Kulawula House PO Box 40343 Tel: +27(0)12 401 4600 526 Madiba Street Arcadia 0007 Fax: +27(0)12 401 4700 Arcadia 0083 Pretoria Email: info@nersa.org.za Pretoria, SOUTH AFRICA SOUTH AFRICA www.nersa.org.za @NERSA_ZA @NERSAZA 1. SUBJECT The publication of Eskom’s third Multi-Year Price Determination (MYPD3) Regulatory Clearing Account (RCA) Year 2 (2014/15), Year 3 (2015/16) and Year 4 (2016/17) applications. 2. PURPOSE The purpose of this publication is to request stakeholders and affected parties to submit comments on Eskom’s MYPD3 RCA Year 2 (2014/15), Year 3 (2015/16) and Year 4 (2016/17) applications and indicative timelines for the determination process. 3. INTRODUCTION AND BACKGROUND The National Energy Regulator of South Africa (NERSA) is a regulatory authority established as a juristic person in terms of Section 3 of the National Energy Regulator Act, 2004 (Act No. 40 of 2004). NERSA’s mandate is to regulate the electricity, piped-gas and petroleum pipelines industries in terms of the Electricity Regulation Act, 2006 (Act No. 4 of 2006), Gas Act, 2001 (Act No. 48 of 2001) and Petroleum Pipelines Act, 2003 (Act No. 60 of 2003). NERSA has received Eskom’s MYPD3 RCA Year 2 (2014/15), Year 3 (2015/16) and Year 4 (2016/17) applications totalling R66.6bn. 4. ANALYSIS OF ESKOM’S REVENUE APPLICATION FOR 2018/19 The Energy Regulator will assess Eskom’s application following due regulatory processes. The indicative timeline for the decision-making process is provided in Table 1 below. Table 1: Indicative Timeline (Subject to change) Activity Timeframe 1. Publish Eskom’s applications on NERSA website for stakeholder comments 23 January 2018 2. Closing date for stakeholder comments 23 March 2018 3. Public Hearings on RCAs – 2 nd , 3 rd & 4 th year MYPD3 (9 provinces in 3 weeks) 7 – 25 May 2018 (see details in Table 2) 4. NERSA’s Electricity Subcommittee (ELS) to consider draft Reasons for Decision 6 August 2018 5. Energy Regulator decision on Eskom’s RCA applications 29 August 2018 The planned dates for the public hearings on this matter are provided in Table 2 below and are subject to change. Table 2: Proposed public hearing dates and venues* PROVINCE DATE Western Cape 7 May 2018 Eastern Cape 9 May 2018 KwaZulu-Natal 11 May 2018 North West 14 May 2018 Northern Cape 16 May 2018 Free State 18 May 2018 Mpumalanga 21 May 2018 Limpopo 23 May 2018 Gauteng 25 May 2018 *The dates of the public hearings are subject to review depending on the number of presenters that register. Venues will be communicated in due course. Eskom’s RCA applications are available on the NERSA website at www.nersa.org.za. Stakeholders are requested to comment in writing on Eskom’s applications. Written comments can be forwarded to mypd@nersa.org.za, hand-delivered to 526 Madiba Street, Arcadia, Pretoria or posted to PO Box 40343, Arcadia, 0083, Pretoria, South Africa. The closing date for the submission of comments is 23 March 2018 at 16:00. Members of the public and stakeholders who wish to attend or present their views at any of the public hearings must submit their request to publichearings@nersa.org.za by 15:30 on 19 April 2018. For more information and queries on the above, please contact Ms Lehuma Masike or Mr Dumisani Njezula on 012 401 4600 or via Facsimile on 012 401 4700. --- Document Separator --- MYPD 3 (Year 2014/15) Regulatory Clearing Account Submission to NERSA 13 May 2016 MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 TABLE OF CONTENTS 1 PREFACE ....................................................................................................................................... 12 1.1 The basis of submissions ........................................................................................................ 12 1.2 The structure of 2014/15 RCA Submission ............................................................................. 13 2 OBJECTIVE ................................................................................................................................... 15 3 OVERVIEW OF THE 2014/15 RCA SUBMISSION ....................................................................... 16 3.1 Revenue ...................................................................................................................................... 17 3.2 Primary energy .......................................................................................................................... 17 3.3 Environmental levy ................................................................................................................... 17 3.4 Phased nuclear decommissioning provision per MYPD3 RCA 2013/14 decision .............. 17 3.5 International electricity purchases .......................................................................................... 17 3.6 Capital expenditure variance ................................................................................................... 18 3.7 Operating costs ......................................................................................................................... 18 3.8 Integrated demand management ............................................................................................. 18 3.9 Other income ............................................................................................................................. 18 3.10 Inflation adjustments ............................................................................................................. 19 3.11 Service Quality Incentives (SQI) ........................................................................................... 19 3.12 Reasonableness test ............................................................................................................. 19 3.13 Comparison of RCA 2014/15 submission to RCA 2013/14 decision ................................. 19 3.14 Conclusion .............................................................................................................................. 20 4 FACTORS IMPACTING ON 2014/15 RCA SUBMISSION ............................................................ 21 MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 4.1 Timeline for application and decision ..................................................................................... 21 4.2 Changes in fundamental assumptions since MYPD3 application ....................................... 22 5 REVENUE VARIANCE .................................................................................................................. 24 6 MYPD METHODOLOGY ................................................................................................................ 24 7 CALCULATION OF THE REVENUE VARIANCE ......................................................................... 24 7.1 Revenue computed on an equivalent basis ........................................................................... 25 7.2 Allowed Revenue ....................................................................................................................... 28 7.3 Sales volumes contribute to recovery of fixed costs ............................................................ 29 7.4 Volumes: Allowed vs Actuals .................................................................................................. 30 7.5 Sales volume variance explanation ......................................................................................... 31 7.5.1 The process in deriving the 5 year forecast .................................................................... 32 7.5.2 Critical assumptions relevant during 2011 in deriving forecasts .................................. 32 7.5.3 Sales volume variance explanation for FY2015 ............................................................... 33 8 CONCLUSION OF REVENUE VARIANCE ................................................................................... 37 9 IMPACT OF DEMAND RESPONSES ON SALES VOLUMES ..................................................... 37 10 COLLECTABILITY OF REVENUE DOES NOT IMPACT RCA ................................................. 37 11 RCA IMPLEMENTATION RISKS ............................................................................................... 38 12 PRUDENCY AND EFFICIENCY ................................................................................................. 38 13 FACTORS WHICH INFLUENCE ESKOM PRODUCTION PLANS ........................................... 40 14 PRIMARY ENERGY .................................................................................................................... 41 14.1 Primary energy variances and RCA impact for 2014/15 .................................................... 41 MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 15 INDEPENDENT POWER PRODUCERS .................................................................................... 44 15.1 Medium-term Power Purchase Programme (MTPPP) ........................................................ 44 15.2 Municipal Base-load Purchases ........................................................................................... 44 15.3 Short-term Power Purchases Programme (STPPP) ........................................................... 44 15.4 Wholesale Electricity Pricing System (WEPs) programme ............................................... 44 15.5 Long-term IPP programmes .................................................................................................. 45 15.5.1 IPP open cycle gas turbine (“Peaker”) programme ..................................................... 45 15.5.2 Renewable Energy Independent Power Producer (RE-IPP) procurement programme 45 15.6 Legal basis for IPPs per the MYPD Methodology ............................................................... 46 15.7 IPP Approvals ......................................................................................................................... 46 15.8 Regulatory rules for power purchase cost recovery .......................................................... 47 15.9 IPP allowed costs for 2014/15 ............................................................................................... 47 15.10 Actual IPP costs for 2014/15 ................................................................................................. 47 15.10.1 Reasons for IPP variances in 2014/15 ........................................................................... 49 15.11 IPP variance for 2014/15 RCA ............................................................................................... 51 16 INTERNATIONAL PURCHASES ............................................................................................... 52 16.1 Regional IPPs - Aggreko ....................................................................................................... 52 17 COAL BURN COSTS ................................................................................................................. 54 17.1 Extract of MYPD Methodology on Coal adjustments ......................................................... 54 17.2 NERSA’s decision on coal benchmark and alpha .............................................................. 55 17.3 Coal cost – RCA 2015 calculation ........................................................................................ 56 17.3.1 Step 1 – Calculate the performance base regulation cost allowance ............................... 56 17.3.2 Step 2 – Calculate the pass through coal burn costs ....................................................... 57 MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 17.3.3 Step 3 – Split the pass through coal burn cost into volume variance and price variance summarised below. ............................................................................................................................ 57 17.4 Coal burn cost variance explanations ................................................................................. 59 17.4.1 Lower electricity production from coal fired stations ................................................. 59 17.4.2 Different mix and efficiency of power stations generating electricity ....................... 60 17.5 Coal Purchases ...................................................................................................................... 60 17.5.1 Eskom’s coal costs contracts ........................................................................................ 60 17.5.2 Coal cost variance ........................................................................................................... 63 17.5.3 Medupi Take or Pay payment ......................................................................................... 64 17.5.4 Kusile Risk Sharing Agreement ..................................................................................... 65 18 OTHER PRIMARY ENERGY ...................................................................................................... 66 18.1 Allowed other primary energy in 2014/15 ............................................................................ 66 18.1.1 Allowed other primary energy costs for 2014/15 ......................................................... 66 18.2 Actual other primary energy in 2014/15 ............................................................................... 66 18.2.1 Reasons for start-up gas and oil costs variance ......................................................... 67 18.2.2 Reasons for coal handling costs variance ................................................................... 68 18.2.3 Reasons for water costs variance ................................................................................. 69 18.2.4 Reasons for fuel procurement costs variance ............................................................. 70 18.2.5 Nuclear costs variance ................................................................................................... 70 18.2.6 Water treatment costs variance ..................................................................................... 70 18.3 Other primary energy variance in 2014/15 RCA .................................................................. 71 19 ENVIRONMENTAL LEVY ........................................................................................................... 72 20 DEMAND MARKET PARTICIPATION ....................................................................................... 73 20.1.1 Allowed DMP in 2014/15 .................................................................................................. 73 20.1.2 Actual DMP in 2014/15 .................................................................................................... 73 20.1.3 Computation of DMP variance for RCA in 2014/15 ...................................................... 74 21 OPEN CYCLE GAS TURBINES (OCGTS) ................................................................................ 75 21.1 Reasons for OCGTs variance ............................................................................................... 75 MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 21.2 Balancing the power supply system .................................................................................... 76 21.2.1 Actual OCGTs usage and load shedding in 2014/15.................................................... 76 21.3 OCGTs allowed in MYPD 3 for 2014/15 ................................................................................ 77 21.4 Actual OCGTs costs in 2014/15 ............................................................................................ 78 21.5 Computation of OCGTs claim for RCA purposes in 2014/15............................................. 78 21.5.1 Price impact up to allowed diesel litre usage of 297ML (million litres) ..................... 79 21.5.2 Excess volumes above GWh recovered at average coal costs .................................. 80 21.5.3 Recovery of the 450 GWh for January 2015 to March 2015 ........................................ 80 21.5.5 Actual Plant performance in 2014/15 ............................................................................. 82 22 CAPITAL EXPENDITURE CLEARING ACCOUNT (CECA) ..................................................... 87 22.1 Regulated asset base adjustment for CECA ....................................................................... 87 22.1.1 Step 1: Computing change in RAB ................................................................................ 87 22.1.2 Calculation of the CECA claim ....................................................................................... 89 22.2 MYPD3 decision ..................................................................................................................... 90 22.3 Reasons for variance between actual and decision ........................................................... 91 22.4 Delivering on capital expansion ........................................................................................... 92 22.4.1 Medupi .............................................................................................................................. 93 22.4.2 Kusile ................................................................................................................................ 94 22.4.3 Ingula ................................................................................................................................ 95 22.5 New build cost changes ........................................................................................................ 96 22.5.1 Medupi: Cost overruns ................................................................................................... 96 22.5.2 Kusile : Cost overruns .................................................................................................... 96 22.5.3 Ingula : Cost variances ................................................................................................... 97 22.5.4 Delays in new build capacity .......................................................................................... 97 22.6 Why the RAB must be indexed ........................................................................................... 100 22.7 Conclusion on capital expenditure .................................................................................... 101 23 INFLATION ADJUSTMENT ...................................................................................................... 103 MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 24 ENERGY EFFICIENCY AND DEMAND SIDE MANAGEMENT (EEDSM) .............................. 104 24.1 Demand side management ................................................................................................. 104 24.1.1 The demand-response programme ............................................................................. 104 24.1.2 The Residential mass roll-out programme ................................................................. 104 24.2 Energy-efficiency measures ............................................................................................... 104 24.3 Energy Efficiency demand Side Management (EEDSM) .................................................. 105 24.3.1 Allowed EEDSM for 2014/15 ......................................................................................... 105 24.3.2 Actual EEDSM for 2014/15 ............................................................................................ 106 24.3.3 Computation of EEDSM for the RCA ........................................................................... 108 25 OPERATING COSTS ................................................................................................................ 109 25.1 Allowed operating costs in 2014/15 ................................................................................... 109 25.1.1 Allowed employee costs in 2014/15 ............................................................................ 110 25.1.2 Allowed maintenance costs in 2014/15 ....................................................................... 110 25.1.3 Allowed arrear debts in 2014/15 ................................................................................... 110 25.1.4 Allowed cost of cover in 2014/15 ................................................................................. 111 25.1.5 Allowed corporate costs in 2014/15 ............................................................................ 111 25.1.6 Other operating costs in 2014/15 ................................................................................. 111 25.2 Actual operating costs in 2014/15 ...................................................................................... 111 25.3 Reasons for variance in operating costs........................................................................... 112 25.3.1 Employee benefits ......................................................................................................... 112 25.3.2 Maintenance ................................................................................................................... 112 25.3.3 Arrear debt ..................................................................................................................... 113 25.3.4 Cost of cover .................................................................................................................. 116 25.4 Savings through Business Productivity Programme ....................................................... 116 25.5 Other Income ........................................................................................................................ 117 25.5.1 Actual other income in 2014/15 .................................................................................... 117 25.5.2 Principles for treatment of other income in the RCA ................................................ 117 25.5.3 Other income included for RCA ................................................................................... 119 25.6 EDI Holdings levy ................................................................................................................. 119 MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 25.7 Operating cost variance for 2014/15 RCA ......................................................................... 119 25.8 Why symmetrical treatment of operating costs is needed .............................................. 120 26 SERVICE QUALITY INCENTIVES ........................................................................................... 122 26.1 Transmission service quality incentives (SQI) for 2014/15 ............................................. 122 26.2 Distribution Service Quality Incentive Scheme (SQI) for 2014/15 ................................... 124 27 REASONABILITY TESTS ........................................................................................................ 126 27.1 EBITDA-To-Interest Cover Ratio (EBITDA / Interest Payments) ..................................... 126 27.2 Understanding the ratio....................................................................................................... 126 27.3 Interest cover ratio ............................................................................................................... 128 27.4 Debt service cover ratio (Interest + Capital) ...................................................................... 128 27.5 Computation of ratios for FY 2015 ..................................................................................... 128 27.6 EBIT Interest cover ratio...................................................................................................... 130 27.7 EBITDA: Total debt service ratio ........................................................................................ 130 28 CONCLUSION .......................................................................................................................... 131 ANNEXURES: .................................................................................................................................... 132 Annexure 1: Income Statement in AFS 2015 .................................................................................. 132 Annexure 2: The Eskom energy wheel (Eskom Integrated report 2015, page22) ...................... 133 Annexure 3: Sales volumes GWh – Statistical tables for 2014/15 ............................................... 134 Annexure 4: Primary Energy Note 34 extract AFS March 2015, page 91 .................................... 135 Annexure 5: Finance income note 40 and Finance cost note 41 (Extracts AFS March 2015, page 93) ....................................................................................................................................................... 136 MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 Annexure 6: OPEX note 38 extract from AFS March 2015, page 92 ............................................ 137 Annexure 7: EEDSM costs in 2014/15 Annual report .................................................................... 138 Annexure 8: Copy of NERSA letter approval of 450GWh ............................................................. 139 29 ABBREVIATIONS ..................................................................................................................... 140 30 GLOSSARY AND TERMS ........................................................................................................ 143 Figure 1: Time lag between application and actuals ....................................................................... 21 Figure 2: Production FY 2015 ............................................................................................................ 40 Figure 3: Coal costs R/ton in 2014/15 ............................................................................................... 60 Figure 4 : Load shedding impact in 2014/15 .................................................................................... 77 Figure 5 : Monthly Energy Utilisation Factor in 2014/15 ................................................................. 85 Figure 6 : Relationship between high EUF to EAF and EUF ........................................................... 86 Figure 7: Transmission system minutes (<1) ................................................................................. 123 Figure 8 : Line faults /100km ............................................................................................................ 124 Figure 9 : EBITDA-To-Interest Cover Ratio .................................................................................... 126 Table 1: Summary of 2014/15 RCA Submission .............................................................................. 16 Table 2: RCA Trend Analysis ............................................................................................................. 20 Table 3: Key assumptions which have changed ............................................................................. 22 Table 4 : Calculation of MYPD3 revenue variance for 2014/15 ....................................................... 25 Table 5 : Reconciliation of AFS revenue to RCA revenue .............................................................. 25 Table 6: Revenue note from AFS for March 2015 ........................................................................... 26 Table 7 : Load shedding and curtailment impact in 2014/15 .......................................................... 28 Table 8 : Sales volume variance ........................................................................................................ 30 Table 9 : Reconciliation of decision volumes .................................................................................. 31 Table 10: MYPD3 Sales volume ......................................................................................................... 32 Table 11 : GDP forecasts used for MYPD3 in 2011 .......................................................................... 32 Table 12: Commodity Prices Variance .............................................................................................. 33 Table 13 : Sales volume variance ...................................................................................................... 33 Table 14 : Total primary energy comparison and RCA impact for 2014/15 .................................. 42 Table 15: Primary energy actual costs per note 34 in the AFS of 2015 ......................................... 42 Table 16: IPPs costs and volumes ................................................................................................... 48 Table 17: Actual energy procured through IPP programme in 2014/15 ........................................ 49 MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 Table 18: International purchases ..................................................................................................... 52 Table 19: NERSA’s decision on coal benchmark and alpha .......................................................... 55 Table 20: Working Coal Mechanism .................................................................................................. 56 Table 21 : Coal burn pass-through .................................................................................................... 57 Table 22: The coal burn breakdown for the RCA ............................................................................. 57 Table 23: MYPD 3 Assumptions vs. Actual 2014/15 ........................................................................ 59 Table 24: Other Primary Energy ........................................................................................................ 67 Table 25: Approved Demand Response (DR) Expenditure for MYPD3 ......................................... 73 Table 26: DMP comparison for RCA in 2014/15 ............................................................................... 73 Table 27 : Summary of allowed OCGTs components ..................................................................... 77 Table 28: Summary of OCGTs actual results for 2014/15 ............................................................... 78 Table 29: OCGTs RCA summary ....................................................................................................... 79 Table 30 : OCGTs price impact for 297ML ........................................................................................ 79 Table 31: OCGTs RCA claim related to excess volumes above allowed GWh ............................. 80 Table 32 : Special allowance for OCGTs usage up to 450GWh per month (Jan~Mar 2015) provides an additional 206ML ............................................................................................................ 81 Table 33 : Definitions of technical performance parameters ......................................................... 82 Table 34 : Comparison of Generation technical performance ....................................................... 82 Table 35: Average Eskom coal power station heat rate for period 20112/13 to 2014/15 ............. 83 Table 36: Breakdown of system UCLF (%) ....................................................................................... 83 Table 37: Calculation average capital expenditure ......................................................................... 88 Table 38: CECA Calculation: Return due to/by Eskom ................................................................... 90 Table 39 : Regulatory asset base for 2014/15 .................................................................................. 90 Table 40: Returns and percentage allowed in 2014/15 ................................................................... 90 Table 41: Capital expenditure in 2014/15 ......................................................................................... 91 Table 42: Capital expenditure for 2014/15 ........................................................................................ 91 Table 43: Capital Expenditure (excluding capitalised borrowing costs) per division ................. 92 Table 44: Inflation Data ..................................................................................................................... 103 Table 45 : Inflation adjustment ........................................................................................................ 103 Table 46: Allowed EEDSM ................................................................................................................ 106 Table 47: Verified demand side management and internal energy efficiency savings ............. 106 Table 48: Reconciliation between demand savings MWs used in RCA Calculation.................. 107 Table 49: EEDSM comparison for RCA in 2014/15 ........................................................................ 107 Table 50 : Total operating costs in MYPD3 decision ..................................................................... 109 Table 51: The allowed employee costs for Generation, Transmission and Distribution .......... 110 Table 52: Allowed Maintenance Costs ............................................................................................ 110 MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 Table 53: Allowed Arrear Debts ....................................................................................................... 110 Table 54: Allowed Cost of Cover ..................................................................................................... 111 Table 55: Allowed Corporate Costs in 2014/15 .............................................................................. 111 Table 56 : Other operating costs ..................................................................................................... 111 Table 57: Summary of Operating costs in 2014/15 ........................................................................ 112 Table 58: Arrear municipal and Soweto debt (excluding interest) at 31 March 2015 ................ 114 Table 59 : Other income for 2014/15 ............................................................................................... 117 Table 60 : Other income note in 2014/15 AFS ................................................................................ 118 Table 61 : Summary of SQI performance in 2014/15 ..................................................................... 122 Table 62: Transmission SQI performance in 2014/15 .................................................................... 122 Table 63: Transmission number of major incidents (>1SM) ......................................................... 123 Table 64: Distribution SQI performance in 2014/15 ....................................................................... 125 Table 65: Financial information for ratios in 2014/15 .................................................................... 129 Table 66: EBIT Interest Cover .......................................................................................................... 130 Table 67: EBITDA Debt service cover during 2014/15 ................................................................... 130 MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 1 Preface This document summarises information submitted by Eskom Holdings (SOC) Ltd to the National Energy Regulator of South Africa (hereafter referred to as NERSA, or the Energy Regulator) pertaining to the Eskom’s Regulatory Clearing Account (RCA) balance for the year 2014/15 and in accordance with the Multi-Year Price Determination Methodology (hereafter referred to as the ‘MYPD Methodology’) 1 . This document contains the following: 1. Information provided in regard to Eskom’s 2014/15 RCA balance (hereafter referred to as the ‘2014/15 RCA Submission’ or year 2 of MYPD3) is lodged in accordance with section 14.2.1 of the MYPD Methodology. 2. Information is supported by Eskom’s 2014/15 audited annual financial statements 3. Information is supported by NERSA’s RCA 2013/14 reasons for decision published on 29 March 2016 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. 1 See in particular sections 14.0, 8.0 and 9.0 of the Multi-Year Price Determination Methodology 1 st Edition, published December 2012 MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 14.1.2 Allowing the pass-through of prudently incurred primary energy costs as per Section 8 of the Methodology. 14.1.3 Adjusting capital expenditure forecasts for cost and timing variances as per Section 6 of the Methodology. 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 2014/15 RCA Submission The structure of the summary of 2014/15 RCA Submission provided in this document is guided by the MYPD Methodology. With this in mind, an overview of the 2014/15 RCA submission is first provided summarizing 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. MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 Eskom has provided reconciliations and reasons 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 2014/15 RCA Submission concludes with reasonableness tests such as EBITDA to interest payments and debt service cover ratio being assessed. 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 15) V. Primary Energy - Coal Costs (Section 17) VI. Primary Energy - Gas Turbine Generation Cost (Section 21) VII. Primary Energy – Other costs (Section 18) VIII. Capital Expenditure and Regulatory Asset Base (Section 22) IX. Operating Costs (Section 25) X. Determined RCA Balance to Financial Year End MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 2 Objective The objective of this 2014/15 RCA Submission is to provide the context for the Regulatory Clearing Account (RCA) process in terms of NERSA’s MYPD Methodology requirements. The 2014/15 RCA Submission for the second 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 decision made by NERSA on 1 March 2016 and the reasons for decision published on 29 March 2016. 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 through 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 costs that are subject to re-measurement as outlined in the MYPD methodology. MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 3 Overview of the 2014/15 RCA Submission Eskom’s 2014/15 RCA Submission is driven substantially by revenue under-recovery and higher primary energy costs to meet demand, whilst operating in a constrained electricity system. The determined RCA balance of R19 185m is motivated with evidence for prudent scrutiny by NERSA. Table 1: Summary of 2014/15 RCA Submission RCA for 2014/15Actuals Variance RCA adjustm ent RCA 2014/15 Total Electricity revenue R m illion 146 267 9 790 -1 003 8 787 Prim ary Energy , R m illion Coal 45 195 8 578 -8 004 574 OCGTs 9 546 6 836 -4 892 1 944 Other primary energy 6 890 1 355 1 355 Local IPPs and co-generation 9 454 4 346 4 346 International Purchases 3 679 3 299 3 299 Environmental levy 8 353 -683 -683 Nuclear decommissioning f rom RCA 2013/14 decision phased in over 10 years 83 83 Demand Market Participation (DMP) 309 -379 - -379 Total prim ary energy , R m illion 83 426 23 352 -12 813 10 539 Capital Expenditure Clearing Account (CECA) , R m illion 54 394 9 281 91 91 Integrated Dem and Managem ent (IDM) , R'm illion 654 -299 150 -149 Operating 1 costs , R m illion 44 982 5 565 4 552 -528 Service Quality Incentive (SQI) , R m illion - - 236 236 Inflation adjustm ents , R m illion - 209 209 Total RCA balance , R m illion 19 185 MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 3.1 Revenue The revenue variance of R8 787m is calculated on Eskom’s electricity revenue to all customers because of lower electricity sales volumes. In addition, Eskom has specifically excluded the loss of revenue attributable to the load shedding and load curtailment impacts. 3.2 Primary energy Due to the constrained electricity system, unplanned outages and delays in new build projects, Eskom was required to operate a more expensive mix of plant compared to the assumptions in the MYPD3 decision in order to avoid/minimize load shedding. This included a combination of higher levels of supply from local and regional IPPs, more OCGTs usage and a change in the mix of the coal fleet which was required in trying to meet demand and more importantly to protect the stability of the overall electricity system. Eskom has included R10 539m for primary energy costs in the RCA submission. 3.3 Environmental levy The lower production volumes and the change in production mix resulted in Eskom incurring environmental levy costs of R683m lower than the assumption made in the MYPD3 determination. The RCA methodology 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. 3.4 Phased nuclear decommissioning provision per MYPD3 RCA 2013/14 decision In its 2013/14 RCA decision, NERSA has allowed Eskom to claim the nuclear decommissioning provision of R834 million, over a period of 10 years, in equal installments of R83m via future RCA applications. The first tranche of R83 million was granted in the RCA 2013/14 decision. 3.5 International electricity purchases In the MYPD3 RCA 2013/14 decision, NERSA adopted a total approach for revenue and corresponding costs to include regional components. Eskom has taken this on board and MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 has accordingly applied this to the RCA treatment for international purchases relating to the 2014/15 period. The international purchases cost variance contributes R3 299m to the total primary energy category of the RCA balance. 3.6 Capital expenditure variance Eskom’s Company capital expenditure for regulatory purposes of R54 394 million exceeded the NERSA decision of R45 113 million by R9 281 million in 2014/15. 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 capex is excluded when computing the balance for RCA purposes. 3.7 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 2014/15 the operating costs expenditure of R49 534m exceeds the decision of R39 417m by R10 117m 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. 3.8 Integrated demand management Eskom’s energy efficiency and demand side management (EEDSM) programs produced less capacity (in MW) savings during the year resulting in a pay back to consumers of R149m for RCA purposes. 3.9 Other income Other income is included under the operating costs section and comprises the sale of scrap assets for R186m and R342m relating to the EDI restructuring levy. MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 3.10 Inflation adjustments Section 14.1.1 of the MYPD methodology states “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 R209m in favour of Eskom. 3.11 Service Quality Incentives (SQI) Eskom has achieved the service quality incentive targets set by NERSA for Distribution and Transmission during 2014/15. This resulted in Distribution achieving an SQI of R233m and Transmission of R3m, equating to a total of R236m. 3.12 Reasonableness test Eskom has computed reasonableness tests, namely the EBITDA: Interest cover ratio and Debt service cover ratio. These tests reflect that the RCA adjustment decision will contribute towards the recovery of full efficient costs and allow Eskom to earn the allowed return. Further, the ratio analysis reflects that even with the RCA adjustment, each measure is well below the acceptable range. 3.13 Comparison of RCA 2014/15 submission to RCA 2013/14 decision Eskom has compared the RCA submission for 2014/15 to the decision made by NERSA for the RCA balance for 2013/14. This submission reflects an escalation of R7 944 million which is substantially attributable to an increase in revenue variance and higher utilization of independent power producers and other primary energy. MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 Table 2: RCA Trend Analysis 3.14 Conclusion The RCA balance submission of R19 185m excludes operating cost variances. Furthermore, in aligning to the NERSA decision precedent set in the RCA 2013/14 decision, Eskom absorbed a large OCGT cost variance. RCAs trend analysis Decision RCA 2013/14 Application RCA 2014/15 Movement RCA Decision 2014 to RCA 2015 Revenue 6 175 8 787 2 612 Local IPPs 580 4 346 3 766 International Purchases 2 700 3 299 599 Coal 2 000 574 -1 426 Open Cycle Gas Turbines (OCGTs) 1 252 1 944 692 Other primary energy 72 1 355 1 283 Environmental levy -312 -683 -371 Nuclear decommissioning from RCA 2013/14 decision phased in over 10 years 83 83 - Integrated Demand Management (IDM) -432 -149 283 Demand Market Participation (DMP) -905 -379 526 Capital Expenditure Clearing Account (CECA) 9 91 82 Service Quality Incentives (SQI) 339 236 -103 Inflation adjustment - Opex 33 209 176 Other income -353 -528 -175 RCA balance R'millions 11 241 19 185 7 944 MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 4 Factors impacting on 2014/15 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-13Apr-14Apr-15Apr-16Apr-17Apr-18 5 Year MYPD3 Window MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 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 Sales forecast average growth was 0.9% p.a. with an actual starting value of 217TWh in March 2013 Sales forecast did not materialise due to major changes in the assumptions plus the adverse global economic situation not recovering as anticipated Generation plant performance (Energy availability factor – EAF) assumed at between 82% for 2014/15. Actual average EAF is approximately 74% Actual plant performance is lower than that anticipated at the time of preparing the application in early 2012. New build commission dates for 1 st units Medupi – June 2013 Kusile - 2014/15 Ingula – 2013/14 Sere – 2013/14 New build commission revised dates for 1 st units: Medupi – Commissioned August 2015 Kusile – July 2018 Ingula – Jan 2017 Sere – Commissioned on 31 March 2015 Due to labour disturbances, contractor failures, and inadequate project management capability, the new build projects have been delayed Coal country compact < 10%price increases Efficiency savings implemented through business productivity programme . Price increases will most l likely exceed the less than the10% assumption. MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 OCGTs – load factors assumed at 3% based on certain other assumptions materialising OCGTs – actual load factors >3% due to the other assumptions made at time of application not materialising OCGTs were utilized as last resort to avoid load shedding IPPs – local and international Substantial increase in IPP programs related to DOE programs and securing regional IPPs to address capacity constraints At the time of the MYPD 3 application, the extent of the IPP programs were not envisaged and additional IPP purchases were required to prevent loadshedding as a cheaper options than OCGTs Capex – R337bn over the five year period Capex – given the lower revenue decision, Eskom reprioritized capex to a projected portfolio of R251bn over the five year period. In response to MYPD3 revenue decision Eskom has reprioritised capex spent which resulted in movements of expenditures between licensees. Staff costs – complement of 43 000 growing to 46 000 Revised staff outlook decreasing staff complement to 41 020 by FY 2018 Business Productivity Program (BPP) savings initiative launched in the business. Maintenance More maintenance was undertaken than initially envisaged Addressing the reduced plant performance and maintenance backlog Other Opex Roll out of BPP saving plan Despite cost efficiency and saving programme other operating cost exceeded the decision MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 5 Revenue variance The objective of this section is to demonstrate and explain the revenue variance between the MYPD3 decision and equivalent revenue which was actually derived in year 2 (2014/15) of the MYPD3. This document will highlight Eskom’s approach to the revenue variance calculation and provide reconciliation between the revenue disclosed in the 2014/15 Eskom annual financial statement (AFS) and the MYPD3 revenue determination by NERSA for 2014/15. In addition, it will explain why non-electricity revenue is not included in the revenue variance calculation for RCA purposes. 6 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. Eskom company revenue is made up of electricity and non-electricity revenue. Eskom’s electricity revenue is derived from 3 customer categories viz. standard tariff, local special pricing agreements and exports (international) customers. Non-electricity is made up of deferred income recognized and other revenue. Other income is classified as operating costs and is therefore discussed under that section 7 Calculation of the revenue variance The table below shows the sales volume and revenue variance. 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. MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 Table 4 : Calculation of MYPD3 revenue variance for 2014/15 Revenue variance for 2014/15 MYPD Decision Actuals Variance Total external electricity revenue (R'm) 156 057 147 271 -8 786 Total external sales volumes (GWh) 229 183 216 274 -12 909 Total average selling price (c/kWh) 68.09 68.09 0.00 7.1 Revenue computed on an equivalent basis When computing the RCA balance, it is important to compare the same reference points. Eskom 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 Revenue as reported in Eskom’s 2015 AFS Revenue from continuing operations of R147 691m, reported on page 91 of Eskom’s 2015 AFS, provides the starting point for obtaining the MYPD equivalent for actual revenue. Actual MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 electricity revenue was R146 268m; other revenue was R1 280m and deferred income of R143m for 2014/15. Table 6: Revenue note from AFS for March 2015 Source: Eskom Annual Financial Statements, 31 March 2015 page 91. Note 1: 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). MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 Note 2: IAS 18 adjustment In terms of IAS 18 electricity revenue of R597 million was not recognized as revenue as it was assessed that there is a high probability that the economic benefit will not materialized, 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. Note 3: Estimated Load Reduction impact on revenue loss for 2014/15 During the second year of MYPD3 there were several interruptions and thus load reduction estimated at 574GWh comprised a combination of load shedding and load curtailment. Load shedding contributed about 359 hours of interruptions (60%) and load curtailment about 229 hours of interruptions (40%) during the year as depicted in the table below. Eskom will thus need to reduce their volume variances to cater for the impact of load reductions. Eskom has computed the revenue loss impact using the principle of standard tariff rate as was determined by NERSA in para 31 of the MYPD3 RCA 2013/14 decision. The load reduction impact of 574GWh is multiplied by the actual average standard tariff price (70.65c/kWh). This equates to a total revenue loss attributable to the load reductions was calculated at R406 million. This amount is added back to reduce the amount of revenue variance claimed as part of the RCA submission. MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 Table 7 : Load shedding and curtailment impact in 2014/15 Demand (MW) per hour is taken as the estimated energy consumption for that hour and all hours shed was added to get the total energy (MWh) that was shed for that specific month. This gives an estimated maximum energy consumption impact for that specific month. It should be noted that the risk in using these estimates is that it can be too high or too low as the demand to be shed was a request to the customers and they could have shed more or less during those hours. These figures are estimates as they are not measured and no feedback from the customers was obtained to ascertain the amount that was actually shed during the various hours. Once the load shedding ended, some of the load (energy consumption being impacted), did return. 7.2 Allowed Revenue The allowed revenue used for purposes of the RCA calculation is as per the reasons for decision for MYPD 3 Year 1 RCA, as follows: Load shedding and Curtailment impact in 2014/15 Month Load shedding Hours Load Curtailment Hours Total Load Shedding & Curtailment Hours Load reduction GWh Standard average price c/kWh Revenue loss impact R'million Apr-14- - - - May-14- - - - Jun-145.6 2.6 8.2 6.5 Jul-14- - - - Aug-14- - - - Sep-14- - - - Oct-14- 4.0 4.0 0.7 Nov-1478.5 4.0 82.5 112.8 Dec-1461.0 39.0 100.0 122.3 Jan-1532.5 20.6 53.1 48.8 Feb-15152.0 130.0 282.0 237.4 Mar-1529.0 29.0 58.0 45.7 Total 2014/15358.6 229.2 587.8 574.2 70.65 405.6 MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 Source: NERSA’s reasons for decision on Eskom’s Regulatory Clearing Account Balance- Third Multi Year price determination (MYPD3) Year 1 (2013/14) 7.3 Sales volumes contribute to recovery of fixed costs 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 materialising, it results in Eskom not recovering the allowed revenue components as was assumed. MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 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 need to continue to incur these fixed 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 Operation and maintenance (O&M) costs in the current 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 included in the returns and depreciation building blocks of the allowed revenue for regulatory purposes. 7.4 Volumes: Allowed vs Actuals Table 8 : Sales volume variance Note 1: Decision volumes used; Table 54 as per the NERSA MYPD3 decision shown below reflects a total sales volume of 229 513GWh for 2014/15. MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 Table 54: Approved sales volumes forecast, MYPD3 decision - Table 8 above shows a total sales volumes of 229 183 GWh as the decision volumes. - The difference of 330GWh is due to internal sales and en-route sales as shown below. Internal sales are excluded as the RCA deals with external electricity revenue and the AFS similarly excludes internal revenue from the results. Table 9 : Reconciliation of decision volumes Reconciliation of MYPD3 decision sales to Eskom calculation for RCA 2014/15 Total volumes per NERSA MYPD3 decision 229 513 Less: Internal sales -423 Add: En route sales 93 Total decision volumes 229 183 7.5 Sales volume variance explanation The MYPD forecast is normally finalized in the 2 years preceding the MYPD determination. This becomes a high risk as many economic assumptions can change during this period while the MYPD submission is analyzed and a determination is made. In the case of MYPD3, the MYPD forecast was finalized on 14 September 2011 when the prospects for a higher economic growth were still viable as we recovered from the recession in 2007/08. The table below highlights the difference between MYPD3 forecasts and actual reality over the last three years. The MYPD3 growth over the 5 year period (i.e. 2013/14 to 2017/18 volumes) was assumed to be 7.3 % while the average growth rate per annum was assumed to be 1.8%. GWh2013/142014/152015/162016/172017/18MYPD3 Total Standard tariff sales206 587 208 441 213 544 218 193 223 217 1 069 982 Negotiated pricing agreement11 303 11 303 11 333 11 302 11 302 56 543 Exports9 513 9 769 10 761 9 618 9 507 49 168 Approved sales forecast227 403 229 513 235 638 239 113 244 026 1 175 693 GDP2.6 3.6 3.6 3.9 4.0 MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 Table 10: MYPD3 Sales volume The actual sales variance was 5.7% less than the forecast of 229 513 GWh for 2014/15. 7.5.1 The process in deriving the 5 year forecast The 5 year sales forecast used in the application was compiled using a bottom up approach from customer level. Each of the six Eskom Regions forecasted the Regional sales using a bottom up approach from customer level for their specific Regions. Each Regional forecast were scrutinized on a one on one basis after which the six Regional forecasts and the Top Industrial Customer’s forecast were consolidated into one Eskom view. 7.5.2 Critical assumptions relevant during 2011 in deriving forecasts Table 11 : GDP forecasts used for MYPD3 in 2011  The actual GDP growth rates were approximately half the forecasted assumptions  The most rapid growth in recent decades has been in the less energy intensive services sectors, while the contribution of the energy intensive Mining sector started to dwindle.  High price increases will continue for the next 3 years (25% up to 2014/15). The price was already +/- 2.7 times what it was in 2008/9.  A substantial amount of furnace load will not be utilized in winter because of the high winter prices.  Furnace utilization will be about 95% in the summer months.  Large Co-gen projects that are in an advanced stage in the commissioning process have been included in the budget. 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) 216 561 217 903 216 274 Actual sales growth %-3.66%0.62%-0.75% GDP growth % 2 012 2 013 2 014 2 015 2 016 2 017 MYPD3 GDP growth % 4.0%4.0%4.0%4.5%5.0%5.0% Actual GDP growth %2.2%2.2%1.5%1.3% MYPD3 2014/15 RCA Submission to NERSA 10 May 2016  Municipality generation assumed for PPA up to 2013/14, thereafter normal own generation.  Variance in the forecasted Commodity Prices used in the Decision vs the Actual average prices. Table 12: Commodity Prices Variance  High probability new projects are included.  Average weather conditions have been used. 7.5.3 Sales volume variance explanation for FY2015 The table below shows the sales volume variance that will provide the reasons for the decrease in revenue compared to the decision. Table 13 : Sales volume variance Commodity PricesMYPD3 Decision Actual average prices FeCr$1.20/lb - $1.32/lb$0.76/lb Aluminum$2 500/ton - $2 750/ton$1 867/ton Platinum$1 480/oz - $2 000/oz$1 384/oz Sales volume variance per customer category (GWh) Actual Sales MYPD 3 Variance International 1 11 911 9 862 2 049 Distribution sales 205 154 219 744 -14 590 Re-distributors91 090 95 986 -4 896 Industrial53 467 59 172 -5 705 Mining29 988 35 122 -5 134 Traction3 098 3 117 -19 Residential4 199 4 505 -306 Commercial9 644 9 527 117 Agricultural5 401 5 184 217 Prepayment7 386 6 620 767 International A89 88 1 Internal sales791 423 368 Total electricity sales volumes217 065 229 606 -12 541 Exclude Internal sales-791 -423 -368 Total external electricity sales volumes216 274 229 183 -12 909 MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 Note 1 – International sales is the sum of 11911GWh + International A 89GWh to equal 12000GWh From table 7 above, which reflects the variance between the MYPD NERSA decision and Actual sales for year 2014/15, it can be seen that the unfavorable variance of 14 590GWh in respect of distribution sales is mainly due to three categories, namely Redistributors, Industrial and Mining. The unfavorable variances in these three categories were partially offset by the favorable variance of 2 049 GWh from the export sales and 767 GWh from the prepayment environment. Redistributors: 4 896 GWh unfavourable 7.5.3.1 The unfavorable variance in this category is spread over most of the Municipalities and metro’s and are mainly due to:  The largest unfavorable impacts are seen in the City Power and Ekurhuleni Metro’s due to the sluggish economic growth. City Power and Ekurhuleni are within the economic hub of South Africa and thus severely affected by the slow local & global economic growth. Also in the Southern Region the expectation was that the Coega development project would have started up but due to the absentee of “the anchor project”, very little development have materialized up to this point. Cape Town Municipality introduces a huge savings drive 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.  Rotational load shedding was introduced since November 2014 and it had a significant negative impact on the consumption in the Metro’s and Municipalities.  Due to the Global economy that did not pick up as expected as well as the fluctuation of the ZAR exchange rate, the manufacturing sector behind the bulk meters in the municipalities were not able to secure orders, thus producing less with a resultant drop in energy consumption.  NUMSA strikes also negatively affected the consumption in certain Metro’s in 2014.  Due to the very high price increases, price elasticity also played a role due to savings from customers, especially in the lower LSM’s.  DSM initiatives also impacted the sales negatively due to the roll outs of CFL’s, installation of PV panels and installation of solar geysers. MYPD3 2014/15 RCA Submission to NERSA 10 May 2016  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 budgeted for in the MYPD NERSA decision. Industrial: 5 705 GWh unfavourable. 7.5.3.2 This category was the most severely affected category and it is mainly due to:  The impact from the closure of the Bayside Aluminium smelter which had an unfavourable impact of 1 480 GWh on the Aluminium sector as can be seen from the sales recon table above.  Sasol Infra Chem commissioned their own gas generation plant and displaced 324 GWh from the “Manufacturing of basic Chemicals” sector as seen in the sales recon table above for details.  The Ferro and steel smelting industry realized a drop in consumption against the MYPD NERSA decision of 3 119 GWh due to the very high winter prices, low demand for their products and unfavourable commodity prices that led to diminishing orders and downsizing and closure of customers. The smelting industry opted to take furnaces out during the three winter months to save on costs due to the very high price of electricity. Many customers are downsizing and some is considering full closures. See Sales Recon table above for details. Mining: 5 134 GWh unfavourable 7.5.3.3 This category was also affected severely and it is mainly due to the Gold and Platinum sectors:  The Platinum sector realized a 3 064 GWh drop in consumption against the MYPD NERSA decision due to mainly labour unrests which caused shaft closures and many projects to be delayed and some projects were cancelled in the Platinum sector. The Platinum Industry has endured the longest strike in history and the estimated impact was 775 GWh.  The unfavourable Platinum price and demand for platinum also negatively affect the start-up of project as well as the cancelation of some projects. MYPD3 2014/15 RCA Submission to NERSA 10 May 2016  The Gold sector realized a 2 039 GWh drop in consumption against the budget due cost pressure as a result of labour unrest and high salary increases which caused high cash costs and resulted in down scaling and shaft closures in many of the Gold mines. We also had some Gold mines that were liquidated and shafts that closed. Many shafts were also put under care and maintenance due to cost pressures. The unfavourable commodity price also played a major role in escalating the cost pressures. The unfavorable variance in Sales volumes against the MYPD NERSA decision was offset by the large favorable variance in the Prepayment sales and SAE sales. Prepayment: 767 GWh favourable 7.5.3.4 In the Prepaid environment a significant favorable variance against the MYPD NERSA decision was realized mostly in the Northern Region due to the changing of the supply group codes that eliminated most of the ghost CDU’s in that Region, resulting in higher Sales volumes than anticipated in the MYPD NERSA decision International: 2 049 GWh favourable 7.5.3.5 Exports were higher than budget, predominantly due to BPC experiencing problems at Moropule B during the 2 nd half of the financial year, hence depending on Eskom to make-up their shortfalls. Eskom has bilateral electricity trading agreements with most SAPP members and continues to export and import electricity. Eskom is aware of its responsibility to South Africa regarding the exporting of electricity when the domestic supply-demand balance is constrained. To reduce the impact of exports, Eskom has ensured that the contracts with SAPP trading partners are sufficiently flexible to allow for the following controls: - During emergency situations in South Africa, non-firm agreements (Botswana and Namibia) and industrial customers across the border (Mozal and Skorpion Zinc) are interrupted in line with the terms of their agreements - The remaining firm supply agreements (Swaziland and Lesotho) continue to be supplied in full, but they are urged to reduce consumption. During load shedding in South Africa they are required to undertake proportional load shedding MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 8 Conclusion of 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 revenue variance of R8787m in 2014/15. 9 Impact of demand responses on sales volumes As part of the MYPD3 determination, NERSA does allow for demand response initiatives to be utilised which comprise EEDSM and DMP for 2014/15. Embedded in Eskom’s MYPD3 application was an assumption for EEDSM which was taken into consideration when determining the sales forecasts. In the 2014/15 year, NERSA assumed 1 204 GWh of energy savings at a cost of R953 million which culminated in 294 MW of capacity savings. In reality, EEDSM achieved lower savings during the year with 816 GWh of savings, generating 247.9 MW of capacity savings at a cost of R654 million. The under achievement is addressed through the RCA mechanism which deals with EEDSM. In addition, NERSA assumed DMP costs of R688 million in 2014/15 and actual expenditure was R309 million. 10 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 which is compiled on an accrual basis. 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. This principle is demonstrated by Eskom adding back R597 million to actual revenue which was treated as unrecognized revenue in terms of accounting standards in the annual financial statements. MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 11 RCA implementation risks Eskom is concerned that NERSA has determined that a proportion of the RCA award should be recovered from local SPAs and cross border customers. Local SPA revenue is based on bilateral contracts between Eskom and the counter parties and a major portion of export revenue is also based on bilateral contracts with counter parties. Hence, Eskom believes that practically it would be difficult to recover the respective RCA amounts from these customer categories. 12 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 MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 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 MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 13 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. Therefore 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 some 12 TWh, delays in new build commissioning, 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 2: Production FY 2015 180,000 190,000 200,000 210,000 220,000 230,000 240,000 250,000 260,000 270,000 MYPD3Actuals Production Volumes (GWh) Production FY 2015 OCGTs New build IPPs Imports Other Coal Sales (TWh) MYPD3 229 Actuals 217 MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 14 Primary energy Following the NERSA RCA 2013/14 decision, where the Regulator compared revenue as well as primary energy on a total company approach, Eskom has aligned the treatment for RCA 2014/15 to match that per the RCA 2013/14 decision. This entails that total primary energy including international purchases are compared to the MYPD3 decision for RCA purposes. 