MYPD 3: Regulatory Clearing Account Submission to NERSA FY2017/18, Year 5 of MYPD 3 Period September 2018
Contents Contents Contents... 2 Preface... 8 1.1 The basis of submissions...8 1.2 The structure of 2017/18 RCA Submission...9 2 Objective... 11 3 Overview of the 2017/18 RCA Submission... 12 3.1 Revenue... 13 3.2 Primary energy... 13 3.3 Environmental levy... 13 3.4 Phased nuclear decommissioning provision per MYPD3 RCA 2013/14 decision... 14 3.5 Capital expenditure variance... 14 3.6 Operating costs... 14 3.7 Energy Effiiciency and Demand Side Management (EEDSM)... 14 3.8 Other income... 15 3.9 Inflation adjustments... 15 3.10 Service Quality Incentives (SQI)... 15 3.11 Trend analysis of MYPD3 RCAs... 15 3.12 Conclusion... 17 4 Factors impacting 2017/18 RCA Submission... 18 4.1 Timeline for application and decision... 18 4.2 Changes in fundamental assumptions since MYPD3 application... 19 5 Revenue Variance... 20 5.1 MYPD Methodology... 20 5.2 Revenue computed on an equivalent basis... 21 5.3 Allowed Revenue... 23 5.4 Sales volumes contribute to recovery of fixed costs... 23 5.5 Allowed vs Actuals volumes... 26 5.6 Sales volume variance explanation... 27 5.6.1 The process in deriving the 5 year forecast... 29 5.6.2 Critical changes in assumptions relevant during 2011 in deriving forecasts... 29 5.6.3 Sales volume variance explanation for FY2017/18... 30 5.7 Energy Conservation Scheme (ECS) offsets revenue variance... 37 5.7.1 Using the fixed portion of the tariff... 40 5.7.2 ECS measurement system and calculations... 40 5.7.3 Further Revenue variance due to ECS... 41 5.8 Conclusion on the sales volume and revenue variance... 42 RCA Year 5 (FY 2017/18) September 2018 Page 2 of 121
Contents 6 Impact of demand responses on sales volumes... 43 7 Collectability of revenue does not impact RCA... 44 8 Prudency and Efficiency... 45 9 Factors which influence Eskom production plans... 46 10 Primary energy... 47 10.1 Primary energy variances and RCA impact for 2017/18... 47 10.2 Independent Power Producers... 49 10.3 Legal basis for IPPs per the MYPD Methodology... 50 10.4 IPP Approvals... 50 10.5 Regulatory rules for power purchase cost recovery... 51 10.6 Allowed vs Actual IPP costs for 2017/18... 51 10.6.1 Reasons for IPP variances in 2017/18... 52 11 International purchases... 54 11.1 Cross-border sales and purchases of electricity... 54 12 Coal Burn Costs... 56 12.1 Extract of MYPD Methodology on Coal adjustments... 56 12.2 NERSA s decision on coal benchmark and alpha... 57 12.2.1 Benchmark Average Cost... 57 12.2.2 Coal Burn Costs... 58 12.3 RCA 2018 calculation... 59 12.3.1 Step 1 Calculate the performance base regulation cost allowance... 59 12.3.2 Step 2 Calculate the pass through coal burn costs... 59 12.3.3 Step 3 Split the pass through coal burn cost into volume variance and price variance as summarised below.... 60 12.4 Coal burn cost variance explanations... 61 12.5 Coal purchases... 62 12.5.1 Long term fixed price contracts... 62 12.5.2 Cost plus contracts... 62 12.6 Mode of Transport... 65 12.7 Medupi net coal obligation... 66 13 Other Primary energy... 67 13.1 Allowed other primary energy in 2017/18... 67 13.1.1 Allowed other primary energy costs... 67 13.1.2 Variances in other primary energy... 67 13.1.3 Reasons for start-up gas and oil costs variance... 68 13.1.4 Reasons for coal handling costs variance... 68 13.1.5 Reasons for water costs variance... 69 13.1.6 Reasons for fuel procurement costs variance... 72 13.1.7 Water treatment costs variance... 73 13.1.8 Nuclear costs variance... 73 13.1.9 Sorbent costs variance... 74 14 Environmental levy... 75 RCA Year 5 (FY 2017/18) September 2018 Page 3 of 121
Contents 15 Demand Market Participation... 76 15.1 Allowed DMP... 76 15.1.1 Actual DMP... 76 16 Open cycle gas turbines (OCGTs)... 78 16.1 Allowed OCGT spend... 78 16.1.1 Managing supply-and demand constraints... 79 16.1.2 Actual Plant performance in 2017/18... 80 17 Capital expenditure clearing account (CECA)... 82 17.1 Regulated asset base adjustment for CECA... 82 17.1.1 Step 1: Computing the qualifying RAB capital expenditure variance... 82 17.1.2 Step 2: Computing the CECA... 84 17.2 MYPD3 decision... 85 17.3 Reasons for new build higher expenditures... 85 17.3.1 Medupi... 85 17.3.2 Kusile... 86 17.3.3 Kusile Temporary Coal infrastructure... 87 17.3.4 Ingula Pumped Storage Project... 87 17.4 Owners Development Cost, Contingency and Unplaced Contracts... 88 17.4.1 Owners Development Cost... 88 17.4.2 Contingency... 88 17.4.3 Unplaced contracts... 88 17.5 Actual Capital Expenditure... 89 18 Inflation adjustment... 90 19 Energy efficiency and demand side management (EEDSM)... 92 19.1 Actual EEDSM... 92 19.2 Extracts from the MYPD Methodology... 93 19.2.1 Allowed EEDSM for 2017/18... 93 20 Operating costs... 95 20.1 Allowed operating costs in 2017/18... 95 Note 1: Allowed employee benefits... 96 20.2 Allowed vs Actual operating costs... 98 20.3 Variances in operating costs... 98 20.3.1 Employee benefits... 98 20.3.2 Maintenance... 99 20.3.3 Arrear debt... 99 20.4 Other Income... 99 20.4.1 Actual other income in 2017/18... 99 20.4.2 Principles for treatment of other income in the RCA... 100 20.5 Based on the precedent above, other income does not qualify for inclusion in the RCA operating cost variance for 2017/18 RCA... 100 21 Service Quality Incentives... 101 21.1 Transmission service quality incentives (SQI) for 2017/18... 101 21.2 Distribution Service Quality Incentive Scheme (SQI) for 2017/18... 103 RCA Year 5 (FY 2017/18) September 2018 Page 4 of 121
Contents 22 Reasonability tests... 105 22.1 EBITDA-To-Interest Cover Ratio (EBITDA / Interest Payments)... 105 23 Conclusion... 106 Annexures:... 107 Annexure 1: Income Statement in AFS 2018, page 23... 107 Annexure 2: The Eskom energy wheel (Eskom Intergrated Report)... 108 Annexure 3:Sales volumes GWh Statistical tables for 2017/18... 109 Annexure 4 : Electricity Revenue by Customer category Intergrated Report 2017/18... 110 Annexure 4: Finance income note 40 and Finance cost note 41 (Extracts AFS March 2018, page 91)111 Annexure 5: OPEX note 38 extract from AFS March 2018 page 90... 112 1 Abbreviations... 113 2 Glossary and Terms... 117 List of Tables: Table 1: Summary of 2017/18 RCA Submission... 12 Table 2: RCA Trend Analysis OVER MYPD3 PERIOD... 15 Table 3: Key assumptions which have changed... 19 Table 4 : Calculation of MYPD3 revenue variance for 2017/18... 20 Table 5 : Reconciliation of AFS revenue to RCA revenue... 21 Table 6: Revenue note from AFS for March 2018... 22 Table 7 : Sales volume variance... 26 Table 8: Approved Sales Volumes forecast, mypd3... 27 Table 9: MYPD3 Sales volume... 28 Table 10: MYPD3 Sales volume... 28 Table 11 : GDP forecasts used for MYPD3 in 2011... 29 Table 12: Commodity Prices assumed... 30 Table 13 : Sales volume variance... 30 Table 14 : Commodity prices... 33 Table 15: Commodity Prices assumed... 39 Table 16: Energy conservation scheme consumption summary... 41 Table 17 : Total primary energy comparison and RCA impact for 2017/18... 48 Table 18: Primary energy actual costs per note 34 in the AFS of 2018... 49 Table 19: IPPs costs and volumes... 52 Table 20: International purchases... 54 Table 21 : Cross border sales and purchases... 55 Table 22: NERSA s decision on coal benchmark and alpha... 57 Table 23: The coal burn breakdown for the RCA... 60 Table 24: MYPD 3 Assumptions vs. Actual 2017/18... 61 RCA Year 5 (FY 2017/18) September 2018 Page 5 of 121
Contents Table 25: Coal Transport (ktons)... 65 Table 26: Other Primary Energy... 68 Table 27 : Water consumption PER GWH per power station... 71 Table 28 : Water consumption per power station... 71 Table 29: Nuclear fuel costs 2017/18... 73 Table 30: DMP comparison for RCA... 76 Table 31: OCGT spend AND USAGE... 78 Table 32: Calculation average capital expenditure... 83 Table 33: CECA Calculation: Return due to/ (by) Eskom... 84 Table 34: Regulatory asset base for 2017/18... 85 Table 35: Returns and percentage allowed in 2017/18... 85 Table 36: Capital expenditure in 2017/18... 85 Table 37: Reconciliation of capex from the integrated report to CECA disclosures... 89 Table 38: Capital expenditure (excluding capitalised borrowing costs) per LICENSEE... 89 Table 39: Inflation Data... 90 Table 40 : Inflation adjustment... 90 Table 41: demand and energy savings as per table 1 and table 2 in THE IDM Annual report for FY2018... 93 Table 42: The allowed EEDSM costs... 94 Table 43: EEDSM comparison for RCA in 2017/18... 94 Table 44: Total Operating Cost Allowed... 95 Table 45: Employee benefits are reconciled as follows... 96 Table 46: The allowed employee costs for Generation, Transmission and Distribution... 96 Table 47: Allowed Corporate Costs in 2017/18... 96 Table 48: The depreciation per annum is reflected in the table below.... 97 Table 49: Allowed Maintenance Costs... 97 Table 50: Other costs... 97 Table 51: Allowed Arrear Debts... 97 Table 52: Allowed Cost of Cover... 97 Table 53: Summary of Operating costs in 2017/18... 98 Table 54: Trend in gross employee benefits... 99 Table 55 : Other income for 2017/18... 100 Table 56: Trends in networks performance... 101 Table 57 : Summary of SQI performance in 2017/18... 101 Table 58: Transmission SQI performance in 2017/18... 102 Table 59: Transmission number of major incidents (>1SM)... 103 Table 60: Distribution SQI performance in 2017/18... 104 Table 61: EBITDA Cover... 105 List of Figures: Figure 1: Time lag between application and actuals... 18 RCA Year 5 (FY 2017/18) September 2018 Page 6 of 121
Contents Figure 2 : Performance of Municipalities... 32 Figure 3 : Performance of Ferro Smelters... 34 Figure 4: Performance of iron and steel smelters... 34 Figure 5: Performance of mining sector... 35 Figure 6: Performance of platimun sector... 36 Figure 7: Performance of gold sector... 36 Figure 8: Production FY2018... 46 Figure 9: Transmission system minutes (<1)... 102 Figure 10: Line faults /100km... 103 Figure 11: EBITDA-To-Interest Cover Ratio... 105 RCA Year 5 (FY 2017/18) September 2018 Page 7 of 121
Preface Preface This document summarises information submitted by Eskom Holdings (SOC) Ltd to the National Energy Regulator of South Africa pertaining to the Eskom s Regulatory Clearing Account (RCA) balance for the year 2017/18 in accordance with the Multi-Year Price Determination Methodology published during December 2012. This document contains the following: 1. Information provided in regard to Eskom s 2017/18 RCA balance (hereafter referred to as the 2017/18 RCA Submission or year 5 of MYPD3) is lodged in accordance with section 14.2.1 of the MYPD Methodology. 2. Information is supported by Eskom s 2017/18 audited annual financial statements 3. Information is supported by NERSA s RCA 2013/14 reasons for decision published on 29 March 2016 4. Information is supported by aspects of the RCA submission for the 2014/15, 2015/16 and 2016/17 financial years. The balance decisions on these RCA submissions were made on 14 June 2018. The reasons for decision were not published by the time of this submission and therefore could not have been considered. 1.1 The basis of submissions The basis of this submission is derived primarily from section 14 of the MYPD Methodology (published December 2012) which provides for a Risk Management Device (S. 14.1) administered by way of the RCA (S. 14.2) i.e.: 14.1 The risk of excess or inadequate revenues is managed in terms of the RCA. The RCA is an account in which all potential adjustments to Eskom s allowed revenue which has been approved by the Energy Regulator is accumulated and is managed as follows: 14.1.1 The nominal estimates of the regulated entity will be managed by adjusting for changes in the inflation rate. 14.1.2 Allowing the pass-through of prudently incurred primary energy costs as per Section 8 of the MYPD Methodology. 14.1.3 Adjusting capital expenditure forecasts for cost and timing variances as per Section 6 of the MYPD Methodology. RCA Year 5 (FY 2017/18) September 2018 Page 8 of 121
Preface 14.1.4 Adjusting for prudently incurred under-expenditure on controllable operating costs as may be determined by the Energy Regulator. 14.1.5 Adjusting for other costs and revenue variances where the variance of total actual revenue differs from the total allowed revenue. In addition, a last resort mechanism is put in place to trigger a re-opener of the price determination when there are significant variances in the assumptions made in the price determination. The RCA is part of the overall MYPD Methodology, where section 14.1 confirms that the RCA is intended to mitigate and manage the risk of excess or inadequate returns, and further that it does so by adjusting regulated revenue. Section 14 further sets out that the costs and cost variances (to be recovered through such revenue adjustment) will be assessed for prudency. 1.2 The structure of 2017/18 RCA Submission The structure of the summary of 2017/18 RCA Submission provided in this document is guided by the MYPD Methodology. With this in mind, an overview of the 2017/18 RCA submission is first provided summarising the RCA inputs and balances as calculated by Eskom. This is followed by individual sections covering each of the RCA components as indicated in sections 14.1, 8 and 9 of the MYPD Methodology. The format of the summary of submission is as outlined below. Summary of RCA Submission I. Overview of the RCA Submission (Section 3) II. Components of the RCA balance account (Section 3.1-3.12) III. Revenue Variances (Section 5) IV. Purchases from Independant Power Producers (Section 10) V. Primary Energy - International Purchases (Section 11) VI. Primary Energy - Coal Costs (Section 12) VII. Primary Energy Other costs (Section 13) VIII. Primary Energy - Gas Turbine Generation Cost (Section 16) IX. Capital Expenditure and Regulatory Asset Base (Section 17) X. Operating Costs (Section 20) XI. Service Quality Incentives (Section 21) RCA Year 5 (FY 2017/18) September 2018 Page 9 of 121
Preface Eskom has provided reconciliations and reasons for variances between actual results and the MYPD3 decision. Thereafter the variances are applied to the MYPD Methodology to determine the amount of the respective components which qualify for the RCA balance. The 2017/18 RCA Submission concludes with reasonableness tests such as EBITDA to interest cover ratio being assessed. RCA Year 5 (FY 2017/18) September 2018 Page 10 of 121
Objective 2 Objective The objective of this 2017/18 RCA Submission is to provide the context for the Regulatory Clearing Account (RCA) process in terms of NERSA s MYPD Methodology requirements. The 2017/18 RCA Submission for the fifth year of the MYPD 3 period provides reasons for variances between actual results and the assumptions as made for purposes of the MYPD3 revenue decision. This submission is based on the MYPD Methodology, as published by NERSA during December 2012. It is further influenced by the MYPD3 RCA 2013/14 reasons for decision published by NERSA on 29 March 2016 and the Eskom RCA submissions for the 2014/15, 2015/16 and 2016/17 financial years. It is clarified that the reasons for decision of the subsequent RCA decisions made on 14 June 2018 were not published before this RCA submission was made. The RCA process has two steps: 1. The decision on the RCA balance that is due to Eskom or the consumer, and 2. The RCA balance decision will then be subject to an implementation decision guiding subsequent adjustments in tariffs. In summary the RCA mechanism allows Eskom the opportunity to achieve the initial revenue that was allowed during the MYPD3 revenue decision and to increase/decrease the allowed revenue due to changes in assumptions or costs that are subject to remeasurement as outlined in the MYPD Methodology. RCA Year 5 (FY 2017/18) September 2018 Page 11 of 121
Overview of the 2017/18 RCA Submission 3 Overview of the 2017/18 RCA Submission Eskom s 2017/18 RCA Submission is driven substantially by revenue under-recovery due to lower actual sales than that determined by NERSA for the 5 th year of the MYPD 3 period. Cost variances related mainly to primary energy costs off-set the revenue variance related to sales. The determined RCA application of R21 541 million is motivated with facts and evidence to enable prudency assessments by NERSA. The R21 541 million is then increased by the R83million relating to the phasing in of the nuclear decommissioning provision from the 2013/14 RCA decision resulting in a total RCA claim for liquidation purposes of R21 624 million. TABLE 1: SUMMARY OF 2017/18 RCA SUBMISSION RCA for 2017/18 (Year 5 of MYPD3) MYPD3 Decision Actuals 2017/18 Variance to MYPD3 RCA adjustments RCA 2017/18 Total Revenue R million 205 213 175 041 30 172-3 277 26 895 Primary Energy, R million Coal 49 914 46 992-2 922-15 -2 937 Open Cycle Gas Turbines (OCGTs) 1 724 328-1 396-1 396 Other primary energy 6 766 7 576 810-810 Independent Power Producers 23 018 19 317-3 701 1 983-1 718 International Purchases 470 2 768 2 298 2 298 Environmental levy 9 746 8 061-1 685-1 685 Demand Market Participation (DMP) - 160 160 160 Total primary energy, R million 91 638 85 202-6 436 1 968-4 468 CECA for RCA, R million 33 667 34 592 925 0 925 EEDSM for RCA, R million 1 244 142-1 102-17 -1 118 Operating costs for RCA, R million 47 764 51 892 4 128-4 128 - SQI for RCA, R million 390 390 Inflation adjustments, R million 39 39 ECS (Electricity conservation scheme) adjustment -1 122-1 122 FY2018 RCA application for year 21 541 Nuclear decommissioning from RCA 2013/14 decision phased in over 10 years for liquidation FY2018 Liquidation claim, R million 21 624 83 Note 1 Revenue variance of R30 172 in Annual Financial Statements (AFS) is adjusted by R 3 777 for revenue not collected for a RCA revenue adjustment of R26 895. Thus RCA includes all billed revenue (not collected revenue as in AFS) RCA Year 5 (FY 2017/18) September 2018 Page 12 of 121
Overview of the 2017/18 RCA Submission Note 2- OCGT IPP adjustment is due to different treatment of capacity charge for RCA balance where capacity charge is recovered in year expenditure is made, AFS requires capitalisation over term of PPA Note 3 - Operating costs over expenditure are not allowed to be claimed as part of the RCA in terms of current MYPD Methodology Note 4 The ECS adjustment is related to a reduction in the revenue variance related to possible reduction in sales due to Eskom requesting certain customers to reduce consumption to assist when constraints in the system were experienced prior to the MYPD 3 period. 3.1 Revenue Electricity sales volumes continue to remain lower than that assumed by NERSA in the MYPD 3 decision. This is a continual trend from the previous years of the MYPD 3 period. The revenue variance of R26 895 million is calculated on Eskom s electricity revenue to all customers and is due to lower electricity sales volumes. No load interruptions occurred during the 2017/18 financial years. 3.2 Primary energy During the year lower production levels, the introduction of new generation capacity, and the slight improvement in power stations availability contributed to Eskom meeting demand requirements. This resulted in minimal utilisation of OCGTs resulting in lower spend when compared to the MYPD3 decision. Total primary costs incurred in 2017/18 was R85 210 million which was lower than the MYPD3 decision of R91 638 million by R4 468 million. This application includes variances in favour of the consumer for coal burn costs of R2 937 million, OCGT costs of R1 396 million and IPP costs of R1 718 million. Variances in favour of Eskom include revenue related to international purchases R2 298 million, demand market participation (DMP) costs of R160 million and other primary energy costs of R810 million. 3.3 Environmental levy The lower production volumes and the change in production mix resulted in Eskom incurring environmental levy costs of R 1 685 million lower than the assumption made in the MYPD3 determination. The RCA caters for taxes and levies as a pass through item which requires that under expenditures are for the benefit of consumers in the RCA calculation. RCA Year 5 (FY 2017/18) September 2018 Page 13 of 121
