MYPD 3 (Year 2013/14) Regulatory Clearing Account Submission to NERSA

Transcription

1 MYPD 3 (Year 2013/14) Regulatory Clearing Account Submission to NERSA November 2015

2 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 2 of 205 TABLE OF CONTENTS 1 PREFACE The basis of submissions The structure of 2013/14 RCA Submission OBJECTIVE OVERVIEW OF THE 2013/14 RCA SUBMISSION Revenue Primary energy Environmental levy Net position of Southern African Energy (SAE) Capital expenditure variance Operating costs Integrated demand management Other income Inflation adjustments Service Quality Incentives Reasonableness test Conclusion FACTORS IMPACTING ON 2013/14 RCA SUBMISSION Timeline for application and decision... 24

3 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 3 of Changes in fundamental assumptions since MYPD3 application REVENUE VARIANCE Reasons for revenue variance Allowed revenue Step 1 Understanding the standard tariff impacts Step 2 Matching costs and revenue Step 3 Understanding the other customer impacts Step 4 Subsequently, NERSA revised the allowed revenue for standard tariff customers Step 5 - Confirmation of standard tariff volumes via MYPD2 RCA implementation decision Step 6 Revised allowed regulated revenue for MYPD3 in 2013/ Step 7 Actual standard tariff selling price in 2013/ Step 8 Revenue RCA variance in 2013/ Actual revenue Reporting allowed and actual revenue on an equivalent basis Adjustments to AFS values to achieve the equivalent revenue for RCA Calculation of revenue variance for the year Sales variance explanation Background The process in deriving the 5 year forecast Critical assumptions relevant during 2011 in deriving forecasts Sales volume variance explanation for FY Load shedding in 2013/ Estimated Load shedding & Load Curtailment impact for YR 2013/ Other income Conclusion of revenue variance FACTORS WHICH INFLUENCE ESKOM PRODUCTION PLANS... 52

4 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 4 of PRIMARY ENERGY INDEPENDENT POWER PRODUCERS Medium-term Power Purchase Programme (MTPPP) Municipal Base-load Purchases Short-term Power Purchases Programme (STPPP) Wholesale Electricity Pricing System (WEPs) programme Long-term IPP programmes IPP open cycle gas turbine ( Peaker ) programme Renewable Energy Independent Power Producer (RE-IPP) procurement programme Legal basis for IPPs per the MYPD Methodology IPP Approvals Regulatory rules for power purchase cost recovery IPP allowed costs for 2013/ MTPPP allowed costs in MYPD 3 for 2013/ Short Term IPPs allowed costs in MYPD 3 for 2013/ Renewable IPPs allowed costs in MYPD 3 for 2013/ DOE Peaking allowed costs in MYPD 3 for 2013/ Actual IPP costs for 2013/ Reasons for IPP variances in 2013/ IPP variance for 2013/14 RCA Regional IPPs - Aggreko COAL BURN COST Extract of MYPD Methodology on Coal adjustments... 67

5 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 5 of Extract of MYPD3 Reasons for Decision on Coal costs Coal burn RCA variance impact Coal burn cost variance explanations Lower electricity production from coal fired stations Different mix and efficiency of power stations generating electricity OTHER PRIMARY ENERGY Allowed other primary energy in 2013/ Start up gas and oil allowed for 2013/ Nuclear costs allowed for 2013/ Coal handling costs allowed for 2013/ Water costs allowed for 2013/ Fuel procurement costs allowed for 2013/ Actual other primary energy in 2013/ Reasons for start-up gas and oil costs variance Correlation between start-up gas and oil and UCLF Reasons for nuclear costs variance Reasons for coal handling costs variance Reasons for water costs variance Reasons for fuel procurement costs variance Other primary energy variance in 2013/14 RCA ROAD MAINTENANCE ENVIRONMENTAL LEVY NET POSITION OF SOUTHERN AFRICAN ENERGY (SAE) OPEN CYCLE GAS TURBINES (OCGTS) Reasons for OCGTs variance... 83

6 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 6 of Avoidance of load shedding Power system emergencies and rotational load shedding Declared Emergencies during FY Rotational load shedding on 6 March Actual OCGTs usage and load shedding in 2013/ Impact on load shedding if OCGTs were restricted to Peak hours Cheaper alternatives were maximised and utilised by Eskom Supply side options Demand side options OCGTs allowed in MYPD 3 for 2013/ Actual OCGTs costs in 2013/ Security of supply by the System Operator performance Generating capacity to meet the demand and ensure system security Available generation capacity Pumped storage generation Hydro generation OCGTs Demand Response Options Scheduling and dispatch of generation resources Technical issues impacting OCGT generation Impact of daily load profile on resultant OCGT load factor Speed of response of generators OCGTs role during demand variations Factors influence choice of plant to dispatch Licence conditions for Ankerlig and Gourikwa Summary of a system operations perspective Conclusion on OCGT s OCGTs variance for 2013/14 RCA

7 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 7 of System operator was impacted by delays in new build and Generation plant performance Delays in new build capacity Reasons for delays in new build capacity Evaluation of delay in Eskom new- build projects that impact sustained usage of OCGTs Compared to Eskom/SA, regarding these same five factors: Factors contributing to Generation plant performance Lack of philosophy based maintenance Ageing fleet Actual Plant performance in 2013/ Maintenance backlog reduction strategies Benchmarking Energy efficiency improvement programme Managing supply-and-demand constraints CAPITAL EXPENDITURE CLEARING ACCOUNT (CECA) Regulated asset base adjustment for CECA Step 1: Computing change in RAB Step 2: Computing return impact of change in RAB MYPD3 decision Capital expenditure reprioritised To address the key challenges Eskom allocated funding as follows Reasons for variance Capex actuals in 2013/ Delivering on capital expansion Medupi Kusile Ingula New Build Cost Changes

8 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 8 of Medupi: Cost overruns Kusile : Cost overruns Ingula : Cost overruns Conclusion on capex INFLATION ADJUSTMENT Operating costs Regulatory Asset Base Inflation adjustment on RAB revenue impact Summary: INTEGRATED DEMAND MANAGEMENT Demand-side management: The demand-response programme The residential mass roll-out programme Energy-efficiency measures Methodology Allowed EEDSM for 2013/ Actual EEDSM for 2013/ Computation of EEDSM for the RCA Demand Market Participation and Power Buy Backs Allowed DMP and Power Buy Backs in 2013/ Actual DMP and Power Buy Backs in 2013/ Power buy-backs Demand market participation (DMP) DMP and Power buy back variance in 2013/ Total IDM impact for RCA in 2013/ OPERATING COSTS

9 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 9 of Allowed operating costs in 2013/ Allowed employee costs in 2013/ Allowed maintenance costs in 2013/ Allowed arrear debts in 2013/ Allowed cost of cover in 2013/ Allowed corporate costs in 2013/ Actual operating costs in 2013/ Reasons for variance in other operating costs Employee benefits Maintenance Arrear debt Cost of cover Other operating costs Operating cost variance for 2013/14 RCA Why symmetrical treatment of operating costs is needed INTEREST ON RCA BALANCE SERVICE QUALITY INCENTIVES Transmission service quality incentives (SQI) for 2013/ Distribution Service Quality Incentive Scheme (SQI) for 2013/ REASONABILITY TESTS EBITDA-To-Interest Cover Ratio (EBITDA / Interest Payments) MYPD2 RCA Balance Implementation Plan Understanding the ratio Interest cover ratio

10 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 10 of Debt service cover ratio (Interest + Capital) Computation of ratios for FY EBIT Interest cover ratio EBITDA: Total debt service ratio CONCLUSION ANNEXURES: Annexure 1: Income Statement in AFS Annexure 2: Revenue note 32 from AFS (p81) Annexure 3: Revenue from divisional report 2014 (P47) Annexure 4: Key financial statistics FY Annexure 5: The Eskom energy wheel (Integrated report P22) Annexure 6: Sales volumes GWh (Divisional report page 88) Annexure 7: Primary Energy Note (AFS FY 2014 page 91) Annexure 8: Actual Energy Procured through IPP Programmes in 2013/2014 (Integrated Report FY2014 page 145) Annexure 9: EEDSM Annual report for 2013/ Annexure 10: Supplementary report 2014, page Annexure 11: Annual Financial Statement Annexure 12: Annual Financial Statement Annexure 13: Finance cost extract (AFS FY 2014 page 93) ABBREVIATIONS

11 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 11 of GLOSSARY AND TERMS Figure 1: Time lag between application and actuals Figure 2: Accounting policy - Deferred income in AFS for March Figure 3: Accounting Policy - Payments received in advance in AFS for March Figure 4: GDP Vs Sales growth Figure 5: Production FY Figure 7: Correlation between fuel oil costs (Rand m) and UCLF Figure 8: Load shedding impact in 2013/ Figure 9: Load shedding with OCGTs limited to peak hours Figure 10: Trend in DSM savings Figure 11: OCGTs production in 2013/ Figure 12: Typical profile of generating hours at Drakensberg and Palmiet in a week Figure 13: Coal Power station ages Figure 14: Turbine design vs operating hours Figure 15: Planned maintenance performance Figure 16: Unplanned capability loss factor (UCLF) Annual Results March Figure 17: Monthly UCLF for last 3 years Figure 18: Monthly Energy Utilisation Factor in 2013/ Figure 19: EUF increased by approx. 38% from Figure 20: Energy Availability Factor (EAF) Figure 21: Benchmarking EAF % all coal sizes Figure 22: Benchmarking UCLF % all coal sizes Figure 23: Benchmarking PCLF % all coal sizes Figure 24: Benchmarking EUF % all coal sizes Figure 25: Summer and Winter Load Profiles Figure 26: NERSA determination vs. Eskom Allocation Figure 27: Projected BPP savings Figure 28: Time lapse between application and MYPD2 decision Figure 29: Transmission system minutes (<1) Figure 30: EBITDA-To-Interest Cover Ratio Table 1: Summary of 2013/14 RCA Submission Table 2: Key assumptions which have changed Table 3: Revenue allowed in MYPD3 decision... 29