14.1 Primary energy variances and RCA impact for 2014/15 Total primary energy allowed for 2014/15 was R60 074 million. Eskom incurred R83 426 million in the year which resulted in an extra cost of R23 352 million. However, not all the cost variances qualify for RCA inclusion. In particular the following RCA adjustments were processed: 1. Coal costs – Medupi and Kusile take or pay 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 an alpha adjustment 3. OCGTs – Eskom has aligned the OCGT RCA amount to the precedent adopted by NERSA in their RCA 2013/14 decision and treatment of OCGTs. 4. Nuclear decommissioning provision – implementation of the 10 year phasing of the provision of R833 million in equal tranches. Hence the sum of all these adjustments is R12 813 million and thereby reduces the total primary energy variance to R10 539 million. MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 Table 14 : Total primary energy comparison and RCA impact for 2014/15 Source : Allowed total primary energy is table 17, MYPD3 decision; Source: Actuals , Primary energy note 34, AFS, March 2015 Extract from the AFS, March 2015 reflects the actual total primary costs of R83 425m below. Table 15: Primary energy actual costs per note 34 in the AFS of 2015 MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 With the summary information disclosed, the next section will provide more detail on the respective primary energy components. MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 15 Independent Power Producers Eskom acknowledges the role that IPPs must play in the South African electricity market and remain 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. 15.1 Medium-term Power Purchase Programme (MTPPP) Eskom initiated the MTPPP in 2008 in order to procure base-load capacity from private generators. The total capacity procured under the MTPPP amounted to 290.6 MW (excluding one contract that was awarded but never became operational due to the IPP failure to meet obligations). At 1 April 2014 only one contract (of 13 MW) remained in operation under this programme, as the others had all expired. 15.2 Municipal Base-load Purchases Following continued capacity concerns Eskom approached municipalities to assist with additional generation. Of these contracts only one remained operational during the 2014/15 financial year (with City Power for 420 MW). 15.3 Short-term Power Purchases Programme (STPPP) The capacity constraints also prompted Eskom to launch the STPPP in order to attract additional capacity from private generators on a short-term basis. As at 31 March 2015 the combined contracted capacity under the STPPP was 289 MW. 15.4 Wholesale Electricity Pricing System (WEPs) programme Eskom enters into annual contracts with embedded generators outside of the ambit of the MTPPP and short-term contracts. These contracts are paid at wholesale prices (effectively Eskom’s average price of generation, inclusive of external energy purchases). For the 2014/15 year 87MW of capacity was contracted. MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 15.5 Long-term IPP programmes The Department of Energy (DoE) has instituted long term IPP programmes in which Eskom's role is that of designated purchaser of supplied energy, as well as being the network operator where Eskom owns the network and grid connection infrastructure. 15.5.1 IPP open cycle gas turbine (“Peaker”) programme Power purchase agreements (PPAs) of 1 005MW for the Avon and Dedisa plants were entered into during June 2013 and became effective on 29 August 2013. Commissioning of Dedisa was expected in the second half of 2015, while Avon is expected during the first half of 2016. These did not produce energy during 2014/15 as anticipated. 15.5.2 Renewable Energy Independent Power Producer (RE-IPP) procurement programme The DoE launched the RE-IPP Programme during 2011, which called for 3 725MW of renewable energy technologies in commercial operation between mid-2014 and the end of 2016. Developers were invited to submit proposals for the financing, construction, operation, and maintenance of any onshore wind, solar thermal, solar photovoltaic, biomass, biogas, landfill gas, or small hydro technologies. Eskom has now signed contracts for a total of 3 887MW under the RE-IPP Procurement Programme. As at 31 March 2015, a total of 1 795MW has been connected and is providing power to the grid. An average load factor of 30.85% was achieved during the year. Renewable IPPs are driven by wind and solar PV technologies. MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 15.6 Legal basis for IPPs per the MYPD Methodology Section 9 in the MYPD Methodology deals with the treatment of IPPs: 15.7 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. 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 pass- through 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. MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 15.8 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: 15.9 IPP allowed costs for 2014/15 In the MYPD3 decision NERSA had awarded Eskom a total of R4 835m for energy related costs for local IPP costs as summarised below. These costs covered Eskom own IPPs under the MTPPP of R92m and Short Term programmes of R503m and Renewable IPPs R4 240m. No costs were assumed for the DOE peaking stations for 2014/15. 15.10 Actual IPP costs for 2014/15 Eskom incurred costs of R9 454 m relating to energy costs for Local IPPs during 2014/15. 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. 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. MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 Eskom utilized 3 435 GWh more energy from IPPs when compared to the MYPD3 decision in 2014/15. A summary of the costs and volumes from IPPs are presented in the table below: Table 16: IPPs costs and volumes Total capacity of 5 701MW has been contracted with IPPs as at 31 March 2015, of which 3 887MW relates to contracts under DoE’s renewable energy (RE-IPP) programme. At 31 March 2015, a total of 1 795MW of renewable IPP generation capacity has been connected and is providing power to the grid. An average load factor of 30.85% was achieved during the year. Short- and medium-term contracts which were expiring at the end of March 2015 were renewed for another year, so they can continue to contribute to reducing the supply shortage. IPPs provide much needed renewable energy to the energy mix; they also play a vital role in balancing supply and demand, as well as providing space for maintenance and reducing the need for load shedding. The costs of R9 454m incurred in 2014/15 is highlighted in the extract form Eskom‘s Integrated Report 2015 below: Independent Power Producers (IPPs) FY 2014/15ActualsDecisionVarianceActualsDecisionVarianceActualsDecisionVariance Non-renewable programs2 772 595 2 177 3 006 654 2 352 922 910 12 MTPPP62 92 -30 55 114 -59 1 127 807 320 STPPP (incl Munics)2 635 503 2 132 2 805 540 2 265 939 931 8 WEPS75 - 75 146 - 146 514 514 Renewable IPP's6 682 4 240 2 442 3 017 1 934 1 083 2 215 2 192 22 Renewable IPPs energy6 553 4 240 2 313 3 017 1 934 1 083 2 215 2 192 22 Renewable IPPs - deemed energy payment129 - 129 - - - DOE Peaker- - - - - - Total IPPs 9 454 4 835 4 619 6 023 2 588 3 435 1 570 1 974 -404 IPP ancilliary costs- 273 -273 Total IPPs for RCA9 454 5 108 4 346 6 023 2 588 3 435 Costs (R'million)Volumes (GWh)Average Costs (R/MWh) MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 Table 17: Actual energy procured through IPP programme in 2014/15 Source: Integrated Report 2015, Page 56 15.10.1 Reasons for IPP variances in 2014/15 Medium Term Power Purchase Programme (MTPPP) Lower costs were incurred due to the reduced volumes, partially offset by the higher average cost due to the mid-merit operation of one of the IPPs. Volume variance: All three providers under the MTPPP operated at a lower load factor than was expected at the time of the MYPD3 decision. This is in line with the contract parameters and is encouraged through differential pricing between the peak and off-peak periods. Price variance: As mentioned above the IPPs are incentivised under the MTPPP to operate on a mid-merit basis which some have been able to execute. These IPPs benefit from the higher price applicable over the peak period in the contract (defined as between 06h00 and 22h00). This is higher than the assumed average rate in the MYPD3 decision. Short Term Power Purchase Programmes (STPPP) At the time of the MYPD3 decision it was expected that the short term contracts would expire in December 2013 as the system capacity shortfall would be ameliorated by Eskom new build. The delays in the new build has necessitated the extension of the STPPP and municipal generation contracts leading to the increased purchase volumes and associated costs. Price variance: the average STPPP price was in line with the expectation at the time of the MYPD3 application. ActualActual 2014/152013/14 Total energy purchased, GWh 1 6 0223 671 Total spent, R million 1 9 4543 266 Weighted average cost, c/kWh15788 Measure and unit MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 WEPS The WEPS price reflects the NERSA approved WEPS tariff. Eskom buys energy from embedded generators at the average energy rate as determined by NERSA in the approved WEPS tariff. These contracts are annual contracts limited to generators ability to connect to the Eskom Distribution network at above 1 kVA. These were not included in the NERSA revenue determination. Renewable IPPs Price variance: Prices were marginally higher due to price adjustments between bid announcement and financial close, offset by lower actual CPI escalations (compared to forecast). Volume variance: The volumes produced by REIPP generators were substantially higher than that assumed in the NERSA MYPD3 determination. Renewable generators have mostly commissioned at, or close to, the scheduled commissioning dates and are generating close to their contracted volumes. 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 R129m for the year was made to two IPPs due to delays in grid connection:  The connection of one IPP facility was impacted by delays in project approval, as well as project construction being delayed when landowners denied contractors access to the work site due to seasonal agricultural activities. MYPD3 2014/15 RCA Submission to NERSA 10 May 2016  The second IPP facility was impacted by the need to review the environmental impact assessment, as well as construction material delivery delays resulting from industrial action. 15.11 IPP variance for 2014/15 RCA IPP variance = Actual IPP costs – Allowed IPP costs Eskom spent R9 454m for local IPPs which exceeded the IPP allowance of R4 835m resulting in an over expenditure of R4 619m during 2014/15 A. Transmission Ancillary Costs NERSA approved R273 m for Transmission ancillary costs in the MYPD3 determination for FY 2015. These costs have not been incurred. This portion of the allocation has been added to the budget to accommodate network use of system charges to the IPP which are a pass through to the Eskom Buyer’s Office. Ancillary variance = Ancillary actual – Ancillary decision Eskom did not spend any costs for Transmission ancillary charges attributable to IPPs and thus has over recovered in 2014/15 by R273m MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 16 International purchases Eskom acquired electricity from neighbouring countries that resulted in purchases of R3 679 million which generated energy inflows of 10 731 GWh during the year. The actual costs are agreed to international electricity purchases as disclosed under note 34 for primary energy in the AFS. As mentioned earlier the Aggreko purchases are disclosed separately from other imports. Table 18: International purchases 16.1 Regional IPPs - Aggreko In order to enable Eskom to address its short-term supply side challenges (as identified in the Medium Term Risk Mitigation Strategy) in the Integrated Resources Plan 2010, energy purchases from cross border base-load and peaking generation plant were to be considered. Eskom through its Southern African Energy (SAE) Unit, entered into a PPA with AIPL (Aggreko International Projects Limited) for a contracted capacity of 92.5MW from the Aggreko-Shanduka Gas Fired Plant in Ressano Garcia, Mozambique. Eskom had received approval from NERSA for cost recovery of the Aggreko project in terms of the regulatory rules for cost recovery for power purchases. The project was exempted by the Minister of Energy from the requirement to obtain a Ministerial Determination under regulation 11 of the Electricity Regulations on New Generation Capacity of 04 May 2011, due to the short term nature of the project, and to allow Eskom to address its short term challenges. A due diligence of the AIPL project also showed that the power station would reduce overall transmission losses between RSA and Mozambique, and also deload the transformer in Maputo. The AIPL price was higher than most of the conventional fossil fuel base load plants, but lower than gas and most of the renewable energy technologies. In addition the MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 lead time for fossil fuel base load plants is at least 5 years, whereas AIPL has a lead time of 4 months, which was in line with the maintenance requirements of Eskom. Renewable technologies had longer lead times than the AIPL project, are intermittent in nature, and more expensive than AIPL. Eskom also considered the alternative of an existing 100MW peaking station in Zambia, but the AIPL project was preferred as the Zambian option relied on wheeling power through Zimbabwe, where the transmission network is constrained. On the basis of the above, NERSA approved the cost recovery on the 6 June 2012, for a period of 2 years, for 92.5MW as a base load power station with 100% load factor. Eskom had envisaged that there would be no requirement to extend the agreement after the expiry date as the coal base load plants would be online then and did not include the costs associated with this project in its MYPD3 application to the Energy Regulator. However, due to delays in new build coal plants, Eskom applied for the extension of this PPA by 14 months (from 01 July 2014 to 31 August 2015), which was granted. The recovery of the actual costs will occur via the RCA. The supply profile was now based on a load profile that would maximize the benefits of the power from the plant i.e. off-setting the OCGT’s; hence the plant would now be operated as mid-merit (delivering a minimum of 100MW off-peak hours, and a maximum of 148MW peak hours). This project was used as a lever to contribute towards the supply and demand challenges. During 2014/15 Eskom incurred R1 150m costs to acquire energy from regional sources. MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 17 Coal Burn Costs 17.1 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, short-term 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 pass-through 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 : 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 PBR cost (Rand) = (Alpha x Actual Unit Cost of Coal Burn+ (1 – Alpha) x Coal burn Benchmark price) X Actual Coal Burn Volume MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 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 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”. 17.2 NERSA’s decision on coal benchmark and alpha The following information was received from NERSA: Table 19: NERSA’s decision on coal benchmark and alpha Coal Benchm ark price 2014/15 Coal burn costs (R'm) 36 617 Coal burn volumes (kt) 129 Benchmark price (R/t) 282.6 MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 17.3 Coal cost – RCA 2015 calculation The costs to be included in the RCA are calculated as follows: 17.3.1 Step 1 – Calculate the performance base regulation cost allowance In deriving the actual R/t costs, Eskom first deducts the costs relating to coal which are incurred but does not result in burn and energy being produced (Medupi take or pay and Kusile risk sharing agreement contracts). As presented below the actual R/t is computed by taking actual coal costs of R45 195m and deducting the R7 819m take or pay contractual amount which results in cost of R37 376m. Thereafter the adjusted actual cost of R37 376m is divided by the volume of coal burn of 119 179Mt resulting in an average actual R/t of R313.61. Table 20: Working Coal Mechanism Workings of coal mechanism MYPD3 ActualsVariance Coal burn (R'm)36 617 45 195 8 578 Coal disallowed for qualifying actuals costs (R'm)- -7 819 -7 819 - Medupi take or pay agreement (R'm)-7 803 - Kusile take or pay agreement (R'm)-16 Coal burn costs (R'm)36 617 37 376 759 Coal burn tons ( Mt)129 561 119 179 -10 382 Costs rate per ton (R/t)282.6 313.6 31.0 Alpha - sharing mechanism ( %)95%95% Coal rate after incl Alpha (R/t) 268.5 297.9 29.4 Adjusted MYPD3 decision with alpha312.2 PBR cost (Rand) = (Alpha x Actual Unit Cost of Coal Burn+ (1 – Alpha) x Coal burn Benchmark price) X Actual Coal Burn Volume For 2014/15 PBR cost (Rand) =( ((0.95 X R313.61) + (1-0.95) X R282.6)) X 119 179 Mt )/1000 PBR cost (Rand) = R37 191m Where Alpha = 0.95 Actual coal burn volume = 119 179 Mt Actual unit cost of coal burn = R313.61 per ton Coal burn benchmark cost = R282.6 per ton MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 Note 1: An amount in actual mode of R7 803m is for Medupi and R16m Kusile risk sharing agreement which have not been considered as coal burn costs. 17.3.2 Step 2 – Calculate the pass through coal burn costs Coal burn for RCA is based on a performance based regulation formula. Table 21 : Coal burn pass-through 17.3.3 Step 3 – Split the pass through coal burn cost into volume variance and price variance summarised below. Table 22: The coal burn breakdown for the RCA The coal burn variance of R574m 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. Coal burn passthrough costs RCA 2014/15 Coal burn based on PBR formula (R'm) 37 191 Coal burn allowed per MYPD3 (R'm) 36 617 Coal burn costs included in RCA (R'm) 574 Coal burn variance breakdown RCA 2014/15 Coal burn price variance (R'm) 3 814 Coal burn volume variance (R'm) -3 240 Coal burn costs included in RCA (R'm) 574 For 2014/15 Pass-through Coal Burn Cost = R37 191m – R36617m Pass-through Coal Burn Cost = R574m Where PBR cost = R37 191m Allowed coal burn cost = R36617m (per MYPD3 decision) Pass-through Coal Burn Cost = PBR Cost - Allowed Coal Burn Cost MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 A coal volume variance of R3 240m 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 variance of R3 814m in favour of Eskom. 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. 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 price variance = Allowed coal burn tons X (Actual – Allowed Price in R/t X Alpha) Coal price variance = 129561 X ((R313.61 – R282.6) X 0.95) Coal price variance = 129561 X R29.4 Coal price variance = R3 814m Where: Allowed coal burn tons (Mt) = 129561 Mt Actual Price (R/t) = R313.61 Allowed Price (R/t) = R282.6 Alpha = 0.95 Coal volume variance = Adjusted price r/t with Alpha X variance in coal burn tons Coal volume variance = (R282.6 + ((R313.61- R282.6) X 0.95 )) X (119 179 – 129 561) Coal volume variance = (R282.6 + R29.4) X -10382 Coal volume variance = R312 X -10 382 Coal volume variance = -R3240m Where: Allowed coal burn tons (Mt) = 129 561 Mt Actual coal burn tons (Mt) = 119 179 Mt Allowed Price (R/t) = R282.6 Actual Price (R/t) = R313.7 Alpha = 0.95 MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 17.4 Coal burn cost variance explanations The differences in 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. Table 23: MYPD 3 Assumptions vs. Actual 2014/15 MYPD3 FY15 Assumptions Actual 2014/15 Electricity production from coal fired plant would be 222 661 GWh. Electricity production from coal fired plant was 204 818 GWh. Cost Plus and Fixed Price mines produce at expected levels, except for Arnot Cost Plus and Fixed Price mines produced below expected levels by 6 262ktons (Cost Plus) and 5 838ktons (Fixed Price) New long term mines are producing Only a portion of the coal could be accepted at Medupi Power Station because the station construction was delayed. Prices from future medium term contracts have been based on existing contractual delivered cost. The increase in the price of ST/MT coal was higher than expected. Coal qualities have been adjusted to reflect the impact of the washing plants. Some delays were experienced with coal quality improvement initiatives, primarily because of funding constraints. 17.4.1 Lower electricity production from coal fired stations Total coal burnt was 10 382 kt less than planned. The coal fired power stations generated 17 843 GWh less than have planned. This resulted in a positive volume variance. MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 17.4.2 Different mix and efficiency of power stations generating electricity The utilisation of the coal power station fleet to generate electricity resulted in a price variance driven by:  The unavailability of the conveyor from the mine to Duvha Power Station meant that the coal had to be trucked to the station. In addition, excess coal that could not be burnt or stockpiled at Duvha was trucked to other power stations.  The delay in commissioning of Medupi Power Station.  The under production of Arnot and New Denmark collieries meant that more expensive coal, had to be sourced for Arnot and Tutuka.  Production at the Return to Service (RTS) stations, Majuba and Tutuka was higher than planned, requiring additional coal to be sourced.  The effects of industrial actions at the mines during the financial year. 17.5 Coal Purchases 17.5.1 Eskom’s coal costs contracts 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 is summarized below. Figure 3: Coal costs R/ton in 2014/15 MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 Long term fixed price contracts 17.5.1.1 The total cost of coal includes the cost from different types of contracts and a transport cost for ST/MT contracts. The fixed price contracts were the cheapest source of coal in FY14. Two of Eskom’s Fixed Price agreements are artificially low as there is a built-in cross subsidization clause that was negotiated some years ago. The pricing structure of these contracts is linked to the volumes delivered by the supplier. The base price of the contract is negotiated with an annual price adjustment that is applied. The bulk of this coal is from mines that are next to the power stations that they supply, so the transport cost is minimal and is via conveyor belt. These 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. Cost plus contracts 17.5.1.2 Coal from Cost Plus contracts is the second cheapest coal supply source. The cost of this coal comprises all expenditure incurred at the mine, overheads, capex and a return on the mines’ initial investment. The age of these mines and levels of investment in them, has reduced over time resulting in lower production volumes in recent years. Lower production volumes result in a higher R/ton cost because Eskom is contractually liable for the operating costs of the colliery. However, the transport cost is also minimal because coal is transported by conveyor to the power station. Coal supplied under these agreements is, on average, cheaper than coal from ST/MT contracts. The mines will attempt 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. In this type of contract where the total output is dedicated to Eskom, the bulk of the risk is carried by Eskom in return for coal prices per ton which are generally lower than any other type of contract (however in cases where cost-plus contracts are subsequently converted to fixed-indexed in MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 order to better utilize export quality coal which became available from that colliery, the negotiation dynamics at the time of converting the contract might provide the opportunity for a fixed-indexed price which may be lower than had such contracting approach been followed from the beginning). It also implies that any additional capital investments and operating expenditures which are required to improve the quality of coal or to increase the annual production volumes will impact the price per ton of coal to Eskom. ST/MT contracts 17.5.1.3 Coal from the ST/MT contracts is the most expensive coal supply source. One reason is that the contracts are of a shorter duration, so suppliers do not have the security that comes with long term contracts. The mining operations under these coal supply agreements have generally been commissioned after the mines under the Cost Plus and Fixed price agreements Thus; they do not have the benefit of historically lower cost of infrastructure and establishment. However, the primary reason is because he cost of coal on ST/MT contracts includes a significant transport cost element. This coal is typically further away from the power station than coal on long term contracts. It, therefore, is transported by road or rail, sometimes a combination of the two. The rate per ton/km is influenced by the distance of a route and the condition of the road. Longer routes are more expensive. In addition to the actual transport cost, a handling cost is incurred when coal is loaded and offloaded. This handling cost is increased if coal is taken to a rail siding before being sent on to a power station. In FY15, a higher proportion of ST/MT coal was moved by rail instead of road. This lowered the average cost of transport to 34% of the cost of coal from ST/MT contracts. These contracts may extend over 1-10 years. 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. During the life cycle of a contract the coal prices are typically not directly impacted by the price of export coal but the export price may have an impact at inception in that the supplier may reference this price at the time of negotiations. However, Eskom’s policy is to pay the operating cost of extracting the coal plus a fair return on the required capital investment. Whether this price MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 correlates to the export price at any given time during the life cycle of the contract is likely to be purely coincidental. 17.5.2 Coal cost variance The coal cost variance was a result of lower expenditure on the Cost Plus and Fixed Price contracts. At the cost plus mines, the rephasing of equipment overhauls to FY15 and postponing of the rehabilitation of the Arnot opencast mine contributed to the lower expenditure. Lower conveyor availability at Hendrina Power Station, and a damaged conveyor from the mine to Duvha Power Station resulted in lower volumes from the fixed price mines. Coal Qualities 17.5.2.1 Arnot and Tutuka account for more than half of coal related partial load losses which lead to OCLF of 0.82%. The potential solutions to these problems, which generally imply additional capital investment and operating expenses are, explained under the Cost Plus mines above. Wet coal challenges, as well as the implementation of moisture control, between Grootegeluk Colliery and Matimba Power Station remain a concern. The initiatives implemented at Matla continue to yield benefits. Mode of Transport 17.5.2.2 Coal is transported by conveyor, rail, road or a combination of modes. The dominant transport source is conveyor (61%), road (29%) and rail (10%). a. 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 FY15. MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 b. Rail Rail is the next cheapest mode of transport. However, there are only two stations, Majuba and Tutuka, which have rail infrastructure. Lower total purchases (in part because of lower total electricity production), as well as logistical constraints on both Eskom’s side and Transnet Freight Rail’s (TFR) part also contributed to the lower rail volumes. c. Road Road is the most expensive mode of transport. Because of rail infrastructure constraints, ST/MT coal to all stations, apart from Majuba, 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 because of the costs associated with rail sidings, loading and offloading. The increase in volumes on road is a result of the change in the station/burn mix (i.e. increase in burn at stations without rail infrastructure and stations that do not have dedicated mines, such as the RTS stations. 17.5.3 Medupi Take or Pay payment A take or pay payment was incurred because of the delay in the construction of Medupi Power Station. The construction is ongoing and Eskom has received 144kT of coal in terms of the agreement with Exxaro during 2012/13. Eskom is projecting to receive coal during May 2014 in preparation for the testing and commissioning of the first unit at the power station during the latter part of FY15. Eskom was supposed to take coal from 1 February 2014. Due to the heavy rains, labour problems and technical difficulties experienced at Medupi during FY13 & FY14, the construction of the stock pile base was delayed. This resulted in Eskom providing Exxaro with a different ramp-up profile compared to what was previously agreed. An amount of R7 803m was provided for to compensate Exxaro for costs due to the revised delivery profile. This was not envisioned at the time that the MYPD3 revenue application was submitted. MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 17.5.4 Kusile Risk Sharing Agreement The construction of Kusile Power Station is ongoing. Eskom is still negotiating with Anglo Coal in an attempt to secure the long term coal for the station. The parties have signed a risk sharing agreement with certain milestone dates. Eskom provided for the amounts payable in terms of the risk sharing agreement during FY13. During FY15, interest of R16m was incurred on the provision. MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 18 Other Primary energy The MYPD methodology allows for other primary energy as pass through. Coal burn, OCGTs, IPPs and environmental levy have specific rules. 18.1 Allowed other primary energy in 2014/15 Other primary energy costs assumed for 2014/15 for purposes of the MYPD3 revenue decision was R5 535m. The details regarding some elements are presented hereafter. 18.1.1 Allowed other primary energy costs for 2014/15 The categories of costs allowed for 2014/15 will be referenced to the primary energy costs disclosed in table 25. Therefore other primary energy contains assumed costs such as start- up gas and oil of R1 570m, water costs of R1 957m, coal handing of R1 119m, water treatment costs of R265m, fuel procurement of R272m and nuclear cost of R352m as presented earlier. 18.2 Actual other primary energy in 2014/15 Eskom incurred R6 890m relating to other primary costs during 2014/15 with the major items being start up gas and oil, coal handling and water which is summarised in table below. The actual costs exceeded the MYPD3 decision of R5 535 million by R1 355 million. The overall 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). MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 other primary increased by R1438 million once the phasing in of the nuclear provision of R83 million is incorporated. In NERSA’s decision on 1 March 2016, the Regulator awarded the phasing in of nuclear decommissioning provision of R843 million in 10 equal instalments of R83 million per annum. Table 24: Other Primary Energy 18.2.1 Reasons for start-up gas and oil costs variance Heavy fuel oil starts and shuts down a coal fired power station and stabilizes 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 significantly higher in 2014/15 than what was anticipated at the time of the MYPD3 application and hence the use of fuel oil increased significantly as well. It should be noted that long-term outages which were required for mid- life refurbishment of mechanical and control and instrumentation plant were delayed on the existing fleet. This contributed to the increase in trips and unplanned outages. 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 very volatile and difficult to predict into the future with accuracy. RCA for 2014/15Actuals Variance RCA adjustm ent RCA 2014/15 Other Prim ary Energy Water 1 455 -502 0 -502 Start up gas & oil 2 634 1 064 0 1 064 Coal handling 1 699 580 0 580 Water treatment 384 119 0 119 Nuclear 532 180 0 180 Fuel procurement 186 -86 0 -86 Decommisioning nuclear - phased in per RCA 2013/14 decision 83 83 Other prim ary energy for RCA , R m illion 6 890 1 355 83 1 438 MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 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 R365m due to the unfavourable fluctuation in the Rand/Dollar exchange rate and issues that were outside management control (e.g. torrential rainfall).” 18.2.2 Reasons for coal handling costs variance A variance of R580m in favour of Eskom arose, due to movement of coal within the power stations being more than was originally envisaged. The main stations which contributed to the coal handling variance are highlighted below. Kendal 18.2.2.1 More coal was reclaimed from the strategic to the seasonal coal stockpile than anticipated. In addition strikes at the mines resulted in more coal reclaimed than planned. Kriel and Arnot 18.2.2.2 Higher actual coal handling rates incurred when compared to planning assumptions Komati and Grootvlei 18.2.2.3 Additional staff required to meet coal challenges at these stations Majuba coal silo collapse 18.2.2.4 A coal storage silo at Eskom's Majuba power station in Mpumalanga collapsed on Saturday, 1 November 2014. At the time of the incident all units were on load. Operating personnel reported a visible crack on Silo 20 and immediately evacuated all personnel working in the area. Fortunately no injuries occurred. The generation capacity at Majuba power station was curtailed as coal could not be fed to the affected units, and load shedding had to be implemented. MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 The increase in coal handling costs due to this event has contributed towards the RCA amount for this category. A short-term gap solution has been implemented to resolve the shortfall of electricity generated at Majuba as a result of this incident. This entailed the relocation and repair of the incline conveyors, previously fed by the collapsed Silo 20, and the installation of associated supporting infrastructure. Coal is being fed through an elevated mobile boom feeder, directly to the repaired incline conveyors through to the power station, with a coal throughput of 800 tons per hour. This has now enabled the power station to run at full load on all six units during the morning and evening peak and at an average of 85% load during non-peak periods. A second elevated mobile boom feeder was installed at the end of March 2015 to further ramp up plant performance. A more cost-effective interim coal handling system has been implemented. This solution entails the commissioning of a conveyor system to deliver coal to a distribution bin, with one conveyor delivering to each incline conveyor gantry at the station. This enabled Eskom to reduce the high operational expenditure associated with the short-term gap solution. The feasibility study for a permanent solution has commenced. The reconstruction of the collapsed silo and the reinforcement of the remaining silos are underway and are scheduled for completion by the end of 2017. 18.2.3 Reasons for water costs variance A variance of R502m materialised due to lower expenditures. The variance can be attributed mainly to the following factors:  The implementation of the Waste Discharge Charge being delayed.  Water augmentation projects were delayed  The lower than planned electricity tariff increases this resulted in lower water prices.  Although the coal fired stations produced less than planned, actual water consumption per unit of electricity was higher at most stations than had been estimated for purposes of the MYPD3 revenue application. MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 Water volumes 18.2.3.1 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 generally consume more water. Most of Eskom’s stations are beyond their half-lives. Although the coal fired stations produced less electricity than planned, actual water consumption per unit of electricity was higher at most stations than was planned. The overall water performance for FY15 was 1.56 l/uso against an assumption of 1.54 l/uso. 18.2.4 Reasons for fuel procurement costs variance A variance of R86m occurred due to lower expenditure. The variance was primarily because of lower expenditure on consultants planned for studies on the Waterberg strategy and on legal consultants. 18.2.5 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 was R61m (13%) more than what was applied for and thus a driver to the variance was the amount allowed by NERSA. Detailed reasons for the R119m disallowance were not disclosed in the reasons for decision for MYPD3. 18.2.6 Water treatment costs variance Higher water treatment costs incurred at Kendal, as chemical usage escalated due to passing valves not being repaired based on the need to operate the plant and thus not having space to make the repairs. Due to the floods that occurred at Matimba, the quality of the raw water quality deteriorated which required more chemicals to treat the water. MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 18.3 Other primary energy variance in 2014/15 RCA Other Primary energy variance = Other PE Actuals – Other PE decisions Actual other primary costs of R6 890m was incurred during 2014/15 which is more than the costs assumed in the decision of R5 535m that resulted in an over expenditure of R1 355m which is included in the RCA submission MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 19 Environmental levy The MYPD methodology allows for (under)/over recovery to be adjusted through the RCA mechanism as presented in the extract below: Eskom incurred environmental levy costs of R683m less than the MYPD3 determination for 2014/15. The fundamental driver to the variance for the environmental levy is due to a substantial decrease in volume offset by a slight decrease in renewable production and an increase in the system average auxiliary percentage. 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 2014/15. Environmental levy variance = Levy Actuals – Levy decision Eskom incurred actual environmental levy costs of R8 353m which was lower than the assumed levy costs of R9 036m in the MYPD3 decision equating to under expenditure of R683 m 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 under- recovery will be recorded in the RCA. MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 20 Demand Market Participation 20.1.1 Allowed DMP in 2014/15 Demand market participation and power buybacks assumed in the MYPD3 decision was R688m during the year. Table 25: Approved Demand Response (DR) Expenditure for MYPD3 Source: Table 36 of MYPD3 decision, 28 February 2013 Of the 171.5 MWs saved under the EEDSM initiatives, total projects verified during the 2014/15 year were 147.4 by Eskom and 24.1 by the Department of Energy. 20.1.2 Actual DMP in 2014/15 Demand market participation was underspent by R379 m during the year. Table 26: DMP comparison for RCA in 2014/15 The Demand Market Participation experienced challenges in uptake with reasons listed below. R'm2014/15 DMP and Power buy-back Applied for Funding1 973 Demand Savings (MW)3 355 R/MW0.59 DMP and Power buy-back Adjusted Funding-1 285 Demand Savings (MW)-1 618 R/MW-0.19 DMP and Power buy-back Approved Funding688 Demand Savings (MW)1 737 R/MW0.40 Demand market participation (DMP) in 2014/15 MYPD3 Decision Actuals Variance DMP (R’m)688309-379 MYPD3 2014/15 RCA Submission to NERSA 10 May 2016  The uptake from customers was not to the level as originally anticipated. With industrial, a threshold seems to have been reached where further uptake does not seem to be materialising.  New demand response products were proposed to attract further interest from customers. However, the response was disappointing.  Generally, customer appetite for Demand Response is low.  The lack of further growth in the economy resulted in fewer opportunities for potential customers to respond. 20.1.3 Computation of DMP variance for RCA in 2014/15 Eskom spent R309m for DMP progammes which was lower than the decision of R688m equating to under spend of R379m for the year. MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 21 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 pass- through 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).” 21.1 Reasons for OCGTs variance During the 2014/15 financial year Eskom utilised OCGTs at 2 653 GWh more than was assumed in the MYPD3 decision with the main intention to avoid load shedding. This is clearly stated in the MYPD Methodology para 8.4.2. “For avoidance of doubt, gas turbine generation should be employed before implementation of load shedding activities”. The cost of running the OCGTs for the additional 2 653 GWh resulted in Eskom incurring an additional R6 836m to reduce the impact of load shedding on the economy. Before the OCGTs were utilised, Eskom considered cheaper alternatives which included a combination of demand and supply levers from local and regional IPPs and demand response initiatives were considered. Eskom spent R4345m more on local IPPs and R1150m more on regional IPPs. Eskom did underspend by R379m on DMP due to a lower uptake from customers than originally anticipated. For industrial customers, a threshold seems to have been reached where further uptake does not seem to be materialising. MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 Additionally the lack of further growth in the economy resulted in fewer opportunities for potential customers to respond. Eskom has spent R299m less on DSM projects during the year. The major reason for the under spend was in response to the NERSA MYPD3 decision, where the demand aggregator programme fell away, and the focus reverted to the key industrial load. 21.2 Balancing the power supply system 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. 21.2.1 Actual OCGTs usage and load shedding in 2014/15 During 2014/15, a substantial number of load reduction events occurred when the available supply was insufficient to meet the demand. While only three events occurred over evening peak during winter, we had to implement load shedding and/or load curtailment on 34 days between 1 November 2014 and 31 March 2015. This resulted in supply interruptions of 574GWh after utilising both OCGT’s and IPPs. This meant that OCGTs were used during peak and off peak periods through the year.  OCGTs and IPPs usage reduced load shedding by providing additional capacity  Load reductions occurred substantially between November 2014 and March 2015. MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 Figure 4 : Load shedding impact in 2014/15 21.3 OCGTs allowed in MYPD 3 for 2014/15 For purposes of its revenue decision, NERSA assumed R2 710m for OCGT fuel cost. 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. A summary of the allowed OCGTs costs, rates and volumes as disclosed below. Table 27 : Summary of allowed OCGTs components Open Cycle Gas Turbines - 2014/15 GWh R million Fuel Litres ML Rand/Litre R/MWh Power stations Ankerlig 658 1 646 185 8.91 2 503 Gourikwa 368 934 103 9.02 2 534 Acacia 15 40 4 9.04 2 638 Port Rex 15 40 4 9.06 2 644 Non related fuel energy costs 51 Total / Averages 1 056 2 710 297 2 566 MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 In addition to the decision above, a further decision was taken by NERSA in January 2015 to increase the allowed OCGT usage in the last months of 2014/15 (i.e. January to March) to a total of 450GWh per month. 21.4 Actual OCGTs costs in 2014/15 The actual OCGTs energy cost was R9 546 million to produce 3 709 GWh during 2014/15 as presented in the table below. Table 28: Summary of OCGTs actual results for 2014/15 Open Cycle Gas Turbines - 2014/15 GWh R'million Fuel Litres ML Rand/Litre R/MWh Power stations Ankerlig 2 351 5 940 742 8.00 2 527 Gourikwa 1 226 3 031 385 7.88 2 472 Acacia 65 267 21 12.62 4 138 Port Rex 67 257 24 10.76 3 813 Non fuel related energy costs 51 Total/Averages 3 709 9 546 1 172 2 574 21.5 Computation of OCGTs claim for RCA purposes in 2014/15 In this RCA submission, Eskom has adopted the approach used in NERSA decision for RCA 2013/14 and is as follows: 1. Price pass through impact up to the 297ML per MYPD3 decision 2. Volumes above the assumed GWh are compensated at the actual average coal costs rate The OCGTs impact for RCA purposes for 2014/15 is R1 944 million which is summarised below with details for each component disclosed later. This is far lower than the actual variance of R6 836 million. MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 Table 29: OCGTs RCA summary 21.5.1 Price impact up to allowed diesel litre usage of 297ML (million litres) The MYPD methodology allows for the rate variance to be adjusted through the RCA mechanism as highlighted below. The MYPD Methodology states that as per para 8.4.1 “costs will be allowed as a full pass- through cost, but limited conditional to volumes allowed by the Energy Regulator, except where such use is necessary to ensure security of supply...” . During the 2014/15 period the actual price per litre varied between R8.00/L (Ankerlig) to R10.76/L (Port Rex) which is compared to decision rates for the respective power stations. Favourable price variances occurred at Ankerlig and Gourikwa where the majority of usage materialised. A summary is disclosed in the table below with the overall price variance of R263 million for the consumers’ benefit. Table 30 : OCGTs price impact for 297ML OCGT Sum m ary RCA am ount (R'm ) Excess volumes above allow ed GWh recovered at average coal cost - 538 Price variance on allow ed 297ML - -263 Recovery of 450 GWh for Jan~Mar 2015, provides 206 ML - 1 669 Total OCGT for RCA 1 944 MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 21.5.2 Excess volumes above GWh recovered at average coal costs Eskom generated 2244 GWh for the 9 months (Apr 2014 to Dec 2014) which exceeded the allowed 479 GWh by 1765 GWh. In addition excesses of 75GWh (Jan 2015) and 79 GWh (Feb 2015) were produced, resulting in a total of 1919 GWh above the allowed levels. Thus the total excess of 1919 GWh above the allowed levels for the year is recovered at the average coal cost of 28c/kWh, resulting in a recovery of R538 million in Eskom’s favour. Table 31: OCGTs RCA claim related to excess volumes above allowed GWh 21.5.3 Recovery of the 450 GWh for January 2015 to March 2015 Eskom approached NERSA in January 2015 requesting approval of higher OCGTs usage for the 3 months covering January 2015 to March 2015. NERSA granted the approval of OCGTs usage up to 450GWh per month on 23 January 2015. This resulted in an additional 206ML being utilised which is recovered via the RCA at the actual rates per station. Therefore the RCA recovery for the 206ML is R1 669 million as disclosed in the table below. MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 Table 32 : Special allowance for OCGTs usage up to 450GWh per month (Jan~Mar 2015) provides an additional 206ML 21.5.4 OCGTs variance for 2014/15 RCA OCGTs for RCA = Price pass through limited to 297 ML per decision + Excess volumes of 1 919 GWh compensated at average coal costs rate 28c/kWh + Special allowance for 450 GWh per month (Jan2015~Mar2015), adds a further 206ML Eskom incurred OCGTs actual costs of R9 546m compared to the assumed costs in MYPD3 decision of R2 710m which results in a variance of additional expenditure of R6 836m. However for RCA purposes, Eskom used the approach taken by NERSA in its RCA 2013/14 decision to compute the OCGTs RCA for 2014/15 which results in a claim of R1 944 million. Eskom believes that based on the conditions of the day and choices which were available in 2014/15, the efficient and prudent option of operating the OCGTs in and outside of peak hours was the correct decision for the country. Price variance based on 450GWh cap Actuals Rand/Litre Additional ML based on 450GWh cap RCA am ount (R'm ) Ankerlig8.00 128.3 1 027 Gourikw a7.88 71.3 562 Acacia12.62 3.2 41 Port Rex10.76 3.6 39 Total price variance206.5 1 669 MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 21.5.5 Actual Plant performance in 2014/15 This section will focus on four measures viz. UCLF, PCLF, EAF and EUF. During 2014/15 the Generation fleet delivered plant performance which was lower than that assumed in the MYPD3 determination. The drop in EAF is primarily attributable to the high UCLF. Table 33 : Definitions of technical performance parameters Measure Descriptions EAF Measures plant availability including planned and unplanned unavailability and energy losses not under plant management control UCLF Measures the lost energy due to unplanned energy losses resulting from equipment failures and other plant conditions. PCLF Energy loss during the period because of planned shutdowns OCLF Energy loss during the period because of unplanned shutdowns due to conditions that are outside Generation management control EUF Measures the degree to which energy was produced compared to the extent to which it could have been produced. Table 34 : Comparison of Generation technical performance Generation Fleet Plant Performance MYPD3 Decision 2014/15 Actuals EAF 81.8% 73.7% PCLF 11.4% 9.9% UCLF 5.9% 15.2% OCLF 0.9% 1.1% For 2014/2015, EAF was 73.73%, lower than the 75.13% for 2013/14 .The MYPD3 was based on an assumption of 81.83%. The lower EAF was primarily due to high unplanned energy losses, indicated by a UCLF of 15.22%. MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 The unplanned capability loss factor (UCLF) for the year 2014/15 is slightly higher than previous years, indicative of ageing generating plant, the related deteriorating plant health and the high utilisation of the plant. The UCLF for 2014/15 was 15.22% compared to 12.61% in 2013/14 and 12.12% in 2012/13. The energy efficiency improvement programme aims to improve the heat rate of the units at Eskom’s 13 coal-fired stations. Heat rate measures the efficiency of the conversion of heat from the energy source (coal) to electricity generated. Improvements would indicate an improvement in plant performance and will help reduce Eskom’s environmental footprint, including its carbon emissions. Table 35: Average Eskom coal power station heat rate for period 20112/13 to 2014/15 The overall heat rate (plant performance) improved in 2014/15 by 0.35%, when compared to in 2013/14. Unplanned capability loss factor 21.5.5.1 The unplanned capability loss factor (UCLF) has reflected a deteriorating trend from a UCLF of 8% (2012) to a UCLF of 15.22% (2015) indicative of ageing plant and related deteriorating plant health conditions as well as the increased utilisation of the plant. Table 36: Breakdown of system UCLF (%) MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 The main contributors to UCLF were as follows: 21.5.5.2 21.5.5.2.1 Partial load losses The partial load losses continue to contribute significantly to the system total unplanned losses, and continue to increase. The unplanned capability loss factor to these losses was 5.65%, contributing 37% of the system UCLF. The main reasons for the partial load losses were unavailable space for maintenance outages to resolve problems at the draught plant (22%), mills (13%), turbine (17%), gas cleaning (14%) and feed water (9%). Maintenance was focused on safety and philosophy outages which were prioritised. This figure excludes the partial load losses that occurred due to the silo collapse at Majuba Power Station, which contributed 0.26% to the partial load losses UCLF of 5.65%. 21.5.5.2.2 Boiler tube failures Boiler tube failures are typically the result of welding repair damage, corrosion and fly ash erosion. In the year to March 2015, there were 203 boiler tube failures, with a UCLF of 2.00%, contributing 13% to the system UCLF. This is lower in both number and UCLF contribution when compared to the previous year when a total number of 210 failures and a UCLF contribution of 2.18% were recorded. The unplanned energy loss attributed to boiler tube failures has been decreasing since January 2014, showing an improving trend. Energy utilisation factor (EUF) 21.5.5.3 Energy utilisation of the available plant was high with the coal fleet, in particular, being utilised significantly above design levels. MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 Figure 5 : Monthly Energy Utilisation Factor in 2014/15 The utilisation of available plant capacity (EUF) was significantly higher than industry norms and that of the coal fleet was higher than the previous four years due to the increased loading of available plant to match the demand. The overall fleet EUF was at 83.42% (2013/14: 83.55%). The utilisation of the coal-fired units for the year to 31 March 2015 was 93.02%; nuclear at 99.47% and peaking stations (including the OCGT stations) achieved 20.63%. Relationship between EUF, EAF and UCLF 21.5.5.4 This deterioration in availability performance is a direct result of the constrained system due to insufficient generating capacity being added timeously. This necessitated both the rolling of outages and limited the space to perform all the necessary maintenance required to both stabilise and improve station performance. In addition, the constrained system has necessitated sustained and high load factors of the coal fleet, at the limit of design levels, which have led to higher stresses, particularly on the boilers. On top of this, the regular operation of units in a compromised condition (for example with a boiler tube leak), in order to avoid system load-shedding, has caused additional consequential damage and contributes significantly to the performance deterioration. MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 Figure 6 : Relationship between high EUF to EAF and EUF The figure above indicates that the utilisation / load factors (EUF – Energy Utilisation Factor) for Eskom’s coal fleet increased from around 83% in 2006 to over 90% from 2013. More significant, however, is that the average design parameter for the coal fleet was for a EUF of around 82%-85%. This means that over the last decade Eskom’s coal fleet has been operating at EUF levels above their design parameters. This has contributed to the upward trend in UCLF over this horizon. The EAF trend has been decreasing over the past few years especially since 2010 when EUF was operating at levels approaching and exceeding 90% as disclosed in figure above. The high operating levels of coal plants over the last decade has affected the EAF performance which reached 73.73% by March 2015. Energy availability factors are an outcome of the planned and unplanned maintenance which has occurred. MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 22 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. 22.1 Regulated asset base adjustment for CECA Capital expenditure will affect the value of the regulated asset base (RAB). The actual capital expenditure for the RAB incurred during 2014/15 was R54 394m compared to MYPD3 decision assumption of R45 113m thus resulting in a variance of R9 281m. However, only capex changes that affect the RAB are adjusted for CECA purposes. The total variance of R9 281m comprises Generation capex overspend by R11 703m, Transmission underspend by R1 738m, Distribution underspend by R1 284m and balance is attributable to other capital expenditure. However, for RCA purposes not all changes to capital expenditure affect the regulatory asset base and thus will not qualify for RCA related changes. After making these adjustments the RAB is adjusted downwards with R1723m. 22.1.1 Step 1: Computing change in RAB 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 MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 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 variance of R1 890m. Table 37: Calculation average capital expenditure CECA Calculation -Variance between actual and allowed capex Calculation ref Eskom Company Allowed MYPD capital expenditure45 113 Less: Allowed capital expenditure excluded from the RABA(15 355) Future fuel(3 014) Technical and refurbishment capital expenditure(12 341) Allowed MYPD RAB capital expenditureB29 758 Actual MYPD capital expenditure54 394 Less: Actual capital expenditure excluded from the RABC(20 857) Future fuel(1 651) Payment received in advance recognised to revenue(1 423) Technical and refurbishment capital expenditure(17 783) Actual MYPD RAB capital expenditureD33 537 Annual difference(1 723) Technical and refurbishment capital expenditure excluded from RABC - A(5 502) RAB capital expenditureD - B 3 779 Average capital expenditure difference for CECA calculation(D-B)/21 890 Allowed Return - NERSA MYPD 3 decisionE3.75% MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 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 claim of R91m is computed by applying the allowed RoA to the capex variance. 22.1.2 Calculation of the CECA claim For purposes of the calculating the CECA claim, the allowed RAB of R706 391m is adjusted for the capex variance of the current and prior year.The current year capex variance used is the average of the annual movement in the RAB capex of R3779m shown in table 34 above which equates to R1890m. MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 Table 38: CECA Calculation: Return due to/by Eskom 22.2 MYPD3 decision Below are extracts from MYPD3 decision reflecting approved RAB of R706bn and returns on asset at 3.75%, generating returns of R26 511m and assuming a capital expenditure of R45 513m. Table 39 : Regulatory asset base for 2014/15 Source: Table 10 of MYPD3 decision, 28 February 2013 Table 40: Returns and percentage allowed in 2014/15 Source: Table 9 of MYPD3 decision, 28 February 2013 CECA Calculation : Return due to/(by) Eskom Calculation ref Eskom Company MYPD3 Regulatory assets base706 391 Add /(Deduct): Current year average capex variance1 890 Add/ (Deduct): Cumulative prior year capex variances 536 Adjusted RAB A708 817 MYPD3 allowed return on assetsB26 511 Return on adjusted RABA * C26 602 Increase / (Decrease) in return for RCA (A*C)-B 91 MYPD3 allowed return expressed as a percentage of the rate baseC3.75% R'm2014/15 RAB Applied for852 265 RAB Adjustment -145 874 RAB Approved 706 391 R'm2014/15 Real Pre-tax WACC (%)3.8% Return (R'm)26 511 MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 Table 41: Capital expenditure in 2014/15 Source: Table 11 of MYPD3 decision, 28 February 2013 22.3 Reasons for variance between actual and decision Looking back on 2014, the single biggest commitment was to achieve the first synchronisation of Medupi Unit 6 in the second half of 2014, with a target date of 24 December 2014. However, first synchronisation was delayed to 2 March 2015, due to labour unrest during 2014, as well as a number of technical challenges experienced during the ramp-up period. Commercial operation of Medupi unit 6 occurred on 23 August 2015. The first wind turbines of the 100MW Sere Wind Farm were energised in October 2014 as planned, and Sere was placed in commercial operation on 31 March 2015. Eskom spends approximately half on new build projects through the Group Capital division and the other half incurred on the combined portfolio of existing Generation assets, Transmission and Distribution networks. Table 42: Capital expenditure for 2014/15 R'm2014/15 Capex Applied for67 941 Capex Adjustment -22 828 Capex Approved 45 113 MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 The table below shows the reconciliation of capital expenditure between the integrated report as shown above and amount used in the CECA calculation. Table 43: Capital Expenditure (excluding capitalised borrowing costs) per division 22.4 Delivering on capital expansion Since 2005, Eskom has been expanding its generation and transmission capacity to meet the country’s growing demand for energy. Eskom’s nominal generating capacity in 2005 was 36 208MW. The programme will increase this by 17 384GW by 2019/20. The key generation expansion projects are the 4 764MW Medupi and 4 800MW Kusile coal-fired stations, and the Ingula pumped-storage scheme in the Drakensberg, which will deliver 1 332MW of hydroelectricity during peak demand periods. Transmission line length and substation capacity will also increase substantially. The capacity expansion programme has cost R265billion (excluding capitalised borrowing costs) to date. Since inception, the programme has resulted in additional generation capacity of 6 237MW, mainly through the RTS programme, 5 816km of transmission lines and 29 655MVA of substation capacity. Reconciliation between Eskom Integrated Report capex and CECA disclosures2014/15 Group capital31 691 Generation10 555 Transmission1 121 Distribution6 073 Subtotal49 440 Add Adjustments :4 954 Exclude DOE capex included as part of Distribution - Include Future fuel capex 1 651 Include Corporate and other 3 303 Total per CECA disclosure54 394 MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 22.4.1 Medupi First synchronisation (or first power) of Medupi Unit 6 was achieved on 2 March 2015, with full load achieved on 26 May 2015, at which time the unit delivered full power of 794MW to the national grid. Commercial operation was achieved on the 23 rd August 2015. The unit is the biggest coal-fired unit of its kind in Africa, and the first coal-fired unit to be brought online since the last unit of Majuba in 2001. During the testing phase, while combustion optimisation of the unit continues, output from the unit is variable. The testing phase ensures that all systems are fully operable and reliable for handover, and the unit is safe to operate and perform as designed for the next 50 years. Normal commissioning and optimisation issues are being resolved as they arise, without any significant holdups to reaching commercial operation expected. Additional resources were mobilised to Unit 6 by both the boiler and C&I (control and instrumentation) contractors to mitigate any resource-driven delays. Additional shifts were introduced 24 hours a day, seven days a week in order to accelerate progress on site. We continue to work with contractors to resolve any issues that could affect the schedule. The critical path to first synchronisation included the delivery, installation, testing and integration of the boiler protection system, together with the distributed control system. The recovery strategies that were put in place to implement solutions to the post-weld heat treatment that were reported previously were successful and the technical issues surrounding welding on the Unit 6 boiler reported last year were resolved. The weld procedure requalification exercise was completed, with all weld procedures verified and accepted by both Eskom and the authorised inspection authority. Furthermore, a number of key milestones were achieved during the past year, all leading up to first synchronisation  Successful completion of the boiler chemical clean, the draught group test run and the site integration tests for Unit 6 and the balance of plant, as well as the water treatment plant  First coal was delivered to the coal stockyard, Coal Stacker 1 was safety cleared and commissioning of the coal stacker and coal mills is progressing well MYPD3 2014/15 RCA Submission to NERSA 10 May 2016  First oil fire of Unit 6 on 17 October 2014, followed by first coal fire on 27 November 2014,  Boiler blow-through on 2 January 2015 and steam to set on 12 February 2015 The Transmission integration implementation is ready for the synchronisation of all six units to the Eskom grid, and all required auxiliary services for the whole power station are ready to deliver power to the grid, as and when the remaining units come online. Originally, the commissioning of the next unit, Unit 5, was forecast to occur within six months of bringing Unit 6 online. However, due to the challenges experienced at Unit 6 this will not be possible, as resources were redeployed from Unit 5 in an attempt to recover the schedule at Unit 6. The cumulative cost incurred on the project is R84.7 billion (2013/14: R77 billion) against a total budget of R105 billion, as disclosed in the Eskom Integrated Report March 2015. All amounts exclude capitalised borrowing costs. 22.4.2 Kusile Eskom signed a mutual termination agreement with Alstom regarding the C&I works, after which a contract was awarded to ABB to supply the C&I systems for all units at Kusile. This is considered to be an important step in mitigating one of the largest risks on the project. A number of important milestones on Unit 1 have been achieved over the past year, including successful completion of the steam turbine lube oil system flush, setting the generator step-up transformer into place and the unit being placed on electrical barring. Work related to the flue gas desulphurisation scope of work was also completed recently. Unit 1’s boiler air leak test and hydrotest were successfully conducted during April 2015. Good progress has been made on the civil works for all units, with the boilers of Units 1 to 5 in various stages of construction. Boiler erection, already completed at Unit 1, is expected to drive the critical path for Units 2 to 6. MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 With effect from 1 September 2014, the Kusile Execution Team and contractors began implementing productivity improvement plans that include working additional shifts, more weekends, as well as selected crews and contractors working critical areas during the traditional builders’ break in December. The ramp-up to commissioning of Unit 1 will include strategies to support around-the-clock commissioning activities. The project team remains focused on critical activities necessary to achieve the earliest possible first synchronisation of Unit 1, as well as improving productivity and clawing back schedule on all six units. The cumulative cost incurred on the project is R78.7 billion (2013/14: R66.6 billion) against a total budget of R118.5 billion, as disclosed in the Eskom Integrated Report March 2015. All amounts exclude capitalised borrowing costs. 22.4.3 Ingula The Mine Health and Safety Act (MHSA) Section 54 work stoppage was lifted completely in September 2014, allowing underground works to resume, although the Presiding Officer’s report has not yet been received. Since the tragic incident on 31 October 2013, progress was significantly impacted resulting in limited progress for a period of approximately 12 months. However, the lifting of the work stoppage will enable acceleration of the construction schedule. Despite the delays, the operation floors of Units 3 and 4 have been completed and handed over to mechanical and electrical contractors; the machine hall of Unit 1 was also completed and handed over. In addition, diesel generator safety clearance and cold commissioning were achieved in September 2014, while all four generator-transformers have been installed underground, with the gas-insulated switchgear systems connected on the high-voltage side of the transformers. To date, two of the transformers have been filled with 83 000 litres of oil each. Environmental authorisation and water-use licences have also been received. However, industrial action has led to delays in installation of the heating, ventilation and air conditioning (HVAC) ducting for the control room. Delays have also been experienced in the main underground civil works. MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 The cumulative cost incurred on the project is R22.8bn (2013/14: R19.4bn) against a total budget of R25.9bn, as disclosed in the Eskom Integrated Report March 2015. All amounts exclude capitalised borrowing costs. 22.5 New build cost changes On the back of the new build delays in commissioning, there have been costs increases in these projects when compared to the MYPD3 decision as summarised below. 