station should be shut down. The 80% scenario showed that 3 stations (Grootvlei, Komati and Hendrina) would not be required to produce electricity, starting at the beginning or the middle of 2019/20. In addition, Camden would not be required from the middle of 2020/21. With an EAF reduction to 78%, these dates were delayed by up to 7 months. A further reduction to 75%, however, showed that all 4 of these stations would be required to at least the end of 2023/24. Eskom will continue to strive for and implement plans to achieve the aspirational target of 80% EAF by the end of the MYPD 4 period, but it would, be prudent to base plans on a more realistic and conservative availability. This submission is thus based on an EAF assumption of 78% as shown below. TABLE 2: ASSUMED GENERATION EAF EAF Assumption Application 2019/20 Application 2020/21 Application 2021/22 Forecast 2022/23 Forecast 2023/24 EAF (%) In addition, the stations that are not expected to be required according to the Production Plan will not be decommissioned but will instead be placed in reserve storage. This will allow them to be operational within a year should the assumptions in the Production Plant not be borne out in reality. These uncertainties include Eskom s plant performance, variations in demand, IPP capacity (which is dependent on the IRP and the implementation thereof) and new build timelines. This strategy will allow for some savings as it is assumed that there will be no Capex expenditure on these stations and only minimal Opex for essential services, whilst maintaining flexibility. In effect, these stations will provide risk mitigation against changes to the environment in which Eskom operates. Eskom Holdings Revenue Application FY2019/ /22 September 2018 Page 15 of 131

16 Context of the Generation Licensee operating environment 3.3 Stress test on Production Planning The Production Plan used for this application is based on a plant availability of 78% which is what was achieved in 2017/18. However, current availability, as at the end of August 2018 is an EAF of 75.6%, the year-end projection is 75%, and current financial and system constraints make improvement a challenge. Availability of the Generation fleet is one of many assumptions in the Production Plan. Others include the energy forecast and changes in the Eskom and IPP new build programmes. Due to uncertainties in these Production Planning assumptions, a risk impact assessment on the system was conducted. The assumptions for this assessment include higher sales, 75% EAF throughout the MYPD 4 period, and delay in Eskom new build commercial operation dates (as indicated in the tables below) while all other assumptions remain the same as for this submission. TABLE 3: STRESS TEST ENERGY FORECAST AND PLANT PERFORMANCE EAF Assumption Application 2019/20 Application 2020/21 Application 2021/22 Forecast 2022/23 Forecast 2023/24 Energy Forecast (GWh) EAF (%) PCLF (%) UCLF (%) OCLF (%) TABLE 4: STRESS TEST ASSUMED NEW BUILD COMMERCIAL OPERATIONAL DATES Eskom new build Commercial Operational dates Medupi Power Station Kusile Power Station 1 st Unit Operational Operational 2 nd Unit Operational 13-Jul-19 3 rd Unit Operational 31-Aug-20 4 th Unit 16-Jun Mar-21 5 th Unit 28-Dec Nov-21 6 th Unit 27-May Sep-22 Based on these assumptions, the outcome of the assessment is that the system needs all stations to operate in order to meet hourly demand. Therefore, if availability is at 75%, Hendrina, Komati, Grootvlei and Camden will need to operate until their 50 year life of plant Eskom Holdings Revenue Application FY2019/ /22 September 2018 Page 16 of 131

17 Context of the Generation Licensee operating environment plan. This will mean that investment will need to be made for these stations to operate and other additional cost will be incurred. This means that although the base Production Plan for this application shows that some of the older and more expensive units or stations will not be required to produce electricity to meet demand, these units or stations cannot be decommissioned at this time as they will be required should any of the risks taken into account in the stress test materialise. These units or stations will thus instead be shut down and placed in reserve storage. This submission assumes that there will be opportunities for further efficiencies at these stations due to no Capex and minimal Opex spend for essential services so that the units could return to service within a year should they be required. Effectively, these units or stations will be a risk mitigation or insurance policy for possible changes to the environment in which Eskom operates. 3.4 Plant performance benchmarks Eskom benchmarks its generating plant technical performance against similar stations using the VGB PowerTech (VGB), of which Eskom is a member. The latest available data from VGB is for the 2016 calendar year. Note that Eskom data is also in calendar years. For more than the last 10 years, Eskom s fleet has been running at higher utilisation (EUF) than the VGB benchmark. In addition, until recently the availability of Eskom s plant was higher than the benchmark. This is indicative of the constrained environment in which Eskom was operating and is a contributor to the recent reduced availability due to additional stress on an ageing fleet. Eskom Holdings Revenue Application FY2019/ /22 September 2018 Page 17 of 131

18 Context of the Generation Licensee operating environment FIGURE 3: EUF BENCHMARKING EUF measures how hard the units are being run and thus is an indicator of the wear on systems and components. From the figure above, it can be seen that Eskom coal units have been consistently run harder than the coal units of the other VGB members. In particular, since 2012, even Eskom s lowest quartile stations are running at a higher utilisation than the VGB highest quartile. Eskom Holdings Revenue Application FY2019/ /22 September 2018 Page 18 of 131

19 Context of the Generation Licensee operating environment FIGURE 4: UNPLANNED CAPABILITY LOSS FACTOR (UCLF) BENCHMARKING Until 2010, Eskom s UCLF performance was in line with the VGB benchmark but deteriorated significantly from 2011 to The significant improvement in 2016 contributed to the reduced EUF, seen in figure 3, above. This improvement was partly due to the increased planned maintenance (PCLF) from 2012 to address the maintenance backlog from previous years. Eskom Holdings Revenue Application FY2019/ /22 September 2018 Page 19 of 131

20 Context of the Generation Licensee operating environment FIGURE 5: PLANNED CAPABILITY LOSS FACTOR (PCLF) BENCHMARKING Until 2011, planned maintenance was consistently under the benchmark. Since then, PCLF was increased significantly, particularly on those stations most in need, as can be seen by the top Quartile being higher than the VGB top Quartile. Eskom s planned maintenance was lower during this time due to the constrained capacity where planned maintenance could not be ideally undertaken. Eskom Holdings Revenue Application FY2019/ /22 September 2018 Page 20 of 131

21 Context of the Generation Licensee operating environment FIGURE 6: ENERGY AVAILABILITY FACTOR (EAF) BENCHMARKING In recent years (since 2011), the availability of Eskom s coal fleet has dropped below that of the benchmark, notwithstanding the improvement since The general trend, for both Eskom and the VGB benchmark units is that of reducing availability. This is consistent with the expectation due to ageing fleet with few or no new units being commissioned in this period. Eskom Holdings Revenue Application FY2019/ /22 September 2018 Page 21 of 131

22 Production Planning 4 Production Planning 4.1 Production Planning Objective The main objective of Production Planning is to ensure optimal output from available power stations to reliably meet the system demand at least cost, while recognising Generation, primary energy and any other technical constraints. The key principle for Production Planning is for the merit order dispatch to be maintained within known constraints. Constraints may include emissions, coal shortages/surplus, water shortages and any other technical constraints. Merit order dispatch is achieved by deriving the merit order from the primary energy costs (mainly coal and diesel cost) as well as power station burn rates (station efficiency and coal quality) resulting in an energy cost (R/MWh) ranking per station from the cheapest to the most expensive. Coal and diesel costs are the major contributors to the variable cost of electricity production, and on its own, results in an accurate relative merit order and optimum dispatch. The Production Plan outcome provides the expected production level at each station which is the basis of the Primary Energy (i.e. Coal, Water, Limestone, Nuclear, OCGT, Start-up Fuel, Water Treatment, Coal Handling and Environmental Levy) cost projections. 4.2 Production Planning Process The Production Plan is optimised using a simulation tool called the Plexos Simulation Tool. Plexos is a simulation tool that uses data handling, mathematical programming and stochastic optimisation techniques to provide analytical framework for power market analysis. It is able to optimally dispatch generating units based on user defined constraints and respecting technical limits. This modelling tool determines the optimal dispatch of generating resources within given system constraints to meet the power demand from a single period to daily, weekly, monthly or annual timeframes. Eskom Holdings Revenue Application FY2019/ /22 September 2018 Page 22 of 131

23 Production Planning FIGURE 7: OVERALL PRODUCTION PLANNING PROCESS The process for Production Planning is depicted in the figure above. The inputs to the optimisation tool include hourly demand forecast, planned and unplanned maintenance, ramp rates, variable cost (coal and diesel cost), capacity, number of units per station, minimum generation, operating reserve requirements, commercial operations date for Eskom new build, import capacity, IPPs and all other parameters required for modelling the system. Generators are dispatched from the lowest variable cost to the most expensive generator in the system. Nuclear power station (Koeberg) is a must run station and it is always dispatched to its maximum capacity available. The cycle efficiency of a pumped storage scheme (Drakensberg, Palmiet and Ingula), system costs (based on pumping requirements) and the historical generating patterns of existing schemes determine their generation pattern hence they are given minimum load factors. They are modelled such that their top reservoirs must be full at the beginning of every week. Gariep and Vanderkloof generate as per agreement between Department of Water Affairs and Generation Peaking department. The full capacity of these stations is thus not always available in all hours; they can only be dispatched for an agreed number of hours per day. The OCGTs are not fuel constrained but restricted by their availability, position in the merit order and also by the approved assumption on utilisation. Eskom OCGTs are an emergency supply and are therefore constrained to produce at least 1% load factor per annum to cater for any unforeseen event occurring on the system. Eskom Holdings Revenue Application FY2019/ /22 September 2018 Page 23 of 131

24 Production Planning Coal fired power stations are modelled as per their technical parameters which include; number of units, units end of plant life, minimum generation levels, ramp rates, energy cost, availability and other characteristics required by the tool. Dispatch of power stations will be based on their energy cost. Expensive stations are expected to produce less if the system is not constrained. Non-Eskom generators (Imports and IPPs) are modelled as contracted to Eskom. Renewable IPPs are modelled using their hourly profiles for each technology to meet projected monthly/annual energy. Imports and IPPs are forced in the model to dispatch first and the remainder of the energy is met by Eskom generators. 4.3 Production Planning Assumptions The plan was developed based on a 50-year life of plant plan for all coal fired power stations for planning purposes. It must be noted that the useful life of the power station is not determined by age but also by factors such as economic viability and strategic considerations. The main assumptions include: Eskom Generation Capacity Generation currently operates MW (nominal capacity) of commercial fleet (excluding 100 MW of Sere), of which MW is coal-fired. The rest is made up of MW nuclear, MW of gas turbines, 600 MW hydro and MW pumped storage. The Table below shows the Eskom power stations total installed and nominal capacities. The following units have been removed for production planning purposes: Duvha 3 (575 MW), Hendrina 3 (185 MW), Hendrina 1 (160 MW), Grootvlei 4 (190 MW), Grootvlei 5 (180 MW), Grootvlei 6 (160 MW), Komati 1 (91 MW), Komati 2 (91 MW) and Komati 6 (114 MW). The nominal capacity of MW excludes these units for production planning purposes. The rationale for removal of these units is based on six year Production Plan outcome which does not require these stations to run during this period. This Production Plan is based on 78% EAF, Eskom & IPP OCGTs of 1% load factor per annum, IPP capacity, the Life of Plant Plan (LOPP) based on 50 years and Eskom new build commercial dates based on latest forecast. Some generating plant units need refurbishment which is uneconomical as it will not improve the efficiency of these stations. Other units require an immediate investment on repairs and General Overhauls (GO) to continue to operate. However, no resources have been allocated given the capital constraints. Also, long lead times for the spares dictate that some of these units will only be brought back to service closer to the their shutdown dates based on 50 year LOPP. Eskom Holdings Revenue Application FY2019/ /22 September 2018 Page 24 of 131

25 Production Planning Based on 50 year LOPP for all coal fired stations, during the planning horizon (2019/20 to 2023/24) some stations/units are assumed to be shut down as per their end of life dates. For return-to-service stations, their approved business case life of plant plan is assumed. The figure below shows units reaching end of 50 year life. It should be noted that the above-mentioned units have already been excluded in the Production Plan. For example, Grootvlei is operating three units which are reaching their 50 year life as indicated. Years on top show calendar years and at the bottom of the figure are financial years. FIGURE 8: GENERATING UNITS REACHING 50 YEARS LIFE Eskom Holdings Revenue Application FY2019/ /22 September 2018 Page 25 of 131

26 Production Planning TABLE 5: ESKOM EXISTING CAPACITY Power station capacities as at 03 Sept 2018 The difference between installed and nominal capacity reflects auxiliary power consumption and reduced capacity caused by the age of plant. Name of station Location Years commissioned - first to last unit Number and installed capacity of generator sets MW Total installed capacity MW Total nominal capacity MW Generation Group power stations Base-load stations Coal-fired (15) Arnot Middelburg Sep 1971 to Aug x370; 1x390; 2x396; 2x Camden 1, 2 Ermelo Mar 2005 to Jun x200; 1x196; 2x195; 1x190; 1x Duvha 6 Emalahleni Aug 1980 to Feb x Grootvlei 1 Balfour Apr 2008 to Mar x Hendrina 2 Middelburg May 1970 to Dec x200; 2x195; 1x Kendal 3 Emalahleni Oct 1988 to Dec x Komati 1, 2 Middelburg Mar 2009 to Oct x90; 2x100; 3x Kriel Bethal May 1976 to Mar x Lethabo Vereeniging Dec 1985 to Dec x Majuba 3 Volksrust Apr 1996 to Apr x657; 3x Matimba 3 Lephalale Dec 1987 to Oct x Matla Bethal Sep 1979 to Jul x Tutuka Standerton Jun 1985 to Jun x Kusile 3 Ogies Aug 2017 to 1x799; 5x Medupi 3 Lephalale Aug 2015 to 3x794; 3x Nuclear (1) Koeberg Cape Town Jul 1984 to Nov x Eskom Holdings Revenue Application FY2019/ /22 September 2018 Page 26 of 131

27 Production Planning TABLE 5: ESKOM EXISTING CAPACITY (CONTINUE) Peaking stations Gas/liquid fuel turbine stations (4) Acacia Cape Town May 1976 to Jul x Ankerlig Atlantis Mar 2007 to Mar x149.2; 5x Gourikwa Mossel Bay Jul 2007 to Nov x Port Rex East London Sep 1976 to Oct x Pumped storage schemes (3) Drakensberg Bergville Jun 1981 to Apr x Palmiet Grabouw Apr 1988 to May x Ingula Ladysmith June 2016 to Feb x Hydroelectric stations (2) Gariep Norvalspont Sep 1971 to Mar x Vanderkloof Petrusville Jan 1977 to Feb x Total Generation Group power station capacities (25) Eskom Holdings Revenue Application FY2019/ /22 September 2018 Page 27 of 131

28 Production Planning TABLE 5: ESKOM EXISTING CAPACITY (CONTINUE) Renewables power stations Wind energy (1) Sere Vredenburg Mar x Solar energy Concentrating solar power Upington Under construction 100 Other hydroelectric stations (4) Colley Wobbles Mbashe River 3x First Falls Umtata River 2x3 6 6 Ncora Ncora River 2x0.4; 1x Second Falls Umtata River 2x Total Renewables power station capacities (5) Total Eskom power station capacities (30) Available nominal capacity - Eskom owned 95.02% IPP capacity Hydroelectric energy Wind energy Solar energy Gas/liquid fuel energy Total nominal capacity available to the grid - Eskom and IPPs Eskom Holdings Revenue Application FY2019/ /22 September 2018 Page 28 of 131

29 Production Planning Eskom new build capacity assumptions The new build stations included in this planning horizon are Medupi and Kusile based on the latest commercial operational dates forecasted as listed in table below. Currently 3 units are in commercial operational at Medupi and 1 at Kusile. It should be noted that unit capacities may change depending on onsite performance test as contained in the Grid Code Compliance assessment. TABLE 6: ESKOM NEW BUILD CAPACITY Eskom New Build Capacity Medupi Kusile Capacity CO dates Capacity CO dates 1st Unit 720 Commercial 720 Commercial 2nd Unit 717 Commercial Oct-18 3rd Unit 720 Commercial Aug-19 4th Unit Oct Dec-20 5th Unit May Aug-21 6th Unit May Jun-22 Total Energy forecast assumptions As included in the Distribution Licensee submission, the energy forecast is robustly undertaken within Eskom. For production planning purposes, the source of the energy forecast is the Energy Wheel Diagram. The forecast provides an indication of the energy sales from International exports, Distribution and Transmission national sales per month and/or annum. Distribution and Transmission line losses are added to these sales to arrive at the total energy forecast for a month or year. The production planning model requires an hourly demand forecast for each of the years being studied. The hourly demand forecast is developed from the Energy Wheel Diagram s monthly or annual energies and the IRP hourly profile as a reference of hourly demands. The hourly demands of the reference profile are scaled until the given monthly or annual energy figures are satisfied. The peak demands for each of the years of the study period are also the result of this scaling process. The table below tabulates net energy forecast and the projected peak demand. Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 29 of 131

30 Production Planning TABLE 7: NET ENERGY FORECAST AS PER WHEEL DIAGRAMME Net Energy Forecast Actuals 2017/18 Projections 2018/19 Application 2019/20 Application 2020/21 Application 2021/22 Forecast 2022/23 Forecast 2023/24 Net Energy Forecast (GWh) Peak Demand (MW) Non-Eskom supply assumptions Non-Eskom supply includes Independent Power Producers and International imports. The International imports consist of mainly Cahora Bassa. The IPP initiatives are included up to REIPPPP Bid Window 4.5 as shown in table below. This includes DoE peakers (Avon and Dedisa), CSP, PV, Wind, Hydro, landfill and other. Eskom generators supply the balance after imports and IPPs have been utilised. TABLE 8: INTERNATIONAL IMPORTS AND INDEPENDENT POWER PRODUCERS (GWH) INTERNATIONAL IMPORTS AND IPP'S Actuals Projections Application Application Application Forecast Forecast (GWH) 2017/ / / / / / /24 Imports (GWh) IPPs (GWh) Eskom Plant Performance Indicator Plant Performance Indicator assumptions data determine the availability of the generating plant, its technical performance and the constraints within which the available plant will be operated. These data include unplanned capability loss factor (UCLF) estimates, other capability loss factor (OCLF) estimates, planned capability loss factor (PCLF) and any other specified technical constraints. The Generation Plant Performance is assumed to remain at 78% Energy Availability Factor (EAF) for the horizon as indicated in the table below. TABLE 9: GENERATION TECHNICAL PERFORMANCE Generation Technical Performance Actuals 2017/18 Projections 2018/19 Application 2019/20 Application 2020/21 Application 2021/22 Forecast 2022/23 Forecast 2023/24 Energy Utilisation Factor (EUF) Energy Availability Fcator (EAF) Planned Capacity Loss Factor (PCLF) Unplanned Capacity Loss Factor (UCLF Other Capacity Loss Factor (OCLF) Generation Load Factor (GLF) Approval and monitoring of Production Plan The draft Production Plan from the optimisation process is submitted for approval through the governance process, following which it is implemented. The Energy Wheel diagram is then updated to reflect the final Production Plan. Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 30 of 131