12 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 12 of 205 Table 4: Sales volumes in MYPD3 decision Table 5: Revenue building blocks in MYPD3 decision Table 6: Primary energy costs assumed in MYPD3 decision Table 7: Derived allowed NPA revenue in MYPD3 decision Table 8: Revised standard tariff revenue in MYPD3 decision Table 9: MYPD2 RCA implementation decision Table 10: Standard tariff volumes revised for MYPD Table 11: Revised allowed revenue for MYPD Table 12: Allowed revenues, standard average prices and percentage price increases (revised) Table 13: Actual standard tariff results in 2013/ Table 14: Adjusting AFS Revenue to MYPD RCA equivalent for FY Table 15: Revenue note from AFS for March Table 16: International revenue for RCA adjustment Table 17: AFS- Revenue Table 18: MYPD3 Sales volume Table 19: GDP forecast assumptions during year Table 20: Change in assumptions relating to 2013/ Table 21: Sales volume variances for RCA Table 22: MYPD3 FY 2014 sales volume comparison Table 23: Recon of Total Sales from MYPD 3 Application to Actuals Sales Table 24: Estimated Load Shedding & Load Curtailment impact for 2013/ Table 25: Recon of primary energy from AFS to RCA (Extract: AFS FY 2014) Table 26: Primary energy actual costs per note 33 in the AFS of Table 27: Primary energy variances for 2013/14 RCA Table 28: IPPs costs and volumes Table 29: Actual energy procured through IPP programme in 2013/ Table 30: The net cost to be included in the RCA Table 31: MYPD 3 Assumptions vs. Actual FY Table 32: Start-up gas and oil - MYPD3 Decision Table 33: Nuclear Costs - MYPD3 Decision Table 34: Coal handling MYPD3 Decision Table 35: Approved Water Costs for MYPD Table 36: NERSA allowed R258m for fuel procurement for 2013/ Table 37: Other Primary Energy... 73

13 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 13 of 205 Table 38: Summary of net SAE position Table 39: Load shedding intensity - OCGTs limited to peak Table 40: OCGTs decision from MYPD Table 41: Summary of OCGTs results Table 42: Eskom Generation expansion plan MYPD 3 Application Table 43: Technical performance for the year to 31 March Table 44: Average Eskom coal power station heat rate for period 2011/12 to 2013/ Table 45: Breakdown of system UCLF (%) Table 46: Typical maintenance schedule for a coal-fired power station Table 47: Calculation average capex Table 48: CECA Calculation- Return due to/by Eskom Table 49: Regulatory asset base for 2013/ Table 50: Returns and percentage allowed in 2013/ Table 51: Capital expenditure in 2013/ Table 52: Approved capex portfolio mix Table 53: Reconciliation between Capex shown in the integrated report and CECA calculation Table 54: Capital Expenditure (excluding capitalised borrowing costs) per division Table 55: Inflation adjustment Table 56 : Summary of RAB inflation adjustments Table 57: Return on assets Table 58: Regulatory asset base Table 59: EEDSM MYPD3 Decision Table 60: Recon between demand savings MWs used in RCA Calculation Table 61: EEDSM in 2013/ Table 62: Actual DMP and Power Buy Backs in 2013/ Table 63: Actual Costs and Performance of PBB Table 64: The allowed employee costs for Generation, Transmission and Distribution Table 65: Allowed Maintenance Costs Table 66: Allowed Arrear Debts Table 67: Allowed Cost of Cover Table 68: Allowed Corporate Costs Table 69: Summary of Operating costs in 2013/ Table 70: Trend in actual employee benefits Table 71: Summary of SQI performance in 2013/

14 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 14 of 205 Table 72: Transmission SQI performance in 2013/ Table 73: Transmission number of major incidents (>1SM) Table 74: Line faults / 100km Table 75: Distribution SQI performance in 2013/ Table 76: Financial information for ratios in FY Table 77: EBIT Interest Cover Table 78: EBITDA- Total debt serviced

15 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 15 of 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 2013/14 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 2013/14 RCA balance (hereafter referred to as the 2013/14 RCA Submission which replaces that provided to NERSA 28 January Information is supported by Eskom s 2013/14 audited annual financial statements 1.1 The basis of submissions The basis of this submission is derived primarily from section 14 of the MYPD Methodology 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: The nominal estimates of the regulated entity will be managed by adjusting for changes in the inflation rate Allowing the pass-through of prudently incurred primary energy costs as per Section 8 of the Methodology Adjusting capital expenditure forecasts for cost and timing variances as per Section 6 of the Methodology. 1 See in particular sections 14.0, 8.0 and 9.0 of the Multi-Year Price Determination Methodology 1 st Edition.

16 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 16 of Adjusting for prudently incurred under-expenditure on controllable operating costs as may be determined by the Energy Regulator 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 which, it states in the Introduction, has been developed for the regulation of Eskom s required revenues. 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. With this in mind Eskom s 2013/14 RCA Submission in this document has as their primary focus: Reporting on actual expenditures and revenue to be used in updating the RCA balances for 2013/14 ; Reporting on variances between (ex ante) allowed revenues as determined by the Energy Regulator for 2013/14 and actual revenue for the financial year, similarly between the (ex ante) assumed expenditures upon which the allowed revenues were based in determining the variances and equivalent actual expenditures for the financial year. Calculation of determined RCA balances for the 2013/14 year for review by the Energy Regulator. 1.2 The structure of 2013/14 RCA Submission The structure of the summary of 2013/14 RCA Submission provided in this document is guided completely by the MYPD Methodology, having particular regard for administrative aspects of the RCA set out in section 14. With this in mind an overview of the 2013/14 RCA submission is first provided summarizing RCA inputs and balances as calculated by Eskom.

17 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 17 of 205 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 ) III. Revenue Variances (Section 5) IV. Purchases from independant Power Producers (Section 8) V. Primary Energy - Coal Costs (Section 9) VI. Primary Energy Other costs (Section 10) VII. Primary Energy - Gas Turbine Generation Cost (Section 14) VIII. Capital Expenditure and Regulatory Asset Base (Section 15) IX. Inflation Adjustment X. Integrated Demand Management XI. Operating Costs (Section 18) XII. Service Quality Incentives XIII. Reasonability Test For each component of the RCA balance account actual expenditures for the financial year are reported along with information pertaining to the prudency of expenditure, an analysis of the variance of actual expenditure and revenues as determined by the Energy Regulator; and determined RCA balances calculated in accordance with the MYPD Methodology is included. The 2013/14 RCA Submission concludes with reasonableness tests such as EBITDA to interest payments and debt service cover ratio being assessed.

18 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 18 of Objective The objective of this 2013/14 RCA Submission is to provide the context for the Regulatory Clearing Account (RCA) process in terms of NERSA s MYPD Methodology requirements. The 2013/14 RCA Submission for the first 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 are provided. This submission is based on the revised MYPD Methodology, as published by NERSA during December There have been certain significant changes to the MYPD Methodology from that applicable to the MYPD 2 period. 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. This is aligned to the decisions undertaken during the MYPD2 RCA process. In summary the RCA mechanism allows Eskom the opportunity to achieve the initial revenue that was allowed during MYPD3 revenue decision because of sales volume variances. Furthermore, Eskom will be in position to recoup previously efficiently incurred costs in delivering electricity to South Africans.

19 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 19 of Overview of the 2013/14 RCA Submission Eskom s 2013/14 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 is motivated with evidence for prudent scrutiny by NERSA. Variances can be linked to two key sources: Increases in costs due to a changing environment and assumptions after the MYPD 3 decision; Assumptions made for purposes of the MYPD3 revenue decision which did not materialise. This document will highlight these factors and explain the reasons which lead to the RCA submission summarised in the table below. Table 1: Summary of 2013/14 RCA Submission

20 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 20 of 205 The 2013/14 RCA Submission of R22 789m is being submitted in terms of the MYPD Methodology. This submission is subject to NERSA s review, analysis and approval. This includes a combination of variances either in favour of Eskom or in favour of the customer. The impact of the RCA submission on the quantum and timing of future annual adjustments of the price of electricity will be determined after NERSA has firstly made a decision on the RCA balance and secondly on the implementation thereof. 3.1 Revenue The revenue variance of R11 723m was primarily as a result of lower electricity sales volumes attributable to standard tariff customers. Furthermore, the treatment of revenue relating to the negotiated pricing agreement during the MYPD3 decision contributed to the revenue variance. Lastly, Eskom has specifically excluded the loss of revenue attributable to load shedding impacts contributing to the volume reduction and thus is not being claimed through the RCA process. 3.2 Primary energy Due to the constrained electricity system and level of Generating plant performance, Eskom was required to operate a more expensive mix of generating 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. This resulted in R8 024m higher OCGTs fuel spend, extra net coal burn of R2 000m, more from local IPPs of R580m, regional IPP supply of R1 136m and additional other primary energy of R2 491m compared to the assumptions in the MYPD3 decision. The other primary energy variance was substantially linked to costs for startup gas and oil and nuclear fuel costs. The coal burn variance of R2 000m is a result of a combination of the positive volume variance of R1 378m in favour of the consumer and the negative coal price variance of R3 378 in favour of Eskom. The coal volume variance is attributable to lower coal production

21 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 21 of 205 volumes because of lower sales volumes and reduction in Generation coal plant performance levels compared to that assumed in the MYPD3 decision. Eskom has excluded the coal costs relating to the Medupi take or pay agreement of R1 040m and Kusile of R14m from the coal burn variance. In accordance with the MYPD Methodology the take or pay agreements don t qualify for inclusion in the RCA because there was no electricity produced and no coal burn has occurred. 3.3 Environmental levy The lower production volumes and the change in production mix resulted in Eskom incurring environmental levy costs of R312m less than the MYPD3 determination. The RCA methodology caters for taxes and levies as a pass through item which requires that under expenditures be paid back to consumers. 3.4 Net position of Southern African Energy (SAE) The net energy flow position for regional transactions changed from an assumed net import situation to a net export position in 2013/14 which results in an under spend of R1982m. This was attributable to lower imports from Cahora Bassa (HCB) as a result of reliability of the high-voltage direct current transmission lines. The net position of imports less exports was further affected by higher export sales due to regional demand which was supplied when capacity was available. 3.5 Capital expenditure variance Eskom s Company capital expenditure for regulatory purposes was R57.5bn which exceeded the NERSA assumption of R50.8bn by R6.7bn in 2013/14. The variance is attributable to higher costs linked to new build projects and Generation outage capex and partially reduced by lower expenditures incurred by Transmission and Distribution networks following Eskom s capital expenditure reprioritization process. To compute the capital expenditure clearing account (CECA) impact for the RCA technical and refurbishment capex are excluded before applying the return on assets of 3.36% which results in an overall CECA adjustment of R9m.