22.5.1 Medupi: Cost overruns The project experienced deviations mainly due to the movements on Packages, claims and Owner Development Costs (ODC). Drivers of cost increases include the following:  Schedule delays - Historical delays due to labour unrest, poor productivity and Force Majeure events.  Owners Development Costs (ODC) - New manpower structure with additional positions in critical roles to address key risks (e.g., quality). - Dispute Adjudication Board (DAB) team to support claims management. - Delay in demobilization of resources in line with schedule delays. 22.5.2 Kusile : Cost overruns These schedule impacts have been the major driver of cost increases. Eskom has taken critical steps to mitigate against some of the challenges at Medupi and Kusile.  Schedule delays - Industrial actions - Quality issues / welding repairs in boiler. - Design change and increased scope due to permitting requirements. - Culvert permit delays. MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 - Failed Contractors (COSIRA and NIC Failures), - Overall poor productivity by all contractors with Hitachi and GLTA being the largest contributors.  Interventions include these challenges include: - Signed a modified Partnership Agreement (PA) between Eskom, contractors, and labour. - Reviewed and optimized the model according to which contractors are managed. - Removed C&I scope from Alstom at Kusile due to underperformance. - Signed Memorandum of understanding with boiler contractor to turnaround boiler contractor performance. - Eskom now taking a lead to pro-actively manage the contractors. Panel members now provide support to Eskom teams. - Co-location of key technical experts from Eskom and Contractors at sites to provide quick turn around on key decisions in support of fast tracked schedules. - War-rooms set up at Medupi and Kusile sites. This is meant to deal with issues on a daily basis as and when they arise. 22.5.3 Ingula : Cost variances The total project cost at Ingula is at risk mainly due to the following:  Package cost / Compensation Events from the Main Underground Civil Contractor.  Owners Development Cost (ODC) – Schedule delays will result in additional ODC due to delayed de-mobilisation.  Cost Price Adjustment (CPA) – Schedule delays with result in additional CPA due to later cost flows. 22.5.4 Delays in new build capacity The first contributor to the capacity shortage is the delays of new build capacity. According to the 1998 Energy White Paper the investment decision for new base load power stations needed to be made by, not later than, 1999 in order to meet increasing demand by 2007. However, the approval for Eskom to embark on the build programme was made in late 2004, MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 with the final approval of the first new base load capacity investment decision (Medupi) being made in December 2006, thus at least 7 years later than the latest date envisaged in the Energy White Paper. This resulted in the needed capacity not being available when needed. The project execution has been exacerbated by time constraints for the planning and feasibility stages (which commenced at end 2004) which did not allow nearly enough planning and development work upfront on Medupi and Kusile. This and other factors such as it being the first major project in sixteen years resulted in it not being possible to emulate the international best practice time-period of around 54 months to commissioning of the first units nor the average construction time of 60 to 66 months (however, typically for power stations of two units not six units). Lazard's ‘Levelized Cost Of Energy Analysis—Version 7.0’ of August 2013 gives typical coal power station construction time as 60-66 months. However this is mostly based on US data. The typical coal power stations that have been constructed in the US over the last decade or so were sized between 300MW to 850MW and consisted of, e.g. just in 2010 there were 10 such plants commissioned in the US. It might well be that it takes longer to get to commercial operation of the first unit if such unit is part of a 6 unit power station, compared to a one or two unit station. In addition to that, there are further factors to take into account in ‘translating’ the 60-66 month period to SA for purposes of establishing an efficient norm (not an exhaustive list):  Locality: Much longer distances from suppliers, less skilled local workforce, less developed local infrastructure etc.  Project management and construction capacity: Very little construction activity on new coal power plant since completing the previous build-phase around 1992 (the only activity was the delayed completion of Majuba). Eskom’s project management skills and capacity was mostly lost after 1992. The industrial policy from 1997 to 2004 also prohibited Eskom from further generating capacity investments. “Eskom is not allowed to invest in new generation capacity in the domestic market”. The contractors’ local facilities and skills were also lost over this period. Eskom thus had to completely re-establish its new-build project management capability when the ESI policy changed in late 2004 and Eskom got approval to commence with the MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 build programme, as did many of the contractors. It would have also had to acquire new skills and competencies based on the new technologies available.  Learning curve: After a sixteen year interval, for Eskom the new-build process implied the starting point of the learning curve again.  Up-front planning and preparatory work: When the new-build task was restored to Eskom it was already apparent that there was a generation capacity crisis. Commencing in 2005 the preparation of the ‘business cases’, the investment decisions, the technical designs for the process of requesting tenders, and the adjudicating and awarding of such tenders were completed. The approval of the first new base load capacity investment (for 3x700 MW = 2100 MW) was made in December 2005 and revised by December 2006 to become the 4 764 MW ‘Medupi’ – all within less than two years from receiving the go-ahead. Medupi’s main contracts were placed in October 2007, with Kusile shortly after. Time constraints did not allow nearly enough planning and development work upfront – e.g. Eskom could not follow the normal process for Medupi but went ahead with tendering and contracting based on ‘virtual’ designs i.e. Eskom went to the market using the designs for the 4110MW Majuba power station, which had been designed in the 1980s.  Total projects portfolio: In parallel with the programme to construct the 4 764 MW Medupi base load coal plant, Eskom also: o Embarked on the programme to construct the 4 800 MW Kusile; o Started and have since completed the refurbishment and re-commissioning of three older coal fired power stations (23 units of 3 500 MW in total over the period July 2005 to October 2013); o Constructed and commissioned 2 000 MW of OCGT capacity; o Commenced construction of 1332 MW Ingula pumped storage; and o Executed large Transmission projects Starting with the US norm of 60-66 months, some months should be added for each factor to arrive at a more realistic norm for the construction duration given the specific South African and Eskom context. The 60-66 months US norm very quickly becomes 84-90 months or more, in this context. MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 Overall the root cause is the failure of the previous ESI policy to attract IPP investment for power plants of the required size and at the required time. Additional years were lost before that situation, as well as the crisis regarding commencement of the new build programme, became apparent. It further resulted in the loss of project management skills and construction skills and capacity in Eskom (and also in the local contractors). These factors impeded Eskom and set them further back on the learning curve, forcing a rushed design and commercial process, once approval was obtained. In the end the Medupi start-date was already behind schedule by approximately eight years. 22.6 Why the RAB must be indexed MYPD Methodology: The MYPD Methodology (section 6.4.4) requires the RAB to be valued at Modern Equivalent Asset Value (MEAV) where; “Each year the MEAV value will change. Because it is not practical to conduct an entire MEAV study every year, the value from the last year studied will be increased by the Producer Price Index, each year, until the next MEAV study is carried out, after which the process will repeat itself”. Why indexation  The annual indexation of the RAB is required due to the use of a ‘real’ (rather than a ‘nominal’) rate of return. The inflation impact that would otherwise be reflected in the value of the ‘nominal’ rate of return is instead reflected through the annual inflation indexing of the RAB.  This allows for the recovery of the shortfall in the return of that original year by spreading it over the remaining operational life of the asset.  In the event that a ‘real’ rate of return is used, annual indexation of the RAB is required in order to achieve full cost recovery (as stipulated by the ERA and the EPP) over the life of the assets. MYPD3 2014/15 RCA Submission to NERSA 10 May 2016  Due to very long asset lives; mergers of companies; changes in accounting systems etc., it can in practice be difficult to track original acquisition costs and accumulated depreciation in detail per asset over the long asset life.  A valuation methodology such as depreciated MEAV is often used as an acceptable and reasonable proxy for the inflation indexing of depreciated historical acquisition cost. Annual increase by inflation rate Given that it is quite onerous to perform a complete MEAV every year, section 6.4.4 provides for annual increase the MEAV value by the inflation rate, in between formal revaluations. Given that the typical main driver of an annual change in the MEAV will in any event be the annual inflation rate, inflation indexing would be a reasonable proxy for an annual change in the MEAV CECA mechanism for indexation At the time of publishing the Methodology the changes to the RAB were probably envisaged to be due to movements in capex. However since the MYPD3 decision did not factor in the annual indexation at the beginning as part of the Decision (or, by implication assuming the inflation rate on the RAB at nil), it would be appropriate to include the indexation adjustment on each year’s RAB opening balance into the CECA mechanism i.e. to reflect the change between the actual inflation rate and the inflation rate as assumed for purposes of the MYPD3 revenue decision (in this case, nil percent). The MYPD3 Reasons for Decision also confirms that the RAB would be subject to periodic revaluation – it is assumed that this implies annual revaluation, as required by the MYPD Methodology. Obviously if such revaluation takes place it will mean little if the revaluation is not factored into the CECA. Eskom recommends including the effect of the annual indexation into the CECA mechanism, with the resultant revenue adjustment thus being addressed through the RCA. 22.7 Conclusion on capital expenditure A number of key strategic challenges exist that require a Eskom Capital Portfolio of R300bn, as opposed to NERSA assumption of R230bn for purposes or the MYPD3 revenue decision MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 A rigorous process incorporating world’s best practices for capital prioritisation and optimisation was utilised to allocate the R251bn funding available over the MYPD3 period. MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 23 Inflation adjustment In compiling the inflationary adjustment, cost of cover and arrear debts 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 of 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 44: Inflation Data Table 45 : Inflation adjustment Inflation data2013/142014/15 Inflation - Decision 5.60%5.70% Inflation index - Decision 1.0561.057 Inflation - Actual5.70%6.10% Inflation index - Actual1.0571.121 Inflation adjustment for 2014/15 Calculation ref 2014/15 Total operating costs allowedA36 717 Decision inflation indexB1.115 Actual inflation indexC1.121 Restated allowed costs based on actual inflationD=A/B*C36 926 Inflation adjustment R'mD-A209 MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 24 Energy efficiency and demand side management (EEDSM) 24.1 Demand side management Demand side management is divided into two broad programmes, as discussed below: 24.1.1 The demand-response programme Consists of a range of sub-programmes which offers commercial and industrial customers financial incentives to reduce their electricity requirements as and when needed. Before being placed on hold, the requirements for taking up demand response programme products (standard product and standard offering) were amended to allow smaller companies to participate in the programme. Eskom spent R309m on demand market participation and R653m on demand side management programmes. The reduction in costs from previous year was mainly attributable to the decrease in the power buyback programme. 24.1.2 The Residential mass roll-out programme This Programme aims to reduce residential electricity usage by encouraging households to use energy-efficient technologies. The programme is a significant lever to reduce demand during periods of system constraint. It includes the following sub-programmes:  The focus in the residential sector was the rollout of Phase 3 of compact fluorescent lamps (CFLs), a total of 390 643 CFLs were installed inception-to-date, against a target of 500 000. It must be noted that the roll-out period spans 2 financial years.  The solar water-heater programme – Demand savings of 24.1 MW and energy savings of 153.0 GWh were installed and verified as part of the DoE SWH Programme at a cost of R2m for FY 2014/15. 24.2 Energy-efficiency measures Eskom’s Power Alert and “5pm to 9pm” campaigns were utilised to reduce power demand during the evening peak. The average weekday evening peak impact for the period under MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 review for all colours (green, orange and red) is 224 MW. The average impact for the red flightings in the evening peak on the worst constrained day is 294 MW. Eskom’s utilised the 49M campaign, a long-term behavioural-change initiative that encourages energy efficiency practices, particularly for residential users, which has the ultimate goal of reducing energy consumption by 10%. This includes targeted seasonal campaigns such as the “beat the peak” campaign and the “live lightly” campaign. 24.3 Energy Efficiency demand Side Management (EEDSM) 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. 24.3.1 Allowed EEDSM for 2014/15 The allowed rate for EEDSM savings is R3.24m/MW with 294MW savings being assumed which will cost R953m. MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 Table 46: Allowed EEDSM Source: Table 40 of MYPD3 decision, 28 February 2013 24.3.2 Actual EEDSM for 2014/15 Demand side management interventions encourage customers to use electricity more efficiently, thereby reducing the gap between supply and demand in the short to medium term. During the year, IDM conducted a number of programmes to manage demand and improve energy efficiency as outlined below. Table 47: Verified demand side management and internal energy efficiency savings Measure and unit Actual 2014/15 Actual 2013/14 Demand savings (evening peak), MW 171.5 409.6 Energy savings, GWh 816.2 1 363.0 Internal energy efficiency, GWh 1 10.4 19.4 1. Target not set, as funds have not yet been allocated. Demand savings of 171.5 MW (including DOE savings of 24.1 MW) were substantially lower than the MYPD3 decision of 294 MW due to funding constraints. R'm Applied forApproved Funding2 709 953 Programmes Peak Demand savings (MW)358 294 Programmes Annualised Energy savings (GWh)1 361 1 204 Programme Costs2 419 612 Operating Costs including Depreciation481 341 Other costs-191 - R/MW7.57 3.24 R/kWh1.99 0.79 2014/15 MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 As verified MW is used for determining the savings for the RCA computation, there exists a roll over between financial years relating to the time when projects are implemented and the actual verification of the MW savings. Therefore reconciliation is required to determine the verified MW as presented in the table below. Table 48: Reconciliation between demand savings MWs used in RCA Calculation The table above strips out the DOE funded EEDSM programmes of 24.1 MW which is excluded from the RCA as the tariff did not fund the initiatives. Prior year savings relating to tariff funded projects which are verified in 2014/15 of 100.5 MW are included in the RCA. Hence the total capacity verified for 2014/15 after all the adjustments is 247.9 MW as is reflected in the M&V report submitted to NERSA. The EEDSM performance relating to capacity savings and costs are summarised in the table below. Table 49: EEDSM comparison for RCA in 2014/15 Reconciliation between demand savings MWs reported in AFS to MWs used in RCA 2014/15 MWs achieved in current year (incl DOE) per AFS and Integrated report171.5 Less : MWs installed but not verfied in current year Less : DOE funded MWs achieved -24.1 Add : MWs achieved in the prior year but verfied in current year 100.5 Total verfied demand savings (MW) for RCA247.9 Energy Efficiency & Demand Side Management (EEDSM)MYPD 3ActualsVariance Funding (R'm)953 654 -299 Programmes - Peak Demand savings (MW)294 172 -123 Programmes - DOE funded actual MW savings (MW)24 24 Programme costs (R'm)612 440 -172 Operating costs incl. depreciation (R'm)341 205 -136 Other costs (R'm)- 9 9 EEDSM Rate (R/MW)3.24 4.43 1.19 EEDSM Rate based on verfied MW savings for RCA (R/MW)3.24 2.64 -0.60 MW savings for RCA purposes (MW)294 248 -46 MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 Note 1 – Actual EEDSM using the AFS results equates to R3.81/MW (R654m/(172MW- 24MW). The actual savings MW includes DOE funded savings which is excluded to determine the pure MYPD3 actual rate. Note 2 – For RCA purposes, the verified MW savings is used which results in a lower average rate of R2.64/MW (R654m/248MW) This adjusted rate arises because of the implied timing difference between when programmes are implemented and when the capacity (MW) savings are verified. Based on this rate of R2.64/MW compared to the decision of R3.24/MW, Eskom should have received a benefit for delivering progammes at the lower rate. 24.3.3 Computation of EEDSM for the RCA Following the MYPD3 RCA 2013/14 decision, NERSA has computed the EEDSM which comprised a penalty for under achieving MW savings multiplied by the allowed rate (R/MW). Eskom has computed the IDM impact for the RCA purposes on the basis of shortfall of 46.1MW multiplied by allowed rate of R3.24m/MW equating to an RCA impact of R149m in favour of the consumer. EEDSM penalty = R3.24m/MW X - 46.1MW = - R149m The current EEDSM regulatory rule does not allow for incentive where the MW savings exceed the assumed targets and is a one sided rule which penalises Eskom when capacity savings are not met. MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 25 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. 25.1 Allowed operating costs in 2014/15 The MYPD3 decision comprised the building blocks for allowed revenue per the MYPD Methodology as described earlier in the document. The allowed operating costs disclosed allowed for total revenue of R906bn over the five year horizon. However, following the subsequent revision of the total revenue from R906bn to R863bn was attributable to operating cost component and thus reduced to cater for the revision. The allowed total operating cost was R39 417 million, which is represented by operating costs excluding the ancillary charges of R40 095m reduced by corporate depreciation of R678m included in the total corporate overheads. Table 50 : Total operating costs in MYPD3 decision Source: Table 52 of MYPD3 decision, 28 February 2013 R'm2014/15 Total Applied for57 527 Total Adjustments -17 432 Total Approved excl Ancilliary charges 40 095 Transmission Loss & Ancilliary charges8 470 Total Approved48 565 MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 Some of the cost categories within operating costs are presented below. 25.1.1 Allowed employee costs in 2014/15 Table 51: The allowed employee costs for Generation, Transmission and Distribution Source: Table 43 of MYPD3 decision, 28 February 2013 25.1.2 Allowed maintenance costs in 2014/15 Table 52: Allowed Maintenance Costs Source: Table 44 of MYPD3 decision, 28 February 2013 25.1.3 Allowed arrear debts in 2014/15 Table 53: Allowed Arrear Debts Source: Table 49 of MYPD3 decision, 28 February 2013 R'm2014/15 Manpower Applied for19 103 Manpower Adjustments-2 646 Approved Manpower 16 457 R'm2014/15 Maintenance Applied for13 119 Maintenance Adjustments-1 246 Approved Maintenance 11 873 R'm2014/15 Arrear Debt Applied for1 051 Arrear Debt Adjustments-180 Approved Arrear Debt 871 MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 25.1.4 Allowed cost of cover in 2014/15 Table 54: Allowed Cost of Cover Source: Table 48 of MYPD3 decision, 28 February 2013 25.1.5 Allowed corporate costs in 2014/15 Table 55: Allowed Corporate Costs in 2014/15 Source: Table 51 of MYPD3 decision, 28 February 2013 25.1.6 Other operating costs in 2014/15 Table 56 : Other operating costs 25.2 Actual operating costs in 2014/15 During 2014/15 Eskom incurred operating costs excluding IDM of R49 534m which compares to the MYPD3 assumption of R39 417m resulting in over expenditure of R10 117m. As there is an overall over expenditure position, Eskom operating costs don’t qualify for the RCA adjustment except for the inflation adjustment. . R'm2014/15 Cost of Cover applied for1 829 Cost of Cover adjustments- Approved Cost of Cover1 829 R'm2014/15 Corporate overheads Applied for7 557 Corporate overheads Adjustments -4 155 Approved Corporate overheads3 402 R'm2014/15 Other costs Applied for14 868 Other costs Adjustments -9 205 Approved Other costs 5 663 MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 Table 57: Summary of Operating costs in 2014/15 25.3 Reasons for variance in operating costs 25.3.1 Employee benefits Actual staff costs have exceeded the MYPD3 decision due to firstly the higher salary settlement of 8.5% compared to decision assumption of 5.4%, and secondly the 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. 25.3.2 Maintenance Eskom spent R567m more for maintenance following the introduction of the Generation sustainability programme to arrest the escalating unplanned outages across the power station fleet. Relative to the assumptions made by NERSA for purposes of the MYPD3 revenue decision, Transmission also spent more on maintenance, however Distribution spent less on maintenance during 2014/15. 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. Operating costs in 2014/15 MYPD 3 Decision Actuals Regulatory Adjustm entsRCA Actuals RCA Balance Employee benefits 19 181 22 187 -89 22 098 2 917 Other Opex 1 17 536 22 083 -573 21 510 3 974 Other income- -6 645 4 615 -2 030 -2 030 Net impairment loss871 3 755 599 4 354 3 483 Cost of cover 1 829 3 602 - 3 602 1 773 Total Operating costs R'm illion39 417 44 982 4 552 49 534 10 117 MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 25.3.3 Arrear debt Arrear customer debt has increased across all segments over the past year, with approximately 38% of debt being outstanding for more than 60 days; the most significant increase was seen in arrear municipal debt. Arrear bad debt was 2.17% of external revenue for the year which is more than double (0,5% in decision) the assumption in the MYPD3 decision. Electricity debtors (before provision for impairment) increased to R22 657m while the provision for impairment increased to R7 430m. The increase in the provision for impairment is largely due to an increase in arrear municipal debt, coupled with a decision to provide for all overdue debt over 15 days – being the contractual due date – for certain defaulting municipalities, as well as those not honouring their payment plan agreements. Impairment of arrear debt 25.3.3.1 Previously, Eskom recognised revenue and thereafter impaired the debtor if the amount was later deemed not to be collectable. In the current year, we applied the IAS 18 principle of not recognising revenue if it is deemed not to be collectable at the date of sale. As the revenue and corresponding debtor is never accounted for, there is no need to impair the debtor. At year end, this has resulted in external revenue and debtors of R597m being derecognised, and impairment amounting to R566m being reversed. Despite this, we continue to actively pursue recovery of these amounts. The amounts mentioned earlier are net of the adjustment. Debt collection 25.3.3.2 Debt collection from municipalities and small power users, particularly in Soweto, remains a concern. At 31 March 2015, ten municipalities had total overdue debt greater than R100 m each; the top 20 defaulting municipalities contributed approximately 80% of the total arrear municipal debt. Total Soweto debt, including interest was R8 611 m at 31 March 2015. MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 Response strategies for debt collection 25.3.3.3 Debt collection from municipalities and small power users, particularly in Soweto, remains a concern. At 31 March 2015, ten municipalities had total overdue debt greater than R100 m each; the top 20 defaulting municipalities contributed approximately 80% of the total arrear municipal debt. Table 58: Arrear municipal and Soweto debt (excluding interest) at 31 March 2015 R m 2014/15 2013/14 2012/13 Municipal debt Total municipal debt (including current amounts) 9 849 6 928 5 142 Municipal arrear debt (>15 days) 4 953 2 593 1 202 Percentage arrear debt to total debt 50.3% 37.4% 23.4% Soweto debt Total Soweto debt (including current amounts) 4 182 3 622 3 159 Soweto arrear debt (> 15 days) 4 022 3 442 3 078 Average Soweto payment level, % 16% 20% 16% Historically, payments by municipalities were strongly correlated to them receiving their quarterly equitable share payment from National Treasury. Previously this funding was sufficient to settle outstanding electricity debt, although this is no longer the case, as municipalities face increased electricity prices and reduced funding. A number of other issues also contribute to non-payment by municipalities, such as inadequate skills and competencies to manage municipal functions, poor management of revenue management processes, misalignment of tariffs between Eskom and the municipalities, as well as cash flow challenges. Eskom has made cross-functional teams available to municipalities to share best practices in managing electricity portfolios and offered prepayment options to all municipalities to limit the growth of arrear debt. On 6 March 2015 National Treasury issued a cautionary procedure to all local municipalities advising them to pay their current bulk services accounts and honour their payments. Failure to comply would result in National Treasury withholding the payment of their quarterly equitable shares. MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 Furthermore, in April 2015 Eskom notified the top 20 defaulting municipalities across the country that Eskom would be interrupting their bulk electricity supply from 5 June 2015, should they not settle their accounts or make payment arrangements by then, as the organisation can no longer continue supplying electricty without receiving payment in return. Since the announcement, the majority of municipalities have made payment arrangements, therefore they will not have their bulk electricity supply interrupted. In the event that we cannot reach a satisfactory solution with a municipality, it will be permanently disconnected until its debt is paid in full. Residential revenue management 25.3.3.4 The residential revenue management strategy, which includes Soweto, drives energy protection and energy loss programmes, such as Switch OVA!, to enhance safety, improve quality of supply and reduce energy theft. It also aims to improve debt collection among small power users through the following initiatives:  Installation of split metering with protective enclosures to prevent tampering  Converting the meters of non-paying credit metering customers to prepaid meters, with new supply group codes to eliminate ghost vending  Focused credit management process, together with disconnections, to recover outstanding debt  Driving other recoveries in a structured approach through the Business Productivity Programme The programme was approved late in the 2013/14 financial year. Implementation commenced in Soweto in July 2014 and was expanded since 1 November 2014, with 18 000 households targeted to be converted to prepaid. As part of the process, we engage with customers to educate them on energy efficiency, safety, free basic electricity, inclining block tariffs, buying of prepaid power through legal vendors, as well as the need for household budgeting to provide for electricity purchases. MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 25.3.4 Cost of cover The cost of cover incurred was R3 577m compared to decision of R1 829m resulting in over expenditure of R1 748m. Eskom only budgets for the premium portions (cost of cover / interest differential portion) of forward exchange contracts (FECs). Due to the volatility of the rand, Eskom does not consider the spot to spot movements which should offset in any case, as it would more or less have an equal and opposite movement when comparing the exchange fluctuations on the FEC to the underlying loan or contract (build project) being hedged. Ignoring the different accounting treatment of FECs which are fair valued while loans are booked at amortised cost. The main reason for the increased premium cost is due to a significant portion of the loan book being hedged with FECs for a much longer period than anticipated. Eskom’s preferred hedging tool for foreign loans are Cross Currency Swaps. However Eskom can only enter into Cross Currency Swaps once Eskom is sure of the repayment profile of the loans and/or the size of the loan on book which makes it worthwhile to enter into a Cross Currency Swap. Due to the delay in the build programme drawdowns on the foreign facilities (DFI&ECA financing) were slower than expected and the repayment profiles unclear, hence loans are hedged for a longer period with FECs. In addition Eskom tries to apply cash flow hedge accounting when entering into Cross Currency Swaps to avoid volatility in the income statement, and to do this critical terms (maturity, principal, cash flows) of the Cross Currency Swap and the loan needs to match as closely as possible. One must be cognisant of the fact that even though the FEC premium cost is much higher we will have an offsetting saving in finance cost due to Cross Currency Swaps not being executed as explained above. 25.4 Savings through Business Productivity Programme Eskom implemented the BPP programme, which focuses on the reduction of the cost base, increased productivity, operational efficiencies and revisions of the business model and strategy, to assist in closing the MYPD 3 revenue shortfall. Cash saving opportunities to the MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 value of R61.9 billion over the five years to 31 March 2018 have been identified through the development of various value packages. At the end of the year, cash savings of R9 billion have been banked. Although the targeted savings for 2014/15 were not achieved, Eskom continues to aim to improve. Although critical, a reduction in costs, in terms of estimated savings to be realised under the BPP programme, may be difficult to achieve. 25.5 Other Income 25.5.1 Actual other income in 2014/15 In the course of Eskom operations in 2014/15, Eskom also generated total other income of R6 645 million which is disclosed under the Income Statement for March 2015 shown in Annexure 1. Table 59 : Other income for 2014/15 Eskom could not have reasonably estimated such additional revenue at the time of the MYPD3, Eskom does acknowledge that it did indeed realise additional revenue, some of which may be relevant for the purposes of the RCA. 25.5.2 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 Other Incom e A c t ua ls pe r AFS RCA Insuranc e proc eeds 5 111 Management fee inc ome 2 6 1 Operating lease inc ome 2 19 Dividend inc ome 19 Sale of sc rap 18 6 18 6 Other 8 4 9 3 4 2 T o ta l o th e r in c o me R'm 6 6 4 5 5 2 8 MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 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, “Para 103 As shown in Table 17 below, Eskom did not apply for the inclusion of other income from insurance proceeds (R384m), management fee income (R751m), operating lease income (R175m) and dividend income (R21m). This is allowed because it relates to operating expenditure that does not form part of the RCA.” Similarly for 2014/15, other income from insurance proceeds (R5111 million), management fee income (R261million), operating lease income (R219million) and dividend income (R19m) do not qualify as other income for RCA purposes. This is because it relates to operating expenditure that does not form part of the RCA. Eskom had a sundry other income of R849m, which relate essentially to the sale of ash and unclaimed monies. Included under sundry other income is an amount of R342 million relating to EDI restructuring levy which is being paid back through the RCA. Table 60 : Other income note in 2014/15 AFS MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 25.5.3 Other income included for RCA Sale of scrap 25.5.3.1 Revenue from sale of scrap and disposal of property, plant and equipment (PPE) are generated in relation to CECA. The RCA assessment provides for variances to be included in CECA to which these additional revenue streams relate and are therefore included in the RCA. Eskom generated other income of R186m from the sale of scrap assets. The sale of scrap (R186 million) is included as other income in the RCA submission in favour of the customer as it was generated through costs allowed in the MYPD. 25.6 EDI Holdings levy Monies were received from customers via the tariff specifically for EDI Holdings. However this was not paid over due to the closure of the EDI restructuring office. Hence R342m is a variance in favour of the customer through the RCA. 25.7 Operating cost variance for 2014/15 RCA Operating cost variance = Actual operating costs – Allowed operating costs Based on RCA equivalent actual operating costs of R49 534m and allowed other operating costs in the decision of R 39 417m, Eskom has incurred an additional R10 117m during the year. In terms of the MYPD Methodology Eskom cannot submit these additional expenses for RCA purposes and will have to absorb the variance. It is Eskom’s opinion that non-symmetrical treatment of variances such as in the case of operating costs is not in line with sound regulatory practice which is described lower down. MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 25.8 Why symmetrical treatment of operating costs is needed Current approach in MYPD Methodology: The current MYPD methodology allows for under expenditure to be clawed back in favour of the customer and over expenditure must be absorbed by Eskom. This approach is biased as it implies that any over expenditure is deemed inefficient and cannot be recovered through the RCA process, which violates the NERSA mandate in terms of the Electricity Regulation Act to allow utilities to recover full efficient costs. Proposed approach: Amendment to current methodology for symmetrical treatment of operating costs Motivation  Aligned with policy and legislation It is proposed that the symmetrical treatment of operating expenses would be in line with the intention of the Electricity Regulation Act in terms of which tariffs “must enable an efficient licensee to recover the full cost of its licensed activities, including a reasonable margin or return”. The Electricity Pricing Policy also stipulates that “the revenue requirement for a regulated licensee must be set at a level which covers the full cost of production, including a reasonable risk adjusted margin or return on appropriate asset values”.  Provides licensees with greater assurance The symmetrical treatment of operating cost variances would provide Eskom with greater assurance of adequate revenue to undertake the necessary operating and maintenance activities required for the optimal operation of the electricity system. The undertaking of such activities would still be subject to prudence review by the Energy Regulator. Only adjusting for prudently incurred under-expenditure would not enable Eskom to provide the best service to its customers. As one example, it might be prudent to defer a particular expenditure by one year – under a non-symmetrical treatment of variances it would result in MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 the under-expenditure being clawed-back to the benefit of the consumer but the over- expenditure in the subsequent year not being recovered by Eskom. This disincentive is illustrated by Eskom spending more on maintenance costs (prep missing) the over expenditure is not considered for prudency reviews, yet the current state of Generation plant requires extra efforts for maintenance.  Allows for optimal management decisions  A symmetrical treatment of operating costs would avoid perverse incentive with unintended consequences. A symmetrical mechanism would not imply an uncontrolled ability to spend – the normal prudence assessments undertaken by NERSA will require Eskom to substantiate any under and over-expenditure (when compared to assumptions made in the MYPD revenue decision) and thus act as sufficient incentive for efficiency.  Provide comfort to rating agencies The methodologies applied by the credit rating agencies in terms of which they rate regulated electricity utilities also make that point, with non-symmetrical revenue adjustment rules leading to higher regulatory risk assessment and thus lower credit ratings. Symmetrical mechanisms are one of the key characteristics that are considered during the assessments of the regulatory framework by credit rating agencies. For example, the guidance given by Standard & Poor's Ratings Services for a ‘strong’ rating is “Any incentives in the regulatory scheme are contained and symmetrical” (“Key Credit Factors for the Regulated Utilities Industry”, November 2013). A positive assessment of the regulatory framework is crucial for credit ratings, as the regulatory framework and environment are critical factors considered during a credit ratings assessment – for example in Moody’s Global Investors Service’s methodology it comprises 50% of the total credit risk assessment of a regulated electricity utility (“Rating Methodology - Regulated Electric and Gas Utilities”, November 2013). MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 26 Service Quality Incentives NERSA has approved the targets for service quality incentives for Distribution and Transmission below. NERSA is currently developing service quality incentives for Generation. Table 61 : Summary of SQI performance in 2014/15 26.1 Transmission service quality incentives (SQI) for 2014/15 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 The performance results for these measures as reported in the Eskom Integrated reports for the financial years 2014/15 as been finalized that summarizes the financial reward / penalty based on these results. The SQI reflects a reward of R2.5m for system minutes less than 1 minute as reflected in the table below. Table 62: Transmission SQI performance in 2014/15 MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 Transmission system performance reflects significant improvements with a declining trend in minutes lost from 4.73 in 2012 to 2.85 in 2015. Figure 7: Transmission system minutes (<1) Table 63: Transmission number of major incidents (>1SM) Number of Major Incidents (>1SM) MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 Figure 8 : Line faults /100km 26.2 Distribution Service Quality Incentive Scheme (SQI) for 2014/15 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)  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 SAID and SAIFI performance have shown on-going improvements during 2014/15 of MYPD3 and earned incentive rewards as indicated in the table below. The DSLI performance deteriorated during the same period and resulted in a penalty for year 2 of MYPD3. The net impact of the SQI performance is positive for Eskom. The outcome of the SQI performance is summarised in the table below. MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 Table 64: Distribution SQI performance in 2014/15 Distribution system performance reflects significant improvements with a declining trend in SAIDI interruption durations reducing from 45.8 minutes in 2012 to 36.2 minutes by 2015. MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 27 Reasonability tests 27.1 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 9 : EBITDA-To-Interest Cover Ratio The figure above reflects around 3.0 for 2014/15 27.2 Understanding the ratio NERSA’s ratio might be similar to Moody’s ratio of “Cash from Operations pre-working capital + Interest / Interest” – if so then the appropriate benchmark range for that type of ratio should be used. The minimum for investment grade on Moody’s ratio is 3. Even for a Ba rating (below investment grade) the ratio is 2 to 3. Although this measure only looks at the interest portion of total debt obligations i.e. does not consider the ability to meet the obligations regarding payment of debt principal, it indirectly measures that ability by using a higher benchmark range i.e. >3. NERSA’s target of 3.0 for 2014/15 (reducing to below 2.5 by 2017/18, per the figure) would thus not be appropriate for this ratio as it would be targeting sub-investment grade levels. Clearly this is not NERSA’s intention given that NERSA’s MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 comment in the MYPD2 RCA implementation plan was that it “is not expected to negatively affect the credit rating”. However, to achieve that, a value of >3 is probably required – 2.6 (and below) would certainly be very unfavourable to Eskom’s credit ratings. Alternatively, if the intention is to directly measure the ability to meet debt obligations, then the EBITDA should be compared to interest plus debt principal, not just interest – and in this case a lower benchmark range would be appropriate. Thus in deciding on the ratio to be measured it is critical to understand the intention as that will contribute to the elements required in the proper ratio calculations. In addition the ratio selected must be accompanied with the appropriate target benchmark range for measurement purposes. NERSA’s stated intention is that Eskom must be able to meet its debt obligations. This is confirmed by the Electricity Regulation Act s.16 (1) (a), as well as government’s Electricity Pricing Policy of 2008 that states: “Tariffs, therefore, need to be set at a level which would not only ensure that the utility generates sufficient revenues to cover the full costs (including a reasonable margin or return) but would also allow the utility to obtain reasonably priced funding on a forward looking basis. Rating agencies and lenders focus on a range of appraisal factors including profitability, e.g. Return on Assets (ROA) and Return on Equity (ROE), financial leverage (debt to equity) and debt service (e.g. interest coverage). It is important for the sake of financial sustainability that all these indicators move between acceptable norms and standards on a forward looking basis over the short, medium and long term. If the financial performance of the regulated entity deviates from these norms and standards investors will either be reluctant to extend credit or increase the cost of finance, ultimately resulting in higher tariffs or State support (e.g. guarantees, subsidies) or even bankruptcy in the case of private owners. Ultimately the decision to lend money to a regulated utility is made by the financial institution and not the regulator. The regulator, therefore, has a duty to measure the projected results from its regulatory methodologies (taking into account investment cycles and other cost trends) using the same criteria that reasonable commercial lenders would employ. The MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 regulator needs to consult with commercial lenders when assessing the financial viability of the industry on an ongoing basis.” 27.3 Interest cover ratio A further approach would be to use a conventional ‘interest cover ratio’, in which case the appropriate revenue item to use is EBIT (Earnings before interest and tax), not EBITDA. The reason for deducting Depreciation and Amortisation (thus, to use EBIT instead of EBITDA) is that these are the elements used for the loan repayment. Thus EBIT is used when one measures only interest cover. 27.4 Debt service cover ratio (Interest + Capital) Therefore an EBITDA interest cover ratio > 1 may not necessarily mean Eskom has enough available to pay interest unless the effect of the principal loan repayments are also taken into account, i.e. if EBITDA is used then it should be compared to total debt service obligations (interest plus debt principal). Thus EBITDA is used when one measures the ability to cover the full debt obligations comprising interest plus debt principal. 27.5 Computation of ratios for FY 2015 The financial information relating to debt obligations and the earnings for 2014/15 is presented in table below showing EBITDA of R24 735m, EBIT of R10 734m , net interest payments of R19 999m and debt service costs of R35 250m (interest of R19 999m plus debt repayments of R15 251m). MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 Table 65: Financial information for ratios in 2014/15 Various ratios have been computed as summarised below. Eskom’s 2014/15 AFS reports on such interest cover ratio and reflects it as 0.47 which is way below the minimum of 2.5 required to remain in the lower range of investment grade ratings. Alternatively, if the focus was on debt service cover then the actual result in 2014/15 is 0.7. Irrespective of whether interest cover ratio (using EBIT) or debt service cover ratio (using EBITDA) are used to measure the financial situation, the actual outcome on both are poor in 2014/15 compared to their acceptable ranges of over 2 (and that reference value has also been confirmed by NERSA). If the EBITDA; Interest cover ratio is used then the acceptable range for lower investment grade ratings would be >3. When using ratios that seem similar to this ratio the rating Financial Information for ratios workings2014/15 Calculation of EBITDA EBITDAA24 735 Profit before net finance (cost)/ income - EBITB10 734 Plus : Depreciation and amortisation expense14 001 Calculation of Total debt serviced Finance cost 24 015 Debt securities and borrowings C19 731 Less gov loan interest -2 228 Derivatives IRS and CCS 2 496 Provisions and Employee benefit obligations 3 909 Finance lease payables 107 Finance income -935 Investment in securities-513 Loans receivable-422 Net interest per AFS D23 080 Add / (deduct) items excluded for purposes of the framework : -3 081 Provisions and Employee benefit obligations -3 909 Finance lease payables -107 Finance income 935 Total interest used for calculation 19 999 Add : Debt repaid 15 251 Total debt serviced E35 250 MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 agencies set >3 as the minimum for lower investment grade, with <3 being rates as sub- investment grade. 27.6 EBIT Interest cover ratio The results reflects an EBITDA interest cover ratio 0.47 which entails that Eskom did not generate sufficient earnings to cover its interest commitments. In order for Eskom to cover its interest costs the cover ratio must be at least 1. Therefore at 0.47, Eskom’s earnings during 2014/15 do not even cover half the interest costs for the year. Table 66: EBIT Interest Cover 27.7 EBITDA: Total debt service ratio The results reflect an EBITDA: debt service ratio of 0.70 which means that Eskom did not earn enough to cover interest plus debt repayments, thereby being placed in a situation to refinance debt. The results reflect a shortfall of R10 515m which was effectively refinanced in 2014/15. Table 67: EBITDA Debt service cover during 2014/15 Calculation 2014/15 EBIT Interest coverB/D 0.47 B10 734 D23 080 EBIT Interest cover EBIT Interest Calculation reference 2014/15 B/E 0.70 B24 735 E35 250 Total debt serviced EBITDA : Total debt serviced (Revised calculation to account for debt repaid) EBITDA : Total debt serviced EBITDA MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 28 Conclusion Eskom’s approach to RCA 2014/15 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 utilized by NERSA in making their decision especially when it refers to the treatment of revenue and OCGTs. Eskom believes that this application will contribute towards Eskom and NERSA achieving closer alignment with respective to the RCA process and outcomes. Eskom’s revenue is determined by NERSA through a revenue application process and the RCA process which this document 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. Eskom’s 2014/15 RCA Submission is driven substantially by revenue under recoveries, higher expenditure for IPPs, an aligned OCGTs submission and other primary energy. Eskom has not claimed the over expenditure of R10 117m 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. In addition Eskom has applied the NERSA approach to OCGTs resulting in the organization absorbing R4 892m relating to OCGTs. Ultimately the 2014/15 RCA Submission of R19 185m will allow Eskom the opportunity to earn the allowed revenue and to recoup efficient costs which qualify for the RCA that exceeded the assumptions made in the MYPD3 decision for 2014/15. The need for a significant RCA adjustment is demonstrated by the actual debt cover ratios being well below acceptable norms. Eskom intends to submit the RCA 2015/16 application shortly after the release of the annual financial statements for March 2016. >>>>>>>>>>>>>>>>>>>>>>>>>>>>>>>> END >>>>>>>>>>>>>>>>>>>>>>>>>>>>>>>> MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 Annexures: Revenue: Annexure 1: Income Statement in AFS 2015 MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 Annexure 2: The Eskom energy wheel (Eskom Integrated report 2015, page22) **Note: All figures are in GWh unless otherwise stated. Eskom energy flow diagram All figures in GWh Generation of electricityAvailable for distributionTotal imports 2014/152013/142014/152013/142014/152013/14 Generation222 591227 508Generation (including IPPs)232 322234 800International purchases10 7319 425 OCGT3 7093 621 International purchases10 7319 425Wheeling 1 3 6233 353 Pumping(4 114)(3 862)Wheeling 1 3 6233 353Total 14 35412 778 IPP6 0223 671Subtotal246 676247 578 Total228 208230 938Pumping(4 114)(3 862) Total242 562243 716Total exports 2014/152013/14 International sales 2 12 00012 469 Wheeling 1 3 6233 353 Total 15 62315 822 Internal useExternal sales 2014/152013/14Demand2014/152013/14 Generated( 53)( 129)2014/152013/14Local sales204 274205 434 Internal use 791 465External sales216 274217 903International sales 2 12 00012 469 Total 738 336Technical and other losses20 94021 488Total216 274217 903 Internal use 791 465Technical and other losses Generated( 53)( 129)2014/152013/14 Wheeling3 6233 353Distribution14 920 (6.8%)15 824 (7.1%) Unaccounted/ re-phasing 3 988 636Transmission6 020 (2.5%)5 664 (2.3%) Total242 562243 716Total20 94021 488 3. Includes 352GWh allocated for the BPP sales adjustment. The energy wheel shows the volume of electricity that flowed from local and international power stations and independent power producers (IPP) to Eskom’s distribution and export points during the past two years, including the losses incurred in reaching those customers. 2. International sales includes exports by Distribution International to Lesotho. The actual amounts for 2015 and 2014 were 89GWh and 91GWh respectively. 1. Wheeling is the buying and selling of electricity between Eskom and foreign parties without the power entering into South Africa. South African Power Pool MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 Annexure 3: Sales volumes GWh – Statistical tables for 2014/15 Electricity sales per customer, GWh Category 2014/15 2013/14 Local 204 274 205 525 Redistributors 91 090 91 262 Residential 1 11 586 11 017 Commercial 9 644 9 605 Industrial 53 467 54 658 Mining 29 988 30 667 Agricultural 5 401 5 191 Rail 3 098 3 125 International 12 000 12 378 Utilities 2 797 3 401 End users across the border 9 203 8 977 216 274 217 903 International sales to countries in southern Africa, GWh 12 000 12 378 Botswana 1 237 1 608 Mozambique 8 360 8 314 Namibia 924 1 248 Zimbabwe 108 154 Lesotho 230 122 Swaziland 882 741 Zambia 16 143 Short-term energy market 2 243 48 1. Pre-payments and public lighting are included under residential. 2. The short-term energy market consists of all the utilities in the southern African countries that form part of the Southern African Power Pool. Energy is traded on a daily, weekly and monthly basis as there is no long-term bilateral contract. MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 Primary Energy Annexure 4: Primary Energy Note 34 extract AFS March 2015, page 91 MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 Reasonability test Annexure 5: Finance income note 40 and Finance cost note 41 (Extracts AFS March 2015, page 93) MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 Operating expenses Annexure 6: OPEX note 38 extract from AFS March 2015, page 92 MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 IDM Annexure 7: EEDSM costs in 2014/15 Annual report MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 OCGTs Annexure 8: Copy of NERSA letter approval of 450GWh MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 29 Abbreviations BPP Business Productivity Programme Capex Capital Expenditure c/kWh Cent per kilowatt hour COD Commercial Operation Date CoGTA Department of Cooperative Governance and Traditional Affiars COS Cost of Supply CPI Consumer Price Index CSP Concentrated Solar Power DoE Department of Energy DMP Demand Market Participation DPE Department of Public Enterprises DRC Depreciated Replacement Cost Dx Distribution EAF Energy availability factor (see glossary) EBITDA Earnings before interest, taxation, depreciation and amortisation EPP Electricity Pricing Policy ERTSA Eskom’s Retail Tariff Structural Adjustments EUF Energy utilisation factor (see glossary) GDP Gross Domestic Product GW Gigawatt = 1 000 megawatts GWh Gigawatt-hour = 1 000MWh Gx Generation HVAC Heating, Ventilation and Air Conditioning IBT Inclining Block Tariff IDC Interest during construction IDM Integrated demand management IPP Independent power producer (see glossary) MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 IRP 2010 Integrated Resource Plan 2010-2030 KIC Key industrial customers kt Kiloton = 1 000 tons Km Kilometer kV Kilovolt kWh Kilowatt-hour = 1 000 watt-hours (see glossary) L/USO Litres per unit sent out M&V Measurement and Verification Ml Megalitre = 1 m litres MKI Medupi, Kusile and Ingula Mt M tons MTPPP Medium Term Power Purchase Programme MVA Megavolt-ampere MW Megawatt = 1 m watts MWh Megawatt-hour = 1 000kWh MYPD Multi-Year Price Determination NERSA National Energy Regulator of South Africa O&M Operations and Maintenance OCGT Open-Cycle Gas Turbine (see glossary) OCLF Other Capability Loss Factor ODC Owner’s Development Cost Opex Operating Expenditure PE Primary Energy PPA Power Purchase Agreement PPI Producer Price Index PCLF Planned Capability Loss Factor PAJA Promotion of Administrative Justice Act, 2000 PFMA Public Finance Management Act, 1999 R&D Research and Development R/kVA Rand per kilovolt ampere MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 R/kWh Rand per kilowatt hour R/MW Rand per Megawatt R/MWh Rane per Megawatt hour R’m Rand million RAB Regulatory Asset Base RCA Regulatory Clearing Account RCN Replacement Cost New RTS Return-to-Service SADC Southern African Development Community SAIDI System average interruption duration index SAIFI System average interruption frequency index SBP Single Buyer Procurement SM System Minutes SQI Service Quality Incentive STPPP Short Term Power Purchase Programme SWH Solar Water Heaters TOU Time-of-Use Tx Transmission UAGS Unplanned automatic grid separations UCLF Unplanned Capability Loss Factor (see glossary) UOS Use-of-System WACC Weighted Average Cost of Capital WUC Work Under Construction MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 30 Glossary and Terms 49M The 49M initiative aims to inspire and rally all South Africans behind a common goal: to save electricity and create a better economic, social and environmental future for all Base-load plant Largely coal-fired and nuclear power stations, designed to operate continuously Cost of electricity (excluding depreciation) Electricity-related costs (primary energy costs, employee benefit costs plus impairment loss and other operating expenses) divided by total electricity sales in GWh multiplied by 1 000 Daily peak Maximum amount of energy demanded by consumers in one day Debt/equity including long-term provisions Net financial assets and liabilities plus non-current retirement benefit obligations and non-current provisions divided by total equity Debt service cover ratio Cash generated from operations divided by (net interest paid from financing activities plus debt securities and borrowings repaid) Decommission To remove a facility (e.g. reactor) from service and store it safely Demand side management Planning, implementing and monitoring activities to encourage consumers to use electricity more efficiently, including both the timing and level of demand Electricity EBITDA margin Electricity revenue (excluding electricity revenue not recognised due to uncollectability) as a percentage of EBITDA Electricity operating costs per kWh Electricity-related costs (primary energy costs, employee benefit costs, depreciation and amortisation plus impairment loss and other operating expenses) divided by total electricity sales in kWh multiplied by 100 Electricity revenue per kWh Electricity revenue (including electricity revenue not recognised tue to uncollectability) divided by total kWh sales multiplied by 100 MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 Embedded derivative Financial instrument that causes cash flows that would otherwise be required by modifying a contract according to a specified variable such as currency Energy availability factor (EAF) Measure of power station availability, taking account of energy losses not under the control of plant management and internal non-engineering constraints Energy efficiency Programmes to reduce energy used by specific end-use devices and systems, typically without affecting services provided Energy utilisation factor (EUF) Utilisation of the available plant Forced outage Shutdown of a generating unit, transmission line or other facility for emergency reasons or a condition in which generating equipment is unavailable for load due to unanticipated breakdown Free basic electricity Amount of electricity deemed sufficient to provide basic electricity services to a poor household (50kWh/month) Free funds from operations Cash generated from operations adjusted for working capital Gross debt Debt securities and borrowings plus finance lease liabilities plus the after-tax effect of provisions and employee benefit obligations Gross debt/EBITDA ratio Gross debt divided by earnings before interest, taxation, depreciation and amortisation Independent non-executive director Someone who is: Not a full-time salaried employee of the company or its subsidiary Not a shareholder representative Has not been employed by the company and is not a member of the immediate family of an individual who is, or has been in any of the past three financial years, employed by the company in any executive capacity Not a professional advisor to the company Not a significant supplier or customer of the company MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 Independent power producer (IPP) Any entity, other than Eskom, that owns or operates, in whole or in part, one or more independent power generation facilities Interest cover EBIT divided by (gross finance cost less gross finance income) Kilowatt-hour (kWh) Basic unit of electric energy equal to one kilowatt of power supplied to or taken from an electric circuit steadily for one hour Load Amount of electric power delivered or required on a system at any specific point Load curtailment Typically larger industrial customers reduce their demand by a specified percentage for the duration of a power system emergency. Due to the nature of their business, these customers require two hours’ notification before they can reduce demand Load management Activities to influence the level and shape of demand for electricity so that demand conforms to the present supply situation, long-term objectives and constraints Load shedding Scheduled and controlled power cuts that rotate available capacity between all customers when demand is greater than supply in order to avoid blackouts. Distribution or municipal control rooms open breakers and interrupt load according to predefined schedules Lost-time injury (LTI) A work injury, including any occupational disease/illness or fatality, which arises out of and in the course of employment and which renders the injured employee or contractor unable to perform his/her regular/normal work on one or more full calendar days or shifts other than the day or shift on which the injury occurred Lost-time injury rate (LTIR) Proportional representation of the occurrence of lost-time injuries over 12 months per 200 000 working hours Maximum demand Highest demand of load within a specified period Off-peak Period of relatively low system demand MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 Open-cycle gas turbine (OCGT) Liquid fuel turbine power station that forms part of peak-load plant and runs on kerosene or diesel. Designed to operate in periods of peak demand Outage Period in which a generating unit, transmission line, or other facility is out of service Peak demand Maximum power used in a given period, traditionally between 06:00–10:00, as well as 18:00–22:00 in summer or 17:00- 21:00 in winter Peaking capacity Generating equipment normally operated only during hours of highest daily, weekly or seasonal loads Peak-load plant Gas turbines, hydroelectric or a pumped storage scheme used during periods of peak demand Primary energy Energy in natural resources, e.g. coal, liquid fuels, sunlight, wind, uranium and water Pumped storage scheme A lower and an upper reservoir with a power station/pumping plant between the two. During off-peak periods the reversible pumps/turbines use electricity to pump water from the lower to the upper reservoir. During periods of peak demand, water runs back into the lower reservoir through the turbines, generating electricity Reserve margin Difference between net system capability and the system’s maximum load requirements (peak load or peak demand) Return on assets EBIT divided by the regulated asset base, which is the sum of property, plant and equipment, trade and other receivables, inventory and future fuel, less trade and other payables and deferred income System minutes Global benchmark for measuring the severity of interruptions to customers. One system minute is equivalent to the loss of the entire system for one minute at annual peak. A major incident is an interruption with a severity ≥ 1 system minute Technical losses Naturally occurring losses that depend on the power systems used Unit capability factor (UCF) Measure of availability of a generating unit, indicating how well it is operated and maintained MYPD3 2014/15 RCA Submission to NERSA 10 May 2016 Unplanned capability loss factor (UCLF) Energy losses due to outages are considered unplanned when a power station unit has to be taken out of service and it is not scheduled at least four weeks in advance Used nuclear fuel Nuclear fuel irradiated in and permanently removed from a nuclear reactor. Used nuclear fuel is stored on-site in used fuel pools or storage casks Watt The watt is the International System of Units' (SI) standard unit of power. It specifies the rate at which electrical energy is dissipated (energy per unit of time) Working capital ratio (Inventory plus the current portion of payments made in advance, trade and other receivables and taxation assets) divided by (the current portion of trade and other payables, payments received in advance, provisions, employee benefit obligations and taxation liabilities) --- Document Separator --- MYPD 3 (Year 2015/16) Regulatory Clearing Account Submission to NERSA 15 July 2016 MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 TABLE OF CONTENTS 1 PREFACE .................................................................................................................................. 12 1.1 The basis of submissions ..................................................................................................................... 12 1.2 The structure of 2015/16 RCA Submission ........................................................................................... 13 2 OBJECTIVE .............................................................................................................................. 15 3 OVERVIEW OF THE 2015/16 RCA SUBMISSION ...................................................... 16 3.1 Revenue .............................................................................................................................................. 17 3.2 Primary energy .................................................................................................................................... 17 3.3 Environmental levy .............................................................................................................................. 17 3.4 Phased nuclear decommissioning provision per MYPD3 RCA 2013/14 decision................................... 17 3.5 International electricity purchases ...................................................................................................... 18 3.6 Capital expenditure variance ............................................................................................................... 18 3.7 Operating costs ................................................................................................................................... 18 3.8 Integrated demand management ........................................................................................................ 18 3.9 Other income ...................................................................................................................................... 19 3.10 Inflation adjustments ....................................................................................................................... 19 3.11 Service Quality Incentives (SQI) ........................................................................................................ 19 3.12 Reasonableness test......................................................................................................................... 19 3.13 Trend analysis of MYPD3 RCAs ......................................................................................................... 