31 Production Planning The actual performance versus the assumption in the plan is monitored during the year of operation. Actual versus assumed production variances are investigated and reasons for the variances are reported to the relevant stakeholders. The power stations actual production performance is monitored and reported on a monthly basis. The year-end plan is revised on a quarterly basis for the months ahead. In managing the system, Generation, Transmission and the other relevant role-players meet once a week to look at the week ahead risks to production and devise mitigations accordingly. The Production Plan for the remaining months of the year is revised quarterly due to a revised energy forecast. During the quarterly revisions, changes in forecast volume of energy imports, plant technical indicators, coal issues related to fuel delivery and stockpile days, and nuclear Production Plans are considered. The Production Plan may be revised outside quarterly intervals due to major events on the system. The coal stockpile levels are closely monitored in order to identify supply risks. The aim is to ensure that optimum stockpile levels are maintained. Minimum, target and maximum stockpile days are determined for each coal power station. Power stations are required to ensure that their targeted stockpile levels are maintained and any deviation must be reported, together with mitigation plans to bring the stockpile levels back to the target level. 4.5 Production Plan Outcome The study assumes no restrictions on the fuel availability to the base-load stations, therefore they are only restricted in their output through their available capacity, utilization factors and position in the merit order. A base-load station first in the merit order will generate at full available output in all hours, whilst a base-load station lower down in the merit order will follow the load pattern from hour-to-hour. The table below shows the energy production mix per plant technology from 2019/20 to 2023/24. Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 31 of 131

32 Production Planning TABLE 10: ENERGY PRODUCTION PER PLANT MIX (GWH) Production Plan GWh Actuals 2017/18 Projection 2018/19 Application 2019/20 Application 2020/21 Application 2021/22 Projections 2022/23 Projections 2023/24 Coal Nuclear OCGT Hydro Pumped storage Sere Total Eskom Production IPPs International trader Gross Production Less-pumping Nett Production Conclusion on Production Plan Based on the results observed in the table above, the energy to be supplied by Eskom continues to drop from GWh (2019/20) to GWh in 2023/24, and the Eskom market share decreases from 91% to 88% in the same period supplemented by an increase in the IPPs market share from 5% in 2019/20 to 8% in 2023/24. Imports market share remains at 4% throughout the MYPD 4 period. As the plant availability improves and new capacity is added into the grid, energy growth remains stagnant and plant utilisation will continue to drop. The Energy Utilisation Factor (EUF) drops from 79% in 2019/20 to 77% in 2023/24 for coal fired power stations, whereas EUF for Eskom system drops from 70% in 2019/20 to 68% in 2023/24. The Production Plan outcomes highlight that Hendrina, Komati, Grootvlei and Camden will not be required to contribute towards the supply of electricity as from September 2019, December 2019, December 2019 and January 2020, respectively. This only holds as long as there are no changes to the projected assumptions. It should be noted that maintaining the projected level of performance will require necessary maintenance to be carried out. Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 32 of 131

33 Primary Energy 5 Primary Energy This chapter provides a summary of the overall Primary Energy expenditure, an overview of the Primary Energy business environment, the details of the forecasted Primary Energy costs for the Revenue Application period and the assumptions used to generate the forecast, the risks associated with the forecasts and the relevant cost explanations. The chapter also includes an overview of the operational management processes and the operational performance. 5.1 Overall summary of primary energy The next section will cover the primary energy (PE) and levies & taxes (L&T) components of the build blocks to the allowable revenue formula: AR=(RAB WACC)+E+PE+D+R&D+IDM±SQI+L&T±RCA Eskom s primary energy cost escalations are summarised as follows: Coal burn costs reflect a CAGR over the period of 7.8% per annum. Generation own primary energy costs have a compounded average growth rate (CAGR) of 6.4% per annum from 2018/19 to 2021/22. Non-Eskom primary energy costs reflect a CAGR of 14.8% per annum between 2018/19 to 2021/22. Of this, local IPPs have a CAGR of 15.6%. Total primary energy reflects a CAGR of 9.0% per annum between 2018/19 to 2021/22. Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 33 of 131

34 Primary Energy TABLE 11: SUMMARY OF PRIMARY ENERGY COSTS Total Primary Energy Costs R'million Actuals 2017/18 Projection 2018/19 Application 2019/20 Application 2020/21 Application 2021/22 Projections 2022/23 Projections 2023/24 Coal burn Water costs Fuel procurement costs Coal handling Water treatment Start-up gas and oil Limestone Black start facility(gas fired) Total Coal Nuclear fuel burn OCGT fuel burn Environmental levy Total Eskom Primary Energy Independent Power Producers(IPPs) International Purchases (Imports) Demand Response Total Non-Eskom Primary Energy Total Primary Energy Primary energy will be unpacked into more detailed for the three sources; starting with IPPs which is followed by international purchases and concludes with Eskom s own generation costs. FIGURE 9: ESKOM PRODUCTION VERSUS NON-ESKOM PRODUCTION (GWH) Note: Years are financial years. Eskom Generation production stays flat at around GWh throughout the forecasting period. Non-Eskom production increases from GWh to GWh (50% increase). The increase in Non-Eskom production comes mainly from the IPPs, whose production doubles from GWh in 2017/18 to GWh by 2023/24. This is partially offset by a small reduction in international purchases. Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 34 of 131

35 Primary Energy Overall electricity production has increased by 4.2% from 2017/18 to 2023/24. One can clearly see how the IPPs are displacing the Eskom production, as Eskom s production growth is flat, while IPP growth is 108% positive. 5.2 Independent power producers (IPPs) In accordance with the sections 3.1.4(e) of the GSFA, Eskom is required to consult with and seek approval from the Department of Energy (DOE) together with the Department of Public Enterprises (DPE) and National Treasury with regards to the proposed energy from IPPs, their costs and payment obligations to be included in the MYPD 4 application for the period 2019/20 to 2021/22. In addition, as required by the NERSA MYPD methodology, projections for the two subsequent years (2022/23 to 2023/24) are included. Eskom has undertaken this process. Feedback received by Eskom supports the submission as proposed. TABLE 12: ASSUMED COSTS FOR IPP ENERGY IPPs (local) Cost (R million) Actuals Projection Application Application Application Forecast Forecast '2017/18 '2018/ / / / / /24 Section 34 programmes (-RE) DoE Peaking Renewable IPP Renewable IPPs Round Renewable IPPs Round Renewable IPPs Round Renewable IPPs Round Renewable IPPs Round Renewable IPPs Round Total IPP Network costs (UoS) Total IPP The above costs are based on Bid window prices as per the graph and table below. Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 35 of 131

36 Primary Energy FIGURE 10: RENEWABLE IPP ENERGY COSTS PER TECHNOLOGY TYPE TABLE 13: RENEWABLE IPP ENERGY COSTS PER TECHNOLOGY TYPE Average price (R/MWh) BW1 BW2 BW3 BW4 Apr 2018 ZAR Wind PV CSP Section 34 Procurement a) Renewable Energy IPP Programme All prices are indexed to the assumed inflation, except for certain bid window (BW) 2 and BW 3 options that are only partially indexed in accordance with contractual arrangements. Bid Windows 1 to 3 included as per the energy expectations in the power purchase agreement (PPA) and prices as per PPA. BW 3.5 included as per the energy expectations in the signed power purchase agreements (PPA) and prices as per signed PPA. BW 4 (including Additional) included as per the energy expectations in the signed power purchase agreements (PPA) and prices as per signed PPA. All the prices assumed to be fully indexed to CPI. Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 36 of 131

37 Primary Energy b) Peaker programme The two IPP peaker power stations are operating commercially. These are assumed to be operating at 1% load factor and expected costs split between the fixed capital component and variable energy component Eskom programmes a) Short term power purchase programme (STPPP), including municipal generation and Medium term power purchase programme (MTPPP) It is assumed that no additional PPAs will be signed under these programmes. b) Wholesale Electricity Pricing System (WEPS) contracts The WEPS contracts will no longer be continued. FIGURE 11: SUMMARY OF REIPP COSTS OVER LIFE OF CONTRACTS The figure above reflects the nominal cost of IPP contracts over the life of the contracts for each of the bid windows from Bid window 1 to Bid Window 4+. Most of the contracts have annual increases included in the contracts. 5.3 International purchases Electricity supply from neighbouring countries is mainly driven by imports from Cahorra Bassa (HCB) with expected supply of approximately 1200~1400MW. This source has been subject to fluctuations in recent years due to network constraints or drought conditions Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 37 of 131

38 Primary Energy affecting the level of the dam and thus reducing supply by around 500MW in certain instances. The forecasts remain fairly consistent at around 7.5 TWh. It needs to be noted that a contract with Mozal results in a significant portion of the HCB purchase being made available to Mozal. TABLE 14: INTERNATIONAL PURCHASES International Purchases (Gwh) Actuals Projection Application Application Application Forecast Forecast 2017/ / / / / / /24 International Purchases (R'm) International Purchases (GWh) Demand response Introduction to Demand Response The Demand Response (DR) programme fulfils an important role towards power system security (even during times of surplus capacity) by providing the System Operator (SO) with much needed flexibility and reliability. The SO uses reserves to control the interconnected power system frequency. These reserves are procured from both generators and the Demand Response (DR) programme through the ancillary services process as defined in the Grid Code. Factors that could affect the frequency stability of the electricity supply include: System constraints caused by severe weather and/or power line faults. Generator malfunctions (unexpected trips loss of multiple Generation units). Substantial load and renewables forecast errors due to unforeseen circumstances. The following reserves are obtained from demand response: a) Instantaneous Reserve Instantaneous Reserve from demand response is consumer load contracted to respond to a fall in frequency. The purpose of Instantaneous Reserve is to arrest the frequency at acceptable limits following a contingency, for example a generator trip. It must respond fully within 10 seconds and must be sustained for at least 10 minutes. b) Supplemental Reserves This comprises of Supplemental Demand Response as well as Self-generation Demand Response. These are customer loads that can respond within a notice period of 30 minutes to six hours to restore other reserves. This reserve remains utilised until it can be replaced by other capacity or for a maximum duration agreed with the supplier. It is Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 38 of 131

39 Primary Energy contracted annually with the supplier and bid available day-ahead. It is required to ensure an acceptable day-ahead risk, and to allow time for cold reserve plant to be called up. c) Energy Imbalance Reserves These are customer loads than can be dispatched in advance by the System Operator (as opposed to near real time). The purpose of the energy reduction products is to cater for generation capacity losses in the medium to long term (a day to weeks). The dispatching can be anywhere between a day, a week, or two weeks in advance, for 2 to 24 hour reductions. DR is catered for in the normal daily operations of the SO and is economically dispatched only when required, thereby reducing the need to dispatch expensive peaking stations. The DR Aggregator System (DRAS) is utilised for bidding, scheduling, dispatching and metering of the DR load. The system enables the System Operator to call on large power users to reduce demand within the notice periods (<10 seconds to 120 min) as well as to perform performance and settlement reporting. The Demand Response resource is one of the tools within ancillary services that the System Operator uses to ensure power system reliability Demand response products and rates An increase in the utilisation of DR has been experienced in 2018/19 YTD associated with reduced generation availability and system constraints, therefore it was necessary to make adequate projections in the MYPD 4 application Assumptions The amount of reserves required is based on the Ancillary Services Technical Requirements as published by the SO annually on the Eskom website. The same capacity was assumed for instantaneous and supplemental DR over the MYPD 4 period with an adjustment for inflation of 6% per year on the energy and capacity rates respectively. The Supplemental DR usage was calculated based on customers being dispatched for 150 events (approximately 3 days a week) per annum at 2 hours per event, whereas the Instantaneous DR value was based on customers being scheduled every day of the week for a year. The dispatch of customers in the Demand Response programme is subject to the status and performance of the Eskom power system as determined by the SO. Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 39 of 131

40 Primary Energy The administration costs could vary based on the appointment of a service provider, subject to Eskom procurement process Other Ancillary services The generation supply side ancillary services cost drivers is not exclusively primary energy components. Other operational costs such as employee benefits, maintenance and other opex also form part of the total ancillary services cost. This cost is embedded over the full spectrum of generation s total cost application. The table below reflects other ancillary services (i.e. excluding demand response). Ancillary services (including Demand response) Actuals 2017/18 Projection 2018/19 Application 2019/20 Application 2020/21 Application 2021/22 Forecast 2022/23 Forecast 2023/24 Reserves Total Supply side Demand Response Reactive power Black start & islanding Constrained generation Total Reserves The system operator procures reserves from the generators connected to the grid as well as from the loads that forms part of the demand response program explained in section Reactive Power and Voltage Control In addition to supplying real power, service provider facilities provide reactive power and voltage control to the transmission system. Generators routinely supply or absorb reactive power as necessary to maintain voltage and stability on the transmission grid. Generators can provide this service when generating power (normal operation) and also supply reactive power when not generating, that is during Synchronous Condenser Operation, (SCO) mode Black Start and Islanding Black Start capability is the provision of generating equipment that, following a system black out, is able to start without an outside electrical supply (self-start), and to energize a defined portion of the transmission system so that it can act as a start-up supply for other base load generators to be synchronized as part of a process of power system restoration. At present there are three black start sites on the transmission system. The SO has determined that with the increase of generation over the coming years, it may be desirable to procure further black start facilities in strategic areas. Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 40 of 131

41 Primary Energy Unit Islanding is the capability of a generating unit to disconnect from the Transmission system by the opening of the High Voltage (HV) breaker and to automatically control all the necessary critical parameters sufficiently to maintain the turbine-generator at the desired speed and excitation, hence supplying its auxiliary load without external supply for a specified amount of time. The SO pays a capacity payment and a variable payment to each station which is contracted to provide Islanding. The costs for Islanding are highly dependent on the performance of the generators. Costs could also increase with the arrival of new generation able to provide unit islanding Energy Imbalance (Constrained generation) The South African Grid Code defines the Constrained Generation Ancillary Service (CGAS) as follows: Constrained generation is the service supplied by a power station to the National Transmission Company (NTC) by constraining its power output below (alternatively above) the unconstrained schedule level. The service is required to ensure the interconnected power system (IPS) remains between appropriate operational limits (e.g. thermal, voltage or stability limits).in providing the service, the power station experiences a financial loss, for which it shall be compensated by the NTC, based on the additional cost incurred by the Service Provider. 5.5 Coal burn costs Introduction While Eskom is a regulated entity, the coal market is unregulated, so Eskom competes with local and global buyers on price and supply. Although South Africa has abundant coal resources, coal in close proximity to the power stations is in dwindling supply. Where coal is procured from sources which do not have a conveyor to the power station stock yard, the coal must be transported by road and/or rail, instead of being moved over short distances on conveyor. This adds complexity to the value chain, as well as cost. Eskom purchases between 113 and 130 Mt of coal per annum. Coal is procured on three types of contracts: a) Cost Plus b) Long Term Fixed Price c) Short/Medium Term Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 41 of 131

42 Primary Energy FIGURE 12: COAL BURN COST (RAND MILLION) Coal burn costs reflect a compound annual growth rate (CAGR) over the period 2018/19 to 2021/22 of 7.8% per annum. The relatively large increases in the coal cost in 2018/19 and 2019/20 may be attributed to the following: The increase in the volume of coal on short/medium term contracts. The inclusion of unknown coal from 2018/19. The exclusion of coal from Optimum mine (stopped coal supply during 2017/18) for Hendrina Power Station. The increase in transport costs associated with short/medium term and unknown coal. The decrease in volumes from the cost plus mines as the impact of delayed investment and aging of mines manifests. The inclusion of take or pay payments from 2018/19 for coal from Grootegeluk mine for Matimba and Medupi Power Stations. While Eskom is endeavouring to recover the coal production at the cost plus mines and conclude long term contracts for coal, the present environment is challenging. The next few sections deal with the following topics, which are important to set the scene with regards to coal costs for Eskom: Coal market overview, challenges facing the coal industry, Eskom s strategies on coal, key assumptions and drivers of coal costs, benchmarking and governance. Thereafter the coal costs per the Application are motivated in detail. Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 42 of 131

43 Primary Energy Coal market overview This section summarises the trends and market forces impacting the coal business and the key elements of the Coal Strategy to exploit and mitigate said trends and market forces. It will be demonstrated that the existing market conditions will lead to an increase in coal prices above CPI although Eskom is going out of its way to ensure that coal prices increase in line with or less that CPI Overview of the coal business environment Eskom s coal procurement mandate is to safely and sustainably identify, develop, source, procure and deliver the necessary amounts of coal of the required quality for Eskom s power stations, at the right time and at optimal cost. Key responsibilities and activities of the coal fuel procurement process are to secure future coal requirements and associated logistics by working with relevant stakeholders and government departments at a national level to ensure that adequate coal resources are available and accessible for power generation. This covers a range of functional areas extending from the source of fuel to delivery and stockpiling at the power stations: FIGURE 13: COAL VALUE CHAIN Within each of these functional areas lies an array of factors, over which Eskom has varying degrees of influence. Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 43 of 131

44 Primary Energy FIGURE 14: CHALLENGES FACING ESKOM COAL PROCUREMENT Coal fuel procurement is, thus, exposed to various factors that have had, and will continue to have implications for costs and security of coal supply to Eskom. Some of these factors mentioned above are discussed below Impact of economic uncertainty on the long term growth trend Eskom s coal supply strategy is impacted by the electricity demand forecast. This, in turn, is based on the forecast for economic growth in South Africa. After the high growth and consequent high electricity demand of , the subsequent global economic meltdown resulted in a sharp decline in electricity demand. Recent forecasts are that South Africa will experience very little economic growth. This is reflected in the flat coal purchases volumes forecast for the MYPD 4 period. Eskom can base its electricity, and thus coal, demand forecast on this scenario, but continued economic uncertainty will impact on the accuracy of electricity demand forecasts, reduce the accuracy of forecasts, and increase the risk of under- or over-supply of primary energy. The implications are as follows: Continued uncertainty and economic instability increases the risk of over- or undercontracting of coal supply, which necessitates the requirement for Eskom to increase the volume flexibility in the portfolio of coal contracts. However, this flexibility will result in a cost. Continued uncertainty will also increase the risk associated with cost projections as many of the coal supply agreements are linked to external indices or cost drivers. Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 44 of 131

45 Primary Energy Changing the coal industry structure Perhaps, because of the both the economic and political environment, where South Africa previously saw the emergence of more junior and BEE miners in the coal sector, the current cyclical downturn has resulted in a dearth of new mines. The previously hopeful new players provided Eskom with a larger supplier base. The figure below illustrates that approximately 80% of the South African coal market is dominated by six suppliers. The implications are as follows: Funding in the mining industry is a major challenge especially for smaller miners. There is a lack of large scale investment into the coal mining industry. This will create a supply shortage in the future. The slowdown in global and local economic growth, and the resultant decrease in export demand and pricing, increases the risk of marginal mines facing liquidity challenges. This increases Eskom s supply risk. The increase in export demand for a RB3 product (lower export specification product) has removed the availability of the Eskom quality middling s coal product that was previously available to Eskom. An economic upturn, together with the lack of new investment in mines, could result in increased cost of coal to Eskom and/or a security of coal supply risk to Eskom. Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 45 of 131

46 Primary Energy FIGURE 15: MAIN COAL SUPPLIERS Mines have an alternative market Existing mines are taking advantage of the high export coal prices. Many investment decisions which were made at the height of the last commodity boom are now coming on line. However, these mines are targeting the more lucrative export market and not the domestic market. Facilitating these exports, and reducing the coal available to Eskom, is traders with export allocations at the Richards Bay Coal Terminal (RBCT). These traders are willing and able to buy up coal from small miners, paying cash on delivery. The following figure indicates the price that suppliers obtained from Eskom and from the export market. During the early 2000s, the prices started diverging at a greater rate. It is at this time when Eskom started seeing a larger percentage of its coal being procured from the ST/MT market and an increase in the cost of this coal. Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 46 of 131