Overview of the 2017/18 RCA Submission 3.4 Phased nuclear decommissioning provision per MYPD3 RCA 2013/14 decision In its 2013/14 RCA decision, NERSA has required Eskom to include the nuclear decommissioning provision of R830 million, over a period of 10 years, in equal installments of R83 million via future RCA liquidations. The first tranche of R83 million was granted in the RCA 2013/14 decision. Applications of further tranches were made in each of the 2 nd, 3 rd and 4 th years of the MYPD 3 period. Thus this application represents another installment of the already approved amount. 3.5 Capital expenditure variance Eskom Company capital expenditure of R47 527 million exceeded the NERSA decision of R45 407 million by R2 119 million in 2017/18. The variance is attributable to higher costs incurred for new build projects, outage capital costs and partially reduced by lower expenditures incurred for the Transmission and Distribution networks; following Eskom s capital expenditure reprioritisation process. The technical and refurbishment capital expenditure is excluded when computing the balance for RCA purposes. For RCA purpose the capital expenditure clearing account (CECA) adjustment is R925 million in favour of Eskom. 3.6 Operating costs The Methodology requires that prudently incurred under expenditure on controllable operating costs is paid back to consumers. However, when the situation is reversed the Methodology does not allow for prudently incurred overspend to be included in the RCA. During 2017/18 the operating costs expenditure of R51 892 million exceeds the decision of R47 764 million by R4 128 million and hence does not qualify for inclusion in the RCA balance. This implies that Eskom absorbs the over expenditure even though costs may have been prudently incurred in delivering electricity. The RCA Methodology allows for the impact of changes in inflation. The actual inflation was higher than the decision resulting in R39 million in favour of Eskom. 3.7 Energy Effiiciency and Demand Side Management (EEDSM) Eskom s energy efficiency and demand side management (EEDSM) programs produced less verified capacity (in MW) savings during the year, than determined by NERSA, resulting in a R1 118 million variance in favour of the consumer. RCA Year 5 (FY 2017/18) September 2018 Page 14 of 121
Overview of the 2017/18 RCA Submission 3.8 Other income Other income is included under the operating costs section. 3.9 Inflation adjustments Section 14.1.1 of the MYPD Methodology states that The nominal estimates of the regulated entity will be managed by adjusting for changes in the inflation rate. Inflation adjustments on operating costs amount to R39 million in favour of Eskom. 3.10 Service Quality Incentives (SQI) Eskom has achieved the service quality incentive targets set by NERSA for Distribution and Transmission during 2017/18. This resulted in Distribution achieving an SQI of R292.8 million and Transmission of R99.7 million, equating to a total of R390.5 million. 3.11 Trend analysis of MYPD3 RCAs The value of RCA submissions over the MYPD3 period is been approximately R20 billion per annum as summarized in the table below. TABLE 2: RCA TREND ANALYSIS OVER MYPD3 PERIOD MYPD3 RCA's Decision RCA 2013/14 Application RCA 2014/15 Application RCA 2015/16 Application RCA 2016/17 Application RCA 2017/18 Revenue 6 175 8 787 15 578 20 017 26 895 Coal 2 000 574 3 258-359 -2 937 Open Cycle Gas Turbines (OCGTs) 1 252 1 944 689-1 259-1 396 Other primary energy 72 1 026 489 516 810 Independent Power Producers 580 4 346 620 2 451-1 718 International purchases 2 700 3 299 3 567 2 282 2 298 Environmental levy -312-683 -1 180-1 404-1 685 Demand response (DR) -905-379 248 194 160 Capital Expenditure Clearing Account (CECA) Energy Efficiency & demand Side Management (EEDSM) 9 91 332 636 925-432 -149-368 - -1 118 Other income -353-528 -134 - - RCA Year 5 (FY 2017/18) September 2018 Page 15 of 121
Overview of the 2017/18 RCA Submission Service Quality Incentives (SQI) 339 236 318 343 390 Inflation adjustment - Opex 33 209-152 162 39 ECS (Electricity conservation scheme) Nuclear decommissioning of R830m from RCA 2013/14 decision phased in over 10 years - -1 113-1 294-1 453-1 122 83 83 83 83 83 RCA application for the year 17 743 22 054 22 209 21 541 RCA decision 11 241 12 577 12 058 8 055 * Application RCAs for 2014/15, 2015/16 and 2016/17 refer to applications as revised after public hearings Eskom applied for a total RCA balance of R66.7 billion (year 2 - R19.2 billion, year 3 - R23.6 billion and year 4 - R23.9 billion) during May 2016, July 2016 and July 2017 respectively. These were revised after the public hearings held during April and May 2018 to R62bn (year 2 R17.7billion, year 3 R22.1billion and year 4 22.2billion) The Energy Regulator published Eskom s RCA applications and sought written comments from stakeholders from 22 nd January to 23 rd March 2018. Public hearings were conducted in all nine of South Africa s provinces between 16 th April and 14 th May 2018 to afford interested and affected stakeholders the opportunity to present their views, facts and evidence. On 14 th June 2018, the Energy Regulator approved a total RCA balance of R32.69 billion, as follows: RCA balance of R12.577 billion for the 2014/15 financial year; RCA balance of R12.058 billion for the 2015/16 financial year; and RCA balance of R8.055 billion for the 2016/17 financial year. At the time of this submission, the reasons for the RCA decision have not been published by NERSA. Eskom is awaiting this. NERSA has communicated that an implementation plan for the RCA balance of year 2 (2014/15), year 3 (2015/16) and year 4 (2016/17) of the MYPD3 will be developed for approval by the Energy Regulator by 30 September 2018. It is envisaged that this will outline the recovery of RCA balance in a phased manner over subsequent tariff adjustments. This will be in addition to the MYPD 4 tariff application that is being made for a three year period (2019/20 to 2021/22). RCA Year 5 (FY 2017/18) September 2018 Page 16 of 121
Overview of the 2017/18 RCA Submission 3.12 Conclusion The key variance in this RCA application for the 5 th year of the MYPD 3 period is due to sales volume variances. This is a continuing trend from the first year of the MYPD 3 period. The revenue related to applicable cost areas off-set the revenue variance due to sales variances. RCA Year 5 (FY 2017/18) September 2018 Page 17 of 121
Factors impacting 2017/18 RCA Submission 4 Factors impacting 2017/18 RCA Submission 4.1 Timeline for application and decision The time lapse between Eskom preparing for the MYPD3 revenue application and its actual implementation date is at least 15 months. Taking into account that the MYPD3 is a 5 year decision it will potentially equate to a 75 month period in which many of the initial assumptions, policies, environmental and economic conditions will change. Thus the RCA mechanism will address the impact of these changes in assumptions made for the purpose of the revenue decision, compared to how it has unfolded in the actual mode. FIGURE 1: TIME LAG BETWEEN APPLICATION AND ACTUALS 13 Months 15 Months 27 Months 39 Months 51 Months 63 Months 75 Months Eskom MYPD3 Application Preparation (January 2012) Eskom Submitted (November 2012) MYPD3 Decision (February 2013) Apr-13 Apr-14 Apr-15 Apr-16 Apr-17 Apr-18 5 Year MYPD3 Window RCA Year 5 (FY 2017/18) September 2018 Page 18 of 121
Factors impacting 2017/18 RCA Submission 4.2 Changes in fundamental assumptions since MYPD3 application TABLE 3: KEY ASSUMPTIONS WHICH HAVE CHANGED MYPD3 Application Current Situation Comment Sales forecast average growth of 2% p.a. assumed with a starting value of 222TWh in March 2013 reaching 244 TWh by March 2018 Actual sales reached 212TWh by March 2018. Generation plant performance (Energy availability factor EAF) assumed at an average 82% for 2017/18 New build commission dates for 1 st units Medupi June 2013 Kusile - 2016/17 Ingula 2013/14 Sere 2013/14 Coal country compact < 10%price increases Actual average EAF was an average of 78% for the year New build commissioning revised dates as follows: Medupi Unit6 Aug 2015 Medupi Unit5 Apr 2017 Medupi Unit 4 Nov 2017 Kusile Unit 1- Sept 2017 Ingula All units commissioned by Mar 2017 Sere 31 Mar 2015 Efficiency savings implemented through business productivity programme and design to cost initiatives. Sales forecast did not materialise due to major changes in the assumptions plus the adverse global economic situation not recovering as anticipated Actual plant performance has been improving over the year. However, has not reached the performance level assumed by NERSA in the MYPD 3 decision. Eskom has been meeting its revised commissioning dates. Coal burn escalations dropped significantly in 2017/18 compared to historical trends. In fact coal burn variance is in favour of the consumer. OCGTs load factors assumed at 3% based on certain other assumptions materialising IPPs local and international Capex R337bn over the five year period OCGTs actual load factors have been <1% in 2017/18 Lower costs associated with REIPP programmes Capex given the lower revenue decision, Eskom reprioritized capex to a projected portfolio of R251bn over the five year period. OCGTs usage reflects a turnaround with a significant variance for the benefit of the consumer. Certain REIPP programmes did not mateialise, as anticipated. In response to MYPD3 revenue decision Eskom has reprioritised capex spent RCA Year 5 (FY 2017/18) September 2018 Page 19 of 121
Revenue Variance 5 Revenue Variance The objective of this section is to demonstrate and explain the revenue variance. It will provide reconciliation between the revenue disclosed in the 2017/18 Eskom annual financial statement (AFS) and the actual revenue to be used for RCA purposes to ensure the same reference point is used. In addition, it will explain why non-electricity revenue is excluded in the revenue variance calculation for RCA purposes. 5.1 MYPD Methodology The regulatory clearing account (RCA) balance is calculated by determining the variances which arise by comparing the NERSA MYPD3 decision to the Eskom actuals for particular revenues and costs as provided for in the Methodology. The calculation of the revenue variance to be included in the RCA is in terms of paragraph 14.1.5 of the MYPD Methodology as shown below. 14.1.5 Adjusting for other costs (5) and revenue variances where the variance of total actual revenue differs from the total allowed revenue. Footnote 5 as above: Includes but not limited to taxes and levies (as defined), sales volumes and customer number variances. Eskom company revenue is made up of electricity and non-electricity revenue. Eskom s electricity revenue is derived from 3 customer categories viz. standard tariffs, local negotiated pricing agreements and exports (international) customers. Non-electricity is made up of deferred income that is recognised and other revenue. The table below shows the sales volume and revenue variance with the total average price for all customers being marginally lower than the MYPD3 decision by 0.20c/kWh. TABLE 4 : CALCULATION OF MYPD3 REVENUE VARIANCE FOR 2017/18 2017/18 Revenue variance for 2017/18 MYPD3 Decision RCA Actuals RCA Variance Total external electricity revenue (R'm) 205 214 178 318-26 896 Total external sales volumes (GWh) 243 624 212 190-31 434 Total average selling price (c/kwh) 84.23 84.04 0.20 RCA Year 5 (FY 2017/18) September 2018 Page 20 of 121
Revenue Variance *Note that the total external electricity revenue of R177 041 has been increased by the net revenue impairment adjustment of R3 277 to R178 318. (refer to table 5 below). 5.2 Revenue computed on an equivalent basis When computing the RCA balance, it is important to compare the same reference points. Eskom s annual report discloses Group and Company information. NERSA regulates substantially the Company performance with some adjustments required to present a like for like comparison to the MYPD3 decision. The table below shows the items that need to be excluded from Eskom Company revenue in order to calculate revenue variance for RCA purposes TABLE 5 : RECONCILIATION OF AFS REVENUE TO RCA REVENUE Actual Revenue for RCA calculation in 2017/18 (R'million) Eskom Company Notes Revenue per AFS 177 424 Less : Non-electricity revenue -2 383 Deferred income recognised 1 2 Other revenue -2 383 External electricity revenue 175 041 Add : IAS 18 unrecognised revenue 3 277 Revenue for RCA purposes (R' million) 178 318 3 Note 1: Revenue as reported in Eskom s 2018 AFS: Revenue from continuing operations of R177 424 million, reported on page 89 of Eskom s 2018 AFS, provides the starting point for obtaining the MYPD equivalent for actual revenue. Actual electricity revenue was R175 041 million while all other revenue was R2 383 million for 2017/18. RCA Year 5 (FY 2017/18) September 2018 Page 21 of 121
Revenue Variance TABLE 6: REVENUE NOTE FROM AFS FOR MARCH 2018 Source: Eskom Annual Financial Statements, 31 March 2018, page 89 Note 2: Basis for excluding non-electricity revenue In terms of IFRS, other revenue and deferred income recognized are included in revenue. The accounting policy notes describe the nature of the originating transaction as follows: Deferred income recognized and other revenue: In contrast to IFRS, paragraph 6.1.5 states that the RAB should, however, exclude any capital contributions by customers, though allowance will be made for electrification assets to allow for future replacement of such assets by Eskom at the end of their useful life. It is therefore in the light of paragraph 6.1.5 that non-electricity revenue is removed from electricity revenue (not taken into account when calculating the revenue variance) and credited under capital expenditure (this will reduce capital expenditure and the return on assets). Note 3: IAS 18 adjustment In terms of IAS 18 electricity revenue of R3 227 million was not recognized as revenue as it was assessed that there is a high probability that the economic benefit will not materialize (i.e. high probability that not all revenue billed will be collected). RCA Year 5 (FY 2017/18) September 2018 Page 22 of 121
Revenue Variance However, for regulatory purposes this revenue is added back since in terms of the regulatory framework the sale of energy took place and non-recovery of revenue is currently dealt with in a different manner. The IAS adjustment is added back to actual revenue for the RCA. 5.3 Allowed Revenue Allowed revenue for 2017/18 is R205 214 as shown in the extract below Extract 1: Source: NERSA s reasons for decision on Eskom s Regulatory Clearing Account Balance- Third Multi Year price determination (MYPD3) Year 1 (2013/14) 5.4 Sales volumes contribute to recovery of fixed costs The revenue variance is related to the sales volume variance. When NERSA makes a decision on the sales volume, it allows Eskom to recover the allowed revenue decision through the sales volume. The MYPD3 allowed total revenue covers variable and fixed costs. If the sales volume did not materialise as in the MYPD 3 decision it implies that Eskom did not recover the fixed costs that it would have recovered if the reality had turned out as in the NERSA MYPD 3 decision. The MYPD3 allowed total revenue covers variable and fixed costs. The NERSA MYPD 3 RCA 2013/14 decision supports that Eskom is required to recover the allowed revenue as reflected in the MYPD 3 decision. However these revenues are only fully recovered if all the sales are achieved as assumed in the decision. Therefore, in the event of lower sales RCA Year 5 (FY 2017/18) September 2018 Page 23 of 121
Revenue Variance materialising, it results in Eskom not recovering the allowed revenue components as was assumed by NERSA. Eskom s allowed revenue in terms of the MYPD Methodology and MYPD3 decision is to cover variable costs (mainly primary energy) and fixed costs (operating costs + depreciation + returns). Eskom would still need to continue to incur these costs, when the sales volume increases or decreases. As sales volumes increase or decrease, there would be a concomitant increase or decrease in variable costs. The key variable costs for the electricity industry are related to primary energy costs. Operating and maintenance costs are not included in the determination of the RCA balance and not subject to RCA variance analysis, as higher expenditure on operating and maintenance (O&M) costs in the current MYPD Methodology cannot be recovered through the RCA by Eskom. Primary energy cost variances due to lower sales have been included in each of the primary energy cost elements in the RCA balance computation. Fixed costs include interest and debt repayments which are represented by the return on assets and depreciation in the building blocks of the allowed revenue for regulatory purposes. The RCA mechanism that corrects for electricity demand under/over estimation is not a mechanism to restore sales volume and revenue to the estimated level, but rather is a mechanism to correct for such under/over-recovery of fixed cost caused by variances between estimated demand and actual demand, which it achieves by adjusting estimated sales volumes to align to what actually happened, and recalculates what price would have been on that basis, and thus revenue shortfall to be recovered through the RCA. It is confirmed that the RCA mechanism that corrects for revenue variance related to sales variance is to get back to NERSA s decision made on allowed revenue. The revenue variance in accordance with MYPD methodology is not a matter of prudence, efficiency or reasonableness with regards to the actual outcome, but at most a matter of inaccurate forecasting of an uncontrollable matter irrespective of whether such lower demand was caused by underestimation of price elasticity, lower economic growth, commodity cycles, capacity constraints etc. The correction of such initial over-estimation of electricity demand represents deferred recovery of the fixed cost that would have been recovered from consumers in FY 2018, had demand estimations been accurate. As such, whether or not Eskom would have been able RCA Year 5 (FY 2017/18) September 2018 Page 24 of 121
Revenue Variance to meet demand is a matter of forecasting variance, not of prudence or efficiency. Eskom has also provided information related to the request for large customers to drop their utilisation by 10%. The revenue variance adjusts estimated sales volumes to align to what actually happened, and recalculates what the price would have been on that basis, and thus the revenue shortfall to be recovered through RCA. NERSA made a MYPD 3 decision based on a sales volume that it determined to be viable, according to its analysis. Eskom had proposed that NERSA considers a revised sales volume prior to NERSA making the MYPD 3 decision. This corresponded to a lower volume for each of the financial years of the MYPD 3 period. If the revised (lower) volumes had been deemed to be reflective of what could be achieved for each of the financial years, there would have been different outcomes. The resultant price (in c/kwh) would have been higher because the allowed revenue would have been recovered over a smaller volume of sales. The reason for the higher price is due to the recovery of the fixed cost elements. The variable cost elements are netted off as part of the operating costs. Thus it is only the variable costs that increase and decrease when the sales volume increase and decrease. The fact that NERSA decided to use a higher volume of sales (as indicated by its analysis) does not mean that if this did not materialise it was not a prudent decision made by NERSA, but rather a forecasting variance that occurred. The RCA deals with Decision vs Actuals. Eskom understands that the MYPD methodology does not allow for allow for a situation of what if. It is clarified that the revenue variance is a simple process to get back to the decision already made by NERSA. The sales demand and supply process needs to be separated. It cannot be assumed that if Eskom had achieved the assumed EAF levels would not have changed the actual revenue and sales volumes. Further clarification is that the Allowed Revenue formula for Eskom in the NERSA MYPD Methodology is in line with any typical cost-of-service-based methodology with incentives for cost savings and efficient and prudent procurement by the licensee that will be found in sound international regulatory methodologies. For MYPD3 the specific formula is: AR = (RAB x WACC) + E +PE + D + TNC + R&D + IDM + SQI + L&T +/- RCA RCA Year 5 (FY 2017/18) September 2018 Page 25 of 121