19 3.14 Conclusion ....................................................................................................................................... 20 MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 4 FACTORS IMPACTING ON 2015/16 RCA SUBMISSION ........................................ 21 4.1 Timeline for application and decision .................................................................................................. 21 4.2 Changes in fundamental assumptions since MYPD3 application ......................................................... 22 5 REVENUE VARIANCE .......................................................................................................... 24 5.1 MYPD methodology ............................................................................................................................ 24 5.2 Calculation of the revenue variance .................................................................................................... 24 5.3 Revenue computed on an equivalent basis ......................................................................................... 25 5.4 Allowed Revenue ................................................................................................................................ 29 5.5 Sales volumes contribute to recovery of fixed costs ............................................................................ 30 5.6 Allowed vs Actuals volumes ................................................................................................................ 31 5.7 Sales volume variance explanation ...................................................................................................... 32 5.7.1 The process in deriving the 5 year forecast ....................................................................................... 32 5.7.2 Critical changes in assumptions relevant during 2011 in deriving forecasts ................................... 33 5.7.3 Sales volume variance explanation for FY2016 ................................................................................. 34 5.8 Conclusion on the revenue variance .................................................................................................... 40 6 IMPACT OF DEMAND RESPONSES ON SALES VOLUMES ................................ 41 7 COLLECTABILITY OF REVENUE DOES NOT IMPACT RCA ................................ 41 8 RCA IMPLEMENTATION RISKS ....................................................................................... 41 9 PRUDENCY AND EFFICIENCY ......................................................................................... 42 10 FACTORS WHICH INFLUENCE ESKOM PRODUCTION PLANS ..................... 44 MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 11 PRIMARY ENERGY ............................................................................................................ 45 11.1 Primary energy variances and RCA impact for 2015/16 .................................................................... 45 11.2 Independent Power Producers ......................................................................................................... 47 11.2.1 Medium-term Power Purchase Programme (MTPPP) ................................................................... 47 11.2.2 Municipal Base-load Purchases ...................................................................................................... 47 11.2.3 Short-term Power Purchases Programme (STPPP) ........................................................................ 47 11.2.4 Wholesale Electricity Pricing System (WEPs) programme ............................................................ 47 11.2.5 Long-term IPP programmes ........................................................................................................... 48 11.2.6 IPP open cycle gas turbine (“Peaker”) programme ....................................................................... 48 11.2.7 Renewable Energy Independent Power Producer (RE-IPP) procurement programme ................ 48 11.3 Legal basis for IPPs per the MYPD Methodology .............................................................................. 50 11.4 IPP Approvals ................................................................................................................................... 51 11.5 Regulatory rules for power purchase cost recovery ......................................................................... 51 11.6 Allowed vs Actual IPP costs for 2015/16 .......................................................................................... 51 11.6.1 Reasons for IPP variances in 2015/16 ............................................................................................ 52 11.7 IPP variance for 2015/16 RCA ........................................................................................................... 56 12 INTERNATIONAL PURCHASES ......................................................................................... 57 12.1 Regional IPPs - Aggreko .................................................................................................................... 58 13 COAL BURN COSTS ............................................................................................................... 60 13.1 Extract of MYPD Methodology on Coal adjustments ........................................................................ 60 13.2 NERSA’s decision on coal benchmark and alpha ............................................................................... 61 13.3 Coal cost – RCA 2016 calculation ...................................................................................................... 62 13.3.1 Step 1 – Calculate the performance base regulation cost allowance ............................................. 62 13.3.2 Step 2 – Calculate the pass through coal burn costs ...................................................................... 63 MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 13.3.3 Step 3 – Split the pass through coal burn cost into volume variance and price variance summarised below. ........................................................................................................................................... 63 13.4 Coal burn cost variance explanations ............................................................................................... 65 13.4.1 Different mix and efficiency of power stations generating electricity ......................................... 66 13.5 Coal purchases ................................................................................................................................. 66 13.5.1 Long term fixed price contracts ..................................................................................................... 66 13.5.2 Cost plus contracts ......................................................................................................................... 66 13.6 Future Fuel ....................................................................................................................................... 69 13.7 Coal Qualities ................................................................................................................................... 69 13.8 Mode of Transport ........................................................................................................................... 69 13.9 Medupi Take or Pay payment .......................................................................................................... 70 13.10 Kusile Risk Sharing Agreement ......................................................................................................... 70 13.11 Securing our coal requirements ....................................................................................................... 71 14 OTHER PRIMARY ENERGY ................................................................................................ 72 14.1 Allowed other primary energy in 2015/16 ....................................................................................... 72 14.1.1 Allowed other primary energy costs .............................................................................................. 72 14.2 Allowed vs Actual other primary energy .......................................................................................... 72 14.2.1 Reasons for start-up gas and oil costs variance ............................................................................. 73 14.2.2 Reasons for coal handling costs variance ...................................................................................... 74 14.2.3 Reasons for water costs variance .................................................................................................. 75 14.2.4 Reasons for fuel procurement costs variance ............................................................................... 75 14.2.5 Water treatment costs variance .................................................................................................... 76 14.2.6 Nuclear costs variance .................................................................................................................... 76 15 ENVIRONMENTAL LEVY ..................................................................................................... 77 MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 16 DEMAND MARKET PARTICIPATION.............................................................................. 78 16.1.1 Allowed DMP .................................................................................................................................. 78 16.1.2 Actual DMP ..................................................................................................................................... 78 17 OPEN CYCLE GAS TURBINES (OCGTS) ........................................................................... 80 17.1 Allowed OCGT spend ........................................................................................................................ 80 17.2 Actual OCGTs costs ........................................................................................................................... 81 17.3 Computation of OCGTs claim for RCA purposes in 2015/16 .............................................................. 81 17.3.1 Price impact up to allowed diesel litre usage of 152ML (million litres) ........................................ 82 17.3.2 Excess volumes above GWh recovered at average coal costs ...................................................... 83 17.3.3 Other related OCGT costs ............................................................................................................... 83 17.4 OCGT usage in 2015/16 .................................................................................................................... 84 17.5 Summary of OCGT RCA claim ........................................................................................................... 85 17.5.1 Managing supply-and –demand constraints ................................................................................. 85 17.5.2 Actual Plant performance in 2015/16 ............................................................................................ 86 18 CAPITAL EXPENDITURE CLEARING ACCOUNT (CECA) ................................. 91 18.1 Regulated asset base adjustment for CECA ...................................................................................... 91 18.1.1 Step 1: Computing the qualifying RAB capital expenditure variance ........................................... 91 18.1.2 Step 2: Computing the CECA .......................................................................................................... 93 18.2 MYPD3 decision ............................................................................................................................... 94 18.3 Reasons for new build higher expenditures ..................................................................................... 94 18.4 Actual Capital Expenditure ............................................................................................................... 96 18.5 Detailed Capital expenditure for 2015/16 ........................................................................................ 97 18.6 Delivering on the capital expansion ................................................................................................. 97 18.7 New build projects ........................................................................................................................... 98 MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 18.8 Conclusion on capital expenditure ................................................................................................. 101 19 INFLATION ADJUSTMENT ........................................................................................... 102 20 ENERGY EFFICIENCY AND DEMAND SIDE MANAGEMENT (EEDSM)..... 104 20.1 The Residential mass roll-out programme ...................................................................................... 104 20.2 Energy-efficiency measures ............................................................................................................ 104 20.3 Extracts from the MYPD Methodology ........................................................................................... 106 20.3.1 Allowed EEDSM for 2015/16 ........................................................................................................ 106 20.3.2 Actual EEDSM ............................................................................................................................... 107 20.3.3 Computation of EEDSM for the RCA ............................................................................................ 108 21 OPERATING COSTS ....................................................................................................... 110 21.1 Allowed operating costs in 2015/16 ............................................................................................... 110 Note1: Allowed employee benefits ............................................................................................................... 111 21.2 Allowed vs Actual operating costs .................................................................................................. 113 21.3 Variances in operating costs ........................................................................................................... 113 21.3.1 Employee benefits ........................................................................................................................ 113 21.3.2 Maintenance ................................................................................................................................. 114 21.3.3 Arrear debt ................................................................................................................................... 114 21.3.4 Energy losses and theft ................................................................................................................ 117 21.4 Savings through Business Productivity Programme ........................................................................ 118 21.5 Other Income ................................................................................................................................. 118 21.5.1 Actual other income in 2015/16 .................................................................................................. 118 21.5.2 Principles for treatment of other income in the RCA .................................................................. 119 21.5.3 Other income included for RCA.................................................................................................... 119 21.6 Operating cost variance for 2015/16 RCA ....................................................................................... 120 MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 21.7 Why symmetrical treatment of operating costs is needed ............................................................. 120 22 SERVICE QUALITY INCENTIVES .............................................................................. 123 22.1 Transmission service quality incentives (SQI) for 2015/16 ............................................................. 124 22.2 Distribution Service Quality Incentive Scheme (SQI) for 2015/16 ................................................... 126 23 REASONABILITY TESTS .............................................................................................. 128 23.1 EBITDA-To-Interest Cover Ratio (EBITDA / Interest Payments) ....................................................... 128 23.2 Understanding the ratio ................................................................................................................. 128 23.3 Interest cover ratio ........................................................................................................................ 130 23.4 Debt service cover ratio (Interest + Capital) ................................................................................... 130 23.5 Computation of ratios for FY 2015 ................................................................................................. 130 23.6 EBIT Interest cover ratio ................................................................................................................. 132 23.7 EBITDA: Total debt service ratio ..................................................................................................... 132 24 CONCLUSION ................................................................................................................... 133 ANNEXURES: .............................................................................................................................. 134 Annexure 1: Income Statement in AFS 2016, page 15 .................................................................................. 134 Annexure 2: The Eskom energy wheel (Eskom Fact sheet 2016) .................................................................. 136 Annexure 3: Sales volumes GWh – Statistical tables for 2015/16................................................................. 137 Annexure 4: Primary Energy Note 34 extract AFS March 2016, page 85 ....................................................... 139 Annexure 5: Finance income note 40 and Finance cost note 41 (Extracts AFS March 2016, page 86-87) ...... 140 Annexure 6: OPEX note 38 extract from AFS March 2016, page 86 .............................................................. 141 MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 Annexure 7: Verified EEDSM savings ........................................................................................................... 142 25 ABBREVIATIONS ............................................................................................................... 143 26 GLOSSARY AND TERMS ................................................................................................... 146 Figure 1: Time lag between application and actuals ........................................................................................ 21 Figure 2 : Performance of Re-distributors ........................................................................................................ 36 Figure 3 : Performance of Ferro and Steel ........................................................................................................ 38 Figure 4: Production FY 2016............................................................................................................................. 44 Figure 5: IPPs contracted and connected (by province) ................................................................................. 49 Figure 6: IPP operational capacities by type and location at 31 March 2016 ................................................ 50 Figure 7: IPP capacity available and the actual energy procured ................................................................... 55 Figure 8 : Monthly OCGTs costs and production in 2015/16........................................................................... 84 Figure 9 : Generation technical performance ................................................................................................... 88 Figure 10 : Relationship between high EUF to EAF and EUF.......................................................................... 89 Figure 11 : Transmission projects at March 2016 .......................................................................................... 101 Figure 12: Transmission system minutes (<1) ............................................................................................... 125 Figure 13 : Line faults /100km .......................................................................................................................... 126 Figure 14 : EBITDA-To-Interest Cover Ratio ................................................................................................... 128 Table 1: Summary of 2015/16 RCA Submission ............................................................................................... 16 Table 2: RCA Trend Analysis over the past 3 years ......................................................................................... 20 Table 3: Key assumptions which have changed .............................................................................................. 22 Table 4 : Calculation of MYPD3 revenue variance for 2015/16 ........................................................................ 25 Table 5 : Reconciliation of AFS revenue to RCA revenue ............................................................................... 25 Table 6: Revenue note from AFS for March 2016 ............................................................................................ 26 Table 7 : Load shedding and curtailment impact in 2015/16 ........................................................................... 28 Table 8: Allowed revenue ................................................................................................................................... 29 Table 9 : Sales volume variance ........................................................................................................................ 31 Table 10: MYPD3 Sales volume ......................................................................................................................... 32 Table 11 : GDP forecasts used for MYPD3 in 2011 .......................................................................................... 33 Table 12: Commodity Prices assumed .............................................................................................................. 33 Table 13 : Sales volume variance ...................................................................................................................... 34 Table 14 : Commodity prices ............................................................................................................................. 37 Table 15 : Total primary energy comparison and RCA impact for 2015/16 .................................................... 46 Table 16: Primary energy actual costs per note 34 in the AFS of 2016, pg 35............................................... 46 Table 17: IPPs costs and volumes .................................................................................................................... 52 Table 18: IPPs contracted and connected ........................................................................................................ 56 MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 Table 19: International purchases ..................................................................................................................... 57 Table 20 : Cross border sales and purchases .................................................................................................. 57 Table 21: NERSA’s decision on coal benchmark and alpha ........................................................................... 61 Table 22: Working Coal Mechanism .................................................................................................................. 62 Table 23: The coal burn breakdown for the RCA ............................................................................................. 63 Table 24: MYPD 3 Assumptions vs. Actual 2015/16 ......................................................................................... 65 Table 25: Future Fuel (Coal & Water) ................................................................................................................ 69 Table 26: Securing our coal requirements ........................................................................................................ 71 Table 27: Other Primary Energy......................................................................................................................... 73 Table 28: Approved Demand Response (DR) Expenditure for MYPD3 .......................................................... 78 Table 29: DMP comparison for RCA .................................................................................................................. 78 Table 30 : Summary of allowed OCGTs components ...................................................................................... 81 Table 31: Summary of OCGTs actual results for 2015/16 ................................................................................ 81 Table 32: OCGTs RCA summary ........................................................................................................................ 82 Table 33 : OCGTs price impact for 152ML ........................................................................................................ 83 Table 34: OCGTs RCA claim related to excess volumes above allowed GWh .............................................. 83 Table 35 : OCGTs other costs ............................................................................................................................ 84 Table 36: Calculation average capital expenditure .......................................................................................... 92 Table 37: CECA Calculation: Return due to/ (by) Eskom ................................................................................ 93 Table 38 : Regulatory asset base for 2015/16 ................................................................................................... 94 Table 39: Returns and percentage allowed in 2015/16 ................................................................................... 94 Table 40: Capital expenditure in 2015/16 ......................................................................................................... 94 Table 41: Reconciliation of capex from Integrated report to CECA disclosures ........................................... 97 Table 42: Capital expenditure (excluding capitalised borrowing costs) per division ................................... 97 Table 43: Inflation Data ..................................................................................................................................... 102 Table 44 : Inflation adjustment......................................................................................................................... 103 Table 45: Demand management costs ............................................................................................................ 105 Table 46: Actual savings (not verified) and internal energy efficiency savings .......................................... 105 Table 47: Allowed EEDSM ................................................................................................................................ 106 Table 48: Reconciliation between demand savings MWs used in RCA Calculation ................................... 107 Table 49: EEDSM comparison for RCA in 2015/16 ......................................................................................... 108 Table 50: Actual EEDSM ................................................................................................................................... 108 Table 51: Total Operating Cost Allowed ......................................................................................................... 110 Table 52: Employee benefits are reconciled as follows ................................................................................ 111 Table 53: The allowed employee costs for Generation, Transmission and Distribution ........................... 111 Table 54: Allowed Corporate Costs in 2015/16 ............................................................................................... 111 Table 55: The depreciation per annum is reflected in the table below. ........................................................ 112 Table 56: Allowed Maintenance Costs ............................................................................................................ 112 Table 57: Other costs ........................................................................................................................................ 112 Table 58: Allowed Arrear Debts ....................................................................................................................... 112 MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 Table 59: Allowed Cost of Cover ..................................................................................................................... 113 Table 60: Summary of Operating costs in 2015/16 ......................................................................................... 113 Table 61: Trend in gross employee benefits................................................................................................... 114 Table 62: Municipal and Soweto arrear debt at 31 March 2016 ..................................................................... 115 Table 63 : Other income for 2015/16 ................................................................................................................ 118 Table 64 : Trends in networks performance ................................................................................................... 123 Table 65 : Summary of SQI performance in 2015/16 ...................................................................................... 124 Table 66: Transmission SQI performance in 2015/16 .................................................................................... 124 Table 67: Transmission number of major incidents (>1SM) .......................................................................... 125 Table 68: Distribution SQI performance in 2015/16 ........................................................................................ 127 Table 69: Financial information for ratios in 2015/16 ..................................................................................... 131 Table 70: EBIT Interest Cover .......................................................................................................................... 132 Table 71: EBITDA Debt service cover during 2015/16 ................................................................................... 132 MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 1 Preface This document summarises information submitted by Eskom Holdings (SOC) Ltd to the National Energy Regulator of South Africa (hereafter referred to as NERSA, or the Energy Regulator) pertaining to the Eskom’s Regulatory Clearing Account (RCA) balance for the year 2015/16 and in accordance with the Multi-Year Price Determination Methodology published during December 2012 (hereafter referred to as the ‘MYPD Methodology’) 1 . This document contains the following: 1. Information provided in regard to Eskom’s 2015/16 RCA balance (hereafter referred to as the ‘2015/16 RCA Submission’ or year 3 of MYPD3) is lodged in accordance with section 14.2.1 of the MYPD Methodology. 2. Information is supported by Eskom’s 2015/16 audited annual financial statements 3. Information is supported by NERSA’s RCA 2013/14 reasons for decision published on 29 March 2016 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. 1 See in particular sections 14.0, 8.0 and 9.0 of the Multi-Year Price Determination Methodology 1 st Edition, published December 2012 MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 14.1.2 Allowing the pass-through of prudently incurred primary energy costs as per Section 8 of the Methodology. 14.1.3 Adjusting capital expenditure forecasts for cost and timing variances as per Section 6 of the Methodology. 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 2015/16 RCA Submission The structure of the summary of 2015/16 RCA Submission provided in this document is guided by the MYPD Methodology. With this in mind, an overview of the 2015/16 RCA submission is first provided summarizing 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. MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 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 2015/16 RCA Submission concludes with reasonableness tests such as EBITDA to interest payments and debt service cover ratio being assessed. 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 15) V. Primary Energy - Coal Costs (Section 17) VI. Primary Energy - Gas Turbine Generation Cost (Section 21) VII. Primary Energy – Other costs (Section 18) VIII. Capital Expenditure and Regulatory Asset Base (Section 22) IX. Operating Costs (Section 25) X. Determined RCA Balance to Financial Year End MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 2 Objective The objective of this 2015/16 RCA Submission is to provide the context for the Regulatory Clearing Account (RCA) process in terms of NERSA’s MYPD Methodology requirements. The 2015/16 RCA Submission for the third 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 decision made by NERSA on 1 March 2016 and the reasons for decision published on 29 March 2016. 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 costs that are subject to re-measurement as outlined in the MYPD methodology. MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 3 Overview of the 2015/16 RCA Submission Eskom’s 2015/16 RCA Submission is driven substantially by revenue under-recovery and higher primary energy costs to meet demand, whilst operating in a constrained electricity system. The determined RCA balance of R23 633 million is motivated with evidence for prudent scrutiny by NERSA. Table 1: Summary of 2015/16 RCA Submission Note 1 – Operating costs over expenditure not allowed to be claimed as part of the RCA in terms of current MYPD Methodology Regulatory Clearing Account (RCA) for 2015/16 MYPD3 Decision Actuals Variance RCA adjustments RCA 2015/16 T otal E l ectri ci ty reven u e R m i l l i on 179 587 163 160 16 427 -849 15 578 Primary Energy , R million Coal 39 838 41 775 1 937 1 321 3 258 OCGT s 1 508 8 690 7 182 -6 493 689 Other primary energy 6 040 7 129 1 089 -361 728 Local IPPs and co-generation 14 826 15 106 280 340 620 International purchases 93 3 660 3 567 3 567 Environmental levy 9 300 8 120 -1 180 -1 180 Nuclear decommissioning of R830m f rom RCA 2013/14 decision phased in over 10 years - - 83 83 Nuclear decommissioning R361m f rom RCA 2015/16 decision phased in over 8 years 45 45 Demand Market Participation (DMP) - 248 248 - 248 T otal p ri m ary en erg y , R m i l l i on 71 605 84 728 13 123 -5 065 8 058 C ap i tal E xp en d i tu re C l eari n g A ccou n t ( C E C A ) , R m i l l i on 42 065 56 978 14 913 332 332 I n teg rated D em an d M an ag em en t ( I D M ) , R m i l l i on 819 413 -406 38 -368 O p erati n g 1 costs , R m i l l i on 42 292 55 198 12 905 1 061 -134 S ervi ce Q u al i ty I n cen ti ve ( S Q I ) , R m i l l i on - - - 318 318 I n f l ati on ad j u stm en ts , R m i l l i on - - -152 -152 T otal R C A b al an ce , R m i l l i on 23 633 MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 3.1 Revenue The revenue variance of R15 578 million which is calculated on Eskom’s electricity revenue to all customers is due to lower electricity sales volumes. In addition, Eskom has specifically excluded the loss of revenue attributable to the load shedding and load curtailment impacts of R849 million thereby reducing the revenue variance to R15 578 million. 3.2 Primary energy Due to the constrained electricity system, unplanned outages and delays in new build projects, Eskom was required to operate a more expensive mix of plant compared to the assumptions in the MYPD3 decision in order to avoid/minimize load shedding. This included a combination of higher levels of supply from local and regional IPPs, more OCGTs usage and a change in the mix of the coal fleet which was required in trying to meet demand and more importantly to protect the stability of the overall electricity system. Eskom has included R8 058 million for primary energy costs in the RCA submission. 3.3 Environmental levy The lower production volumes and the change in production mix resulted in Eskom incurring environmental levy costs of R1 180 million lower than the assumption made in the MYPD3 determination. The RCA methodology 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. 3.4 Phased nuclear decommissioning provision per MYPD3 RCA 2013/14 decision In its 2013/14 RCA decision, NERSA has allowed Eskom to claim the nuclear decommissioning provision of R830 million, over a period of 10 years, in equal installments of R83 million via future RCA applications. The first tranche of R83 million was granted in the RCA 2013/14 decision. Thus this application represents the third installment. A further increase in the nuclear provision of R361million was raised during the 2015/16 year. Eskom has phased this over the remaining 8 years and thus R45 million is included in the RCA. MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 3.5 International electricity purchases In the MYPD3 RCA 2013/14 decision, NERSA adopted a total approach for revenue and corresponding costs to include regional components. Eskom has taken this on board and has accordingly applied this to the RCA treatment for international purchases relating to the 2015/16 period. The international purchases cost variance contributes R3 567 million to the total primary energy category of the RCA balance. 3.6 Capital expenditure variance Eskom Company capital expenditure of R56 978 million exceeded the NERSA decision of R42 065million by R14 913 million in 2015/16. 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 capex is excluded when computing the balance for RCA purposes. For RCA purpose the capital expenditure clearing account (CECA) adjustment is R332 million. 3.7 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 2015/16 the operating costs expenditure of R56 258 million (R55198m + R1061m) exceeded the decision of R42 292 million by R13 966 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. 3.8 Integrated demand management Eskom’s energy efficiency and demand side management (EEDSM) programs produced less capacity (in MW) savings during the year resulting in a pay back to consumers of R368 million for RCA purposes. MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 3.9 Other income Other income is included under the operating costs section and comprises the sale of scrap assets for R134 million. 3.10 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 R152 million in favour of customers. 3.11 Service Quality Incentives (SQI) Eskom has achieved the service quality incentive targets set by NERSA for Distribution and Transmission during 2015/16. This resulted in Distribution achieving an SQI of R233 million and Transmission of R85 million, equating to a total of R318 million. 3.12 Reasonableness test Eskom has computed reasonableness tests, namely the EBITDA: Interest cover ratio and Debt service cover ratio. These tests reflect that the RCA adjustment decision will contribute towards the recovery of full efficient costs and allow Eskom to earn the allowed return. Further, the ratio analysis reflects that even with the RCA adjustment, each measure is well below the acceptable range. 3.13 Trend analysis of MYPD3 RCAs Eskom has presented the RCA 2013/14 decision and provided the summary of the RCA submission for 2014/15 and RCA 2015/16 below. MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 Table 2: RCA Trend Analysis over the past 3 years 3.14 Conclusion The RCA balance submission of R23 633 million excludes operating costs in excess of the decision of R13 966 million (R12905m + R1061m). Furthermore, in aligning to the NERSA decision precedent set in the RCA 2013/14 decision, Eskom absorbed a large OCGT cost variance of R6 493 million. RCAs trend analysis Decision RCA 2013/14 Application RCA 2014/15 Application RCA 2015/16 Revenue 6 175 8 787 15 578 Local IPPs 580 4 346 620 International purchases 2 700 3 299 3 567 Coal 2 000 574 3 258 Open Cycle Gas T urbines (OCGT s) 1 252 1 944 689 Other primary energy 72 1 355 728 Environmental levy -312 -683 -1 180 Nuclear decommissioning of R830m f rom RCA 2013/14 decision phased in over 10 years 83 83 83 Nuclear decommissioning R361m f rom RCA 2015/16 decision phased in over 8 years - - 45 Integrated Demand Management (IDM) -432 -149 -368 Demand Market Participation (DMP) -905 -379 248 Capital Expenditure Clearing Account (CECA) 9 91 332 Service Quality Incentives (SQI) 339 236 318 Inf lation adjustment - Opex 33 209 -152 Other income -353 -528 -134 R C A b al an ce R ' m i l l i on s 11 241 19 185 23 633 MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 4 Factors impacting on 2015/16 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-13Apr-14Apr-15Apr-16Apr-17Apr-18 5 Year MYPD3 Window MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 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 235 TWh by March 2016. Sales growth averaged a reduction of 0.9% from a starting value of 216.5TWh in March 2013 to 214.5 TWh in March 2016 Sales forecast did not materialise due to major changes in the assumptions plus the adverse global economic situation not recovering as anticipated Generation plant performance (Energy availability factor – EAF) assumed at an average 82% for 2015/16. Actual average EAF was 71% with improvement in the last quarter of FY2016 Actual plant performance is lower than that anticipated at the time of preparing the application in early 2012. New build commission dates for 1 st units Medupi – June 2013 Kusile - 2015/16 Ingula – 2013/14 Sere – 2013/14 New build commission revised dates for 1 st units: Medupi – Commissioned August 2015 Kusile – July 2018 Ingula – First unit commissioned during 2016 and three others synchronized Sere – Commissioned on 31 March 2015 Due to labour disturbances, contractor failures, and inadequate project management capability, the new build projects have been delayed Coal country compact < 10%price increases Efficiency savings implemented through business productivity programme. Price increases will most l likely exceed the less than the10% assumption. MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 OCGTs – load factors assumed at 3% based on certain other assumptions materialising OCGTs – actual load factors >3% due to the other assumptions made at time of application not materialising OCGTs were utilized as last resort to avoid load shedding IPPs – local and international Substantial increase in IPP programs related to DOE programs and securing regional IPPs to address capacity constraints At the time of the MYPD 3 application, the extent of the IPP programs were not envisaged and additional IPP purchases were required to prevent loadshedding as a cheaper options than OCGTs Capex – R337bn over the five year period Capex – given the lower revenue decision, Eskom reprioritized capex to a projected portfolio of R251bn over the five year period. In response to MYPD3 revenue decision Eskom has reprioritised capex spent which resulted in movements of expenditures between licensees. Staff costs – complement of 43 000 growing to 46 000 Revised staff outlook decreasing staff complement to 41 020 by FY 2018 Business Productivity Program (BPP) savings initiative launched in the business. Maintenance More maintenance was undertaken than initially envisaged Addressing the reduced plant performance and maintenance backlog Other Opex Roll out of BPP saving plan Despite cost efficiency and saving programme other operating cost exceeded the decision MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 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 2015/16 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. 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 special pricing agreements and exports (international) customers. Non-electricity is made up of deferred income recognized and other revenue. Other income is classified as operating costs and is therefore discussed under that section 5.2 Calculation of the revenue variance The table below shows the sales volume and revenue variance with the total average price being marginally below the MYPD3 decision. 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. MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 Table 4 : Calculation of MYPD3 revenue variance for 2015/16 Revenue variance for 2015/16 MYPD3 Decision Actuals Variance Total external electricity revenue (R'm) 179 587 163 160 -16 427 Total external sales volumes (GWh) 235 210 214 487 -20 723 Total average selling price (c/kWh) 76.35 76.07 -0.28 *Note that the actual revenue reflected above excludes the load reduction impact. Once the load reduction impact of R849m is added back it reduces the revenue variance from R16 427m to R15 578m. 5.3 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 Note 1: Revenue as reported in Eskom’s 2016 AFS: Revenue from continuing operations of R163 395 million, reported on page 84 of Eskom’s 2016 AFS, provides the starting point for obtaining the MYPD equivalent for actual revenue. Actual Revenue for RCA calculation in 2015/16 (R'million) Eskom Company Notes Revenue per AFS 163 395 1 Less : Non-electricity revenue -1 707 2 Deferred income recognised -152 Other revenue -1 555 External electricity revenue 161 688 Add : IAS 18 unrecognised revenue 1 472 3 Internal electricity revenue - Revenue before load reduction adjustments 163 160 Add : Load reduction adjustment 849 4 Revenue for RCA purposes (R' million) 164 009 MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 Actual electricity revenue was R161 688 million; other revenue was R1 707 million (including deferred income of R152 million) for 2015/16. Table 6: Revenue note from AFS for March 2016 Source: Eskom Annual Financial Statements, 31 March 2016 page 84. 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 MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 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 R1 647 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). In addition, R175m of previously not recognized revenue has now been recognised in the current year. Eskom continues to actively pursue recovery of these amounts. 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 net impact of the IAS adjustment is R1 472 million which is added back to actual revenue for the RCA. Note 4: Estimated Load Reduction impact on revenue loss for 2015/16 During the third year of MYPD3 there were several interruptions and thus load reduction estimated at 1 064.5 GWh comprised a combination of load shedding and/or load curtailment. Load shedding and/or load curtailment contributed 643.6 hours of interruptions during the year as depicted in the table below. Eskom will thus need to reduce their volume variances to cater for the impact of load reductions. Eskom has computed the revenue loss impact using the principle of standard tariff rate. The load reduction impact of 1 064.5GWh is multiplied by the average standard tariff price of 79.73c/kWh as was determined by NERSA in para 4 of the 2013/14 RCA decision. . This equates to a total revenue loss attributable to the load reductions of R849 million. MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 Table 7 : Load shedding and curtailment impact in 2015/16 Demand (MW) per hour is taken as the estimated energy consumption for that hour and all hours shed was added to get the total energy (MWh) that was shed for that specific month. This gives an estimated maximum energy consumption impact for that specific month. The amount of energy reduced by mandatory load reduction is purely an estimation, and has always been indicated as such. This load reduction is a combination of load shedding and/or curtailment, neither of which can be accurately measured. It is also important to note that the behaviour of customers during and around times of load reduction is not normal. Hence the estimated energy reduction is based on how the expected demand compares against the actual demand supplied. Known variances such as demand behaviour on the day, the time of day, the day in the week and the season of each reduction event is also compensated for. Verification is done on the order of magnitude of each event, using the expected reduction for the relevant stage and duration of load shedding and/or curtailment. Hence the final estimation, although having a margin of error, will give a good indication of the behaviour and magnitude of each reduction event. These estimated values are aggregated monthly, as shown in the table above. Month Load shedding Hours Load Curtailment Hours Total Load Shedding and/or Curtailment Hours Load reduction GWh Standard average price c/kWh Revenue loss impact R'million Apr-15133.2 133.8 136.8 235.2 May-15215.6 213.1 225.1 360.4 Jun-15129.6 9.0 130.0 213.8 Jul-15114.7 30.0 115.0 190.9 Aug-1528.9 5.0 28.9 59.3 Sep-152.3 - 2.3 3.4 Oct-15- 5.5 5.5 1.5 Nov-15- - - - Dec-15- - - - Jan-16- - - - Feb-16- - - - Mar-16- - - - Total FY 2016624.2 396.4 643.6 1 064.5 79.73 848.7 MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 Power system emergency declarations and load shedding From 1 April to 8 August 2015, a total of 79 load reductions were required, particularly over evening peaks. Since then, Eskom had no load shedding, apart from one incident on 14 September 2015, when a low frequency event led to load shedding for 2 hours and 20 minutes. Load to key customers had to be curtailed on 9 October 2015, when five generating units tripped or had to be taken off load. The reduction in load shedding since August can be attributed to Medupi Unit 6 going into commercial operation on 23 August 2015, adding a nominal capacity of 720MW to the national grid, the implementation of the Generation maintenance strategy, lower than expected demand and other interventions. No load shedding is currently forecast for 2016/17. Additional generation capacity is planned to be commissioned by both Eskom and IPPs in the new financial year. However, the system remains vulnerable to incidents of simultaneous high unplanned outages or partial load losses, and high demand. 5.4 Allowed Revenue The allowed revenue of R179 587 million as shown in the table below is derived from the NERSA documentation as shown in the extracts below comprising the MYPD3 revenue determination and the MYPD2 RCA decision. Table 8: Allowed revenue 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) Extract 2: Source: NERSA “The implementation plan of Eskom MYPD 2 Regulatory Clearing Account (RCA) Allowed Revenue 2015/16 R'millionExtract ref MYPD3 Revenue171 769 1 MYPD2 RCA decision7 818 2 Total Revenue 179 587 MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 5.5 Sales volumes contribute to recovery of fixed costs 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 materialising, it results in Eskom not recovering the allowed revenue components as was assumed. 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. MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 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. 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 included in the returns and depreciation building blocks of the allowed revenue for regulatory purposes. 5.6 Allowed vs Actuals volumes Table 9 : Sales volume variance Note 1: The 235 638 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 13 465GWh (13 376GWh + 89GWh) which are based on the geographical location in which the sale occurred. For regulation the 89GWh is not shown as International sales as this is sold by Distribution and as such forms part of Distribution sales. Sales volumes variance per tariff category (GWh) MYPD3 Decision ActualsVariance SPA sales 11 3339 684-1 649 Add: Standard tariff sales including internal sales213 544192 089-21 455 Total Distribution sales224 877201 773-23 104 Add: International sales 2 10 76113 3762 615 Total Sales to all customers 1 235 638215 149-20 489 Less: Internal sales-428-661-233 Total external electricity sales 235 210214 487-20 723 MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 Table 54: Approved sales volumes forecast, MYPD3 decision 5.7 Sales volume variance explanation The MYPD forecast is normally finalized 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 analyzed and a determination is made. In the case of MYPD3, the MYPD forecast was finalized on 14 September 2011 when the prospects for a higher economic growth were still viable as we recovered from the recession in 2007/08. At that time the GDP growth assumptions were still high. The unfavorable variance in sales volumes against the MYPD NERSA decision was offset by the large favorable variance in the prepayment sales and export sales. The table below highlights the difference between MYPD3 forecasts and actual reality that has transpired over the last three years Table 10: MYPD3 Sales volume 5.7.1 The process in deriving the 5 year forecast The 5 year sales forecast used in the application was compiled using a bottom up approach from customer level. Each of the six Eskom Regions forecasted the Regional sales (covering the 9 provinces) using a bottom up approach from customer level for their specific Regions. Each Regional forecast were scrutinized on a one on one basis after which the six Regional GWh2013/142014/152015/162016/172017/18MYPD3 Total Standard tariff sales206 587 208 441 213 544 218 193 223 217 1 069 982 Negotiated pricing agreement11 303 11 303 11 333 11 302 11 302 56 543 Exports9 513 9 769 10 761 9 618 9 507 49 168 Approved sales forecast227 403 229 513 235 638 239 113 244 026 1 175 693 GDP2.6 3.6 3.6 3.9 4.0 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) 216 561 217 903 216 274 214 487 Actual sales growth %-3.66%0.62%-0.75%-0.83% MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 forecasts and the Top Industrial Customer’s forecast were consolidated into one Eskom view. 5.7.2 Critical changes in assumptions relevant during 2011 in deriving forecasts Table 11 : GDP forecasts used for MYPD3 in 2011  The actual GDP growth rates were approximately half the forecasted assumptions as received from various economic forecasts at the time.  The most rapid growth in recent decades has been in the less energy intensive services sectors, while the contribution of the energy intensive Mining sector started to dwindle.  Price increases will continue for the 3 years up to 2015/16 (combined increase of 25%). In addition, the price was already +/- 3 times what it was in 2008/9.  A substantial amount of furnace load would not be utilized in winter because of the higher winter prices.  Furnace utilization would be about 95% in the summer months.  Large Co-gen projects that are in an advanced stage in the commissioning process have been included in the budget.  Municipality generation assumed for inclusion of Power Purchase Agreements (PPAs) up to 2013/14, thereafter normal own generation.  Variance in the forecasted Commodity Prices used in the Decision vs the Actual average prices were higher than assumed. Table 12: Commodity Prices assumed GDP growth % 2 012 2 013 2 014 2 015 2 016 2 017 MYPD3 GDP growth % 4.0%4.0%4.0%4.5%5.0%5.0% Actual GDP growth % 2.2%2.2%1.5%1.3% Commodity PricesMYPD3 Decision Actual average prices FeCr$1.20/lb - $1.32/lb$0.76/lb Aluminum$2 500/ton - $2 750/ton$1 867/ton Platinum$1 480/oz - $2 000/oz$1 384/oz MYPD3 2015/16 RCA Submission to NERSA 15 July 2016  High probability new projects were included but were delayed with the downturn of the economy.  Average weather conditions have been used. 5.7.3 Sales volume variance explanation for FY2016 The table below shows the sales volume variance that will provide the reasons for the decrease in revenue compared to the decision. Table 13 : Sales volume variance From the table above, which reflects the variance between the decision and Actual sales for the year, it can be seen that the unfavorable variance of 23 104GWh in respect of distribution sales is mainly due to three categories, namely Redistributors, Industrial and Mining. The unfavorable variances in these three categories were partially offset by the favorable variance of 2 615 GWh from the export sales and 1 019 GWh from the prepayment environment. Sales volume variance per customer category (GWh) Actual Sales MYPD 3Variance International 13 376 10 761 2 615 Distribution sales201 773 224 877 (23 104) Re-distributors89 591 98 510 (8 920) Industrial50 150 60 145 (9 995) Mining30 629 36 210 (5 582) Traction2 852 3 133 (281) Residential4 034 4 555 (521) Commercial10 150 9 729 421 Agricultural5 733 5 276 457 Prepayment7 820 6 802 1 019 International A89 89 0 Internal Sales661 428 234 Other64 - 64 Total electricity sales volumes215 149 235 638 (20 489) Exclude Internal sales-661 -428 (234) Total external electricity sales volumes214 487 235 210 (20 723) MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 Redistributors: 8 920 GWh unfavourable 5.7.3.1 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 and Ekurhuleni Metro’s due to the sluggish economic growth. City Power and Ekurhuleni are within the economic hub of South Africa and thus severely affected by the slow local & global economic growth.  In the Southern Region the expectation was that the Coega development project would have started up but due to the absence of “the anchor project”, very little development have materialized up to this point.  Cape Town Municipality introduced a huge savings drive 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 eThekwini Metro, a large customer, Tata Steel closed down. In addition the sluggish economic growth resulted in a substantial decline in sales growth.  In 2015 the abnormal warm winter also reduced the energy consumption.  Rotational load shedding had a further impact on the consumption in the Metro’s and Municipalities.  Due to the Global economy that did not pick up as expected as well as the fluctuation of the ZAR exchange rate, the manufacturing sector behind the bulk meters in the municipalities were not able to secure orders, thus producing less with a resultant drop in energy consumption.  NUMSA strikes also negatively affected the consumption in certain Metro’s in 2015.  Due to the price increases, price elasticity also played a role resulting in savings from customers, especially in the lower LSM’s.  DSM initiatives also impacted the sales negatively 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 of the MYPD decision. MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 Figure 2 : Performance of Re-distributors Industrial: 9 995 GWh unfavourable. 5.7.3.2 This category was the most severely affected category and it is mainly due to the following:  The Aluminium sector posted a decline of 1 760 GWh mainly resulting from the closure of the Bayside smelter (1 260 GWh) and the very weak commodity price which forced production cuts due to a drop in world demand for Aluminium.  Sasol Infra Chem commissioned their own gas generation plant and displaced 324 GWh from the “Manufacturing of basic Chemicals” sector.  The Ferro and steel smelting industry realized a drop in consumption against the MYPD NERSA decision of 7 211 GWh due to the low demand for their products as a result of the collapse of commodity prices and cheaper imports from China that led to diminishing orders and downsizing and closure of customers. Refer to the table below on commodity prices.  As a result the smelting industry opted to take furnaces out during the three winter months to save on costs due to the very high price of electricity.  Many customers are downsizing and some considering full closures as a result of a low demand for their product. The combine impact of only three customers Highveld steel, IFM and ASA metals is a reduction in demand of 3 194 GWh. MYPD3 2015/16 RCA Submission to NERSA 15 July 2016  The Titanium sector posted a decline of 1 087 GWh mainly due to the the drop in world demand for their product and the resultant very weak commodity price. This caused the partial closure of furnaces at RBM (883 GWh) which forced production cuts at the plant.  The closure of EB Steam customers also affected the sales unfavourably. Table 14 : Commodity prices Source: LME, Platts, CRU, Metal Bulletin, Marquarie Research, December 2015 201420152016 UnitCYCYQ1 Copper$/tonne6,8625,5154,700 Aliminium$/tonne1,8671,6581,380 Zinc$/tonne2,1641,9421,600 Nickel$/tonne16,86711,8279,000 Lead $/tonne2,0961,7901,720 Tin$/tonne21,89316,06214,000 Manganese ore$/mtu CIF4,52,91,9 FeCr (EU contract)c/lb11910792 Molybdenum oxide$/lb1175 Cobalt (99.8%) $/lb141312 Steel Average HRC$/tonne598417343 Steel Scrap- average #1HMS$/tonne327209155 Iron Ore- Australian Finesc/mtu fob1428170 Iron Ore- Australian Lumpc/mtu fob16610082 Spot 62% Fe iron ore China$/t cfr975548 Thermal Coal- Australian Spot$/t fob715953 Thermal Coal- JFY contract$/t fob826882 Hard coking coal$/t fob12610281 Semi-soft coking coal$/t fob937865 LV PCI coal$/t fob1048469 Coke - China export spot$/t fob195145110 Gold$/oz1,2661,1571,140 Silver$/oz191615,10 Platinum$/oz13841,051875 Palladium$/oz803692580 Uranium Spot$/lb333736 Rhodium$/oz1,206961750 Rand basket priceZAR/oz12,99111,76211,031 MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 Figure 3 : Performance of Ferro and Steel Mining: 5 582 GWh unfavourable 5.7.3.3 This category was also affected severely and it is mainly due to the Gold and Platinum sectors: Mining production in South Africa slumped 18% year-on-year in 2015, according to figures from Statistics South Africa. Worst hit were Platinum Group Metals (PGM’s), which declined by 23.7%, Manganese ore (-24.3%) and iron ore (21.4%). Coal production dropped 15.8% and Gold production was 7.4 % lower. Part of the drop in Platinum output is attributable to a closure at Amplats refinery and Implats 14 Shaft. 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 realized a 2 578 GWh drop in consumption against the MYPD NERSA decision mainly due to o labour unrests which caused shaft closures . The Platinum Industry has endured the longest strike in history during 2014. 1,300 1,400 1,500 1,600 1,700 1,800 1,900 2,000 2,100 2,200 GWh Ferro & Steel Sector (GWh) Act Sales 2013Act Sales 2014Act Sales 2015 MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 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  The Gold sector realized a 2 435 GWh drop in consumption against the budget due cost pressure as a result of labour unrest and high salary increases. This again caused high cash costs and resulted in down scaling and shaft closures in many of the Gold mines. Some Gold mines were liquidated while others closed their shafts. Many shafts were put under care and maintenance due to cost pressures. The unfavourable commodity price also played a major role in escalating the cost pressures. Prepayment: 1 019 GWh favourable 5.7.3.4 In the Prepaid environment a significant favorable variance against the MYPD NERSA decision was realized mostly in the Northern Region due to the changing of the supply group codes that eliminated most of the ghost CDU’s in that Region, resulting in higher Sales volumes than anticipated in the MYPD NERSA decision. International: 2 615 GWh favourable 5.7.3.5 The favourable variance against the MYDP NERSA decision was mainly due to the higher than budgeted sales mainly due to the delay of BPC Morupule power station being commissioned. This resulted in more sales to. neighbouring countries. The drought affecting the Southern African region continued in 2015/16, resulting in reduced hydroelectric capacity available in the DRC, Zambia and Zimbabwe. This continues to provide Eskom with a market for additional electricity sales. Non-firm sales are being made to ZESCO and the Copperbelt Energy Corporation, both of Zambia, and ZESA of Zimbabwe. The lower water levels also led to reduced generation specifically at Ruacana which meant increased Sales from Eskom to NamPower. MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 5.8 Conclusion on the 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 revenue variance of R15 578m in 2015/16. Exports Sales Eskom has bilateral electricity trading agreements with most SAPP members and continues to export and import electricity. Eskom is aware of its responsibility to South Africa regarding the exporting of electricity when the domestic supply-demand balance is constrained. Eskom has ensured that the contracts with SAPP trading partners are sufficiently flexible to allow for the following controls: -During emergency situations in South Africa, non-firm agreements (Botswana and Namibia) and industrial customers across the border (Mozal and Skorpion Zinc) are interrupted in line with the terms of their agreements -The remaining firm supply agreements (Swaziland and Lesotho) continue to be supplied in full, but they are urged to reduce consumption. During load shedding in South Africa they are required to undertake proportional load shedding. MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 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 2015/16. Embedded in Eskom’s MYPD3 application was an assumption for EEDSM which was taken into consideration when determining the sales forecasts. In the 2015/16 year, NERSA assumed 763 GWh of energy savings at a cost of R819 million which culminated in 187 MW of capacity savings. In reality, EEDSM achieved lower savings during the year generating 119 MW of capacity savings at a cost of R413 million. For RCA purposes, however, the verified MW savings of 102.8MW at March 2016 is used results in an underachievement incorporated in the RCA mechanism. In addition, NERSA assumed DMP costs of zero in 2015/16 while actual expenditure was R248 million. 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 which is compiled on an accrual basis. 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. 8 RCA implementation risks Eskom is concerned that NERSA has determined that a proportion of the RCA award should be recovered from local SPAs and cross border customers. Local SPA revenue is based on bilateral contracts between Eskom and the counter parties and a major portion of export revenue is also based on bilateral contracts with counter parties. Hence, Eskom is of the opinion that it would be virtually impossible to recover the respective RCA amounts from these customer categories. MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 9 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” MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 “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 MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 10 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 some 21TWh, delays in new build commissioning, 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 4: Production FY 2016 MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 11 Primary energy Eskom has aligned the treatment of primary energy to the 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. 