47 Primary Energy FIGURE 16: PRICE OF COAL COMPARISON ESKOM VS EXPORT Source: Chamber of Mines (2016) The figure below reflects that the cost plus mines were maintaining production during the early 2000s, but the increase in the demand for coal at the power stations necessitated an increase in purchases which had to be from the ST/MT market. FIGURE 17: PURCHASES AND BURN VOLUMES (MT) Although China tried to reduce thermal coal s share of the generation mix in order to raise environmental standards in the country, the lack of alternative power and heating supplies is expected to result in this policy being relaxed in the colder months. If the country does not Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 47 of 131

48 Primary Energy increase its coal production, it will have to import coal. While India is expected to become self-sufficient in producing its own coal, the country is still reporting a shortage. There are varying opinions for the long term outlook for coal prices. The CEO of Glencore, Ivan Glasenberg, thinks that the fundamentals for coal are solid, partly because of underinvestment in new mines 1. Goldman Sachs holds a positive view of coal prices because of continuous disruptions in the sector. However, Anglo American was uncertain whether the long term prospects for thermal coal were that good. Exxaro is one producer that has invested in new mines, but this coal is destined for the export market. The company is projecting that its coal exports will increase by 85% between now and The demand for lower quality coal is reflected in the fact that the bulk of coal exported out of Richards Bay is now the kcal coal instead of kcal, and that coal of kcal is also being exported. These are qualities used by Eskom s power stations. The implications are as follows: The uncertainty makes planning for coal purchases very challenging. There could be significant variations between forecasts and actual events and costs. Because of the uncertainty, there is a lag in new projects. Coal allocated to Eskom is being diverted to the export market. Suppliers are demanding higher base prices when negotiating new contracts. There are other markets for coal that used to be exclusively for Eskom s use. Historically, export prices cross-subsidised Eskom s middling product. Now the middling product is being exported to India. Current lower shipping freight cost environment is also contributing to the attractiveness of South African export coal Deteriorating resource/reserve base The mines in the Mpumalanga basin are entering a phase where the cost of coal is driven upwards by factors such as deteriorating coal quality, increased occurrence of geological disturbances, thinner coal seams, depleting reserves in the currently accessible reserve blocks, high investments to access the remaining new small reserve blocks and longer onmine transport distances. These factors increase coal handling, maintenance and labour costs and reduce productivity, while increasing the need for costly beneficiation of the coal. 1 IHS SACR (591) 2 IHS SACR (593) Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 48 of 131

49 Primary Energy The majority of Eskom s current long-term coal supply sources have been in operation in excess of 20 years and, as some of the oldest operating mines in South Africa, are directly impacted by these increased costs. Managing the quality and quantity of Eskom s coal supply is becoming more challenging. The implications are as follows: The costs of establishing and operating new mines will be significantly higher than in the past, due also to the increased geological complexity with thinner and deeper coal seams. This will translate into higher coal prices for Eskom. Substantial investment will be required to open new, more marginal coal reserve blocks (with limited life as the large blocks have been mined) to maintain coal supplies. The calorific value of coal is decreasing. There will be an increased need for beneficiation of certain resources to meet power station coal quality parameters; further increasing costs Increased transport distances between mines and power stations The procurement of coal from sources, which are great distances from the power stations means that this coal must be transported by road or rail. The implications are as follows: Coal resources and reserves away from an existing Power Station will incur some kind of logistics cost to deliver that coal to the Power Station which will result in an increase in the coal cost Increasing environmental pressure Eskom s coal-focused generation mix requires significant volumes of water; a scarce and important resource in South Africa. The opening of new coal mines to supply both Eskom and the export market is expected to place pressure on the already strained environment and on water catchments. Existing and new environmental legislation is expected to be more stringent than past standards, and the requirements are likely to result in a decrease in productivity levels and/or an increase in costs. The implications are as follows: New emissions standards for power stations will necessitate higher coal quality specifications, which could, potentially, increase the cost of coal. Similarly, any more stringent environmental legislation will increase the mine environmental, rehabilitation and closure costs, leading to higher overall prices charged to Eskom Supply constraints in key mining inputs Most mine input costs have been increasing at rates higher than general inflation over Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 49 of 131

50 Primary Energy FIGURE 18: MINE COST INFLATION OUTSTRIPS PPI (SOURCE: SA CHAMBER OF MINES) As the world s economic recovery and political stability in many regions remain uncertain, commodity prices will also fluctuate. This uncertainty is compounded by labour unrest in the mining industry in South Africa that could result in mine closures and higher prices of commodities. There is speculation that falling sea borne thermal coal prices, together with poorer quality Indian domestic coal, could provide support to coal imports (Wood Mackenzie, May 2017, Commodity Market report). While the price of coal from Eskom s existing contracts is not impacted significantly by export prices, increased exports of RB3 type coal does affect the coal that is available for Eskom in the South African market. The implications are as follows: Continued real increases in domestic mining input and labour costs will impact all of Eskom s coal contracts as industry wide input cost changes are ultimately passed through to Eskom, since they are deemed to be beyond the control of the coal suppliers. Lower volumes of RB3 (Eskom quality) coal available to Eskom in the South African market Key elements of Eskom coal strategy to exploit and mitigate the trends and market forces Eskom Coal Strategy Eskom revised its coal strategy in 2016 to align with changes in its financial and operating environment: Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 50 of 131

51 Primary Energy TABLE 15: COAL STRATEGY FY16 COMPARED TO FY08 & FY12 Changes in PED operating Environment since last Coal Strategies (2008 & 2012) Funding Requirement to ensure price variance risk of coal costs is not carried by Eskom Delays in cost plus mine recapitalization due to funding constraints and funding reallocation Demand & energy mix Coal supply landscape Emissions regulations Contract performance Water scarcity and pricing Uncertain and declining demand, with current electricity growth being below original forecasts Introduction of self dispatching IPPs reduces Eskom energy required Declining coal reserves, coal mines closing down and limited new mines The current environment is not incentivizing investment in new mines. low export prices, increasing mining costs, environmental concerns around coal, uncertainty around mining legislation, limited funding available Excessive mining cost inflation negatively affects Eskom s coal purchase costs. Air Quality legislation more stringent gaseous emissions limits, eg CO, SOXs, NOXs, create uncertainty on coal power plants future COP21 commitment will result in premature coal generating assets retirement Existing coal contracts have experienced several challenges (e.g., inability to exit or pause contracts as and when required, quality variations) with a significant portion of the risk covered by Eskom Existing long term fixed pricecoal contracts have experienced several difficulties as contracts are not flexible enough to be terminated or to be paused when off-take is delayed or no longer required by Eskom. Water scarcity brought on by existing drought and over abstraction of the catchments pose an operational and cost risk to Eskom. The National Water Pricing Strategy Draft will introduce further water charges to Eskom. Within this context, five guiding principles have been used to revise the Eskom coal strategy: Focus on delivering end-to-end cost of (Opex and Capex) coal efficiency for coal fired stations. Ensure Eskom coal costs are secured at best prices that benefit the electircity consumer. Create flexibility in coal contracting to manage key uncertainties and demand fluctuations. Enable Generation to meet coal burn demand within prescribed coal quality. Support Eskom s socio-economic policy objectives. Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 51 of 131

52 Primary Energy The following objectives have been developed to shape the 2016 Business Strategy: Financial Sustainability: Attain a cost effective delivered cost of coal and year on year increases. Generation Least Cost of Production: Ensure optimal dispatch of coal-fired power stations on least cost merit order. Security of Supply: Achieve an acceptable balance of security of coal supply and risk exposure, by securing all coal resources and reserves close to the power stations. Logistics Optimisation: Optimise road and rail transportation operations to drive cost efficiency while delivering the road-to-rail migration programme. Market Transformation: Leverage Eskom s buying power to enable coal market entrance by black emerging miners and to drive Eskom s transformation objectives. Eskom s focus is to attain effective cost of coal and maintain unit coal cost escalations to achieve the committed savings. In the table below, the initiative and timeframe over which it will be implemented are captured on a single line, below which are the KPIs the initiative addresses, the key actions identified and critical success factors for the initiative are shown. The operating environment for Eskom has changed over the past year which necessitates a review of the strategy. A strategic approach to addressing current challenges with regards to coal shortages, increasing costs as well as transformation objectives is being developed. FIGURE 19: CHALLENGES IN ESKOM S ENVIRONMENT Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 52 of 131

53 Primary Energy Key assumptions underlying the coal sourcing plans and coal forecasts The key assumptions underlying the primary energy sourcing plans and cost forecasts are detailed below. Changes in one or a combination of these assumptions will result in changes to the forecast costs Demand for coal a) Coal sources and volumes Dedicated (Cost Plus) mines, produce at expected levels, which are largely below contractual volumes. Multi-product (Fixed Price) mines produce at expected levels. Kriel and Matla CSAs will be extended. Capex will be available immediately for investment in cost plus mines. Any shortfalls will be sourced from smaller operating mines, most of which are already supplying Eskom. b) Coal costs and price escalations Cost Plus mines costs have been escalated at 8%. Long term fixed price mine costs have been escalated in accordance with the terms of the contracts using Eskom s parameters. A modelled index has been used for future escalations for contracts that are still to be negotiated. Prices from medium term contracts have been based on existing contractual delivered cost. Export parity price used for coal not yet contracted. c) Logistics Majuba heavy haul line will be operational from the second half of 2018/19. The FCA road transport contracts expire in September It is assumed that any new contracts will also be subject to the existing rates model. d) Parameters used in forecasts The forecast cost of coal ultimately depends on a forecast demand for electricity and on expected coal volumes and costs from cost plus, long term fixed price and short/medium term sources, as well as the various costs associated with the value chain, e.g. logistics costs. Eskom has made certain assumptions with regard to these variables. Eskom has based these assumptions on the information available at the time this application was complied. Changes to these assumptions will result in changes to the costs and volumes. Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 53 of 131

54 Primary Energy Benchmarking This section compares the volumes and prices of coal supplied to the domestic market (primarily Eskom) with that exported. The graph below reflects the trend in the average Eskom price per tonne compared with the price out of Richards Bay (converted at the average ZAR/$ for the year). The purpose of the graph is to indicate that the average export prices far exceed the average prices Eskom pays and that this gap is expected to remain. This provides suppliers with leverage during price negotiations. It also provides an incentive for mines that export and supply to Eskom to prioritise exports at the expense of Eskom. FIGURE 20: AVERAGE FOT STEAM COAL PRICES(R/T) The difference between the Eskom average price and that of the Eskom ST/MT price is indicative of the difference between prices from the long term cost plus and long term fixed price contracts, and prices from the ST/MT contracts. This also makes a case for further investment in the cost plus mines Governance Governance issues in coal procurement have been in the media recently. Eskom s new Board has embarked on a process of addressing the findings and recommendations from various reports. Eskom s delegation of authority specifies who may authorise transactions/expenditure and the financial limits applicable to each delegee. In the Primary Energy Department (PED), procurement of goods and services follows the Eskom commercial process. Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 54 of 131

55 Primary Energy Summary of total coal forecast volumes and cost The following section details the coal volumes required to meet Eskom s forecast electricity generation and the related costs Coal Volumes The volume of coal to be purchased is a function of the opening stock, the coal forecast to be burnt and the closing stock required as per Eskom s coal stock policy. The coal to be burnt is determined from the generation production forecast, in which power stations are scheduled according to cost, fuel availability and maintenance plans. These volumes are determined for each power station. Eskom s projected coal burn for 2017/18and 2018/19 remains flat, increases in line with electricity generation in 2019/20, then decreases over the period 2020/ /23 as a result of a lower average burn rate and declining coal-fired electricity generation. FIGURE 21: COAL BURN PROJECTIONS (MT) Forecast Coal Supply to meet Coal Burn Eskom prefers to contract for coal on long term contracts. The presumption is that this provides Eskom with assurance of supply at a lower cost because the supplier is able to depreciate certain fixed costs over a longer revenue stream. Sometimes, for various reasons, it is not possible to contract for all of Eskom s coal requirements on long term contracts. However, contracts of a shorter duration and a percentage of uncontracted coal allow for flexibility should there be a change in overall demand or should there be a need to change the mix of supply. It is prudent to have a portfolio of coal supply agreements that allows flexibility to meet changing electricity demand patterns. Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 55 of 131

56 Primary Energy In 2016/17, approximately 63% of coal was procured on long term contracts. These are historical contracts with original durations of 40 years, which were designed to match the life of the associated power station(s). In 2018/19, this proportion decreases to 58%. Although there is an increase in coal procured on the Medupi contract, there is no coal being procured on the Optimum contract for Hendrina Power Station. And, although there is a small increase in coal volumes from the cost plus contracts, there is a significant proportion of coal required for which there is no known source. This, combined with an increase in the total coal required in 2018/19, results in more coal having to be forecast for on medium term, including unknown, contracts, as is evidenced in the figure below. FIGURE 22: COAL PROCURED CATEGORISED BY CONTRACT TYPE (%) The total volume of coal procured to meet the burn requirement in 2016/17 and 2017/18 was 120 and 115 Mt p.a. respectively. As electricity production from coal fired stations declines, the volume of coal that Eskom needs to procure is also forecast to decline Coal Burn Cost This section explains what the coal burn cost is and how it is derived. The coal burn figure is derived from the coal purchases cost, amortised future fuel, mine closure provisions, transport and planned stock levels. Therefore, the reasons for variances in the coal burn will be similar to the reasons for the variances in the coal purchase costs. These are discussed in more detail further on in this section. The changes in the coal burn figures over the 2017/ /22 period are made up of efficiency, mix, volume and price variances. The change has been analysed per annum in the table below. The table indicates the absolute and percentage annual increase in burn costs. This increase is then allocated between price, volume and other (efficiency and mix) variances. The price variance is the largest variance. However, it should be viewed Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 56 of 131

57 Primary Energy in context. There is a R13.9bn increase in total burn cost from 2018/19 compared to 2021/22 which equates to a 7.8% CAGR over the MYPD 4 period. Between 2016/17 and 2017/18, the burn cost increased by 7% as per the table below. The price variance of R1.71bn is only 3.6% on the 2017/18 burn of R47.164bn. Note: the R47.164bn coal burn cost for 2017/18 excludes the coal obligation provision of R0.172 billion. TABLE 16: ANALYSIS OF ANNUAL COAL BURN VARIANCES (RBN) Analysis of Annual Coal Burn Actuals Actuals Projection Application Application Application Variances 2016/ / / / / /22 Total burn (R'million) YoY % change 7% 17% 16% 3% 5% YoY change in burn cost (R'million) The YoY variance in burn cost (R'million) comprises the following: Price % % 92.49% % % Volume % 6.73% 6.69% % % Other % % 0.82% % % Other variance comprises the efficiency and mix variances. Efficiency refers to the rate at which power stations consume coal to generate a unit of electricity. There is a small improvement in the CV and a small positive efficiency variance. The mix variance refers to the manner in which power stations are utilised. There are a number of reasons why one power station may generate more than another. Some of these are planned maintenance, the cost of generation at a power station, fuel availability, minimum generation requirements and grid stability and efficiency. From 2018/19 to 2019/20, there is a negative volume variance in line with the increase in coal-fired generation. In 2020/21 and 2021/22, the positive volume variance is because of lower year on year coal-fired generation. The biggest portion of the increase is related to the price Annual coal purchases costs The average annual growth in coal purchases costs over 2019/ /22 is 4%. Over the same period, between 47% and 51% of the coal purchases costs come from long term contracts. Between 55% and 60% of coal volumes comes from long term contracts. It is Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 57 of 131

58 Primary Energy Eskom s policy to secure long term contracts with mines close to power stations. Over the 2020/21-24 period, the compound average growth rate of annual coal expenditure is ~7%. Other costs referred to below, include coal sampling costs and take or pay payments. FIGURE 23: ANNUAL COAL EXPENDITURE PER SUPPLY SOURCE Logistics This section explains how coal is transported from a source, which is usually a mine, to a power station. It also explains what factors drive the cost of transporting coal. Forecast logistics modes and costs for medium and long term sources of coal. Eskom transports coal by one of three modes or a combination of these modes: Conveyor this is the mode used for coal from collieries located close to the power station receiving the coal. It is the cheapest mode. Rail Transnet Freight Rail provides the rolling stock. Coal is railed from the supplier to the power station, if the supplier and the power station have the infrastructure. Alternatively, coal may be transported from a supplier to a rail siding by truck, and then railed to a power station. If the power station does not have rail infrastructure either, coal may be transported by truck to a siding, then railed to another siding closer to the power station, and again loaded onto a truck for the final leg to the power station. The more complex the transport arrangement, the more expensive the transport cost is likely to be. Road Coal is trucked to its destination when conveyor and rail are not possible. Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 58 of 131

59 Primary Energy Rail is preferred over longer distances. However, only Majuba and Tutuka Power Stations have the infrastructure for coal to be railed to the station. Majuba uses a sophisticated tippler system whilst the other stations use a containerized solution. Grootvlei and Camden Power Stations are located close to rail sidings, so coal is railed to the siding and then trucked to the station. Rail has historically generally been cheaper than road for a system that delivers coal from the mine directly to a power station. Rail has also proven to be safer than road. So, where it is possible, Eskom strives to maximize volumes on rail. The organization is also investigating the feasibility of establishing infrastructure to accommodate alternative modes of transport, e.g. rail infrastructure where a station cannot accommodate the volumes of truck deliveries. Currently, Transnet is the only provider of freight rail. The organization determines the tariff, which varies with the type of service required, e.g. open top wagons are cheaper than closed containers. The setting of the tariffs is not a transparent process, making Eskom a price taker. Tariffs are escalated annually in accordance with a basket of published indices agreed to by Eskom and Transnet. This increase has been higher than general inflation over the past five years. A new contract for 2018/19 and beyond is in progress. This forecast assumes that the new contract will not include any minimum take or pay volume clauses. This, however, is a risk as Transnet, generally, does not conclude contracts without a minimum offtake agreement. The volume of coal on rail increases from 13.2 Mt in 2016/17 to 14.5 Mt in 2018/19. While some new coal purchases will be on rail, unknown sources are assumed to be on road. Most of the smaller sources will not have links to the rail system. These sources at the time of this script have not yet been established or been through the required commercial processes. Transport on road is managed using two types of contracts: Delivered the cost of coal includes the cost of transport. The coal supplier is accountable for the transport. The transporter contracts with the mine. Free Carrier (FCA) Eskom pays the coal supplier for the coal only. Eskom then allocates the route to one of the transporters contracted to Eskom. The existing FCA contracts expire at the end of September The assumption is that the same terms and conditions will apply to any further contracts. As part of its effort to contain costs and minimize disruptions around the renegotiations, Eskom will engage in proper consultation and communication with the FCA community. The various components of the road transport rates are as follows: 50% of the rate is assumed to be fixed. Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 59 of 131

60 Primary Energy 40% of the rate is assumed to be diesel, which is escalated at PPI. For this plan PPI is 6% p.a. 10% is assumed to be labour, which is escalated at 6% p.a. As total coal volumes procured increase in 2018/19, and because the volumes from long term contracts only start to ramp up in 2020/21, there is an increase in the transport by road initially. Thereafter, total volumes procured remain flat. Because there is a marginal increase in long term coal, as explained under the Cost Plus and Long Term Fixed price purchases above, there is a corresponding decrease in the ST/MT volumes on road. The rate of movement from road to rail has been slower than previously envisioned because of funding and infrastructure limitations. It is anticipated that this will remain the case for this period. In any event, some road transportation will remain necessary as some sources cannot be economically moved on other modes. Additionally, road provides flexibility for short term coal movements. One of the factors in deciding which mode of transport should be chosen is the cost. The figure below indicates the average R/t cost of transport for the 2016/ /24 period and the volumes per transport mode. Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 60 of 131