Revenue Variance The formula reflects the elements that are aggregated in order to calculate the Allowed Revenue. The values for all these elements are based on forecasts and projections firstly by the applicant as at the time of preparing the revenue application, and secondly by the regulator who assesses the forecasts and projections as made by the applicant and decides whether or not they are reasonable and whether or not to base the Allowed Revenue decision on those forecasts and projections. As such the forecasts and projections also become those of the regulator, during the process of deciding on the Allowed Revenue. 5.5 Allowed vs Actuals volumes TABLE 7 : SALES VOLUME VARIANCE Sales volumes variance per tariff category (GWh) MYPD3 Decision FY 2018 Actuals Variance NPA sales 11 302 9 707-1 595 Add: Standard tariff sales including internal sales 223 217 187 761-35 456 Total Distribution sales 234 519 197 468-37 051 Add: International sales (see note 2) 9 507 15 173 5 666 Total Sales to all customers (see note 1) 244 026 212 641-31 385 Less: Internal sales -402-451 -49 Total external electricity sales 243 624 212 190-31 434 Actual external electricity sales volume of 212 190GWh is disclosed in Annexure 3. Note 1: The 244 026 GWh is as per Table 54 from the NERSA MYPD3 decision. Refer table below. Note 2: The international sales shown in the Annual Financial Statements reflect 15 808GWh (15 173GWh + 95GWh) which are based on the geographical location in which the sale occurred. For regulation purposes the 95GWh is not shown as International sales as this is sold by Distribution and as such forms part of Distribution sales. RCA Year 5 (FY 2017/18) September 2018 Page 26 of 121
Revenue Variance TABLE 8: APPROVED SALES VOLUMES FORECAST, MYPD3 GWh 2017/18 Standard tariff sales 223 217 Negotiated pricing agreement 11 302 Exports 9 507 Approved sales forecast 244 026 GDP 4.0 Source: Table 54 Approved Sales Volumes Forecast, MYPD3 Decision 5.6 Sales volume variance explanation The MYPD forecast is normally finalised in the 2 years preceding the MYPD determination. This in itself poses a high risk as many economic assumptions can change during this period while the MYPD submission is analysed and a determination is made. In the case of MYPD3, the MYPD forecast was finalised on 14 September 2011 when the prospects for a higher economic growth were still viable as the country recovered from the recession in 2007/08. At that time the GDP growth assumptions were still high. However, the effect of the continuing global recession on the South African economy caused a decline in South African GDP growth. It is difficult to separately quantify the individual impacts of events as some occurred simultaneously and some are interrelated. Further, short term load reduction in the form of rotational load shedding and power buy backs had a permanent negative impact on the energy consumption. Notable is that there are some large industrial customers that were greatly affected by these hardships as can be seen from the table below. RCA Year 5 (FY 2017/18) September 2018 Page 27 of 121
Revenue Variance TABLE 9: MYPD3 SALES VOLUME Year End Sales (GWh) Top Industrial Customers (GWh) Actual 2014/15 Actual 2015/16 Actual 2016/17 Actual 2017/18 MYPD 2017/18 Actual vs MYPD variance Silicon Smelters 634 593 177 273 696-422 Rand Carbide 568 510 426 482 539-57 Assmang Machadodorp 205 27 12 5 721-716 Highveld Steel & Vanadium - 564 262 301 1 800-1 500 ASA Metals 1 091 321 - - 1 423-1 423 SASOL Infrachem 15 16 15 16 1 154-1 138 SASOL Synthetics 273 1 512 1 819-5 121-5 121 Hillside Aluminium 10 121 10 126 10 177 10 263 10 360-97 Ferrometals 1 571 1 709 1 721 1 658 1 839-181 International Ferro Metals 834 323 210 711 1 309-598 The drivers of this declining sales trend in the Industrial and Mining sectors include: Increasing prices Energy efficiency improvements; closures due to competitiveness and profitability; reduced peak / high season usage; increased use of own generation. Weakening markets oversupply and high stock levels; low commodity prices; environment that favours cutbacks over growth. Deteriorating electricity supply performance (maintenance and restoration) poor quality and reliability of supply causing plant stoppages. Low growth and low infrastructure spend in SA projects (sales growth) being delayed or cancelled; inadequate infrastructure and policy/regulatory uncertainty. The table below highlights the difference between MYPD3 forecasts and actual reality that has transpired over the last five years. TABLE 10: MYPD3 SALES VOLUME Total Eskom Sales (GWh) 2012/13 2013/14 2014/15 2015/16 2016/17 2017/18 MYPD3 sales (GWh) 222 756 227 403 229 513 235 638 239 113 244 026 MYPD3 growth % -1.10% 2.09% 0.93% 2.67% 1.47% 2.05% Actuals sales (GWh) 217 022 218 368 217 097 215 149 214 601 212 641 Actual sales growth % -3.66% 0.62% -0.58% -0.90% -0.25% -0.91% RCA Year 5 (FY 2017/18) September 2018 Page 28 of 121
Revenue Variance 5.6.1 The process in deriving the 5 year forecast The 5 year sales forecast used in the MYPD3 application was compiled using a bottom up approach from customer level. For each region, the sales forecasting categories were as follows: Individually forecasted customers Individually forecasted customers future consumption was projected based on each of the customer specific business plans and environmental influences on the customer s business. The forecasting of International customers was also on an individual basis. Non-individually forecasted customers The customers that are categorized as in the residual +/-20% were forecasted per sector. This further segmentation by sector for non-individually forecasted customers was done as economic and business environment influences have a closer correlation by sector. Each of the Eskom Operating Units (OUs) forecasted the regional sales (covering the 9 provinces) using a bottom up approach from customer level for their specific OU. Each OU forecast were scrutinised on a one on one basis after which the six OU forecasts and the Top Industrial Customer s forecast were consolidated into one Eskom view. 5.6.2 Critical changes in assumptions relevant during 2011 in deriving forecasts TABLE 11 : GDP FORECASTS USED FOR MYPD3 IN 2011 GDP growth % 2012 2013 2014 2015 2016 2017 MYPD3 GDP growth % 4.0% 4.0% 4.0% 4.5% 5.0% 5.0% Actual GDP growth % 2.20% 2.20% 1.50% 1.30% 0.30% 0.66% The actual GDP growth rates were approximately half the forecasted assumptions as received from various economic forecasts at the time for the first part of MYPD3; declining to about 20% of the forecast in the last 2 years. The most growth in recent decades has been in the less energy intensive services sectors, while the contribution of the energy intensive industrial and mining sectors declined rapidly. A substantial amount of furnace load has not been utilised in winter because of the higher winter prices. Furnaces were taken out for maintenance in winter. RCA Year 5 (FY 2017/18) September 2018 Page 29 of 121
Revenue Variance Certain forecasted commodity prices used in the MYPD3 were higher than the actual average commodity prices that were realised. TABLE 12: COMMODITY PRICES ASSUMED Commodity Prices MYPD3 Decision 2016 2017 2018 FeCr $1.20/lb - $1.32/lb 0.96 1.37 1.44 Aluminum $2 500/ton - $2 750/ton 1604.00 1917 1806 Platinum $1 480/oz - $2 000/oz 986.00 978 1156 Average weather conditions have been used. 5.6.3 Sales volume variance explanation for FY2017/18 The table below shows the sales volume variance that will provide the reasons for the decrease in sales volumes compared to the decision. TABLE 13 : SALES VOLUME VARIANCE Sales volume variance per customer category (GWh) Actual Sales MYPD 3 Variance International 15 173 9 507 5 666 Distribution sales 197 468 234 519 (37 051) IPP Network Charge 60 60 Municipalities 87 073 102 129 (15 056) Industrial 47 854 63 265 (15 411) Mining 30 235 38 113 (7 878) Traction 3 148 3 142 6 Residential 3 844 4 644 (800) Commercial 10 539 10 117 422 Agricultural 5 711 5 442 269 Prepayment 8 458 7 173 1 285 International 95 92 3 Internal Sales 451 402 49 Other - Total electricity sales volumes 212 641 244 026 (31 385) Exclude Internal sales (451) (402) (49) Total external electricity sales volumes 212 190 243 624 (31 434) RCA Year 5 (FY 2017/18) September 2018 Page 30 of 121
Revenue Variance From the table above, which reflects the variance between the decision and actual sales for the year 2017/18, it can be seen that the unfavorable variance of 37 051 GWh in respect of distribution sales is mainly due to three categories, namely Municipalities, Industrial and Mining. The unfavorable variances in these three categories were partially offset by the favorable variance of 5 374 GWh from the international sales and 1 286 GWh from the prepayment environment. 5.6.3.1 Municipalities: 15 056 GWh unfavourable The unfavorable variance in this category is spread over most of the municipalities and metro s and are mainly due to the following: The largest unfavorable impacts are seen in the City Power due to sluggish economic growth and Kelvin Power station generation offsetting City Power s consumption from Eskom. In the Southern Region the expectation was that the Coega development project would have been active and ramping up but due to the absence of the anchor project, these failed to materialize. Cape Town Municipality introduced and is actively driving a huge savings programme to save 10% of their total consumption. Other metro s and municipalities were also severely negatively affected due to the slow local & global economic growth. In 2017 the abnormal high winter temperatures in July and August also reduced the energy consumption. As a result of the global economy that did not grow as expected and the fluctuation of the ZAR exchange rate; the manufacturing sectors behind the bulk meters in the municipalities were not able to secure orders, thus producing fewer goods with a resultant drop in energy consumption. EEDSM initiatives had a permanent negative impact on sales due to the roll outs of CFL s, installation of PV panels and installation of solar geysers. The closure of EB Steam customers by Eskom also affected the variance unfavourably especially in the Western Cape, Eastern Cape and KZN as they were included in the assumptions used for the MYPD decision. RCA Year 5 (FY 2017/18) September 2018 Page 31 of 121
Revenue Variance FIGURE 2 : PERFORMANCE OF MUNICIPALITIES 5.6.3.2 Industrial: 15 411 GWh unfavourable The industrial customers were the most severely affected category that was caused by the following: The Aluminium sector saw a slight improvement in weak commodity prices but not enough to erode the negative performance against MYPD expectations. Subdued performance is still due to a drop in world demand for Aluminium that forces production cuts. The Ferro and steel smelting industry saw a drop in consumption compared to the MYPD NERSA decision of 11 051.46 GWh due to the low demand for their products as a result of the collapse of commodity prices and cheaper imports from China. This led to a continuing decline in orders, downsizing and closure of customers. Refer to the table and figure on commodity prices below. The Titanium sector posted a decline of 471 137 GWh as a direct result of slow recovering world demand for their product on the back of weak commodity prices. The closure of EB Steam customers also affected the sales unfavorably in this category. RCA Year 5 (FY 2017/18) September 2018 Page 32 of 121
Revenue Variance TABLE 14 : COMMODITY PRICES Source LME, TSI, CRU, Metal Bulletin, Macquarie Research, June 2017 RCA Year 5 (FY 2017/18) September 2018 Page 33 of 121
Revenue Variance FIGURE 3 : PERFORMANCE OF FERRO SMELTERS FIGURE 4: PERFORMANCE OF IRON AND STEEL SMELTERS RCA Year 5 (FY 2017/18) September 2018 Page 34 of 121
Revenue Variance 5.6.3.3 Mining: 7 879 GWh unfavourable The mining customers were also affected severely mainly due to the gold and platinum sectors. Mining production in South Africa continued to slump in 2017, according to figures from Statistics South Africa. The biggest factors affecting production are commodity prices, followed by cutbacks, official and unofficial go slows, Section 54 and 55 safety stoppages and strikes. The Platinum sector showed a 4 087.9 GWh drop in consumption against the MYPD3 NERSA decision mainly due to: o o The unfavourable platinum price and demand for platinum that negatively affected the start-up of projects (delayed in the hope of an upturn in the markets) while others were cancelled. Section 54 and 55 safety stoppages. The Gold sector experienced a 2 938.07 GWh drop in consumption compared to the forecast. Many mines are reeling from ageing infrastructure, depleted reserves, safety related incidents and silicosis settlements. Some gold mines were liquidated while others closed their shafts. Many shafts were put under care and maintenance due to these cost pressures. The unfavourable commodity price also played a major role in escalating the cost pressures. FIGURE 5: PERFORMANCE OF MINING SECTOR RCA Year 5 (FY 2017/18) September 2018 Page 35 of 121
Revenue Variance FIGURE 6: PERFORMANCE OF PLATIMUN SECTOR FIGURE 7: PERFORMANCE OF GOLD SECTOR RCA Year 5 (FY 2017/18) September 2018 Page 36 of 121
Revenue Variance 5.6.3.4 Prepayment: 1 286 GWh favourable In the Prepaid environment a significant favorable variance was experienced compared to the MYPD3 NERSA decision, mostly in the Northern and Central Operating Units where the changing of the supply group codes eliminated most of the ghost CDU s. This resulted in higher than anticipated sales volumes 5.6.3.5 International: 5 374 GWh favourable The favourable variance against the MYDP3 NERSA decision was mainly due to the higher than budgeted sales caused by the drought experienced in the neighboring countries. The persisting drought impacted the Southern African region resulting in reduced available hydroelectric capacity in the DRC, Zambia and Zimbabwe. This provided Eskom with an opportunity to realise additional electricity sales. 5.7 Energy Conservation Scheme (ECS) offsets revenue variance The electricity crisis in early 2008 highlighted the extremely fine balance that existed between supply and demand for electrical energy in the country, and which would have persisted until much of the new base load capacity from Medupi and Kusile became available later. In the beginning of 2008, Eskom was requested to develop the Power Conservation Programme (of which the Energy Conservation Scheme was part) on behalf of National Government to address the energy crisis. Subsequently an industry task team was created by the EIUG in March 2010, under the sponsorship of the DoE, with participation from Eskom and other stakeholders. This team produced a technical report concluding that after all demand and supply side solutions have been implemented, a residual gap between supply and demand still remains for the next 3 to 4 years at that time. The team identified a number of strategies to mitigate the risk to security of supply, one of which was ECS. The ECS was designed to simultaneously achieve three objectives at a minimum economic cost to South Africa, namely the improved management of South Africa s electricity system, by enhancing information exchange between large industrial and commercial Customers and the System Operator; RCA Year 5 (FY 2017/18) September 2018 Page 37 of 121
Revenue Variance a sustained reduction of (initially determined as 10%) in the country s historic electricity consumption base, primarily arising from improved energy efficiency; and the promotion of energy efficient growth in electricity consumption. Eskom s MYPD3 revenue application submission considered the implementation of a mandatory ECS to manage the anticipated shortage of supply. The application highlighted that demand forecast changes would pose a risk to the price path and therefore called for a safety net in the form of a mandatory ECS to be in place to ensure a stable power system, even if other supply-and-demand levers were not able to close the energy gap. The mandatory scheme would apply to South Africa s 500 largest electricity users those using more than 25 gigawatt-hours (GWh) a year to reduce their energy usage. Certain fundamental decisions were still outstanding at the time of implementation of MYPD3, which prevented the promulgation of the mandatory ECS scheme. The voluntary participation on ECS continued from July 2008 until January 2014. In January 2014, following a number of engagements with stakeholders, Eskom had to make a decision in the absence of direction from decision makers with regards to the implementation of a mandatory scheme. It was then decided that the ECS will remain a voluntary scheme and participating customers were requested to save up to 10% of their base line consumption of the period before load shedding - as a reference line. Important to note is that the savings by customers cannot only be contributed to the lack of generating capacity and that the notion that if the forecasted load had materialised Eskom would anyway not have been able to supply is not agreed with. As such, whether or not Eskom would have been able to meet demand is a matter of forecasting variance and not of prudence or efficiency. Eskom, therefore, does not agree that the revenue variance should be lowered as a result. In year 2 to 4 of MYPD 3, Eskom on request from NERSA, proposed that if NERSA requires the reduction of revenue due to Eskom requesting a reduction in demand from its customers a credible and measurable option must be used to calculate the possible impact. It was suggested that the savings achieved through the voluntary ECS scheme as outlined in the MYPD methodology Clause 11.4 and 11.5 below is used: RCA Year 5 (FY 2017/18) September 2018 Page 38 of 121
Revenue Variance This is a reliable way of calculating the savings as Eskom at the time established internal governance structures, a project management office and a system to ensure the business readiness for the implementation of both the voluntary and mandatory ECS scheme. 72% of key customers had confirmed reference consumption, while 27% of the top 500 Eskom customers had confirmed reference consumption. During the voluntary implementation of the scheme, it became clear as outlined earlier in this document - that customer usage patterns, other than the ECS targets were influenced by: The rising electricity prices from the previously very low base. The strength of the commodity markets economic crisis since 2008. Introduction of energy efficient technologies. High probability new projects were included in the sales forecast but were delayed with the downturn of the economy and much lower commodity prices than expected (the drop in commodity prices have also been provided during the public hearings. TABLE 15: COMMODITY PRICES ASSUMED RCA Year 5 (FY 2017/18) September 2018 Page 39 of 121