11.1 Primary energy variances and RCA impact for 2015/16 Total primary energy allowed for 2015/16 was R71 605 million. Eskom incurred R84 728 million in the year which resulted in an extra cost of R13 123 million. 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 an alpha adjustment 3. OCGTs – Eskom has aligned the OCGT RCA amount to the precedent adopted by NERSA in their 2013/14 RCA decision. 4. Nuclear decommissioning provision  Implementation of the 2013/14 provision of R830 million in ten equal tranches as per the 2013/14 RCA decision. i.e R83m inclusion in the 2015/16 RCA and  Implementation of the current 2015/16 provision of R361 million over the remaining life of 8 years i.e R45m inclusion in the RCA 5. IPP’s – In terms of IFRS, a portion of the Dedisa contract is accounted for under “IFRIC 4 Determining whether an arrangement contains a lease”. However for regulatory purposes, an adjustment of R340 million is deemed to be accounted for as an IPP purchase. Hence the sum of all these adjustments is R5 065 million and thereby reduces the total primary energy variance to R8 058 million. Refer table below for the RCA calculation for total primary energy. MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 Table 15 : Total primary energy comparison and RCA impact for 2015/16 Source : Allowed total primary energy -table 17, MYPD3 decision; Actuals - Primary energy note 34, AFS, March 2016 Extract from the AFS, March 2016 reflects the actual total primary costs of R84 728m below. Table 16: Primary energy actual costs per note 34 in the AFS of 2016, pg 35 With the summary information disclosed, the next section will provide more detail on the respective primary energy components. Primary Energy , R million MYPD3 Decision Actuals Variance RCA adjustments RCA 2015/16 Coal 39 838 41 775 1 937 1 321 3 258 OCGT s 1 508 8 690 7 182 -6 493 689 Local IPPs and co-generation 14 826 15 106 280 340 620 International purchases 93 3 660 3 567 - 3 567 Environmental levy 9 300 8 120 -1 180 - -1 180 Nuclear decommissioning of R830m f rom RCA 2013/14 decision phased in over 10 years - - - 83 83 Nuclear decommissioning R361m f rom RCA 2015/16 decision phased in over 8 years - - - 45 45 W ater 2 101 1 673 -428 - -428 Start up gas & oil 1 631 2 288 657 - 657 Coal handling 1 186 1 728 542 - 542 W ater treatment 281 365 84 - 84 Nuclear 498 918 420 -361 59 Fuel procurement 287 156 -131 - -131 Sorbent 56 1 -55 -55 P ri m ary en erg y , R m i l l i on 71 605 84 480 12 875 -5 065 7 810 Demand market participation - 248 248 - 248 T otal p ri m ary en erg y , R m i l l i on 71 605 84 728 13 123 -5 065 8 058 MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 11.2 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. 11.2.1 Medium-term Power Purchase Programme (MTPPP) Eskom initiated the MTPPP in 2008 in order to procure base-load capacity from private generators. The total capacity procured under the MTPPP amounted to 294 MW (excluding one contract that was awarded but never became operational due to the IPP failure to meet obligations). As at 1 April 2015 only one contract (of 13 MW) remained in operation under this programme, as the others had all expired. 11.2.2 Municipal Base-load Purchases Following continued capacity concerns Eskom approached municipalities to assist with additional generation. Of these contracts only one remained operational during the 2015/16 financial year (with City Power for 250 MW). 11.2.3 Short-term Power Purchases Programme (STPPP) The capacity constraints also prompted Eskom to launch the STPPP in order to attract additional capacity from private generators on a short-term basis. Short-term contracts with private generators with a combined contracted capacity of 812.3MW. 11.2.4 Wholesale Electricity Pricing System (WEPs) programme Eskom enters into annual contracts with embedded generators outside of the ambit of the MTPPP and short-term contracts. These contracts are paid at wholesale prices (effectively Eskom’s average price of generation, inclusive of external energy purchases). For the 2015/16 year 87MW of capacity was contracted. MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 11.2.5 Long-term IPP programmes In the procurement process for DoE’s long-term IPP programmes, Eskom's role is that of network operator, where Eskom owns the network and grid connection infrastructure, and is the designated purchaser of supplied energy. 11.2.6 IPP open cycle gas turbine (“Peaker”) programme Power purchase agreements (PPAs) of 1 005MW for the Avon and Dedisa plants were entered into on June 2013 and became effective on 29 August 2013. Commissioning of Dedisa took place on 30 September 2015 (335 MW), while Avon is expected during mid- 2016. 11.2.7 Renewable Energy Independent Power Producer (RE-IPP) procurement programme The DoE launched the RE-IPP Programme during 2011, which called for 3 725MW of renewable energy technologies in commercial operation between mid-2014 and the end of 2016. Developers were invited to submit proposals for the financing, construction, operation, and maintenance of any onshore wind, solar thermal, solar photovoltaic, biomass, biogas, landfill gas, or small hydro technologies. This has since been extended with additional Ministerial Determinations (adding 3200 MW in 2012 and 6300 MW in 2015). Eskom has now signed contracts for a total of 3 900MW under the RE-IPP Procurement Programme. As at 31 March 2016, a total of 2 145MW has been connected and is providing power to the grid. An average load factor of 30.7% was achieved during the year. Renewable IPPs are driven by wind and solar PV technologies. MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 Figure 5: IPPs contracted and connected (by province) MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 Figure 6: IPP operational capacities by type and location at 31 March 2016 1. Capacities (MW) indicate the contract maximum (or operational capacity if lower). 2. Other short-term refers to hydro, biomass, coal, gas turbines and engines, mixed fuels, etc. of which 460MW relates to coal and 253MW to gas turbines and engines. 11.3 Legal basis for IPPs per the MYPD Methodology Section 9 in the MYPD Methodology deals with the treatment of IPPs: Concentrated solar power Photo- voltaic Hydro and biomass Wind Eastern Cape70577335982 Free State121114235 Gauteng250250 KwaZulu-Natal123123 Limpopo5858 Mpumalanga413413 Northern Cape200651107412946 North West77 Western Cape59319377 Total operational200965109703359123 392 Total contracted4001 479271 9951 0059125 818 Province, MW RE-IPP Programme Diesel Other short term Total 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 pass- through 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. MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 11.4 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. 11.5 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: 11.6 Allowed vs Actual IPP costs for 2015/16 Eskom was awarded a total of R14 826 million for IPP’s in the MYPD 3 decision for 2015/16. This includes IPP ancillary costs of R388 million. Actual costs amounted to R 15 397 million. 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. MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 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. Eskom utilized 2 031 GWh more energy from IPPs when compared to the MYPD3 decision in 2015/16. A summary of the costs and volumes from IPPs are presented in the table below: Table 17: IPPs costs and volumes NB : The actual costs include the RCA adjustment amount relating to IFRIC 4 adjustment. 11.6.1 Reasons for IPP variances in 2015/16 Eskom utilized 2 031 GWh more energy from IPPs when compared to the MYPD3 decision in 2015/16, resulting in R620 million more spent on IPPs compared to the MYPD3 decision. A. Medium Term Power Purchase Programme (MTPPP) At the time of the MYPD3 application it was expected that the MTPPP contracts would have expired by FY 2016. The delay in the new build has necessitated the extension of the last MTPPP contract resulting in the additional energy purchases and additional cost. Volume variance: There is only one IPP remaining in the MTPPP. As a gas turbine (operating on piped gas) the generator has significant flexibility and operates in a mid-merit basis. This is in line with the contract parameters and is encouraged through differential pricing between the peak and off-peak periods. Price variance: As mentioned above the last IPP under the MTPPP operates on a mid-merit basis and thus benefits from the higher price applicable over the peak period in the contract (defined as between 06h00 and 22h00). Independent Power Producers (IPPs)Note 2015/16ActualsDecisionVarianceActualsDecisionVarianceActualsDecisionVarianceReference Non-renewable programs3 674 - 3 674 3 969 - 3 969 926 - 926 MTPPP56 - 56 44 - 44 1 269 1 269 A STPPP 2 682 - 2 682 2 816 - 2 816 952 952 B Municipalities858 - 858 976 - 976 879 - 879 B WEPS78 - 78 132 - 132 595 595 C Renewable IPP's11 182 13 243 -2 061 5 003 6 835 -1 832 2 235 1 938 298 Renewable IPPs energy11 158 13 243 -2 085 5 003 6 835 -1 832 2 230 1 938 293 D Renewable IPPs - deemed energy payment24 - 24 - - - D DOE Peaker590 1 195 -605 62 168 -106 9 540 7 130 2 410 E Total IPPs 15 446 14 438 1 008 9 034 7 002 2 031 1 710 2 062 -352 IPP ancilliary costs- 388 -388 F Total IPPs for RCA15 446 14 826 620 9 034 7 002 2 031 Costs (R'million)Volumes (GWh)Average Costs (R/MWh) MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 B. Short Term Power Purchase Programmes (STPPP) At the time of the MYPD3 application it was expected that the short term contracts would be phased out during FY 2015 as the system capacity shortfall was ameliorated by Eskom new build. The delay in the new build has necessitated the extension of the STPPP and municipal generation contracts leading to the increased purchase volumes and associated costs. C. WEPS The WEPS price reflects the NERSA approved WEPS tariff. Eskom buys energy from embedded generators at the average energy rate as determined by NERSA in the approved WEPS tariff. These contracts are annual contracts limited to generators ability to connect to the Eskom Distribution network at above 1 kVA. These were not included in the NERSA revenue determination. D. Renewable IPPs Price variance: Prices were marginally higher due to price adjustments between bid announcement and financial close, offset by lower actual CPI escalations (compared to forecast). Volume variance: The volumes produced by REIPP generators were lower than that assumed in the NERSA MYPD3 determination. There were a number of large REIPPP projects that experienced commissioning delays and some projects performing below the expected P50 values in the PPAs. 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 R23.9 million for the year were made due to:  The delay in grid connection for two projects  A System Event relating to grid connection for one project MYPD3 2015/16 RCA Submission to NERSA 15 July 2016  A System Event relating to extended network disruption for one project Not included as deemed energy (but paid as part of the total) is an additional payment for a Compensation Event for one IPP of R11.9 million. E. DOE Peaker Price variance: The payment to the Peaker is split between capacity payments and energy payments (for utilization) as it is fully dispatchable by Eskom. The average rate paid is higher than anticipated in the MYPD3 decision due to lower utilization (approx. 4, 2% for the period of operation) relative to the expected 5%. Volume variance: As explained above the volumes were lower, partly due to lower utilization by Eskom, but also that the project went into commercial operation later than originally anticipated. F. TRANSMISSION ANCILLIARY COSTS NERSA approved R388 million for Transmission ancillary costs in the MYPD3 determination for FY 2016. These costs have not been incurred. This portion of the allocation has been added to the budget to accommodate network use of system charges to the IPP which are a pass through to the Eskom Buyer’s Office. During FY 2016 the total payment for use of system charges was R48,6 million. This is included in the total payment for REIPP. Energy capacity and purchases This table summarises the IPP capacity available and the actual energy procured under various IPP programmes for the year to 31 March 2016, including the comparative year ending 31 March 2015. MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 Figure 7: IPP capacity available and the actual energy procured Measure and unit Actual 2015/16 Actual 2014/15 Total capacity, MW 3 392 2 606 Total energy purchases, GWh 9 033 6 022 Total spent on energy, R million 15 446 9 454 IFRIC 4 reallocation, R million (340) − Total spent after reallocation, R million 15 106 9 454 Weighted average cost, c/kWh 171 157 1. The weighted average cost has been calculated on the total energy cost before the IFRIC 4 reallocation. Eskom entered into a power purchase agreement with the IPP peaker Dedisa. For IFRS purposes, the capacity charge is treated as an arrangement that contains a lease in terms of IFRIC 4. The lease has been assessed as a finance lease and is accounted for under property plant and equipment at a fair value of R3 492 million. The IPP cost for Dedisa of R541 million under primary energy has been reduced by R292 million, and depreciation of R135 million and interest of R302 million will be charged to the income statement. During the peak demand hour in 2015 renewable IPPs were producing at 24% of their total capacity (with wind generating at 52% of capacity, but none from solar photovoltaic as the peak hour occurred during the evening.) Deemed energy payments of R23.9 million were made during the year (2014/15: R129 million), due to delays in grid connection for two projects and a network failure at a substation taking power from the IPP, which resulted in 24 hours of lost generation. Furthermore, a deemed energy payment of R11.9 million was required for a delay in the issuing of the grid compliance certificate for one IPP. These amounts are included in the total RE-IPP expenditure. Projects that have signed PPAs are in various stages of construction. MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 Table 18: IPPs contracted and connected 11.7 IPP variance for 2015/16 RCA IPP variance = Actual IPP costs – Allowed IPP costs Eskom spent R15 106m for local IPPs which exceeded the IPP allowance of R14 826m resulting in an over expenditure of R280m during 2015/16. In addition the accounting adjustment of R340m was reversed for regulatory purposes, resulting in a total RCA of R620m. MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 12 International purchases Eskom acquired electricity from neighboring countries that resulted in purchases of R3 660 million which generated energy inflows of 9 703 GWh 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 19: International purchases * Actuals includes Aggreko purchases of R643 million Cross-border sales and purchases of electricity The drought affecting the Southern African region continued in 2015/16, resulting in reduced hydroelectric capacity available in the DRC, Zambia and Zimbabwe. This continues to provide Eskom with a market for additional electricity sales. Non-firm sales are being made to ZESCO and the Copperbelt Energy Corporation, both of Zambia, and ZESA of Zimbabwe. Eskom is providing support to the region to the extent possible, but given the domestic constraints, support is mainly limited to off-peak hours. We are aware of our responsibility to South Africa regarding the exporting of electricity when the domestic supply-demand balance is constrained. Eskom has ensured that sales contracts with Southern African Power Pool trading partners are sufficiently flexible to allow us to restrict supply during emergency situations in South Africa. Table 20 : Cross border sales and purchases GWh Actual 2015/16 Actual 2014/15 International sales 13 465 12 000 International purchases 9 703 10 731 Net sales/(purchases) 3 762 1 269 International purchases , R million MYPD3 Decision Actuals RCA 2015/16 International purchases 93 3 660 3 567 MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 12.1 Regional IPPs - Aggreko In order to enable Eskom to address its short-term supply side challenges (as identified in the Medium Term Risk Mitigation Strategy) in the Integrated Resources Plan 2010, energy purchases from cross border base-load and peaking generation plant were to be considered. Eskom through its Southern African Energy (SAE) Unit, entered into a PPA with AIPL (Aggreko International Projects Limited) for a contracted capacity of 92.5MW from the Aggreko-Shanduka Gas Fired Plant in Ressano Garcia, Mozambique. Eskom had received approval from NERSA for cost recovery of the Aggreko project in terms of the regulatory rules for cost recovery for power purchases. The project was exempted by the Minister of Energy from the requirement to obtain a Ministerial Determination under regulation 11 of the Electricity Regulations on New Generation Capacity of 04 May 2011, due to the short term nature of the project, and to allow Eskom to address its short term challenges. A due diligence of the AIPL project also showed that the power station would reduce overall transmission losses between RSA and Mozambique, and also deload the transformer in Maputo. The AIPL price was higher than most of the conventional fossil fuel base load plants, but lower than gas and most of the renewable energy technologies. In addition the lead time for fossil fuel base load plants is at least 5 years, whereas AIPL has a lead time of 4 months, which was in line with the maintenance requirements of Eskom. Renewable technologies had longer lead times than the AIPL project, are intermittent in nature, and more expensive than AIPL. On the basis of the above, NERSA approved the cost recovery on the 6 June 2012, for a period of 2 years, for 92.5MW as a base load power station with 100% load factor. Eskom had envisaged that there would be no requirement to extend the agreement after the expiry date as the coal base load plants would be online then and therefore did not include the costs associated with this project in its MYPD3 application to the Energy Regulator. However, due to delays in new build coal plants, Eskom applied for the extension of this PPA by 14 months (from 01 July 2014 to 31 August 2015), the approval of which was granted. The recovery of the actual costs will occur via the RCA. MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 The supply profile was now based on a load profile that would maximize the benefits of the power from the plant i.e. off-setting the OCGT’s; hence the plant would now be operated as mid-merit (delivering a minimum of 100MW off-peak hours, and a maximum of 148MW peak hours). This project was used as a lever to contribute towards the supply and demand challenges. During 2015/16 Eskom incurred R643 million costs to acquire energy from regional sources. MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 13 Coal Burn Costs 13.1 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, short-term 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 pass-through 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 : 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 PBR cost (Rand) = (Alpha x Actual Unit Cost of Coal Burn+ (1 – Alpha) x Coal burn Benchmark price) X Actual Coal Burn Volume MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 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 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”. 13.2 NERSA’s decision on coal benchmark and alpha The following information was received from NERSA: Table 21: NERSA’s decision on coal benchmark and alpha Coal benchmark Unit MYPD3 2015/16 Coal burn costs R'm39 838 Coal burn volumes kt128 000 Benchmark avg cost rate R/t311.2 MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 13.3 Coal cost – RCA 2016 calculation The costs to be included in the RCA are calculated as follows: 13.3.1 Step 1 – Calculate the performance base regulation cost allowance In deriving the actual R/t costs, Eskom first deducts the costs relating to coal which are incurred but does not result in burn and energy being produced (Medupi take or pay and Kusile risk sharing agreement contracts). As presented below the actual R/t is computed by taking actual coal costs of R41 775m and adding back the reversal of R1 709m take or pay contractual amount which results in cost of R43 484m. Thereafter the adjusted actual cost of R43 484m is divided by the volume of coal burn of 114 806Mt resulting in an average actual R/t of R378.8. Table 22: Working Coal Mechanism Workings of coal mechanism UnitMYPD3 ActualsVariance Coal burn R'm39 838 41 775 1 937 Coal disallowed for qualifying actuals costs R'm- 1 709 1 709 - Medupi take or pay agreement R'm1 709 - Kusile take or pay agreement R'm- Coal burn costs R'm39 838 43 484 3 646 Coal burn tons Mt128 000 114 806 -13 194 Costs rate per ton R/t311.2 378.8 67.5 Alpha - sharing mechanism %95%95% Coal rate after incl Alpha R/t295.7 359.8 64.2 Adjusted MYPD3 decision with alpha375.4 PBR cost (Rand) = (Alpha x Actual Unit Cost of Coal Burn+ (1 – Alpha) x Coal burn Benchmark price) X Actual Coal Burn Volume For 2015/16 PBR cost (Rand) =( ((0.95 X R378.8) + (1-0.95) X R311.2)) X 114 806 Mt )/1000 PBR cost (Rand) = R43 096m Where Alpha = 0.95 Actual coal burn volume = 114 806 Mt Actual unit cost of coal burn = R378.8 per ton Coal burn benchmark cost = R311.2 per ton MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 13.3.2 Step 2 – Calculate the pass through coal burn costs 13.3.3 Step 3 – Split the pass through coal burn cost into volume variance and price variance summarised below. Table 23: The coal burn breakdown for the RCA The coal burn variance of R 3 258m 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 R4 953m 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 variance of R8 211m 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 burn variance breakdown Unit RCA 2015/16 Coal burn price variance R'm8 211 Coal burn volume variance R'm-4 953 Coal burn costs included in RCA R'm3 258 For 2015/16 Pass-through Coal Burn Cost = R43 096m – R39 838m Pass-through Coal Burn Cost = R3 258m Where PBR cost = R43 096m Allowed coal burn cost = R39 838m (per MYPD3 decision) Pass-through Coal Burn Cost = PBR Cost - Allowed Coal Burn Cost MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 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 price variance = Allowed coal burn tons X (Actual – Allowed Price in R/t X Alpha) Coal price variance = 128000 X ((R378.8 – R311.2) X 0.95) Coal price variance = 128000 X R64.2 Coal price variance = R8 211m Where: Allowed coal burn tons (Mt) = 128 000 Mt Actual Price (R/t) = R378.8 Allowed Price (R/t) = R311.2 Alpha = 0.95 Coal volume variance = Adjusted price r/t with Alpha X variance in coal burn tons Coal volume variance = (R311.2 + ((R378.8- R311.2) X 0.95 )) X (114 806 – 128 000) Coal volume variance = (R311.2 + R64.2) X -13 194 Coal volume variance = R375.4 X -13 194 Coal volume variance = -R4 953m Where: Allowed coal burn tons (Mt) = 128 000 Mt Actual coal burn tons (Mt) = 114 806 Mt Allowed Price (R/t) = R311.2 Actual Price (R/t) = R313.7 Alpha = 0.95 MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 13.4 Coal burn cost variance explanations The differences in 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. Table 24: MYPD 3 Assumptions vs. Actual 2015/16 MYPD3 FY16 Assumptions Actual 2015/16 Electricity production from coal fired plant would be 229 194 GWh. Electricity production from coal fired plant was 199 061 GWh. Cost Plus and Fixed Price mines produce at expected levels, except for Arnot Cost Plus and Fixed Price mines produced below expected levels by 19 899 kt. New long term mines are producing Only a portion of the coal could be accepted at Medupi Power Station because the station construction was delayed. Coal qualities have been adjusted to reflect the impact of the washing plants. Some delays were experienced with coal quality improvement initiatives, primarily because of funding constraints. The new power stations (Medupi and Kusile) use flue gas desulphurisation (FGD) at 0.45 litres per units sent out (l/USO). Medupi and Kusile did not come into commercial operation. Majuba heavy haul line and other rail infrastructure are approved, constructed and commissioned on schedule. Rail infrastructure was delayed Water consumption per unit was 1.54 litres for coal fired power stations Water consumption per unit was 1.56 litres for coal fired power stations Current infrastructure is old and the backlog of maintenance will also result in an increase to the water tariff. The DWA was unable to carry out all planned maintenance and still has a backlog. MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 13.4.1 Different mix and efficiency of power stations generating electricity The utilisation of the coal power station fleet to generate electricity resulted in a price variance driven by:  The delay in commissioning of Medupi Power Station.  The under production of Arnot and New Denmark collieries meant that more expensive coal, had to be sourced for Arnot and Tutuka. 13.5 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, comprising average ST/MT costs of R458/t, Cost plus costs of R388/t and fixed price costs of R262/t. 13.5.1 Long term fixed price contracts The total cost of coal includes the cost from different types of contracts and a transport cost for ST/MT contracts. The fixed price contracts were the cheapest source of coal. The pricing structure of these contracts is linked to the volumes delivered by the supplier. 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. The bulk of this coal is from mines that are next to the power stations that they supply, so the transport cost is minimal and is via conveyor belt. Approximately 28% of coal for FY16 was sourced from long term fixed price contracts. 13.5.2 Cost plus contracts Coal from Cost Plus contracts is the second cheapest coal supply source. The cost of this coal comprises all expenditure incurred at the mine, overheads, capex and a return on the mines’ initial investment. The age of these mines and levels of investment in them has reduced over time resulting in lower production volumes in recent years. Lower production MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 volumes result in a higher R/ton cost because Eskom is contractually liable for the operating costs of the colliery. However, the transport cost is also minimal because coal is transported by conveyor to the power station. Coal supplied under these agreements is, on average, cheaper than coal from ST/MT contracts. The mines will attempt 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. In this type of contract where the total output is dedicated to Eskom, the bulk of the risk is carried by Eskom in return for coal prices per ton which are generally lower than any other type of contracts. Additional capital investments and operating expenditures are required to improve the quality of coal or to increase the annual production volumes will impact the price per ton of coal to Eskom. 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 items that has been reduced. The result has been lower production from these mines and a consequent increase in the R/ton cost. This lower production is one of the reasons for the increase in coal purchased on ST/MT contracts. The under production during FY16 occurred, mostly, at Arnot, New Denmark, New Vaal and Matla mines. There has been limited investments in the cost plus mines in recent years which have impacted negatively on the production from these mines. It is foreseen that this impact will be felt during the remainder of MYPD3, as well. Cost plus mines provided approximately 33% of the coal procured in FY16. MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 ST/MT contracts 13.5.2.1 Coal from the ST/MT contracts is the most expensive coal supply source. One reason is that the contracts are of a shorter duration, so suppliers do not have the security that comes with long term contracts. The mining operations under these coal supply agreements have generally been commissioned after the mines under the Cost Plus and Fixed price agreements and thus they do not have the benefit of historically lower cost of infrastructure and establishment. However, the primary reason is because the cost of coal on ST/MT contracts includes a significant transport cost element. This coal is typically further away from the power station than coal on long term contracts. It, therefore, is transported by road or rail, sometimes a combination of the two. The rate per ton/km is influenced by the distance of a route and the condition of the road, with longer routes are more expensive. In addition to the actual transport cost, a handling cost is incurred when coal is loaded and offloaded. This handling cost is increased if coal is taken to a rail siding before being sent on to a power station. 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. During the life cycle of a contract the coal prices are typically not directly impacted by the price of export coal but the export price may have an impact at inception in that the supplier may reference this price at the time of negotiations. However, Eskom’s policy has been to pay the operating cost of extracting the coal plus a fair return on the required capital investment. Whether this price correlates to the export price at any given time during the life cycle of the contract is likely to be purely coincidental. These contracts supplied approximately 39% of the coal in FY16. In FY16 Eskom burned less than forecasted with the cost plus and fixed price contracts produced fewer tons than forecasted. Although electricity generation was lower than forecasted, ST/MT purchases at some stations were higher such as Arnot, Tutuka and Matla because of production problems at these stations’ dedicated mines. Purchases were also higher at Majuba and Camden (supplied by ST/MT contracts) due to actual production being higher than anticipated following changes in mix of stations. MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 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. 13.6 Future Fuel Future fuel had a variance of R1 747million when compared to the decision. This was primarily due to reprioritisation of capital expenditure. As shown in Table below, this comprises R46 M from future fuel (Water) and R1 702m from future fuel (Coal) respectively. Table 25: Future Fuel (Coal & Water) MYPD3 decision FY16 Actual Expenditure Decision vs Actual Coal 2,318 617 1,702 Water 53 7 46 Total 2,371 624 1,747 13.7 Coal Qualities In FY16, Tutuka and Matla Power Stations accounted for approximately 97% of coal-related load losses. The partial load losses reduction plan is divided into 3 phases, short-, medium-, and long-term. The short term solutions have already been implemented successfully in the priority power stations, namely Matla and Tutuka. The thermal load loss indicator as a gatekeeper in the allocation of losses will also be implemented as a short-term solution. 13.8 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 dominant transport source is conveyor (62%), road (27%) and rail (11%). MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 a. 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 FY16. b. Rail Rail is the next cheapest mode of transport. However, there are only four stations, Majuba and Tutuka, Camden and Grootvlei which have rail infrastructure. c. Road Road is the most expensive mode of transport. Because of rail infrastructure constraints, ST/MT coal to all stations, is transported by road or a combination of road and rail (multi- mode transport). In some instances, this multi-mode may be more expensive than road alone because of the costs associated with rail sidings, loading and offloading. The increase in volumes on road is a result of the change in the station/burn mix (i.e. increase in burn at stations without rail infrastructure and stations that do not have dedicated mines, such as the RTS stations. 13.9 Medupi Take or Pay payment A take or pay payment was incurred because of the delay in the construction of Medupi Power Station. The provision was reduced by R1 727 million. 13.10 Kusile Risk Sharing Agreement The construction of Kusile Power Station is ongoing. Eskom is still negotiating with Anglo Coal in an attempt to secure the long term coal for the station. The parties have signed a risk sharing agreement with certain milestone dates. Eskom provided for the amounts payable in MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 terms of the risk sharing agreement during FY13. During FY16, interest of R18m was incurred on the provision. 13.11 Securing our coal requirements Table 26: Securing our coal requirements Measure and unit Actual 2015/16 Actual 2014/15 Coal burnt, Mt 114.81 119.18 Coal purchased, Mt 118.70 121.67 Coal stock days 58 51 Road-to-rail migration (additional tonnage transported on rail), Mt SC 13.6 12.6 The significantly higher than targeted stock days is largely due to more coal than that required being delivered to Lethabo and Medupi Power Stations. Lethabo is supplied by a cost-plus mine, where there is no financial benefit in reducing the coal production. The high coal stock level at Medupi is caused by us taking delivery of coal in terms of the take-or-pay contract, even though the commissioning of units at Medupi has been delayed. MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 14 Other Primary energy The MYPD methodology allows for other primary energy as pass through. Coal burn, OCGTs, IPPs and environmental levy have specific rules and are dealt with separately in the document. 14.1 Allowed other primary energy in 2015/16 14.1.1 Allowed other primary energy costs Other primary energy costs in the MYPD 3 decision for 2015/16 is R6 040m. The details are presented in the table below. 14.2 Allowed vs Actual other primary energy Eskom incurred R7 129m relating to other primary costs during 2015/16 with the major items being start up gas and oil, coal handling and water which is summarised in table below. The actual costs exceeded the MYPD3 decision of R6 040 million by R1 089 million. By effecting the necessary adjustments the RCA claim is R856 million as highlighted in the table below. 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). MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 Table 27: Other Primary Energy Note 1: implementation of the 2013/14 provision of R830 million in ten equal tranches as per the 2013/14 RCA decision. i.e R83m inclusion in the 2015/16 RCA and Note 2: Implementation of the current 2015/16 provision of R361 million over the remaining life of 8 years i.e R45m inclusion in the RCA 14.2.1 Reasons for start-up gas and oil costs variance Start-up gas and oil contributes R657 million to the RCA. Heavy fuel oil starts and shuts down a coal fired power station and stabilizes 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 significantly higher in 2015/16 than what was anticipated at the time of the MYPD3 application and hence the use of fuel oil increased significantly as well. An improvement of 13% from previous year in terms of UAGs performance from 5.63 to 4.72 (UAGS/7000 was experienced. 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 very volatile and difficult to predict into the future with accuracy. Other Primary Energy , R' million MYPD3 Decision Actuals Variance RCA adjustments RCA 2015/16 Reference W ater 2 101 1 673 -428 0 -428 Start up gas & oil 1 631 2 288 657 0 657 Coal handling 1 186 1 728 542 0 542 W ater treatment 281 365 84 0 84 Nuclear 498 918 420 -361 59 Fuel procurement 287 156 -131 0 -131 Sorbent 56 1 -55 -55 O th er p rim ary en erg y b ef ore n u clear p rovision s 6 040 7 129 1 089 -361 728 Nuclear decommissioning of R830m from RCA 2013/14 decision phased in over 10 years - - - 83 83 Note 1 Nuclear decommissioning R361m from RCA 2015/16 decision phased in over 8 years - - - 45 45 Note 2 O th er p rim ary en erg y af ter n u clear p rovision s 6 040 7 129 1 089 -233 856 MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 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).” 14.2.2 Reasons for coal handling costs variance A variance of R542 million in favour of Eskom arose, due to movement of coal within the power stations being more than was originally envisaged. The main contributor to the coal handling variance was the Majuba coal silo incident. Majuba coal silo collapse 14.2.2.1 A coal storage silo at Eskom's Majuba power station in Mpumalanga collapsed on Saturday, 1 November 2014. At the time of the incident all units were on load. Operating personnel reported a visible crack on Silo 20 and immediately evacuated all personnel working in the area. Fortunately no injuries occurred. The generation capacity at Majuba power station was curtailed as coal could not be fed to the affected units, and load shedding had to be implemented. The increase in coal handling costs due to this event has contributed towards the RCA amount for this category. A short-term gap solution has been implemented to resolve the shortfall of electricity generated at Majuba as a result of this incident. This entailed the relocation and repair of the incline conveyors, previously fed by the collapsed Silo 20, and the installation of associated supporting infrastructure. Coal is being fed through an elevated mobile boom feeder, directly to the repaired incline conveyors through to the power station, with a coal throughput of 800 tons per hour. This has now enabled the power station to run at full load on all six units during the morning and evening peak and at an average of 85% load during MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 non-peak periods. A second elevated mobile boom feeder was installed at the end of March 2015 to further ramp up plant performance. A more cost-effective interim coal handling system has been implemented. This solution entails the commissioning of a conveyor system to deliver coal to a distribution bin, with one conveyor delivering to each incline conveyor gantry at the station. This enabled Eskom to reduce the high operational expenditure associated with the short-term gap solution. The feasibility study for a permanent solution has commenced. The reconstruction of the collapsed silo and the reinforcement of the remaining silos are underway and are scheduled for completion by the end of 2017. 14.2.3 Reasons for water costs variance NERSA granted Eskom R2.1 billion for Water costs in FY16. Actual expenditure was R1.6 billion resulting in under expenditure of R458 million compared to the decision and R940 million compared to the application. 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 tariff based costs. Expenditure on pumping and O&M was also significantly lower than planned. 14.2.4 Reasons for fuel procurement costs variance A variance of R131 million occurred due to lower expenditure. The primary components of fuel procurement expenditure and the reasons for the bulk of the under expenditure are: o Manpower was underspent because of savings initiatives, during which a moratorium was placed on hiring staff. o Savings on consulting fees due to the studies planned for the Waterberg strategy did not materialise. MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 14.2.5 Water treatment costs variance Higher water treatment costs incurred at Kendal, as chemical usage escalated due to resin approaching its maximum shelf life. o Matimba: The anion resin was planned to be purchased in FY2015, but it was rephased to FY2016. o Kriel: Because of the poor quality of water, more chemicals were used than anticipated. 14.2.6 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 R420 million more than the decision. The nuclear spent fuel provision once-off adjustment of R361million relates to an increased estimate of the costs of metal casks. However, for RCA purposes the provision of R361 million is disclosed separately as it is phased in over 8 years. MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 15 Environmental levy The MYPD methodology allows for (under)/over recovery to be adjusted through the RCA mechanism as presented in the extract below: Eskom incurred environmental levy costs of R 1 180m less than the MYPD3 determination for 2015/16. The fundamental driver to the variance for the environmental levy is due to a substantial decrease in volume offset by a slight decrease in renewable production and an increase in the system average auxiliary percentage. 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 2015/16. 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 under- recovery will be recorded in the RCA. MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 16 Demand Market Participation 16.1.1 Allowed DMP No DMP and power buybacks were allowed in the MYPD 3 decision. Table 28: Approved Demand Response (DR) Expenditure for MYPD3 Source: Table 36 of MYPD3 decision, 28 February 2013 16.1.2 Actual DMP Demand market participation had a variance of R248 m during the year. Table 29: DMP comparison for RCA 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 or has a lower impact that uncontrolled load shedding. R'm2015/16 DMP and Power buy-back Applied for Funding1 972 Demand Savings (MW)3 355 R/MW0.59 DMP and Power buy-back Adjusted Funding-1 972 Demand Savings (MW)-3 355 R/MW-0.59 DMP and Power buy-back Approved Funding- Demand Savings (MW)- R/MW- Demand market participation (DMP) in 2015/16 MYPD3 Decision Actuals RCA 2015/16 DMP (R’m) - 248 248 MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 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 considered a 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. MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 17 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 pass- through 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).” 17.1 Allowed OCGT spend For purposes of its revenue decision, NERSA assumed R1 508m for OCGT fuel cost from a production of 540 GWh requiring 152 ML of diesel. 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. A summary of the allowed OCGTs costs, rates and volumes as disclosed below. MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 Table 30 : Summary of allowed OCGTs components * Note: Ankerlig Rand/litre excludes other costs component of R53.9million 17.2 Actual OCGTs costs The actual OCGTs energy cost was R8 690 million to produce 3 937 GWh requiring 152 million litres during 2015/16 as presented in the table below. Table 31: Summary of OCGTs actual results for 2015/16 * Note: Ankerlig Rand/litre excludes other costs component of R44.3million 17.3 Computation of OCGTs claim for RCA purposes in 2015/16 In this RCA submission, Eskom has adopted the approach used in NERSA decision for RCA 2013/14 and is as follows: 1. Price pass through impact up to the 152ML per MYPD3 decision 2. Volumes above the assumed GWh are compensated at the actual average coal costs rate Allowed OCGT Usage and Spend GWhR million Fuel million litres Rand/LitreR/MWh Ankerlig337957 959.542 839 Gourikwa189513 539.662 712 Acacia719 29.542 783 Port Rex720 29.562 788 Total 5401 508152 Actual OCGT Usage and spend GWhR'million Fuel million litres Rand/LitreR/MWh Ankerlig2 5045 423 7866.842 166 Gourikwa1 3072 788 4176.692 133 Acacia57217.7902 19.660211.083 833 Port Rex69261.3462 24.094810.853 768 Total 3 9378 6901 246 MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 The OCGTs impact for RCA purposes for 2015/16 is R689 million which is summarised below with details for each component disclosed later. This is far lower than the actual variance of R7 182 million. Table 32: OCGTs RCA summary 17.3.1 Price impact up to allowed diesel litre usage of 152ML (million litres) The MYPD methodology allows for the rate variance to be adjusted through the RCA mechanism as highlighted below. The MYPD Methodology states that as per para 8.4.1 “costs will be allowed as a full pass- through cost, but limited conditional to volumes allowed by the Energy Regulator, except where such use is necessary to ensure security of supply...” . During the 2015/16 period the actual price per litre varied between R6.69/L (Gourikwa) to R10.89/L (Acacia) which is compared to decision rates for the respective power stations. Favourable price variances occurred at Ankerlig and Gourikwa where the majority of usage materialised. Cognisance must be taken of the fact that Ankerlig and Gourikwa use diesel fuel whereas Port Rex and Acacia make use of jet fuel. A summary is disclosed in the table below with the overall price variance of R408 million for the consumers’ benefit. OCGT Summary RCA amount (R'm) Excess volumes above allowed GWh recovered at average coal cost 1 106.6 Price variance on allowed 152ML -407.5 Other related OCGT costs -9.7 Total OCGT RCA R'million689.4 MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 Table 33 : OCGTs price impact for 152ML 17.3.2 Excess volumes above GWh recovered at average coal costs The excess of 3 397GWh above the allowed levels for the year is recovered at the average coal cost of 32.58c/kWh, resulting in a recovery of R1 106 million in Eskom’s favour as reflected in the table below. Table 34: OCGTs RCA claim related to excess volumes above allowed GWh 17.3.3 Other related OCGT costs Other related OCGT costs are in respect of standby trucks, tank rentals and storage costs for Ankerlig power station. There was a favourable variance of R10 million for the 2015/16 year as reflected in the table below. Price variance limited to the decision volumes (ML) Decision Rand/Litre Actuals Rand/Litre Variance Rand/Litre Allowed ML RCA amount (R'm) Ankerlig9.54 6.85 -2.69 95 - 255.6 Gourikwa9.66 6.69 -2.97 53 - 157.2 Acacia9.54 10.89 1.35 2 2.7 Port Rex9.56 10.81 1.25 2 2.5 T otal p rice varian ce im p act ( R ' m )152 - 407.5 Allowed MYPD3 volumes (GWh) Actual volumes (GWh) Excess volumes (GWh) Coal variable unit cost (c/kWh) RCA amount (R'm) Ankerlig 337 2 504 2 167 32.58705.8 Gourikwa 189 1 307 1 118 32.58364.3 Acacia 7 57 50 32.5816.2 Port Rex 7 69 62 32.5820.3 T otal excess volu m e com p en sation ( R ' m )540 3 937 3 397 1 106.6 MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 Table 35 : OCGTs other costs 17.4 OCGT usage in 2015/16 The diesel powered open-cycle gas turbines (OCGTs) production has decreased significantly from August 2015 to March 2016 due to improved Generation capacity available, lower demand, as well as increased production by IPPs. OCGT production for the eight months from August 2015 to March 2016 (since load shedding has ceased) totalled 1 539GWh, compared to production of 2 397GWh for the four months from April to July 2015 (during regular load shedding). For the year ending 31 March 2016, the OCGT production of 3 936GWh exceeded the MYPD3 assumption of 540GWh by 3 396GWh. This translates to an actual cost of R8 690 million, an overspend of R7 182 million against the MYPD3 allowance of R1 508 million. However, for RCA purposes Eskom is submitting R689 million in the RCA application having applied the 2013/14 RCA NERSA decision as a precedent. Figure 8 : Monthly OCGTs costs and production in 2015/16 Other OCGT related costs R'million MYPD3 decision Actuals RCA 2015/16 Ankerlig 54 44 -10 MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 17.5 Summary of OCGT RCA claim OCGTs for RCA = Price pass through limited to 152 ML per decision + Excess volumes of 3396 GWh compensated at average coal costs rate 32.58c/kWh Eskom incurred OCGTs actual costs of R8 690m compared to the assumed costs in MYPD3 decision of R1 508m which results in a variance of additional expenditure of R7 182m. However for RCA purposes, Eskom used the approach taken by NERSA in its RCA 2013/14 decision to compute the OCGTs RCA for 2015/16 which results in a claim of R689 million. Eskom believes that based on the conditions of the day and choices which were available in 2015/16, the operation of the OCGTs in and outside of peak hours was the correct decision for the country. 17.5.1 Managing supply-and –demand constraints 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. MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 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. 17.5.2 Actual Plant performance in 2015/16 Attached below is extracts from the 2015/16 integrated report which highlights the performance of the generation fleet. Operating highlights  There has been no load shedding since 8 August 2015, except for one incident on 14 September 2015, and load curtailment of key customers on 9 October 2015  The Tetris planning tool has assisted in optimising the scheduling of outages  Adhered to the summer and winter maintenance budget (planned and unplanned) of 11.5GW and 8.5GW respectively  Medupi Unit 6 has been in commercial operation since August 2015  UCLF improved from an average of 15.22% in 2014/15, to 14.91% in 2015/16, while  PCLF improved from an average of 9.91% in 2014/15, to 12.99% in 2015/16  EAF increased from an average of 69.85% in the last quarter of 2014/15, to 73.51% in the last quarter of 2015/16 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. MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 Generation Sustainability Strategy Until recently, Eskom has deferred some maintenance as a result of capacity constraints. Since August 2015, the extent of unplanned breakdowns has improved and new capacity has been added. This has enabled Eskom to adopt a revised maintenance strategy, which aims to perform all required maintenance, whilst adhering to the strict maintenance target (planned and unplanned) of 11 500MW in summer and 8 500MW in winter. Eskom has improved its outage scheduling using the Tetris planning tool. This provides a graphical representation of the maintenance schedule and the capacity outlook, and is able to provide a forward-looking view. This allows for more informed decision making regarding the prioritisation of maintenance and rescheduling to minimise the risk of load shedding. 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 Unplanned breakdowns (UCLF) have also improved from a monthly average of 16.15% in April 2015 to 11.48% in March 2016, due to a focus on partial load losses and improvements due to previous planned maintenance. Although the current efforts have helped to improve system performance, it is critical to note that the system remains constrained. Strategies are in place to address system constraints. Pressure on the system is expected to ease further as Medupi, Ingula and Kusile are progressively commissioned, combined with further increased production from IPPs. MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 Figure 9 : Generation technical performance Duvha Unit 3 over-pressurisation incident On 30 March 2014, Eskom experienced an over-pressurisation incident in the boiler of Unit 3 at Duvha Power Station, taking the 575MW unit out of service. This continues to have a material impact on the current UCLF. The letter of commitment for the construction contract has been accepted by both parties, paving the way for site establishment and mobilisation. The contract is expected to be awarded in mid-2016. Demolition of the damaged property will commence in 2016, whilst concurrently finalising the detailed design of the new boiler. It is envisaged that the unit will be commercially operational in 2020. Collapse of the Majuba coal silo Following the collapse of the coal silo at Majuba Power Station on 1 November 2014, construction of a coal silo interim solution has been completed with conveyor belts running from the permanent stockpiles to ensure greater efficiency in the coal handling process. The contract for a permanent solution for the rebuilding of Silo 20, the reinforcement of Silos 10 and 30 and the reinstatement of the coal conveyor system has been awarded. Detail design and construction activities are currently under way. The permanent coal handling plant is expected to be completed by the end of 2016. MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 Relationship between EUF, EAF and UCLF 17.5.2.1 This deterioration in availability performance is a direct result of the constrained system due to insufficient generating capacity being added timeously. This necessitated both the rolling of outages and limited the space to perform all the necessary maintenance required to both stabilise and improve station performance. In addition, the constrained system has necessitated sustained and high load factors of the coal fleet, at the limit of design levels, which have led to higher stresses, particularly on the boilers. On top of this, the regular operation of units in a compromised condition (for example with a boiler tube leak), in order to avoid system load-shedding, has caused additional consequential damage and contributes significantly to the performance deterioration. Figure 10 : Relationship between high EUF to EAF and EUF The figure above indicates that the utilisation / load factors (EUF – Energy Utilisation Factor) for Eskom’s coal fleet increased from around 83% in 2006 to over 90% from 2013. More significant, however, is that the average design parameter for the coal fleet was for a EUF of around 82%-85%. This means that over the last decade Eskom’s coal fleet has been operating at EUF levels above their design parameters. This has contributed to the upward trend in UCLF over this horizon. The EAF trend has been decreasing over the past few years especially since 2010 when EUF was operating at levels approaching and exceeding 90% as disclosed in figure above. The high operating levels of coal plants over the last decade has affected the EAF MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 performance which reached 71.07% by March 2016. Energy availability factors are an outcome of the planned and unplanned maintenance which has occurred. EAF has improved from a monthly average of 67.84% in April 2015 to 74.21% in March 2016. This improvement in EAF is indicative of the turnaround in Generations performance. Plant utilisation (EUF) for the year to 31 March 2016 was 82.69%, compared to 83.42% for the previous year. The utilisation of coal-fired power stations was 92.66%; Koeberg Nuclear Power Station was 99.19% and the peaking stations 20.26%. Eskom’s EUF is approximately 20% above the international norm, indicating the high levels at which we are operating our plant. MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 18 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. 18.1 Regulated asset base adjustment for CECA Capital expenditure will affect the value of the regulated asset base (RAB). The actual capital expenditure incurred during 2015/16 was R56 978 million compared to the MYPD3 decision assumption of R42 064 million thus resulting in a variance of R14 914 million. However, only capex changes that affect the RAB are adjusted for CECA purposes. The total variance of R14 914 million comprises Generation capex overspend by R20 764 million, Transmission underspend by R 3 500 million, Distribution underspend by R3 264 million with the balance attributable to other capital expenditure. Included in Generation were new build expenditures which exceeded the MYPD3 assumptions by R18.5 billion, comprising Medupi of R6.4 billion, Kusile of R8.6 billion and Ingula of R3.5 billion. The under expenditure in the network businesses were due to Eskom reprioritisation of its capital expenditure portfolio following the MYPD3 decision. However, for RCA purposes not all changes to capital expenditure affect the regulatory asset base and thus do not qualify for RCA related changes. Of the total variance of R14 914 million, only R9 180 million qualifies as RAB expenditure. 18.1.1 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. MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 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 variance of R 4 590 million (i.e R 9180 million divided by 2). Table 36: Calculation average capital expenditure CECA Calculation -Variance between actual and allowed capex Calculation ref Eskom Company Allowed MYPD capital expenditure42 064 Less: Allowed capital expenditure excluded for CECA purposesA(16 541) Future fuel(3 315) Technical and refurbishment capital expenditure(13 226) Capex subject to re-measurement for CECA B25 523 Actual MYPD capital expenditure56 978 Less: Actual capital expenditure excluded for CECA purposes C(22 276) Future fuel(2 114) Payment received in advance recognised to revenue(1 706) Technical and refurbishment capital expenditure(18 455) Actual Capex subject to re-measurement for CECA D34 702 Annual difference14 914 Technical and refurbishment capital expenditure excluded for CECA purposesA - C5 735 Capex subject to CECA re-measurement D - B 9 180 Average capital expenditure difference for CECA calculation(D-B)/24 590 MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 18.1.2 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 R332 million is computed by applying the allowed RoA to the capex variance. Table 37: CECA Calculation: Return due to/ (by) Eskom Note: For purposes of the calculating the CECA claim, the allowed RAB of R709 952m is adjusted for the capex variance of the current year of R4 590 million and prior year of R 4 316 million. CECA Calculation : Return due to/(by) Eskom Calculation ref Eskom Company MYPD3 Regulatory assets base709 952 Add /(Deduct): Current year average capex variance4 590 Add/ (Deduct): Cumulative prior year capex variances4 316 Adjusted RAB A718 857 MYPD3 allowed return on assetsB26 436 Return on adjusted RABA * C26 768 Increase / (Decrease) in return for RCA (A*C)-B 332 MYPD3 allowed return expressed as a percentage of the rate baseC3.72% MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 18.2 MYPD3 decision Below are extracts from MYPD3 decision reflecting approved RAB of R710bn and returns on asset at 3.72%, generating returns of R26 436 million and assuming a capital expenditure of R42 064 million. Table 38 : Regulatory asset base for 2015/16 Source: Table 10 of MYPD3 decision, 28 February 2013 Table 39: Returns and percentage allowed in 2015/16 Source: Table 9 of MYPD3 decision, 28 February 2013 Table 40: Capital expenditure in 2015/16 Source: Table 11 of MYPD3 decision, 28 February 2013 18.3 Reasons for new build higher expenditures Medupi: The over-expenditure of R6.4bn is mainly due to; Basic cost – Increase of R2.7bn due to;  Additional variation requests due to design changes, design integration challenges and additional employer policy requirements such as the Partnership Agreement. R'm2015/16 RAB Applied for919 662 RAB Adjustment -209 712 RAB Approved 709 950 R'm2015/16 Real Pre-tax WACC (%)3.7% Return (R'm)26 436 R'm2015/16 Capex Applied for64 835 Capex Adjustment -22 770 Capex Approved 42 065 MYPD3 2015/16 RCA Submission to NERSA 15 July 2016  Claim costs mainly due to prolongation as a result of access delays, force majeure events (including labour unrest) and construction challenges on the Boiler, Turbine and Civil packages.  The impact of the revision of the project completion date from December 2014 to June 2019. Escalation – Decrease of R0.4bn  Due to CPA linked to various indices and changing from time to time this might be favourable or unfavourable as compared to the projected amount. Owners Development Cost (ODC) – Increase of R1.9bn  Increase due to the new manpower structure with additional positions in critical roles (e.g. quality), DAB team to support claims management and the delay in the demobilization of resources in line with schedule delays Contingency - Increase of R2.3bn  Increase of R0.8bn 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.  Increase of R1.5bn due to Increase in the accrual for work done not assessed for all plant areas, it now includes all progressed milestones for all units to date including variation orders. Kusile: The over-expenditure of R8.6bn is mainly due to Basic cost – Increase of R3.0bn due to;  The MYPD 3 expenditure that was based on the 2014 synchronization date whereas the current expenditure is based on the increase expenditure to support the 2016 synchronization date. Escalation – Increase of R0.4bn MYPD3 2015/16 RCA Submission to NERSA 15 July 2016  Due to CPA actual expenditure being higher mainly because of the increase on labour indices. Owners Development Cost (ODC) – Increase of R2.5bn  Increase of R1.4bn due to cost incurred but not allowed in the determination.  Increase of R1.1bn due to hiring of strategic personnel and changes on working hours in order to meet the 1st unit synchronization date. Contingency – Increase of R3.1bn  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. Ingula: The over-expenditure of R3.5bn is mainly due to the following:  In the MYPD 3 applications for Ingula it was planned for the project to be completed by the 2014/15 financial year. Costs were however incurred in 2015/16 due to the delayed completion of the project mainly due to the accident on the inclined high pressure shaft 3 & 4 on 31 October 2013.  Since the tragic incident progress was significantly impacted resulting in limited progress for a period of approximately 12 months. 18.4 Actual Capital Expenditure Eskom spends approximately half on new build projects through the Group Capital division 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. MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 Table 41: Reconciliation of capex from Integrated report to CECA disclosures Detailed extract of capital expenditure of R57.3 billion is disclosed in table below. 18.5 Detailed Capital expenditure for 2015/16 Table 42: Capital expenditure (excluding capitalised borrowing costs) per division 1. Capital expenditure includes additions to property, plant and equipment, intangible assets and future fuel, but excludes construction stock and capitalised borrowing costs. 18.6 Delivering on the capital expansion Since 2005, Eskom has been expanding its generation and transmission capacity to meet the country’s growing demand for energy. Eskom’s nominal generating capacity in 2005 was 36 208MW. The programme will increase this by 17 384GW by 2019/20. The key generation expansion projects are the 4 764MW Medupi and 4 800MW Kusile coal-fired stations, and the Ingula pumped-storage scheme in the Drakensberg, which will deliver 1 332MW of hydroelectricity during peak demand periods. Transmission line length and substation capacity will also increase substantially, increasing IPP and customer connections, as well as asset maintenance and replacement projects. . Capital Expenditure R'million Actuals Total Eskom Group Capex per Integrated Report 57 352 Exclude : Eskom Enterprises -373 Total Capex for CECA disclosure 56 979 ActualActual 2015/162014/15 Group Capital 33 799 31 691 Generation 11 440 10 555 Transmission 998 1 121 Distribution5 4906 073 Subtotal51 72749 440 Future fuel 2 114 1 651 Eskom Enterprises 373 439 Other areas including intergroup eliminations3 1381 547 Total Eskom group funded capital expenditure 1 57 352 53 077 Division, R million MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 Since inception, our capacity expansion programme has increased installed generation capacity by 7 031MW, mainly through the RTS programme and most recently, Medupi Unit 6; transmission lines by 6 162km and substation capacity by 32 090MVA. The programme has cost R289.5 billion to date (excluding capitalised borrowing costs). Ongoing schedule delays have impacted the total cost of projects, specifically Medupi and Kusile, necessitating the revision of business cases, thereby increasing the available amounts to R145 billion for Medupi and R161.4 billion for Kusile (previously R105 billion and R118.5 billion respectively). 18.7 New build projects Medupi Power Station Commercial operation of Medupi Unit 6 was achieved on 23 August 2015 in line with commitments to accelerate delivery of all current new build projects, This marks the first new unit commissioned under our capacity expansion programme, delivering nominal capacity of 720MW (compared to installed capacity of 794MW) to the national grid, although the schedule was impacted by low productivity due to labour unrest as well as support provided to National Control to maintain the stability of the grid during times of constrained supply. Satisfactory progress is being maintained on Units 4 to 1, although schedule pressure on Unit 5 has caused some contractors to pull resources from later units to achieve scheduled milestone dates on Unit 5. The risk that work may be further delayed by industrial action is very low, and manpower levels are back to planned levels following the year-end break. The integrated master schedule has been finalised, providing planning and construction guideline dates for critical activities for all five remaining units. Commercial operation of Unit 5 is currently planned for the first half of 2018, with the final unit expected to be in commercial operation by the first half of 2020. The cumulative cost incurred on the project is R94.9 billion (March 2015: R84.7 billion) against the revised budget of R145 billion. All amounts exclude capitalised borrowing costs. MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 Kusile Power Station The project continues to achieve set milestones, on track for Unit 1 commercial operation by the second half of 2018. Good progress is also being made on Units 2 to 6, with the final unit expected to be in commercial operation by the second half of 2022. The project achieved a number of significant milestones since April 2015, and achieved all planned milestones during the year, only missing the commissioning of the diesel generator in December 2015. Milestones achieved include the boiler reheater hydro test, turbine air- cooled condenser leak test and super heater hydro test of Unit 1. Further areas of significant progress during the year include the Unit 1 stator coolant system flush that was successfully completed; commencement of Unit 6 boiler steel erection; as well as starting the pre-setting of fan blades and shrouds for all units, in preparation for fan testing. Progress on Unit 2 is also positive, with the air-cooled condenser condensate tank building structure being completed, turbine lube oil piping starting on 27 August 2015, and the generator stator being transported and set into position on 23 September 2015. Commissioning of the auxiliary cooling tower was completed on 29 September 2015. The sewerage plant was also commissioned. The cumulative cost incurred on the project is R95.1 billion (March 2015: R78.7 billion) against the revised budget of R161.4 billion. All amounts exclude capitalised borrowing costs. Ingula Pumped Storage Scheme Ingula Unit 3 was successfully synchronised to the national grid on 3 March 2016 and performed excellently for over a month. Ingula Unit 4 was successfully synchronised to the national grid on 25 March 2016. However, an unfortunate incident occurred on 6 April 2016 when the unit faulted and was damaged during commissioning and optimisation by the contractor. A full investigation to evaluate the extent of the damage is under way. The unit will be repaired, ready for commercial operation before the end of the 2016/17 financial year. Overall construction is 86% complete at the end of March 2016. Commercial operation of Units 3 and 4 is planned for the 2016/17 financial year, with commercial operation of Units 2 and 1 targeted for the second half of 2017. Work on the critical path is being closely monitored to ensure that key dates and associated milestones on the accelerated schedule MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 are not at risk of being delayed. The demobilisation of local labour is being managed through engagement with various stakeholders, to avoid negative outcomes. The cumulative cost incurred on the project is R26.8 billion (March 2015: R22.8 billion) against a budget of R25.9 billion. The project budget will require revision prior to project completion, after conclusion of the legal reviews of contract-related disputes. All amounts exclude capitalised borrowing costs. Power lines and substation capacity During the year, we installed 345.8km of high-voltage transmission lines and commissioned substation capacity of 2 435MVA under the new build programme, bringing the total since inception of the capacity expansion programme to 6 162km transmission lines and 32 090MVA substation capacity. The Gamma-Kappa 765kV line was energised, together with the Eros-Vuyani 400kV line, Mercury-Mookodi 400kV line, Ferrum-Mookodi 400kV line and the Anglo deviation line, Borutho 400kV line and Hendrina-Gumeni 400kV line, a total of 887.6km during the year. A key risk in achieving the transmission strengthening project remains the time required to obtain environmental approvals, securing land and obtaining the required water-use licences from the Department of Water Affairs. Funds available for Transmission strengthening projects are currently limited, which will extend the time taken to meet network reliability requirements and constrain our ability to connect customers. MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 Figure 11 : Transmission projects at March 2016 18.8 Conclusion on capital expenditure A number of key strategic challenges exist that require a Eskom Capital Portfolio greater than R300bn, as opposed to NERSA assumption of R230bn for purposes of the MYPD3 revenue decision MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 A rigorous process incorporating world’s best practices for capital prioritisation and optimisation was utilised to allocate the R251bn funding available over the MYPD3 period. 