61 Primary Energy FIGURE 24: FORECAST LOGISTICS MODES AND COSTS FOR LONG AND MEDIUM TERM SOURCES The average annual cost of getting a tonne of coal from the source to the power station increases by 6% p.a. Coal transported by rail will often include a road component because there may not be a rail link from the source to the power station. Additionally, there may not be a rail line to the power station, so the last leg from the siding to the power station stock yard will be on road. Therefore, there is not always a clear correlation between increases or decreases in volumes on rail and the cost. In some instances, the multi-mode trip may be more expensive than a direct road trip, but rail is preferred because the reduced time on the road translates into fewer possibilities for road accidents. Eskom would prefer to have all of its coal on conveyor or rail, but conveyor is only feasible where the mine is close to the power station. A rail link is only an option where the volumes make it economically feasible. Like Eskom, Transnet must allocate its capital where it will yield the best returns. The figure below indicates that, although total volumes purchased decline over the period, there is a small increase in volumes transported by conveyor and Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 61 of 131

62 Primary Energy rail, and in general, there is a corresponding decline in the proportion of money spent on road transport. FIGURE 25: FORECAST LOGISTICS PERCENTAGES PER MODE FOR LONG AND MEDIUM TERM SOURCES Conveyor is the cheapest mode of transport. However, it is only feasible where the mine is located close to the power station. Because the cost plus and long term fixed price mines, which are linked by conveyor to the power stations, are experiencing the challenges already elaborated on under the sections on coal volumes and costs, it is necessary to procure coal from other sources further away. This coal must be transported by road and/or rail, depending on the access to rail sidings and the infrastructure at the power stations. While Eskom would like to move this coal on rail rather than road, these physical constraints make this impossible. Both Eskom and Transnet Freight Rail are constantly discussing adding rail capacity. This does requires large capital investment, but progress is being made. Rail will also not necessarily prove cheaper because Transnet s pricing is not regulated. The increase in the cost of coal on road is managed by the pricing and escalation terms in the transport contracts. Eskom has managed to reduce these rates in the past, but there are real Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 62 of 131

63 Primary Energy cost increases which transporters face, e.g. fuel, maintenance and labour. Over the 2019/ /22 period, Eskom does expect to increase the percentage of coal transported over conveyor and reduce that on road Stock management over the MYPD 4 Period FIGURE 26: FORECAST SYSTEM COAL STOCK DAYS Eskom is considering the following measures to bring and maintain stock days at expected levels: Investigate alternative storage facilities at stations that need it. Automate the system to track energy (GJs) and dates to trigger notifications of contract expiration dates. Modify coal supply agreements to maximise coal volumes, where feasible Conclusion on coal costs Coal burn costs reflect a compound annual growth rate (CAGR) over the period 2018/19 to 2021/22 of 8% per annum. Coal burn R/MWh increases above inflation from 2017/18 to 2019/20 and then it stays flat over the rest of the forecasting period. While Eskom is endeavouring to recover the coal production at the cost plus mines and conclude long term contracts for coal, the present environment is challenging. Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 63 of 131

64 Primary Energy 5.6 Water Introduction This section explains the challenges and assumptions that underlie this forecast. It also details how and where Eskom obtains the water needed to produce electricity and the components of the costs of this water. Eskom receives raw water from the Department of Water Affairs (DWS) and Rand Water. This water is then treated for its intended use for human consumption or for the plant. The power stations cannot function without water for cooling the plant and producing steam for the turbines. The cost of water is impacted, not only by how much water is consumed, but to a larger extent by the tariffs. Over the 2019/ /22 period, the total volume of water consumed decreases, but the cost of water is expected to increase because of the increase in existing tariffs and the introduction of additional tariffs. These tariffs are legislated, as are their increases. The cost of water also depends on the source (certain schemes are more expensive). New infrastructure is likely to be more expensive, so the water from that source will have a higher tariff. Some schemes have specific tariffs; e.g. water from the Vaal attracts the Vaal River Tariff. The introduction of environmentally friendly measures, such as the Demand Management Levy or the Waste Discharge Charge, adds to the cost of water. Eskom is a strategic user of water, consuming approximately 2% of the total annual use of the country, which is equivalent to the consumption of the City of Cape Town. As the demand for electrification grows, there will be an increased demand for scarce water supplies. The implications are as follows: Increased demand will require significant investment in new water schemes, the cost of which must ultimately be recovered from both current and future users, including Eskom. There is a need for significant investment in infrastructure to supply water to the Waterberg area, which will increase water costs and tariffs in that region. There is a possibility that the DWS might re-price the water tariffs to reflect water scarcity in the country, which will be reflected in the revised National Water Pricing Strategy. The possibility exists that additional costs may be incurred if the effects of the current drought in certain parts of the country are prolonged or if the drought extends to other parts of South Africa. These costs have not been included in this application. The figure below illustrates forecast water costs for the period under review. Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 64 of 131

65 Primary Energy TABLE 17: TOTAL RAW WATER COSTS FOR ALL STATIONS Water Costs Actuals Projection Application Application Application Forecast Forecast (R'm) 2017/ / / / / / /24 Coal stations Koeberg Peaking Renewables Total water costs The compound annual growth rate (CAGR) for water costs over the period 2018/19 to 2021/22 is 7.5%. Water costs are dominated by the coal-fired stations. These are shown in the figure below. FIGURE 27: TOTAL RAW WATER COSTS FOR COAL-FIRED STATIONS The compound annual growth rate (CAGR) for coal-fired station water costs over the period 2018/19 to 2021/22 is 8%. In 2022/23 one sees a step change (increase in over R1bn) in water costs where an estimate was added to the base for the impact of the new water strategy that is expected to be implemented by then Water Assumptions The new power stations (Medupi and Kusile) will use flue gas desulphurisation (FGD) at litres per units sent out (l/uso). Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 65 of 131

66 Primary Energy New infrastructure projects are planned to meet the water requirements of Eskom and other large water users. All new infrastructures will be developed and financed by the DWS using the project financing model. The costs will be recovered through the water tariffs. Current infrastructure is old and the backlog of maintenance will also result in an increase to the water tariff. Tariffs for Medupi comprise of MCWAP1 until 2023/24. Thereafter, MCWAP2 will be commissioned and a new system tariff will be calculated. Tariffs are calculated on a take or pay basis Key drivers affecting the water cost forecast The Department of Water Affairs has under-spent on maintenance and refurbishment on bulk water infrastructure over the years. This has resulted in a backlog of maintenance and refurbishment that is required to be planned and implemented in the forthcoming years to ensure plant reliability and availability. The development and implementation of new water infrastructure, such as MCWAP2 required for water to the Waterberg, will increase the cost of water. Water costs are regulated in line with the prevailing National Water Pricing Strategy. A new draft Water Pricing Strategy has been issued. Water tariffs could change once the draft Pricing Strategy is finalised. Water cost increases are primarily driven by increasing water demands of the new build, which require new water infrastructure and therefore higher capital tariffs to repay off the financing debt. Eskom pays for the water it consumes through a series of water tariffs. These are legislated, so Eskom has no control over what they are. Historically, water costs have been very low as a percentage of the Eskom operating costs. The main reason for this is that the water infrastructure assets (Eskom s and those of DWS) were constructed several years ago and are almost completely depreciated. As new infrastructure and water charges have been introduced, the demand for water and the cost have increased. Furthermore, the cost increases as the distances over which water needs to be transferred increase and as new tariffs are introduced into legislation. Recent new water infrastructure includes augmentation to the Vaal, Komati and Mokolo water schemes. The DWS National Water Pricing Strategy allows DWS to implement these projects off budget and to recover associated costs via a tariff. The Komati and Mokolo costs are recovered on a take or pay pricing basis. Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 66 of 131

67 Primary Energy The water financial plan comprises the following cost elements: Water cost, including cost of new water infrastructure. Electricity. Operations and maintenance. Amortization and capital spend Future Water Demand and Infrastructure The National Integrated Resource Plan (NIRP) forecasts new generating capacity. The new infrastructure is developed by DWS via their off budget funding mechanism, as described in the DWS National Pricing Strategy. The strategy allows for DWS to recover monies to redeem the loan repayments and operational cost. NIRP illustrates the timing and technology of choice, thereby prescribing the related water use. Changes in how and where electricity will be generated also impact the capital expenditure required. The DWS is responsible for capital expenditure for the Usutu, Usutu- Vaal and Vaal. Eskom owns the Komati Water Scheme and is responsible for all capital expenditure costs. The capital expenditure for this scheme over the 2019/ /22 period is indicated in the section on Future Fuel below Water Risks Water Quality The deteriorating water quality poses a major risk to Eskom. The power stations will have to construct appropriate treatment plants and use chemical technologies to manage deteriorating water quality. The problem is further compounded by the management of the hazardous waste generated by the intake of poor quality water. Kriel and Duvha Power Stations are most affected as they have two sources of water. Duvha currently receives mostly clean Komati Water. Kriel Power Station is also supplied from two sources, (approximately 60% Vaal and 40% Usutu). The Vaal supply is not only more expensive but is also of a poorer quality than Usutu Catchment water Waste Discharge Charge System The DWS s pricing strategy focuses mainly on water use in terms of volumes abstracted or stored and not on the discharge or disposal of waste or water containing waste or the associated effects. The waste discharge charge system, which will form a vital component of the pricing strategy, will address the latter by introducing financial and economic Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 67 of 131

68 Primary Energy instruments, designed to internalise costs associated with waste, to encourage the reduction in waste and to minimise the detrimental effects on water resources. The DWS has not determined a mechanism and tariff for this charge, so Eskom has allowed for the waste discharge charge in this application Drought Eskom has assumed the normal inter-basin water transfer required by DWS in its hydrological model. The model is fairly robust in forecasting one year. However, beyond a year, water transfer in drought conditions cannot be fully determined. No allowance/provisions have been made for either additional water transfers or water infrastructure that may be needed to mitigate the effects of drought. During drought conditions the water resource quality deteriorates which further exacerbates the water management problem at the power stations New Water Infrastructure The Crocodile West Augmentation Project (MCWAP) provides water to Medupi Power Station. The second phase of MCWAP has been delayed to 2024/25. In the interim, Medupi Power Station will utilise the water for flue gas desulphurisation from its current water allocation. The second phase will increase the water supply to Medupi for the flue gas desulphurisation process and additional generation. It will also make available water for two future coal-fired power stations in the Waterberg area. The DWS will also supply water to Sasol, Lephalale Municipality and mines that will be developed in the area. The cost for the second phase is already being incurred because the TCTA raised the funding for it earlier as per the original project schedule. This cost currently makes up around 11% of the cost of water. A cost risk exists regarding new water infrastructure. Currently, Eskom pays a tariff based on the actual cost of the infrastructure. The Trans-Caledon Tunnel Authority (TCTA) has provided budget estimates. Any increases outside the budgets provided by TCTA are not allowed for in this submission. The cost of water to Eskom is largely outside of the control of Eskom. As part of being environmentally responsible, Eskom puts in place measures to monitor and manage water consumption. However, power stations do use water for people and plant. If electricity generation changes (output volume or mix of power stations), water needs to be supplemented from other schemes, the DWS introduces new tariffs or new infrastructure is required, the total cost of water is impacted. Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 68 of 131

69 Primary Energy Conclusion on water costs The cost of water is impacted, not only by how much water is consumed, but to a larger extent by the tariffs. Over the 2019/ /22 period, the total volumes of water consumed decreases, but the cost of water is expected to increase because of the increase in existing tariffs and the introduction of additional tariffs. These tariffs are legislated, as are their increases. The compound annual growth rate (CAGR) for water costs over the period 2018/19 to 2021/22 is 8%. In 2022/23 one sees a step change (increase in over R1bn) in water costs where an estimate was added to the base for the impact of the new water strategy that is expected to be implemented by then. 5.7 Limestone Introduction to Limestone This section explains what Eskom uses limestone for, what it is likely to cost and why. Limestone is required for the flue gas desulphurisation (FGD) technology at Medupi and Kusile Power Stations. The sources identified for this commodity are located in the Northern Cape. The limestone is railed from the Northern Cape to Gauteng. Then, because of a lack of rail infrastructure, it is trucked to the powers stations. These process increases the delivered cost of limestone significantly. The use of limestone also increases the water requirements at each of the above-mentioned power stations. The primary energy water volumes and cost include water for FGD at Medupi and Kusile, based on a requirement of 0.45 litres per unit of energy sent out. The decision to implement flue gas desulphurisation plant at Medupi and Kusile Power Stations is in line with environmental requirements to reduce emissions globally. There is a cost to implementing these measures. The long distance over which the limestone needs to be transported adds to this cost. Eskom is investigating options to reduce this cost, such as alternative sources of limestone which may be closer to the power stations. At this stage, the source with the capacity to supply the volumes required is the mine in the Northern Cape. Therefore, the costs have been based on this information. For this submission, the following assumptions have been made with regards to limestone: Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 69 of 131

70 Primary Energy Quantities of limestone required The limestone volume requirements per station for each year are based on the GWh energy sent out per station, as per the 78% EAF Production Plan. Although Medupi power station has already started generating, it will only be retro fitted with FGD at a later stage. It is estimated that Medupi will start using limestone for FGD in 2023/24 and that it will only be unit 4 which will be retrofitted by then. Kusile Power Station will have all six units fitted with FGD from when they are commissioned. TABLE 18: ENERGY SENT OUT FOR STATIONS WITH FGD Energy Sent Out for stations with FGD (GWh) Actuals 2017/18 Projections 2018/19 Application 2019/20 Application 2020/21 Application 2021/22 Forecast 2022/23 Forecast 2023/24 Medupi ,352 Kusile 4,165 4,920 10,272 14,372 20,323 23,464 24,841 Total 4,165 4,920 10,272 14,372 20,323 23,464 34,194 The estimated consumption of limestone is shown in the table below. TABLE 19: VOLUME OF LIMESTONE REQUIRED Volume of limestone required (Tons '000) Actuals 2017/18 Projections 2018/19 Application 2019/20 Application 2020/21 Application 2021/22 Forecast 2022/23 Forecast 2023/24 Medupi Kusile Total The cost of limestone: Key drivers affecting the cost of limestone The coal-fired power stations where Flue Gas Desulphurisation is planned are geographically remote from viable limestone sources; hence logistics and the final delivered cost will contribute to the selection of the most cost effective option. Estimated pricing escalations are assumed to be driven by PPI. Greenfield sources will require capital investment in rail infrastructure and as such will require a return Cost assumptions: The cost of limestone for Kusile is R110/ton FCA in 2017/18. This is based on the existing contract. The cost of limestone for Medupi is R225/ton in 2017/18. This cost is based on a recent request for information (RFI) issued by Eskom. There is no contract for limestone for Medupi as yet. The cost of transport for Kusile is R597/ton in 2017/18. This is the cost of the rail and road elements. Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 70 of 131

71 Primary Energy The cost of transport for Medupi is R945/ton 2017/18. This cost was obtained from the RFI Cost escalations: The limestone price and the transport cost have been escalated by PPI as per Eskom s parameters. TABLE 20: FORECAST PURCHASES COST OF LIMESTONE (R M NOMINAL) Forecast Purchases Cost of Limestone (R m Nominal) Actuals 2017/18 Projections 2018/19 Application 2019/20 Application 2020/21 Application 2021/22 Forecast 2022/23 Forecast 2023/24 Limestone Transport Total The purchases costs above translate into consumption costs as follows: TABLE 21: FORECAST CONSUMPTION COST OF LIMESTONE (R M NOMINAL) Forecast consumption cost of limestone (R m Nominal) Actuals 2017/18 Projections 2018/19 Application 2019/20 Application 2020/21 Application 2021/22 Forecast 2022/23 Forecast 2023/24 Costs (R 'm) Volumes (kt) Conclusion on limestone costs The decision to implement flue gas desulphurisation at Medupi and Kusile Power Stations is in line with environmental requirements to reduce emissions globally. There is a cost to implementing these measures. The long distance over which the limestone needs to be transported adds to this cost. Eskom is investigating options to reduce this cost, such as alternative sources of limestone which may be closer to the power stations. At this stage, the source with the capacity to supply the volumes required is the mine in the Northern Cape. 5.8 Nuclear fuel burn Introduction Nuclear Fuel procurement comprises the acquisition of uranium, conversion, enrichment and the fabrication of the fuel assemblies for Nuclear Fuel. Longterm contracts are established to ensure security of supply as well as availability of nuclear fuel at the appropriate time and within the prescribed quality standards. When purchased, the nuclear fuel value is considered as future fuel Capex which is accounted for as a non-current asset in the balance sheet. When the fuel is loaded into the nuclear reactor (refuelling), it is transferred from the nuclear future fuel account to the Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 71 of 131

72 Primary Energy nuclear fuel stock account, a current asset in the balance sheet. As the nuclear fuel is burnt over a period of 54 months, it is expensed through the income statement by crediting the nuclear fuel stock account and debiting the nuclear fuel burn account (primary energy cost). The fuel manufacturing process is approximately eighteen months with contractual progress payments throughout the fuel manufacturing cycle. As indicated above, this results in the above Capex future fuel expenditure of the fuel not being aligned to fuel assembly deliveries. Fuel assembly deliveries will fluctuate as they follow the delivery requirements for Koeberg. Fuel is required to be delivered approximately six months prior to each refuelling outage. All the Nuclear Fuel expenditure is incurred in foreign currency and cash flow hedge accounting is applied to the purchases. The cash flow hedge accounting requires a basis adjustment to the price of the delivered fuel Assumptions Nuclear Fuel costs mainly comprise four categories, being Uranium, Uranium Conversion, Uranium Enrichment and Fuel Assembly manufacturing. The cost contribution per category depends on market prices and the ruling exchange rates. Based on June 2017 Term-market prices the respective apportionment of the total cost is: 48% Uranium 8% Uranium Conversion 22% Uranium Enrichment 22% Fuel Assembly manufacturing Nuclear Fuel purchases are based on the following forward-looking nuclear fuel price assumptions: TABLE 22: NUCLEAR FUEL PRICING (R MILLION) Nuclear fuel planning assumptions Actuals 2017/18 Projection 2018/19 Application 2019/20 Application 2020/21 Application 2021/22 Forecast 2022/23 Average fuel assembly price The above nuclear fuel assembly prices are the average prices per fuel assembly delivered to Koeberg during that financial year. The cost of the delivered nuclear fuel is expensed as part of Koeberg's primary energy costs over the period that the assemblies remain in the reactor, which is normally 54 months. Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 72 of 131

73 Primary Energy Thus, there is not a direct correlation between when the nuclear fuel procurement costs are incurred and when they are expensed as primary energy costs. TABLE 23: NUCLEAR FUTURE FUEL BALANCE SHEET RECONCILIATION (R MILLION) Nuclear future fuel R'million Actuals 2017/18 Projection 2018/19 Application Application 2019/ /21 Application 2021/22 Forecast 2022/23 Forecast 2023/24 Opening balance Add: Nuclear future fuel capex Less: Transfer to nuclear fuel stock Closing balance When nuclear fuel that was purchased as future fuel is loaded into the nuclear reactor (refuelling), it is transferred from the nuclear future fuel account to the nuclear fuel stock account. Both are balance sheet accounts. As the nuclear fuel is burnt over the period of 54 months, it is expensed through the income statement by crediting the nuclear fuel stock account and debiting the nuclear fuel burn account (primary energy cost). TABLE 24: NUCLEAR FUEL STOCK RECONCILIATION Nuclear fuel stock R'million Actuals 2017/18 Projection 2018/19 Application Application 2019/ /21 Application 2021/22 Forecast 2022/23 Forecast 2023/24 Opening balance Add: Transfers in from nuclear future fuel Less: Nuclear fuel burnt Nuclear fuel written off Nuclear spent fuel management: Increase in decommissioning asset Depreciation of decomm asset Closing balance Nuclear fuel primary energy cost Koeberg Power Station consists of two reactors, each requiring a loading of the reactor core of 157 fuel assemblies. To achieve an even energy output, one third of the fuel assemblies are replaced at each refuelling cycle. These fuel assemblies remain in the reactor core and are burnt over a period between 45 and 54 months depending on the Production Plan and the refuelling strategies. The costs of the fresh fuel assemblies are amortised over the anticipated burn period and are reflected in Primary Energy costs. Factors influencing Koeberg s primary energy (nuclear fuel) costs include: Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 73 of 131