22 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 22 of Operating costs The MYPD Methodology requires that prudently incurred under-expenditure on controllable operating costs is paid back to consumers. However, when the situation is reversed the MYPD Methodology does not allow for prudently incurred overspend to be included in the RCA submission. During 2013/14 the operating costs expenditure of R50bn exceeded the decision of R40bn by R10bn and hence does not qualify for the RCA. This implies that Eskom has to absorb the over expenditure even though costs incurred were prudently required in delivering electricity. The main contributors to the over expenditure have been staff costs, maintenance, arrear debt, insurance and cost of cover. 3.7 Integrated demand management Eskom s integrated demand management (IDM) response strategy comprised demand side management programmes, demand market participation and power buybacks in 2013/14. The net position comprised paybacks for under achievement of MW savings for EEDSM of R316m and under expenditure for DMP of R905m. 3.8 Other income Other income relates to the sale of scrap assets of R198m which was received during the year. 3.9 Inflation adjustments Costs which do not have a specific adjustment mechanism will be subject to inflation adjustments per section of the MYPD Methodology. The inflation adjustment reflects any difference between the inflation rates as assumed by NERSA for purposes of the revenue determination, and actual inflation rates. Thus operating costs will qualify only for inflationary adjustments which amounted to R33m.

23 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 23 of Service Quality Incentives Eskom has exceeded the service quality incentives targets set by NERSA for Transmission and Distribution during 2013/14. This culminated in Distribution achieving a reward of R263m and Transmission receiving a reward of R76m equating to a total of R339m Reasonableness test Eskom has computed a reasonableness tests such as the EBITDA: Interest cover ratio and debt service cover ratio which reflect the need for the RCA decision that will contribute towards the recovery of full efficient costs and allow Eskom to earn a fair return. In the absence of an RCA adjustment, Eskom s financial results fall well below NERSA s own targets Conclusion The RCA balance submission of R million excludes any amounts attributable to the symmetrical treatment of operating costs which will require amendments to current MYPD Methodology. Therefore assuming that these amendments are applicable would result in the 2013/14 RCA submission being adjusted to R38 billion as disclosed in the Eskom Integrated Report of 2015.

24 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 24 of Factors impacting on 2013/14 RCA Submission 4.1 Timeline for application and decision The time lapse between Eskom preparing for the MYPD3 revenue application and its actual implementation date is at least 15 months. Taking into account that the MYPD3 is a 5 year decision it will potentially equate to a 75 month period in which many of the initial assumptions, policies, environmental and economic conditions will change. Thus the RCA mechanism will address the impact of these changes in assumptions made for the purpose of the revenue decision, compared to how it has unfolded in the actual mode. Figure 1: Time lag between application and actuals 13 Months 15 Months 27 Months 39 Months 51 Months 63 Months 75 Months Eskom MYPD3 Application Preparation (January 2012) Eskom Submitted (November 2012) MYPD3 Decision (February 2013) Apr-13 Apr-14 Apr-15 Apr-16 Apr-17 Apr-18 5 Year MYPD3 Window 4.2 Changes in fundamental assumptions since MYPD3 application Table 2: Key assumptions which have changed MYPD3 Application Current Situation Comment Sales forecast average growth 2% p.a. with starting value 217TWh in March 2013 Sales forecast average growth 0.9% p.a. with actual starting value 208TWh in March 2013 (- 9TWh less in base) Sales forecast did not materialize as anticipated and forecasts could have been on the optimistic side. Adverse economic situation exists globally with markets not recovering as expected.

25 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 25 of 205 MYPD3 Application Current Situation Comment Generation plant performance (Energy availability factor EAF) assumed of between 82%~83% over MYPD3 period Actual average EAF is approximately 75% Board decision made in June 2013 (post the MYPD3 decision of February 2013) to migrate from present low levels towards the 80:10:10 levels by 2019 (80% availability, 10% planned and 10% unplanned capability loss). New build commission dates for 1 st units: Medupi June 2013 Kusile /15 Ingula 2013/14 Sere 2013/14 Coal country compact of annual coal price increases of less than 10% OCGTs load factors assumed at 3% based on other combined assumptions materialising Capex R337bn over the five year period Staff costs complement of growing to New build commission revised dates for 1 st units: Medupi August 2015 Kusile July 2018 Ingula Jan 2016 Sere CO 31 March 2015 Efficiency savings implemented through business productivity programme. OCGTs actual load factors greater than 3% due to combined assumptions made at the time of the application not materialising Capex given the lower revenue decision, Eskom reprioritized capex to a projected portfolio of R251bn over the five year period. Revised staff outlook to cap numbers at and decreasing to by 2018 Due to increased labour unrests, contractor failures, and lack of proper project management capability, the new build projects have been delayed. Savings will likely be less than the MYPD3 assumption of 10% savings OCGTs were utilized as a last measure to avoid load shedding and resulted in higher usage of these supply options. In response to MYPD3 revenue decision Eskom has reprioritised its capex spend which resulted in capex reallocations between licensees. BPP savings initiative launched in the business

26 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 26 of 205 MYPD3 Application Current Situation Comment Maintenance More maintenance was undertaken than was initially envisaged Addressing the reduced plant performance and maintenance backlog Other Opex Implemented BPP saving plan Despite cost efficiency and saving programme other operating cost exceeded decision

27 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 27 of Revenue variance The regulatory clearing account (RCA) balance is calculated by determining the variances which arise by comparing the NERSA MYPD3 revenue decision to the actual Eskom sales for particular revenues and costs as provided for in the MYPD Methodology. The calculation of the revenue variance to be included in the RCA is in terms of section of the MYPD Methodology as shown below 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. The practical application of para is further guided by the Energy Regulator s 17 March 2014 RCA decision in that: The RCA methodology allows for the assessment of Eskom s total allowed revenue against actual revenue recovered from customers during the MYPD2 review period for inclusion of the revenue variance in the RCA balance. Actual revenue recovered from customers is reconciled to Eskom s audited Annual Financial Statements (AFS) consistent with para of the MYPD Methodology which provides that The review (of the RCA balance) will be performed on receipt of audited statements from Eskom. The information reported in this section of the submission focuses on: Reasons for revenue variance Allowed revenue as approved by the Energy Regulator Actual revenue as reconciled to Eskom s audited AFS Calculation of revenue variance for the year Reasonability test for volume variance is demonstrated

28 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 28 of Reasons for revenue variance The revenue variance is driven by lower volumes from standard tariff customer s lower volumes and the treatment of negotiated pricing agreements (NPAs). Firstly the lower volumes of GWh which occurred from standard tariff customers are multiplied by the standard tariff rate which results in a revenue shortfall of R 7 263m. Secondly, in the MYPD3 decision NERSA assumed too much revenue of R7 875m being received from NPAs resulting in an under recovery of R 4 484m from these customers. The revenue under recovery for the RCA is reduced by R24m as Eskom is not claiming revenue variances linked to load shedding volumes. This results in a total under recovery of revenue by R11 723m during 2013/14 for the RCA. 5.2 Allowed revenue Eskom receives revenue from three customer categories, firstly standard tariff customer, local negotiated pricing agreements (NPA) and international export revenue (across South African borders energy sold to neighbouring countries). History has shown that the NERSA revenue and price decisions mainly affect standard tariff customer, whilst the NPA revenue is based on bilateral contracts between Eskom and the counter parties and the international export revenue is also based on bilateral contracts with counter parties. Therefore it is important to know which customer categories are catered for in the MYPD3 decision. In order for Eskom to confirm the meaning of the revenue determination for MYPD3 and analysis of the MYPD3 decision and MYPD2 RCA implementation decision is provided below Step 1 Understanding the standard tariff impacts The table below reflects the extract from the MYPD3 decision made on 28 February 2013 which shows the price increases of 8% per annum, the allowed revenue, forecast sales to tariff customers and standard average price (c/kwh) and total expected revenue from all customers.

29 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 29 of 205 Table 3: Revenue allowed in MYPD3 decision In the MYPD3 decision, the sales to tariff customers in 2013/14 are disclosed as GWh and so forth with GWh applicable to 2017/18. However, comparing the volumes in the table above to the sales volumes outlined in the table below which is extracted from the MYPD3 decision highlights an issue relating to which customers are implied in the decision. In the detailed sales volume table below the standard tariff volumes is reflected as GWh for 2013/14. The difference between the allowed revenue table above and sales table is GWh ( GWh GWh) which is exactly the volume linked to negotiated price agreements (local NPA). Table 4: Sales volumes in MYPD3 decision

30 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 30 of Step 2 Matching costs and revenue Eskom allowed revenue comprises costs, depreciation and returns which add up to R906bn over the full period. As part of determining the allowed revenue, the NERSA will match the revenue to corresponding costs for production under primary energy component. In 2013/14 primary energy assumed was R5 1067m (primary energy costs) and IPPs of R2 686m totalling R m. Similarly the total primary energy costs for 2014/15 is R60 074m (R54 966m + R5 108m) and R71 605m (R56 779m + R14 826m) in 2015/16. Table 5: Revenue building blocks in MYPD3 decision The sum of primary energy costs and IPPs costs in allowed revenue table above are broken down in details under the primary energy table as shown below.

31 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 31 of 205 Table 6: Primary energy costs assumed in MYPD3 decision The detailed primary energy above reconcile to allowed revenue table except that in 2013/14 the total of R44 911m is reflected instead of the R53 753m. This is due to an error under the approved column for 2013/14 which is out by R8 842m attributable to the environmental levy in that year not being added in the final total Importance of net imports (Dx) costs in primary energy As mentioned earlier, Eskom conducts transactions with neighbouring countries which results in flow of electricity into and outside of South Africa through Southern African Energy (SAE). The net position of these transactions is defined as the difference between international electricity purchases less international electricity sales. If import volumes exceed exports it is termed net import and net export where exports are greater than import volumes. For regulatory purposes only the net position impacts on the revenue determination and is incorporated in the RCA. This implies that the gross costs and gross revenues relating to the transactions undertaken by SAE are excluded from the MYPD determination.