19 Inflation adjustment In compiling the inflationary adjustment, cost of cover, arrear debts (net impairment loss) and DSM 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 43: Inflation Data The qualifying expenses of R 39 582 million for the inflation calculation comprise employee benefits cost of R 19 844 million and other operating costs of R 19 738 million. Refer to the table below for the Inflation RCA claim. Inflation data2013/142014/152015/16 Inflation CPI - Decision 5.60%5.60%5.60% Inflation index - Decision 1.0561.1151.178 Inflation CPI - Actual5.70%6.10%4.60% Inflation index - Actual1.0571.1211.173 MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 Table 44 : Inflation adjustment Due to the actual compounded CPI index of 1.173 in 2015/16 being lower than allowed compounded CPI index of 1.178, this results in an inflation adjustment of R152 million in favour of the customer. Inflation adjustment for 2015/16 Calculation ref 2015/16 Total operating costs allowedA39 582 Decision inflation indexB1.178 Actual inflation indexC1.173 Restated allowed costs based on actual inflationD=A/B*C39 430 Inflation adjustment R'mD-A-152 MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 20 Energy efficiency and demand side management (EEDSM) 20.1 The Residential mass roll-out programme This Programme aims to reduce residential electricity usage by encouraging households to use energy-efficient technologies. The programme is a significant lever to reduce demand during periods of system constraint. It includes the following sub-programmes:  The focus in the residential sector was the rollout of Phase 3 of compact fluorescent lamps (CFLs), a total of 390 643 CFLs were installed inception-to-date, against a target of 500 000. It must be noted that the roll-out period spans 2 financial years.  The solar water-heater programme – Demand savings of 24.1 MW and energy savings of 153.0 GWh were installed and verified as part of the DoE SWH Programme at a cost of R2m for FY 2015/16. 20.2 Energy-efficiency measures Eskom’s Power Alert and “5pm to 9pm” campaigns were utilised to reduce power demand during the evening peak. The average weekday evening peak impact for the period under review for all colours (green, orange and red) is 224 MW. The average impact for the red flightings in the evening peak on the worst constrained day is 294 MW. Eskom’s utilised the 49M campaign, a long-term behavioural-change initiative that encourages energy efficiency practices, particularly for residential users, which has the ultimate goal of reducing energy consumption by 10%. This includes targeted seasonal campaigns such as the “beat the peak” campaign and the “live lightly” campaign. Integrated Demand Management (IDM) plays a key role in assisting us to balance power supply and demand during periods of generation constraints. Demand side management interventions encourage customers to use electricity more efficiently, thereby reducing the gap between supply and demand in the short to medium term. MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 Table 45: Demand management costs R million Actual 2015/16 Actual 2014/15 Total energy efficiency demand side management 413 656 Power buybacks – − Demand response 248 309 Total (excluding transfer pricing) 661 965 Table 46: Actual savings (not verified) and internal energy efficiency savings Measure and unit Actual 2015/16 Actual 2014/15 Demand savings (evening peak), MW 214.9 171.5 Internal energy efficiency, GWh 1.7 10.4 Actual expenditure is below budget due to IDM programmes being on hold for the first three months of the financial year, and due to the new contracting model, which makes provision for payments to be made only once demand savings have been verified. IDM runs a number of programmes to manage demand and improve energy efficiency. The Demand Response Programme has a combined certified capacity of 1 466MW of dispatchable load (2014/15: 1 356MW), which can be reduced for short intervals to restore system security, if requested by the System Operator. The compact fluorescent light (CFL) sustainability programme has installed a total of 1 696 120 CFLs since the project commenced in February 2104, of which 1 305 477 have been installed in in the current year. A second phase rollout of 10 million CFLs is planned for 2016/17 and 2017/18. Our Power Alert and “5pm to 9pm” campaigns continue to reduce power demand during the evening peak. MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 20.3 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. 20.3.1 Allowed EEDSM for 2015/16 The allowed rate for EEDSM savings is R4.38m/MW with 187MW savings being assumed which will cost R819m. Table 47: Allowed EEDSM Source: Table 40 of MYPD3 decision, 28 February 2013 R'm Applied forApproved Funding1 862 819 Programmes Peak Demand savings (MW)221 187 Programmes Annualised Energy savings (GWh)826 763 Programme Costs1 581 468 Operating Costs including Depreciation485 351 Other costs-204 - R/MW8.42 4.38 R/kWh2.25 1.07 2015/16 MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 20.3.2 Actual EEDSM Demand side management interventions encourage customers to use electricity more efficiently, thereby reducing the gap between supply and demand in the short to medium term. During the year, IDM conducted a number of programmes to manage demand and improve energy efficiency. Demand savings of 171.5 MW (including DOE savings of 24.1 MW) were substantially lower than the MYPD3 decision of 294 MW. As verified MW is used for determining the savings for the RCA computation, there exists a roll over between financial years relating to the time when projects are implemented and the actual verification of the MW savings. Therefore a reconciliation is required to determine the verified MW as presented in the table below. Table 48: Reconciliation between demand savings MWs used in RCA Calculation See Annexure 7 for details on measurement and verification report Hence the total capacity verified for 2015/16 after all the adjustments is 102.8 MW as is reflected in the M&V report submitted to NERSA. The EEDSM performance relating to capacity savings and costs are summarised in the table below. Reconciliation between demand savings MWs reported in AFS to MWs used in RCA2015/16 MWs achieved in current year (incl DOE) per AFS and Integrated report214.9 Less : MWs installed but not verfied in current year -112.1 Less : DOE funded MWs achieved 0 Add : MWs achieved in the prior year but verfied in current year 0 Total verfied demand savings (MW) for RCA102.8 MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 Table 49: EEDSM comparison for RCA in 2015/16 Table 50: Actual EEDSM R million Actual 2015/16 Actual 2014/15 Total energy efficiency demand side management 413 656 Power buybacks – − Demand response 248 309 Total (excluding transfer pricing) 661 965 Note 1 – For RCA purposes, the verified MW savings is used which results in a lower average rate of R4.02/MW (R413m/102.8MW) when compared to the decision rate of R4.38/MW. This benefit is passed onto Eskom as the lower actual rate benefit is applied to the verified savings of 102.8MW resulting in a benefit to R37 million. Thus in absolute terms Eskom underspent by R406 million but is being penalised to payback R369m. The difference is attributable to the benefit of the efficient overall rate benefit of R37m. Thus the MYPD methodology is reflecting the correct penalty of R369m. 20.3.3 Computation of EEDSM for the RCA Following the MYPD3 RCA 2013/14 decision, NERSA has computed the EEDSM which comprised a penalty for under achieving MW savings multiplied by the allowed rate (R/MW). Eskom has computed the IDM impact for the RCA purposes on the basis of Energy Efficiency & Demand Side Management (EEDSM)UnitMYPD 3ActualsVariance Funding R'm819 413 -406 Programmes - Peak Demand savings MW187 102.8 -84 Programme costs R'm763 Operating costs incl. depreciation R'm468 216 Other costs R'm351 197 EEDSM Rate R/MW4.38 4.02 -0.36 EEDSM Rate based on verfied MW savings for RCA R/MW4.02 -0.36 MW savings for RCA purposes MW102.8 RCA Penalty for not achieving MW savings R'm -369 MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 shortfall of 84MW multiplied by allowed rate of R4.38m/MW equating to an RCA impact of R369m in favour of the consumer. EEDSM penalty = R4.38m/MW X - 84MW = - R369m The current EEDSM regulatory rule does not allow for an incentive where the MW savings exceed the assumed targets and is a one sided rule which penalises Eskom when capacity savings are not met. 8484 MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 21 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. 21.1 Allowed operating costs in 2015/16 The MYPD3 decision comprised the building blocks for allowed revenue per the MYPD Methodology as described earlier in the document. The allowed operating costs disclosed allowed for total revenue of R906bn over the five year horizon. However, following the subsequent revision of the total revenue from R906bn to R863bn, which was attributable to the operating cost component and which was thus reduced to cater for the revision. The total operating cost allowed is R42 292 million as shown below. Table 51: Total Operating Cost Allowed FY2016 Allowed operating costR'millionNote ref Employee benefits 19 844 1 Other opex 19 738 2 Other income- Net impairment loss 1 031 3 Cost of cover 1 679 4 Total42 292 MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 Note1: Allowed employee benefits Table 52: Employee benefits are reconciled as follows Source A: Total GTD allowed employee benefits per NERSA decision Table 53: The allowed employee costs for Generation, Transmission and Distribution Source: Table 43 of MYPD3 decision, 28 February 2013 Source B: Total corporate overheads allowed Table 54: Allowed Corporate Costs in 2015/16 Source: Table 51 of MYPD3 decision, 28 February 2013 The R3 188 million above includes R930 million in respect of corporate depreciation which is reallocated from corporate overheads to depreciation. Source 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. Employee benefits allowedR'million Source ref Total GTD 17 586 A Add: Corporate Overheads3 188 B Less: Corporate depreciation-930 C Total Employee benefits allowed19 844 R'm2015/16 Manpower Applied for20 984 Manpower Adjustments-3 398 Approved Manpower 17 586 R'm2015/16 Corporate overheads Applied for7 194 Corporate overheads Adjustments -4 006 Approved Corporate overheads3 188 MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 Table 55: The depreciation per annum is reflected in the table below. Note 2: Other opex Other operating costs comprise repairs and maintenance and other costs, refer below. Table 56: Allowed Maintenance Costs Source: Table 44 of MYPD3 decision, 28 February 2013 Table 57: Other costs Source: Table 50 of MYPD3 decision, 28 February 2013 Note 3: Net impairment loss (Arrear debt) Table 58: Allowed Arrear Debts Source: Table 49 of MYPD3 decision, 28 February 2013 Total Corporate depreciation allowed (R'million) 20142015201620172018Total MYPD3 Corporate Depreci ati on434 678 930 1 091 769 3 902 R'm2015/16 Maintenance Applied for15 674 Maintenance Adjustments-2 175 Approved Maintenance 13 499 R'm2015/16 Other costs Applied for16 632 Other costs Adjustments -10 393 Approved Other costs 6 239 R'm2015/16 Arrear Debt Applied for1 215 Arrear Debt Adjustments-184 Approved Arrear Debt 1 031 MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 Note 4: Cost of cover Table 59: Allowed Cost of Cover Source: Table 48 of MYPD3 decision, 28 February 2013 21.2 Allowed vs Actual operating costs During 2015/16 Eskom incurred operating costs excluding IDM of R56 258m which compares to the MYPD3 assumption of R42 292m resulting in over expenditure of R13 966m. As there is an overall over expenditure position, Eskom operating costs don’t qualify for the RCA adjustment except for the inflation adjustment. Table 60: Summary of Operating costs in 2015/16 21.3 Variances in operating costs 21.3.1 Employee benefits Actual staff costs have exceeded the MYPD3 decision due to  Higher salary settlement of 8.5% compared to decision assumption of 5.4%, 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 R'm2015/16 Cost of Cover applied for1 679 Cost of Cover adjustments- Approved Cost of Cover1 679 Operating Costs R'millionsAllowedAFS actualsVariance Regulatory adjustmentsRCA actualsRCA balance Employee benefits19 844 24 720 4 876 -91 24 629 4 785 Other opex119 738 25 170 5 432 -309 24 861 5 123 Other income- 2 471 2 471 -9 2 462 2 462 Net impairment loss1 031 1 159 128 1 470 2 629 1 598 Cost of cover1 679 1 677 -2 - 1 677 -2 Total Operating Costs R'millions42 292 55 198 12 905 1 061 56 258 13 966 MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 MYPD2 revenue decision and the actuals during MYPD2. Hence the starting point was too low, thus contributing to the difference included in the RCA. Table 61: Trend in gross employee benefits Gross employee benefits has reflected a downward trajectory with 1.9% (2014/15) and -2.1% (2015/16). 21.3.2 Maintenance Overall Eskom underspend on maintenance. Generation and Transmission maintenance exceeded the MYPD3 decision and in 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. 21.3.3 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. Response strategies for debt collection 21.3.3.1 The top 20 defaulting municipalities contributed R4.8 billion at 31 March 2016, constituting 80% of total municipal arrear debt. Soweto arrear debt (excluding interest) increased to R4.7 billion at year end (March 2015: R4 billion). Actual employee costs2013/142014/152015/16 Net employee costs (before capitalisation)22 38422 18724 721 Employee costs capitalised to assets5 6856 4043 266 G ross em p loyee costs R ' m )28 06928 59127 987 Growth in gross employee benefits8.7%1.9%-2.1% MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 The rollout of smart prepaid meters is progressing well, with 18 997 conventional meters in Soweto and 4 227 in Kagiso being converted to prepaid at 31 March 2016. A total of 5 923 smart meters were installed in Sandton and Midrand, while the conversion to prepaid will resume in July 2016. Table 62: Municipal and Soweto arrear debt at 31 March 2016 R m 2015/16 2014/15 Municipal debt Total municipal debt (including interest ) 11 325 9 849 Municipal arrear debt (>15 days) 6 005 4 953 Percentage arrear debt to total debt 53% 50% Soweto debt Total Soweto debt (excluding interest) 4 746 4 182 Soweto arrear debt (> 15 days) 4 678 4 022 Average Soweto payment level, % 18% 16% Total arrear municipal debt as at 31 March 2016 has increased to R6 005 million, compared to R4 953 million at 31 March 2015. At year end, a total of 11 municipalities had total overdue debt greater than R100 million each; the top 20 defaulting municipalities contributed R4 819 million to arrear municipal debt, or approximately 80% of the total arrears. Furthermore, 82% of the arrear municipal debt is concentrated in the Free State, Mpumalanga and North West municipalities, contributing 47%, 24% and 11% respectively. Soweto arrear debt has increased to R4 678 million (March 2015: R4 022 million), with the payment level during the period at 18%. Residential revenue management 21.3.3.2 Every effort is made to ensure that customers pay their accounts on time. Eskom constantly monitors payments and are willing to enter into reasonable payment arrangements that take into account defaulting customers’ circumstances. Considerable effort also goes into building stronger relationships with these customers. Disconnection of supply remains a last resort. Customers are increasingly experiencing adverse market conditions, negatively impacting revenue and debtor’s days. MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 In Gauteng, we have embarked on an Eskom Operational Efficiency Service Level Improvement Programme (EOESLIP, previously branded Switch Ova!) focusing mainly on Soweto, Kagiso and other problematic areas, as well as Midrand and Sandton. The programme comprises several initiatives:  Decreasing energy losses by removing illegal connections, conducting meter audits, rectifying faulty or tampered meters and curbing ghost vending by introducing new supply group codes  Installing split smart prepayment meters within protective enclosures to prevent tampering, as well as bulk meters on supplies to hostels and entering into supply agreements with the owners  Improving payment levels by stepping up disconnections for customers not honouring their current accounts  Increasing debt collection from businesses by stepping up disconnections, entering into payment arrangements for arrears and installing split prepayment meters Soweto split prepaid metering rollout Soweto has approximately 180 000 customers, 80% of whom are on the conventionally billed metering system (post-paid) and the remainder on the prepaid metering system. The plan is to convert all meters to split prepaid meters within five years from 2014/15. The programme started off slowly due to numerous community protest actions. Nonetheless, at 31 March 2016, a total of 18 997 meters of previously post-paid customers were converted to prepaid in Soweto, representing 48% of the initial target of 39 794 customers. Due to community unrest, the strategy was changed to complete installation of meters in steel enclosures before conversion to prepaid. Since inception, the conversion of meters to prepaid has improved revenue collected by R60.79 million. Furthermore, conversions have resulted in an increase in revenue billed from R0.2 million in July 2014 to R4 million per month in March 2016, as demand is now being metered, as well as a drop in energy demand, due to customers now having to pay for their consumption. MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 Smart prepaid metering rollout in Sandton and Midrand In May 2015, we made a strategic decision to convert our post-paid residential customers to prepaid, starting with Sandton and Midrand residential customers. The project plans to convert 33 885 single phase and three-phase post-paid customers in these areas. At 31 March 2016, a total of 5 923 meters were installed; conversions to prepaid will resume in July 2016 once the upgrade of the Online Vending System to cater for prepaid recovery of network charges is complete. The project is targeted for completion by the end of the 2016/17 financial year. Impairment of arrear debt 21.3.3.3 Previously, Eskom recognised revenue and thereafter impaired the debtor if the amount was later deemed not to be collectable. In the current year, we applied the IAS 18 principle of not recognising revenue if it is deemed not to be collectable at the date of sale. As the revenue and corresponding debtor is never accounted for, there is no need to impair the debtor. At year end, this has resulted in external revenue and debtors of R1472m being derecognised, and impairment amounting to R566m from the previous year being reversed. 21.3.4 Energy losses and theft During the year, total energy losses were 8.59% (March 2015: 8.79%). Non-technical losses due to illegal connections and electricity theft in Distribution were estimated at between 1.61% and 2.57% (or between 3 467GWh and 5 546GWh). Transmission energy losses was 2.61% and Distribution energy losses was 6.43% during the year. The following progress was made on interventions aimed at reducing energy losses and recovering revenue:  Just under 87% of the feeders that require energy balancing have been balanced  A total of 8 065 large power user meter audits, 66 150 small power user meter audits and 646 160 prepaid meter audits were completed during the course of the year  Recovery of revenue, as a result of billing historically unbilled energy owing to meter tampers, faulty/vandalised metering installations or customers not loaded correctly on the system, amounting to R371.8 million was billed to large and small power customers MYPD3 2015/16 RCA Submission to NERSA 15 July 2016  Fines realised from prepaid customers tampering with their electricity meters amounted to R32.8 million at the end of financial year  A total of 3 565 tipoffs on electricity theft have been received from the public  Other interventions are in progress, such as the implementation of technologies (such as split metering and protective enclosures) to prevent access to the metering unit to restrict meter tampering, conversion of customers to prepaid, as well as the conversion of supply group codes on prepaid meters to prevent the use of illegal prepaid vouchers 21.4 Savings through Business Productivity Programme The Business Productivity Programme (BPP) aims to deliver cost savings to the value of R61.9 billion were identified over the five years to 31 March 2018. For the year ended 31 March 2016, savings of R17.5 billion were achieved against a target of R13.4 billion. Inception-to-date savings amount to R28.5 billion against a target of R25.9 billion, an overall stretch of R2.6 billion. 21.5 Other Income 21.5.1 Actual other income in 2015/16 In the course of Eskom operations in 2015/16, Eskom also generated total other income of R2 471 million which is disclosed under the Income Statement for March 2016 shown in Annexure 1. Table 63 : Other income for 2015/16 MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 21.5.2 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 Based on the precedent above, all items mentioned thereto do not qualify for inclusion in the RCA. Refer to extract below which shows the actual other income breakdown as per the AFS. 21.5.3 Other income included for RCA Sale of scrap 21.5.3.1 Revenue from sale of scrap and disposal of property, plant and equipment (PPE) are generated in relation to CECA. The RCA assessment provides for variances to be included in CECA to which these additional revenue streams relate and are therefore included in the RCA. Eskom generated other income of R134m from the sale of scrap assets. The sale of scrap (R134 million) is included as other income in the RCA submission in favour of the customer as it was generated through costs allowed in the MYPD. MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 21.6 Operating cost variance for 2015/16 RCA Operating cost variance = Actual operating costs – Allowed operating costs Based on RCA equivalent actual operating costs of R56 258 million and allowed other operating costs in the decision of R 42 292 million, Eskom has incurred an additional R13 966 million during the year. In terms of the MYPD Methodology Eskom cannot submit these additional expenses for RCA purposes and will have to absorb 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 which is described lower down. 21.7 Why symmetrical treatment of operating costs is needed Current approach in MYPD Methodology: The current MYPD methodology allows for under expenditure to be clawed back in favour of the customer and over expenditure must be absorbed by Eskom. This approach is biased as it implies that any over expenditure is deemed inefficient and cannot be recovered through the RCA process, which violates the NERSA mandate in terms of the Electricity Regulation Act to allow utilities to recover full efficient costs. Proposed approach: Amendment to current methodology for symmetrical treatment of operating costs Motivation  Aligned with policy and legislation MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 It is proposed that the symmetrical treatment of operating expenses would be in line with the intention of the Electricity Regulation Act in terms of which tariffs “must enable an efficient licensee to recover the full cost of its licensed activities, including a reasonable margin or return”. The Electricity Pricing Policy also stipulates that “the revenue requirement for a regulated licensee must be set at a level which covers the full cost of production, including a reasonable risk adjusted margin or return on appropriate asset values”.  Provides licensees with greater assurance The symmetrical treatment of operating cost variances would provide Eskom with greater assurance of adequate revenue to undertake the necessary operating and maintenance activities required for the optimal operation of the electricity system. The undertaking of such activities would still be subject to prudence review by the Energy Regulator. Only adjusting for prudently incurred under-expenditure would not enable Eskom to provide the best service to its customers. As one example, it might be prudent to defer a particular expenditure by one year – under a non-symmetrical treatment of variances it would result in the under-expenditure being clawed-back to the benefit of the consumer but the over- expenditure in the subsequent year not being recovered by Eskom. This disincentive is illustrated by Eskom spending more on maintenance costs. The over expenditure is not considered for prudency reviews, yet the current state of Generation plant requires extra efforts for maintenance.  Allows for optimal management decisions  A symmetrical treatment of operating costs would avoid perverse incentive with unintended consequences. A symmetrical mechanism would not imply an uncontrolled ability to spend – the normal prudence assessments undertaken by NERSA will require Eskom to substantiate any under and over-expenditure (when compared to assumptions made in the MYPD revenue decision) and thus act as sufficient incentive for efficiency.  Provide comfort to rating agencies MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 The methodologies applied by the credit rating agencies in terms of which they rate regulated electricity utilities also make that point, with non-symmetrical revenue adjustment rules leading to higher regulatory risk assessment and thus lower credit ratings. Symmetrical mechanisms are one of the key characteristics that are considered during the assessments of the regulatory framework by credit rating agencies. For example, the guidance given by Standard & Poor's Ratings Services for a ‘strong’ rating is “Any incentives in the regulatory scheme are contained and symmetrical” (“Key Credit Factors for the Regulated Utilities Industry”, November 2013). A positive assessment of the regulatory framework is crucial for credit ratings, as the regulatory framework and environment are critical factors considered during a credit ratings assessment – for example in Moody’s Global Investors Service’s methodology it comprises 50% of the total credit risk assessment of a regulated electricity utility (“Rating Methodology - Regulated Electric and Gas Utilities”, November 2013). For example an operating costs expenditure of say R1 million in March 2015 may not occur in that month due to logistic and governance processes. Hence if all assumptions and costs panned out to be exactly as per the MYPD decision other than this item, then according to the current MYPD methodology: RCA FY2015 - Eskom pays back this under expenditure through the RCA process RCA FY2016 - During the next month (April 2015), once the processes have been resolved the same prudent and efficient expenditure is incurred. Assuming that all else being exactly the same as per MYPD decision, Eskom is not allowed to claim the R1 million over expenditure relating to RCA for FY 2016 according to current methodology. Thus penalised twice for the same item, once for the under expenditure and secondly for over expenditure once cost is incurred as it cannot be recovered through the RCA. This highlight the need to revise the operating costs treatment to become symmetrical MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 22 Service Quality Incentives NERSA has approved the targets for service quality incentives for Distribution and Transmission below. NERSA is currently developing service quality incentives for Generation. Transmission plans, operates and maintains our transmission assets, while our Distribution network relays electricity from the high-voltage transmission network to customers, including municipalities that manage their own distribution networks. Table 64 : Trends in networks performance Measure and unit Actual 2015/16 Actual 2014/15 Number of system minutes lost <1 minute, minutes SC 2.41 2.85 Number of major incidents >1 minute, number 1 2 System average interruption frequency index (SAIFI), events SC 20.5 19.7 System average interruption duration index (SAIDI), hours SC 38.6 36.2 Note : One system minute is equivalent to interrupting the entire South Africa at maximum demand for one minute. Transmission achieved excellent system performance, with system minutes lost < 1 of 2.41, as well as the best ever reported performance of 1.51 line faults per 100km. This was supported by a high level of maintenance execution, as well as improved plant availability. There was one major incident at Witkop Substation in Limpopo Province, resulting in the supply to Polokwane and surrounding areas being interrupted for approximately 100 minutes. Performance risks still remain, with ageing assets and vulnerabilities due to network infirmness. Although the system average interruption frequency index (SAIFI) and system average interruption duration index (SAIDI) are better than target, there is a worsening trend in network performance. Eskom remain focused on Distribution sustainability through MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 refurbishment, reliability improvements and addressing maintenance backlogs. The longer term performance of the Distribution network is at risk given the prevailing resourcing constraints, which could lead to an inability to sustain network performance within regulatory norms. Table 65 : Summary of SQI performance in 2015/16 22.1 Transmission service quality incentives (SQI) for 2015/16 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 The performance results for these measures as reported in the Eskom Integrated reports for the financial years 2015/16 has been finalized and the subsequent financial reward / penalty based on these results has been computed. The SQI reflects a reward of R85m for system minutes less than 1 minute as reflected in the table below. Table 66: Transmission SQI performance in 2015/16 Licensee Service Quality Incentives (SQI) Incentive/ (Penalty) 2015/16 Distribution SQIIncentive233 Transmission SQIIncentive85 Total SQI for 2015/16 R'm)Incentive318 Transmission Service Quality Incentives (SQI) Performance result Incentive / (Penalty) R'm Comment SM<12.4124.50Reward Major incidents120Reward Line faults / 100km1.5140Reward Total Transmission SQI for 2015/16 (R'm)84.50 MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 Transmission system performance reflects significant improvements with an improvement in minutes lost from 2.85 in 2014/15 to 2.41 in 2015/16. Figure 12: Transmission system minutes (<1) Table 67: Transmission number of major incidents (>1SM) Number of Major Incidents (>1SM) MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 Figure 13 : Line faults /100km 22.2 Distribution Service Quality Incentive Scheme (SQI) for 2015/16 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)  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 2015/16 of MYPD3 and earned incentive rewards as indicated in the table below. The DSLI performance deteriorated during the same period and resulted in a penalty for year 2 and year 3 of MYPD3 cycle. The net impact of the SQI performance is positive for Eskom. The outcome of the SQI performance is summarised in the table below. MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 Table 68: Distribution SQI performance in 2015/16 Distribution system performance reflects significant improvements with a declining trend in SAIDI interruption durations reducing from 45.8 minutes in 2012/13 to 32.3 minutes by 2015/16. Informative Notes NOTE 1: The reported Distribution data is only for sustained supply interruptions (loss of supply for two or more minutes). NOTE 2: The performance figures show all events excluding agreed/approved exclusion events and 50% of planned SAIDI contribution (as per the NERSA approved Distribution SQI for MYPD3). NOTE 3: The performance figures in the mid-year report for April 2015 to September 2015 were preliminary numbers and are marginally different from the year-end report now that all events for the 2015/16 year have been closed. Distribution Service Quality Incentives (SQI) Incentive/ (Penalty) 2015/16 SAIDIIncentive145.90 SAIFIIncentive116.72 DSLIPenalty-29.18 Distribution total SQI R'mIncentive233.44 MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 23 Reasonability tests 23.1 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 14 : EBITDA-To-Interest Cover Ratio The figure above reflects around 3.0 for 2015/16 23.2 Understanding the ratio NERSA’s ratio might be similar to Moody’s ratio of “Cash from Operations pre-working capital +/- Interest ” – if so then the appropriate benchmark range for that type of ratio should be used. The minimum for investment grade on Moody’s ratio is 3. Even for a Ba rating (below investment grade) the ratio is 2 to 3. Although this measure only looks at the interest portion of total debt obligations i.e. does not consider the ability to meet the obligations regarding payment of debt principal, it indirectly measures that ability by using a higher benchmark range i.e. >3. NERSA’s target of 3.0 for 2015/16 (reducing to below 2.5 by 2017/18, per the figure) would thus not be appropriate for this ratio as it would be targeting sub-investment grade levels. Clearly this is not NERSA’s intention given that NERSA’s MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 comment in the MYPD2 RCA implementation plan was that it “is not expected to negatively affect the credit rating”. However, to achieve that, a value of >3 is probably required – 2.6 (and below) would certainly be very unfavorable to Eskom’s credit ratings. Alternatively, if the intention is to directly measure the ability to meet debt obligations, then the EBITDA should be compared to interest plus debt principal, not just interest – and in this case a lower benchmark range would be appropriate. Thus in deciding on the ratio to be measured it is critical to understand the intention as that will contribute to the elements required in the proper ratio calculations. In addition the ratio selected must be accompanied with the appropriate target benchmark range for measurement purposes. NERSA’s stated intention is that Eskom must be able to meet its debt obligations. This is confirmed by the Electricity Regulation Act s.16 (1) (a), as well as government’s Electricity Pricing Policy of 2008 that states: “Tariffs, therefore, need to be set at a level which would not only ensure that the utility generates sufficient revenues to cover the full costs (including a reasonable margin or return) but would also allow the utility to obtain reasonably priced funding on a forward looking basis. Rating agencies and lenders focus on a range of appraisal factors including profitability, e.g. Return on Assets (ROA) and Return on Equity (ROE), financial leverage (debt to equity) and debt service (e.g. interest coverage). It is important for the sake of financial sustainability that all these indicators move between acceptable norms and standards on a forward looking basis over the short, medium and long term. If the financial performance of the regulated entity deviates from these norms and standards investors will either be reluctant to extend credit or increase the cost of finance, ultimately resulting in higher tariffs or State support (e.g. guarantees, subsidies) or even bankruptcy in the case of private owners. Ultimately the decision to lend money to a regulated utility is made by the financial institution and not the regulator. The regulator, therefore, has a duty to measure the projected results from its regulatory methodologies (taking into account investment cycles and other cost trends) using the same criteria that reasonable commercial lenders would employ. The MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 regulator needs to consult with commercial lenders when assessing the financial viability of the industry on an ongoing basis.” 23.3 Interest cover ratio A further approach would be to use a conventional ‘interest cover ratio’, in which case the appropriate revenue item to use is EBIT (Earnings before interest and tax), not EBITDA. The reason for deducting Depreciation and Amortisation (thus, to use EBIT instead of EBITDA) is that these are the elements used for the loan repayment. Thus EBIT is used when one measures only interest cover. The objective of the interest cover ratio is used to determine how easily a company can pay interest on outstanding debt. It is a debt and profitability ratio. 23.4 Debt service cover ratio (Interest + Capital) Therefore an EBITDA interest cover ratio > 1 may not necessarily mean Eskom has enough available to pay interest unless the effect of the principal loan repayments are also taken into account, i.e. if EBITDA is used then it should be compared to total debt service obligations (interest plus debt principal). Thus EBITDA is used when one measures the ability to cover the full debt obligations comprising interest plus debt principal. 23.5 Computation of ratios for FY 2015 The financial information used to compute the ratios is disclosed below. MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 Table 69: Financial information for ratios in 2015/16 Various ratios have been computed as summarised below. Eskom’s 2015/16 AFS reports on such interest cover ratio and reflects it as 0.45 which is way below the minimum of 2.5 required to remain in the lower range of investment grade ratings. Alternatively, if the focus was on debt service cover then the actual result in 2015/16 is 0.74. Irrespective of whether interest cover ratio (using EBIT) or debt service cover ratio (using EBITDA) are used to measure the financial situation, the actual outcome on both are poor in 2015/16 compared to their acceptable ranges of over 2 (and that reference value has also been confirmed by NERSA). If the EBITDA; Interest cover ratio is used then the acceptable range for lower investment grade ratings would be >3. When using ratios that seem similar to this ratio the rating Financial Information for ratios workings2015/16 EBITDAA29 592 Profit before net finance (cost)/ income - EBITB13 075 Plus:Depreciation and amortisation expense16 517 30 603 C23 333 3 151 1 130 2 583 406 -1 651 Investment in securities-347 Loans receivable-446 Cash and cash equivalents-858 D28 952 115 -1 130 -406 1 651 29 067 11 013 E40 080 Employee benefit obligations Calculation of EBITDA Calculation of Total debt serviced Finance cost Debt securities and borrowings Derivatives IRS and CCS Finance income Total interest used for calculation Add : Debt repaid Total debt serviced Provisions Finance lease payables Finance income Net interest per AFS Add / (deduct) items excluded for purposes of the framework : Provisions and Employee benefit obligations Finance lease payables MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 agencies set >3 as the minimum for lower investment grade, with <3 being rated as sub- investment grade. 23.6 EBIT Interest cover ratio The results reflects an EBITDA interest cover ratio 0.45 which entails that Eskom did not generate sufficient earnings to cover its interest commitments. In order for Eskom to cover its interest costs the cover ratio must be at least 1. Therefore at 0.45, Eskom’s earnings during 2015/16 do not even cover half the interest costs for the year. Table 70: EBIT Interest Cover 23.7 EBITDA: Total debt service ratio The results reflect an EBITDA: debt service ratio of 0.74 which means that Eskom did not earn enough to cover interest plus debt repayments, thereby being placed in a situation to refinance debt. The results reflect a shortfall of R10 488m (R40 080m minus R29 592m) which was effectively refinanced in 2015/16. Table 71: EBITDA Debt service cover during 2015/16 Calculation Reference 2015/16 EBIT Interest coverB/D 0.45 B13 075 D28 952 EBIT Interest cover EBIT Interest Calculation reference 2015/16 B/E 0.74 B29 592 E40 080 EBITDA Total debt serviced EBITDA : Total debt serviced (Revised calculation to account for debt repaid) EBITDA : Total debt serviced MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 24 Conclusion Eskom’s approach to RCA 2015/16 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 utilized by NERSA in making their decision especially when it refers to the treatment of revenue and OCGTs. 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. Eskom’s 2015/16 RCA Submission is driven substantially by revenue under recoveries, higher expenditure for IPPs, an aligned OCGTs submission and other primary energy. Eskom has not claimed the over expenditure of R13 966m 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. In addition Eskom has applied the NERSA approach to OCGTs resulting in the organization absorbing R6 493m relating to OCGTs. Ultimately the 2015/16 RCA Submission of R23 633m will allow Eskom the opportunity to earn the allowed revenue and to recoup efficient costs which qualify for the RCA that exceeded the assumptions made in the MYPD3 decision for 2015/16. The need for a significant RCA adjustment is demonstrated by the actual debt cover ratios being well below acceptable norms. >>>>>>>>>>>>>>>>>>>>>>>>>>>>>>>> END >>>>>>>>>>>>>>>>>>>>>>>>>>>>>>>> MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 Annexures: Revenue: Annexure 1: Income Statement in AFS 2016, page 15 1. Refer to note 49 2. A nominal amount is attributable to the non-controlling interest in the group. Theremainder is attributable to the owner of the company. Refer to note 49. Restatement note 49, page 94 AFS 2016 Income statements for the year ended 31 March 2016 2016201520162015 NoteRmRmRmRm Continuing operations Revenue32163 395 147 691 163 395 147 691 Other income332 390 4 444 2 471 6 645 Primary energy34(84 728)(83 425)(84 728)(83 425) Employee benefit expense35(29 257)(25 912)(24 721)(22 187) Net impairment loss36(1 170)(3 766)(1 159)(3 755) Other expenses37(18 663)(15 771)(25 170)(22 083) 31 967 23 261 30 088 22 886 Depreciation and amortisation expense38(16 531)(14 115)(16 517)(14 001) 39(1 452)(4 117)(1 492)(4 208) Net fair value gain on embedded derivatives 997 1 310 996 1 310 Profit before net finance cost14 981 6 339 13 075 5 987 Net finance cost(7 919)(6 109)(8 776)(6 769) Finance income403 447 2 996 2 667 2 360 Finance cost41(11 366)(9 105)(11 443)(9 129) Share of profit of equity-accounted investees after tax11 43 49 - - Profit/(loss) before tax7 105 279 4 299 ( 782) Income tax42(2 488)( 37)(1 697) 160 Profit/(loss) for the year from continuing operations4 617 242 2 602 ( 622) Discontinued operations Loss for the year from discontinued operations- ( 42)- - Profit/(loss) for the year 2 4 617 200 2 602 ( 622) GroupCompany Net fair value loss on financial instruments, excluding embedded derivatives Restated 1 Restated 1 Profit before depreciation and amortisation expense and net fair value loss (EBITDA) MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 Notes to the financial statements (continued) for the year ended 31 M arch 2016 49.Restatement of comparatives Change in measurement basis of cross-currency swaps classified as derivatives held for risk management The impact of the restatement is as follows: Previously reported AdjustmentsRestatedPreviously reported AdjustmentsRestated RmRmRmRmRmRm Statements of financial position at 31 March 2015 Assets Non-current Derivatives held for risk management19 242 (4 939)14 303 19 242 (4 939)14 303 Equity Capital and reserves attributable to owner of the company122 247 (5 083)117 164 116 040 (5 083)110 957 Liabilities Non-current Derivatives held for risk management 520 2 121 2 641 520 2 121 2 641 Deferred tax20 131 (1 977)18 154 19 825 (1 977)17 848 Income statements for the year ended 31 March 2015 Continuing operations 23 261 - 23 261 22 886 - 22 886 Depreciation and amortisation expense(14 115)- (14 115)(14 001)- (14 001) Net fair value gain/(loss) on financial instruments excluding embedded derivatives 630 (4 747)(4 117) 539 (4 747)(4 208) Net fair value gain on embedded derivatives1 310 - 1 310 1 310 - 1 310 Profit before net finance cost11 086 (4 747)6 339 10 734 (4 747)5 987 Net finance cost(6 109)- (6 109)(6 769)- (6 769) Finance income2 996 - 2 996 2 360 - 2 360 Finance cost(9 105)- (9 105)(9 129)- (9 129) Share of profit of equity-accounted investees, net of tax 49 - 49 - - - Profit before tax5 026 (4 747) 279 3 965 (4 747)( 782) Income tax(1 366)1 329 ( 37)(1 169)1 329 160 Profit for the year from continuing operations3 660 (3 418) 242 2 796 (3 418)( 622) Discontinued operations Loss for the year from discontinued operations( 42)- ( 42)- - - Profit for the year3 618 (3 418) 200 2 796 (3 418)( 622) GroupCompany EskommakesuseofavaluationtechniqueintermsofIFRStodeterminethefairvalueofcross-currencyswapsthatareheldforriskmanagement.Eskomreviewedandimprovedthevaluation techniquetobetterreflectnon-performancerisk,inparticularcreditrisktakingintoaccountthecreditvalueadjustment(CVA)ofthecounterpartyanddebitvalueadjustment(DVA)ofEskom. This resulted in a value that is more representative of the net credit exposure to a counterparty. Astheimprovementsinthevaluationtechniquearerelevanttodeterminethefairvalueinprioryearsandgiventhesizeoftheadjustmentsrelatedtoprioryears,theprioryearfinancial statements have been restated. Profit before depreciation and amortisation expense and net fair value gain/(loss) (EBITDA) MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 Annexure 2: The Eskom energy wheel (Eskom Fact sheet 2016) **Note: All figures are in GWh unless otherwise stated. MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 Annexure 3: Sales volumes GWh – Statistical tables for 2015/16 Electricity sales per customer category, GWh Category 2015/162014/15 Local 201 022 204 274 Redistributors 89 591 91 090 Residential 1 11 917 11 586 Commercial 10 150 9 644 Industrial 50 150 53 467 Mining 30 629 29 988 Agricultural 5 733 5 401 Rail 2 852 3 098 International 13 465 12 000 Utilities 4 018 2 797 End users across the border 9 447 9 203 214 487 216 274 International sales to countries in southern Africa, GWh 13 465 12 000 Botswana1 0991 237 Lesotho205230 Mozambique8 2818 360 Namibia1 746 924 Swaziland1 044882 Zambia 344 16 Zimbabwe 252 108 Short-term energy market 2 494 243 1. Prepayments and public lighting are included under residential. 2. The short-term energy market consists of all the utilities in the southern African countries that form part of the Southern African Power Pool. Energy is traded on a daily, weekly and monthly basis as there is no long-term bilateral contract. MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 Electricity revenue per customer category, R million Category 2015/162014/15 Local 154 959 140 074 Redistributors 66 353 60 051 Residential 1 12 824 11 361 Commercial 10 100 8 599 Industrial 31 406 30 377 Mining 24 133 20 848 Agricultural 7 278 6 247 Rail 2 754 2 591 IPP network charge 111– International 8 055 6 306 Utilities 8 055 2 988 End users across the border 3 318 Gross electricity revenue 163 014 146 380 Environmental levy included in revenue 2 513 485 Less: Revenue capitalised 3 (367) - Less: IAS 18 revenue reversal 4 (1 472) (597) Electricity revenue per note 32 in the annual financial statements 161 688 146 268 3. Revenue from the sale of production while testing generating plant not yet commissioned, capitalised to plant. 2. The environmental levy of 2c/kWh tax was effective from 1 July 2009 to 31 March 2011. On 1 April 2011 the levy was raised to 2.5c/kWh. On 1 July 2012 the levy was raised to 3.5c/kWh. The levy is payable for electricity produced from non-renewable sources (coal, nuclear and petroleum). The levy is raised on the total electricity production volumes and is recovered through sales. 4. The IAS 18 principle of only recognising revenue if it is deemed collectable at the date of sale, as opposed to recognising the revenue and then impairing the customer debt when conditions change, has been applied since 2015. External revenue to the value of R1 472 million was thus not recognised at 31 March 2016. 1. Prepayments and public lighting are included under residential. MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 Primary Energy Annexure 4: Primary Energy Note 34 extract AFS March 2016, page 85 2016201520162015 NoteRmRmRmRm 34.Primary energy Own generation costs57 594 61 630 57 594 61 630 Environmental levy8 120 8 353 8 120 8 353 International electricity purchases3 660 3 679 3 660 3 679 Independent power producers15 106 9 453 15 106 9 453 Other 248 310 248 310 84 728 83 425 84 728 83 425 Own generating costs relates to the cost of coal, uranium, water and liquid fuels that are used in the generation of electricity. Eskom use a combination of short-, medium- and long-term agreements with suppliers for coal purchases and long-term agreements with the DWA to reimburse the department for the cost incurred in supplying water to Eskom. GroupCompany MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 Reasonability test Annexure 5: Finance income note 40 and Finance cost note 41 (Extracts AFS March 2016, page 86-87) Notes to the financial statements (continued) for the year ended 31 M arch 2016 2016201520162015 NoteRmRmRmRm 40.Finance income Investment in securities 723 739 347 513 Loans receivable 825 799 446 422 Finance lease receivables 65 68 65 68 Trade and other receivables 951 677 951 676 Cash and cash equivalents 883 713 858 681 3 447 2 996 2 667 2 360 41.Finance cost Debt securities and borrowings23 242 19 699 23 333 19 731 Eskom bonds10 202 9 381 10 202 9 381 Promissory notes 6 5 6 5 Commercial paper 587 677 573 627 Eurorand zero coupon bonds 520 458 520 458 Foreign bonds3 637 2 041 3 637 2 041 Development financing institutions4 777 3 192 4 777 3 192 Export credit facilities1 560 1 345 1 560 1 345 Subordinated loan from shareholder1 208 2 228 1 208 2 228 Other loans 745 372 850 454 Derivatives held for risk management3 151 2 496 3 151 2 496 Employee benefit obligations281 158 1 060 1 130 1 034 Provisions292 588 2 877 2 583 2 875 Finance lease payables 387 87 406 107 Trade and other payables 266 275 266 275 Gross finance cost30 792 26 494 30 869 26 518 Capitalised to property, plant and equipment8(19 426)(17 389)(19 426)(17 389) 11 366 9 105 11 443 9 129 GroupCompany MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 Operating expenses Annexure 6: OPEX note 38 extract from AFS March 2016, page 86 ` 2016201520162015 NoteRmRmRmRm 35.Employee benefit expense Salaries20 092 18 681 18 517 17 446 Overtime1 970 1 682 1 657 1 446 Post-employment medical benefits 583 473 573 465 Leave 675 767 635 714 Annual and performance bonus2 140 1 383 2 133 1 256 Pension benefits2 089 1 976 1 943 1 845 Direct costs of employment27 549 24 962 25 458 23 172 Direct training and development 147 197 117 176 Temporary and contract staff costs3 124 2 743 843 883 Other staff costs1 703 1 016 1 569 962 Gross employee benefit expense32 523 28 918 27 987 25 193 (3 266)(3 006)(3 266)(3 006) 29 257 25 912 24 721 22 187 GroupCompany Capitalised to property, plant and equipment Notes to the financial statements (continued) for the year ended 31 M arch 2016 2016201520162015 NoteRmRmRmRm 36.Net impairment loss Impairment1 644 3 905 1 623 3 882 Property, plant and equipment8 789 1 157 789 1 156 Inventories 11 5 11 5 Loans receivable15 14 15 - - Trade and other receivables19 830 2 728 823 2 721 Reversal( 469)( 132)( 459)( 120) Property, plant and equipment8( 2)( 7)( 2)( 7) Inventories- ( 21)- ( 14) Loans receivable15( 3)( 1)- - Trade and other receivables19( 464)( 103)( 457)( 99) Bad debts recovered( 5)( 7)( 5)( 7) 1 170 3 766 1 159 3 755 GroupCompany Notes to the financial statements (continued) for the year ended 31 M arch 2016 2016201520162015 NoteRmRmRmRm 37.Other expenses Managerial, technical and other fees 563 715 505 678 Direct research and development 38 35 38 35 Operating lease expense1 117 1 397 412 753 Auditors' remuneration 1 94 97 80 84 Net loss on disposal of property, plant and equipment 358 111 494 103 Government grant- - - - Income( 23)( 209)( 23)( 209) Expenses incurred 23 209 23 209 Repairs and maintenance, transport and other expenses16 493 13 416 23 641 20 430 18 663 15 771 25 170 22 083 GroupCompany MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 Annexure 7: Verified EEDSM savings Breakdown of performance of IDM Solution MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 25 Abbreviations BPP Business Productivity Programme Capex Capital Expenditure c/kWh Cent per kilowatt hour COD Commercial Operation Date CoGTA Department of Cooperative Governance and Traditional Affiars COS Cost of Supply CPI Consumer Price Index CSP Concentrated Solar Power DoE Department of Energy DMP Demand Market Participation DPE Department of Public Enterprises DRC Depreciated Replacement Cost Dx Distribution EAF Energy availability factor (see glossary) EBITDA Earnings before interest, taxation, depreciation and amortisation EPP Electricity Pricing Policy ERTSA Eskom’s Retail Tariff Structural Adjustments EUF Energy utilisation factor (see glossary) GDP Gross Domestic Product GW Gigawatt = 1 000 megawatts GWh Gigawatt-hour = 1 000MWh Gx Generation HVAC Heating, Ventilation and Air Conditioning IBT Inclining Block Tariff IDC Interest during construction IDM Integrated demand management MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 IPP Independent power producer (see glossary) IRP 2010 Integrated Resource Plan 2010-2030 KIC Key industrial customers kt Kiloton = 1 000 tons Km Kilometer kV Kilovolt kWh Kilowatt-hour = 1 000 watt-hours (see glossary) L/USO Litres per unit sent out M&V Measurement and Verification Ml Megalitre = 1 m litres MKI Medupi, Kusile and Ingula Mt M tons MTPPP Medium Term Power Purchase Programme MVA Megavolt-ampere MW Megawatt = 1 m watts MWh Megawatt-hour = 1 000kWh MYPD Multi-Year Price Determination NERSA National Energy Regulator of South Africa O&M Operations and Maintenance OCGT Open-Cycle Gas Turbine (see glossary) OCLF Other Capability Loss Factor ODC Owner’s Development Cost Opex Operating Expenditure PE Primary Energy PPA Power Purchase Agreement PPI Producer Price Index PCLF Planned Capability Loss Factor PAJA Promotion of Administrative Justice Act, 2000 PFMA Public Finance Management Act, 1999 R&D Research and Development MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 R/kVA Rand per kilovolt ampere R/kWh Rand per kilowatt hour R/MW Rand per Megawatt R/MWh Rane per Megawatt hour R’m Rand million RAB Regulatory Asset Base RCA Regulatory Clearing Account RCN Replacement Cost New RTS Return-to-Service SADC Southern African Development Community SAIDI System average interruption duration index SAIFI System average interruption frequency index SBP Single Buyer Procurement SM System Minutes SQI Service Quality Incentive STPPP Short Term Power Purchase Programme SWH Solar Water Heaters TOU Time-of-Use Tx Transmission UAGS Unplanned automatic grid separations UCLF Unplanned Capability Loss Factor (see glossary) UOS Use-of-System WACC Weighted Average Cost of Capital WUC Work Under Construction MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 26 Glossary and Terms 49M The 49M initiative aims to inspire and rally all South Africans behind a common goal: to save electricity and create a better economic, social and environmental future for all Base-load plant Largely coal-fired and nuclear power stations, designed to operate continuously Cost of electricity (excluding depreciation) Electricity-related costs (primary energy costs, employee benefit costs plus impairment loss and other operating expenses) divided by total electricity sales in GWh multiplied by 1 000 Daily peak Maximum amount of energy demanded by consumers in one day Debt/equity including long-term provisions Net financial assets and liabilities plus non-current retirement benefit obligations and non-current provisions divided by total equity Debt service cover ratio Cash generated from operations divided by (net interest paid from financing activities plus debt securities and borrowings repaid) Decommission To remove a facility (e.g. reactor) from service and store it safely Demand side management Planning, implementing and monitoring activities to encourage consumers to use electricity more efficiently, including both the timing and level of demand Electricity EBITDA margin Electricity revenue (excluding electricity revenue not recognised due to uncollectability) as a percentage of EBITDA Electricity operating costs per kWh Electricity-related costs (primary energy costs, employee benefit costs, depreciation and amortisation plus impairment loss and other operating expenses) divided by total electricity sales in kWh multiplied by 100 Electricity revenue per kWh Electricity revenue (including electricity revenue not recognised tue to uncollectability) divided by total kWh sales multiplied by 100 MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 Embedded derivative Financial instrument that causes cash flows that would otherwise be required by modifying a contract according to a specified variable such as currency Energy availability factor (EAF) Measure of power station availability, taking account of energy losses not under the control of plant management and internal non-engineering constraints Energy efficiency Programmes to reduce energy used by specific end-use devices and systems, typically without affecting services provided Energy utilisation factor (EUF) Utilisation of the available plant Forced outage Shutdown of a generating unit, transmission line or other facility for emergency reasons or a condition in which generating equipment is unavailable for load due to unanticipated breakdown Free basic electricity Amount of electricity deemed sufficient to provide basic electricity services to a poor household (50kWh/month) Free funds from operations Cash generated from operations adjusted for working capital Gross debt Debt securities and borrowings plus finance lease liabilities plus the after-tax effect of provisions and employee benefit obligations Gross debt/EBITDA ratio Gross debt divided by earnings before interest, taxation, depreciation and amortisation Independent non-executive director Someone who is: Not a full-time salaried employee of the company or its subsidiary Not a shareholder representative Has not been employed by the company and is not a member of the immediate family of an individual who is, or has been in any of the past three financial years, employed by the company in any executive capacity Not a professional advisor to the company Not a significant supplier or customer of the company MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 Independent power producer (IPP) Any entity, other than Eskom, that owns or operates, in whole or in part, one or more independent power generation facilities Interest cover EBIT divided by (gross finance cost less gross finance income) Kilowatt-hour (kWh) Basic unit of electric energy equal to one kilowatt of power supplied to or taken from an electric circuit steadily for one hour Load Amount of electric power delivered or required on a system at any specific point Load curtailment Typically larger industrial customers reduce their demand by a specified percentage for the duration of a power system emergency. Due to the nature of their business, these customers require two hours’ notification before they can reduce demand Load management Activities to influence the level and shape of demand for electricity so that demand conforms to the present supply situation, long-term objectives and constraints Load shedding Scheduled and controlled power cuts that rotate available capacity between all customers when demand is greater than supply in order to avoid blackouts. Distribution or municipal control rooms open breakers and interrupt load according to predefined schedules Lost-time injury (LTI) A work injury, including any occupational disease/illness or fatality, which arises out of and in the course of employment and which renders the injured employee or contractor unable to perform his/her regular/normal work on one or more full calendar days or shifts other than the day or shift on which the injury occurred Lost-time injury rate (LTIR) Proportional representation of the occurrence of lost-time injuries over 12 months per 200 000 working hours Maximum demand Highest demand of load within a specified period Off-peak Period of relatively low system demand MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 Open-cycle gas turbine (OCGT) Liquid fuel turbine power station that forms part of peak-load plant and runs on kerosene or diesel. Designed to operate in periods of peak demand Outage Period in which a generating unit, transmission line, or other facility is out of service Peak demand Maximum power used in a given period, traditionally between 06:00–10:00, as well as 18:00–22:00 in summer or 17:00- 21:00 in winter Peaking capacity Generating equipment normally operated only during hours of highest daily, weekly or seasonal loads Peak-load plant Gas turbines, hydroelectric or a pumped storage scheme used during periods of peak demand Primary energy Energy in natural resources, e.g. coal, liquid fuels, sunlight, wind, uranium and water Pumped storage scheme A lower and an upper reservoir with a power station/pumping plant between the two. During off-peak periods the reversible pumps/turbines use electricity to pump water from the lower to the upper reservoir. During periods of peak demand, water runs back into the lower reservoir through the turbines, generating electricity Reserve margin Difference between net system capability and the system’s maximum load requirements (peak load or peak demand) Return on assets EBIT divided by the regulated asset base, which is the sum of property, plant and equipment, trade and other receivables, inventory and future fuel, less trade and other payables and deferred income System minutes Global benchmark for measuring the severity of interruptions to customers. One system minute is equivalent to the loss of the entire system for one minute at annual peak. A major incident is an interruption with a severity ≥ 1 system minute Technical losses Naturally occurring losses that depend on the power systems used Unit capability factor (UCF) Measure of availability of a generating unit, indicating how well it is operated and maintained MYPD3 2015/16 RCA Submission to NERSA 15 July 2016 Unplanned capability loss factor (UCLF) Energy losses due to outages are considered unplanned when a power station unit has to be taken out of service and it is not scheduled at least four weeks in advance Used nuclear fuel Nuclear fuel irradiated in and permanently removed from a nuclear reactor. Used nuclear fuel is stored on-site in used fuel pools or storage casks Watt The watt is the International System of Units' (SI) standard unit of power. It specifies the rate at which electrical energy is dissipated (energy per unit of time) Working capital ratio (Inventory plus the current portion of payments made in advance, trade and other receivables and taxation assets) divided by (the current portion of trade and other payables, payments received in advance, provisions, employee benefit obligations and taxation liabilities) --- Document Separator --- FY2016/17 July 2017 MYPD 3: Regulatory Clearing Account Submission to NERSA List of Tables Eskom Holdings RCA Submission FY 2016/17 Page: 2 Contents List of Tables ............................................................................................................................................. 6 List of Figures ........................................................................................................................................... 8 Preface ....................................................................................................................................................... 9 1.1 The basis of submissions ............................................................................................................. 9 1.2 The structure of 2016/17 RCA Submission ............................................................................... 10 2 Objective ....................................................................................................................................... 12 3 Overview of the 2016/17 RCA Submission ................................................................................ 13 3.1 Revenue ........................................................................................................................................ 14 3.2 Primary energy ............................................................................................................................. 14 3.3 Environmental levy ...................................................................................................................... 14 3.4 Phased nuclear decommissioning provision per MYPD3 RCA 2013/14 decision ................. 14 3.5 Capital expenditure variance ...................................................................................................... 14 3.6 Operating costs ............................................................................................................................ 