74 Primary Energy Nuclear Fuel Price Nuclear fuel procurement comprises mainly of four distinct phases, being procurement of uranium, conversion of the uranium into the gas UF6, enrichment of the U-235 isotopes to the required level, and the fabrication and delivery of the fuel assemblies. All these activities are undertaken internationally and are subject to market price and foreign exchange fluctuations. Eskom had contracts that covered 100% of Koeberg s demand until the end of 2017 with procurement currently in progress to acquire uranium, conversion and enrichment services for the period up until For the fuel assembly fabrication phase, Eskom recently concluded contracts for the supply of fabricated assemblies up until 2022 with an option to extend to The pricing formula for the fuel assembly fabrication is 100% a base escalated price. For the rest, namely the uranium, uranium conversion and uranium enrichment, a mix of price conditions has been agreed to. This is a mix between base escalated and market related prices, a mix between term and spot market prices and/or a reset of the base price to market during the contract period. These prices are stated in the international functional currency of USD and are translated into ZAR at the rates provided by Eskom Treasury Koeberg Production Plan Koeberg has the lowest cost of primary energy per MWh produced in the Generation fleet and is therefore run as a base-load station. Its Production Plan is influenced by its need for refuelling every eighteen months as well as its maintenance regime which requires it to replace and modify its plant components. The fuel is burnt over a period of three reload cycles of approximately eighteen months each, typically being a maximum of 54 months. However, based on the energy requirements, some fuel assemblies may be changed and replaced with fresh fuel after only two cycles. These partially burnt assemblies are then expensed fully (written off) and removed from the reactor Spent Fuel Management Costs The costs associated with the management, including the disposal of the Spent Fuel Assemblies generated by Koeberg, is quantified from extensive studies which are incorporated into the Reference Technical Plan and reflected in a Spent Fuel Management Provision. The costs in raising the liability to safely and responsibly manage the spent fuel is amortised over the burn period of the fuel in the reactor core. The Spent Fuel Reference Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 74 of 131

75 Primary Energy Technical Plan, which is based on extensive consulting studies, is revised every three years or earlier when deemed necessary. TABLE 25: NUCLEAR PRIMARY ENERGY COSTS (R MILLION) Nuclear fuel burn R'million Actuals 2017/18 Projection 2018/19 Application Application 2019/ /21 Application 2021/22 Forecast 2022/23 Forecast 2023/24 Nuclear fuel burn (Units 1+2) Depreciation of decomm asset Nuclear Other Total nuclear fuel burn costs The costs above represent the following: Unit 1 and Unit 2 nuclear fuel burn costs These costs represent the fuel burnt. The fuel assemblies loaded are expected to be burnt over a period of three cycles which equates to approximately 54 months. Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 75 of 131

76 Primary Energy Spent Fuel Backend Costs All the costs required to manage the Spent Fuel must be allocated to the period of production from which the benefits of burning the fuel are derived. Hence, the costs relating to the long-term storage and disposal of the fuel are expensed over the period for which the fuel is burnt. This represents the variable costs of burning the fuel as should the fuel not be irradiated the costs would be avoided. The above charge to the income statement is credited to Spent Fuel Provision thereby ensuring that the obligation for managing the Spent Fuel is correctly reflected on the balance sheet. The Spent Fuel assemblies are stored in the Spent Fuel Pools at Koeberg Power Station. However, given that Koeberg has been operating for over 34 years, the pools are reaching their capacity. The station has commenced acquiring Spent Fuel Casks which will allow the spent fuel to be removed from the pools and stored in dual-purpose, storage and transport casks. With each fresh reload of fuel into the reactor core the displaced spent fuel from the core will require older and cooler spent fuel to be removed from the pool. Hence the cash flow expenditure relating to the Spent Fuel Provision is now being incurred since the 2017 financial year and will continue through to the end of life of the station. Unlike the Plant Decommissioning expenditure which is mainly incurred at the end of life of the station, the spent fuel decommissioning expenditure is a current and ongoing cost Nuclear Other These costs represent the write-off of partially burnt fuel. Partially burnt fuel arises when due to energy requirements not all fuel assemblies can be fully burnt over the 54 months. The Reactor Fuel Engineering section calculates the energy requirements from the fuel so as to ensure sufficient energy for the full duration of each cycle Nuclear fuel primary energy cost The compound annual growth rate (CAGR) for nuclear primary energy costs over the period 2018/19 to 2021/22 is 4%. Eskom commissions periodic (typically every 3 years) studies to evaluate the adequacy of the Nuclear Spent Fuel provision. No provision for any once-off adjustments has been made in this application as any adjustments could be either negative or positive. 5.9 OCGT fuel burn Introduction to OCGT fuel The purpose of this submission is to provide information on how OCGTs are utilised to indicate their prudent usage considering the dynamics of the system. The focus is on the operational aspects of their usage. From a planning perspective, the OCGTs are considered Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 76 of 131

77 Primary Energy together with the other available supply and demand options as peaking stations for use during peak hours which provides space for essential maintenance at base-load stations as well as for emergencies as a last resort before load reductions during extreme events. The load factor for OCGTs during the forecasting period was assumed to be 1%, which translates to 211 GWh per annum. The fuel used is mainly diesel (Ankerlig and Gourikwa). The price of the diesel is subject to the international USD price of Brent crude oil and the ZAR/USD exchange rate. The official Eskom economic parameters for the forecasting period were used in the calculations of the fuel costs. The diesel used by Eskom is subject to a wholesale discount and a fuel rebate as determined by the Minister of Finance. TABLE 26: OCGT ASSUMPTIONS OCGT Assumptions Actuals Projection Application Application Application Forecast Forecast 2017/ / / / / / /24 Total OCGT Fuel burn cost (R'm) Total OCGT Production (GWh) OCGT Specifications Ankerlig and Gourikwa are heavy duty industrial gas turbines (Siemens) and can be used over a wide variety of loading regimes from peaking to base load. Acacia and Port Rex are based on jet engine technology. Ankerlig and Gourikwa were constructed to assist with the demand supply balance predicted from the early 2000s because of their shorter (2-3 years) construction times. Originally, the business case for the OCGTs was based on a load factor of 6% OCGT Decision Making Criteria When making a decision to run the OCGTs, all available resources are considered, for the current day as well as the next few days. Possible restrictions on Eskom generation include the dam levels at the pump storage stations (Ingula, Palmiet and Drakensberg) and the availability of water at the other hydro stations (Gariep and Vanderkloof) which is managed by the Dept. of Water Affairs. OCGTs are used only once available base, mid merit and hydro-generation have been utilised or planned to be utilised over peak, and once load reduction through the Virtual Power Station (VPS) and other demand response options have been dispatched. These have limited energy reduction opportunity and they are normally planned to be utilised over peak. Emergency reserves are then considered. These include Emergency Level 1, Interruptible Load Shedding (ILS) and the OCGT generation. Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 77 of 131

78 Primary Energy When the system is constrained, OCGTs are used to meet the remaining load when all other available generation is on line. In winter this is typically for a few hours over evening peak due to the peaky load profile. However in summer this may be for many hours per day due to the significantly flatter load profile. During the day, fewer units will be required than over evening peak. OCGTs typically take about minutes to come on line and cannot all be brought on simultaneously. The number of units expected to be required for evening peak are brought on load prior to the sharp evening pick up to ensure they are on load on time and prevent running at low frequencies. If the load does not materialise as expected there may appear to be extra machines on load but it is necessary that the machines are ready to support the load and the expected peak in the peak. If large amounts of generation are lost it is essential to have this quick response available to the System Operator. Hence the utilising of OCGTs is done to meet total system demand; they may also be used to manage power transfer to the Cape. This may become an issue during Koeberg single or zero unit operation, as well as during certain transmission outages Coal handling Introduction to coal handling Coal handling refers to all the activities that are necessary to get the coal to the boiler once it has been delivered to the power station. The main cost components of coal handling include labour, and machinery and vehicles such as bobcats, bulldozers etc., which are known as white and yellow plant. The fuel for the yellow and white plant as well as contingencies is also significant cost drivers. Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 78 of 131

79 Primary Energy FIGURE 28: COAL HANDLING COSTS RMILLION At most stations, coal handling costs are assumed to increase by inflation. Overall, the total coal handling costs remain flat in over the forecasting period and thus are decreasing in real terms. This is mainly because coal handling costs at the reserve storage stations (Grootvlei, Hendrina and Komati) have been set at zero and costs for Kendal and Majuba has been reduced as they were abnormally high in 2017/ Conclusion on coal handling Coal handling costs have a CAGR of -1.1% for the MYPD 4 period (2018/ /22), which is a reduction in costs from the previous year Water treatment The quality of water from the various sources impacts on the water treatment costs. The main drivers of water treatment costs are the cost of the chemicals used to treat the water including purchases of materials that are not stock items which include ion exchange resins, membranes, furniture and other small equipment and instruments. Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 79 of 131

80 Primary Energy FIGURE 29: WATER TREATMENT COSTS Water treatment costs have a CAGR of 0.3% for the MYPD 4 period (2018/ /22), which is significantly below inflation. The main reason is that a minimal amount will be spent on water treatment costs at the reserve storage stations (Grootvlei, Hendrina and Komati) Start-up gas & oil Start-up gas & oil reduces from 2018/19 to 2019/20 and then stays flat over the forecasting period. This is due mainly to fuel oil costs at the reserve storage stations (Grootvlei, Hendrina and Komati) being set to zero. This is partially offset by an increase in fuel oil costs at Medupi and Kusile as new units are commissioned. There are three different purposes for the fuel oil plant installed at Eskom s power stations, namely boiler start-up, mill start-up and coal firing support. Each power station s fuel oil plant will need an offloading and storage plant, fuel oil preparation and pumping station as well as the oil burners and associated pipework installed at the boilers. Eskom uses a variety of different fuel oil plant designs. This condition exists due to the era when the Power Stations were designed, different OEMs and the recommended technology at the time. Consequently, different Power Stations have different designs, although many are fairly similar to one another. Similarly, the fuel oil type used at each station may be different and Eskom stations use three different grades of fuel oil. Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 80 of 131

81 Primary Energy The oil burners are located either within the coal burners or adjacent to the coal burners, depending on boiler design. The location of the oil burners allows for easy ignition of the coal flame as well as being able to provide for heating of the boiler during a boiler start-up. To ensure safe operation, the oil burners are designed to deliver an energy input which is between 8% and 20% of the associated coal burner energy input. To achieve this, a typical 600MW power station would have an oil burner that could provide an energy input of between 7 MW and 12 MW. To provide this energy, the fuel oil flow rate would be between 600 kg/h and 1028 kg/h. At Eskom s power stations, similar philosophies are applicable and due to the size differences, oil burner sizes range from 350 kg/h to 1900 kg/h. For a 600 MW boiler, the following approximate fuel oil consumption could be expected. a) Start-up: Cold (when the unit has been shut down for an extended period, which varies from plant to plant) 100 tons. If testing is required, this value could increase substantially. Hot (only shut down for a short time this also varies from plant to plant) 50 tons. b) Mill changes (start-up or shutdown of a mill): 1.5 tons per activity. c) Combustion support to ensure that there is sufficient combustion in the boiler during operation: This can vary substantially and depends on the length of time that the support is required. Different power station designs may influence the frequency of need for this support. Reasons for combustion support include: - Poor combustion which could include coal outside of design requirements. - Soot blowing activities. - Ash removal activities. - Low load operation. - Boiler disturbances. All power stations receive their fuel oil via road tankers from the suppliers. The offloading plant consists of pumps that draw the fuel oil from the road tankers via a flexible hose, associated pipework, strainers and flow meter, and deliver the fuel oil to storage tanks. For the lighter grade 1 and 2 fuel oils, no heating system is provided, whereas for the grade 3 Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 81 of 131

82 Primary Energy fuel oils, a heating system is located within the storage tank at the tank outlet. The heating system for grade 3 fuels is needed to allow for the fuels viscosity to be controlled at a value that allows for proper handling of the fuel. FIGURE 30: START-UP GAS AND OIL COSTS Start-up gas & oil costs decrease from 2018/19 to 2019/20 and then stay flat relatively over the forecasting period. The reduction in costs is mainly because fuel oil costs at the reserve storage stations (Grootvlei, Hendrina and Komati) were set at zero. This is partially offset by an increase in fuel oil costs at Medupi and Kusile as new units are commissioned. Fuel oil volumes decrease by litres (27%) from 2017/18 to 2021/22 which is the last year of MYPD 4. The reduction in volumes is mainly at Hendrina, Grootvlei and Komati, the stations with zero production over the MYPD 4 period. The impact of this is significant as these stations are older and are heavier users of fuel oil. The fuel oil and gas prices are difficult to forecast accurately as they are very volatile. The key reasons for this is that the fuel oil price is dependent on mainly the Rand/Dollar exchange rate and the international dollar price of crude oil fluctuates on a daily basis and is difficult to predict. Fuel oil costs have a CAGR of -5% for the MYPD 4 period (2018/ /22). Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 82 of 131

83 Primary Energy 5.13 Environmental levy Introduction The Customs and Excise Act, 1964 promulgated in July 2009 that the generation of electricity from Non Renewable generators is liable to pay an Environmental Levy. The Government Gazette No dated 01 July 2012 set the rate at 3.5 c/kwh on the generated volume. All Eskom generators with the exclusion of Hydro and Pumped Storage Power Stations were registered and licenced as manufacturing warehouses as required by legislation Process According to the Act, the owner of the Manufacturing Warehouse is accountable for the compliance to the Act. In Eskom s case it is the Power Station Manager of each Power Station. With twenty different sites liable for the payment of the Environmental Levy it is necessary to manage, consolidate and plan on a centralised basis to ensure full compliance from all participants. Each Power Station has procedures in place which govern this process. The Act requires the appointment of a Responsible Person. Power Station Managers are required to appoint a Production Manager and a Financial Manager in writing as Responsible for full compliance to all aspects of the process Planning Any future budget or plan of the Generation Environmental Levy is done centrally to ensure a consistent methodology based on prudent principles. The first principle of this application or any other budget process is that it must be fully aligned with the official approved Eskom sales volumes. The Eskom Production Plan is the only source that could be used as a prudent source of the volume applicable which is liable for the payment of the Environmental Levy. The Production Plan takes cognisance of all supply requirements such as imports and IPP supply and then on a least cost methodology allocate supply to Eskom generators to meet the Eskom sales predictions. Power Station volumes as expressed in the Production Plan are measured at the bus bar of each Power Station where it is exported onto the Transmission grid. The common terminology used for energy at this point is Energy Sent Out (ESO). Since the Act imposes the Environmental Levy on generated volumes as measured at the generator of the Power Station one needs to derive the difference between generated energy and sent out. This difference in volume is the energy consumed by the Power Station (also known as auxiliary consumption) which is not available to be exported onto the grid. Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 83 of 131

84 Primary Energy For planning purposes this auxiliary volume is expressed as a percentage of sent out energy known as the Aux % of a Power Station and ultimately added to the sent out energy as expressed in the Production Plan. The result is the gross generated volume on which the Levy is calculated and which is fully aligned with the overall Eskom approved sales plan. The auxiliary consumption of the Power Station is for unit auxiliary equipment, common plant such as lighting and lifts, and outside plant such as conveyer systems, admin buildings, laboratories, stores, security, and water and ash plants. The Aux % for each Power Station is different and fluctuates from hour to hour. Auxiliary equipment differs between generators. There is little direct short-term correlation between Aux % and energy sent out at a Power Station. The Auxiliary consumption on common plant does not reduce linearly when the production from one or more of the units reduces or stops due to planned or unplanned events. This variability will therefore mostly result in variances between a Power Station s estimated Auxiliary consumption and the actual volumes consumed. The Aux % used in this submission is the weighted average of individual Power Stations estimated Aux % and the sent out mix of this specific Production Plan. The system Aux % should not be seen as a constant. Variances in individual Power Station Aux %, as well as variances in ratio of production between Power Stations and between renewable / nonrenewable sources will result in Levy cost variances. TABLE 27: ENVIRONMENTAL LEVY SUMMARY Environmental levy summary Actuals Projection Application Application Application Forecast Forecast 2017/ / / / / / /24 Energy sent out (GWh) Non Renewable Energy Sent Out (GWh) Renewable Energy Sent Out (GWh) System Average Aux % 8.21% 7.93% 7.98% 8.06% 8.07% 8.07% 8.12% Generated Volumes (GWh) Environmental Levy Cost - R'm Notes: The fluctuation of the system average Aux% is due to the different mix between Power Stations from year to year due to maintenance and other availability factors. The increase in the latter years is due to the inclusion of Medupi and Kusile with an assumed Aux% similar to Matimba Power Station with similar Auxiliary processes. Their Auxiliary energy is the highest in the Generation fleet due to dry cooling processes. Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 84 of 131

85 Primary Energy No increase in the rate is assumed for the planning period Fuel Procurement costs Fuel procurement costs are generally incurred to operate the primary energy procurement function. Most of these consist of manpower related costs. These Fuel Procurement costs are reflected under Primary Energy and are not included under Expenses in the Allowable Revenue claim in this application. TABLE 28: FUEL PROCUREMENT COST PER CATEGORY RAND MILLION Actuals Projection Application Application Application Forecast Forecast Fuel Procurement Cost (R'm) 2017/ / / / / / /24 Fuel Procurement Cost The departmental costs, the largest component of which is manpower, discussed here apply only to the Primary Energy function. This cost decreases in real terms as the headcount declines from 114 employees in 2016/17 to a 59 in 2021/22 by considering further efficiency improvements. Other costs include operating and administration costs, such as insurance premiums and subscriptions to databases. The compounded annual growth rate (CAGR) for Fuel Procurement costs is -0.2%, a decrease in costs. Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 85 of 131

86 Operating Costs (Opex) 6 Operating Costs (Opex) 6.1 Introduction to Operating Expenditure Operating costs or Operational Expenditure (Opex) comprises 3 categories, namely Manpower, Maintenance and Other Opex. Also considered are Other Income and a pro-rata portion of Corporate Overheads. The compound average growth rate (CAGR) for the period 2018/19 to 2021/22 for Generation Operating Costs including Corporate Overheads is 4%, which is below inflation. In order to meet its obligation to supply electricity, Eskom must exercise due care in the operations and maintenance of its generation fleet. Based on the recent, current and projected trends of load growth, reserve margin, load factors, technical performance, forced outage rates and historical maintenance costs, the ages of the plants in service, future maintenance activities and costs can be planned. The aim of this section of the document is to provide an overview of the operating costs projections required to support the Production Plan. Motivations and the explanations for the cost levels and the annual movements are provided. Included in the section are descriptions of the planning processes used to manage and thereby forecast Manpower, Maintenance and Other operating expenditure. 6.2 Key drivers of operating costs Capacity expansion Eskom is in the process of commissioning two new coal power stations Medupi and Kusile. Once fully commissioned, these will increase the Eskom fleet generating capacity by approximately 20%. Therefore, one can expect Generation s operating costs to increase by more than inflation over the period of the application and beyond Reserve storage stations According to the Production Plan, at an overall assumed Eskom fleet EAF of 78%, four coal stations can be placed into reserve storage, as they will not be needed to produce electricity to meet the demand. The stations are Hendrina, Grootvlei, Komati and Camden. In addition, a stress test scenario at an EAF of 75% showed, however, that all 4 stations would need to run to meet the system demand throughout the MYPD 4 period. Therefore, at this stage, it is premature to decommission these 4 stations and a decommissioning decision has not yet been made. Generation has, however, reduced the operating costs at these 4 stations over the planning period to reflect a reduction in activities during a period of reserve storage. Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 86 of 131