32 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 32 of 205 It is clear that in the detailed primary energy table there is no allowance for the full import purchases which historically averages about R3bn per annum. As highlighted in the table above NERSA has accepted Eskom s net import costs throughout the period with R611m being allowed for 2013/14. The treatment by NERSA of the net imports costs which excludes the gross costs of international purchases from HCB thus confirms that the corresponding SAE revenues do not form part of the total allowed revenue by NERSA in MYPD3. Hence the total allowed revenue in MYPD3 represents total local revenue (standard tariffs and negotiated pricing agreements) Step 3 Understanding the other customer impacts Having confirmed that the total revenue allowed in MYPD3 relates to only standard tariffs and NPAs, it is important to understand the impacts on NPAs. Taking the total allowed revenue of R m in 2013/14 and deducting the standard tariff revenue of R m results in the assumed NPAs revenue of R7 191m. Using the volumes linked to NPAs of 11303GWh implies that Eskom would obtain revenue from NPAs customers at an average price of 63.6c/kWh as disclosed in table below. However, historically this has been lower than the average selling price of electricity. Table 7: Derived allowed NPA revenue in MYPD3 decision Allowed revenue for Negotiated Pricing Agreement 2013/ / / / /18 MYPD 3 Allowed revenue from tariff based sales (R'm) Total expected revenue from all customers (R'm) Difference between total and standard - NPA (R'm) Forecast sales for NPA customers (GWh) Derived average selling price for NPA customers (c/kwh) Step 4 Subsequently, NERSA revised the allowed revenue for standard tariff customers After announcing the MYPD3 decision, NERSA subsequently informed Eskom of a change in the allowed revenue on 8 March 2013; which is summarised below.

33 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 33 of 205 Table 8: Revised standard tariff revenue in MYPD3 decision Nersa revised revenue decision (Rm) 2013/ / / / /18 MYPD 3 Revenue from standard tariff customers Revenue from standard tariff customers Reduction in revenue affected only standard tariff custom Step 5 - Confirmation of standard tariff volumes via MYPD2 RCA implementation decision Following the MYPD2 RCA decision of R7818m, NERSA made the MYPD2 RCA implementation decision on 17 September 2014 which reflects the standard tariff revenues as below. The revenue from standard tariff customers agrees with the revised lower tariff revenue highlighted in grey in step 4. Table 9: MYPD2 RCA implementation decision Thus the MYPD2 RCA implementation decision confirms the drop in allowed revenue is linked to only standard tariff customers. The implementation contains the exact selling price for electricity such as 70.75ckWh in 2014/15 and 76.41c/kWh in 2015/16 when compared to the initial decision prices. Therefore the only way to keep the selling price (c/kwh) unchanged when revenue has reduced would mean that the volumes linked to standard tariff customers would also have to reduce. This is presented in the table below which shows that the standard tariff volumes used for the MYPD2 RCA implementation is the same as per sales details in MYPD3 except for a

34 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 34 of 205 slight change under 2013/14 which now reflects GWh instead of original GWh. Table 10: Standard tariff volumes revised for MYPD3 Impact on standard tariff volumes - (MYPD2 RCA Implementation decision) This analysis confirms that the allowed revenue table (Refer table 1 in the MYPD3 Decision) in the original decision had incorrect volumes disclosed to be recovered from standard tariff customers. 2013/ / / / /18 MYPD 3 Revenue (R'm) Standard tariff sales volumes (GWh) Standard average price (c/kwh) Step 6 Revised allowed regulated revenue for MYPD3 in 2013/14 As shown earlier that the allowed revenue by NERSA is only for standard tariff customers and NPA customers. The total impact is summarised below: Table 11: Revised allowed revenue for MYPD3 Allowed regulated revenue in MYPD3 2013/ / / / /18 MYPD 3 Allowed revenue from tariff based sales (R'm) Allowed revenue from NPA based sales (R'm) Adjustment to achieve smooth price path Allowed Revenue in MYPD The above revenue table was confirmed with a letter of notification received from NERSA to Eskom stating that the allowed revenues and sales volumes for MYPD3 have been revised per the schedule below and should be used as the basis for calculating the standard tariffs. Table 12: Allowed revenues, standard average prices and percentage price increases (revised) 2012/ / / / / /18 MYPD 3 Forecasts sales to tariff customers (GWh)** Revenue Standard Customers Total Revenue from all customers Average Tariff (c/kwh) Increase in standard Tariffs 8% 8% 8% 8% 8% ** base on page 7 of 102 (Part 2 MYPD3 Tariff submission) Source: Reproduced from NERSA communication Table 1 (dated 8 March 2013)

35 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 35 of 205 The figures shown in the table above are used as the reference point for reporting allowed revenue and calculation of revenue variance for 2013/14. Total allowed revenue for 2013/14 is set at R m Step 7 Actual standard tariff selling price in 2013/14 During 2013/14 Eskom revenue from standard tariff customer was R m from a volume of GWh that equates to average price of 65.94c/kWh which reflects that Eskom implemented the NERSA decision. The marginal difference is linked to some fixed charges and time of use profiles. Table 13: Actual standard tariff results in 2013/14 Actual standard tariff results 2013/14 Actual revenue from standard tariff (R'm) Standard tariff sales volumes (GWh) Actual average rate applied (c/kwh) Allowed standard tariff (c/kwh) Step 8 Revenue RCA variance in 2013/14 In deriving the revenue RCA variance of R11 723m, the volume drop in standard tariff category was GWh that equates revenue variance of R7 263m. The balance of the variance is attributable to the original decision implying that Eskom could recover revenue from NPA customers at prices of 63.6c/kWh which is obviously far from reality which exacerbates our revenue variance for the RCA submission. Another way to interpret the revenue under recovery is that the lower sales volume of GWh should have resulted in a revenue shortfall of R11 723m if the average selling price had been 99c/kWh, which however was not the decision for 2013/14. Thus even if volumes sold were exactly the same as per the revenue decision, Eskom would under recover revenue of about R4bn per year attributable to the incorrect treatment of local NPAs as explained earlier. Eskom expects that this situation will apply throughout the MYPD3 period.

36 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 36 of Actual revenue Reporting allowed and actual revenue on an equivalent basis In the calculation of the revenue variance it is important to report actual revenue in terms of an equivalent basis to that of the MYPD allowed revenue which is to say that they need to be comparable. As a cost of service methodology 2, allowed revenue is built up from a predetermined set of qualifying costs established within the MYPD Methodology. Allowed revenue is therefore defined in terms unique to the MYPD Methodology. Alternatively, primary data under which actual revenue is reported is sourced from Eskom s audited Annual Financial Statements (AFS) which are compiled in accordance with International Financial Reporting Standards (IFRS) and requirements of the Public Finance Management Act, and the Companies Act. Given the difference in the way in which MYPD allowed revenue and AFS actual revenue is reported, direct comparison of these variables is rather meaningless. For actual revenue to be compared to MYPD allowed revenue it must be defined to be equivalent to that under which allowed revenue has been determined. In practical terms this means that actual revenue should align to the same underlying activities and costs as for allowed revenue. To place this squarely within the context of the MYPD Methodology we take as the starting point the definition of total allowed revenue set out in para 3.2 of the MYPD Methodology: AR = (RAB x WACC) + E +PE + D + TNC + R&D + IDM + SQI + L&T +/- RCA 2 NERSA describe the MYPD Methodology as,, a cost-of-service-based methodology with incentives for cost savings and efficient and prudent procurement by the licensee (Eskom).,,,. (Section 1, MYPD Methodology)

37 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 37 of 205 Where: AR = Allowable Revenue RAB = Regulatory Asset Base WACC = Weighted Average Cost of Capital E = Expenses (operating and maintenance costs) PE = Primary Energy costs (inclusive of non-eskom generation) D = Depreciation TNC = Transmission and Network Costs R&D = Costs related to research and development programmes/projects IDM = Integrated Demand Management costs (EEDSM, PCP, DMP, etc.) SQI = Service Quality Incentives related costs L&T = Government imposed levies or taxes (not direct income taxes) RCA = The balance in the Regulatory Clearing Account Total allowed revenue is therefore the sum of defined costs as provided for in the AR formula of the MYPD Methodology. 3 Eskom Holdings Company revenue is made up of electricity revenue and other revenue. Eskom s electricity revenue is recovered from 3 customer categories viz. standard tariff, local special pricing agreements and exports (international) customers. Other revenue includes amortization of deferred income, connection fees and cash upfront revenue. As reflected in section 3.2 of the MYPD Methodology, the MYPD3 revenue determination is based on the revenue requirements of the three licensees within Eskom: Generation, Transmission and Distribution. This means that other areas such as Eskom s international business (Southern African Energy) are unregulated and thus excluded. In addition revenue and costs relating to Eskom subsidiaries are also excluded as they represent unregulated activities. Therefore when determining the Eskom actuals costs and revenues for the RCA submission the reference point in the AFS is the Company accounts and not the Group 3 And adjusted on an ex post basis for incentive factors and risk management devices

38 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 38 of 205 accounts. This document deals with the revenue variance from standard tariff and local special pricing agreements customers only. As motivated above, actual revenue starts with values reported in Eskom s AFS and in accordance with IFRS. The steps taken to transform actual revenue as reported in Eskom s audited financial statements to MYPD equivalent terms are set out below Adjustments to AFS values to achieve the equivalent revenue for RCA Table 14: Adjusting AFS Revenue to MYPD RCA equivalent for FY2014 Revenue for RCA purposes (Numbers expressed in nominal R'm) FY2014 Revenue Refer step 1 Less: Revenue excluded from RCA International Refer step 2 Other revenue Refer step 3 External local revenue Add: internal electricity revenue 416 refer step 4 Equivalent Revenue reconciled to AFS Add: Revenue loss due to load shedding 24 Equivalent Revenue for RCA Step 1: Revenue as reported in Eskom s 2014 AFS Revenue from continuing operations of R m reported on page 81 of Eskom s 2014 AFS provides the starting basis for obtaining MYPD equivalent values for actual revenue. Table 15: Revenue note from AFS for March 2014 Source: Eskom Annual Financial Statements, 31 March 2014 page 81.