15 3.7 Energy Effiiciency and Demand Side Management (EEDSM) ................................................. 15 3.8 Other income ................................................................................................................................ 15 3.9 Inflation adjustments ................................................................................................................... 15 3.10 Service Quality Incentives (SQI) ............................................................................................. 16 3.11 Trend analysis of MYPD3 RCAs .............................................................................................. 16 3.12 Conclusion ................................................................................................................................ 16 4 Factors impacting 2016/17 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 ............................................................... 24 5.5 Allowed vs Actuals volumes ....................................................................................................... 25 5.6 Sales volume variance explanation ............................................................................................ 26 5.6.1 The process in deriving the 5 year forecast ........................................................................ 26 5.6.2 Critical changes in assumptions relevant during 2011 in deriving forecasts ...................... 26 5.6.3 Sales volume variance explanation for FY2017 .................................................................. 27 5.7 Conclusion on the sales volume and revenue variance .......................................................... 33 6 Impact of demand responses on sales volumes ...................................................................... 34 7 Collectability of revenue does not impact RCA ........................................................................ 35 8 Prudency and Efficiency ............................................................................................................. 36 9 Factors which influence Eskom production plans ................................................................... 37 List of Tables Eskom Holdings RCA Submission FY 2016/17 Page: 3 10 Primary energy ............................................................................................................................. 38 10.1 Primary energy variances and RCA impact for 2016/17 ....................................................... 38 10.2 Independent Power Producers ................................................................................................ 40 10.2.1 Medium-term Power Purchase Programme (MTPPP) ........................................................ 40 10.2.2 Municipal Base-load Purchases .......................................................................................... 40 10.2.3 Short-term Power Purchases Programme (STPPP) ........................................................... 40 10.2.4 Wholesale Electricity Pricing System (WEPs) programme ................................................. 40 10.2.5 Long-term IPP programmes ................................................................................................ 41 10.2.6 IPP open cycle gas turbine (“Peaker”) programme ............................................................. 41 10.2.7 Renewable Energy Independent Power Producer (RE-IPP) procurement programme ...... 41 10.3 Legal basis for IPPs per the MYPD Methodology ................................................................. 42 10.4 IPP Approvals ........................................................................................................................... 43 10.5 Regulatory rules for power purchase cost recovery ............................................................ 43 10.6 Allowed vs Actual IPP costs for 2016/17 ................................................................................ 43 10.6.1 Reasons for IPP variances in 2016/17 ................................................................................ 44 11 International purchases ............................................................................................................... 47 11.1 Cross-border sales and purchases of electricity .................................................................. 47 12 Coal Burn Costs ........................................................................................................................... 48 12.1 Extract of MYPD Methodology on Coal adjustments ............................................................ 48 12.2 NERSA’s decision on coal benchmark and alpha ................................................................. 49 12.3 Coal cost – RCA 2017 calculation ........................................................................................... 49 12.3.1 Step 1 – Calculate the performance base regulation cost allowance ................................. 49 12.3.2 Step 2 – Calculate the pass through coal burn costs .......................................................... 50 12.3.3 Step 3 – Split the pass through coal burn cost into volume variance and price variance summarised below. ............................................................................................................................ 50 12.4 Coal burn cost variance explanations .................................................................................... 52 12.5 Coal purchases ......................................................................................................................... 52 12.5.1 Long term fixed price contracts ........................................................................................... 53 12.5.2 Cost plus contracts .............................................................................................................. 53 12.6 Mode of Transport .................................................................................................................... 54 12.7 Medupi Take or Pay payment .................................................................................................. 54 12.8 Kusile Risk Sharing Agreement .............................................................................................. 54 13 Other Primary energy................................................................................................................... 56 13.1 Allowed other primary energy in 2016/17 .............................................................................. 56 13.1.1 Allowed other primary energy costs .................................................................................... 56 13.1.2 Allowed vs Actual other primary energy .............................................................................. 56 13.1.3 Reasons for start-up gas and oil costs variance ................................................................. 57 13.1.4 Reasons for coal handling costs variance ........................................................................... 58 13.1.5 Reasons for water costs variance ....................................................................................... 58 13.1.6 Reasons for fuel procurement costs variance ..................................................................... 58 13.1.7 Water treatment costs variance ........................................................................................... 58 13.1.8 Nuclear costs variance ........................................................................................................ 58 13.1.9 Sorbent costs variance ........................................................................................................ 60 14 Environmental levy ...................................................................................................................... 61 15 Demand Market Participation ...................................................................................................... 62 15.1 Allowed DMP ............................................................................................................................. 62 15.1.1 Actual DMP .......................................................................................................................... 62 16 Open cycle gas turbines (OCGTs) .............................................................................................. 64 List of Tables Eskom Holdings RCA Submission FY 2016/17 Page: 4 16.1 Allowed OCGT spend ............................................................................................................... 64 16.1.1 Managing supply-and –demand constraints ....................................................................... 65 16.1.2 Actual Plant performance in 2016/17 .................................................................................. 66 17 Capital expenditure clearing account (CECA) .......................................................................... 68 17.1 Regulated asset base adjustment for CECA ......................................................................... 68 17.1.1 Step 1: Computing the qualifying RAB capital expenditure variance .................................. 68 17.1.2 Step 2: Computing the CECA .............................................................................................. 69 17.2 MYPD3 decision ........................................................................................................................ 70 17.3 Reasons for new build higher expenditures .......................................................................... 71 17.3.1 Medupi: ................................................................................................................................ 71 17.3.2 Kusile: .................................................................................................................................. 72 17.3.3 Ingula: .................................................................................................................................. 72 17.4 Actual Capital Expenditure ...................................................................................................... 73 18 Inflation adjustment ..................................................................................................................... 74 19 Energy efficiency and demand side management (EEDSM) ................................................... 75 19.1 Actual EEDSM ........................................................................................................................... 75 19.2 The Residential mass roll-out programme ............................................................................ 75 19.3 Other Energy-efficiency measures ......................................................................................... 76 19.4 Extracts from the MYPD Methodology ................................................................................... 77 19.4.1 Allowed EEDSM for 2016/17 ............................................................................................... 77 20 Operating costs ............................................................................................................................ 79 20.1 Allowed operating costs in 2016/17 ........................................................................................ 79 Note1: Allowed employee benefits .................................................................................................... 79 20.2 Allowed vs Actual operating costs ......................................................................................... 81 20.3 Variances in operating costs ................................................................................................... 82 20.3.1 Employee benefits ............................................................................................................... 82 20.3.2 Maintenance ........................................................................................................................ 82 20.3.3 Arrear debt ........................................................................................................................... 83 20.4 Other Income ............................................................................................................................. 83 20.4.1 Actual other income in 2016/17 ........................................................................................... 83 20.4.2 Principles for treatment of other income in the RCA ........................................................... 83 20.5 Based on the precedent above, other income does not qualify for inclusion in the RCA. Operating cost variance for 2016/17 RCA................................................................................... 84 21 Service Quality Incentives ........................................................................................................... 85 21.1 Transmission service quality incentives (SQI) for 2016/17 .................................................. 85 21.2 Distribution Service Quality Incentive Scheme (SQI) for 2016/17 ....................................... 87 22 Reasonability tests....................................................................................................................... 89 22.1 EBITDA-To-Interest Cover Ratio (EBITDA / Interest Payments) .......................................... 89 23 Conclusion .................................................................................................................................... 90 Annexures:............................................................................................................................................... 91 Annexure 1: Income Statement in AFS 2017, page 15 ........................................................................ 91 Annexure 2: The Eskom energy wheel (Eskom Fact sheet 2017) ...................................................... 92 Annexure 3: Sales volumes GWh – Statistical tables for 2016/17 ..................................................... 93 Annexure 4: Finance income note 40 and Finance cost note 41 (Extracts AFS March 2017, page 86-87) .............................................................................................................................................. 95 List of Tables Eskom Holdings RCA Submission FY 2016/17 Page: 5 Annexure 5: OPEX note 38 extract from AFS March 2016, page 86 .................................................. 96 1 Abbreviations ............................................................................................................................... 97 2 Glossary and Terms ..................................................................................................................... 99 List of Tables Eskom Holdings RCA Submission FY 2016/17 Page: 6 List of Tables Table 1: Summary of 2016/17 RCA Submission ................................................................................ 13 Table 2: RCA Trend Analysis over the MYPD3 .................................................................................. 16 Table 3: Key assumptions which have changed ................................................................................. 19 Table 4 : Calculation of MYPD3 revenue variance for 2016/17 .......................................................... 20 Table 5 : Reconciliation of AFS revenue to RCA revenue .................................................................. 21 Table 6: Revenue note from AFS for March 2017 ............................................................................. 21 Table 7: Allowed revenue .................................................................................................................... 23 Table 8 : Sales volume variance ......................................................................................................... 25 Table 9: Approved Sales Volumes forecast, mypd3 ........................................................................... 25 Table 10: MYPD3 Sales volume ......................................................................................................... 26 Table 11 : GDP forecasts used for MYPD3 in 2011 ........................................................................... 26 Table 12: Commodity Prices assumed ............................................................................................... 27 Table 13 : Sales volume variance ....................................................................................................... 28 Table 14 : Commodity prices .............................................................................................................. 31 Table 15 : Total primary energy comparison and RCA impact for 2016/17 ........................................ 39 Table 16: Primary energy actual costs per note 34 in the AFS of 2017 ............................................. 39 Table 17: Renewable IPP Agreements ............................................................................................... 41 Table 18: IPP operational capacities by type and location at 31 March 2017 .................................... 42 Table 19: IPPs costs and volumes ..................................................................................................... 44 Table 20: International purchases ....................................................................................................... 47 Table 21 : Cross border sales and purchases .................................................................................... 47 Table 22: NERSA’s decision on coal benchmark and alpha .............................................................. 49 Table 23: Working Coal Mechanism ................................................................................................... 50 Table 24: The coal burn breakdown for the RCA................................................................................ 51 Table 25: MYPD 3 Assumptions vs. Actual 2016/17 .......................................................................... 52 Table 26: Securing our coal requirements .......................................................................................... 55 Table 27: Other Primary Energy ......................................................................................................... 57 Table 28: Approved Demand Response (DR) Expenditure for MYPD3 ............................................. 62 Table 29: DMP comparison for RCA ................................................................................................... 62 Table 30: OCGT .................................................................................................................................. 64 Table 31: Calculation average capital expenditure ............................................................................. 69 Table 32: CECA Calculation: Return due to/ (by) Eskom ................................................................... 70 Table 33 : Regulatory asset base for 2016/17 .................................................................................... 70 Table 34: Returns and percentage allowed in 2016/17 ..................................................................... 70 Table 35: Capital expenditure in 2016/17 .......................................................................................... 71 Table 36: Reconciliation of capex from the integrated report to CECA disclosures ........................... 73 Table 37: Capital expenditure (excluding capitalised borrowing costs) per division........................... 73 List of Tables Eskom Holdings RCA Submission FY 2016/17 Page: 7 Table 38: Inflation Data ....................................................................................................................... 74 Table 39 : Inflation adjustment ............................................................................................................ 74 Table 40: Demand management costs ............................................................................................... 76 Table 41: Actual savings (not verified) and internal energy efficiency savings .................................. 76 Table 42: Reconciliation between demand savings MWs used in RCA Calculation .......................... 77 Table 43: The allowed EEDSM costs ................................................................................................. 78 Table 44: EEDSM comparison for RCA in 2016/17 ............................................................................ 78 Table 45: Total Operating Cost Allowed ............................................................................................. 79 Table 46: Employee benefits are reconciled as follows ...................................................................... 79 Table 47: The allowed employee costs for Generation, Transmission and Distribution ..................... 80 Table 48: Allowed Corporate Costs in 2016/17 .................................................................................. 80 Table 49: The depreciation per annum is reflected in the table below. .............................................. 80 Table 50: Allowed Maintenance Costs ................................................................................................ 81 Table 51: Other costs .......................................................................................................................... 81 Table 52: Allowed Arrear Debts .......................................................................................................... 81 Table 53: Allowed Cost of Cover ........................................................................................................ 81 Table 54: Summary of Operating costs in 2016/17 ............................................................................ 82 Table 55: Trend in gross employee benefits ....................................................................................... 82 Table 56 : Other income for 2016/17 .................................................................................................. 83 Table 57 : Trends in networks performance ....................................................................................... 85 Table 58 : Summary of SQI performance in 2016/17 ......................................................................... 85 Table 59: Transmission SQI performance in 2016/17 ........................................................................ 86 Table 60: Transmission number of major incidents (>1SM) ............................................................... 86 Table 61: Distribution SQI performance in 2016/17 ............................................................................ 88 Table 62: EBITDA Cover ..................................................................................................................... 89 List of Figures Eskom Holdings RCA Submission FY 2016/17 Page: 8 List of Figures Figure 1: Waterfall Chart of RCA 2016/17 .......................................................................................... 17 Figure 2: Time lag between application and actuals ........................................................................... 18 Figure 3 : Performance of Re-distributors ........................................................................................... 29 Figure 4 : Performance of Ferro and Steel ......................................................................................... 32 Figure 5: Production FY 2017 ............................................................................................................. 37 Figure 6 : Generation technical performance...................................................................................... 67 Figure 7: Transmission system minutes (<1) ...................................................................................... 86 Figure 8 : Line faults /100km ............................................................................................................... 87 Figure 9 : EBITDA-To-Interest Cover Ratio ........................................................................................ 89 Preface Eskom Holdings RCA Submission FY 2016/17 Page: 9 Preface This document summarises information submitted by Eskom Holdings (SOC) Ltd to the National Energy Regulator of South Africa (hereafter referred to as NERSA, or the Energy Regulator) pertaining to the Eskom’s Regulatory Clearing Account (RCA) balance for the year 2016/17 and in accordance with the Multi-Year Price Determination Methodology published during December 2012 (hereafter referred to as the ‘MYPD Methodology’) 1 . This document contains the following: 1. Information provided in regard to Eskom’s 2016/17 RCA balance (hereafter referred to as the ‘2016/17 RCA Submission’ or year 4 of MYPD3) is lodged in accordance with section 14.2.1 of the MYPD Methodology. 2. Information is supported by Eskom’s 2016/17 audited annual financial statements 3. Information is supported by NERSA’s RCA 2013/14 reasons for decision published on 29 March 2016 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. 1 See in particular sections 14.0, 8.0 and 9.0 of the Multi-Year Price Determination Methodology 1 st Edition, published December 2012 Preface Eskom Holdings RCA Submission FY 2016/17 Page: 10 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 2016/17 RCA Submission The structure of the summary of 2016/17 RCA Submission provided in this document is guided by the MYPD Methodology. With this in mind, an overview of the 2016/17 RCA submission is first provided summarizing 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) VIII. Primary Energy - Gas Turbine Generation Cost (Section 16) VII. Primary Energy – Other costs (Section 13) IX. Capital Expenditure and Regulatory Asset Base (Section 17) X. Operating Costs (Section 20) XI. Service Quality Incentives (Section 21) Preface Eskom Holdings RCA Submission FY 2016/17 Page: 11 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 2016/17 RCA Submission concludes with reasonableness tests such as EBITDA to interest cover ratio being assessed. Objective Eskom Holdings RCA Submission FY 2016/17 Page: 12 2 Objective The objective of this 2016/17 RCA Submission is to provide the context for the Regulatory Clearing Account (RCA) process in terms of NERSA’s MYPD Methodology requirements. The 2016/17 RCA Submission for the fourth 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 decision made by NERSA on 1 March 2016 and the reasons for decision published on 29 March 2016. 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 costs that are subject to re-measurement as outlined in the MYPD Methodology. Overview of the 2016/17 RCA Submission Eskom Holdings RCA Submission FY 2016/17 Page: 13 3 Overview of the 2016/17 RCA Submission Eskom’s 2016/17 RCA Submission is driven substantially by revenue under-recovery and higher primary energy costs to meet demand, whilst operating in an electricity system. The determined RCA balance of R23 786 million is motivated with evidence for prudent scrutiny by NERSA. This submission is increased by R83 million relating to the phasing in of the nuclear decommissioning provision from the 2013/14 RCA decision resulting in a total RCA balance of R23 869 million. TABLE 1: SUMMARY OF 2016/17 RCA SUBMISSION RCA for 2016/17 (Year 4 of MYPD3) MYPD3 Decision Actuals 2016/17 Variance to MYPD3 RCA adjustments RCA 2016/17 Total Revenue R million 198 035 175 094 -22 941 2 925 20 016 Primary Energy , R million Coal 44 245 44 652 407 -766 -359 Open Cycle Gas Turbines (OCGTs) 1 599 340 -1 259 - -1 259 Other primary energy 6 327 7 049 722 722 Independent Power Producers 19 269 21 721 2 452 2 452 International Purchases 399 2 681 2 282 2 282 Environmental levy 9 490 8 086 -1 404 -1 404 Demand Market Participation (DMP) - 194 194 194 Total primary energy , R million 81 329 84 723 3 394 -766 2 628 CECA for RCA , R million 46 655 58 924 12 269 636 636 EEDSM for RCA , R million 712 376 -336 336 - Operating costs for RCA , R million 45 896 61 211 15 315 - - SQI for RCA , R million - 343 343 Inflation adjustments , R million - 162 162 FY2017 RCA 23785 Nuclear decommissioning from RCA 2013/14 decision phased in over 10 years - - - 83 83 Total RCA balance , R million 23 868 Note 1: Operating costs over expenditure are not allowed to be claimed as part of the RCA in terms of current MYPD Methodology Overview of the 2016/17 RCA Submission Eskom Holdings RCA Submission FY 2016/17 Page: 14 3.1 Revenue The revenue variance of R20 016 million which is calculated on Eskom’s electricity revenue to all customers is due to lower electricity sales volumes. No load interruptions occurred in during 2016/17. 3.2 Primary energy During the year, the introduction of new generation capacity, the improvement in power stations availability and higher IPPs has contributed to Eskom meeting demand requirements. This resulted is minimal utilization of OCGTs resulting in lower spend when compared to the MYPD3 decision. Total primary costs incurred in 2016/17 was R84 723 million which exceeded the MYPD3 decision of R81 329 million by R3 394 million. This application provides for claw backs of coal (R359m) and OCGTs (R1259m). Eskom is claiming the extra spend of IPPs (R2452m), international purchases (R2282m), other primary energy (R722m) and DMP (R194m). 3.3 Environmental levy The lower production volumes and the change in production mix resulted in Eskom incurring environmental levy costs of R1 404 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. 3.4 Phased nuclear decommissioning provision per MYPD3 RCA 2013/14 decision In its 2013/14 RCA decision, NERSA has allowed Eskom to claim 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. Thus this application represents another installment. 3.5 Capital expenditure variance Eskom Company capital expenditure of R58 924 million exceeded the NERSA decision of R46 655million by R12 269 million in 2016/17. 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 Overview of the 2016/17 RCA Submission Eskom Holdings RCA Submission FY 2016/17 Page: 15 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 R636 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 2016/17 the operating costs expenditure of R61 211 million exceeds the decision of R45 896 million by R15 315 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 R162 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 more verified capacity (in MW) savings during the year resulting in a R336 million claim in Eskom’s favour. However, the MYPD Methodology does not allow for symmetrical treatment of EEDSM performance. Therefore this RCA reflects a zero impact relating to EEDSM. 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 R162 million in favour of Eskom. Overview of the 2016/17 RCA Submission Eskom Holdings RCA Submission FY 2016/17 Page: 16 3.10 Service Quality Incentives (SQI) Eskom has achieved the service quality incentive targets set by NERSA for Distribution and Transmission during 2016/17. This resulted in Distribution achieving an SQI of R263 million and Transmission of R80 million, equating to a total of R343 million. 3.11 Trend analysis of MYPD3 RCAs The value of RCA submissions over the MYPD3 period is been consistently about R23 billion per annum as summarized in the table below. TABLE 2: RCA TREND ANALYSIS OVER THE MYPD3 MYPD3 RCA Trends Decision RCA 2013/14 Application RCA 2014/15 Application RCA 2015/16 Application RCA 2016/17 Revenue 6 175 8 787 15 578 20 016 Independent Power Producers 580 4 346 620 2 452 International purchases 2 700 3 299 3 567 2 282 Coal 2 000 574 3 258 -359 Open Cycle Gas Turbines (OCGTs) 1 252 1 944 689 -1 259 Other primary energy 72 1 355 728 722 Environmental levy -312 -683 -1 180 -1 404 Nuclear decommissioning of R830m from RCA 2013/14 decision phased in over 10 years 83 83 83 83 Nuclear decommissioning R361m from RCA 2015/16 decision phased in over 8 years - - 45 - Energy Efficiency & Demand Side Management (EEDSM) -432 -149 -368 - Demand Market Participation (DMP) -905 -379 248 194 Capital Expenditure Clearing Account (CECA) 9 91 332 636 Service Quality Incentives (SQI) 339 236 318 343 Inflation adjustment - Opex 33 209 -152 162 Other income -353 -528 -134 - RCA balance R'millions 11 241 19 185 23 633 23 868 3.12 Conclusion In this submission Eskom is paying back R3 022 million comprising of coal burn (R359m), OCGTs (R1259m) and environmental levy (R1404m). Eskom is claiming costs of R6 874m consisting of other primary energy (R722m), DMP (R194 million), IPPs (R2452m), international purchases (R2282m) and other components (R1224m). Thus the Overview of the 2016/17 RCA Submission Eskom Holdings RCA Submission FY 2016/17 Page: 17 net cost of R3 852 million is being claimed with the balance attributable to the revenue under recovery of R20 016 million linked to lower sales volumes. The RCA 2016/17 submission of R23 868 million excludes operating costs of R15 315 million which exceeded the MYPD3 decision. FIGURE 1: WATERFALL CHART OF RCA 2016/17 Finally the RCA 2016/17 submission of R23 868 million excludes operating costs of R15 315 million which exceeded the MYPD3 decision. R23868m IPPs Other Primary Energy International Purchases R DMPCECA RCA Submission 2016/17 Cost claimed Rand millions R R2452m R2282m R722m R194m -R1404m Summary of RCA 2016/17 R636m SQI R343m Inflation Opex R162m R83m R3852m Nuclear Decomm OCGTs Environ levy Coal Net Cost claimed -R1259m -R359m Revenue under recovery R20016m R6874m -R3022m Factors impacting 2016/17 RCA Submission Eskom Holdings RCA Submission FY 2016/17 Page: 18 4 Factors impacting 2016/17 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 2: 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-13Apr-14Apr-15Apr-16Apr-17Apr-18 5 Year MYPD3 Window Factors impacting 2016/17 RCA Submission Eskom Holdings RCA Submission FY 2016/17 Page: 19 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 239 TWh by March 2016. Sales growth averaged a reduction of 0.9% from a starting value of 216.5TWh in March 2013 to 214.1 TWh in March 2017 Sales forecast did not materialise due to major changes in the assumptions plus the adverse global economic situation not recovering as anticipated Generation plant performance (Energy availability factor – EAF) assumed at an average 82% for 2016/17. Actual average EAF was 77% with a peak of 81% and low of 74% during the year. Actual plant performance improved significantly over this period compared to FY2016. New build commission dates for 1 st units Medupi – June 2013 Kusile - 2016/17 Ingula – 2013/14 Sere – 2013/14 New build commissioning revised dates as follows: Medupi Unit6 – Aug 2015 Medupi Unit5 – Apr 2017 Kusile Unit 1- Sept 2017 Ingula – All units commissioned by Mar 2017 Sere – 31 Mar 2015 Over the past 18 months, Eskom has been meeting its revised commissioning dates. Coal country compact < 10%price increases Efficiency savings implemented through business productivity programme and design to cost initiatives. Coal burn escalations dropped significantly in 2016/17 compared to historical trends. In fact coal burn variance is clawed back in favour of the consumer. OCGTs – load factors assumed at 3% based on certain other assumptions materialising OCGTs – actual load factors have been <1% in 2016/17 OCGTs usage reflects a successful turnaround with a significant under spend being clawed back in this submission. IPPs – local and international Increase in non-renewable IPP programs to contribute to balancing supply and demand. At the time of the MYPD 3 application, non-renewable IPPs usage was not anticipated. Capex – R337bn over the five year period Capex – given the lower revenue decision, Eskom reprioritized capex to a projected portfolio of R251bn over the five year period. In response to MYPD3 revenue decision Eskom has reprioritised capex spent which resulted in movements of expenditures between licensees. Staff costs – complement of 43 000 growing to 46 000 Revised staff outlook decreasing staff complement to 41 238 by FY 2018 Business Productivity Program (BPP) savings initiative launched in the business reflects cumulative savings of R49 billion at 31 March 2017. Maintenance More maintenance was undertaken than initially envisaged Better maintenance planning is reaping the rewards in terms of plant performance Other Opex Roll out of BPP saving plan and design to cost initiatives Despite cost efficiency and saving programme other operating cost exceeded the decision Revenue Variance Eskom Holdings RCA Submission FY 2016/17 Page: 20 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 2016/17 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. 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 special pricing agreements and exports (international) customers. Non-electricity is made up of deferred income recognized and other revenue. The table below shows the sales volume and revenue variance with the total average price for all customers being marginally higher than the MYPD3 decision by 0.13c/kWh. TABLE 4 : CALCULATION OF MYPD3 REVENUE VARIANCE FOR 2016/17 Revenue variance for 2016/17 MYPD3 Decision RCA actualsVariance Total external electricity revenue (R'm)198 035178 019-20 016 Total external sales volumes (GWh)239 113214 601-24 512 Total average selling price (c/kWh) 82.8282.950.13 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. Revenue Variance Eskom Holdings RCA Submission FY 2016/17 Page: 21 *Note that the total external electricity revenue of R175 094 has been increased by the net revenue impairment adjustment of R2 925m to R178 019m (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 Note 1: Revenue as reported in Eskom’s 2017 AFS: Revenue from continuing operations of R177 136 million, reported on page 84 of Eskom’s 2017 AFS, provides the starting point for obtaining the MYPD equivalent for actual revenue. Actual electricity revenue was R175 094 million; other revenue was R2 042 million (including deferred income of R271 million) for 2016/17. TABLE 6: REVENUE NOTE FROM AFS FOR MARCH 2017 Actual Revenue for RCA calculation in 2016/17 (R'million) Eskom Company Notes Revenue per AFS 177 136 1 Less : Non-electricity revenue -2 042 2 Deferred income recognised - Other revenue -2 042 External electricity revenue 175 094 A dd : IA S 18 unre c o gnis e d re v e nue 2 925 3 Internal electricity revenue - Revenue for RCA purposes (R' million) 178 019 2017201620172016 RmRmRmRm 32.Revenue Electricity175 094 161 688 175 094 161 688 Other2 042 2 551 2 042 2 551 177 136 164 239 177 136 164 239 GroupCompany ElectricityrevenueofR3196million(2016:R1647million)wasnotrecognisedasitwasassessedthatthereisa highprobabilitythattherelatedeconomicbenefitswillnotmaterialise.Inaddition,R271million(2016:R175 million)ofpreviouslynotrecognisedrevenuehasnowbeenrecognisedinthecurrentyear.Eskomcontinuesto actively pursue recovery of these amounts. Refer to note 5.1.2(a). Revenue Variance Eskom Holdings RCA Submission FY 2016/17 Page: 22 Source: Eskom Annual Financial Statements, 31 March 2017, page 84. 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 196 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). In addition, R271m of previously not recognized revenue has now been recognised in the current year. Eskom continues to actively pursue recovery of these amounts. 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 net impact of the IAS adjustment is R2 925 million which is added back to actual revenue for the RCA. Revenue Variance Eskom Holdings RCA Submission FY 2016/17 Page: 23 5.3 Allowed Revenue The allowed revenue of R198 035 million as shown in the table below is derived from the NERSA documentation as shown in the extracts below comprising the MYPD3 revenue determination and the MYPD3 RCA decision. TABLE 7: ALLOWED REVENUE Allowed Revenue R'million 2016/17 Extract Ref MYPD3 Allowed Revenue 186 794 1 MYPD3 RCA 2013/14 decision 11 241 2 Total Revenue 198 035 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) Source: NERSA “MYPD3 ERTSA decision for 2016/17” Extract 2: Source: NERSA “The implementation plan of Eskom MYPD 3 Regulatory Clearing Account (RCA) for 2013/14 Revenue Variance Eskom Holdings RCA Submission FY 2016/17 Page: 24 5.4 Sales volumes contribute to recovery of fixed costs 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 materialising, it results in Eskom not recovering the allowed revenue components as was assumed. 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 Revenue Variance Eskom Holdings RCA Submission FY 2016/17 Page: 25 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. 5.5 Allowed vs Actuals volumes TABLE 8 : SALES VOLUME VARIANCE Actual external electricity sales volumes of 214 121GWh are disclosed in Annexure 3. Note 1: The 239 113 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 093GWh (15 006GWh + 87GWh) which are based on the geographical location in which the sale occurred. For regulation the 87GWh is not shown as International sales as this is sold by Distribution and as such forms part of Distribution sales. TABLE 9: APPROVED SALES VOLUMES FORECAST, MYPD3 Sales volume variance per tariff category (GWh) FY 2017 MYPD3 Decision Actuals Variance NPA Sales11 302 9 750 (1 552) Add: Standard tariff sales including internal sales218 193 189 845 (28 348) Total Distibution sales 229 495 199 595 (29 899) Add: International sales ( see note 2)9 618 15 006 5 387 Total sales to all customers (see note 1)239 113 214 601 (24 512) Less: Internal sales(398) (480) (82) Total external electricity sales238 715 214 121 (24 594) GWh2016/17 Standard tariff sales218 193 Negotiated pricing agreement11 302 Exports9 618 Approved sales forecast239 113 Revenue Variance Eskom Holdings RCA Submission FY 2016/17 Page: 26 Source: Table 54 Approved Sales Volumes Forecast, MYPD3 Decision 5.6 Sales volume variance explanation The MYPD forecast is normally finalized 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 analyzed and a determination is made. In the case of MYPD3, the MYPD forecast was finalized on 14 September 2011 when the prospects for a higher economic growth were still viable as we recovered from the recession in 2007/08. At that time the GDP growth assumptions were still high. The unfavorable variance in sales volumes against the MYPD NERSA decision was offset by the large favorable variance in the prepayment sales and export sales. The table below highlights the difference between MYPD3 forecasts and actual reality that has transpired over the last four years. TABLE 10: MYPD3 SALES VOLUME 5.6.1 The process in deriving the 5 year forecast The 5 year sales forecast used in the application was compiled using a bottom up approach from customer level. Each of the six Eskom Regions forecasted the Regional sales (covering the 9 provinces) using a bottom up approach from customer level for their specific Regions. Each Regional forecast were scrutinized on a one on one basis after which the six Regional 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 Total Eskom Sales (GWh)2012/132013/142014/152015/162016/17 MYPD3 Sales (GWh)222 756 227 403 229 513 235 638 239 113 MYPD3 Sales Growth %-1.10%2.09%0.93%2.67%1.47% Actual Sales (GWh) 217 022 218 368 217 097 215 149 214 601 Actual Sales Growth %-3.66%0.62%-0.58%-0.90%-0.25% GDP growth %201220132014201520162017 MYPD3 GDP growth % 4.0%4.0%4.0%4.5%5.0%5.0% Actual GDP growth % 2.2%2.2%1.5%1.3%0.3% Revenue Variance Eskom Holdings RCA Submission FY 2016/17 Page: 27  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.  Municipality and other STPPP generation assumed for inclusion of Power Purchase Agreements (PPAs) continued up to the end of the 2016/17 financial year; a much longer period than anticipated that has off-set the drop in sales from other sectors.  The 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 Actual FeCr $1.20/lb - $1.32/lb $0.96/lb Aluminum $2 500/ton - $2 750/ton $1 604/ton Platinum $1 480/oz - $2 000/oz $986/oz  High probability new projects were included but were delayed with the downturn of the economy and much lower commodity prices.  Average weather conditions have been used. 5.6.3 Sales volume variance explanation for FY2017 The table below shows the sales volume variance that will provide the reasons for the decrease in sales volumes compared to the decision. Revenue Variance Eskom Holdings RCA Submission FY 2016/17 Page: 28 TABLE 13 : SALES VOLUME VARIANCE From the table above, which reflects the variance between the decision and actual sales for the year 2016/17, it can be seen that the unfavorable variance of 29 899 GWh in respect of distribution sales is mainly due to three categories, namely Re-distributors, Industrial and Mining. The unfavorable variances in these three categories were partially offset by the favorable variance of 5 387 GWh from the international sales and 1 143 GWh from the prepayment environment. 5.6.3.1 Redistributors: 10 510 GWh unfavourable The unfavorable variance in this category is spread over most of the Redistributors are mainly due to the following:  The largest unfavorable impacts are seen in the City Power and Ekurhuleni Metro’s due to the sluggish economic growth. City Power and Ekurhuleni are within the economic hub of South Africa and thus severely affected by the slow local & global economic growth.  In the Southern Region the expectation was that the Coega development project would have started up but due to the absence of “the anchor project”, very little development have materialized up to this point. Sales volume variance per customer category (GWh)Actual SalesMYPD 3Variance International 15 005 9 618 5 387 Distribution sales199 596 229 495 (29 899) IPP Network Charge52 - 52 Re-distributors89 666 100 176 (10 510) Industrial48 295 61 697 (13 402) Mining30 559 37 191 (6 632) Traction2 849 3 133 (284) Residential3 911 4 591 (680) Commercial10 339 9 903 436 Agricultural5 405 5 344 61 Prepayment8 115 6 972 1 143 International A87 90 (3) Internal Sales480 398 82 Other(162) - (162) Total electricity sales volumes214 601 239 113 (24 512) Exclude Internal sales-480 -398 (82) Total external electricity sales volumes214 121 238 715 (24 594) Revenue Variance Eskom Holdings RCA Submission FY 2016/17 Page: 29  Cape Town Municipality introduced a huge savings drive 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 eThekwini Metro, a large customer, Tata Steel closed down. In addition the sluggish economic growth resulted in a substantial decline in sales growth.  In 2016 the abnormal low summer temperatures also reduced the energy consumption.  Due to the Global economy that did not pick up as expected as well as the fluctuation of the ZAR exchange rate, the manufacturing sector behind the bulk meters in the municipalities were not able to secure orders, thus producing less with a resultant drop in energy consumption.  Due to the price increases, price elasticity also played a role resulting in savings from customers, especially in the lower LSM’s.  DSM initiatives also impacted the sales negatively 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 of the MYPD decision. FIGURE 3 : PERFORMANCE OF RE-DISTRIBUTORS 5.6.3.2 Industrial: 13 402 GWh unfavourable. This category was the most severely affected category and it is mainly due to the following: Revenue Variance Eskom Holdings RCA Submission FY 2016/17 Page: 30  The Aluminium sector posted a decline of 1 760 GWh mainly resulting from the closure of the Bayside smelter (1 679 GWh) and the very weak commodity price which forced production cuts due to a drop in world demand for Aluminium.  Sasol Infra Chem commissioned their own gas generation plant and displaced 324 GWh from the “Manufacturing of basic Chemicals” sector.  The Ferro and steel smelting industry realized a drop in consumption against the MYPD NERSA decision of 10 591 GWh due to the low demand for their products as a result of the collapse of commodity prices and cheaper imports from China that led to diminishing orders and downsizing and closure of customers. Refer to the table below on commodity prices.  As a result the smelting industry opted to take furnaces out during the three winter months to save on costs due to the winter price of electricity.  Many customers are downsizing and some considering full closures as a result of a low demand for their product. The combine impact of three customers Highveld steel, IFM and ASA metals is a reduction in demand of 4 271 GWh. - The Titanium sector posted a decline of 1 157 GWh mainly due to the drop in world demand for their product and the resultant very weak commodity price. This caused the partial closure of furnaces at RBM (843 GWh) which forced production cuts at the plant. - The closure of EB Steam customers also affected the sales unfavourably. Revenue Variance Eskom Holdings RCA Submission FY 2016/17 Page: 31 TABLE 14 : COMMODITY PRICES Source: LME, Platts, CRU, Metal Bulletin, Marquarie Research, March 2017 Revenue Variance Eskom Holdings RCA Submission FY 2016/17 Page: 32 FIGURE 4 : PERFORMANCE OF FERRO AND STEEL 5.6.3.3 Mining: 6 632 GWh unfavourable This category was also affected severely and it is mainly due to the Gold and Platinum sectors: Mining production in South Africa slumped year-on-year in 2016, 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 realized a 3 397 GWh drop in consumption against the MYPD NERSA decision mainly due to: - Labour unrests which caused shaft closures. - 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 realized a 2 509 GWh drop in consumption against the forecast due cost pressure as a result of labour unrest and high salary increases. This again caused high cash costs and resulted in down scaling and shaft closures in many of the Gold Revenue Variance Eskom Holdings RCA Submission FY 2016/17 Page: 33 mines. Some Gold mines were liquidated while others closed their shafts. Many shafts were put under care and maintenance due to cost pressures. The unfavourable commodity price also played a major role in escalating the cost pressures. 5.6.3.4 Prepayment: 1 143 GWh favourable In the Prepaid environment a significant favorable variance against the MYPD NERSA decision was realized mostly in the Northern Region due to the changing of the supply group codes that eliminated most of the ghost CDU’s in that Region, resulting in higher Sales volumes than anticipated in the MYPD NERSA decision. 5.6.3.5 International: 5 387 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 drought impacted the Southern African region throughout 2016/17, resulting in reduced available hydroelectric capacity in the DRC, Zambia and Zimbabwe. This provided Eskom with an opportunity to realise additional electricity sales. Non-firm electricity sales were made to ZESCO and the Copper belt Energy Corporation, both of Zambia, and ZESA of Zimbabwe. The lower water levels at the Gove dam also led to reduced generation specifically at Ruacana which resulted in increased sales to NamPower. 5.7 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 R20 016m in 2016/17. Impact of demand responses on sales volumes Eskom Holdings RCA Submission FY 2016/17 Page: 34 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 2016/17. Embedded in Eskom’s MYPD3 application was an assumption for EEDSM which was taken into consideration when determining the sales forecasts. In the 2016/17 year, NERSA assumed 939 GWh of energy savings at a cost of R712 million which culminated in 196 MW of capacity savings. In reality, EEDSM achieved higher verified savings during the year of 290 MW of capacity. However, in terms of the RCA Methodology - EEDSM will incur penalties for under achieving their targets and EEDSM is not compensated for MW savings exceeding MW savings in the decision. In addition, NERSA assumed DMP costs of zero in 2016/17 while actual expenditure was R194 million. Collectability of revenue does not impact RCA Eskom Holdings RCA Submission FY 2016/17 Page: 35 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 uncollectibility is removed as the amount deducted in the annual report under IAS18, R2925 million 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. Prudency and Efficiency Eskom Holdings RCA Submission FY 2016/17 Page: 36 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 Factors which influence Eskom production plans Eskom Holdings RCA Submission FY 2016/17 Page: 37 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 some 25TWh, 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 5: PRODUCTION FY 2017 Primary energy Eskom Holdings RCA Submission FY 2016/17 Page: 38 10 Primary energy Eskom has aligned the treatment of primary energy to the 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 2016/17 Total primary energy allowed for 2016/17 was R81 329 million. Eskom incurred R84 723 million in the year which resulted in an extra cost of R3 394 million. 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 an alpha adjustment 3. Nuclear decommissioning provision: Implementation of the 2013/14 provision of R830 million in ten equal tranches as per the 2013/14 RCA decision. i.e. R83m inclusion in the 2016/17 RCA and 4. IPP’s – In terms of IFRS, a portion of the Dedisa contract is accounted for under “IFRIC 4 Determining whether an arrangement contains a lease”. However for regulatory purposes, an adjustment of R1 964 million is deemed to be accounted for as an IPP purchase. Hence the sum of all these adjustments is R766 million and thereby reduces the total primary energy variance to R2 628 million. Refer table below for the RCA calculation for total primary energy. Primary energy Eskom Holdings RCA Submission FY 2016/17 Page: 39 TABLE 15 : TOTAL PRIMARY ENERGY COMPARISON AND RCA IMPACT FOR 2016/17 Primary Energy , R million MYPD3 Decision Actuals 2016/17 Variance RCA adjustments RCA 2016/17 Coal 44 245 44 652 407 -766 -359 Open Cycle Gas Turbines (OCGTs) 1 599 340 -1 259 -1 259 Independent Power Producers 19 269 21 721 2 452 2 452 International Purchases 399 2 681 2 282 2 282 Environmental levy 9 490 8 086 -1 404 -1 404 Water 2 188 1 751 -437 -437 Start-up gas & oil 1 695 2 227 532 532 Coal handling 1 257 1 758 501 501 Water treatment 298 423 125 125 Nuclear 446 727 281 281 Fuel procurement 304 163 -141 -141 Sorbent usage 139 0 -139 -139 Demand Market Participation - 194 194 194 Primary energy , R million 81 329 84 723 3 394 -766 2 628 Nuclear decommissioning from RCA 2013/14 decision phased in over 10 years 83 83 Total primary energy variance R million 81 329 84 723 3 394 -683 2 711 Source: Allowed total primary energy -table 17, MYPD3 decision; Actuals - Primary energy note 34, AFS, March 2016 Extract from the AFS, March 2017 reflects the actual total primary costs of R82 760m below. TABLE 16: PRIMARY ENERGY ACTUAL COSTS PER NOTE 34 IN THE AFS OF 2017 2017201620172016 RmRmRmRm 34.Primary energy Own generation costs52 042 57 594 52 042 57 594 Environmental levy8 086 8 120 8 086 8 120 International electricity purchases2 681 3 660 2 681 3 660 Independent power producers19 757 15 106 19 757 15 106 Other 194 248 194 248 82 760 84 728 82 760 84 728 GroupCompany Own generation costs relate to the cost of coal, uranium, water and liquid fuels that are used in the generation of electricity. Eskom use a combination of short-, medium- and long-term agreements with suppliers for coal purchases and long-term agreements with the DWA to reimburse the department for the cost incurred in supplying water to Eskom. Primary energy Eskom Holdings RCA Submission FY 2016/17 Page: 40 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 allows for full pass through of IPP expenditure. Therefore the total for IPP’s in the AFS of R19 757 million is increased by R1 964 million resulting in a total for IPP’s of R21 721 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. 10.2.1 Medium-term Power Purchase Programme (MTPPP) Eskom initiated the MTPPP in 2008 in order to procure base-load capacity from private generators. The total capacity procured under the MTPPP amounted to 294 MW (excluding one contract that was awarded but never became operational due to the IPP failure to meet obligations). The 13MW remaining under this programme expired on 31 March 2017. 10.2.2 Municipal Base-load Purchases Eskom’s contract with City Power for 250MW expired on 31 March 2017. On 27 January 2017 the maximum contract value of the City Power contract was reached, with no energy purchases from that date until expiry. 10.2.3 Short-term Power Purchases Programme (STPPP) The capacity constraints also prompted Eskom to launch the STPPP in order to attract additional capacity from private generators on a short-term basis. Short-term contracts with private generators with a combined contracted capacity of 812.3MW. Short-term contracts with private generators with a combined contracted capacity of 557MW expired on 31 March 2017. 10.2.4 Wholesale Electricity Pricing System (WEPs) programme Eskom enters into annual contracts at wholesale prices with co-generators outside the ambit of the MTPPP and short-term contracts. A total of 92MW of capacity has been Primary energy Eskom Holdings RCA Submission FY 2016/17 Page: 41 contracted during the year to March 2017. These contracts expired on 31 March 2017 and were not renewed. 10.2.5 Long-term IPP programmes In the procurement process for DoE’s long-term IPP programmes, Eskom's role is that of network operator, where Eskom owns the network and grid connection infrastructure, as well as the designated purchaser of energy supplied. 10.2.6 IPP open cycle gas turbine (“Peaker”) programme Power purchase agreements of 1 005MW were entered into for the Avon and Dedisa plants. Dedisa was commissioned on 30 September 2015 (335MW), while the commissioning of Avon (670MW) took place on 20 July 2016. The load factors for the year to March 2017 have been much lower than target, due to the lower dispatch requirement from Eskom. With lower volumes, the fixed capacity charge increases the unit cost of OCGT Peakers power. 10.2.7 Renewable Energy Independent Power Producer (RE-IPP) procurement programme The DoE launched the RE-IPP Programme during 2011, which called for 3 725MW of renewable energy technologies in commercial operation between mid-2014 and the end of 2016. Developers were invited to submit proposals for the financing, construction, operation, and maintenance of any onshore wind, solar thermal, solar photovoltaic, biomass, biogas, landfill gas, or small hydro technologies. This has since been extended with additional Ministerial Determinations (adding 3200 MW in 2012 and 6300 MW in 2015). Renewable projects with signed power purchase agreements are in various stages of construction. New operational contracts during the year include 449MW wind, 509MW solar PV, 4MW hydro and 3MW landfill gas. TABLE 17: RENEWABLE IPP AGREEMENTS MW Mar-17 Signed Contracts Operational Contracts RE-IPP 4 000 3 110 Load Factor % - 30.7 Primary energy Eskom Holdings RCA Submission FY 2016/17 Page: 42 Deemed energy expenditure of R477 million was incurred during the year (R24 million for year to March 2016), due to delays in grid connection for a number of projects, as well as system curtailment events. TABLE 18: IPP OPERATIONAL CAPACITIES BY TYPE AND LOCATION AT 31 MARCH 2017 1. Capacities (MW) indicate the contract maximum (or operational capacity if lower). 2. Other short-term refers to hydro, biomass, coal, gas turbines and engines, mixed fuels, etc. of which 460MW relates to coal and 253MW to gas turbines and engines. 10.3 Legal basis for IPPs per the MYPD Methodology Section 9 in the MYPD Methodology deals with the treatment of IPPs: Concentrated solar power Photo- voltaic Hydro and biomass WindLandfill Eastern Cape70947335 1 352 Free State1964114 314 Gauteng3250 253 KwaZulu-Natal670123 793 Limpopo118 118 Mpumalanga423 423 Northern Cape20095010153 1 313 North West7 7 Western Cape1343192 455 Total 200 1 475 14 1 419 3 1 005 912 5 028 Province, MW RE-IPP Programme Diesel Other short term Total 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 pass- through 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. Primary energy Eskom Holdings RCA Submission FY 2016/17 Page: 43 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. 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: 10.6 Allowed vs Actual IPP costs for 2016/17 Eskom was awarded a total of R19 269 million for IPP’s in the MYPD 3 decision for 2016/17. This includes IPP ancillary costs of R97 million. Actual costs amounted to R 21 721 million resulting in extra spend of R 2 452 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. Eskom utilized 3 098 GWh more energy from IPPs when compared to the MYPD3 decision in 2016/17. A summary of the costs and volumes from IPPs are presented in the table below: 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. Primary energy Eskom Holdings RCA Submission FY 2016/17 Page: 44 TABLE 19: IPPS COSTS AND VOLUMES Note: The actual costs include the RCA adjustment amount relating to IFRIC 4 adjustment. 10.6.1 Reasons for IPP variances in 2016/17 Eskom utilized 3 098 GWh more energy from IPPs when compared to the MYPD3 decision in 2016/17, resulting in R2 452 million more spent on IPPs compared to the MYPD3 decision. A. Medium Term Power Purchase Programme (MTPPP) At the time of the MYPD3 application it was expected that the MTPPP contracts would have expired by FY 2016. The delay in the new build has necessitated the extension of the last MTPPP contract resulting in the additional energy purchases and additional cost. Volume variance: There is only one IPP remaining in the MTPPP. As a gas turbine (operating on piped gas) the generator has significant flexibility and operates in a mid-merit basis. This is in line with the contract parameters and is encouraged through differential pricing between the peak and off-peak periods. Price variance: As mentioned above the last IPP under the MTPPP operates on a mid- merit basis and thus benefits from the higher price applicable over the peak period in the contract (defined as between 06h00 and 22h00). B. Short Term Power Purchase Programmes (STPPP) At the time of the MYPD3 application it was expected that the short term contracts would be phased out during FY 2015 as the system capacity shortfall was ameliorated by Eskom new build. The delay in the new build has necessitated the extension of the STPPP and municipal generation contracts leading to the increased purchase volumes and associated costs. Independent Power ProducersNote 2016/17ActualsDecisionVarianceActualsDecisionVarianceActualsDecisionVarianceRef Non-Renewable39533953423504235933 MTPPP373729291 276 A STPPP2861286130033003953 B Municipalities98598510981098897 B WEPS70701050105667 C Renewable IPP's1558216386-80472277991-76421562051106 Renewable IPP Energy1510516386-128172277991-76421562051106D Renewable IPP - Deemed Energy Payments 477477D DOE Peaker 21862786-60067440-37332627633226295E Total IPPs217211917225491152984313098 IPP Ancilliary Cost097-97F Total IPP for RCA 217211926924521152984313098 Cost (R'm)Volumes(GWh)Average Costs (R/MWh) Primary energy Eskom Holdings RCA Submission FY 2016/17 Page: 45 C. WEPS The WEPS price reflects the NERSA approved WEPS tariff. Eskom buys energy from embedded generators at the average energy rate as determined by NERSA in the approved WEPS tariff. These contracts are annual contracts limited to generators ability to connect to the Eskom Distribution network at above 1 kVA. These were not included in the NERSA revenue determination. D. Renewable IPPs Price variance: Prices were marginally higher due to price adjustments between bid announcement and financial close, offset by lower actual CPI escalations (compared to forecast). Volume variance: The volumes produced by REIPP generators were lower than that assumed in the NERSA MYPD3 determination. There were significant delays in the implementation of bid window 3 caused by delays in financial close as well as some REIPPP projects that experienced commissioning delays. 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 R171 million for the year were made due to:  Delays in grid connection for number of projects  System Curtailment Events relating to a system requirement to reduce generation in specific hours. In addition a provision of R306 million was made for potential deemed energy payments relating to current disputes. E. DOE Peaker Price variance: The payment to the Peaker is split between capacity payments and energy payments (for utilization) as it is fully dispatchable by Eskom. The average rate paid is higher than anticipated in the MYPD3 decision due to lower utilization (approx. 1% for the period of operation) relative to the expected 5%. Primary energy Eskom Holdings RCA Submission FY 2016/17 Page: 46 Volume variance: As explained above the volumes were lower, mainly due to lower utilization by Eskom, but also that one project went into commercial operation later than originally anticipated. F. TRANSMISSION ANCILLIARY COSTS NERSA approved R97 million for Transmission ancillary costs in the MYPD3 determination for FY 2017. These costs have not been incurred. This portion of the allocation has been added to the budget to accommodate network use of system charges to the IPP which are a pass through to the Eskom Buyer’s Office. During FY 2017 the total payment for use of system charges was R75.13 million. This is included in the total payment for REIPP. International purchases Eskom Holdings RCA Submission FY 2016/17 Page: 47 11 International purchases Eskom acquired electricity from neighboring countries that resulted in purchases of R2 681 million which generated energy inflows of 7 418 GWh 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 million MYPD3 Decision Actuals RCA 2016/17 International purchases 399 2 681 2 282 11.1 Cross-border sales and purchases of electricity Eskom’s current excess capacity has provided an opportunity to make additional international electricity sales. International sales for the year to 31 March 2017 have increased by 12% compared to the previous year. This as a result of a focused strategy to boost export sales in order to partly offset the reduction in revenue from local sales, utilise excess operational capacity as well as alleviate the effect of the drought affecting the Kariba Power Station on the Zambezi River, which supplies Zimbabwe and Zambia. The lower volume of cross-border purchases can be attributed primarily to Cahora Bassa (HCB) reducing their supply due to water levels at HCB being affected by the drought in the region. 