87 Operating Costs (Opex) Ageing fleet and high UCLF impact on maintenance costs The existing operational fleet of power stations is now on average about 32 years old and more than half of the coal-fired fleet will be older than 37 years by the start of the MYPD 4 period. Thus, a real increase in maintenance costs on this ageing fleet over the next 10 years is expected due to additional maintenance activities and mid-life refurbishments on older power plants. In the period 2013/14 to 2016/17, Eskom experienced a steep increase in maintenance costs (capital and operating costs). The benefit of the investments made in maintenance costs over the period is evidenced in the improvement of the overall technical performance of the power stations with an EAF for the financial year 2017/18 of 78% from a low of an EAF of 72%. To maintain an EAF of 78%, this high level of maintenance spending needs to be maintained or the technical performance will once again deteriorate Employee benefit costs Headcount Overall, the number of employees, including support service employees is assumed to reduce during the MYPD 4 period. This includes the additional employees for the new build power stations. Significant efficiencies have been realized in the existing power station fleet to cater for the increase in employees in newly commissioned power stations. The reduction in headcount will lead to a decrease in manpower costs. TABLE 29: HEADCOUNT ASSUMPTIONS Generation headcount Actuals Projection Application Application Application Forecast Forecast 2017/ / / / / / /24 Generation Licence Headcount Year-on-Year % change -2% -6% -4% -1% 0% 0% Manpower inflation The decrease in manpower costs due to reduction in headcount is partially countered by above inflationary salary increases for bargaining unit staff for the next 3 years Insurance costs An upward trend in insurance costs has been experienced. This is typical for a generation fleet that has experienced high levels of unplanned outages that resulted in an increase in insurance premiums from a very low base. In addition, more assets will be under insurance, as the new units of Medupi and Kusile are commissioned. Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 87 of 131

88 Operating Costs (Opex) Once-off abnormal items The following are once-of abnormal items that should be disregarded from the base when comparing MYPD 4 application costs to historical costs Once-off decommissioning adjustment in 2017/18 The 2017/18 actual operating costs had to accommodate a necessary adjustment in the applicable discount rate for a once-off adjustment to the decommissioning provision. The adjustment was a once-off credit of R3.2bn Once-off provision raised for Duvha unit 3 insurance refunds in 2017/18 An R1.5bn provision was raised at the 2017/18 year-end for the Duvha unit 3 boiler explosion insurance refunds Maintenance costs in 2018/19 and 2021/22 Koeberg has 2 long duration outages of 90 days each; instead of the normal average 35 day refuelling outages. Koeberg power station follows a maintenance routine of a short duration outage (SDO) of approximately 35 days followed by a long duration outage (LDO) of approximately ninety days. In both types of outages, fuel is replaced. However, in the LDO additional maintenance and modifications are undertaken. Due to legislative requirements, during 2018/19, Koeberg will be undertaking LDOs on both of its units. This has resulted in the higher maintenance costs in 2018/19 which is only seen in one of the three years in the MYPD 4 application; i.e. in 2021/22. TABLE 30: OVERALL SUMMARY OF OPERATING COSTS Total Generation Opex Actuals Projection Application Application Application Forecast Forecast (R'm) 2017/ / / / / / /24 Manpower Maintenance Other opex Other income Total Generation Opex excl O/H Corporate Overheads Total Generation Opex The compound average growth rate (CAGR) for the period 2018/19 to 2021/22 for Generation operating costs including corporate overheads is 4%, which is below inflation. The CAGR for the period 2018/19 to 2021/22 for Total Generation Opex excluding O/H is 4.6%. Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 88 of 131

89 Operating Costs (Opex) The CAGR for the period 2018/19 to 2021/22 for Generation manpower costs is 3.2%, which is below inflation. The above inflation increases for the bargaining unit employees per the negotiated wage settlement with the trade unions, was offset by the reduction in headcount over the forecasting period. The CAGR for the period 2018/19 to 2021/22 for Generation maintenance costs is 3%, which is below inflation. This is mainly due to the reduction in maintenance costs at the reserve storage stations, partially offset by increased maintenance costs at Medupi and Kusile as new units are brought into commercial operation, which will add maintenance costs to the Generation fleet base during the MYPD 4 period. The CAGR for the period 2018/19 to 2021/22 for Generation Other Opex is 11.2%, which is above inflation. This is mainly because the 2018/19 other Opex is abnormally low due to liquidity challenges. However, this low level of expenditure on other Opex is not sustainable into the future. Using the 2017/18 actuals (adjusted for abnormal items) as a base, other Opex costs reduces over the forecasting period. This reduction in costs is mainly due to a reduction in costs at the reserve storage stations. The CAGR for the period 2018/19 to 2021/22 for Generation Corporate Overheads is 1.4%, which is significantly below inflation. The reasons for the reduction in corporate overheads are explained in the Corporate MYPD 4 Submission. 6.3 Opex Benchmarking It is acknowledged that comparison to operational cost benchmarks is not always simple nor an exact science due to complexity in the status of various power plants. Sources of benchmark data may vary significantly from Eskom plant in terms of equipment, age, maintenance philosophy and overall condition of plant. However, certain comparisons have been undertaken for Eskom s coal power plants. They give an indication of level of cost comparatively to other similar utilities. This analysis could improve confidence in own costs or stimulate investigation if own costs do not compare favourably Benchmark benefits Eskom has compared its operational performance against an international benchmark with a 2015 base year comparison Benchmark Fixed operations and maintenance cost (O&M)= $40/kW Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 89 of 131

90 Operating Costs (Opex) Variable (O&M) = $4/MWh Coal Station Load Factor 2015 = 65.45% Relates to $22.93/kW Total (O&M) = $62.93/kW Note that O&M for Eskom for purposes of this comparison includes technical plan and outage Capex. FIGURE 31: BENCHMARK COMPARED TO REAL O&M $/KW (COAL ONLY) The benchmark is skewed in that it considers lifecycle costs which smooth the benchmark, whereas we are comparing to Eskom power station annual costs, the bulk of which are in mid-life cycle requiring higher mid-life refurbishment costs and as well as maintenance backlog costs which saw an EAF improvement from In addition, more expensive maintenance interventions were performed at the Return to Service stations and Hendrina where the units are smaller with a higher impact from a $/KW perspective than spend on the conventional 600MW units. The high utilisation of the Eskom power stations over a number of years has placed unusually high stress on plant systems and components which would also increase operating and maintenance costs. Bearing this in mind one would expect the Eskom costs to be higher than the benchmark. However, at the applicable exchange rate, Generation is consistently below the International benchmark for the MYPD 4 period. The reduction in the spend at the stations that will be placed in reserve storage, will contribute to a lower R/kW. This provides a perspective of Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 90 of 131

91 Operating Costs (Opex) Eskom generating costs being better than the comparisons of other utilities. The comparison at R11 US$ is included purely as a sensitivity test; however, it also reflects a very favourable comparison. It is Generation s intent to keep the Opex cost within international benchmarks, unless there is strategic intent to increase maintenance to improve technical performance due to aging plant or high utilisation compared to international benchmarks. 6.4 Manpower Introduction The need for fundamental operational changes is recognized in order to provide an affordable and sustainable electricity supply to all South Africans. Workforce optimisation was identified as a major component to drive internal efficiencies, increase productivity and lower operating costs. However, in a continual quest to optimize costs, Eskom does embark on benchmarking exercises to evaluate its costs against world-wide trends. According to the results of this evaluation, total Opex (of which Employee Benefits is a component) is within the norms as set out in the section on Opex Benchmarking above The headcount planning process Headcount has been identified as the major driver for manpower cost and therefore workforce optimisation becomes key to cost reduction. The approach to headcount reduction focuses mainly on retention of critical workforce segments while reducing non-core workforce across the organisation. The model below has been used to classify the organisational critical workforce segments. Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 91 of 131

92 Operating Costs (Opex) FIGURE 32: CLASSIFICATION OF ORGANISATIONAL CRITICAL WORKFORCE SEGMENTS As such, retention of critical workforce segments (i.e. core, critical & scarce skills) for the generation business continues to be the focus of optimisation initiatives. While retention of critical workforce segments remains the focus, the organisation is embarking on initiatives to improve the workforce productivity. This will ensure the establishment of the right skills mix across all segments while ensure the optimum level of supply of skills. TABLE 31: GENERATION HEADCOUNT Generation headcount Actuals Projection Application Application Application Forecast Forecast 2017/ / / / / / /24 Generation Licence Headcount Year-on-Year % change -2% -6% -4% -1% 0% 0% In order to view the headcount numbers in context, cognisance should be taken of the following: Growth in generating capacity and refurbishments required since 2007 A number of external commentators have attempted to simplify this matter to a comparison of annual sales in GWh in 2007 vs. that in It is, however, not as simplistic as that. Electricity generation is a long-term industry, for which capacity expansion is commenced many years ahead of actual anticipated demand growth. Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 92 of 131

93 Operating Costs (Opex) Insufficient or late expansion of capacity can result in load shedding and significant economic disruption, as South Africa had experienced due to the late start in 2006 of the new generation capacity build programme. Thus, irrespective of current sales volumes, the Eskom business has grown significantly since the start of the new generation capacity build programme Return to Service stations: At 31 March 2007 there were only five of Camden s eight units in operation. Four of the five were only commissioned during that year so the operating costs as in financial year 2006/7 would not have reflected a full year s costs for operating those four units. It would thus probably be more accurate to say that in 2006/7 there was only one unit that operated for the full year. Thus the costs for operating, manning and maintaining the other 22 of the 23 units of those three power stations (3500 MW in total) were only incurred after Ankerlig and Gourikwa OCGTs: Four units with a total of 583 MW had been commissioned during 2006/7 thus the operating costs as in financial year 2006/7 would not have reflected a full year s costs for operating those four units. It would thus probably be more accurate to say that the costs for operating, manning and maintaining fourteen units of 2084 MW total capacity were only incurred after Ingula pumped storage: Four units of 1332 MW total capacity constructed and commissioned, thus the costs for operating, manning and maintaining those units were only incurred after Medupi and Kusile: Four units constructed and commissioned after 2007 and another eight units under construction. Their operating, manning and maintenance costs were thus only incurred after Large mid-life refurbishment These are projects on existing power stations which have reached ages of years old since On the other hand, the Production Plan shows that three stations namely Grootvlei, Komati and Hendrina, will not be required to produce energy from late 2019/20 depending on the various assumptions in the Production Plan. The intent is to shutdown these power stations but not to decommission them as they may be needed in the future, again depending on the outcomes of the various assumptions in the Production Plan. This will nevertheless provide Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 93 of 131

94 Operating Costs (Opex) an opportunity to reduce staffing at these stations. Following this preservation, the standard Eskom processes will be utilised to re-deploy personnel across the Generation business and in Eskom as a whole to fill other critical vacancies, including re-skilling of personnel for where required. Another option that will be explored is to displace service providers at the other coal stations with any surplus Eskom employees Assessing the Reasonability of the Headcount In August 2016 the World Bank s Energy and Extractives Global Practice Group released the Policy Research Working Paper titled Financial Viability of Electricity Sectors in Sub- Saharan Africa - Quasi-Fiscal Deficits and Hidden Costs. For Eskom Generation, the World Bank s report estimated the optimum staffing number at for the total installed capacity of MW, which implies a ratio of 9.53MW of generation plant capacity per employee. This is significantly higher than the World Bank report s implied average for Africa of 2.3MW per employee and with 75% of electricity generation in Sub-Saharan Africa (SSA) (excluding South Africa) produced from hydro and natural gas plants it could be argued that the ratio of MW per employee for SSA should be higher than for Eskom, not lower as implied by these numbers. For coal plant specifically, the World Bank report implies a ratio of 2.44MW per employee in the case of Botswana, whilst using a ratio for Eskom of 9.53MW per employee which is also (mostly) coal plant. Eskom s own further research, based on published US Government data, indicates that the ratio of generation plant capacity per employee for US coal power stations is around 3.38MW per employee. It therefore appears that also on the optimum staffing numbers for Eskom s generation activities, a human error might have slipped in. Using a more moderate ratio of 3.2MW per employee (14% lower than the US data for coal plants, but 30% higher than the World Bank report s ratio for coal as per Botswana and 40% higher than their ratio for SSA for mostly hydro and natural gas plants), it translates to employees for Eskom Generation. Based on the 2017/18 actuals (i.e. before the planned headcount reductions on which MYPD 4 is based), the MW per employee was 3.30MW for the coal stations and an overall of 3.32MW for the total Generation fleet. This compares favourably with the World Bank s Botswana benchmark as well as that of US coal power stations. Taking cognisance of the headcount reductions in MYPD 4, this measure should be set to improve further. Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 94 of 131

95 Operating Costs (Opex) Therefore, based on the data, Generation s headcount numbers are in line with World norms Risks associated with headcount reductions In pursuit of headcount reduction, the following risks have been identified that will require management thereof: Negative impact on Generation operations: Following the loss of other critical skills through normal attrition and non-replacement thereof, there are certain vacancies that remain critical without which the operations within the generation business have been negatively impacted Unintended loss of core and critical skills: The headcount reduction, if not properly managed, could result in the loss of critical skills that should in fact be retained Increased Costs: Loss of core skills and expertise may negatively impact on operations which could result in higher costs Unachieved Employment Equity Targets: Unrealistic employment equity targets that are pushed without consideration of headcount targets and current core and critical resources requirements Low Employee Morale: Pursuit of headcount reduction resulting in the non-replacement of critical positions may lead to employees assuming multiple roles and conflicting work demands may cause low staff morale and fatigue Conclusion on employee benefits Manpower costs increase at below inflation for the MYPD 4 period, primarily due to targeted headcount reduction. This reduction is partially offset by above inflation increases for, at least, bargaining unit staff. The headcount reduction assumes an aggressive drive to reduce numbers. External influences such as bargaining forum and political interventions could impact the realisation of these assumptions, resulting in costs above those assumed. However, based on World Bank Report s (after correcting for data error) benchmarking analysis of MW per employee, Generation s headcount numbers are in line with World norms. Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 95 of 131

96 Operating Costs (Opex) 6.5 Maintenance cost Introduction Eskom applies asset management principles which include planning on how to ensure the optimal operating and maintenance of the existing fleet for the duration of its economic life, including inputs such as primary energy and major refurbishments. Planning for the operating and maintenance of the fleet can be separated into Maintenance Planning and Production Planning. Maintenance Planning is informed by what maintenance needs to be performed, in terms of replacement/refurbishment of components of the assets as well as the routine outage maintenance activities. The Life of Plant Plan (LOPP), details these major maintenance and refurbishment projects that are required over the life of the plant. The Technical Plan is a more refined extract of the LOPP over a shorter period and the Maintenance Plan is a listing of the outages required to implement the LOPP and Technical Plans. The Capacity Plan then takes a detailed view of the first year of the Maintenance Plan to ensure that all required outages are scheduled whilst ensuring there is adequate capacity available to meet demand. Production Planning describes how the required energy demand is to be met on an hourly basis whilst maintaining least-cost dispatch within known constraints. FIGURE 33: MAINTENANCE PLANNING OVERVIEW Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 96 of 131

97 Operating Costs (Opex) The LOPP is a plan of major maintenance and refurbishment interventions that are required over the full life of the station. Eskom uses a plant-aged assumption for long term planning including the Generation expansion, financial and Life of Plant Plans (LOPP), however, the actual life is not determined by age but the economic viability. Currently, 50 years for the coal fleet is used for planning purposes. The LOPP is based on a codified preventive maintenance strategy for each power station. This prescribes what maintenance interventions are required at what periodicity as well as the standard maintenance activities required. Stations have specific requirements with respect to the numerous cyclical maintenance interventions required on a power plant. However, generic rules exist: General Overhaul (GO): Every years plant shutdown to do inspection and repair of turbine & generator. Mini GO: Every 5-6 years inspection of low pressure turbines, and statutory pressure test. Interim Repair (IR): monthly plant is shutdown to inspect and repair the boiler components. Boiler Inspection (IN): Between IR s an inspection is carried out to review condition of the boiler and scope the next outage. Opportunity maintenance frequently leads to the above schedule being modified which gives rise to adaptions of the sequence, but every effort is made to recover the sequence to ensure plant safety and operability. Maintenance activities are prioritisation by scheduling outages according to the following priority: Immediate safety risk as per ERAP inclusive of any emerging technical threat which is deemed to pose immediate and significant personnel or plant risk. Statutory such as pressure tests. Licence to operate risks such as major contraventions of legislation. Philosophy/Reliability scope is included in the outages based on the durations available. Maintenance costs are primarily a function of the amount of maintenance and the cost of each maintenance activity. The amount of maintenance is influenced by factors such as Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 97 of 131

98 Operating Costs (Opex) capacity added to or removed from the system, the age of plant and maintenance activities are determined by the maintenance planning process. The compound annual growth rate (CAGR) for the period 2018/19 to 2021/22 for Generation maintenance costs is 3%, which is below inflation. This is mainly due to the reduction in maintenance costs at the reserve storage stations, partially offset by increased maintenance costs at Medupi and Kusile as new units are brought into commercial operation, which will add maintenance costs to the Generation fleet base during the MYPD 4 period Key drivers of maintenance costs Capacity expansion Eskom Generation has initiated the process towards commissioning two new power stations to its fleet (Medupi and Kusile) which will roughly increase the fleet generating capacity by 20% when fully commissioned. Therefore one can expect Generation s maintenance costs to increase in real terms Ageing fleet and high UCLF impact on maintenance costs The existing operational fleet of power stations is now on average about 32 years old. Thus a real increase in maintenance costs on this ageing fleet in the next 10 years is expected due to additional maintenance activities on older power plants. In the period 2013/14 to 2016/17, Eskom experienced a steep increase in maintenance costs (capital and operating costs). The benefit of the investments made in maintenance costs over the period is evidenced in the improvement of the overall technical performance of the power stations to an EAF for the financial year 2017/18 of 78% from a low of an EAF of 72%. To maintain an EAF of 78%, this high level of maintenance spending needs to be maintained or the technical performance will deteriorate again Maintenance costs in 2018/19 and 2021/22 Koeberg has 2 long duration outages of 90 days each, instead of the average 35 day refuelling outages in these two financial years. In accordance with legislative requirements, Koeberg power station follows a maintenance routine of a short duration outage (SDO) of approximately 35 days followed by a long duration outage (LDO) of approximately ninety days. In both types of outages, fuel is replaced however in the LDO additional maintenance and modifications are undertaken. Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 98 of 131