39 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 39 of Step 2: Treatment of International Sales Revenue as reported in the AFS is adjusted for international sales (i.e. cross border trade) so as to obtain equivalency with MYPD allowed revenue values. This is done as costs associated with cross border trade (i.e. import purchases) are not part of the MYPD revenue allowance and are removed from AFS revenue when reporting on RCA revenue variances. The international revenue of R5 887m for 2013/14 is disclosed in revenue statistics table (Refer Appendix A: Table 5 in the Supplementary Divisional Report FY2014). This revenue adds the environmental levy international component of R95m and deducts the revenue attributable to distribution international sales of R51m. Table 16: International revenue for RCA adjustment Step 3: Treatment of other revenue and Deferred Income Other revenue of R1 301m includes upfront payments and connection fees which are removed as it does not relate to electricity revenue. Deferred income of R143 m is removed as it does not relate to electricity revenue. Deferred income and capital contributions (i.e. other revenue ) are recognized as revenue in the AFS as highlighted in note 32 below. Table 17: AFS- Revenue

40 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 40 of Treatment of non-electricity revenue excluded from revenue In contrast to the AFS treatment as stated in the accounting policy note shown below, para of the MYPD Methodology 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. Having regard for para of the MYPD Methodology these two components of revenue dealing with capital contributions are removed from total revenue as reported in the AFS and credited under capital expenditure thereby reducing the regulatory asset base The accounting policy notes below describe the nature of the originating transaction as follows: Figure 2: Accounting policy - Deferred income in AFS for March 2014 Figure 3: Accounting Policy - Payments received in advance in AFS for March 2014

41 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 41 of Step 4: Adding back Internal Electricity Revenue and Unrecognised Revenue For Regulatory Reporting purposes, Internal Electricity Revenue is disclosed as part of Electricity Revenue as the Regulatory Reporting Manual (RRM) Volume 1 and 2 as gazetted by NERSA requires the internal electricity usage to be disclosed as such. However, internal electricity revenue of R416m is not shown separately in the AFS due to consolidation rules which states that only external transactions are reported. It is therefore setoff against internal costs and added back to total revenue for the purpose of reporting RCA revenue variance. Actual equivalent revenue for 2013/14 RCA is reported at R m Reported on an equivalent basis to MYPD 3 allowed revenue and reconciled to Eskom s audited financial statements. Further adjusted for load shedding impact. 5.4 Calculation of revenue variance for the year Revenue variance = Actual equivalent revenue Decision revenue Based on RCA equivalent actual revenue of R m and allowed revenue of R m, the revenue variance for 2013/14 RCA purposes is that Eskom under recovered revenue of R11 723m The revenue variance is attributable to lower sales volumes materializing when compared to the MYPD3 forecasts. The slower turnaround of the economic environment and the manner in which tariffs were computed are the driving forces to the under recovery of revenue. In determining the prices for 2013/14 there was an incorrect deduction of too much SPA revenue during the MYPD3 decision. It is important to remember that the revenue variance compares the revenue per the annual financial statements which is compiled on an accrual basis which means that revenue is

42 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 42 of 205 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 which implies that all revenue billed is collected. 5.5 Sales variance explanation Background The MYPD sales forecast is normally finalized in the 2 years preceding the MYPD determination. This becomes a high risk as many economic assumptions may change during this period while the MYPD submission is analyzed and a determination is made. In the case of MYPD3, the MYPD sales forecast was finalized on 14 September 2011 when the prospects for a higher economic growth were still viable while recovering from the recession in 2007/08, refer to the red dotted line in the figure below. The blue line is the actual Gross Domestic Product (GDP) rate. The green line represents the MYPD3 decision sales growth compared to the brown line that represents the actual sales growth. Figure 4: GDP Vs Sales growth

43 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 43 of 205 Table 18: MYPD3 Sales volume Total Eskom Sales (GWh) 2012/ / / / / /18 MYPD3 Sales Decision % Growth -1.1% 2.21% 0.81% 2.20% 1.92% 2.01% Actual Sales % Growtrh -3.63% 0.62% The table above shows the sales assumption for the MYPD 3 decision over the 5 year period. The MYPD3 sales growth over the 5 year period (i.e. 2013/14 to 2017/18 volumes) was assumed to be 7.3 % while the actual average growth rate per annum amounts to 1.8% The process in deriving the 5 year forecast The 5 year sales forecast used in the application was compiled by each of the six Eskom regions forecasting the regional sales using a bottom up approach from a customer level upwards for their specific regions. Each regional forecast was scrutinized after which the six regional forecasts and the Top Industrial Customer s forecast were then consolidated into one Eskom view Critical assumptions relevant during 2011 in deriving forecasts Table 19: GDP forecast assumptions during year MYPD GDP Growth % 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 Sales volume variance explanation for FY2014 Eskom has adjusted the sales volume variance by the load shedding impact.

44 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 44 of 205 Table 20: Change in assumptions relating to 2013/14 MYPD3 Assumptions MYPD3 Actual The GDP assumption for FY14 during 2011 The GDP that materialized for FY14 was 1.9%. when the submission was made, was assumed to be 4% This drastic lower GDP manifested itself in contributing to the much lower growth - mainly in the Municipalities. The variance in the Municipality category was GWh lower than forecasted and it was mainly attributed to the lower GDP growth that materialized. In 2011 it was assumed that the high price The price (c/kwh) in FY 2010/11 was 40.4 c/kwh increases will continue for the next 3 years on average and it increased to c/kwh in FY (25% up to FY15). The current price is already 2013/14. This increase in price was also +/- 2.7 times what it was in 2008/9. contributing to the lower consumption across most of the Eskom customer base. Price elasticity and DSM will lower the growth Due to the higher cost of electricity the customers especially in the earlier years. embarked on an energy savings drive to lower their consumption to save money. Eskom were also involved in promoting DSM which reduced the energy consumption mainly in the Residential and Municipality sector and this contributed to the lower Municipality category sales. Municipality generation assumed for PPA up to After the termination of the PPA deals with the 2013/14, thereafter normal own generation. municipalities, own generation was not resumed as it was too expensive and the municipalities took full supply from Eskom - offsetting the lower consumption trends. A substantial amount of furnace load will not The Industrial category realized a drop in be utilised in winter because of the high winter consumption as compared to the forecast of prices. Furnace utilisation will be about 95% in GWh. the summer months. The main contributor to this unfavourable variance is from the assumption that the high prices will result in less furnace running in winter which was too optimistic. Much more furnace load was

45 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 45 of 205 Large Co-gen projects that are in an advanced stage in the commissioning process have been included in the budget. High probability new projects are included. Commodity price assumptions were made while expecting some growth. taken out to do maintenance during the very high winter prices than anticipated. The Ferro and Steel smelting sector realized a drop in consumption of GWh. Also the high summer utilization did not fully materialize due to lower orders received by the smelters as a result of low demand for their product. Co-generation projects for Sasol SSF were taken into account and it was mostly on target. Sasol infra Chem also started up a very successful gas co-generation plant which displaced 466 GWh and this was not included in the forecast. The Mining category realized a drop in consumption as compared to the forecast of GWh. The Platinum environment was identified as a growth area with most of the new projects that resided in this sector. The Platinum sector realized a GWh drop in consumption against the budget due to mainly labour unrest which caused shaft closures and project to be delayed and some projects were also cancelled in the Platinum sector. The Gold sector realized a GWh drop in consumption against the budget due to cost pressure as a result of labour unrest and high salary increases which caused down scaling and shaft closures in many of the Gold mines. We also had some Gold mines that were liquidated. The unfavourable commodity prices also played a major role in escalating the cost pressures.

46 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 46 of 205 Table 21: Sales volume variances for RCA Sales volumes (GWh) 2013/14 Actual volume variance Less Load shedding impact 54 Adjusted volume variance after load shedding The table below shows the actual sales volume variance before the load shedding impact: Table 22: MYPD3 FY 2014 sales volume comparison From the table above, which reflects the variance between the MYPD NERSA decision and Actual sales for year 2013/14, it reflects that the unfavourable (i.e. lower) variance of TWh is mainly attributed to three categories, namely Redistributors, Industrial and Mining. The unfavourable variances in these three categories were partially offset by the favourable (i.e. higher) variance of 2.49 TWh from the import - export sales. The reasons for the variances are cited below:

47 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 47 of 205 Table 23: Recon of Total Sales from MYPD 3 Application to Actuals Sales 2013/14 MYPD3 Application Sales (GWh) MYPD 3 YoY Forecasted sales growth (%) 2.3% Redistributors (3 680) Ethekwini Electricity (130) City of Tshwane Metro (391) City of Cape Town (627) City Power of Johannesburg (472) Rustenburg Local Municipality (486) Ekurhuleni Metro (103) Nelson Mandela Metro (308) Emfuleni Local Municipality (75) Other (1 087) Industrial (5 156) Iron & Steel Sector (1 081) Ferro Chrome Sector (2 146) Ferro Manganese Sector (645) Ferro Silicon Sector (411) Paper & Pulp (464) Steam & Hot water Supply (308) Manufacturing of basic Chemicals (216) Aluminium 52 Other 63 Mining (3 555) Platinum (2 159) Gold (1 353) Other (43) International Other 490 Total Actual/Projection sales (GWh) Actual YoY sales growth (%) 0.6% Redistributors: GWh unfavourable The unfavourable variance in this category is spread over most of the Municipalities and Metropolitan areas and is mainly due to the following: The largest unfavourable impacts are seen in City Power and Ekurhuleni Metro s due to the slow economic growth. City Power and Ekurhuleni are within the economic hub of South Africa and thus are severely affected by the slow local economic growth.