Revenue Variance In the industrial sector there was a drop in consumption of 7 474 GWh during the period of these RCAs from ONLY 14 customers - the majority mainly as a result of a collapse in commodity prices or a lack of orders for their products as reflected below. It was no longer feasible to continue with the voluntary scheme as the majority of customers achieved the required savings causing the voluntary scheme to lose momentum as a result. 5.7.1 Using the fixed portion of the tariff Eskom s allowed revenue in terms of the MYPD Methodology and MYPD3 decision is to cover variable costs (mainly primary energy) and fixed costs (operating costs + depreciation + returns). Eskom would still need to continue to incur the fixed costs, when the sales volume increases or decreases. a) Variable costs: As sales volumes increase or decrease, there would be a concomitant increase or decrease in variable costs. The key variable costs for the electricity industry are related to primary energy costs. Operating and maintenance costs are not included in the determination of the RCA balance and not subject to RCA variance analysis, as higher expenditure on Operation and maintenance (O&M) costs in the current methodology cannot be recovered through the RCA by Eskom. b) Fixed costs Fixed costs include interest and debt repayments, which are included in the returns and depreciation building blocks of the allowed revenue for regulatory purposes. Therefore, although Eskom still had to incur the fixed cost associated with the savings, the only additional revenue that Eskom could sacrifice as required by NERSA - without being penalised twice - is the revenue associated with the fixed cost component of the savings. The fixed cost recovery through the network and retail charges was therefore calculated for the customers that signed ECS agreements. 5.7.2 ECS measurement system and calculations During the preparations for the mandatory implementation of the ECS, the ECS base line and allocations was signed and agreed with 131 customers, of which 95 were Key Industrial Customers. The consumption of these customers has been tracked. What was used in the current calculation was therefore drawn from a manual system that was developed in 2008 and projected until the end of the MYPD3 period. The ECS report system and the database on which it resided was discontinued in the first quarter of 2014, RCA Year 5 (FY 2017/18) September 2018 Page 40 of 121
Revenue Variance therefore ECS information is currently not readily available anymore. The only auditable savings that could be provided were those savings when actual consumption was compared to the allocation in the ECS using the original allocation based on a 10% saving. However, in terms of the ECS rules the reference consumption was compared with those customers allocation (saving of 10%) for the RCA year of 2017/18. Savings has been calculated up to 10% as was agreed with customers. In most cases the additional savings beyond 10% was due to other reasons than the request to save consumption. 5.7.3 Further Revenue variance due to ECS The total savings were tracked, but based on the explanation in this submission; the primary energy cost variances due to lower sales have already been included in each of the primary energy cost elements in the RCA balance computation. To include the variable cost savings in the number provided would have been double counting and Eskom would have been penalised twice for the same reduced variable cost savings. The variable component of the savings has already been in favour of customers by way of the cost savings in the coal costs resulting from the lower production volumes the fixed cost recovery through the network and retail charges that was calculated for the customers that signed ECS agreements. The energy reduction (in kwh) and associated fixed cost reduction achieved by customers when comparing their agreed allocation vs baseline as per the ECS consumption summary are as follows: TABLE 16: ENERGY CONSERVATION SCHEME CONSUMPTION SUMMARY ECS Consumption Summary Reference Consumption for the Year (GWh) Allocation for the Year (GWh) Actual Consumption (GWh) Total Reduction achieved through savings (GWh) Actual reduction in sales required and to be given back to Customers (GWh) Marginal Variable Energy Charge (c/kwh) Fixed Cost Charge (c/kwh) Total Average Price (c/kwh) Rand Value of ECS Fixed Cost (Rm) 2017/18 77 232 78 894 61 123 21 399 3 123 46 35,93 81,93 R 1 122 Eskom has therefore adjusted the revenue variance with the ECS fixed costs, which is a sacrificed by Eskom. It reduces the original RCA balance by R1.12bn. This is in line with the RCA revised application (after the public hearings) for the 2 nd, 3 rd and 4 th years of the MYPD 3 period. RCA Year 5 (FY 2017/18) September 2018 Page 41 of 121
Revenue Variance 5.8 Conclusion on the sales volume and revenue variance The revenue variance calculated and explained above is consistent with the requirements of the Regulatory Framework i.e. rule 14.1.5. Eskom believes they have supplied the necessary explanations required for the sales volume and revenue variance of R26 895 million in 2017/18. Further adjustments are made due to the ECS contribution. RCA Year 5 (FY 2017/18) September 2018 Page 42 of 121
Impact of demand responses on sales volumes 6 Impact of demand responses on sales volumes As part of the MYPD3 determination, NERSA allowed for demand response initiatives to be utilised which comprise EEDSM and DMP for 2017/18. Embedded in Eskom s MYPD3 application was an assumption for EEDSM which was taken into consideration when determining the sales forecasts. In the 2017/18 year, NERSA assumed 2 132GWh of energy savings at a cost of R1 244 million which culminated in 415MW of capacity savings. In reality, EEDSM achieved lower verified savings during the year of 42MW of capacity. Due to financial constraints, Eskom was obliged to reprioritise its EEDSM programmes to be in a position to address its liquidity challenges. In addition, NERSA assumed DMP costs of zero in 2017/18 while actual expenditure was R160million. RCA Year 5 (FY 2017/18) September 2018 Page 43 of 121
Collectability of revenue does not impact RCA 7 Collectability of revenue does not impact RCA It is important to note that the revenue variance compares the revenue as reflected in the audited annual financial statements. For RCA purposes the risk of un-collectability is removed as the amount deducted in the annual report under IAS18, R3 277million is added back. This means that revenue is recognized on the basis of billed revenues. Thus collectability of revenue and ability for consumers to pay are excluded in revenue amount and thus excluded in the revenue variance for RCA purposes which implies that all revenue billed is assumed to be collected. RCA Year 5 (FY 2017/18) September 2018 Page 44 of 121
Prudency and Efficiency 8 Prudency and Efficiency South African Legislation Section 16(1) (a) of the Electricity Regulation Act determines that A licence condition determined under section 15 relating to the setting or approval of prices, charges and tariffs and the regulation of revenue - (a) must enable an efficient licensee to recover the full cost of its licensed activities, including a reasonable margin or return. This principle is confirmed by the Electricity Pricing Policy, which also states that. an efficient and prudent licensee should be able to generate sufficient revenues that would allow it to operate as a viable concern now and in the future.. International references: The concept of prudence is usually defined as a test of reasonableness of the [utility s] decision under all of the circumstances known at the time. The majority of regulatory jurisdictions in the US that conduct prudence reviews have adopted this common definition e.g. the Missouri Public Service Commission have defined prudence as: [The] company s conduct should be judged by asking whether the conduct was reasonable at the time, under all the circumstances, considering that the company had to solve its problems prospectively rather than in reliance on hindsight. In effect, our responsibility is to determine how reasonable people would have performed the tasks that confronted the company In accepting a reasonable care standard, the Commission does not adopt a standard of perfection. Perfection relies on hindsight. Under the reasonableness standard relevant factors to consider are the manner and timelines in which problems were recognized and addressed. Perfection would require a trouble-free project. The Australian Energy Regulator states the following in a 2013 document: Prudent expenditure is that which reflects the best course of action, considering available alternatives In ex post reviews, however, we must account for only information and analysis that the NSP [Network service provider] could reasonably be expected to have considered or undertaken when it spent the relevant capex However, in determining whether capex meets the criteria, we must account for only information and analysis that the NSP could reasonably be expected to have considered or undertaken when it undertook the relevant capex. Conclusion: In compiling this document Eskom has adhered to globally-accepted standards of sound regulation RCA Year 5 (FY 2017/18) September 2018 Page 45 of 121
Production volumes in GWh Factors which influence Eskom production plans 9 Factors which influence Eskom production plans Sales are a critical factor which influences production plans. Demand side options are incorporated in the eventual sales requirements which must be met by a corresponding production plan. In addition to sales, supply options from new build capacity, local and regional supply sources plus the performance and maintenance requirements of the existing fleet all contribute to the eventual production plans. Due to changing assumptions and environment, the figure below outlines the change between the assumed production plans and the actual production results. At a glance the drop in sales requirements by approximately 31TWh, new build commissioning dates, performance of existing coal fleet and levels for IPPs and OCGTs all contribute to the actual production results. The details surrounding the supply options and new build commissioning including the Generation power station performance will be discussed later in the document. The volumes of electricity produced will drive the cost impacts under primary energy which will be explained in the next section. FIGURE 8: PRODUCTION FY2018 280 000 270 000 260 000 250 000 240 000 230 000 220 000 210 000 200 000 190 000 Electricity Output in 2017/18 Imports IPP Nuclear Wind energy Gas turbine stations Pumped storage stations Hydroelectric stations Coal-fired stations MYPD3 Actuals RCA Year 5 (FY 2017/18) September 2018 Page 46 of 121
Primary energy 10 Primary energy Eskom has aligned the treatment of primary energy to the NERSA 2013/14 RCA decision which looks at primary energy on a total company approach. This means that total primary energy now includes international purchases when compared to the MYPD3 decision. 10.1 Primary energy variances and RCA impact for 2017/18 Total primary energy allowed for 2017/18 was R91 638 million. Eskom incurred primary energy costs of R85 202 million in the year which resulted in a variance of R6 436 million for the benefit of the consumer. However, not all the cost variances qualify for RCA inclusion. In particular the following RCA adjustments were processed: 1. Coal costs Medupi take or pay and Kusile risk sharing amounts have been excluded where no coal burn materialised. 2. Coal costs Applying the MYPD Methodology requires that the coal burn component is subject to a risk factor adjustment 3. IPP s In terms of IFRS, a portion of the Avon and Dedisa contract is accounted for under IFRIC 4 Determining whether an arrangement contains a lease. However for regulatory purposes, an adjustment of R1 983 million is deemed to be accounted for as an IPP purchase. Hence the sum of all these adjustments is R1 968 million and thereby reduces the total primary energy variance to R4 468 million. Refer table below for the RCA calculation for total primary energy. RCA Year 5 (FY 2017/18) September 2018 Page 47 of 121
Primary energy TABLE 17 : TOTAL PRIMARY ENERGY COMPARISON AND RCA IMPACT FOR 2017/18 R million MYPD3 Decision Actuals Variance RCA adjustment RCA 2017/18 Coal usage 49 914 46 992-2 922-15 -2 937 Net coal obligation raised/(reversed) - - - - - Water usage 2 319 1 796-523 - -523 Fuel procurement service 321 137-184 - -184 Water procurement service - - - - - Coal handling 1 333 2 223 890-890 Water treatment 316 437 121-121 Sorbent usage 250 13-237 - -237 Gas and oil (coal fired start-up) 1 761 2 149 388-388 Total coal 56 214 53 748-2 466-15 -2 482 Nuclear 466 820 354-354 Coal and gas (Gas-fired) - - - - - Road repairs - - - - - OCGT fuel cost 1 724 328-1 396 - -1 396 Environmental levy 9 746 8 061-1 685 - -1 685 Total generation 68 150 62 957-5 193 - -5 193 IPPs 23 018 19 317-3 701 1 983-1 718 International Purchases 470 2 768 2 298-2 298 Demand response and cogeneration - 160 160-160 Total primary energy variance R million 91 638 85 202-6 436 1 968-4 468 Source: Allowed total primary energy -table 17, MYPD3 decision; Actuals - Primary energy note 34, AFS, March 2018 Extract from the AFS, March 2018 reflects the actual total primary costs of R85 202m below. RCA Year 5 (FY 2017/18) September 2018 Page 48 of 121
Primary energy TABLE 18: PRIMARY ENERGY ACTUAL COSTS PER NOTE 34 IN THE AFS OF 2018 Note A: For regulatory purposes, the IFRIC 4 adjustment for IPPs which capitalises a portion of the DOE Peaker costs is reversed as the MYPD Methodology requires for full pass through of IPP expenditure. Therefore the total for IPP s in the AFS of R19 317 million is increased by R1 983 million resulting in a total costs for IPP s of R21 300 million. With the summary information disclosed, the next section will provide more detail on the respective primary energy components. 10.2 Independent Power Producers Eskom acknowledges the role that IPPs must play in the South African electricity market and remains committed to facilitating the entry of IPPs, to strengthen the system adequacy and meet the growing power demand. Eskom has procured a combination of short, medium and long term supply from IPPs. RCA Year 5 (FY 2017/18) September 2018 Page 49 of 121
Primary energy 10.3 Legal basis for IPPs per the MYPD Methodology Section 9 in the MYPD Methodology deals with the treatment of IPPs: 9.1 In accordance with the provisions of Section 14(f) of the Electricity Regulation Act, the Energy Regulator shall, as a condition of licence, review power purchase agreements (PPAs) entered into by licensees before signature. This also includes all PPAs considered under the Ministerial Determination by the Department of Energy (DoE). In evaluating the MYPD, the cost associated with the Independent Power Producers (IPPs) will be done based on the conditions of the respective PPAs. 9.2 The Energy Regulator will review the efficiency and prudency of the IPP before and after PPA contracts are concluded. 9.3 Purchases or procurement of energy and capacity from IPPs, including capacity payments, energy payments and any other payments as set out in the PPA, will be allowed as a full passthrough cost. 9.5 Energy output (deemed payments) that would otherwise be available to the buyer but due to a System Event or a Compensation Event (e.g. system unavailability) was not incurred in accordance with provisions of power purchase agreements reviewed by the Energy Regulator, will be allowed as full pass-through costs. 9.10 The variances (i.e. difference between MYPD allowed costs and actual incurred costs) together with reasons shall be presented to the Energy Regulator. After the review, the variance will be debited/credited to the RCA. 10.4 IPP Approvals All the IPP Power Purchase Agreements (PPA) entered into during the MYPD3 period was approved as part of the licensing process by NERSA prior to being finalised and signed. Eskom has secured recovery of costs associated with all IPP contracts in accordance with the regulatory rules for power purchase cost recovery. RCA Year 5 (FY 2017/18) September 2018 Page 50 of 121
Primary energy 10.5 Regulatory rules for power purchase cost recovery The following are extracts of relevant portion of the regulatory rules for power purchase cost recovery as published in November 2009: 14 Pass through of costs For authorised power purchases, net recoverable costs will be passed through to customers via an adjustment of the buyer s revenue allowance (albeit subject to review by NERSA as set out in rule 17 below). This will require a reconciliation of accounts comparing forecast recoverable costs to actuals. 17 Duration 17.1 An authorisation for power purchase cost recovery should remain valid for the duration of the relevant PPA. Investors will need to be confident in the buyer s ability to make payments into the future, and the buyer will need an appropriate level of regulatory certainty in regard to its recovery of power purchase costs. 17.2 For the avoidance of doubt, the review process set out in rule 16 is limited to reconciling cost variances and draw-down of the power purchase account balance, and is not a retrospective review of the general authorisation or the basis on which cost effectiveness was established. 10.6 Allowed vs Actual IPP costs for 2017/18 Eskom was awarded a total of R23 018 million for IPP s in the MYPD 3 decision for 2017/18. This includes IPP ancillary costs of minus R175 million. Actual costs amounted to R 21 300 million resulting in a variance of R1718 million. Note: The IPP purchase volumes (Energy) for the NERSA decision were inferred from the costs associated with each programme as no energy was disclosed in the MYPD3 decision. A variance of 64GWh of energy from IPPs when compared to the MYPD3 decision in 2017/18 materailised. RCA Year 5 (FY 2017/18) September 2018 Page 51 of 121
Primary energy A summary of the costs and volumes from IPPs are presented in the table below: TABLE 19: IPPS COSTS AND VOLUMES Independent Power Producers (IPPs) Costs (R millions) Energy (GWh) Average Costs (R/MWh) 2017/18 Actuals Decision Variance Actuals Decision Variance Actuals Decision Variance Renewable IPP programme 19 008 19 689-681 9 479 9 080 399 2 005 2 168-163 DoE Peaker 2 291 3 504-1 213 105 440-335 21 728 7 960 13 768 Total IPPs 21 300 23 193-1 893 9 584 9 520 64 2 222 2 436-214 IPP ancillary cost -175 175 Total IPPs for RCA 21 300 23 018-1 718 9 584 9 520 64 2 222 2 418-195 NB: The actual costs include the RCA adjustment amount relating to IFRIC 4 adjustment. 10.6.1 Reasons for IPP variances in 2017/18 Eskom utilized 64 GWh more energy from IPPs when compared to the MYPD3 decision in 2017/18, but due to lower average costs the results was R1 718 million less spent on IPPs compared to the MYPD3 decision. 10.6.1.1 Renewable IPPs Price variance: Prices were substantially lower due to lower actual CPI escalations (compared to forecast). Volume variance: The volumes produced by REIPP generators were slightly higher than that assumed in the NERSA MYPD3 determination. 10.6.1.2 Deemed energy payments Deemed energy payments are payments made to the IPP (in particular under the Renewable IPP programme) for energy that would otherwise have been produced if it were not for a system event (either curtailment, network unavailability or a delay in grid connection not caused by the IPP). Deemed energy payments of R0.3 million for the year were made due to delays in grid connection for a few projects and system curtailment events relating to a system requirement to reduce generation in specific hours. This amount also includes a partial reversal for an earlier deemed energy payment (due to the facility power curve being finalised after a period of commercial operation). RCA Year 5 (FY 2017/18) September 2018 Page 52 of 121
Primary energy In addition the provision of R306 million made in FY 2016/17 was partially reversed by R253.6 million due to recent arbitration results that reduced the potential claims against the Buyer s Office. The total deemed energy reflected for this financial year is then R253,3m. 10.6.1.3 DOE Peaker Price variance: The payment to the Peaker is split between capacity payments and energy payments (for utilization) as it is fully dispatched by Eskom. The average rate paid is higher than anticipated in the MYPD3 decision due to lower utilization (approx. 1.2% for the period of operation) relative to the expected 5%. Volume variance: As explained above the volumes were lower, mainly due to lower utilization by Eskom. 10.6.1.4 Transmission Ancillary Costs NERSA approved R175 million for Transmission ancillary costs in the MYPD3 determination for FY 2018. These costs have not been incurred. This portion of the allocation has been added to accommodate network use of system charges to the IPP which are a pass through to the Eskom Buyer s Office. During FY 2018 the total payment for use of system charges was R105.75 million. This is included in the total payment for REIPP. RCA Year 5 (FY 2017/18) September 2018 Page 53 of 121