99 Operating Costs (Opex) During the 2019 financial year, Koeberg will be undertaking LDO on both of its units. This is reflected in the high maintenance cost of R 510m in 2018/19. Similarly, an abnormal high maintenance cost for Koeberg in 2021/22 is forecast. FIGURE 34: TOTAL MAINTENANCE COSTS R M Except for the spike in maintenance costs in 2018/19 and 2021/22, maintenance cost in Generation grows very gradually over the forecasting period, despite Medupi and Kusile s new units being commissioned that will add additional maintenance costs to the base. The spike in maintenance costs in 2018/19 and 2021/22 is caused by two long duration outages at Koeberg in those two years. In the figure below, Koeberg s maintenance costs are excluded to see the trend in the rest of the fleet. If Koeberg s maintenance costs are excluded from the rest of the fleet, one can see an increase in maintenance costs at a rate lower than inflation over the forecasting period. This is driven mainly by a reduction in maintenance costs at the reserve storage stations (Hendrina, Grootvlei and Komati) as reflected in the table below. Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 99 of 131

100 Operating Costs (Opex) TABLE 32: REDUCTION IN MAINTENANCE COSTS AT THE RESERVE STORAGE STATIONS (R M) Reduction-maintenance costs Application Application Application Forecast Forecast 2019/ / / / /24 Grootvlei Hendrina Komati Total reduction in costs Maintenance costs at the reserve storage stations have been reduced to reflect that they are forecasted not to produce any electricity over the forecasting period. If any of the risks materialise, then these units would need to be utilised. This reduction in costs has been built into the total maintenance costs already Conclusion on maintenance costs The compound annual growth rate (CAGR) for the period 2018/19 to 2021/22 for Generation maintenance costs is 3%, which is below inflation. This is mainly due to the reduction in maintenance costs at the reserve storage stations, partially offset by increased maintenance costs at Medupi and Kusile as new units are brought into commercial operation, which will add maintenance costs to the Generation fleet base during the MYPD 4 period. 6.6 Other Opex The cost category Other Opex contains all the operating costs that are not classified as either manpower or maintenance costs. It consists of the operating costs of the following roles in Generation: Finance, operating, engineering, HR, commercial, IT, fleet management, communication, safety/risk, medical centre, protective services, technology, environmental, horticulture, office services, catering, internal electricity usage, rates and taxes, insurance, stakeholder management and decommissioning provisions. The compound annual growth rate (CAGR) for the period 2018/19 to 2021/22 for Generation Other Opex is 11.2%, which is above inflation. This mainly because the 2018/19 other Opex is abnormally low. If other Opex in 2017/18 is adjusted for the two abnormal items as shown in the table below, then actual other Opex costs were R6 194m. If this adjusted base is compared to the 2018/19 projection of R4 384m, other Opex reduced year-on-year by 29%. This reduction in Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 100 of 131

101 Operating Costs (Opex) 2018/19 is due to the liquidity constraints that Eskom is experiencing, but that level of expenditure is not sustainable into the future. If the 2017/18 actuals (adjusted for abnormal items) is used as the base, then the other Opex costs reduces in real terms over the forecasting period. This reduction is mainly due to a reduction in other costs at the reserve storage stations. TABLE 33: GENERATION OTHER OPEX R M Total Generation Other Opex Actuals Projection Application Application Application Forecast Forecast R'million 2017/ / / / / / /24 Other Opex Abnormal items in 2017/18 Duvha unit 3 Prov for refund to insurers Long term provisions adjustments Total Generation Other Opex Decommissioning provision adjustment The 2017/18 actual operating costs had to accommodate a necessary adjustment in the applicable discount rate for a once-off adjustment to the decommissioning provision. This abnormal credit of R3.1bn resulted in an abnormally low base for Other Opex Internal electricity usage Internal electricity costs increase from R290m in 2017/18 to R654m in 2018/19. There is an equal, but opposite amount under revenue. 6.7 Other Income Other income consists of the following categories: Insurance income, operating lease income, sale of scrap and sundry income. Other income is difficult to forecast with any degree of accuracy. The forecast for the next few years was done based on historical trends. TABLE 34: GENERATION OTHER INCOME RAND MILLION Other Income (R'm) Actuals Projection Application Application Application Forecast Forecast 2017/ / / / / / /24 Insurance income Operating lease income Sale of scrap Sundry income Total Other Income Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 101 of 131

102 Operating Costs (Opex) 6.8 Conclusion on Opex As was motivated in detail above, Generation s operating costs forecast is prudent and efficient. The benchmarking exercise proves that Generation s operating costs are lower than international norms. The compound average growth rate (CAGR) for the period 2018/19 to 2021/22 for Generation operating costs including corporate overheads is 4%, which is below inflation. The CAGR for the period 2018/19 to 2021/22 for Total Generation Opex excluding O/H is 4.6%. The CAGR for the period 2018/19 to 2021/22 for Generation manpower costs is 3.2%, which is below inflation. The above inflation increases for the bargaining unit employees per the negotiated wage settlement with the trade unions, was offset by the reduction in headcount over the forecasting period. The CAGR for the period 2018/19 to 2021/22 for Generation maintenance costs is 3%, which is below inflation. This is mainly due to the reduction in maintenance costs at the reserve storage stations, partially offset by increased maintenance costs at Medupi and Kusile as new units are brought into commercial operation, which will add maintenance costs to the Generation fleet base during the MYPD 4 period. The CAGR for the period 2018/19 to 2021/22 for Generation Other Opex is 11.2%, which is above inflation. This mainly because the 2018/19 other Opex is abnormally low due to liquidity challenges. However, this low level of expenditure on other Opex is not sustainable into the future. Using the 2017/18 actuals (adjusted for abnormal items) as a base, Other Opex costs reduce over the forecasting period. This reduction in costs is mainly due to a reduction in costs at the reserve storage stations. The CAGR for the period 2018/19 to 2021/22 for Generation Corporate Overheads is 1.4%, which is significantly below inflation. Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 102 of 131

103 RAB, Return and Depreciation 7 RAB, Return and Depreciation 7.1 Regulated asset base (RAB) The capital related aspects of the MYPD allowed revenue formula are considered here. Key aspects that are considered are the determination of the regulatory asset base, depreciation and return on assets. The relevant aspects of the allowed revenue, in terms of the MYPD methodology considered here are highlighted: AR=(RAB WACC)+E+PE+D+R&D+IDM±SQI+L&T±RCA The ERA and the Electricity Pricing Policy (EPP) require the recovery of efficient costs and earning a fair return on capital. The EPP and the MYPD methodology require that assets are valued at replacement value for setting of regulated revenue. In accordance with the MYPD methodology, Eskom has undertaken a revaluation of all completed assets used in the generation, transmission and distribution of energy as at 31 March This was undertaken by an independent entity that has international experience in the realm of asset valuation for large infrastructure companies. As required by the MYPD methodology, the determination of the regulatory asset base value is based on the costs to replace these assets (i.e. Modern Equivalent Assets Valuation) and adjusted for the remaining life. This valuation has been undertaken in accordance with the guidelines and requirements of the International Valuation Standards. The basis of the valuation was the Eskom fixed asset registers and comparisons were made with market data for actual construction cost of similar assets. This valuation exercise was a continuation of previous asset valuation exercises, during which site visits to samples of the physical assets were performed. The Depreciated Replacement Cost (DRC) was determined through the application of the cost approach methodology, which is a recognised approach for the valuation of specialist assets which are not regularly traded. The cost approach methodology includes the identification of the estimated new replacement cost of assets, which is then adjusted to reflect physical, functional and economic obsolescence. Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 103 of 131

104 RAB, Return and Depreciation FIGURE 35: PROCESS FOR VALUATION OF EXISTING ASSETS The asset values in the Regulatory Asset Base are therefore not shown at the new cost to replace them but at their depreciated replacement cost. For example, if it costs R1bn to replace an asset at the end of March 2016 which has two years remaining life out of a total useful life of 25 years, the depreciated replacement cost at the end of March 2016 would be R80 m (i.e R1bn x 2/25). This valuation forms the basis of the RAB application as shown in the table below. Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 104 of 131

105 RAB, Return and Depreciation TABLE 35: REGULATORY ASSET BASE (RAB) SUMMARY 2017/ / / / / / /24 Regulatory asset base (R'millions) MYPD3 Decision Decision Application Application Application Forecast Forecast Assets (Including WUC) Working capital and Equipment and vehicles Average Generation RAB Assets (including WUC) comprise the following components: In accordance with the MYPD methodology, the regulatory asset base is comprised of the following: Assets as per the March 2016 asset valuation Work under construction (WUC): In accordance with the MYPD methodology, for assets that constitute creation of additional capacity, the capital project expenditures or WUC values (excluding IDC) incurred prior to the assets being placed in Commercial Operation (CO) are included in the RAB and earn a rate of return based on the real WACC. New constructed assets: This refers to assets transferred into Commercial Operation subsequent to the 2016 asset valuation. It includes power station units as well as networks commissioned subsequent to the asset valuation. Once commissioned, these assets are included in the RAB for purposes of earning a return as well as for the depreciation allowance. The depreciation allowance is calculated by dividing the cost of the asset over the number of years that the asset is to be used for i.e. the useful life of the asset. 7.3 Assets as per the March 2016 asset valuation The extract of the Depreciated Replacement Costs (DRC) from the valuation report is shown in the Table below. The valuation report excludes interest during construction (IDC) due to the WUC being included in the RAB for return purposes. In addition, working capital, asset purchases and Work under Construction were also excluded since these were not part of the scope of the consultants valuation project but will be added to the report s values, in accordance with the MYPD methodology. Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 105 of 131

106 RAB, Return and Depreciation TABLE 36: EXTRACT FROM CONSULTANT 2016 ASSET VALUATION REPORT The RAB summary in the Table above reflects a growth in the average RAB of R536 billion between the RAB values as assumed for purposes of the FY2019 revenue decision, and those for FY2020. The key reasons for the growth are as follows: The RAB value for purposes of the revenue determination for FY2018/19 was not based on a valuation exercise, due to the requirement for such valuation only becoming known when the revised MYPD Methodology was published at the end of October 2016, which did not allow sufficient time for the external valuation project to be completed. Eskom thus requested condonation from complying with that requirement and proposed the use of the last public domain RAB values i.e. as for the fifth year of the MYPD3 cycle. NERSA approved the request for condonation. In addition, relative to the RAB for FY2018/19, the RAB for FY2020 is adjusted with subsequent actual and planned capital expenditure and the consumer price index (CPI) adjustments The existing asset base as at 31 March 2016 has been revalued, amounting to R639 billion (as shown in Table above) compared to the NERSA determination of R410 billion for FY2016 for purposes of the MYPD 3 revenue decision as reflected in Table below. A key reason for the increase is due to the change in the overnight cost which has increased between the previous 2010 valuation (used for MYPD3 and the FY2019 revenue decision) and the 2016 valuation. The overnight cost for this purpose is determined by the consultants based on global benchmark costs for similar infrastructure projects in the electricity industry. Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 106 of 131

107 RAB, Return and Depreciation TABLE 37: FY2016 RAB VALUES AS ASSUMED FOR PURPOSES OF MYPD3 REVENUE DECISION FY2016 RAB- MYPD 3 Decision (R'millions) Generation Transmission Distribution Total Eskom Property and Plant Equipment & Vehicles Total Work Under Construction Total Working Capital Total average RAB The breakdown reflected in the table above is as per the extract of the NERSA Reasons for Decision for the MYPD 3 revenue determination as shown below: 7.4 Work under construction (WUC) In terms of the MYPD methodology the criteria for inclusion of WUC into the RAB is for those assets that are for the creation of additional generation, transmission and distribution capacity and are defined as follows: Expansion this is capital expenditure to create additional capacity to meet the future anticipated energy demand forecast. Upgrade this is capital expenditure incurred to ensure that the current and future energy demand forecast is met. Replacement this is capital expenditure to replace assets that have reached the end of their useful life in order to continue meeting the current demand. Environmental legislative requirements this is capital expenditure incurred to ensure that the licensing condition is maintained thereby continuing to meet the current energy demand forecast. A WUC in essence refers to the capital expenditure being undertaken and meets the criteria referred to above for inclusion in the RAB. In terms of the MYPD methodology, the WUC balance is required to earn a return on assets but is not depreciated until assets are Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 107 of 131

108 RAB, Return and Depreciation transferred to Commercial Operation (CO). Only upon commercial operation (CO) do these assets incur depreciation costs. Transfers to commercial operation for generation assets are grouped per station and the normal useful life for depreciation is limited to the remaining life of the respective power station. 7.5 Depreciation As is required by the MYPD methodology, the annual depreciation allowance is determined by dividing the cost of the asset less the residual value by the estimated useful life of that asset. Table below reflects the revenue related to depreciation for the MYPD 4 period. TABLE 38: DEPRECIATION Depreciation (R'millions) 2017/ / / / / / /24 MYPD3 Decision MYPD 3 decision Application Application Application Forecast Forecast Assets as per FY2016 valuation Other Total Depreciation on assets as per the FY2016 valuation is computed by dividing the depreciated value of the assets over the remaining life of the respective assets as reflected at the end of March There is a steep change between FY2019 and FY2020, which is due to the current asset valuation being higher by about R229 billion in FY2016 compared to the MYPD3 values for FY2016. For the Generation Other category of assets, all subsequent transfers to commercial operation are depreciated over the asset life but limited to the remaining life of the power station. 7.6 Return on assets Generation, in this revenue application has applied the NERSA MYPD methodology, combined with a smoothed phasing-in of the return on assets. However, the return on assets at the end of the three year period do not reach the weighted average cost of capital (WACC) as determined in accordance with the MYPD methodology, nor the WACC as was determined by NERSA for purposes of the 2018/19 revenue determination. This phasing in approach was limited to the degree required so as to ensure that the depreciation and return on asset covers a significant portion of the interest and repayment costs over the three year period and fully covers annual debt service costs (interest and principal) for the 2021/22 financial year. Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 108 of 131

109 RAB, Return and Depreciation TABLE 39: RETURN ON ASSETS Return on assets (R'millions) 2017/ / / / / / /22 Decision Decision Application Application Application Forecast Forecast Average RAB (R'm) Full Return on Assets (ROA) % 7.65% 6.9% 9.31% 9.34% 9.37% 9.39% 9.40% Returns (R'm) Phased in ROA % 4.7% 4.00% -1.32% -0.21% 1.45% 1.76% 2.46% Phased in Returns (R'm) Returns sacrificed (R'm) Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 109 of 131

110 Capital Expenditure 8 Capital Expenditure 8.1 Introduction This chapter provides an overview of the Capex to be spent and the assumptions used to derive the cost estimates. The largest contributor to the projected Capex spend is for the remaining units of the new build projects, Medupi and Kusile. Eskom Group Capital also manages major refurbishment and upgrade projects for the Generation fleet and these are included with the new build Capex. In addition, Eskom Generation manages and accounts for Technical Plan and Outage Capex separately so these are also shown as separate line items. Other contributors are for Renewables (Sere), and for Future Fuel, both Coal and Nuclear. TABLE 40: GENERATION CAPEX SUMMARY Total Generation Capex R'million Actuals 2017/18 Projection 2018/19 Application 2019/20 Application 2020/21 Application 2021/22 Forecast 2022/23 Forecast 2023/24 New build and major projects Outage capex Technical Plan capex Renewables Future Fuel capex Nuclear future fuel Coal future fuel Asset purchases Total Gx License Capex-NERSA Generation New build and major technical plan projects Overview Eskom is executing the largest capital expansion programme in Africa and executes projects that ensure environmental compliance, transmission strengthening, customer connections and refurbishment of existing assets in accordance with Eskom s project life-cycle model (PLCM). The two largest projects are the new builds at Medupi and Kusile. Medupi is 95% complete (as at August 2018) with units 6, 5 and 4 already in commercial operation adding MW to the national grid. Kusile is 89% complete (as at August 2018) with unit 1 already in commercial operation, adding 720MW to the national grid. In addition, Eskom is in the process of constructing the following key generation projects: Upgrading other existing plants (Matla, Kriel and Duvha Power Stations). Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 110 of 131

111 Capital Expenditure Executing other Generation coal projects, such as emission compliance projects and fabric filter plant (FFP) retrofits. Constructing a 68 km railway between Majuba Power Station and the coal railway hub in the town of Ermelo in Mpumalanga. Executing the Koeberg steam generator replacement project for units 1 and 2. Executing the Ankerlig Transmission Koeberg Second Supply (ATKSS) Project. Executing the distributed battery storage project, as an alternative to a 100 MW Concentrated Solar Power (CSP) plant, at Eskom distribution constrained sites close to renewable energy Independent Power Producer (IPP) plants and at Sere Wind Farm. Executing other diversified, but related projects, such as Smart Grid and Medupi Fuel Gas Desulphurisation (FGD) are also executed by GCD Key issues impacting the build programme Some key issues include the following: Delays in the commercial process, poor contractor performance, stability on site due to labour unrest, vandalism and material unavailability and/or theft result in projects falling behind schedule. Outage availability/difficulty in integrating project outage schedules with the National Control Outage Schedule and the unavailability of commissioning resources. TABLE 41: COMMERCIAL OPERATION DATES FOR REMAINING UNITS PROJECT Unit Latest Forecast CO Date Medupi Unit 3 31-Oct-18 Medupi Unit 2 31-May-19 Medupi Unit 1 31-May-20 Kusile Unit 2 31-Oct-18 Kusile Unit 3 31-Aug-19 Kusile Unit 4 31-Dec-20 Kusile Unit 5 31-Aug-21 Kusile Unit 6 30-Jun Project scope and progress The project scope and progress of the major projects are: Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 111 of 131

112 Capital Expenditure a) Medupi The Medupi Power Station Project near Lephalale in the Limpopo Province is a green-fields coal-fired power plant comprising of six units rated in total at 4 764MW installed capacity. Medupi incorporates super critical technology with its boilers and turbines, which is able to operate at higher temperatures and pressures than Eskom s previous generation plant, and most importantly operates with greater efficiency, resulting in better use of natural resources, for example, water and coal, and will have improved environmental performance. The plant uses direct dry-cooling due to the water scarcity in the area. In this process, all the water will be re-used in the electricity generation process. Once completed, the power station will be the fourth largest coal-fired plant and the largest dry-cooled power station in the world. The planned operational life of the power station is 50 years. Unit Six (6) achieved commercial operation on the 23 August 2015, Unit Five (5) on 3 April 2017 and Unit 4 on 28 Nov TABLE 42: MEDUPI OVERALL % COMPLETE AS AT END OF AUGUST 2018 Overall % Complete as at August 2018 Unit Medupi % Complete Unit 6 Unit 6 Overall Progress 100% Unit 5 Unit 5 Overall Progress 100% Unit 4 Unit 4 Overall Progress 100% Unit 3 Unit 3 Overall Progress 99% Unit 2 Unit 2 Overall Progress 93% Unit 1 Unit 1 Overall Progress 78% Overall % Complete 95% b) Kusile Kusile is a greenfield coal fired power plant project comprising 6 units with a total installed capacity of MW. The Kusile site is about hectares in size, and is situated on the Hartbeesfontein and Klipfontein farms in the Nkangala District of the Mpumalanga Province. Kusile is the first power station in South Africa to have Flue Gas Desulphurization (FGD) installed. FGD is the current state of the art technology used to remove oxides of sulphur Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 112 of 131