48 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 48 of 205 Other Metro s and Municipalities were also negatively affected due to the slow local economic growth. Due to the global economy that did not pick up as expected and the poor ZAR exchange rate, the manufacturing sector linked to the bulk meters in the municipalities were not able to secure orders, thus producing less with a resultant drop in energy consumption. Price elasticity responsiveness played a role in driving savings from customers, especially in the lower Living Standards Measure (LSM). The closure of EB steam customers by Eskom also affected the sales unfavourably especially in the Western Cape, Eastern Cape and KZN Industrial: GWh unfavourable This category was most affected and is mainly due to: Power Buy Back s that were implemented GWh were bought back by Eskom from the large industrial customers. Sasol Infra Chem commissioned their own gas generation plant and displaced 466 GWh during the year. The Ferro and steel smelting industry realized a drop in consumption against the decision of GWh due to the higher winter peak prices, low demand for their product and unfavorable commodity prices that led to diminishing orders. The smelting industry opted to do maintenance during the three winter months during which electricity prices are higher Mining: GWh unfavourable This category was also severely affected and it is mainly due to the Gold and Platinum sectors: The Platinum sector realized a GWh drop in consumption to mainly due to labour unrest which caused shaft closures and delays and cancellations in some projects in the Platinum sector. The unfavourable commodity price also affected the platinum sector negatively.

49 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 49 of 205 The gold sector realized a GWh drop in consumption due to cost pressures as a result of labour unrest and high wage increases which caused down scaling and shaft closures in many of the gold mines. In addition some Gold mines were liquidated. The unfavourable commodity price also played a major role in escalating the cost pressures Prepayment: 324 GWh favourable With the role out of the electrification programme in recent years a number of preprogrammed vending machines or Cash Dispensing Units (CDU) were stolen and electricity is currently being sold illegally from these machines. The tokens can be used on the Eskom prepayment system, but no revenue is recovered by Eskom it only increases the electricity theft from Eskom. However, due to a dedicated programme by Eskom to change the supply group codes eliminated most of the ghost CDU s in the Northern Region. The prepaid environment in that Region now shows a significant favorable variance against the MYPD3 NERSA decision, resulting in higher sales volumes than anticipated in the MYPD3 NERSA decision International: GWh favourable. 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

50 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 50 of 205 Botswana failed to bring its new Morupule B coal-fired power station into commercial operation, resulting in a significant supply deficit in that country. Eskom agreed to continue supplying 100MW on a firm basis (which is withdrawn if South Africa is exposed to rotational load shedding) and additional capacity subject to availability. For 2013/14, 15% of the international sales have occurred during peak periods, 38% during standard hours and 47% during off-peak hours. 5.6 Load shedding in 2013/14 Rotational load shedding was introduced again in 2014 due to the power constraints. These load shedding activities have negatively affected the Eskom energy sales consumption. Unfortunately these impacts cannot be accurately determined as it was not actively measured. The best indication of its impact on the Energy sales consumption is an estimate of the energy lost that is derived from the demand (MW) that the System Operator has requested the various customers to shed each hour Estimated Load shedding & Load Curtailment impact for YR 2013/14 Table 24: Estimated Load Shedding & Load Curtailment impact for 2013/14 GWh Revenue (Rm) energy C/KWh Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Total 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

51 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 51 of 205 demand to be shed was a request to the customers and they could have shed more or less during those hours. These figures 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 have ended, some of the load (energy consumption being impacted), did return. To be able to put estimated revenues to the estimated load shedding consumption impact, the total average energy price for the month was used to calculate the revenue. This average is used due to a lack of information on which tariffs were shed for what duration. During load shedding only the energy portion of the revenue calculation will be lost and not the fixed charges and demand charges. 5.7 Other income Revenue from sale of scrap assets 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 R198m from the sale of scrap assets. 5.8 Conclusion of revenue variance The revenue variance of R11 723m calculated and explained above is consistent with the requirements of the Regulatory Framework i.e. rule

52 Production Volumes (GWh) MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 52 of Factors which influence Eskom production plans Sales are a critical factor which influences production plans which are supplied during the year. 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 of the existing fleet all contribute to the eventual the 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 9 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 5: Production FY Production FY 2014 Sales (TWh) MYPD3 227 Actuals 218 OCGTs New build IPPs Imports Other Coal MYPD3 Actuals

53 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 53 of Primary energy Primary energy is Eskom s largest operational cost category with R69bn having being incurred during 2013/14. However, for regulatory purposes the cost of international purchases of R3.3bn are excluded except in the case of a net import situation, and for the emergency energy acquired through regional IPP contracts such as Aggreko which cost R1.1bn over the year which results in R67bn of primary energy costs qualifying for the RCA. In the case of a net export situation the primary energy cost related to the net export volume is deducted from the total primary energy cost. Table 25: Recon of primary energy from AFS to RCA (Extract: AFS FY 2014) Recon of primary energy from AFS to RCA FY2014 Own generation costs Environmental levy International electricity purchases Independent power producers Other 519 Total Primary energy per AFS Adjustments for RCA : Exclude : International electricity purchases Include : Aggrekko IPP Total Primary energy for RCA (R'millions) Primary energy costs of R69 812m incurred in 2013/14 is seen in the extract from the AFS of March 2014 as outlined below.

54 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 54 of 205 Table 26: Primary energy actual costs per note 33 in the AFS of 2014 Total primary energy cost have exceeded the MYPD3 decision by R14 087m comprising of local IPPs of R580m, coal burn of R2 000m, other primary energy costs of R2 491m, regional IPPs of R1 136m, OCGTs of R8 024m and road repairs of R169m. These variances are reduced by under expenditure of R312m relating to environmental levy. For RCA purposes there are specific rules applicable to the different primary energy categories. Table 27: Primary energy variances for 2013/14 RCA Primary energy for 2013/14 RCA Submission (R'm) R millions Coal burn Coal volume Coal price Independent Power Producers (IPPs) 580 Regional IPP Open cycle gas turbines (OCGTs) Other primary energy Environmental levy -312 Road repairs 169 Primary Energy

55 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 55 of 205 With the above in mind, the information reported in this section of the submission focuses on the following components of primary energy: Independent Power Producers (IPPs) Coal burn variance Other Primary Energy (excluding IPPs and OCGTs) Open Cycle Gas Turbines (OCGTs) Allowed costs for respective primary energy areas Actual costs for respective primary energy areas reconciled to Eskom s audited AFS Calculation of cost variances for respective primary energy elements for the year.

56 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 56 of 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. 8.1 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 MW (excluding one contract that was awarded but never became operational due to IPP failure to meet obligations). Between 1 April and 31 December 2013 there were three contracts (totalling 255,6 MW) in operation under this programme, and from 1 January 2014 to 31 March 2014, 2 contracts (totalling 253 MW) in operation. 8.2 Municipal Base-load Purchases Following continued capacity concerns Eskom approached municipalities to assist with additional generation. During the 2013/14 financial year there were two contracts awarded (City Power for 420 MW and City of Tshwane for 165 MW). There was no energy purchased under the City of Tshwane contract during the year. 8.3 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 2014 the combined contracted capacity under the STPPP was 289 MW. 8.4 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

57 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 57 of /14 year 81 MW of capacity was contracted. 8.5 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 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 Commissioning of Dedisa is expected in the second half of 2015, while Avon is expected during the first half of These did not produce energy during 2013/14 as anticipated 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 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. As at 31 March 2014, a total of 191 MW had achieved early operating or commercial operation. The renewable projects with signed PPAs are in various stages of the construction phase. The first project under the RE-IPP was connected to the grid in September 2013, and the first IPP was commissioned in November 2013.

58 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 58 of Legal basis for IPPs per the MYPD Methodology Section 9 in the MYPD Methodology deals with the treatment of IPPs: 9.1 In accordance with the provisions of Section 14(f) of the Electricity Regulation Act, the Energy Regulator shall, as a condition of licence, review power purchase agreements (PPAs) entered into by licensees before signature. This also includes all PPAs considered under the Ministerial Determination by the Department of Energy (DoE). In evaluating the MYPD, the cost associated with the Independent Power Producers (IPPs) will be done based on the conditions of the respective PPAs. 9.2 The Energy Regulator will review the efficiency and prudency of the IPP before and after PPA contracts are concluded. 9.3 Purchases or procurement of energy and capacity from IPPs, including capacity payments, energy payments and any other payments as set out in the PPA, will be allowed as a full 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 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. 8.7 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. 8.8 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: 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 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.

59 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 59 of IPP allowed costs for 2013/14 In the MYPD3 decision NERSA had awarded Eskom a total of R2 545m for energy related costs for local IPP costs as summarised below. These costs covered Eskom own IPPs under the MTPPP of R1 523 m and Short Term programmes of R1 022 m. No costs were assumed for renewable IPPs and the DOE peaking stations for 2013/ MTPPP allowed costs in MYPD 3 for 2013/14 Table 30: Approved MTPP Costs for MYPD3 The MTPPP costs were adjusted based on the signed contracts and terms of the Power Purchase Agreements (PPAs) Short Term IPPs allowed costs in MYPD 3 for 2013/14 Table 33: Approved Short Term Purchases The existing Power Purchase Agreements (PPAs) were considered together with the potential of other IPPs that are in MTPPP (after expiration of the agreement) joining the STPPP.

60 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 60 of Renewable IPPs allowed costs in MYPD 3 for 2013/ Renewable Energy IPPs Table 31: Approved Renewable Energy Costs for MYPD3 R'm 2012/13 Approved Expenditure 2013/ / / / /18 MYPD3 Total Renewable Applied For Renewable Adjustments (1 428) (4 747) (636) Approved Renewable The revised Commercial Operation Dates (CODs) for the first round IPPs and the second round IPPs were used to calculate the costs. Also included is the third round of the procurement programme as determined by the Minister of Energy IPP renewable energy procurement programme DOE Peaking allowed costs in MYPD 3 for 2013/14 Table 32: Approved DoE Costs Peaking for MYPD3 R'm 2012/13 Approved Expenditure 2013/ / / / /18 MYPD3 Total DoE Peaking Applied For DoE Peaking Adjustments (1 001) (2 841) (1 952) (374) 313 (5 855) Approved DoE Peaking In calculating the allowable costs for this project, the delayed financial close for the Avon and Dedisa plants together with the construction periods required for these plants before they come on line were considered. Allowed total IPPs costs for 2013/14 is R2 545m 8.10 Actual IPP costs for 2013/14 Eskom incurred costs of R3 266m relating to energy costs for Iocal IPPs during 2013/14.