International purchases 11 International purchases Eskom acquired electricity from neighboring countries that resulted in purchases of R2 768 million which generated energy inflows of 7 731GWh during the year. The actual costs are agreed to be the international electricity purchases as disclosed under note 34 for primary energy in the AFS. TABLE 20: INTERNATIONAL PURCHASES International purchases R'm MYPD3 Decision Actuals RCA 2017/18 International purchases 470 2 768 2 298 11.1 Cross-border sales and purchases of electricity Eskom has pursued additional international sales in order to increase sales. Sales volumes to March 2018 increased by 1.2% year-on-year. Cross-border purchase volumes were 20% below the assumption and 4.2% lower than the previous year. The lower volumes are due to Hidroelèctrica de Cahora Bassa (HCB) reducing their supply to below contractual obligations, as water levels at Cahora Bassa are still affected by the drought in the region, despite improved rainfall experienced by some of Eskom s other regional trading partners. In accordance with the requirements of the contract, Eskom will continue to purchase from HCB, as the vast majority of imports are from HCB. Eskom is providing support to the region to the extent possible, whilst ensuring local demand is met. Eskom has ensured that sales contracts with Southern African Power Pool trading partners are sufficiently flexible to allow Eskom to restrict supply during emergency situations in South Africa. RCA Year 5 (FY 2017/18) September 2018 Page 54 of 121
International purchases TABLE 21 : CROSS BORDER SALES AND PURCHASES GWh Actual 2015/16 Actual 2016/17 Actual 2017/18 Note International sales per Integrated Report 13 465 15 093 15 268 International purchases 9 703 7 418 7 731 A Net sales/(purchases) 3 762 7 675 7 537 Note A: International sales for the year ended 31 March 2018 include 95GWh sold to Lesotho and Botswana direct from distribution networks at distribution voltage levels (87GWh - FY2017 and 89GWh - FY2016). RCA Year 5 (FY 2017/18) September 2018 Page 55 of 121
Coal Burn Costs 12 Coal Burn Costs 12.1 Extract of MYPD Methodology on Coal adjustments Criteria for Allowing Primary Energy Costs 8.1 All rules applicable to operating expenditure shall apply to the primary energy costs. 8.2 In considering the allowable primary energy costs, the Energy Regulator will consider the most appropriate generation mix that can be achieved practically to the best interest of both the customer and the supplier. 8.3 Coal Costs 8.3.1 Coal will be treated as a single cost centre without differentiating between the various coal sources (for example cost plus contracts, fixed price contracts, shortterm contracts and long-term contracts). 8.3.2 The Energy Regulator will determine and approve the coal benchmark cost (i.e. an average cost of coal R/ton), and Alpha for each year will be determined as part of the MYPD3 final decision. 8.3.3 The coal benchmark price is determined by the Energy Regulator in order to be used in comparison with the actual coal cost for the purpose of determining passthrough costs. 8.3.4 The coal benchmark price will be compared to Eskom s actual cost of coal burn (R/ton) using a Performance Based Regulation (PBR) formula. The PBR formula is the maximum amount to be allowed for pass-through, calculated by applying the following formula PBR cost (Rand) = (Alpha x Actual Unit Cost of Coal Burn+ (1 Alpha) x Coal burn Benchmark price) X Actual Coal Burn Volume : Where: Actual Cost = Actual unit cost of coal burn in a particular financial year Benchmark Price = Allowed coal burn cost/coal burn volume (R/ton) Actual Coal Burn Volume = Actual ton of coal burn in a particular financial year Alpha = Alpha is the factor that determines the ratio in which risks in coal burn expenditure is divided: i.e. those that are passed through to the customers, and those that must be carried by Eskom. Any number of the alpha between 0 and 1, set to share the risk of the coal cost variance between licensees and its customers. 8.3.5 The pass-through component of the coal burn cost is equal to the coal burn volume variance plus Alpha times the coal burn cost variance: Pass through coal burn cost = PBR cost (Rand) minus Allowed Coal burn cost (Rand) = Coal burn Volume variance + Alpha Where: Actual Cost = Actual unit cost of coal burn in a particular financial year Benchmark Price = Allowed coal burn cost/coal burn volume (R/ton) Actual Coal Burn Volume = Actual ton of coal burn in a particular financial year Alpha = Alpha is the factor that determines the ratio in which risks in coal burn expenditure is divided: i.e. those that are passed through to the customers, and those that must be carried by Eskom. Any number of the alpha RCA Year 5 (FY 2017/18) September 2018 Page 56 of 121
Coal Burn Costs between 0 and 1, set to share the risk of the coal cost variance between licensees and its customers. 8.3.6 The coal benchmark price will be used to determine the resulting allowed actual coal burn cost (R/ton) and transferred to the RCA. The amount transferred to the RCA will therefore be calculated as the difference between the PBR amount and the amount forecast/allowed in the MYPD decision. 8.3.7 The coal stock level (stock days) will be reviewed by the Energy Regulator when necessary. 12.2 NERSA s decision on coal benchmark and alpha As indicated in the table below coal burn cost for FY18 as determined by NERSA is R49 914 million, coal burn volumes 133 Mt and the benchmark for FY18, as per NERSA, is RXXX/ton. The actual average R/ton cost in FY18 was RXXX TABLE 22: NERSA S DECISION ON COAL BENCHMARK AND ALPHA Coal Benchmark Unit NERSA Decision 2017/18 Actuals 2017/18 Coal burn costs R'm 49 914 47 164 Coal burn volumes Benchmark avg cost rate kt R/t 12.2.1 Benchmark Average Cost The FY18 R/ton, as per NERSA, is an escalation of the FY14 R/ton that NERSA approved. Eskom is of the opinion that the R/ton approved for FY14 was inappropriate for the reasons below. Because the R/ton approved by NERSA for FY18 would have been impacted by the R/ton approved for FY14, it follows that the R/ton for FY18 will also be inappropriate. Therefore, the following discussion is still relevant for FY18. NERSA s approved FY14 R/ton, on which the benchmark is based, was calculated using the approved FY13 R/ton (from the MYPD2 decision) plus an increase of 10%. Eskom is of the opinion that this is inappropriate for the following reasons: NERSA made a decision for MYPD3 in 2013 based on information and assumptions from 2009, not taking into account changes that had occurred since then. At the time of the MYPD3 decision, the RCA process for MYPD2 had not been finalised, nor were the actual costs for FY14 available. However, the latest actuals and projections based on the coal contracts (as required by the MYPD Methodology) were provided to NERSA. RCA Year 5 (FY 2017/18) September 2018 Page 57 of 121
Coal Burn Costs Production from cost plus mines was assumed to be at contracted volumes in MYPD2, totalling 62.2 Mtpa. In FY13, cost plus volumes were 52.5 Mtpa. The difference was made up of more expensive short/med term contracts. As per NERSA s reasons for decision, NERSA s approved FY14 R/ton, on which the benchmark is based, was calculated by adjusting the approved MYPD2 R/t by 10%. However, production from the cost plus mines, which are all in the latter part of their lifecycles, proved to be more expensive than expected. This trend has been a reality throughout the MYPD 3 period. The increased production during the MYPD 2 period, beyond contractual volumes at certain mines, was to address the power capacity constraints in the short term. New long term contracts were not concluded as assumed in the MYPD2 period which results in much more expensive short/medium term coal purchases. Short/med term contracted prices were and are much higher than that anticipated in the MYPD 2 application. Beneficiation of coal anticipated to be undertaken in the MYPD2 submission has not materialised resulting in higher coal burn rates and reduced power station efficiencies. Anticipated increase in cheaper rail volumes did not materialise from a pricing or capacity perspective. 12.2.2 Coal Burn Costs The burn cost of R56 642 million is the cost that was included in the revenue application. NERSA determined R49 914 million as part of the revenue determination. However, it is not clear what coal purchase costs or what coal volumes were used to arrive at the burn cost of R49 914 million. RCA Year 5 (FY 2017/18) September 2018 Page 58 of 121
Coal Burn Costs 12.3 RCA 2018 calculation The costs to be included in the RCA are calculated as follows: 12.3.1 Step 1 Calculate the performance base regulation cost allowance PBR cost (Rand) = (Alpha x Actual Unit Cost of Coal Burn+ (1 Alpha) x Coal burn Benchmark price) X Actual Coal Burn Volume For 2017/18 PBR cost (Rand) = (((0.XX X Rxxx.xx) + (1-0.XX) X RXXX)) X 115 490 Mt)/1000 PBR cost (Rand) = R46 977m Where Alpha = 0.XX Actual coal burn volume = 115 490 Mt Actual unit cost of coal burn = XXXX.XX per ton Coal burn benchmark cost = RXXX per ton The actual R/t is computed by taking actual coal costs of R47 164 million divided by the volume of coal burn of 115 490Mt resulting in an average actual R/t of xxxx.xx 12.3.2 Step 2 Calculate the pass through coal burn costs For 2017/18 Pass-through Coal Burn Cost = PBR Cost - Allowed Coal Burn Cost Pass-through Coal Burn Cost = R46 977m R49 9145m Pass-through Coal Burn Cost = -R2 937m RCA Year 5 (FY 2017/18) September 2018 Page 59 of 121
Coal Burn Costs 12.3.3 Step 3 Split the pass through coal burn cost into volume variance and price variance as summarised below. TABLE 23: THE COAL BURN BREAKDOWN FOR THE RCA Coal burn variance breakdown Coal burn price variance Coal burn volume variance Coal burn costs included in RCA Unit R'm R'm R'm RCA 2017/18 4 084-7 021-2 937 The coal burn variance of R2 937 million for the benefit of the consumer is a result of a combination of the variances in volume of coal and the unit cost of coal when compared to the benchmark as determined by NERSA. A coal volume variance of R7 021 million in favour of the consumer is included as a result of lower coal utilisation due to lower sales volumes. A variance from the unit benchmark cost of coal was experienced. This resulted in a price variance of R4084 million in favour of Eskom. Step 3a. Coal price variance determines the price impact of actual results compared to that assumed during the decision and allowing for the alpha and multiplying by the allowed volumes of coal burn tons. Coal price variance = Allowed coal burn tons X (Actual Allowed Price in R/t X Alpha) Coal price variance = 132750 X ((xxxx.x xxxx.x) X 0.xx) Coal price variance = 132750 X R30.8 Coal price variance = R4 084m Where: Allowed coal burn tons (Mt) = 132750 Mt Actual Price (R/t) = xxxx.x Allowed Price (R/t) = xxxx.x Alpha = x.xx RCA Year 5 (FY 2017/18) September 2018 Page 60 of 121
Coal Burn Costs Step 3b. Coal burn volume variance determines the impact of change in volumes when comparing actual volumes to that assumed in the decision and multiplying by the decision price plus the price variance after accounting for the alpha. Coal volume variance = Adjusted price r/t with Alpha X variance in coal burn tons Coal volume variance = xxxxxxxxxxxxxxxxxxxxxxxxxx X (132750 115490) Coal volume variance = (xxxxxxxxxxx) X -17260 Coal volume variance = xxxx.x X -17260 Coal volume variance = -R7 021m Where: Allowed coal burn tons (Mt) = 132750 Mt Actual coal burn tons (Mt) = 115490 Mt Allowed Price (R/t) = xxxx Actual Price (R/t) = xxxx.x Alpha = x.xx 12.4 Coal burn cost variance explanations The differences in certain assumptions made in the MYPD 3 decision process and what actually transpired are listed in the table. The details of the differences follow in the explanations below. These factors influenced the higher than benchmark price of coal to some extent. TABLE 24: MYPD 3 ASSUMPTIONS VS. ACTUAL 2017/18 MYPD3 Assumptions for 2017/18 Actual 2017/18 Electricity production from coal fired plant Electricity production from coal fired plant was would be 213 095GWh. lower at 199 084 GWh. Cost Plus and Fixed Price mines produce at Cost Plus and Fixed Price mines produced below expected levels, except for Arnot expected levels. New long term mines are producing Coal qualities have been adjusted to reflect the impact of the washing plants. The new power stations (Medupi and Kusile) use flue gas desulphurisation (FGD) at 0.45 litres per units sent out (l/uso). Only a portion of the coal could be accepted at Medupi Power Station because the station construction was delayed. Some delays were experienced with coal quality improvement initiatives. FGD has not yet been implemented at Medupi and Kusile RCA Year 5 (FY 2017/18) September 2018 Page 61 of 121
Coal Burn Costs MYPD3 Assumptions for 2017/18 Actual 2017/18 Majuba heavy haul line and other rail Rail infrastructure was delayed infrastructure are approved, constructed and commissioned on schedule. The analysis below is an explanation of the actual FY18 burn costs versus the costs for FY18 that were included the MYPD3 revenue application. There was lower electricity production from coal fired power stations. Total coal burnt was 21 119 kt less than expected. The coal fired power stations generated 14 010 GWh less than expected. The positive volume variance as a result of this is R10 605 million. The positive volume variance was partially offset by a different mix and efficiency of power stations generating electricity. The total variance between actual burn cost and what was applied for is R9 478 million. The cost of coal burned is determined primarily by the cost of coal purchased. The average R/ton cost of coal was higher than the benchmark determined. 12.5 Coal purchases The average price Eskom pays for coal is determined by the volume of coal procured from each type of contract (cost plus, fixed price and ST/MT) and the price of coal from each type of contract. These are impacted by various factors: 12.5.1 Long term fixed price contracts This category comprises the MMS (Duvha), Hendrina (Optimum), Matimba (Grootegeluk) and Medupi (Grootegeluk) contracts. The mines supply contractual volumes. The price is determined by the terms of the contract, e.g. an annual escalation may be applied to the price established at the inception of the contract. The contract will stipulate how the escalation is to be calculated. None of the existing contracts are impacted on directly by the price of export coal. Approximately 27% of coal for FY18 was sourced from long term fixed price contracts against a forecast of 31%. 12.5.2 Cost plus contracts The mines attempted to supply contractual volumes. There are circumstances which may prevent this, e.g. geological difficulties, the age of the mines and historical supply profiles. The unit price (R/ton) will be the total cost of operating that mine for that period divided by the production volumes. The export price has little direct impact. Cost plus mines provided approximately 35% of the coal procured in FY18 against the forecast of 32%. RCA Year 5 (FY 2017/18) September 2018 Page 62 of 121
Coal Burn Costs 12.5.2.1 ST/MT contracts These contracts are of varying durations. They are essentially fixed price contracts, but are differentiated from the original 40 year contracts referred to above as long term fixed price contracts. The suppliers supply contractual volumes. As with the long term fixed price contracts, the price is determined by the terms of the contract, e.g. an annual escalation may be applied to the price established at the inception of the contract. The contract will stipulate how the escalation is to be calculated. The export price may have an impact in that the supplier may reference this price at the time of negotiation. However, Eskom s policy is to pay the cost of coal plus a fair return. Whether this price correlates to the export price at any given time is likely to be purely coincidental. These contracts supplied approximately 38% of the coal in FY18 against the plan of 36%. NERSA, in its MYPD 3 decision, did not clarify what coal purchases costs were assumed to calculate the allowed burn cost of R49 914 M. Therefore, the following explanations compare the costs and volumes as per the MYPD3 application with actual costs and volumes. Actual coal purchased in FY18 amounted to R47 043 million for 115 246 ktons 25 997 ktons less than MYPD3 expected purchases. Total purchases spend was R14 717 million less than expected. The R/ton, was R29 (7%) lower than expected. This is a result of the mix of coal purchases between the contract types. Production from the Cost Plus contracts was lower than expected, by about 10%. However, expenditure was lower by about 14%, resulting in a positive impact on the R/ton cost from these mines. The primary reason for the under expenditure on the Fixed Price contracts is the delay in commissioning of the Medupi units. Expenditure on the ST/MT purchases was lower than expected, largely because of the lower burn requirement. a) Cost Plus mines: Eskom pays for all expenditure incurred at the Cost Plus mines, irrespective of the level of production. Lower production results in a higher R/ton. The Cost Plus mines produced 4 620 ktons less than expected. Historically, when Eskom required the Cost Plus mines to supply coal volumes in excess of their contractual obligations, the mines were willing to do so. The only cost to Eskom, and the consumer, was the variable rate of return that the mines earned, so it was cheaper than buying coal elsewhere. Between 1996 and 2011, the Cost Plus mines supplied Eskom s power stations 51.6 Mt more than their contractual volumes. The impact of this has been felt in the more recent past. The mines depleted reserves that would have been supplied to Eskom in later years. As electricity demand increased, additional reserves needed to be accessed and new equipment was required. Because of funding constraints, future fuel expenditure on the Cost Plus mines is one of the RCA Year 5 (FY 2017/18) September 2018 Page 63 of 121
Coal Burn Costs items that has been reduced. The result has been lower production from these mines and a consequent increase in the R/ton cost. The ongoing cash constraints have limited the investment in the cost plus mines which, in turn, has impacted negatively on the production from these mines. It is foreseen that this impact will be felt post MYPD3, as well. Eskom has been seeking alternative funding options, and continues to do so. However, this is becoming increasingly difficult and more expensive. The under production, during FY18, occurred at the following mines: b) Long Term Fixed Price mines Although the proportion of coal sourced from LT Fixed Price contracts remained around 27% in FY18, the volume of coal was 13 455 ktons lower than expected. Delays at Medupi Power Station accounted for 7 301 ktons of this. Lower production from Optimum and MMS mines contributed 5 494 ktons to the 13 455 ktons. Optimum mine experienced financial and labour challenges, while the conveyor between Duvha Power Station and MMS mine had intermittent operational challenges making it difficult to transfer all of the coal to the station across the belt. Total spend on the long term fixed price mines was R4 687 million less than the application. Higher spend at Matimba was offset by lower spend at Medupi, Hendrina and Duvha Power Stations. The average R/ton was R13/ton lower. c) ST/MT coal In FY18, Eskom generated 14 010 GWhs less than the MYPD3 application, so although both the cost plus and fixed price contracts produced fewer tons than the application, ST/MT purchases were still lower by 7 922 ktons. The additional cost associated with purchasing ST/MT coal is the transport cost. Coal may be transported by conveyor, rail, road or a combination of modes. ST/MT coal is typically unable to be transported by conveyor. The MYPD3 and actual volumes, with associated transport modes, for FY18 are reflected in the table below: RCA Year 5 (FY 2017/18) September 2018 Page 64 of 121