113 Capital Expenditure (SOx), e.g. sulphur dioxide (SO2), from the exhaust flue gases in power plants that burn coal or oil. This technology is fitted as an atmospheric emission abatement technology, in line with current international practice, to ensure compliance with air quality standards, especially since the power station located in a priority airshed. Unit One (1) achieved commercial operation on the 30 August TABLE 43: KUSILE OVERALL % COMPLETE AS AT END OF AUGUST 2018 Overall % Complete as at August 2018 Unit Kusile % Complete Unit 1 Unit 1 Overall Progress 100% Unit 2 Unit 2 Overall Progress 99% Unit 3 Unit 3 Overall Progress 93% Unit 4 Unit 4 Overall Progress 80% Unit 5 Unit 5 Overall Progress 69% Unit 6 Unit 6 Overall Progress 60% Overall % Complete 89% c) ATKSS Project The Acacia Project or also referred to as ATKSS (Ankerlig Transmission Koeberg second supply project) is needed to release the Acacia Koeberg 132 kv line, currently used as a dedicated line for the Koeberg off-site supply, to be energised as the second Acacia Koeberg 400 kv line. The second 400 kv line is required for the network to be grid code compliant. Not executing the project will result in the existing lines connecting Koeberg with Acacia to exceed their thermal limit under system healthy conditions. It will also limit the generation capacity at Ankerlig to a maximum of four units under certain network contingencies. The scope of work includes the following: Installation of new generation units at Ankerlig PS site of a total generating capacity of approximately 100 MW to be used as Koeberg Second Supply in place of Acacia Power Station. This will be either 3 units of 30MW to 50 MW each or 4 units of 20MW to 30MW each, depending on offers from the market. The Power Station will be integrated by looping the current Koeberg Dassenberg 132 kv line into a new 132 kv High Voltage yard that is being constructed at the new power station. The portion of the line between the new power station and Koeberg power station will be refurbished to increase the reliability of the line. In order to maintain the integrity of the current off-site supply line, Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 113 of 131

114 Capital Expenditure allowance has been made to replace some off the insulators on the Koeberg Acacia 132kV line with 400kV insulators. d) Koeberg Steam Generator Replacement Project The replacement of the steam generators (SGs) for units 1 and 2 at Koeberg Nuclear Power Station: It has become the norm in the nuclear industry to replace steam generators that have Alloy 600 Mill Annealed tubing (Koeberg-type), rather than manage the risk associated with tube degradation. Steam generator replacement campaigns in American and French plants have commenced in the early 1980 s and these utilities plan to replace their last remaining Alloy 600 Mill Annealed steam generator by Due to the risks posed by these degraded components, Koeberg needs to replace its steam generators at the earliest opportunity. The steam generators were previously considered to be plant life-limiting components due to the cost of replacement. However, the latest international experience has demonstrated that SG replacement presents an opportunity to both extend the operating life of the units, and increase their power output through improved heat transfer capabilities. The changed thinking is based on the increased return on investment that operators around the world are realising as a result of the additional generating capacity. The long term asset management (LTAM) business case, is based on the above international experience, and has demonstrated the feasibility of the following strategies: Koeberg plant life extension from 40 to 60 years. Steam Generator Replacement which allows for the opportunity for thermal power uprate. Thermal Power uprate detailed feasibility study to confirm the 10% power uprate. The concept phase of the LTAM strategy highlighted the technical challenges which impact the operational lifespan of Koeberg. The most significant financial hurdle identified is the replacement of the steam generators. The replacement is driven by integrity concerns primarily related to stress corrosion cracking of the tubing and the resultant uncertainty associated with long-term operation. e) Battery Storage One of the conditions of the World Bank (WB) loan agreements concluded for the Medupi Power Station in 2010 was for Eskom to develop and implement a 100MW mid-merit Kiwano Concentrated Solar Power (CSP) plant to serve as a catalyst for further roll out of CSP and Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 114 of 131

115 Capital Expenditure other renewable energy technologies. Subsequently the 100 MW Kiwano CSP was included in the IRP 2013 as an allocation to Eskom for a demonstration plant. However, after embarking on a commercial process from November 2013 to obtain fixed and firm Engineering, Procurement and Construction (EPC) bid prices which concluded in February 2016, Eskom informed the WB via a letter dated 17 January 2017 that the chosen CSP technology was too expensive, risky and it intended to investigate an alternative project solution. The WB supported Eskom s request to select an alternative project solution to Kiwano CSP but affirmed that the alternative project should be renewable energy capacity of 100MW, offset the same carbon emissions, be commercially operated (COD) by December 2019 and be an innovation technology with the ability to transform the market to allow more renewables into the grid. Eskom proposed to the WB the Distributed Battery Storage with Distributed Solar Photo Voltaic (PV) project to be installed in its distribution networks and substations as the most suitable solution to meet the criteria set by the WB. The Distributed Battery Storage with Distributed Photo Voltaic (PV) project is currently in the development phase. The project will be implemented in 2 phases, namely, phase 1 of 800MWh per day by December 2019; phase 2 of 640MWh with 60MW of distributed PV by December The total battery storage capacity is therefore 1440MWh. The Distributed Battery Storage with Distributed Photo Voltaic (PV) project will directly contribute towards the following three (3) Eskom s strategic objectives: Ensure reliable supply of electricity to all South Africans. Securing adequate future electricity supply at the optimal cost of renewable energy for South Africa. Directly and indirectly supporting the socio-economic development objectives of South Africa. Further, it is imperative that Eskom complete this project as an alternative to CSP Kiwano due to the below mentioned WB and government agreements: WB conditions for implementing the phase one (1) of the distributed battery storage with distributed solar PV project, are that final draw down of the WB loan be achieved by December Failure to achieve the final draw down by the above mentioned date will mean Eskom will have to complete the project at its own cost. Failure for Eskom to not complete the project at all will be deemed that Eskom have dishonoured its loan agreement. Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 115 of 131

116 Capital Expenditure This will have a negative impact to Eskom and the country as a whole for future loan applications. Government guarantees provided to Eskom mean that on recall of the loan Government will have to pay the WB and its co-financiers the 3.5 Billion USD immediately. Eskom and government s reputation will be tarnished as they would be seen as not performing on its loan obligations. The scope of work is for the engineering designs, procurement, installation and commissioning of the Battery Energy Storage Systems (BESS) and its associated infrastructure at identified Distribution (Dx) sites including the Eskom Sere Wind farm site. The project is aimed at addressing current, voltage, frequency, capacity and other constraints on the Dx networks. The Battery storage solution for each of the identified Dx may also defer the capital requirements for network strengthening. Each solution is deemed to be unique in relation to the constraint identified in each Dx network. The methodology for network load profile analysis was used to evaluate the suitability of the Battery Storage solution for each Dx network. Investment approval for development cost (design release approval) was obtained in March 2018, allowing further development work to continue for the project. f) Medupi FGD The Medupi Power Station Flue Gas Desulfurization (FGD) Retrofit Project consists of the addition of FGD systems to six 800 megawatt (MW) coal fired steam electric generating units being constructed in Limpopo Province, approximately 15 kilometres (km) west of the town of Lephalale, South Africa. The FGD Project will result in the addition of wet limestone open spray tower FGD systems to each of the operating units and will be operational within six years following commercial operation of the respective generating units. Each of these units has been designed and is being constructed with provisions incorporated into the space and equipment design to accommodate the installation of wet limestone FGD systems. Each of the six FGD absorbers will treat the flue gas from one boiler; commercialgrade saleable gypsum will be produced as a by-product. A cluster of three absorbers will be located near each of the plant s two chimneys. Systems for makeup water, limestone preparation, FGD by-product (gypsum) dewatering and storage/disposal, and treatment of the wastewater stream will be common to all FGD absorbers in the plant Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 116 of 131

117 Capital Expenditure Capex cost elements Basic plant cost Basic plant cost refers to the basic plant cost estimate at a certain base date. Basic plant costs are further sub-divided into placed and unplaced packages, local and foreign component as well as fixed and variable components. No escalation is included in basic plant cost. Basic plant cost estimates for placed packages are as per the signed contracts. For unplaced packages, estimates are used and market quotations are obtained where possible. The accuracy of estimates for placed packages is at risk due to possible future contract modifications. The accuracy of estimates for unplaced packages is at risk due to the possible impact of changes in market conditions in relation to these estimates when the contracts are eventually placed. Frequent reviews of cost estimates and possible future modifications are used to mitigate this risk Contract price adjustments (CPA)/ Escalations Contract Price Adjustments/Escalations refer to the inflationary adjustments on the basic plant cost and are applicable to the variable portion of a contract or cost estimate. Contract Price Adjustments formulae and indices for placed packages are specified in the contract document e.g. SEIFSA Labour index, and are used to calculate these adjustments. For unplaced packages CPA estimates are based on the Eskom Economic planning parameters e.g. PPI, CPI etc. The accuracy of future index movements are the biggest risk for project CPA estimates. Eskom obtains an independent view on index forecasts on a quarterly basis. There will be continuous engagement with independent economists to continuously test the accuracy of the estimates until the end of the build programme Owners development cost (ODC) Owners Development Cost (ODC) refers to the internal Eskom resource costs that are allocated to the project i.e. Project management, Engineering, Quality assurance etc. It also includes cost directly related to the commissioning of a production unit i.e. commissioning staff, commissioning coal etc Contingency provision The contingency provision is a risk allowance for unknown future costs, the contingency is assumed based on the perceived risk in the project. Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 117 of 131

118 Capital Expenditure Interest during construction (IDC) Interest during construction refers to allocation of interest / borrowing cost to a project during the construction phase Environmental compliance The environmental clause in the Bill of Rights sets the context for environmental protection, providing for an environment which is not harmful to health and well-being and for ecological sustainable development. The National Environmental Act and several Strategic Environmental Management Acts (SEMA s) give effect to the environmental right in the Constitution. The development of environmental legislation has resulted in new and more stringent requirements which Eskom is obligated to respond to in order to continue operating its power stations. Given the nature of Eskom s activities these requirements are far reaching, they affect all the divisions and subsidiaries in some manner, including air quality, protection of the natural environment and biodiversity, water use and preventing pollution of water resources, general and hazardous waste management, the utilisation of ash and licensing processes. These legislative requirements are enforced through licences and permits. They lead to operational and capital expenses. To retain the licence to continue to operate, these expenses must be allowed for in the tariff, preferably in a manner which separates non-negotiable statutory requirements from refurbishment and maintenance expenses. The most significant environmental costs over the next 10 years are for air quality R67bn, air quality offset R4bn, ash dams/dumps R6bn and water management R6bn Air Quality Implementation Plan Minimum Emission Standards were published in 2010 in terms of the National Environmental Management: Air Quality Act, 2004 requiring facilities to comply with existing plant standards by 2015 and for existing plants to comply with new plant standards by There are three pollutants which Eskom is required to control; Sulphur dioxide, nitrogen oxide and particulate matter. Applying new plant standards to existing/aged plant is technically challenging, with only one technology, Flue Gas Desulphurisation (FGD) which can meet the regulated sulphur dioxide limits. FGD is very costly to install and will significantly increase both Capex and Opex requirements. Nitrogen oxide limits require the installation of low NOx burners and Particulate Matter limits require the installation of fabric filter bags or electrostatic precipitators (ESPs) and associated flue gas conditioning technologies. Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 118 of 131

119 Capital Expenditure Eskom is required to embark on a programme to implement the required pollution control technologies but due to the cost, water requirements and logistics to implement, has requested and been granted postponements for some plants in February Postponements are only valid for 5 years, in Eskom s case some are valid from and others from 2020 to Therefore, a second postponement application will be submitted to the Department of Environmental Affairs (DEA) in 2018/19. In parallel to the programme to reduce air emissions at coal fired power stations Eskom is required to embark on an air quality offset project in communities surrounding Eskom power stations. This project will reduce the most significant contributor to health impacts in low income communities. The offset project is a legal requirement enforced through the approval of the postponement application and as a condition of Atmospheric Emission Licences Eskom s emission reduction plan Logistically it was not possible for Eskom to implement a retrofit programme to meet the Minimum Emissions Standards by 2020; this was due to the long outages required, insufficient water to operate FGD and the impact on the tariff. Eskom decided it would be prudent to prioritise upgrades at higher emitting and newer power stations. Eskom submitted such an application for postponement for all coal-fired power stations (except Kusile Power Station) and Acacia and Port Rex Power Stations in The postponement applications included a commitment to upgrade certain power stations. The National Air Quality Officer approved most of these postponement requests in 2015 with an additional requirement for FGD at Matimba and Kendal power station. If required to be implemented, these retrofits would increase the cost from R67bn to R140bn Air Quality Offsets Eskom is required to implement air quality offsets as a condition of the approved Minimum Emission Standards postponements, and a condition of all Highveld power stations Atmospheric Emission Licences. Air quality offsets are designed to reduce human exposure to harmful levels of air pollution by reducing emissions from local sources, like domestic coal burning and waste burning. Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 119 of 131

120 Capital Expenditure FIGURE 36: OPPORTUNITIES FOR AIR QUALITY OFFSETS: REDUCING LOCAL WASTE BURNING (LEFT) OR DOMESTIC COAL BURNING (RIGHT) Eskom s air quality offset programme is intended to reduce emissions from coal/wood burning in Mpumalanga (through insulating houses and swopping existing coal stoves for LPG heaters and combined electric and LPG stoves), and from local waste burning in the Vaal. The offset programme has been informed by a desktop pre-feasibility study conducted in 2012/13, in which many options to reduce household emissions were evaluated, and two pilot studies conducted on 120 households in KwaZamokuhle, 17 km from Hendrina Power Station, over the winters of 2015 and Offsets need to be implemented on at least one settlement of reasonable size for each power station. Areas are prioritised based on the impact of emissions from the power station, but only areas where there is a potential for non-compliance with ambient air quality standards and where opportunities for improving ambient air quality through offsetting exist, are considered. Since air quality offsets have not been tested at scale yet, Eskom is proposing a phased approach to air quality offset implementation: Phase 1 ( ): Lead implementations at one Eskom-impacted community per district municipality. The logistics required to implement offsets on the scale of a whole settlement will be tested. Housing insulation and LPG devices will be distributed in KwaZamokuhle (next to Hendrina) and Ezamokuhle (next to Amersfoort), and interventions to reduce waste burning will be rolled out in Sharpeville. Phase 2 ( ): Full implementation. Once the interventions have been refined, they will be rolled out simultaneously at at least one community per power station. Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 120 of 131

121 Capital Expenditure The offset programme will cost an estimated R4bn between now and Around households will receive cleaner energy and/or insulation, and many more will be indirectly affected through community interventions. The successful implementation of air quality offsets promises to meaningfully improve the air quality of the air breathed by thousands of people, and should improve the health and create employment opportunities for many Ash dam/dump extensions Ash dams and dumps are a key component in the generation of electricity. Without an ashing facility the power station cannot continue to operate. Eskom produces approximately 30 million tonnes of ash annually, six to eight percent of which is recycled. Tthe remaining ash is sent from the power station and disposed of in an ash dam or dump. In terms of the National Environment Management Waste Act (NEMWA), ash is classified as a hazardous waste. Prior to the promulgation of the Act there was no requirement for a Waste Management Licence (WML) for ashing facilities. However, the extension of ashing facilities beyond their original planned ashing footprint triggered the requirement for a WML which in turn triggered the requirement for lining the ashing facilities. Since Eskom was not able to install the lining immediately on dry ashing facilities, the DEA, at Eskom s request, granted an exemption to install the lining within four/five years of receiving the WML for the following power stations: Tutuka (Dec 2019), Majuba (Feb 2020), Kendal (May 2020) and Matimba (Feb 2022). It is important to note that the budget allocated to these projects is not only for lining, it is also to ensure the continued safe and efficient operation of the ashing facilities. Furthermore, if the liner is not installed by the said dates, then operations will have to be stopped as these will be impacted by licence to operate conditions. The estimated cost for the ash dam extensions between 2018 and 2020 is R6.2bn and for the next 10 years up to 2026 is R12.5bn Water management Eskom is one of the largest consumers of fresh water in South Africa, accounting for approximately 2-3% of the country s total water consumption annually. The reliability of water infrastructure and the availability and quality of water have a significant impact on Eskom s ability to produce electricity and to use water efficiently. In terms of the National Water Act 36 of 1998 and the National Water Resource Strategy 2, Eskom is required to use water efficiently, to comply with licence conditions and ensure that our activities do not cause or potentially lead to pollution of water resources. This Eskom Water Strategy was developed to set the direction on water-related issues and address compliance. The strategy outlines the key activities required to ensure efficiency Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 121 of 131

122 Capital Expenditure and compliance, these include the lining of all dirty water dams, design and construction of separate dirty and clean water systems, the installation/upgrade of water treatment plants. The total cost to ensure compliance with power station Water Use Licences is estimated at R6bn. 8.3 Generation Technical Plan Projects Overview of the life of plant plan (LOPP) for a power station Every station has an unconstrained LOPP to address refurbishment, replacement and compliance requirements to sustain the plant throughout its lifespan. The 10 year, 5 year and 1 year plans are produced from the LOPP. The age based replacement required for LOPP is refined with condition and risk assessments in annual plant strategy documents produced by Engineering. Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 122 of 131

123 Capital Expenditure TABLE 44: EXAMPLES OF REFURBISHMENT/REPLACEMNT INTERVALS Examples of refurbishment or replacement intervals Component Interval Gen-Transformer Smaller Transformer Insights on failure and refurbishment The health of the transformers is determined by condition monitoring analysis of oil/gas The health of the transformers is determined by condition monitoring analysis of oil/gas C&I migration 15-May Computers become obsolete after 5 years Generator rewind 35 Due to insulation breakdown Turbine rotor replacement 40 Cracks can no longer be managed through maintenance Condenser re-tubing Replacement once in the life (30 years) once they have been rewound at least 3 times Large motors 30 HP piping Once in the life once they have been rewound at least 3 times Must be replaced once it shows signs of needing major replacements TechPlan Capex The LOPP Capex requirements are prioritised based on evolving requirements and conditions as well as implement-ability and expectation of available funding to determine Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 123 of 131

124 Capital Expenditure priority projects. This results in the Technical Plan (TechPlan) Capex requirement as shown in the table below. Almost all TechPlan Capex has been removed for Hendrina, Komati and Grootvlei which is consistent with the assumption that they will not be required for most of the MYPD 4 period and will thus be placed in reserve storage. Capex for Camden has been reduced, but not entirely. This is due to the assumption that the station will be required post MYPD 4 and there is thus a higher probability that it may be required if the assumptions in the Production Plan don t eventuate. These amounts are thus a risk mitigation as well as a proxy for unforeseen Capex requirements throughout the fleet. 8.4 Outage Capex Eskom has a codified preventive maintenance strategy in place for each Power Station. FIGURE 37: CODIFIED ASSET MANAGEMENT STRATEGY FOR GENERATION Overview of outage maintenance strategy There are numerous cyclical maintenance interventions required on a power plant. If an activity is required at least twice in the life of a station and will require plant shutdown, the Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 124 of 131

125 Capital Expenditure implications are required to be documented in a document called the outage philosophy. All stations have specific requirements but generic rules exist: General Overhaul (GO): Every years plant shutdown to do inspection and repair of turbine & generator. Mini GO: Every 5-6 years inspection of low pressure turbines, and statutory pressure test. Interim Repair (IR): monthly plant is shutdown to inspect and repair the boiler components. Boiler Inspection (IN): Between IR s an inspection is carried out to review condition of the boiler and scope the next outage. Opportunity maintenance frequently leads to the above schedule being modified which gives rise to adaptions of the sequence, but every effort is made to recover the sequence to ensure plant safety and operability Prioritisation of outages: Immediate safety risk as per ERAP inclusive of any emerging technical threat which is deemed to pose significant personnel or plant risk. Statutory such as pressure tests. Licence to operate risks such as major contraventions of legislation. Reliability scope is included in the outages based on the durations available Capacity planning The objective is to ensure that there is enough capacity to meet the demand and operating reserves whilst performing required maintenance. Plant on maintenance The Capacity Plan illustrates, on a daily basis (at peak), the ability to meet the demand, considering planned and unplanned maintenance, and required operating reserves. Eskom Holdings MYPD 4 Revenue Application FY2019/ /22 Page 125 of 131