61 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 61 of 205 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 405 GWh more energy from IPPs when compared to the MYPD3 decision in 2013/14. A summary of the costs and volumes from IPPs are presented in the table below: Table 28: IPPs costs and volumes Independent Power Producers FY 2014 Costs (R'million) Volumes GWh Average R/MWh Actuals Decision Variance Actuals Decision Variance Actuals Decision NOTE REF # Non-renewable programs MTPPP A STPPP (including Munics) B WEPS C Renewable IPP's Renewable IPP's - energy D Renewable IPP's - deemed energy payment D DOE Peaker Total IPP energy costs IPP ancilliary costs E Total IPP costs The costs of R3266 m incurred in 2013/14 is highlighted in the extract form Eskom s Integrated Report 2014 below:

62 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 62 of 205 Table 29: Actual energy procured through IPP programme in 2013/14 Source: Integrated Report 2014, Page 145 Actual IPP costs incurred for 2013/14 is R3266 m Reasons for IPP variances in 2013/14 A. Medium Term Power Purchase Programmes (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 submission. 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.

63 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 63 of 205 B. Short Term Power Purchase Programmes (STPPP) At the time of the MYPD3 application 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. 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: NERSA removed the REIPPP generation from the MYPD3 decision for the 2013/14 financial year so no price expectation is reflected in the decision. The application expected an average price of R1 977/MWh while the actual was substantially lower at R1 557/MWh reflecting the larger component of early operating energy produced by generators during 2013/14 which comes at a discount to the commercial energy rate. Volume variance: The expected energy in the MYPD3 application for 2013/14 was 722 GWh; this was removed in the regulatory decision. Actual energy produced by REIPP generators was 250 GWh. E. 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).

64 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 64 of 205 There were no deemed energy payments to IPPs during 2013/ IPP variance for 2013/14 RCA IPP variance = Actual IPP costs Allowed IPP costs Eskom spent R3 266m for local IPPs which exceeded the IPP allowance of R2 545m resulting in an over expenditure of R721m during 2013/14 F. Transmission Ancillary Costs NERSA approved R141m for Transmission ancillary costs in the MYPD3 determination for FY 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 2014 there were no payments for use of system charges and thus Eskom has over recovered by R141m which must be paid back through the RCA process. 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 2013/14 by R141 m 8.12 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 mandated its Southern African Energy (SAE) Unit to enter 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.

65 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 65 of 205 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. 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).

66 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 66 of 205 This project was used as a lever to contribute towards the supply and demand challenges witheskom incurring R1 135m costs to acquire energy from regional sources. Regional IPP variance = Actual costs Allowed costs Eskom incurred R1 135m in 2013/14 against a zero allowance in the MYPD3 decision resulting in this variance being included in the RCA submission

67 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 67 of Coal Burn Cost 9.1 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 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) 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 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 The coal benchmark price will be compared to Eskom s actual cost of coal burn (R/ton) using a Performance Based Regulation (PBR) formula. The PBR formula is the maximum amount to be allowed for pass-through, calculated by applying the following formula PBR cost (Rand) = (Alpha x Actual Unit Cost of Coal Burn+ (1 Alpha) x Coal burn : Benchmark price) X Actual Coal Burn Volume Where: Actual Cost = Actual unit cost of coal burn in a particular financial year Benchmark

68 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 68 of 205 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 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 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 The coal stock level (stock days) will be reviewed by the Energy Regulator when necessary. 9.2 Extract of MYPD3 Reasons for Decision on Coal costs Table 18: Approved Coal Burn Costs for MYPD3

69 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 69 of The reasons for adjustments in coal burn costs are due to the reduction in the burn rate from 0.57 to 0.56 tons per MWh. It is expected that Eskom target a burn rate of 0.56 tons per MWh which represents a normal deterioration in station efficiency from the current 0.55 tons/mwh due to ageing infrastructure. The rand per ton amount that was approved in MYPD2 has been adjusted by 10% p.a. after considering the historic mining inflation experienced by Eskom together with specific input from the mining industry, for the first year of MYPD Coal burn RCA variance impact In deriving the coal burn RCA impact, Eskom deducts upfront the costs relating to coal which are incurred but don t result in burn and energy being produced (Medupi and Kusile take or pay payment contracts). The actual coal costs of R35 927m were reduced by deducting the R1 054m take or pay contractual amount which results in cost of R34 873m. The above PBR formula was applied resulting in a net coal burn variance of R2000m as disclosed below. Table 30: The net cost to be included in the RCA Coal burn pass through FY2014 Coal burn Price variance to included in RCA Coal burn Volume variance to be included in RCA Coal burn costs be included in the RCA (R'million) 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 31: MYPD 3 Assumptions vs. Actual FY14 MYPD3 FY14 Assumptions Cost Plus and Fixed Price mines produce at expected levels, except for Arnot New long term mines are producing Prices from future medium term contracts have been based on existing contractual Actual FY14 Cost Plus and Fixed Price mines produced below expected levels Coal could not be accepted for Medupi Power Station The actual contracted price of new short and medium term coal contracts was higher than

70 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 70 of 205 MYPD3 FY14 Assumptions delivered cost. Coal qualities have been adjusted to reflect the impact of the washing plants. Water infrastructure is old. Tariff increases are expected to pay for the refurbishment The new power stations (Medupi and Kusile) use flue gas desulphurization (FGD) at 0.45 litres per units sent out (l/uso). Actual FY14 expected. Some delays were experienced with coal quality improvement initiatives, primarily because of funding constraints. Tariff increases for infrastructure were not higher than expected. However, the future impact of the new Water Pricing Strategy is unclear. Medupi did not come online as assumed Lower electricity production from coal fired stations Total coal burnt was 4 860kt less than planned. The coal fired power stations generated MWh less than have planned. This resulted in the positive volume variance Different mix and efficiency of power stations generating electricity The utilization 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. This resulted in some of the coal being moved from Duvha Power Station to other power stations. The delay in commissioning of Medupi Power Station. The under production of Arnot and New Denmark collieries (3.1 Mt) Need to have coal to support production at Return to Service RTS stations, Majuba and Tutuka. The effects of industrial actions at the mines during the financial year.

71 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 71 of Other Primary energy The MYPD methodology allows for other primary energy as pass through. Coal burn, OCGTs, IPPs and environmental levy have specific rules. MYPD Methodology - Other Primary Energy Costs Other primary energy costs such as nuclear, hydro, and sorbent, will be allowed as pass-through costs 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) Allowed other primary energy in 2013/14 Other primary energy costs assumed for 2013/14 in the assumptions made for purposes of the revenue MYPD3 decision was R5 208m as disclosed with some of the decision elements are presented hereafter Start up gas and oil allowed for 2013/14 NERSA did not adjust Eskom s assumptions (as reflected in its MYPD3 revenue application) for purposes of its revenue decision thus NERSA assumed costs in 2013/14 of R1 511m as disclosed below. Table 32: Start-up gas and oil - MYPD3 Decision

72 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 72 of Nuclear costs allowed for 2013/14 The fuel used at Koeberg is wholly imported. Consequently international benchmarks (Rand per kilogram) were used to determine the approved price. Table 33: Nuclear Costs - MYPD3 Decision Coal handling costs allowed for 2013/14 For purposes of the MYPD3 revenue decision NERSA had assumed R1 056m for coal handling based on previous performance. Table 34: Coal handling MYPD3 Decision Water costs allowed for 2013/14 Table 35: Approved Water Costs for MYPD3

73 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 73 of Fuel procurement costs allowed for 2013/14 Table 36: NERSA allowed R258m for fuel procurement for 2013/14. Allowed Other Primary Energy in 2013/14 is R5 208 m 10.2 Actual other primary energy in 2013/14 Eskom incurred R7 699m relating to other primary costs during 2013/14 which is summarised in table below. Table 37: Other Primary Energy Other Primary Energy MYPD3 Decision Actuals RCA 2013/ /14 Water Startup Gas & Oil Coal Handling Water treament Nuclear Fuel procurement Sorbent Other Primary energy (R'millions) Actual other primary costs incurred in 2013/14 was R7699 m

74 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 74 of 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 2013/14 than what was anticipated at the time of the MYPD3 application and hence the use of fuel oil increased significantly as well Correlation between start-up gas and oil and UCLF There is a strong correlation between an increase in UCLF and an increase in fuel oil costs. As the number of unplanned breakdowns increase, so does the number of start-ups to bring the unit back into operation increase and hence the increase in fuel oil needed for start-ups. At the time when the MYPD3 application was made in 2011/12, one can see that based on historical trends for the period 2009 to 2012, fuel oil costs were consistently in the region of R1bn to R1.2bn in that period. Generation did not anticipate that UCLF would increase significantly from 2012/13 onwards and hence that fuel oil costs would also increase significantly. Figure 6: Correlation between fuel oil costs (Rand m) and UCLF High component of fuel costs exist at Arnot, Duvha, Kriel and Tutuka power stations. The RTS stations (Camden, Grootvlei and Komati) also have high fuel oil costs. The price of fuel oil is mainly driven by the US dollar price of fuel oil and thus is not under 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.

75 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 75 of 205 The key reasons for the increase in volume of fuel oil used are: Increased number of Unplanned automatic grid separations (UAGS) trips and start-ups from significantly more unplanned outages Impact of deteriorating coal quality Diminished mill performance Warm and cold light-ups Increased boiler tube leaks High fuel oil usage resulting from combustion problems on the boiler and fuel oil support to the units to avoid load loss High fuel oil burn due to the Hendrina Power Station inclined coal conveyor fire incident, which resulted in a reduced supply of coal to the plant and the need for usage of fuel oil to sustain combustion because Unit 5 and 6 were only receiving half of the normal coal supply. Shutdown for planned low pressure blade and high pressure pipe work inspection Reasons for nuclear costs variance A variance of R884m occurred due to higher expenditure. The main reason for the nuclear fuel costs being higher than what was originally assumed was a once-off adjustment to the nuclear spent fuel decommissioning provision of R830m. Periodically an engineering study is commissioned to determine whether the estimate for nuclear spent fuel decommissioning costs, and the related provision, is still valid. Depending on the outcome of the study, the long term provision can be adjusted either upwards or downwards Reasons for provision increase Transient Interim Dry Storage: The fuel management strategy at Koeberg has now changed to incorporate low-burn up (highly reactive) spent fuel that would require special measures (e.g. neutron absorber inserts) for its management. Furthermore, more spent fuel assemblies will be discharged from the reactor to make way for the larger fresh fuel reload batches as part of the strategy to increase Koeberg s energy output. A bulk of old spent fuel assemblies will need to be transferred to a transient

76 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 76 of 205 interim (dry) storage facility on Koeberg site, which has become a significant additional cost. Centralised Interim Dry Storage: Here the main cost factor has been the dramatic increase in the price of the dry storage casks. The cost for the dry storage facility was further adjusted following the conceptual study conducted in The other costs (encapsulation, repository, transportation etc.) reflect normal cost escalation in line with the inflation rate Reasons for coal handling costs variance A variance of R377m 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 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 Arnot Implementation of the staith bypass project (not anticipated at the time of the MYPD3 application) meant that maintenance costs on the buffalo feeder was a new cost driver that was added to Arnot s coal handling costs Grootvlei The strategic stock pile had to be re-built; additional yellow plant was hired in December Furthermore, 2x rollers were added in January Low deliveries and wet coal coming to the station from the mines, led to coal being reclaimed from the stockpiles and sent to the stations.