Coal Burn Costs TABLE 25: COAL TRANSPORT (KTONS) Transport mode Revenue application Act FY18 Under/(Over) Conveyor 111,047 71,656 39,391 Rail 18,409 11,589 6,820 Road 11,787 32,001-20,214 Total 141,243 115,246 25,997 12.6 Mode of Transport Coal is transported by conveyor, rail, road or a combination of modes. The additional cost associated with purchasing ST/MT coal is the transport cost. The mix between the transport sources is conveyor (62%), road (10%) and rail (28%). Conveyor Conveyor is the cheapest mode of transport. The Cost Plus and Fixed Price mines, which are located close to the stations, use this mode. Because of lower production from these mines, fewer tons were transported by conveyor in FY18. Rail Rail is the next cheapest mode of transport. Utilisation of this mode of transport is constrained by the fact that only Majuba, Tutuka and Camden Power Stations presently have rail infrastructure. Even where a power station has the necessary rail infrastructure, another consideration is that not all suppliers have access to a rail facility. It is rare that one of the smaller mines have direct access. The coal needs to be transported by road to a rail siding, offloaded and then reloaded onto a train. These additional steps in the logistics process add to the delivered cost of coal. Where this is not possible, coal is transported by road to the power station. So, although Majuba and Camden burnt more during FY18, fewer tons were transported by rail. The lower production from Matla, Arnot and MMS mines needed to be complemented by ST/MT coal on road. Road Road is the most expensive mode of transport. Coal also needed to be sourced for the higher burn at Majuba. Because of the rail infrastructure constraints, ST/MT coal to the power stations is transported by road or a combination of road and rail (multi-mode transport). In some instances, this mode may be more expensive than road alone. During RCA Year 5 (FY 2017/18) September 2018 Page 65 of 121
Coal Burn Costs FY18, more coal was transported by road, because of the issues discussed above. Despite this, the average ST/MT R/ton cost was lower than the application. 12.7 Medupi net coal obligation A reduction in the Medupi coal obligation was made in the current year due to a lower inflation adjustment (cost of coal index). The net coal obligation of minus R172 million was reversed for RCA purposes. RCA Year 5 (FY 2017/18) September 2018 Page 66 of 121
Other Primary energy 13 Other Primary energy The MYPD Methodology allows for other primary energy variances as pass through. Coal burn, OCGTs, IPPs and environmental levy have specific rules and are dealt with separately in the document. MYPD Methodology - Other Primary Energy Costs 8.5.1 Other primary energy costs such as nuclear, hydro, and sorbent, will be allowed as pass-through costs. 8.5.2 Primary energy costs at the coal-fired power stations, for example water treatment, start-up fuel and coal handling costs will be allowed as a pass-through and will be reviewed by the Energy Regulator based on the percentage cost increase (inflation forecast). 13.1 Allowed other primary energy in 2017/18 13.1.1 Allowed other primary energy costs Other primary energy costs in the MYPD 3 decision for 2017/18, excluding demand market participation (i.e. DMP), is R6 766 million. 13.1.2 Variances in other primary energy Eskom incurred R7 584 million relating to other primary costs during 2017/18 with the major items being start up gas and oil, coal handling, water and nuclear fuel which is summarised in table below. The actual costs exceeded the MYPD3 decision by R810 million as highlighted in the table below. RCA Year 5 (FY 2017/18) September 2018 Page 67 of 121
Other Primary energy TABLE 26: OTHER PRIMARY ENERGY Other Primary Energy R' million MYPD3 Decision Actuals 2017/18 RCA 2017/18 Water Start-up gas and oil Coal handling Water treatment Nuclear Fuel procurement 2 319 1 796-523 1 761 2 149 388 1 333 2 223 890 316 437 121 466 820 354 321 137-184 Sorbent usage 250 13-237 Other primary energy for RCA, R million 6 766 7 576 810 13.1.3 Reasons for start-up gas and oil costs variance Start-up gas and oil contributes R388 million to the RCA balance. Heavy fuel oil starts and shuts down a coal fired power station and stabilises the boiler flame on occasion e.g. when operating at low load. The number of starts are driven by the number of outages (planned and unplanned) and the number of trips (UAGS) at the units of a station. The number of unplanned outages and trips were slightly higher in 2017/18 than what was anticipated at the time of the MYPD3 application and hence the use of fuel oil increased slightly as well. The price of fuel oil is mainly driven by the US dollar price of fuel oil which is beyond the control of Eskom. The price of oil and the rand/dollar exchange rate is volatile and difficult to predict into the future with accuracy. This principle to allow for price fluctuations was implemented in the NERSA RCA 2013/14 decision, with an extract presented below: Para 56. Eskom is allowed R365 million due to the unfavourable fluctuation in the Rand/Dollar exchange rate and issues that were outside management control (e.g. torrential rainfall). 13.1.4 Reasons for coal handling costs variance A variance of R890m million in favour of Eskom arose, due to movement of coal within the power stations being more than was originally envisaged. However, the year-on-year coal handling costs increased by 26%. The main reason for the increase in coal handling costs from 2016/17 to 2017/18 was at Kendal power station- R384m increase year-on-year). RCA Year 5 (FY 2017/18) September 2018 Page 68 of 121
Other Primary energy Kendal has increased the coal handling costs due to the following: Mine not meeting its production targets (Section 54 due to safety, mine challenges and unrest in the area). Strategic stock pile was depleted in the current year. Coal was moved using trucks next to stackers and mobile feeders This requires small local truckers to fulfil the activities of moving the coal which is costly. Contractor Machinery failed to deliver to such an extent that even Eskom Kendal equipment has been damaged i.e. stacker reclaimer 1 (+- R10M to R15M) this has led to other equipment being sought to assist. During this financial year under- production from the mine is 550,000 Tons and the import reduction is +- 200,000 Tons compared to the previous year. 13.1.5 Reasons for water costs variance NERSA determined that the revenue related to water costs would be R2 319 million for the 2018 financial year. Actual water costs for the 2018 financial year was R1 796 million resulting in a variance for the benefit of the consumer of R 523 million compared to the decision. Key changes in assumptions related to water costs are reflected in the table below: TABLE 28: KEY CHANGES IN ASSUMPTIONS ON WATER COSTS Assumptions in MYPD3 decision Water consumption per unit was 1.44 litres Current infrastructure is old and the backlog of maintenance will also result in an increase to the water tariff. Actuals for 2018 financial year Water consumption per unit was 1.39 litres The DWA was unable to carry out all planned maintenance and still has a backlog. The capital unit charge (CUC), Vaal River Tariff (VRT) and the Waste Discharge Charge are the significant contributors to the under expenditure. These are legislated tariffs. At the RCA Year 5 (FY 2017/18) September 2018 Page 69 of 121
Other Primary energy time of the application for MYPD3, the actual tariffs were not yet published. Expenditure on pumping and O&M was also significantly lower than planned. Capital unit charge: This is a legislated tariff. The increase in the planned tariff included the tariff for new infrastructure. Because the cost is based on volumes, lower volumes result in a lower total cost. Vaal River Tariff (VRT): This is a legislated tariff. VRT is paid on all water that is sourced from the Vaal River scheme. The Vaal Water system is also the system of last resort. Water is drawn from the Vaal to supplement the other systems. Lower total consumption resulted in lower volumes of water being sourced from this scheme, which resulted in a lower VRT being paid. Pumping costs: Pumping costs are the electricity costs incurred to move water. The lower than planned electricity tariff increases and lower transfers resulted in a saving on the cost of pumping of water within and between water schemes. Waste Discharge Charge: This is a legislated tariff. The implementation of the Waste Discharge Charge has been delayed. It is not certain when the DWA will implement this tariff. Operations and Maintenance: Eskom pays the actual costs incurred by the Department of Water Affairs (DWA). The DWA conducts all repairs and maintenance on the water pipelines and charges the costs to the users. Eskom does not control or manage this maintenance. During FY18, there was under expenditure of R41 million on operations and maintenance. 13.1.5.1 Volume of water The volumes of water consumed are driven primarily by the electricity produced by the power stations. The volume consumed to generate a unit of electricity varies per power station, so the total consumption will depend on the mix of stations used to generate electricity. Older stations consume more per unit. Most of Eskom s stations are beyond the halfway mark of their lifespans. Although the coal fired stations produced less than planned, actual water consumption per unit of electricity was higher at most stations than was expected, as is evidenced in the table below. RCA Year 5 (FY 2017/18) September 2018 Page 70 of 121
Other Primary energy TABLE 27 : WATER CONSUMPTION PER GWH PER POWER STATION ML/GWh Power Station MYPD3 FY18 Actual FY18 Under/(Over) consumption OLDER POWER STATIONS Kendal 0.15 0.25 (0.10) Kriel 2.22 2.33 (0.10) Majuba 1.07 1.01 0.06 Matla 2.03 1.99 0.04 Tutuka 1.97 2.26 (0.29) Duvha 2.00 1.47 0.53 Lethabo 1.85 1.95 (0.10) Matimba 0.14 0.15 (0.01) Arnot 2.16 2.90 (0.73) Hendrina 2.28 3.03 (0.75) REFURBISHED POWER STATIONS Camden 2.55 2.45 0.11 Grootvlei 2.77 1.86 0.91 Komati 4.51 4.49 0.02 The overall water performance at coal fired power stations for FY18 was 1.39 l/uso. Ageing water infrastructure and the delay in commissioning Medupi and Kusile Power Stations resulted in the rate of consumption being higher. Due to lower production, the volume of water consumed was 53 490 ML less than the assumed in the NERSA decision. Water consumption and the variances for FY18 are reflected in Table below. TABLE 28 : WATER CONSUMPTION PER POWER STATION ML Power Station MYPD FY18 Actual FY18 Under/(Over) consumption Medupi 13 299 1 518 11 781 Kusile 9 427-9 427 New Station 22 726 1 518 21 208 Kendal 2 995 6 311-3 316 Kriel 42 633 28 370 14 263 Majuba 16 061 24 601-8 540 Matla 40 159 38 677 1 482 Tutuka 34 015 37 857-3 842 Duhva 35 001 19 059 15 942 Lethabo 43 858 35 479 8 379 Matimba 3 582 3 985-403 Arnot 24 049 29 841-5 792 RCA Year 5 (FY 2017/18) September 2018 Page 71 of 121
Other Primary energy ML Power Station MYPD FY18 Actual FY18 Under/(Over) consumption Hendrina 26 869 23 259 3 610 Old Stations 269 222 247 439 21 783 Camden 16 293 16 586-293 Grootvlei 11 844 6 135 5 709 Komati 15 006 9 923 5 083 RTS Stations 43 143 32 644 10 499 TOTAL 335 091 281 601 53 490 13.1.6 Reasons for fuel procurement costs variance The variance with regards to fuel procurement expenditure was R180 million for the benefit of the consumer. The primary components of fuel procurement expenditure and the reasons for the bulk of the under expenditure are: Manpower costs Manpower costs comprise the bulk of the fuel procurement costs. These costs include all salaries, allowances, company contributions and legislated costs such as workman s compensation and skills development payments. Variance in manpower costs was because of savings initiatives, during which a moratorium was placed on hiring staff. Consulting costs Total consulting related expenditure for the 2018 financial year was a variance of R135 million in favour of the consumer. The variance was primarily due to the studies planned for the Waterberg strategy that did not materialise. Eskom s Waterberg strategy is part of the larger Presidential Infrastructure plan to develop the Waterberg region. At the time of the MYPD3 application, this plan was strongly motivated. There is some uncertainty now regarding whether the project will go ahead. In addition, the business productivity Improvement initiative implemented at Eskom required the business to reconsider strategies and projects, and the use of consultants. This resulted in reductions in operational cost reductions across the business. Legal fees Expenditure on legal fees for the 2018 financial year resulted in a variance in favour of the consumer. Most of this saving was because of the business productivity improvement initiative implemented at Eskom. RCA Year 5 (FY 2017/18) September 2018 Page 72 of 121
Other Primary energy Other Other costs include insurance, marketing and subscriptions to databases that are relevant for the business. These were some of the first costs to be targeted in the business productivity improvement initiative. 13.1.7 Water treatment costs variance The time lag in implementing FGD at Medupi power station has resulted in no sorbent costs being incurred during 2017/18 at that station. However one unit of Kusile (which has FGD) was commissioned resulting in a small amount of sorbent being used in 2017/18. This resulted in a claw back of R237 million in the RCA submission. 13.1.8 Nuclear costs variance According to para 60 of the MYPD3 decision, it was confirmed that the fuel used at Koeberg is wholly imported. Consequently international benchmarks (Rand per kilogram) were used to determine the approved price. The actual nuclear fuel costs were R354 million in favour of Eskom. TABLE 29: NUCLEAR FUEL COSTS 2017/18 Nuclear fuel costs R' million MYPD3 Decision Actuals 2017/18 RCA 2017/18 Nuclear other Nuclear fuel burn U1 Nuclear fuel burn U2 Nuclear spent fuel Eskom MYPD3 Application Nersa disallowed Total Nuclear Fuel costs 32 20-12 447 362-85 356 373 17 20 64 44 856 819-36 -390 0 390 466 819 354 13.1.8.1 Nuclear other Fuel write-off for partially burnt fuel assemblies were less than estimated at the time of the MYPD3 Decision. Also a change in future loading of fuel assemblies and no provision adjustments were made during the 2017/18 financial year. RCA Year 5 (FY 2017/18) September 2018 Page 73 of 121
Other Primary energy 13.1.8.2 Nuclear fuel burn U1 The cost of fresh fuel assemblies loaded after Outage 122 was lower than originally budgeted for due to favourable uranium market prices, leading to a lower cost of recovery of fuel burn every month. 13.1.8.3 Nuclear fuel burn U2 The cost of fresh fuel assemblies loaded after Outage 222 was higher than originally budgeted for, leading to a higher cost of recovery of fuel burn every month. 13.1.8.4 Nuclear spent fuel Changes on the spent fuel asset implemented at the end of 2013/14 increased the amortisation of the fuel assemblies loaded in the core in each outage. 13.1.9 Sorbent costs variance The time lag in implementing FDG at Medupi power station has resulted in no sorbent costs being incurred during 2017/18 thus resulting in a variance in favour of the consumer of R237 million in the RCA balance submission. RCA Year 5 (FY 2017/18) September 2018 Page 74 of 121
Environmental levy 14 Environmental levy The MYPD Methodology allows for (under)/over recovery to be adjusted through the RCA mechanism as presented in the extract below: 13. Taxes and Levies (not income taxes) 13.1 The Government imposes certain taxes and levies that are payable by Eskom. 13.2 Levies are any charges that the Government may impose and payable by Eskom arising from its licensed activity. 13.3 Taxes are any amount arising from an enacted legislation that the Government may require Eskom to pay which amount will be calculated in terms of such legislation. 13.4 Principles regarding taxes and levies 13.4.1 The taxes and levies are exogenous and will be treated as a pass-through cost in the MYPD. 13.4.2 Taxes and levies will be treated as a separate account in the Eskom revenue determination. 13.4.3 Eskom must ensure that the cost of the taxes and levies is specified and that the calculation thereof is clear and concise. 13.4.4 The amount provided for the taxes and levies must be ring-fenced and any over or underrecovery will be recorded in the RCA. Eskom incurred environmental levy costs of R1 685 million less than the MYPD3 determination for 2017/18. The fundamental driver to the variance for the environmental levy is due to a substantial decrease in utilization of coal fired power stations, due to lower sales compared to MYPD3 when compared to the determination made by NERSA in the MYPD 3 decision. The MYPD 3 submission and subsequent NERSA decision was based on an assumption of the levy rate of 3.5c/kWh for the full period. The rate remained unchanged during 2017/18. RCA Year 5 (FY 2017/18) September 2018 Page 75 of 121
Demand Market Participation 15 Demand Market Participation 15.1 Allowed DMP No DMP and power buybacks were allowed in the MYPD 3 decision. TABLE 31: APPROVED DEMAND RESPONSE (DR) EXPENDITURE FOR MYPD3 R'm 2017/18 DMP and Power buy-back Applied for Funding 2 001 Demand Savings (MW) 3 855 R/MW 0.52 DMP and Power buy-back Adjusted Funding -2 001 Demand Savings (MW) -3 855 R/MW 0.52 DMP and Power buy-back Approved Funding - Demand Savings (MW) - Source: Table 36 of MYPD3 decision, 28 February 2013 15.1.1 Actual DMP Demand market participation had a variance of R160 million during the year. TABLE 30: DMP COMPARISON FOR RCA Rand million MYPD3 Decision Actuals RCA 2017/18 Demand Response - 160 160 Nersa has disallowed all revenue related to Demand Market Participation (DMP) in this year of the MYPD decision. The funds for DMP are crucial in ensuring security of supply. DMP is an appropriate lever as it used over short periods, allows the customer the flexibility to make up production at different times of the day and is a lower cost than running open cycle gas turbines. Furthermore, demand response programmes will be needed by the system operator even after a healthy reserve margin is established. This is due to the need to deal with unforeseen events on a daily and hourly basis such as higher than expected demand and plant trips, particularly in view of the technical risks associated with the significant levels of renewable power stations to be connected to the grid. Demand response programmes are RCA Year 5 (FY 2017/18) September 2018 Page 76 of 121
Demand Market Participation considered as best practice for modern system operators and should continue. Thus the costs associated with the DMP programmes were utilised to provide these reliability and security of supply reasons. RCA Year 5 (FY 2017/18) September 2018 Page 77 of 121
Open cycle gas turbines (OCGTs) 16 Open cycle gas turbines (OCGTs) The usage and cost of open cycle gas turbines are allowed as pass through costs subject to prudency review of volumes. The current year volumes exceed that assumed in the MYPD decision as highlighted in section 8.4 of the MYPD Methodology. The MYPD Methodology states that as per para 8.4.1 costs will be allowed as a full passthrough cost, but limited conditional to volumes allowed by the Energy Regulator, except where such use is necessary to ensure security of supply. This situation is further reinforced in para 8.4.2 Capacity constraints shall be mitigated by gas turbine generation as a last resort. For avoidance of doubt, gas turbine generation should be employed before implementation of load shedding activities. Para 8.4.3 any variances in the operation of the gas turbine, the reasonableness of such expenses will be subject to review by the Energy Regulator to determine the efficiency and prudency review in which Eskom has to demonstrate that it has maximised the availability and utilisation of cheaper resources such as Integrated Demand Management (IDM) and Demand Market Participation (DMP). 16.1 Allowed OCGT spend For purposes of its revenue decision, NERSA assumed R1 724 million for OCGT fuel cost from a production of 538GWh. This was based on the assumptions made by Eskom in their MYPD3 application surrounding the timing of new build commissioning dates and Generation plant performance. The energy availability of Eskom fleet, commissioning of new power stations and usage of IPPs have resulted in usage of OCGT being lower as determined in MYPD3 for 2017/18. Therefore a variance of R1396 million for the benefit of the consumer were realised and was included in the RCA balance submission. TABLE 31: OCGT SPEND AND USAGE Open Cycle Gas Turbines (OCGTs) MYPD3 Decision Actuals RCA 2017/18 OCGT costs (R m) 1 724 328-1 396 OCGT volumes (GWh) 538 118-420 RCA Year 5 (FY 2017/18) September 2018 Page 78 of 121