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 us to restrict supply during emergency situations in South Africa. TABLE 21 : CROSS BORDER SALES AND PURCHASES GWh Actual 2014/15 Actual 2015/16 Actual 2016/17 International Sales 12000 13465 15093 A International Purchases 10731 9703 7418 Net Sales/(Purchases) 1269 3762 7675 Note A: The international sales shown in the Annual Financial Statements reflect 15 093GWh (15 006GWh + 87GWh) which are based on the geographical location in which the sale occurred. For regulation the 87GWh is not shown as International sales as this is sold by Distribution and as such forms part of Distribution sales. Coal Burn Costs Eskom Holdings RCA Submission FY 2016/17 Page: 48 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, short- term 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 pass- through 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 : 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 PBR cost (Rand) = (Alpha x Actual Unit Cost of Coal Burn+ (1 – Alpha) x Coal burn Benchmark price) X Actual Coal Burn Volume Coal Burn Costs Eskom Holdings RCA Submission FY 2016/17 Page: 49 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 The following information was received from NERSA: TABLE 22: NERSA’S DECISION ON COAL BENCHMARK AND ALPHA Coal benchmark Unit MYPD3 2016/17 Coal burn costs R'm 44 245 Coal burn volumes kt 129 000 Benchmark avg cost rate R/t 343.0 12.3 Coal cost – RCA 2017 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 In deriving the actual R/t costs, Eskom first deducts the costs relating to coal which are incurred but does not result in burn and energy being produced (Medupi take or pay and Kusile risk sharing agreement contracts). As presented below the actual R/t is computed by taking actual coal costs of R44 652m and deducting the R510m in respect of the take or PBR cost (Rand) = (Alpha x Actual Unit Cost of Coal Burn+ (1 – Alpha) x Coal burn Benchmark price) X Actual Coal Burn Volume For 2016/17 PBR cost (Rand) = (((0.95 X R388.1) + (1-0.95) X R343)) X 113 737 Mt)/1000 PBR cost (Rand) = R43 886m Where Alpha = 0.95 Actual coal burn volume = 113 737 Mt Actual unit cost of coal burn = R388.1 per ton Coal burn benchmark cost = R343.0 per ton Coal Burn Costs Eskom Holdings RCA Submission FY 2016/17 Page: 50 pay contractual amount, resulting in a total cost of R44 142m. Thereafter the adjusted actual cost of R44 142m is divided by the volume of coal burn of 113 737Mt resulting in an average actual R/t of R388.1 TABLE 23: WORKING COAL MECHANISM Workings of coal mechanism Unit MYPD3 Actuals Variance Coal burn R'm 44 245 44 652 407 Coal disallowed for qualifying actuals costs R'm - -510 -510 - Medupi take or pay agreement R'm -510 - Kusile take or pay agreement R'm - Coal burn costs R'm 44 245 44 142 -103 Coal burn tons Mt 129 000 113 737 -15 263 Costs rate per ton R/t 343.0 388.1 45.1 Alpha - sharing mechanism % 95% 95% Coal rate after incl Alpha R/t 325.8 368.7 42.87 Adjusted MYPD3 decision with alpha 385.8 12.3.2 Step 2 – Calculate the pass through coal burn costs 12.3.3 Step 3 – Split the pass through coal burn cost into volume variance and price variance summarised below. For 2016/17 Pass-through Coal Burn Cost = R43 886m – R44 245m Pass-through Coal Burn Cost = -R359m Pass-through Coal Burn Cost = PBR Cost - Allowed Coal Burn Cost Coal Burn Costs Eskom Holdings RCA Submission FY 2016/17 Page: 51 TABLE 24: THE COAL BURN BREAKDOWN FOR THE RCA Coal burn variance breakdown Unit RCA 2016/17 Coal burn price variance R'm 5 530 Coal burn volume variance R'm -5 889 Coal burn costs included in RCA R'm -359 The coal burn variance of minus R 359m 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 R5 889m 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 R5 530m 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. 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 price variance = Allowed coal burn tons X (Actual – Allowed Price in R/t X Alpha) Coal price variance = 129000 X ((R388.1 – R343) X 0.95) Coal price variance = 129000 X R42.87 Coal price variance = R5 530m Where: Allowed coal burn tons (Mt) = 129 000 Mt Actual Price (R/t) = R388.1 Allowed Price (R/t) = R343 Alpha = 0.95 Coal Burn Costs Eskom Holdings RCA Submission FY 2016/17 Page: 52 12.4 Coal burn cost variance explanations The differences in 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. TABLE 25: MYPD 3 ASSUMPTIONS VS. ACTUAL 2016/17 MYPD3 – Assumptions for 2016/17 Actual 2016/17 Electricity production from coal fired plant would be 237 921 GWh. Electricity production from coal fired plant was 199 495 GWh. Cost Plus and Fixed Price mines produce at expected levels, except for Arnot Cost Plus and Fixed Price mines produced below expected levels. New long term mines are producing Only a portion of the coal could be accepted at Medupi Power Station because the station construction was delayed. Coal qualities have been adjusted to reflect the impact of the washing plants. Some delays were experienced with coal quality improvement initiatives. The new power stations (Medupi and Kusile) use flue gas desulphurisation (FGD) at 0.45 litres per units sent out (l/USO). FGD has not yet been implemented at Medupi and Kusile Majuba heavy haul line and other rail infrastructure are approved, constructed and commissioned on schedule. Rail infrastructure was delayed 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, comprising average ST/MT costs of R458/t, Cost plus costs of R388/t and fixed price costs of R262/t. Coal volume variance = Adjusted price r/t with Alpha X variance in coal burn tons Coal volume variance = (R343 + ((R388.1- R343) X 0.95)) X (113 737 – 129 000) Coal volume variance = (R343 + R42.87) X -15 263 Coal volume variance = R385.87 X -15 263 Coal volume variance = -R5 889m Where: Allowed coal burn tons (Mt) = 129 000 Mt Actual coal burn tons (Mt) = 113 737 Mt Allowed Price (R/t) = R343.0 Actual Price (R/t) = R313.7 Alpha = 0.95 Coal Burn Costs Eskom Holdings RCA Submission FY 2016/17 Page: 53 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 Duvha, Hendrina, Matimba and Medupi 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 28% of coal for FY17 was sourced from long term fixed price contracts against a plan of 33%. 12.5.2 Cost plus contracts Coal from Cost Plus contracts is the second cheapest coal supply source. The cost of this coal comprises all expenditure incurred at the mine, overheads, capex and a return on the mines’ initial investment. The age of these mines and levels of investment in them has reduced over time resulting in lower production volumes in recent years. Lower production volumes result in a higher R/ton cost because Eskom is contractually liable for the operating costs of the colliery. However, the transport cost is also minimal because coal is transported by conveyor to the power station. Coal supplied under these agreements is, on average, cheaper than coal from ST/MT contracts. The mines will attempt 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 33% of the coal procured in FY17 against the plan of 35%. 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 Coal Burn Costs Eskom Holdings RCA Submission FY 2016/17 Page: 54 price at any given time is likely to be purely coincidental. These contracts supplied approximately 34% of the coal in FY17 against the plan of 37%. 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 (59%), road (10%) and rail (31%). a. 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 FY17. b. Rail Rail is the next cheapest mode of transport. However, there are only four stations, Majuba, Tutuka and Camden which have rail infrastructure. c. Road Road is the most expensive mode of transport. Although total volumes purchased were lower than planned, higher burn at Majuba and the RTS stations meant that coal needed to be transported to these stations. Because of 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 FY17, more coal was transported by road than planned, because of the issues discussed above and because the additional rail infrastructure that was planned for has been delayed. This contributed to the higher R/ton cost. 12.7 Medupi Take or Pay payment A take or pay payment of R488 million was incurred because of the delay in the construction of Medupi Power Station. 12.8 Kusile Risk Sharing Agreement The construction of Kusile Power Station is ongoing. Eskom is still negotiating with Anglo Coal in an attempt to secure the long term coal for the station. The parties have signed a risk sharing agreement with certain milestone dates The risk sharing payment for the FY2017 year amounted to R22 million. Securing our coal requirements Coal Burn Costs Eskom Holdings RCA Submission FY 2016/17 Page: 55 TABLE 26: SECURING OUR COAL REQUIREMENTS Although coal stock stood at 74 days, adjustments are made for volumes at certain power stations to arrive at normalised coal stock days of 38 days, which is slightly higher than the overall target of 37 days. All power stations’ stock days were maintained above minimum levels, except for Arnot, Kriel, Tutuka, Duvha and Majuba Power Stations. Deliveries were negatively impacted by heavy rains, and rail tippler breakdowns’ at Majuba further impacted deliveries. Plans are in place to improve the stockholding at these stations in the coming financial year. The following volume adjustments are made to arrive at normalised coal stock days:  The high coal stock level at Medupi (11Mt) is excluded. This results from Eskom taking delivery of coal in terms of the colliery contract, rather than pay a penalty, even though the commissioning of units at Medupi was delayed  Likewise coal at Kusile (1.9Mt) is excluded, as the station is not yet in production  Lethabo is serviced by a cost-plus mine, where there is no financial benefit to Eskom to reduce coal production, resulting in the higher than targeted stockholding of 70 days at Lethabo (which is normalised to the target of 30 days) Measure and unit Actual 2016/17 Actual 2015/16 Actual 2014/15 Coal burnt, Mt113.74114.81119.18 Coal purchased, Mt120.25118.7121.67 Coal stock days745851 Road-to-rail migration (additional tonnage 13.213.612.6 Other Primary energy Eskom Holdings RCA Submission FY 2016/17 Page: 56 13 Other Primary energy The MYPD Methodology allows for other primary energy as pass through. Coal burn, OCGTs, IPPs and environmental levy have specific rules and are dealt with separately in the document. 13.1 Allowed other primary energy in 2016/17 13.1.1 Allowed other primary energy costs Other primary energy costs in the MYPD 3 decision for 2016/17 excluding demand market participation (i.e. DMP) is R6 327m. The details are presented in the table below. 13.1.2 Allowed vs Actual other primary energy Eskom incurred R7 049m relating to other primary costs during 2016/17 with the major items being start up gas and oil, coal handling and water which is summarised in table below. The actual costs exceeded the MYPD3 decision of R6 327 million by R722 million as highlighted in the table below. 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). Other Primary energy Eskom Holdings RCA Submission FY 2016/17 Page: 57 TABLE 27: OTHER PRIMARY ENERGY 13.1.3 Reasons for start-up gas and oil costs variance Start-up gas and oil contributes R532 million to the RCA. Heavy fuel oil starts and shuts down a coal fired power station and stabilizes 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 significantly higher in 2016/17 than what was anticipated at the time of the MYPD3 application and hence the use of fuel oil increased significantly as well. Fuel oil costs decreased by R63m from FY2016 to FY2017 (therefore a real decrease year- on-year). Since 2013/14 when Generation spent R3bn on fuel oil, fuel oil costs had been reduced substantially in subsequent years to R2.2bn in 2016/17. 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 very 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).” Other Primary Energy R'millions MYPD3 Decision Actuals 2016/17 RCA 2016/17 Water 2 188 1 751 -437 Start up gas & oil 1 695 2 227 532 Coal handling 1 257 1 758 501 Water treatment 298 423 125 Nuclear 446 727 281 Fuel procurement 304 163 -141 Sorbent usage 139 0 -139 Other primary energy for RCA , R million 6 327 7 049 722 Other Primary energy Eskom Holdings RCA Submission FY 2016/17 Page: 58 13.1.4 Reasons for coal handling costs variance A variance of R501 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 3% only (below inflation) even though Medupi unit 6 is fully operational. As a result of the collapse of coal silo 20 at Majuba, there was an excessive use of yellow plant equipment in 2015/16. Due to the earlier than planned commissioning of the interim solution of silo 20, coal handling costs were reduced due to a lesser usage of yellow plant equipment and diesel in comparison to the previous financial year. 13.1.5 Reasons for water costs variance NERSA granted Eskom R2 188 million for Water costs in FY16. Actual expenditure was R1751 million resulting in under expenditure of R437 million compared to the decision. 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 tariff based costs. Expenditure on pumping and O&M was also significantly lower than planned. 13.1.6 Reasons for fuel procurement costs variance A variance of R141 million occurred due to lower expenditure. The primary components of fuel procurement expenditure and the reasons for the bulk of the under expenditure are:  Manpower was underspent because of savings initiatives, during which a moratorium was placed on hiring staff.  Savings on consulting fees due to the studies planned for the Waterberg strategy did not materialise. 13.1.7 Water treatment costs variance A variance of R125 million in favour of Eskom arose, due to water treatment costs within the power stations being more than was originally envisaged. The drought in South Africa impacted the quality of water at all the power stations and hence the stations spent more on chemicals to treat the poor quality water. 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) Other Primary energy Eskom Holdings RCA Submission FY 2016/17 Page: 59 were used to determine the approved price. The actual nuclear fuel costs were R281 million more than the decision. TABLE 27: NUCLEAR FUEL COSTS 2016/17 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 2016/17 financial year. The MYPD3 Application assumed that 64 fuel assemblies will be loaded, but only 56 were loaded as currently there is no storage space. 13.1.8.2 Nuclear fuel burn U1 The cost of fresh fuel assemblies loaded after outage 122 was lower than originally estimated at the time of the MYPD3 Application, leading to a lower cost of recovery of fuel burn every month. 13.1.8.3 Nuclear fuel burn U2 Outage 222 that was scheduled to start on 20 March, was shitfted out to the next financial year and hence more fuel was burnt. Also, no UCLF incidents were incurred on unit 2 during the financial year. 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. Nuclear fuel costs R'million Actuals 2016/17 MYPD3 Decision 2017/18 Variance to MYPD3 Nuclear other 28 103- 75 Nuclear fuel burn U1 334 349- 15 Nuclear fuel burn U2 320 295 25 Nuclear spent fuel 45 20 25 Eskom MYPD3 Application 727 767- 40 Nersa disallowed - 321 321 Total Nuclear Fuel costs 727 446 281 Other Primary energy Eskom Holdings RCA Submission FY 2016/17 Page: 60 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 2016/17 thus resulting in a claw back of R139 million in the RCA submission. Environmental levy Eskom Holdings RCA Submission FY 2016/17 Page: 61 14 Environmental levy The MYPD Methodology allows for (under)/over recovery to be adjusted through the RCA mechanism as presented in the extract below: Eskom incurred environmental levy costs of R 1 404m less than the MYPD3 determination for 2016/17. The fundamental driver to the variance for the environmental levy is due to a substantial decrease in coal volume due to lower sales compared to MYPD3 plus the additional supply from IPPs and an increase in the system average auxiliary percentage. 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 2016/17. 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 under- recovery will be recorded in the RCA. Demand Market Participation Eskom Holdings RCA Submission FY 2016/17 Page: 62 15 Demand Market Participation 15.1 Allowed DMP No DMP and power buybacks were allowed in the MYPD 3 decision. TABLE 28: APPROVED DEMAND RESPONSE (DR) EXPENDITURE FOR MYPD3 Source: Table 36 of MYPD3 decision, 28 February 2013 15.1.1 Actual DMP Demand market participation had a variance of R194 m during the year. TABLE 29: DMP COMPARISON FOR RCA 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 considered a best practice for modern system operators and should continue. Thus the R'm2016/17 DMP and Power buy-back Applied for Funding1 835 Demand Savings (MW)3 855 R/MW0.48 DMP and Power buy-back Adjusted Funding-1 835 Demand Savings (MW)-3 855 R/MW-0.48 DMP and Power buy-back Approved Funding- Demand Savings (MW)- R/MW- Demand market participation (DMP) MYPD3 Decision Actuals RCA 2016/17 DMP (R’m) - 194 194 Demand Market Participation Eskom Holdings RCA Submission FY 2016/17 Page: 63 costs associated with the DMP programmes were utilised to provide these reliability and security of supply reasons. Open cycle gas turbines (OCGTs) Eskom Holdings RCA Submission FY 2016/17 Page: 64 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 pass- through 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 599m for OCGT fuel cost from a production of 533 GWh requiring 150 ML of diesel. 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 improved performance in the existing fleet in terms of energy availability, commissioning new power stations and growth in IPPs have resulted in a turnaround in the usage of OCGT to almost zero in 2016/17. Therefore OCGTs costs of R1259 million were saved in the year and claw back in terms of this RCA submission. TABLE 30: OCGT Open Cycle Gas Turbines (OCGTs) MYPD3 Decision Actuals Variance OCGTs costs (R'million) 1 599 340 -1 259 OCGTs volumes (GWh) 533.00 29.28 -504 Open cycle gas turbines (OCGTs) Eskom Holdings RCA Submission FY 2016/17 Page: 65 The OCGT cost for the year R340 million. This comprises OCGT burn of R60 million and diesel storage and demurrage costs of R280 million, incurred as a result of not running the OCGTs. 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. Open cycle gas turbines (OCGTs) Eskom Holdings RCA Submission FY 2016/17 Page: 66 16.1.2 Actual Plant performance in 2016/17 Attached below is extracts from the 2016/17 integrated report which highlights the performance of the generation fleet. 16.1.2.1 Operating highlights  There has been no load shedding since 8 August 2015, except for one incident on 14 September 2015, and load curtailment of key customers on 9 October 2015  The Tetris planning tool has assisted in optimising the scheduling of outages  Adhered to the summer and winter maintenance budget (planned and unplanned) of 11.5GW and 8.5GW respectively  Medupi Unit 6 has been in commercial operation since August 2015  UCLF improved from an average of 15.22% in 2014/15, to 14.91% in 2016/17, while  PCLF improved from an average of 9.91% in 2014/15, to 12.99% in 2016/17  EAF increased from an average of 69.85% in the last quarter of 2014/15, to 73.51% in the last quarter of 2016/17 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 Unplanned breakdowns (UCLF) have also improved from a monthly average of 10.95% in April 2016 to 9.2% in March 2017, due to a focus on partial load losses and improvements due to previous planned maintenance. Although the current efforts have helped to improve system performance, it is critical to note that the system remains constrained. Strategies are in place to address system constraints. Pressure on the system is expected to ease further as Medupi, Ingula and Open cycle gas turbines (OCGTs) Eskom Holdings RCA Submission FY 2016/17 Page: 67 Kusile are progressively commissioned, combined with further increased production from IPPs. FIGURE 6 : GENERATION TECHNICAL PERFORMANCE 16.1.2.3 Generation Sustainability Strategy Until recently, Eskom has deferred some maintenance as a result of capacity constraints. Since August 2015, the extent of unplanned breakdowns has improved and new capacity has been added. This has enabled Eskom to adopt a revised maintenance strategy, which aims to perform all required maintenance, whilst adhering to the strict maintenance target (planned and unplanned) of 11 500MW in summer and 8 500MW in winter. Eskom has improved its outage scheduling using the Tetris planning tool. This provides a graphical representation of the maintenance schedule and the capacity outlook, and is able to provide a forward-looking view. This allows for more informed decision making regarding the prioritisation of maintenance and rescheduling to minimise the risk of load shedding. Capital expenditure clearing account (CECA) Eskom Holdings RCA Submission FY 2016/17 Page: 68 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 2016/17 was R58 924 million compared to the MYPD3 decision assumption of R46 655 million thus resulting in a variance of R12 269 million. However, only capex changes that affect the RAB are adjusted for CECA purposes. The total variance of R12 269 million comprises Generation capex overspend by R24 034 million, Transmission underspend by R7 991 million, Distribution underspend by R5 782 million with the balance of R2 009 attributable to other capital expenditure. Included in Generation were new build expenditures which exceeded the MYPD3 assumptions by R22.44 billion, comprising Medupi of R6.12 billion, Kusile of R14.69 billion and Ingula of R1.63 billion. However, for RCA purposes not all changes to capital expenditure affect the regulatory asset base and thus do not qualify for RCA related changes. Of the total variance of R12 269 million, only R5 827 million qualifies as RAB expenditure. 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. Capital expenditure clearing account (CECA) Eskom Holdings RCA Submission FY 2016/17 Page: 69 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 R 2 914 million (i.e. R 5 827 million divided by 2) for FY2017. Table 31: Calculation average capital expenditure 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. CECA Calculation -Variance between actual and allowed capexCalculation Reference Eskom company Allowed MYPD capital expenditureA46 655 Less: Capital expenditure excludedB17 830 Future fuel3 647 Technical and refurbishment capital expenditure14 183 Allowed RAB capital expenditureA-B28 825 Actual MYPD capital expenditureC58 924 Less: Capital expenditure excludedD24 272 Future fuel114 Payment received in advance recognised to revenue2 042 Technical and refurbishment capital expenditure22 116 Actual RAB capital expenditureC-D34 652 Total actual minus total allowed capital expenditureC-A12 269 Less: Variance on capital expenditure excludedD-B6 442 Variance on RAB capital expenditureE5 827 Average capital expenditure difference for CECA calculationE/22 914 Allowed Return - NERSA MYPD 3 decisionE3.9% Capital expenditure clearing account (CECA) Eskom Holdings RCA Submission FY 2016/17 Page: 70 The section below illustrates how the CECA of R636 million is computed by applying the allowed ROA to the capex variance. Table 32: CECA Calculation: Return due to/ (by) Eskom Note: For purposes of the calculating the CECA claim, the allowed RAB of R713 380m is adjusted for the capex variance of the current year of R2 914 million and prior year of R 13 495 million , resulting in an adjusted RAB of R729 789 million. 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 33 : Regulatory asset base for 2016/17 Source: Table 10 of MYPD3 decision, 28 February 2013 Table 34: Returns and percentage allowed in 2016/17 Source: Table 9 of MYPD3 decision, 28 February 2013 CECA Calculation : Return due to/(by) Eskom Calculation Reference Eskom company MYPD3 Regulatory assets base (RAB)713 380 Add /(Deduct): Current year average capex variance2 914 Add/ (Deduct): Cumulative prior year capex variances13 495 Adjusted MYPD3 Regulatory assets base (RAB) F729 789 MYPD3 allowed return on assets (ROA)G27 657 Return on adjusted RABF*H28 293 Increase / (Decrease) in ROA for RCA (F*H)-G636 MYPD3 allowed ROA %H3.88% R'm2016/17 RAB Applied for981 853 RAB Adjustment -269 073 RAB Approved 712 780 R'm2016/17 Real Pre-tax WACC (%)3.9% Return (R'm)27 657 Capital expenditure clearing account (CECA) Eskom Holdings RCA Submission FY 2016/17 Page: 71 Table 35: Capital expenditure in 2016/17 Source: Table 11 of MYPD3 decision, 28 February 2013 17.3 Reasons for new build higher expenditures 17.3.1 Medupi: The over-expenditure of R6.1bn is mainly due to; 17.3.1.1 Basic cost - Increase of R1.9bn due to; - Additional variation requests due to design changes, design integration challenges and additional employer policy requirements such as the Partnership Agreement. - Claim costs mainly due to prolongation, because of access delays, force majeure events (including labour unrest) and construction challenges on the Boiler, Turbine and Civil packages. - Unplaced packages that were not allowed such as costs relating to excess coal stockyard and others. - The impact of the revision of the project completion date from December 2014 to May 2020. 17.3.1.2 Escalation - Increase of R1.3bn - Due to the increase in Basic cost. 17.3.1.3 Owners Development Cost (ODC) - Increase of R1.6bn - Increase of R0.04bn due to cost incurred but not allowed in the determination. - Increase of R1.56bn due to the new manpower structure with additional positions in critical roles (e.g. quality), DAB team to support claims management and the delay in the demobilization of resources in line with schedule delays 17.3.1.4 Contingency - Increase of R1.4bn - Increase of R0.5bn 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. R'm2016/17 Capex Applied for66 626 Capex Adjustment -19 971 Capex Approved 46 655 Capital expenditure clearing account (CECA) Eskom Holdings RCA Submission FY 2016/17 Page: 72 - Increase of R0.9bn due to Increase in the accrual for work done not assessed for all plant areas, it now includes all progressed milestones for all units to date including Variation Orders. 17.3.2 Kusile: The over-expenditure of R14.7bn is mainly due to; 17.3.2.1 Basic cost - Increase of R5.5bn due to; - The MYPD 3 expenditure that was based on the 2014 synchronization date of Unit 1 whereas the current expenditure is based on the increase expenditure to support the 2016 synchronization date of Unit 1 and the final completion date of Unit 6 of Sep 2022. 17.3.2.2 Escalation - Increase of R2.6bn due to the increase in Basic cost. 17.3.2.3 Owners Development Cost (ODC) - Increase of R3.1bn - Increase of R1.1bn due to cost incurred but not allowed in the determination. - Increase of R2bn due to hiring of strategic personnel and changes on working hours in order to meet the synchronization date of Unit 1. 17.3.2.4 Contingency – - Increase of R3.5bn - 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 Ingula: The over-expenditure of R1.6bn is mainly due to the following; In the MYPD 3 application for Ingula it was planned for the project to be completed by the 2014/15 financial year. Cost was however incurred in 2016/17 due to the delayed completion of the project mainly due to the fatal accident at the inlet tunnels which resulted in 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 project schedule critical path and resulted in project delays and late completion of the project. Capital expenditure clearing account (CECA) Eskom Holdings RCA Submission FY 2016/17 Page: 73 17.4 Actual Capital Expenditure Eskom spends approximately half on new build projects through the Group Capital division 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 36: Reconciliation of capex from the integrated report to CECA disclosures Capital Expenditure R'million Actuals Total Eskom Group Capex per Integrated Report 60 032 Exclude : Eskom Enterprises -1 107 Total Capex for CECA disclosure 58 925 Detailed extract of capital expenditure of R60.0 billion is disclosed in table below. TABLE 37: CAPITAL EXPENDITURE (EXCLUDING CAPITALISED BORROWING COSTS) PER DIVISION Division, R million Actual 2016/17 Actual 2015/16 Group Capital 35 458 33 799 Generation 14 376 11 440 Transmission 940 998 Distribution 5 220 5 490 Subtotal 55 994 51 727 Future fuel 114 2 114 Eskom Enterprises 1107 373 Other areas including intergroup eliminations 2 817 3 138 Total Eskom group funded capital expenditure 1 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. Inflation adjustment Eskom Holdings RCA Submission FY 2016/17 Page: 74 18 Inflation adjustment In compiling the inflationary adjustment, cost of cover, arrear debts (net impairment loss) and DSM 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 38: Inflation Data Inflation data 2013/14 2014/15 2015/16 2016/17 Inflation CPI - Decision 5.60% 5.60% 5.60% 5.60% Inflation index - Decision 1.056 1.115 1.178 1.244 Inflation CPI - Actual 5.70% 6.10% 4.60% 6.40% Inflation index - Actual 1.057 1.121 1.173 1.248 The qualifying expenses of R 43 651 million for the inflation calculation comprise employee benefits cost of R 22 118 million and other operating costs of R 21 533 million. Refer to the table below for the Inflation RCA claim. Qualifying expenses excludes arrear debts, EEDSM, costs of cover and ancillary services as they are treated separately for RCA purposes. Table 39 : Inflation adjustment Due to the actual compounded CPI index of 1.248 in 2016/17 being higher than allowed compounded CPI index of 1.244, this results in an inflation adjustment of R162 million in favour of the Eskom. Inflation adjustment for 2016/17 Calculation ref 2016/17 Total operating costs allowedA43 651 Decision inflation indexB1.244 Actual inflation indexC1.248 Restated allowed costs based on actual inflation (A/B * C)D43 813 Inflation adjustment R'mD-A162 Energy efficiency and demand side management (EEDSM) Eskom Holdings RCA Submission FY 2016/17 Page: 75 19 Energy efficiency and demand side management (EEDSM) 19.1 Actual EEDSM In view of the improved power system status and outlook, the focus of the IDM function is shifting to balancing electricity demand and sales management, and creating space for future sales growth initiatives by shifting demand from peak to off-peak periods. Eskom is working towards its objectives through: • Implementing a “step change” in demand management delivery through an integrated and innovative portfolio of demand management initiatives; • Optimally using Eskom and national resources to deliver the national demand-side management initiative; and • Partnering with stakeholders through a proactive and collaborative approach to contribute to national energy efficiency objectives. Demand side management interventions encourage customers to use electricity more efficiently, thereby reducing the gap between supply and demand in the short to medium term. During the year, IDM conducted a number of programmes to manage demand and improve energy efficiency. 19.2 The Residential mass roll-out programme This Programme aims to reduce residential electricity usage by encouraging households to use energy-efficient technologies. The programme is a significant lever to reduce demand during periods of system constraint. It includes the following sub-programmes:  Residential Compact Fluorescent Lamps (CFLs)  The DoE solar water heating programme Energy efficiency and demand side management (EEDSM) Eskom Holdings RCA Submission FY 2016/17 Page: 76 19.3 Other Energy-efficiency measures IDM runs a number of programmes to manage demand and improve energy efficiency.  The Demand Response Programme has a average certified capacity of 1 267MW of dispatchable load (2015/16: 1 466MW), which can be reduced for short intervals to restore system security, if requested by the System Operator.  The compact fluorescent light (CFL) sustainability programme has installed a total of 4 765 921 CFLs since the project commenced in November 2015, of which 2 705 699 have been installed in in the current year. The last phase of the rollout of 10 million CFLs is planned for 2017/18.  The solar water-heating programme – demand savings of 7.8 MW and energy savings of 81.9 GWh were installed and verified as part of the DoE SWH Programme.  Power Alert - A consequence of the improved power system status and outlook, was that “RED” flightings [in the absence of load shedding, the worst constraint day RED, is the day with least amount of reserve] were stopped. The methodology for determining the colour codes in Power Alert was changed at the end of July 2016. The change is that OCGT plant (both Eskom owned and IPP) is now included as normal generating capacity in the Power Alert calculations, as opposed to emergency generating capacity. Only GREEN flightings occurred - GREEN flightings request the public to use energy wisely and savings are expected to be sustainable (i.e. switch off unnecessary lights). TABLE 40: DEMAND MANAGEMENT COSTS R million Actual 2016/17 Actual 2015/16 Actual 2014/15 Total energy efficiency demand side management 376 413 656 Demand response 194 248 309 Total (excluding transfer pricing) 570 661 965 TABLE 41: ACTUAL SAVINGS (NOT VERIFIED) AND INTERNAL ENERGY EFFICIENCY SAVINGS Measure and unit Actual 2016/17 Actual 2015/16 Actual 2014/15 Demand savings (evening peak), MW 236.9 214.9 271.5 Internal energy efficiency, GWh 5.9 1.7 10.4 Energy efficiency and demand side management (EEDSM) Eskom Holdings RCA Submission FY 2016/17 Page: 77 As verified demand savings [MWs] are used for determining the savings for the RCA computation, there exists a roll over between financial years relating to the time when projects are implemented and the actual verification of the MW savings. Therefore reconciliation is required to determine the verified MW as presented in the table below. TABLE 42: RECONCILIATION BETWEEN DEMAND SAVINGS MWS USED IN RCA CALCULATION The total capacity verified for 2016/17 of 290.3 MW is used for the RCA calculation. 19.4 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. 19.4.1 Allowed EEDSM for 2016/17 The allowed EEDSM costs, MWs and the associated rate are shown in table 46 below. Reconciliation Between Demand Savings (MW) reported by Energy Audit and IDM Demand Savings (MW) Total Verified by Energy Audit (not Incl DoE)290.3 Less Projects Claimed by IDM in FY 2015-9.5 Less Projects Claimed by IDM in FY 2016-51.7 Total IDM Claimed229.1 Plus DoE- Solar Water Heating Projects7.79 Total IDM Claimed for FY 2017236.9 Energy efficiency and demand side management (EEDSM) Eskom Holdings RCA Submission FY 2016/17 Page: 78 TABLE 43: THE ALLOWED EEDSM COSTS Source: Table 40 of MYPD3 decision, 28 February 2013 The EEDSM performance relating to capacity savings and costs are summarised in the table below. TABLE 44: EEDSM COMPARISON FOR RCA IN 2016/17 The current EEDSM regulatory rule does not allow for an incentive where the MW savings exceed the assumed targets and is a one sided rule which penalises Eskom when capacity savings are not met. Hence due to the MYPD Methodology not allowing for symmetrical incentives on achieving extra MW savings, Eskom has included a zero impact for this RCA submission. EEDSM Approved Funding712 Programmes Peak Demand savings (MW)196 Programmes Annualised Energy savings (GWh)939 Programme Costs348 Operating Costs including Depreciation365 Other costs- R/MW3.64 R/kWh0.76 2016/17 Energy Efficiency & Demand Side Management (EEDSM)Unit MYPD 3 2016/17 Actuals 2016/17 Variance Funding R'm712 376 -336 Programmes - Peak Demand savings MW196 290 94 Programme costs R'm348 Operating costs incl. depreciation R'm365 373 Other costs R'm- 3 EEDSM Rate R/MW3.63 1.30 -2.34 EEDSM Rate based on verfied MW savings for RCA R/MW3.63 - MW savings for RCA purposes MW290 Annualised energy savingsGWh939 RCA incentive for achieving more MW savings R'm 342 Operating costs Eskom Holdings RCA Submission FY 2016/17 Page: 79 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 2016/17 The total operating cost allowed is R45 896 million as shown below. TABLE 45: TOTAL OPERATING COST ALLOWED Allowed operating costs R'million 2016/17 Note Ref Employee benefits 22 118 1 Other Opex 21 533 2 Other Income 0 Net Impairment loss 1 219 3 Cost of cover 1 026 4 Total 45 896 Note1: Allowed employee benefits TABLE 46: EMPLOYEE BENEFITS ARE RECONCILED AS FOLLOWS Employee benefits allowed R'million 2016/17 Note Ref Total GTD 18 875 A Add : Corporate 3 243 Corporate Overheads 4 334 B Less: Corporate depreciation -1 091 C Total Employee Benefits allowed 22 118 Reference A: Total GTD allowed employee benefits per NERSA decision Operating costs Eskom Holdings RCA Submission FY 2016/17 Page: 80 TABLE 47: THE ALLOWED EMPLOYEE COSTS FOR GENERATION, TRANSMISSION AND DISTRIBUTION Source: Table 43 of MYPD3 decision, 28 February 2013 Reference B: Total corporate overheads allowed TABLE 48: ALLOWED CORPORATE COSTS IN 2016/17 Source: Table 51 of MYPD3 decision, 28 February 2013 The R4 334 million above includes R1 091 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. TABLE 49: THE DEPRECIATION PER ANNUM IS REFLECTED IN THE TABLE BELOW. Note 2: Other opex Other operating costs of R21 533 million (R14715m+R6818m) comprises repairs and maintenance and other costs as shown below. R'm2016/17 Manpower Applied for23 345 Manpower Adjustments-4 470 Approved Manpower 18 875 R'm2016/17 Corporate overheads Applied for7 569 Corporate overheads Adjustments -3 235 Approved Corporate overheads4 334 Total Corporate depreciation allowed R'million2013/142014/152015/162016/172017/18Total MYPD3 Corporate depreciation4346789301 0917693 902 Operating costs Eskom Holdings RCA Submission FY 2016/17 Page: 81 TABLE 50: ALLOWED MAINTENANCE COSTS Source: Table 44 of MYPD3 decision, 28 February 2013 TABLE 51: OTHER COSTS Source: Table 50 of MYPD3 decision, 28 February 2013 Note 3: Net impairment loss (Arrear debt) TABLE 52: ALLOWED ARREAR DEBTS Source: Table 49 of MYPD3 decision, 28 February 2013 Note 4: Cost of cover TABLE 53: ALLOWED COST OF COVER Source: Table 48 of MYPD3 decision, 28 February 2013 20.2 Allowed vs Actual operating costs During 2016/17 Eskom incurred operating costs excluding IDM of R61 211m which compares to the MYPD3 assumption of R45 896m resulting in over expenditure of R'm2016/17 Maintenance Applied for17 941 Maintenance Adjustments-3 226 Approved Maintenance 14 715 R'm2016/17 Other costs Applied for16 130 Other costs Adjustments -9 312 Approved Other costs 6 818 R'm2016/17 Arrear Debt Applied for1 388 Arrear Debt Adjustments-169 Approved Arrear Debt 1 219 R'm2016/17 Cost of Cover applied for1 026 Cost of Cover adjustments- Approved Cost of Cover1 026 Operating costs Eskom Holdings RCA Submission FY 2016/17 Page: 82 R15 315m. 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 54: SUMMARY OF OPERATING COSTS IN 2016/17 Operating Costs R'millions Allowed AFS actuals Variance Regulatory adjustments RCA actuals RCA balance Employee benefits 22 118 27 902 5 784 -99 27 803 5 685 Other opex 21 533 30 950 9 417 -274 30 676 9 143 Other income - -2 094 -2 094 1 -2 093 -2 093 Net impairment loss 1 219 1 629 410 3 196 4 825 3 606 Cost of cover 1 026 -1 026 - - -1 026 Total Operating Costs R'millions 45 896 58 387 12 491 2 824 61 211 15 315 20.3 Variances in operating costs 20.3.1 Employee benefits Actual staff costs have exceeded the MYPD3 decision due to  Higher salary settlement of 8.5% 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. TABLE 55: TREND IN GROSS EMPLOYEE BENEFITS Actual employee costs 2013/14 2014/15 2015/16 2016/17 Net employee costs (before capitalisation) 22 384 22 187 24 721 27 902 Employee costs capitalised to assets 5 685 6 404 3 266 3 655 Gross employee costs R'm) 28 069 28 591 27 987 31 557 Growth in gross employee benefits 8.7% 1.9% -2.1% 12.8% Gross employee benefits have averaged 5.3% per annum over the last 4 years. 20.3.2 Maintenance Overall Eskom underspent on maintenance. Generation and Transmission maintenance exceeded the MYPD3 decision whilst Distribution maintenance was underspent. For Operating costs Eskom Holdings RCA Submission FY 2016/17 Page: 83 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 2016/17 In the course of Eskom operations in 2016/17, Eskom generated total other income of R2 094 million which is shown in the table below: TABLE 56 : OTHER INCOME FOR 2016/17 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, 2017201620172016 RmRmRmRm 33.Other income Insurance proceeds- 917 812 1 393 Services income 256 355 - - Management fee income- - 146 117 Net surplus on disposal of property, plant and equipment- - - - Operating lease income 296 262 231 226 Dividend income 40 32 32 32 Sale of scrap 202 134 201 134 Other 779 690 672 569 1 573 2 390 2 094 2 471 GroupCompany Operating costs Eskom Holdings RCA Submission FY 2016/17 Page: 84 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 2016/17 RCA Operating cost variance = Actual operating costs – Allowed operating costs Based on RCA equivalent actual operating costs of R61 211 million and allowed other operating costs in the decision of R 45 896 million, Eskom has incurred an additional R15 315 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. Service Quality Incentives Eskom Holdings RCA Submission FY 2016/17 Page: 85 21 Service Quality Incentives NERSA has approved the targets for service quality incentives for Distribution and Transmission below. NERSA is currently developing service quality incentives for Generation. Transmission plans, operates and maintains our transmission assets, while our Distribution network relays electricity from the high-voltage transmission network to customers, including municipalities that manage their own distribution networks. TABLE 57 : TRENDS IN NETWORKS PERFORMANCE Measure and unit Actual 2016/17 Actual 2015/16 Actual 2014/15 Number of system minutes lost <1 minute, minutes SC 3.8 2.41 2.85 Number of major incidents >1 minute, number - 1 2 System average interruption frequency index (SAIFI), events SC 18.9 20.5 19.7 System average interruption duration index (SAIDI), hours SC 38.9 38.6 36.2 Note: One system minute is equivalent to interrupting the entire South Africa at maximum demand for one minute. TABLE 58 : SUMMARY OF SQI PERFORMANCE IN 2016/17 Licensee Service Quality Incentives (SQI) Incentive/ (Penalty) 2016/17 Distribution SQI Incentive 262.6 Transmission SQI Incentive 80.0 Total SQI for 2016/17 (R'millions) Incentive 342.6 21.1 Transmission service quality incentives (SQI) for 2016/17 Eskom Transmission Service Quality Incentive Scheme Results with NERSA comprises of the following 3 measures: - System Minutes (<1) - Number of Major Incidents (SM>1) Service Quality Incentives Eskom Holdings RCA Submission FY 2016/17 Page: 86 - Line Faults / 100 km The performance results for these measures as reported in the Eskom Integrated reports for the financial years 2016/17 has been finalized and the subsequent financial reward / penalty based on these results has been computed. The SQI reflects a net reward of R80m for 2016/17. TABLE 59: TRANSMISSION SQI PERFORMANCE IN 2016/17 Transmission Service Quality Incentives (SQI) Performance result Incentive / (Penalty) R'm Comment SM<1 3.8 0 Dead band Major incidents 0 40 Reward Line faults / 100km 1.6 40 Reward Total Transmission SQI for 2016/17 (R'm) 80 FIGURE 7: TRANSMISSION SYSTEM MINUTES (<1) TABLE 60: TRANSMISSION NUMBER OF MAJOR INCIDENTS (>1SM) Number of Major Incidents (>1SM) Service Quality Incentives Eskom Holdings RCA Submission FY 2016/17 Page: 87 FIGURE 8 : LINE FAULTS /100KM 21.2 Distribution Service Quality Incentive Scheme (SQI) for 2016/17 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)  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 2016/17 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. Service Quality Incentives Eskom Holdings RCA Submission FY 2016/17 Page: 88 TABLE 61: DISTRIBUTION SQI PERFORMANCE IN 2016/17 Distribution Service Quality Incentives (SQI) Incentive/ (Penalty) 2016/17 SAIDI Incentive 145.90 SAIFI Incentive 116.72 DSLI Penalty 0.00 Distribution total SQI ( R'millions) Incentive 262.62 Distribution system performance reflects significant improvements with a declining trend in SAIDI interruption durations reducing from 45.8 minutes in 2012/13 to 29.69 minutes by 2016/17. Reasonability tests Eskom Holdings RCA Submission FY 2016/17 Page: 89 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 9 : EBITDA-TO-INTEREST COVER RATIO The figure above reflects a ratio of approximately 2 for 2016/17. If the above Nersa definition is applied to the actual results for the 2017 financial year, the ratio is as follows: TABLE 62: EBITDA COVER Reference A: 2017 Annual financial statements, Company Income statement (see Annexure 1) Reference B: 2017 Annual financial statements, Note 41 (see Annexure 4) EBITDA Interest Cover Calculation Reference 2016/17 EBITDA Interest CoverA/B1.38 EBITDA A 35.989 InterestB26.003 Conclusion Eskom Holdings RCA Submission FY 2016/17 Page: 90 23 Conclusion Eskom’s approach to RCA 2016/17 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 utilized 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 submission of R23 868 million, Eskom is paying back R3 022 million comprising of coal burn (R359m), OCGTs (R1259m) and environmental levy (R1404m). Eskom is claiming back a total of R6 873 million consisting of other primary energy (R722m), DMP (R194 million), IPPs (R2452m), international purchases (R2282m) and other components (R1224m). Thus the net cost of R3 851 million is being claimed with the balance attributable to the revenue under recovery of R20 016million linked to lower sales volumes. Eskom has not claimed the over expenditure of R15 315m 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 >>>>>>>>>>>>>>>>>>>>>>>>>>>>>>>> Annexures: Eskom Holdings RCA Submission FY 2016/17 Page: 91 Annexures: Revenue: Annexure 1: Income Statement in AFS 2017, page 15 Income statements for the year ended 31 March 2017 2017201620172016 NoteRmRmRmRm Revenue32177 136 164 239 177 136 164 239 Other income331 573 2 390 2 094 2 471 Primary energy34(82 760)(84 728)(82 760)(84 728) Employee benefit expense35(33 178)(29 257)(27 902)(24 721) Net impairment loss36(1 669)(1 170)(1 629)(1 159) Other expenses37(23 570)(18 663)(30 950)(25 170) 37 532 32 811 35 989 30 932 Depreciation and amortisation expense38(20 300)(16 633)(20 277)(16 619) 39(3 342)(1 452)(3 203)(1 492) Net fair value gain on embedded derivatives1 611 997 1 611 996 Profit before net finance cost15 501 15 723 14 120 13 817 Net finance cost(14 377)(7 919)(15 389)(8 776) Finance income405 212 3 447 4 290 2 667 Finance cost41(19 589)(11 366)(19 679)(11 443) Share of profit of equity-accounted investees after tax11 35 43 - - Profit/(loss) before tax1 159 7 847 (1 269)5 041 Income tax42( 271)(2 696) 399 (1 905) Profit/(loss) for the year 2 888 5 151 ( 870)3 136 GroupCompany Net fair value loss on financial instruments, excluding embedded derivatives Restated 1 Restated 1 Profit before depreciation and amortisation expense and net fair value loss (EBITDA) Annexures: Eskom Holdings RCA Submission FY 2016/17 Page: 92 Annexure 2: The Eskom energy wheel (Eskom Fact sheet 2017) **Note: All figures are in GWh unless otherwise stated. Eskom's energy flow diagram All figures in GWh, unless otherwise indicated. Generation of electricity2016/172015/16Available for distribution2016/172015/16Total imports2016/172015/16 Generation220 137216 043Generation (including IPPs)231 695229 012International purchases7 4189 703 OCGTs 293 936International purchases7 4189 703 Wheeling 1 2 9103 930 Own generation220 166219 979 Wheeling 1 2 9103 930Total 10 32813 633 IPPs11 5299 033Subtotal242 023242 645 Generation (including IPPs)231 695229 012Pumping(4 808)(4 046) Pumping(4 808)(4 046)Total237 215238 599 Total226 887224 966Total exports2016/172015/16 International sales 2 15 09313 465 Wheeling 1 2 9103 930 Total 18 00317 395 Internal use2016/172015/16Demand2016/172015/16External sales2016/172015/16 Internal use 480 661Total sales214 121214 487Local sales199 028201 022 Generated(20) (71) Technical and other losses21 39919 895 International sales 2 15 09313 465 Total 460 590Internal use 480 661Total214 121214 487 Generated(20) (71) Wheeling2 9103 930Technical and other losses2016/172015/16 Unaccounted(1 675) (303)Distribution16 29313 866 Total237 215238 599Transmission5 1066 029 Total21 39919 895 Distribution %7.55%6.43% Transmission %2.22%2.61% Total %8.85%8.59% The energy wheel shows the volume of electricity that flowed from local and international power stations and independent power producers (IPPs) to Eskom’s distribution and export points during the past two years, including the losses incurred in reaching those customers. Southern African Power Pool 1. Wheeling refers to the movement of electricity between international customers through our network, without the power being available to customers on the South African grid. 2. International sales includes exports by Distribution International to Lesotho. The actual volumes were 87GWh for 2016/17 and 89GWh for 2015/16. Annexures: Eskom Holdings RCA Submission FY 2016/17 Page: 93 Annexure 3: Sales volumes GWh – Statistical tables for 2016/17 Electricity sales per customer category, GWh Category 2016/172015/16 Local 199 028 201 022 Distributors 89 718 89 591 Residential 1 11 863 11 917 Commercial 10 339 10 150 Industrial 48 295 50 150 Mining 30 559 30 629 Agricultural 5 405 5 733 Rail 2 849 2 852 International 15 093 13 465 Utilities 5 750 4 018 End users across the border 9 342 9 447 214 121 214 487 International sales to countries in southern Africa, GWh 15 093 13 465 Botswana 9841 099 Lesotho252205 Mozambique8 1208 281 Namibia2 0891 746 Swaziland 9861 044 Zambia 352 344 Zimbabwe1 743 252 Short-term energy market 2 567 494 1. Prepayments and public lighting are included under residential. 2. The short-term energy market consists of all the utilities in the southern African countries that form part of the Southern African Power Pool. Energy is traded on a daily, weekly and monthly basis as there is no long-term bilateral contract. Annexures: Eskom Holdings RCA Submission FY 2016/17 Page: 94 Electricity revenue per customer category, R million Category 2016/172015/16 Local 167 813 154 959 Distributors 73 009 66 396 Residential 1 14 070 12 884 Commercial 11 279 10 157 Industrial 32 701 31 412 Mining 25 915 23 895 Agricultural 7 659 7 349 Rail 2 990 2 755 IPP network charge 190 111 International 10 682 8 055 Utilities 6 632 4 163 End users across the border 4 050 3 892 Gross electricity revenue 178 495 163 014 Environmental levy included in revenue 2 512 513 Less: Revenue capitalised 3 (717) (367) Less: IAS 18 revenue reversal 4 (3 196) (1 472) Electricity revenue per note 32 in the annual financial statements 175 094 161 687 3. Revenue from the sale of production while testing generating plant not yet commissioned, capitalised to plant. 2. The environmental levy of 2c/kWh tax was effective from 1 July 2009 to 31 March 2011. On 1 April 2011 the levy was raised to 2.5c/kWh. On 1 July 2012 the levy was raised to 3.5c/kWh. The levy is payable for electricity produced from non-renewable sources (coal, nuclear and petroleum). The levy is raised on the total electricity production volumes and is recovered through sales. 4. The IAS 18 principle of only recognising revenue if it is deemed collectable at the date of sale, as opposed to recognising the revenue and then impairing the customer debt when conditions change, has been applied since 2015. External revenue to the value of R3 196 million was thus not recognised at 31 March 2017. 1. Prepayments and public lighting are included under residential. Annexures: Eskom Holdings RCA Submission FY 2016/17 Page: 95 Reasonability test Annexure 4: Finance income note 40 and Finance cost note 41 (Extracts AFS March 2017, page 86-87) Notes to the financial statements (continued) for the year ended 31 M arch 2017 2017201620172016 NoteRmRmRmRm 40.Finance income Investment in securities1 001 723 518 347 Loans receivable 885 825 483 446 Finance lease receivables 59 65 59 65 Trade and other receivables1 349 951 1 349 951 Cash and cash equivalents1 918 883 1 881 858 5 212 3 447 4 290 2 667 41.Finance cost Debt securities and borrowings25 872 23 242 26 003 23 333 Eskom bonds12 598 10 202 12 598 10 202 Promissory notes 7 6 7 6 Commercial paper 489 587 492 573 Eurorand zero coupon bonds 587 520 587 520 Foreign bonds3 662 3 637 3 662 3 637 Development financing institutions5 895 4 777 5 895 4 777 Export credit facilities1 643 1 560 1 643 1 560 Subordinated loan from shareholder- 1 208 - 1 208 Other loans 991 745 1 119 850 Derivatives held for risk management4 439 3 151 4 439 3 151 Employee benefit obligations281 552 1 158 1 515 1 130 Provisions293 758 2 588 3 754 2 583 Finance lease payables1 922 387 1 922 406 Trade and other payables 279 266 279 266 Gross finance cost37 822 30 792 37 912 30 869 Capitalised to property, plant and equipment8(18 233)(19 426)(18 233)(19 426) 19 589 11 366 19 679 11 443 GroupCompany Annexures: Eskom Holdings RCA Submission FY 2016/17 Page: 96 Operating expenses Annexure 5: OPEX note 38 extract from AFS March 2016, page 86 2017201620172016 NoteRmRmRmRm 36.Net impairment loss Impairment2 462 1 644 2 417 1 623 Property, plant and equipment81 128 789 1 128 789 Inventories- 11 - 11 Loans receivable15 32 14 - - Trade and other receivables191 302 830 1 289 823 Reversal( 787)( 469)( 784)( 459) Property, plant and equipment8( 644)( 2)( 644)( 2) Loans receivable15- ( 3)- - Trade and other receivables19( 143)( 464)( 140)( 457) Bad debts recovered( 6)( 5)( 4)( 5) 1 669 1 170 1 629 1 159 GroupCompany 2017201620172016 NoteRmRmRmRm 37.Other expenses Managerial, technical and other fees1 351 563 1 325 505 Operating lease expense 940 1 117 375 412 Auditors' remuneration 1 119 94 109 80 Net loss on disposal of property, plant and equipment 260 358 263 494 Government grant- - - - Income- ( 23)- ( 23) Expenses incurred- 23 - 23 Repairs and maintenance, transport and other expenses20 900 16 531 28 878 23 679 23 570 18 663 30 950 25 170 GroupCompany 2017201620172016 RmRmRmRm 33.Other income Insurance proceeds- 917 812 1 393 Services income 256 355 - - Management fee income- - 146 117 Net surplus on disposal of property, plant and equipment- - - - Operating lease income 296 262 231 226 Dividend income 40 32 32 32 Sale of scrap 202 134 201 134 Other 779 690 672 569 1 573 2 390 2 094 2 471 GroupCompany Annexures: Eskom Holdings RCA Submission FY 2016/17 Page: 97 1 Abbreviations BPP Business Productivity Programme Capex Capital Expenditure c/kWh Cent per kilowatt hour CPI Consumer Price Index DMP Demand Market Participation EAF Energy availability factor (see glossary) EBITDA Earnings before interest, taxation, depreciation and amortisation ERTSA Eskom’s Retail Tariff Structural Adjustments EUF Energy utilisation factor (see glossary) GDP Gross Domestic Product GW Gigawatt = 1 000 megawatts GWh Gigawatt-hour = 1 000MWh IDM Integrated demand management IPP Independent power producer (see glossary) kt Kiloton = 1 000 tons Km Kilometer kV Kilovolt kWh Kilowatt-hour = 1 000 watt-hours (see glossary) L/USO Litres per unit sent out M&V Measurement and Verification Ml Megalitre = 1 m litres Mt M tons MTPPP Medium Term Power Purchase Programme MW Megawatt = 1 m watts Annexures: Eskom Holdings RCA Submission FY 2016/17 Page: 98 MWh Megawatt-hour = 1 000kWh MYPD Multi-Year Price Determination NERSA National Energy Regulator of South Africa O&M Operations and Maintenance OCGT Open-Cycle Gas Turbine (see glossary) ODC Owner’s Development Cost Opex Operating Expenditure PE Primary Energy PPA Power Purchase Agreement PCLF Planned Capability Loss Factor R/kWh Rand per kilowatt hour R/MW Rand per Megawatt R/MWh Rand per Megawatt hour R’m Rand million RAB Regulatory Asset Base RCA Regulatory Clearing Account SAIDI System average interruption duration index SAIFI System average interruption frequency index SM System Minutes SQI Service Quality Incentive STPPP Short Term Power Purchase Programme SWH Solar Water Heaters UAGS Unplanned automatic grid separations UCLF Unplanned Capability Loss Factor (see glossary) WUC Work Under Construction Annexures: Eskom Holdings RCA Submission FY 2016/17 Page: 99 2 Glossary and Terms Cost of electricity (excluding depreciation) Electricity-related costs (primary energy costs, employee benefit costs plus impairment loss and other operating expenses) divided by total electricity sales in GWh multiplied by 1 000 Debt service cover ratio Cash generated from operations divided by (net interest paid from financing activities plus debt securities and borrowings repaid) Decommission To remove a facility (e.g. reactor) from service and store it safely Demand side management Planning, implementing and monitoring activities to encourage consumers to use electricity more efficiently, including both the timing and level of demand Electricity EBITDA margin Electricity revenue (excluding electricity revenue not recognised due to uncollectability) as a percentage of EBITDA Electricity operating costs per kWh Electricity-related costs (primary energy costs, employee benefit costs, depreciation and amortisation plus impairment loss and other operating expenses) divided by total electricity sales in kWh multiplied by 100 Electricity revenue per kWh Electricity revenue (including electricity revenue not recognised tue to uncollectability) divided by total kWh sales multiplied by 100 Energy availability factor (EAF) Measure of power station availability, taking account of energy losses not under the control of plant management and internal non-engineering constraints Energy efficiency Programmes to reduce energy used by specific end-use devices and systems, typically without affecting services provided Energy utilisation factor (EUF) Utilisation of the available plant Independent power producer (IPP) Any entity, other than Eskom, that owns or operates, in whole or in part, one or more independent power generation facilities Annexures: Eskom Holdings RCA Submission FY 2016/17 Page: 100 Interest cover EBIT divided by (gross finance cost less gross finance income) Kilowatt-hour (kWh) Basic unit of electric energy equal to one kilowatt of power supplied to or taken from an electric circuit steadily for one hour Load Amount of electric power delivered or required on a system at any specific point Load curtailment Typically larger industrial customers reduce their demand by a specified percentage for the duration of a power system emergency. Due to the nature of their business, these customers require two hours’ notification before they can reduce demand Load shedding Scheduled and controlled power cuts that rotate available capacity between all customers when demand is greater than supply in order to avoid blackouts. Distribution or municipal control rooms open breakers and interrupt load according to predefined schedules Maximum demand Highest demand of load within a specified period Off-peak Period of relatively low system demand Open-cycle gas turbine (OCGT) Liquid fuel turbine power station that forms part of peak-load plant and runs on kerosene or diesel. Designed to operate in periods of peak demand Outage Period in which a generating unit, transmission line, or other facility is out of service Peak demand Maximum power used in a given period, traditionally between 06:00–10:00, as well as 18:00–22:00 in summer or 17:00- 21:00 in winter Peak-load plant Gas turbines, hydroelectric or a pumped storage scheme used during periods of peak demand Primary energy Energy in natural resources, e.g. coal, liquid fuels, sunlight, wind, uranium and water Annexures: Eskom Holdings RCA Submission FY 2016/17 Page: 101 Pumped storage scheme A lower and an upper reservoir with a power station/pumping plant between the two. During off-peak periods the reversible pumps/turbines use electricity to pump water from the lower to the upper reservoir. During periods of peak demand, water runs back into the lower reservoir through the turbines, generating electricity Reserve margin Difference between net system capability and the system’s maximum load requirements (peak load or peak demand) Return on assets EBIT divided by the regulated asset base, which is the sum of property, plant and equipment, trade and other receivables, inventory and future fuel, less trade and other payables and deferred income System minutes Global benchmark for measuring the severity of interruptions to customers. One system minute is equivalent to the loss of the entire system for one minute at annual peak. A major incident is an interruption with a severity ≥ 1 system minute Technical losses Naturally occurring losses that depend on the power systems used Unit capability factor (UCF) Measure of availability of a generating unit, indicating how well it is operated and maintained Unplanned capability loss factor (UCLF) Energy losses due to outages are considered unplanned when a power station unit has to be taken out of service and it is not scheduled at least four weeks in advance Used nuclear fuel Nuclear fuel irradiated in and permanently removed from a nuclear reactor. Used nuclear fuel is stored on-site in used fuel pools or storage casks Watt The watt is the International System of Units' (SI) standard unit of power. It specifies the rate at which electrical energy is dissipated (energy per unit of time) --- Document Separator --- 1 Regulatory Clearing Account (RCA) for MYPD 3 – Explained Definition: The Regulatory Clearing Account (RCA) is a monitoring and tracking mechanism that compares certain uncontrollable costs and revenues assumed in the MYPD decision (made by the National Energy Regulator of South Africa (NERSA)) to actual costs and revenues incurred by Eskom. This is to allow for changes in the actual conditions for specifically identified cost items when compared to assumptions made when the MYPD application was considered. Should there be a difference between the decision and actual costs and revenues; the difference is subject to RCA rules. The RCA rules applicable to a MYPD decision are informed by the approved regulatory framework applicable to the MYPD decision period. This results in a RCA balance that should either be recovered by Eskom (if overspent) or be given back to the customers (if underspent). Once the RCA balance has been determined by Nersa, a separate process is followed to decide on the liquidation thereof, which would take place through implementation of adjustment in tariffs. How the RCA works: The RCA mechanism is a process that will apply to every elapsed year. It is a means to retrospectively reconcile the variances between the assumptions upon which Nersa had based its revenue decision, and the actual outturn, on certain specified elements. As such the RCA process will take place on elapsed years whether or not a re-opening on a future year takes place. As the RCA process develops, it will become more certain and predictable. Any approved recovery of variances takes place by adjusting the electricity price in a future year, relative to what it otherwise would have been. It is thus also inherent to the RCA process that there would be a delay between a variance occurring, and the revenue adjustment taking place, whether being an increase or a decrease. The process is two-fold: first Eskom compiles the RCA balance based on its understanding and interpretation of the MYPD Methodology relating to the RCA and thereafter submits it to NERSA for review, approval and implementation. The activities may be outlined as follows: -  Eskom:- a. Identify the items (cost and revenue) to be assessed b. Apply the RCA rules to determine the value to be included in the RCA c. Compute the RCA balance and obtain supporting documentation to motivate for differences – it is important that Nersa is provided with the reasons, facts and evidence for our submission. d. Obtain internal governance approval e. Submit to NERSA for review, approval and implementation  NERSA:- a. Receive Eskom RCA submission 2 b. Review of the RCA items for prudency, where applicable; i. Some of the costs differences may be deemed to be imprudent and those costs will not be taken into account when calculating the RCA balance. ii. If the costs differences are deemed to be prudent, these will be included in the in the RCA balance. iii. The total RCA balance is calculated by adding together all the cost and revenue differences together, therefore no one cost or revenue item is looked at individually (the RCA balance represents the basket impact). c. Recalculation of the RCA d. Approve the RCA balance e. Decide on the liquidation of the RCA balance i.e. implement tariff adjustments (increases or decreases). The differences included in the MYPD3 Year 1 - RCA calculation:  Revenue,  Coal burn costs: subject to an alpha factor - a risk sharing ratio that is pre-determined by Nersa (volume and price changes taken into account)  Independent Power Producers: costs will be treated as a pass through with the proviso that requirements in terms of the power purchase cost recovery mechanism are met.  Environmental levy: costs are treated as a pass through, where energy sent out is levied  OCGT costs: subject to prudency review (volume and price changes taken into account). Changes in prices are considered to be beyond Eskom’s control and are thus allowed.  Other primary energy costs such as nuclear, hydro, and sorbent, will be allowed as pass-through costs.  Capital expenditure variances will attract only the return on assets component of the difference between capital expenditure assumed in the MYPD decision and actual capital expenditure incurred.  Service quality incentive schemes o This will include technical performance for both transmission and distribution network  Demand Side Management – it is Eskom’s understanding that if Eskom achieves additional savings (in MW) then an incentive in accordance with a pre-determined formula will be allowed. A penalty will be applied if savings, when compared to the decision are not achieved.  Energy Efficiency and demand side management will incur penalties for under achieving their targets. 3  Operating costs - Inflation changes to MYPD decision are taken into account. Prudently incurred under- expenditure in operating costs should be included in the RCA balance. Any variance above the determined operating costs is for Eskom’s account. How is the RCA balance liquidated ? NERSA will liquidate the MYPD 3 year one RCA balance by adjusting future prices of electricity - up if the RCA is in favour of Eskom and down if the RCA is in favour of customers. When can the RCA be liquidated? NERSA compares the recalculated MYPD2 RCA Balance and will make a decision on the amount of the revenue to be liquidated in the 2016/17 financial year through the adjustment of the tariffs. Status of the MYPD3 year one RCA application to NERSA: A formal RCA application for MYPD 3 year one (2013/14) has been submitted to Nersa on 10 November 2015. Eskom has made a submission to Nersa in accordance with the MYPD methodology that was published by Nersa during December 2012. It needs to be highlighted that in terms of the MYPD methodology, Eskom makes an application for variances between actual costs and revenues that materialised in comparison to the MYPD 3 decision that Nersa made. The rules that govern the treatment of the variances are applied. In terms of these rules, there are certain instances where Eskom has to provide evidence, motivations and proof for the variances where Nersa is required to determine the prudency. In practice ‘prudence’ means that Eskom must prove that the variations (relative to the assumptions as made by Nersa for purposes of the MYPD3 revenue decision) are reasonable and efficient under the circumstances. Regarding the use of OCGTs it includes demonstrating that the use is necessary to ensure security of supply and is a last resort regarding the mitigation of capacity constraints, before implementation of load shedding activities. It includes that Eskom has to demonstrate that it has maximised the availability and utilisation of cheaper resources before resorting to the use of OCGTs. What is the difference between a Re-opener and RCA? A re-opening pertains to a future year or years, as a means to prospectively change the revenue decision regarding those future years on the basis of new and different assumptions. On the other hand RCA – is a backward looking view to determine prudency.

Eskom’s third Multi-Year Price Determination (MYPD3) Regulatory Clearing Account (RCA) Year 2 (2014/15), Year 3 (2015/16) and Year 4 (2016/17) applications and indicative timelines for the determination process

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