Open cycle gas turbines (OCGTs) The OCGT cost for the year of R328 million comprises diesel burn and storage and demurrage costs 16.1.1 Managing supply-and demand constraints 16.1.1.1 Role of the System Operator The System Operator provides an integrative function for the operation and risk management of the interconnected power system by balancing supply and demand in real time, trading energy internationally and buying energy from IPPs, all of which enable us to supply electricity to our customers in accordance with our mandate. In order to balance and protect the power system, Eskom has to apply demand management practices, which include supply-side and demand-side options. Supply-side options focus on increasing electricity supply, including utilising OCGTs, pumped storage schemes, supply by IPPs as well as international power imports. Demand-side options, which are contingent upon the support of customers, focus on reducing demand, and include demand response programmes which utilise interruptible load agreements, demand side management, energy efficiency initiatives as well as the 5pm to 9pm demand reduction campaign and higher winter tariffs. The System Operator places great focus on risk management to protect the stability of the power system. The various defence systems in place are frequently tested to ensure their effective response capability to prevent a major system event. For many hours of the day, the reserve margin is sufficiently adequate. However, during peak hours or when abnormal events occur, demand at times exceeds supply. When this occurs, Eskom implements demand and supply-side management strategies, including the demand response programme where selected large customers reduce their demand at Eskom s request. As a last resort, Eskom introduces rotational load shedding to protect the integrity of the power system. Failure to do so could lead to a full national power blackout with severe consequences for the country. Clear protocols are in place for the event where the last option is to resort to load shedding. RCA Year 5 (FY 2017/18) September 2018 Page 79 of 121
Open cycle gas turbines (OCGTs) 16.1.2 Actual Plant performance in 2017/18 Eskom is committed to meeting the country s electricity demand and continuously improving generation performance. 16.1.2.1 Operating highlights There were 333 UAGS trips during the year, compared to 444 trips last year Boiler tube failures contributed 1.37% to UCLF, compared to 1.66% last year Two Medupi units (Units 4 and 5) and one Kusile unit (Unit 1) achieved commercial operation during the year Partial load losses have improved, at 3.29% compared to 3.48% in the previous year Eskom is committed to accomplishing the overarching goals of meeting the country s demand and also improve the performance of Generation. This commitment will be fulfilled whilst avoiding load shedding and still conducting regular maintenance on the Generation fleet to sustain improved performance. 16.1.2.2 Generation technical performance Generation s technical operations are assessed in terms of the following: Energy availability factor (EAF), which measures plant availability and takes account of planned and unplanned unavailability and energy losses not under the control of plant management Unplanned capability loss factor (UCLF), which measures unplanned energy losses resulting from equipment failures and other plant conditions Planned capability loss factor (PCLF), which measures energy losses because of planned shutdowns during the period Plant availability (EAF) of 78.00% for the year was realised. The PCLF of 10.35% was undertaken. A UCLF of 10.18% resulted for the financial year. There has been an increasing trend in the last quarter, consistent with seasonal trends. This seasonal performance is attributed to partial load losses improvements. Boiler tube failures have seen a year-on-year improvement. There were 149 boiler tube failures for the year to March 2018, with a contribution of 1.37% to Generation UCLF, compared to 169 failures last year, with a UCLF contribution of 1.66%. RCA Year 5 (FY 2017/18) September 2018 Page 80 of 121
Open cycle gas turbines (OCGTs) During the first half of the financial year, the generation plant performed well and very low usage of open-cycle gas turbines (OCGTs) was required to support the power system. Both Eskom-owned and IPP-owned OCGTs were operated only to meet minimum operating requirements during this period. RCA Year 5 (FY 2017/18) September 2018 Page 81 of 121
Capital expenditure clearing account (CECA) 17 Capital expenditure clearing account (CECA) Capital expenditure variance is monitored through the CECA and the change in regulatory asset base is multiplied by the return on asset percentage awarded in MYPD3 decision. 17.1 Regulated asset base adjustment for CECA Capital expenditure will affect the value of the regulated asset base (RAB). The actual capital expenditure incurred during 2017/18 was R47 527 million compared to the MYPD3 decision assumption of R45 407 million thus resulting in a variance of R2 119 million. However, only R769m of the R2119 million qualifies for adjustment of the RAB in the CECA calculation.the R769 million comprises Generation capex variance in favour of Eskom of R12 003million, Transmission variance by R5 574million and Distribution variance of R5 660 million in favour of the consumer. 17.1.1 Step 1: Computing the qualifying RAB capital expenditure variance The change in RAB is determined in terms of rule 6.7.2.3 as shown below. 6.7.2 To accommodate the unstable environment in which the WUC cost will be undertaken, the approach for adjusting works under construction for cost and timing variances will be as follows: 6.7.2.1 Eskom will annually report to the Energy Regulator on its capital expenditure programme, providing information on timing and cost variances. 6.7.2.2 At the end of each financial year, Eskom will provide the Energy Regulator with a final reconciliation report of the actual works under construction incurred. 6.7.2.3 On receipt, the Energy Regulator will record all efficient works under construction above or below the approved amount on the works under construction carryover account (CECA) and quantify Eskom s exposure. The capital expenditure is adjusted to exclude the following items a) future fuel because it is accounted for as working capital and b) Technical and refurbishment capex as it is not re-measured under the current Methodology. The calculation below reflects an increase of the RAB by the average capital expenditure variance of R384 million (i.e. R769 million divided by 2) for FY2018. RCA Year 5 (FY 2017/18) September 2018 Page 82 of 121
Capital expenditure clearing account (CECA) Table 32: Calculation average capital expenditure CECA Calculation -Variance between actual and allowed capex Calculation Reference Eskom Company Allowed MYPD capital expenditure A 45 407 Less: capital expenditure excluded B 20 066 Future fuel 4 012 Technical and refurbishment capital expenditure 16 054 Allowed RAB capital expenditure A-B 25 342 Actual MYPD capital expenditure C 47 527 Less: capital expenditure excluded D 21 416 Future fuel 1 225 Payment received in advance recognised to revenue 2 383 Technical and refurbishment capital expenditure 17 808 Actual RAB capital expenditure C-D 26 111 Total actual minus total allowed capital expenditure C-A 2 119 Less Variance on capital expenditure excluded D-B 1 350 Variance on RAB capital expenditure E 769 Average capital expenditure difference for CECA calculation E/2 384 Allowed Return - NERSA MYPD3 decision 4.69% RCA Year 5 (FY 2017/18) September 2018 Page 83 of 121
Capital expenditure clearing account (CECA) 17.1.2 Step 2: Computing the CECA Extract from MYPD Methodology: 6.7.3 Balances on the CECA will be adjusted as follows in the Regulatory Clearing Account (RCA) as follows: 6.7.3.1 At the end of the financial year, if there is any under-expenditure compared to forecasted works under construction, the value of the RAB will be adjusted downwards for works under construction not undertaken and the revenues for the subsequent financial year adjusted to compensate for the return earned on unused funds in the previous MYPD. For any over-expenditure approved by the Energy Regulator compared to forecasted works under construction, the balance will be added to the RAB and Eskom will be allowed additional returns on the CECA balance to recover the costs of the over-expenditure for that year. This approach will effectively minimise any potential windfall losses or gains should the approved capital expenditure differ from the actual expenditure. The section below illustrates how the CECA of R925 million is computed by applying the allowed ROA to the capex variance. Table 33: CECA Calculation: Return due to/ (by) Eskom CECA Calculation : Return due to/(by) Eskom Calculation ref Eskom Company MYPD3 Regulatory assets base (RAB) 717 513 Add /(Deduct): Current year average capex variance 384 Add/ (Deduct): Cumulative prior year capex variances 19 322 Adjusted MYPD3 Regulatory assets base (RAB) F 737 220 MYPD3 allowed return on assets (ROA) G 33 667 Return on adjusted RAB F*H 34 592 Increase / (Decrease) in ROA for RCA (F*H)-G 925 MYPD3 allowed return expressed as a percentage of the rate base H 4.69% Note: For purposes of calculating the CECA claim, the allowed RAB of R717 513 million is adjusted for the capex variance of the current year of R384 million and prior year of million R19 322, resulting in an adjusted RAB of R737 220million. RCA Year 5 (FY 2017/18) September 2018 Page 84 of 121
Capital expenditure clearing account (CECA) 17.2 MYPD3 decision Below are extracts from MYPD3 decision reflecting approved RAB of R713bn and returns on asset at 3.88%, generating returns of R27 657 million and assuming a capital expenditure of R46 655 million. TABLE 34: REGULATORY ASSET BASE FOR 2017/18 R'm 2017/18 RAB Applied for 1 043 100 RAB Adjustment -325 587 RAB Approved 717 513 Source: Table 10 of MYPD3 decision, 28 February 2013 TABLE 35: RETURNS AND PERCENTAGE ALLOWED IN 2017/18 R'm 2017/18 Real Pre-tax WACC (%) 4.7% Return (R'm) 33 667 Source: Table 9 of MYPD3 decision, 28 February 2013 TABLE 36: CAPITAL EXPENDITURE IN 2017/18 R'm 2017/18 Capex Applied for 65 000 Capex Adjustment -19 593 Capex Approved 45 407 Source: Table 11 of MYPD3 decision, 28 February 2013 17.3 Reasons for new build higher expenditures 17.3.1 Medupi The variance of R6.5bn is mainly due to the impact of the revision of the forecasted commercial operation date of the last unit from May 2016 to May 2020 (P80). The reason for the revision of the forecasted commercial operation date includes: The impact of initiation of construction prior to complete designs led to design changes and risks being managed during construction Unexpected significant labour unrest added schedule uncertainty and resulted in delay claims and increased costs to resolve labour issues Contractor productivity considerably lower than projected and inconsistent with accelerated project timeline RCA Year 5 (FY 2017/18) September 2018 Page 85 of 121
Capital expenditure clearing account (CECA) Due to the complexity of the mega build projects, ongoing integration challenges between major packages resulting from initial design phase causes changes to scope, unexpected rework, and accompanying delay and cost Absence of fully integrated project and construction schedule meant activities were out of phase resulting in rework, delays and subsequent claims The impact of this delay has resulted in additional expenditure against what was determined in respect of the following cost categories; Basic cost Increase of R1.6bn Escalation Increase of R1.9bn Owners Development Cost (ODC) Increase of R0.8 due to cost incurred but not allowed in the determination Contingency Increase of R2.3bn due to cost incurred but not allowed in the determination as contingency was only limited to 10% of the placed contracts Basic cost and CPA. 17.3.2 Kusile The variance of R11.6bn is mainly due to the impact of the revision of the forecasted commercial operation date of the last unit from Jan 2019 to Sep 2022 (P80). The reason for the revision of the forecasted commercial operation date includes: The impact of initiation of construction prior to complete designs led to design changes and risks being managed during construction Unexpected significant labour unrest added schedule uncertainty and resulted in delay claims and increased costs to resolve labour issues Funding constraints prevent necessary decisions being made and resulted in uncertainty in contract management and the stalling of projects Contractor productivity considerably lower than expected and inconsistent with accelerated project timeline Ongoing integration issues between major packages resulting from initial design phase caused changes to scope, unexpected rework, and accompanying delay and cost Absence of fully integrated project and construction schedule meant activities were out of phase resulting in rework, delays and subsequent claims RCA Year 5 (FY 2017/18) September 2018 Page 86 of 121
Capital expenditure clearing account (CECA) The impact of this change has resulted in additional expenditure against what was awarded in respect of the following cost categories; Basic cost Increase of R4.8bn Escalation Increase of R1.9bn Owners Development Cost (ODC) Increase of R1.6bn of which R0.88bn was due to cost incurred but not allowed in the determination. Contingency Increase of R3.4bn due to cost incurred but not allowed in the determination as contingency was only limited to 10% of the placed contracts Basic cost and CPA. 17.3.3 Kusile Temporary Coal infrastructure The Kusile Temporary Coal Infrastructure project is a new project related to the main Kusile project. The project scope is to construct the long term Kusile Coal Off-loading Facility and related supporting infrastructure, as a mitigation strategy for the permanent coal supply to Kusile Power Station as a result of the unsigned Coal Supply Agreement between Eskom Holdings SOC Limited and Anglo American Inyosi Coal Proprietary Limited 17.3.4 Ingula Pumped Storage Project In the MYPD 3 application for Ingula it was planned for the project to be completed by the 2014/15 financial year. The project was completed in the 2016/17 financial year and the cost in the 2017/18 financial year relates to outstanding work that was done. The reasons for the delay include: Ground conditions in reality differed from the outcome previous studies undertaken Unexpected labour unrest that occurred The fatal accident on the Inclined High Pressure Shaft 3 & 4 on 31 October 2013 resulted in further significant impact due to a work stoppage of the affected area imposed by the Department of Mineral Resources (DMR). This work stoppage was on the section of the plant that was on the critical path of the project schedule and resulted in project delays and late completion of the project. RCA Year 5 (FY 2017/18) September 2018 Page 87 of 121
Capital expenditure clearing account (CECA) 17.4 Owners Development Cost, Contingency and Unplaced Contracts 17.4.1 Owners Development Cost The Owner s Development Cost ( ODC ) refers to Eskom s own project management, project engineering and other resources used in managing the contractors responsible for the build progamme. The capitalisation of ODC on Medupi, Kusile & Ingula was disallowed by NERSA stating that: Eskom has not provided its deduction from the forecasted operating expenditure. Capitalisation of ODC and not reducing operating expenditure by the same amount will result in double counting. ODC incurred during 2017/18 had already been deducted from operating expenditure and capitalised to the projects in line with International Financial Reporting Requirements. Detail of this capitalisation is clarified below. 17.4.2 Contingency Contingency includes a provision for known and unknown risk on both placed and unplaced contracts e.g. contractor claims for delays and variations to contract price & scope. It also provides for risk related to variations in CPA, ODC, and foreign exchange rates. Contingency on Medupi, Kusile & Ingula was limited to 10% by NERSA stating that: The contingency provision applied for by Eskom ranges from 19% to 397% of the indexed basic contracted amounts for each of the respective years. The contingency provision has been limited to 10% of the contracted cost as indexed. The timing of the actual realisation of contingency is not in direct relation to contract basic and can result due to a number of factors e.g. delays due to quality issues, labour unrest, Force Majeure events, poor contractor productivity etc. The realisation of contingency is also higher during the later stages of the project. Contractor claims and variations are subject to thorough assessments and management approval. Significant claims that are under dispute are taken through the Dispute Adjudication Board process. 17.4.3 Unplaced contracts A provision for specific unplaced contract packages is made as part of basic cost. The unplaced contracts estimate on Medupi, Kusile & Ingula was not allowed by NERSA stating that: The unplaced contract cost which together with the associated escalation amounts to RCA Year 5 (FY 2017/18) September 2018 Page 88 of 121
Capital expenditure clearing account (CECA) R3 405m is disallowed. The unplaced contract amount is included in the contingency allowance. The provision for unplaced contract packages is made as part of basic cost and this provision is not provided for in the contingency provision. 17.5 Actual Capital Expenditure As reflected in the annual financial statements, Eskom spends approximately half on new build projects and the other half incurred on the combined portfolio of existing Generation assets, Transmission and Distribution networks. The table below shows the reconciliation of capital expenditure between the integrated report as shown above and amount used in the CECA calculation. TABLE 37: RECONCILIATION OF CAPEX FROM THE INTEGRATED REPORT TO CECA DISCLOSURES Capital Expenditure, R million Actuals 2017/18 Total Eskom Group Capex per Integrated Report 48 003 Exclude : Eskom Enterprises -476 Total Capex for CECA disclosure 47 527 Detailed extract of capital expenditure of R47.5 billion is disclosed in table below. TABLE 38: CAPITAL EXPENDITURE (EXCLUDING CAPITALISED BORROWING COSTS) PER LICENSEE Division, R million Actual Actual Actual 2017/18 2016/17 2015/16 Group Capital 29 278 35 458 33 799 Generation 9 746 14 376 11 440 Transmission 807 940 998 Distribution 5 170 5 220 5 490 Subtotal 45 001 55 994 51 727 Future fuel 1 226 114 2 114 Eskom Enterprises 476 1 107 373 Other areas including intergroup eliminations 1 300 2 817 3 138 Total Eskom group funded capital expenditure 1 48 003 60 032 57 352 1. Capital expenditure includes additions to property, plant and equipment, intangible assets and future fuel, but excludes construction stock and capitalised borrowing costs. RCA Year 5 (FY 2017/18) September 2018 Page 89 of 121
Inflation adjustment 18 Inflation adjustment In compiling the inflationary adjustment, cost of cover, arrear debts (net impairment loss) and EEDSM are excluded in the computation. Operating costs are subject to an adjustment for inflation as per paragraph 14.1.1 in the MYPD Methodology. The consumer price index (CPI) is used to determine the rate of inflation for purposes of these adjustments. The adjustment corrects the assumption on inflation that went into the revenue determination, with the actual inflation during the period. In other words, the costs assumed in the decision are restated using the actual inflation over the period, and compared with the costs allowed at the time of the determination. TABLE 39: INFLATION DATA Inflation data 2013/14 2014/15 2015/16 2016/17 2017/18 Inflation CPI - Decision 5.60% 5.60% 5.60% 5.60% 5.60% Inflation index - Decision 1.056 1.115 1.178 1.244 1.313 Inflation CPI - Actual 5.70% 6.10% 4.60% 6.40% 6.00% Inflation index - Actual 1.057 1.121 1.173 1.248 1.323 The qualifying expenses of R45 837 million for the inflation calculation comprise employee benefits cost of R23 578 million and other operating costs of R22 259 million. Refer to the table below for the Inflation RCA application. Qualifying expenses excludes arrear debts, EEDSM, costs of cover and ancillary services as they are treated separately for RCA purposes. TABLE 40 : INFLATION ADJUSTMENT Inflation adjustment for 207/18 Calculation ref 2017/18 Total operating costs allowed A 45 837 Decision inflation index B 1.313 Actual inflation index C 1.314 Restated allowed costs based on actual inflation D=A/B*C 45 876 Inflation adjustment R'm D-A 39 RCA Year 5 (FY 2017/18) September 2018 Page 90 of 121
Inflation adjustment Due to the actual compounded CPI index of 1.314 in 2017/18 being higher than allowed compounded CPI index of 1.313, this results in an inflation adjustment of R39 million in favour of the Eskom. RCA Year 5 (FY 2017/18) September 2018 Page 91 of 121
Energy efficiency and demand side management (EEDSM) 19 Energy efficiency and demand side management (EEDSM) 19.1 Actual EEDSM IDM has focused on the realisation of energy and demand savings within the evening peak, utilising ESCO related projects in the industrial, mining and commercial sectors of the economy, in addition to hot water load management and energy-efficient lightings projects (compact fluorescent lamps or LEDs) within the municipal residential environment. The demand for electricity was significantly lower than the levels anticipated at the time of preparing the MYPD3 submission. In view of this, as well as the operating reserve margin on the system at the time, Eskom s Executive Committee took a decision on 2 March 2017 to revise the FY18 EEDSM target from 415 MW to a more appropriate target of 110 MW. Furthermore the emphasis was on the peak-demand reduction projects rather than on high load factor energy efficiency projects. The total evening peak demand savings achieved (verified as per performance assessment reports) for FY2018 were 41.87 MW against the NERSA determination of 415 MW and the revised Eskom savings of 110 MW. This resulted in Eskom incurring a penalty of R1 118 million that is included in the RCA as calculated in Table below. RCA Year 5 (FY 2017/18) September 2018 Page 92 of 121
Energy efficiency and demand side management (EEDSM) TABLE 41: DEMAND AND ENERGY SAVINGS AS PER TABLE 1 AND TABLE 2 IN THE IDM ANNUAL REPORT FOR FY2018 The total capacity verified for 2017/18 of 41.87 MW is used for the RCA calculation. 19.2 Extracts from the MYPD Methodology The MYPD Methodology deals with demand side management and demand market participation separately with their respective rules. The energy efficiency demand side management is disclosed below: IDM 11.1.1.8 IDM will incur penalties for under achieving their targets. In case of non-performance, the penalty will be calculated as follows: Penalty(R) = total allowed revenue /projected MW target X MW unsaved = R/MW X MW unsaved EEDSM performance is computed on verified MW savings. 19.2.1 Allowed EEDSM for 2017/18 The allowed EEDSM costs, MWs and the associated rate are shown in the table below. RCA Year 5 (FY 2017/18) September 2018 Page 93 of 121
Energy efficiency and demand side management (EEDSM) TABLE 42: THE ALLOWED EEDSM COSTS EEDSM 2017/18 Approved Funding 1 244 Programmes Peak Demand savings (MW) 415 Programmes Annualised Energy savings (GWh) 2 132 Programme Costs 834 Operating Costs including Depreciation 410 Other costs - R/MW 3.00 R/kWh 0.58 Source: Table 40 of MYPD3 decision, 28 February 2013 Based on the EEDSM actual performance, Eskom has incurred a penalty for not meeting allowed capacity savings as calculated in the table below. TABLE 43: EEDSM COMPARISON FOR RCA IN 2017/18 Energy Efficiency & Demand Side Management (EEDSM) Unit Decision 2017/18 Actuals 2017/18 Variance Funding (A) R'm 1 244 142-1 102 Programme costs R'm 834 21-813 Operating costs incl. depreciation R'm 410 107-303 Other costs R'm - 13 13 Annualised energy savings GWh 2 132 134-1 998 Programmes - Peak Demand savings (B) MW 415 42-373 EEDSM Rate (A/B) R/MW 3.00 3.39 RCA Penalty = Variance in MW's x Decision EEDSM rate R'mill -1 118 Due to Eskom not meeting capacity savings in line with the NERSA decision an amount of R1118 million is included in the RCA submission for the benefit of the consumer. RCA Year 5 (FY 2017/18) September 2018 Page 94 of 121
Operating costs 20 Operating costs Operating costs comprises employee benefits, maintenance and other operating costs. It excludes IDM which is treated separately for RCA purposes. Operating costs 14.1.1 The nominal estimates of the regulated entity will be managed by adjusting for changes in the inflation rate. 14.1.4 Adjusting for prudently incurred under-expenditure on controllable operating costs as may be determined by the Energy Regulator. 20.1 Allowed operating costs in 2017/18 The total operating cost allowed is R47 764 million as shown below. TABLE 44: TOTAL OPERATING COST ALLOWED Allowed operating costs R'million 2017/18 Note Ref Employee benefits 23 578 1 Other Opex 22 259 2 Other Income 0 Net Impairment loss 1 442 3 Cost of cover 485 4 Total 47 764 RCA Year 5 (FY 2017/18) September 2018 Page 95 of 121
Operating costs Note 1: Allowed employee benefits TABLE 45: EMPLOYEE BENEFITS ARE RECONCILED AS FOLLOWS Employee benefits allowed R'million 2017/18 Note Ref Total GTD 20 225 A Add : Corporate 3 353 Corporate Overheads 4 122 B Less: Corporate depreciation -769 C Total Employee Benefits allowed 23 578 Reference A: Total GTD allowed employee benefits per NERSA decision TABLE 46: THE ALLOWED EMPLOYEE COSTS FOR GENERATION, TRANSMISSION AND DISTRIBUTION R'm 2017/18 Manpower Applied for 24 977 Manpower Adjustments -4 752 Approved Manpower 20 225 Source: Table 43 of MYPD3 decision, 28 February 2013 Reference B: Total corporate overheads allowed TABLE 47: ALLOWED CORPORATE COSTS IN 2017/18 R'm 2017/18 Corporate overheads Applied for 7 876 Corporate overheads Adjustments -3 754 Approved Corporate overheads 4 122 Source: Table 51 of MYPD3 decision, 28 February 2013 The R4 122 million above includes R769 million in respect of corporate depreciation which is reallocated from corporate overheads to depreciation. Reference C: Corporate depreciation The total allowed corporate depreciation over the MYPD 3 period is R 3 902 million. Refer paragraph 112 from the NERSA decision below. RCA Year 5 (FY 2017/18) September 2018 Page 96 of 121
Operating costs TABLE 48: THE DEPRECIATION PER ANNUM IS REFLECTED IN THE TABLE BELOW. Total Corporate depreciation allowed R'million 2013/14 2014/15 2015/16 2016/17 2017/18 Total MYPD3 Corporate depreciation 434 678 930 1 091 769 3 902 Note 2: Other opex Other operating costs of R22 259 million (R14 812+7 446m) comprises repairs and maintenance and other costs as shown below. TABLE 49: ALLOWED MAINTENANCE COSTS R'm 2017/18 Maintenance Applied for 16 664 Maintenance Adjustments -1 852 Approved Maintenance 14 812 Source: Table 44 of MYPD3 decision, 28 February 2013 TABLE 50: OTHER COSTS R'm 2017/18 Other costs Applied for 17 777 Other costs Adjustments -10 331 Approved Other costs 7 446 Source: Table 50 of MYPD3 decision, 28 February 2013 Note 3: Net impairment loss (Arrear debt) TABLE 51: ALLOWED ARREAR DEBTS R'm 2017/18 Arrear Debt Applied for 1 511 Arrear Debt Adjustments -69 Approved Arrear Debt 1 442 Source: Table 49 of MYPD3 decision, 28 February 2013 Note 4: Cost of cover TABLE 52: ALLOWED COST OF COVER R'm 2017/18 Cost of Cover applied for 485 Cost of Cover adjustments - Approved Cost of Cover 485 Source: Table 48 of MYPD3 decision, 28 February 2013 RCA Year 5 (FY 2017/18) September 2018 Page 97 of 121
Operating costs 20.2 Allowed vs Actual operating costs During 2017/18, Eskom incurred operating costs (excluding IDM) of R51 892 million which compares to the MYPD3 assumption of R47 764 million resulting in a variance of R4 128 million. Eskom operating costs don t qualify for the RCA adjustment except for the inflation adjustment. Actual operating costs are presented in Annexure 1 and Annexure 5. TABLE 53: SUMMARY OF OPERATING COSTS IN 2017/18 Operating Costs R'millions Allowed AFS actuals Variance Regulatory adjustment RCA actuals RCA balance Employee benefits Other opex Other income Net impairment loss 23 578 24 455 877-92 24 363 785 22 259 25 598 3 339-66 25 532 3 273 - -1 787-1 787-20 -1 807-1 807 1 442 528-914 3 277 3 805 2 363 Cost of cover 485 - -485 - - -485 Total Operating Costs R'millions 47 764 48 794 1 030 3 098 51 892 4 128 20.3 Variances in operating costs 20.3.1 Employee benefits Actual staff costs vary from the MYPD3 decision due to Higher salary settlement compared to decision assumption of 5.6%, and Starting point for the staff costs base being referenced to MYPD2 decision. The difference in staff costs is attributable to the starting point where NERSA used the MYPD2 revenue decision, made in 2009, as their reference for making the MYPD3 decision. Allowance was not made for the changes that occurred between the MYPD2 revenue decision and the actuals during MYPD2. Hence the starting point was too low, thus contributing to the difference included in the RCA. RCA Year 5 (FY 2017/18) September 2018 Page 98 of 121
Operating costs TABLE 54: TREND IN GROSS EMPLOYEE BENEFITS Actual employee costs 2013/14 2014/15 2015/16 2016/17 2017/18 Net employee costs (before capitalisation) 22 384 22 187 24 721 27 902 24 455 Employee costs capitalised to assets 5 685 6 404 3 266 3 655 3 201 Gross employee costs R'm) 28 069 28 591 27 987 31 557 27 656 Growth in gross employee benefits 8.7% 1.9% -2.1% 12.8% -12.4% Gross employee benefits have averaged 2% per annum over the last 5 years. 20.3.2 Maintenance Overall Eskom underspent on maintenance. Generation and Transmission maintenance exceeded the MYPD3 decision whilst Distribution maintenance was underspent. For purposes of the MYPD3 revenue decision, NERSA did substantially base its assumptions regarding maintenance cost on the amounts as estimated by Eskom in its revenue application. 20.3.3 Arrear debt Arrear debt refers only to overdue amounts, excluding interest, and is not the total amount due. Debt collection in the municipal and residential segments remains a significant challenge, although the rollout of smart prepaid meters is assisting in improving revenue recovery. Management of energy protection and revenue losses, through Operation Khanyisa and other initiatives are ongoing. 20.4 Other Income 20.4.1 Actual other income in 2017/18 In the course of Eskom operations in 2017/18, Eskom generated total other income of R1787 million which is shown in the table below: RCA Year 5 (FY 2017/18) September 2018 Page 99 of 121
Operating costs TABLE 55 : OTHER INCOME FOR 2017/18 20.4.2 Principles for treatment of other income in the RCA The principle used for the treatment of other income for RCA purposes is based on whether the other income has a corresponding cost item which qualifies for RCA adjustments. In the event where the other income component represents credits for operating cost items which do not qualify for RCA purposes, then the other income similarly does not qualify for RCA inclusions. This principle was implemented by NERSA in their RCA 2013/14 decision as the extract disclosed below, Source: Paragraph 103, NERSA 2013/14 RCA decision 20.5 Based on the precedent above, other income does not qualify for inclusion in the RCA operating cost variance for 2017/18 RCA Operating cost variance = Actual operating costs Allowed operating costs Based on RCA equivalent actual operating costs of R51 892 million and allowed other operating costs in the decision of R47 764 million, Eskom has incurred an additional R4 128 million during the year. In terms of the MYPD Methodology Eskom cannot submit these additional expenses for RCA purposes and have thus absorbed the variance. It is Eskom s opinion that this non-symmetrical treatment of variances such as in the case of operating costs is not in line with sound regulatory practice. RCA Year 5 (FY 2017/18) September 2018 Page 100 of 121
Service Quality Incentives 21 Service Quality Incentives NERSA has approved the targets for service quality incentives for Distribution and Transmission as below. NERSA is currently developing service quality incentives for Generation. Transmission plans, operates and maintains our transmission assets, while Distribution network relays electricity from the high-voltage transmission network to customers, including municipalities that manage their own distribution networks. TABLE 56: TRENDS IN NETWORKS PERFORMANCE Measure and unit Actual 2017/18 Actual 2016/17 Actual 2015/16 Number of system minutes lost < 1 minute, miuntes SC 2.09 3.8 2.4 Number of major incidents >1 minute, number 0 0 1.0 System average interruption frequency index (SAIFI), events SC 18.7 18.9 20.5 System average interruption duration index (SAIDI), hours SC 38.80 38.9 38.6 Note: One system minute is equivalent to interrupting the entire South Africa at maximum demand for one minute. TABLE 57 : SUMMARY OF SQI PERFORMANCE IN 2017/18 Licensee Service Quality Incentives (SQI) Incentive/ (Penalty) 2017/18 Distribution SQI Incentive 292 Transmission SQI Incentive 99 Total SQI for 2016/17 (R'millions) Incentive 390 21.1 Transmission service quality incentives (SQI) for 2017/18 Eskom Transmission Service Quality Incentive Scheme Results with NERSA comprises of the following 3 measures: - System Minutes (<1) - Number of Major Incidents (SM>1) - Line Faults / 100 km RCA Year 5 (FY 2017/18) September 2018 Page 101 of 121
Service Quality Incentives The performance results for these measures as reported in the Eskom Integrated reports for the financial years 2017/18 has been finalized and the subsequent financial reward / penalty based on these results has been computed. The SQI reflects a net reward of R99 million for 2017/18. TABLE 58: TRANSMISSION SQI PERFORMANCE IN 2017/18 Transmission Service Quality Incentives (SQI) Performance result Incentive/ (Penalty) R'm SM<1 2.09 40 Major incidents 0 40 Line faults / 100km 1.86 19 Total Transmission SQI for 2017/18 (R'm) 99 FIGURE 9: TRANSMISSION SYSTEM MINUTES (<1) RCA Year 5 (FY 2017/18) September 2018 Page 102 of 121
Service Quality Incentives TABLE 59: TRANSMISSION NUMBER OF MAJOR INCIDENTS (>1SM) Number of Major Incidents (>1SM) Incentive (Rm) Major Incidents (No) R 40 0 2018=0 R 20 1 R 0 2 R -20 3 R -40 4 FIGURE 10: LINE FAULTS /100KM 21.2 Distribution Service Quality Incentive Scheme (SQI) for 2017/18 The Energy Regulator, at its meeting held on 28 October 2014, approved the Distribution Service Quality Incentive Scheme (SQI) for the third Multi-Year Price determination (MYPD3). The Distribution SQI had been designed to encourage Distribution to earn additional revenue for improved performance levels but also to penalize Distribution for deteriorating performance levels. The Distribution SQI for MYPD3 comprises of 3 measures: System Average Interruption Duration Index (SAIDI) RCA Year 5 (FY 2017/18) September 2018 Page 103 of 121
Service Quality Incentives System Average Interruption Frequency Index (SAIFI) Distribution Supply Loss Index (DSLI). The value of the scheme was set at 1% of the allowed revenue requirements for Distribution. The total value of the scheme is limited to R291.80m per annum and a total of R1 459bn over the five-year control period. The SADI and SAIFI performance have shown on-going improvements during 2017/18 of MYPD3 and earned incentive rewards as indicated in the table below. The DSLI performance has improved from 2014/15 resulting in no penalty being incurred. The net impact of the SQI performance is positive for Eskom. The outcome of the SQI performance is summarised in the table below. TABLE 60: DISTRIBUTION SQI PERFORMANCE IN 2017/18 Distribution Service Quality Incentives (SQI) Incentive/ (Penalty) 2017/18 SAIDI Incentive 145.9 SAIFI Incentive 116.7 DSLI Incentive 29.2 Distribution total SQI (R'millions) Incentive 291.8 RCA Year 5 (FY 2017/18) September 2018 Page 104 of 121
Reasonability tests 22 Reasonability tests 22.1 EBITDA-To-Interest Cover Ratio (EBITDA / Interest Payments) Para 31 of the MYPD3 decision states that: The allowed returns will enable Eskom to meet its debt obligations. The figure below illustrates that Eskom s Earnings Before Interest Depreciation Tax & Amortisation (EBIDTA)-To-Interest cover ratio is more than 2 times at the end of MYPD3 control period. FIGURE 11: EBITDA-TO-INTEREST COVER RATIO The figure above reflects a ratio of approximately 2.4 for 2017/18. If the above NERSA definition is applied to the actual results for the 2017 financial year, the ratio is as follows: TABLE 61: EBITDA COVER EBITDA Interest Cover Calculation Reference 2017/18 EBITDA Interest Cover A/B 1.57 EBITDA A 43 428 Interest B 27 729 Reference A: 2018 Annual financial statements, Company Income statement (see Annexure 1) Reference B: 2018 Annual financial statements, Note 41 (see Annexure 4) The reasonableness test has been conducted to highlight the need for the RCA adjustment as demonstrated by the actual EBITDA to Interest Cover ratio being below MYPD3 decision assumption. RCA Year 5 (FY 2017/18) September 2018 Page 105 of 121
Conclusion 23 Conclusion Eskom s approach to RCA 2017/18 was based on the MYPD Methodology (published December 2012) and the NERSA RCA 2013/14 reasons for decision which was published on 29 March 2015. This RCA submission adopts the principles utilised by NERSA in making their decision especially when it refers to the treatment of revenue. Eskom believes that this application will contribute towards Eskom and NERSA achieving closer alignment with respect to the RCA process and outcomes. Eskom s revenue is determined by NERSA through a revenue application process and the RCA process which this submission addresses. The RCA is meant to ensure that Eskom can recover its full efficient costs as the actual realities have occurred differently than that assumed during the MYPD3 decision. In this RCA submission of R21 541 million, Eskom is applying for the following for the benefit of the consumer - R2 937 million for coal burn, R1 396 million for OCGTs, R1 718m million for IPP s, R1 685 million for environmental levy, R1 122 million with respect to the ECS adjustment and R1118 million for EEDSM. Eskom is applying for a total of R4 622 million consisting of other primary energy R810 million, DMP of R160 million, international purchases of R2298 million, CECA of R925 million and other components of R429 million. Thus revenue related to a net cost of R5 354 million offsets the balance attributable to the revenue under recovery of R26 895 million linked to lower sales volumes. Eskom has not applied for the variance of R4 128 million relating to operating costs as these costs don t qualify for the RCA resulting in Eskom absorbing the entire variance as the MYPD Methodology does not cater for symmetrical treatment of operating costs. Finally, a reasonableness test has been conducted to highlight the need for the RCA adjustment as demonstrated by the actual EBITDA to Interest Cover ratio being below MYPD3 decision assumption. The MYPD Methodology states that risk of excess or inadequate returns is managed in terms of the RCA. >>>>>>>>>>>>>>>>>>>>>>>>>>>>>>>> END >>>>>>>>>>>>>>>>>>>>>>>>>>>>>>>> RCA Year 5 (FY 2017/18) September 2018 Page 106 of 121
Annexures: Annexures: Revenue: Annexure 1: Income Statement in AFS 2018, page 23 RCA Year 5 (FY 2017/18) September 2018 Page 107 of 121
Annexures: Annexure 2: The Eskom energy wheel (Eskom Intergrated Report) **Note: All figures are in GWh unless otherwise stated. RCA Year 5 (FY 2017/18) September 2018 Page 108 of 121
Annexures: Annexure 3:Sales volumes GWh Statistical tables for 2017/18 RCA Year 5 (FY 2017/18) September 2018 Page 109 of 121
Annexures: Annexure 4 : Electricity Revenue by Customer category Intergrated Report 2017/18 RCA Year 5 (FY 2017/18) September 2018 Page 110 of 121
Annexures: Reasonability test Annexure 4: Finance income note 40 and Finance cost note 41 (Extracts AFS March 2018, page 91) RCA Year 5 (FY 2017/18) September 2018 Page 111 of 121
Annexures: Operating expenses Annexure 5: OPEX note 38 extract from AFS March 2018 page 90 RCA Year 5 (FY 2017/18) September 2018 Page 112 of 121