77 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 77 of Komati The strategic stock pile had to be increased to cater for the additional units at the station being re-commissioned; additional vehicles were hired in. Low deliveries and wet coal coming to the station from the mines, led to more tons of coal being reclaimed and sent to the stations. Another impact was that the vehicle hours increased, leading to increased coal handling costs Reasons for water costs variance A variance of R295m 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 Water volumes The volumes of water consumed are driven primarily by the electricity produced by the power stations. The volume consumed to generate a unit of electricity varies per power station, so the total consumption will depend on the mix of stations used to generate electricity. Older stations consume more. Most of Eskom s stations are beyond the halfway mark of their lifespans. 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 FY14 was 1.35 l/uso, excluding Komati. Due to the delay in commissioning of the new dry cooled power stations the water performance did not reduce to 1.2 l/uso as had been assumed by NERSA for purposes of its revenue decision.

78 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 78 of 205 The continuous rains into March 2014 contributed to water saving at power stations. Otherwise, consumption would have been higher. The volume of water consumed was 3.69 Mm 3 less than assumed Reasons for fuel procurement costs variance A variance of R79m 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 Other primary energy variance in 2013/14 RCA Other Primary energy variance = Other PE Actuals Other PE decisions Actual other primary costs of R7 699m was incurred during 2013/14 which is more than the costs assumed in the decision of R5 208m that resulted in an over expenditure of R2 491m which is included in the RCA submission

79 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 79 of Road Maintenance Eskom spent R169m more for road repairs. The deteriorating condition of 1200 km coal haulage roads in the Mpumalanga Province were mainly caused by the large volumes of coal trucks that were using the roads. The condition of the roads deteriorated to such an extent that it had become a threat to the safety of the general public, employees, truck drivers and ultimately coal supply to the power stations. Major stakeholders, especially local businessmen and communities were threatening to blockade coal haulage routes and protest against coal trucks should Eskom not address the condition of roads urgently. The MYPD3 revenue decision did not assume any costs for road repairs. Road repairs variance = Actual road repairs costs Decision road repairs costs Eskom spent R169m on road repairs in 2013/14 against a zero allowance in the MYPD3 decision results in the full amount being included in the RCA submission

80 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 80 of Environmental levy The MYPD methodology allows for (under)/over recovery to be adjusted through the RCA mechanism as presented in the extract below: 13. Taxes and Levies (not income taxes) 13.1 The Government imposes certain taxes and levies that are payable by Eskom Levies are any charges that the Government may impose and payable by Eskom arising from its licensed activity 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 Principles regarding taxes and levies The taxes and levies are exogenous and will be treated as a pass-through cost in the MYPD Taxes and levies will be treated as a separate account in the Eskom revenue determination Eskom must ensure that the cost of the taxes and levies is specified and that the calculation thereof is clear and concise The amount provided for the taxes and levies must be ring-fenced and any over or under-recovery will be recorded in the RCA. The lower production volumes and the change in production mix resulted in Eskom incurring environmental levy costs less than the MYPD3 determination culminating in a over recovery of R312m. 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. Environmental levy variance = Levy Actuals Levy decision Eskom incurred actual environmental levy costs of R8 530m which was lower than the assumed levy costs of R8 842m in the MYPD3 decision equating to under expenditure of R312 m

81 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 81 of Net position of Southern African Energy (SAE) The net impact of SAE is influence by the net electricity volume position and the rates charged for import and export volumes. During 2013/14 the decision assumed that imports would exceed exports by 1937 GWh which would cost Eskom R611m. However, in actual mode the volume position reversed with exports exceeding imports by 3374GWh. This was attributable to lower imports from Cahora Bassa (HCB) as a result of reliability of the highvoltage direct current transmission lines. The net position of imports less exports was further affected by higher export sales due to regional demand which was supplied when capacity was available. The net export position in actual mode resulted in additional net revenue being achieved of R1372m. Thus the customer benefits by the change in net costs/revenue resulting is an overall benefit of R1982m to the customer for RCA purposes. Table 38: Summary of net SAE position SAE net position for 2013/14 Decision Actuals Variance Import (GWh) Export (GWh) Net Import/(Export) GWh Net Import/(Export) Costs R'm Note the above volumes on exports and imports exclude en route volumes.

82 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 82 of Open cycle gas turbines (OCGTs) Usage and cost of open cycle gas turbines are allowed as pass through subject to prudency reviews of volumes which 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 costs will be allowed as a full passthrough cost, but limited conditional to volumes allowed by the Energy Regulator, except where such use is necessary to ensure security of supply. `This situation is further reinforced in para 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. The MYPD methodology does state that the OCGTs usage is a last resort after cheaper alternatives have been investigated and utilised. Para 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). The information reported in this section of the submission focuses on: Reasons for OCGTs variance Avoidance of load shedding Cheaper alternatives were maximized and utilised by Eskom Allowed OCGTs costs as approved by the Energy Regulator. Actual OCGTs costs as reconciled to Eskom s audited AFS Calculation of OCGTs cost variance for the year Security of supply by the System Operator

83 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 83 of Reasons for OCGTs variance During the 2013/14 financial year Eskom utilised OCGTs at 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 For avoidance of doubt, gas turbine generation should be employed before implementation of load shedding activities. Eskom illustrates this avoidance by calculating the impact of load shedding had Eskom limited the use of OCGTs to only peak hours during the year. These results reflected that load shedding would have increased the by 2586 GWh, effectively South Africans would have experienced regular load shedding between April 2013 and March The cost of running the OCGTs for the extra 2586GWh resulted in Eskom incurring an extra R 8 024m to reduce the impact of load shedding on the economy. Before the OCGTs were utilised, Eskom did consider cheaper alternatives which included a combination of demand and supply levers from local and regional IPPs, demand response initiatives and green/brown field options of supply were considered. Eskom spent R580m more on local IPPs, R1136m more on regional IPPs, R212m more on DMP and Power Buybacks combined and slightly less on DSM programs by R99m when compared to the MYPD3 decision. Eskom is of the view that this additional expenditure on OCGT fuel was both prudent and necessary in the national interest. The cost to the economy of unserved energy is significantly higher than that of diesel fuel which was required to produce the extra 2565GWh of electricity and the R8024m should be allowed in the RCA decision Avoidance of load shedding Power system emergencies and rotational load shedding For many hours of the day, the reserve margin is more than 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

84 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 84 of 205 demand response programme where selected large customers reduce their demand on request from Eskom. As a last resort, Eskom will introduce 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 in the event that there is no option but to resort to load shedding. The emergency response command centre was activated on a total of 36 occasions in the year to 31 March The majority of the activations were proactive interventions (in alert mode) to manage emerging threats. However, emergencies had to be declared on four occasions during the year Declared Emergencies during FY 2014 Power system emergencies were declared when there was insufficient capacity to meet the demand. Instructions were given to large customers to reduce demand in accordance with the protocols for stage one load reduction. Control centres were instructed to be ready for load shedding. For the first three emergencies rotational shedding was not required as the response from customers was adequate to stabilise the power system. However on 6 March rotational load shedding was instituted. Customers responded admirably when Eskom declared these emergencies and reduced demand by 600 MW in November 2013, by 340 MW in February 2014 and by MW during March Rotational load shedding on 6 March 2014 The already constrained system was exacerbated by a rapid change in the early hours of 6 March 2014, as production at four units at power stations was severely curtailed, with load losses of MW by 08:00. An emergency was declared at 06:00 and load curtailment commenced. By 08:00 it was necessary to commence with rotational load shedding, which continued for 14 hours. The load shedding reached stage three in the morning, reducing demand by approximately MW thus enables the stable operation of the system. By mid-day the load reduction was reduced to stage two and at 22:00 the system emergency was cancelled and the entire load was restored.

85 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 85 of 205 Stages one, two and three indicate the degree of severity of the supply shortfall, and thus the frequency and duration of the required rotational load shedding, with three being the most severe. Stage one requires 1000 MW to be reduced, Stage two requires 2000 MW to be reduced off the system and Stage three requires 4000 MW reduction on the system. The curtailment of production at the four units was mainly due to the handling difficulties regarding wet coal as a result of continuous rain over a number of days leading up to this date. After the load shedding in 2008 following heavy rains, Eskom is mixing coarse coal with the finer coal to prevent the wet coal from coagulating on the conveyors. However, the length of this period of wet weather conditions meant that many of the coarse stock piles were depleted. This was the only incident of rotational load shedding during the year Actual OCGTs usage and load shedding in 2013/14 During 2013/14 Eskom experienced minimal supply interruptions of 54 GWh after utilising IPPs and OCGTs as presented in the figure below. 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 Minimal Load shedding and curtailment was experienced substantially in March 2014.

86 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 86 of 205 Figure 7: Load shedding impact in 2013/ Impact on load shedding if OCGTs were restricted to Peak hours The following section will demonstrate the implications load shedding had Eskom restricted the utilisation of OCGTs only to peak hours during the year. It is evident if the IPPs were not utilised and the OCGTs were restricted to peak, the level of load shedding would have been more regular and severe than that which actually materialised. This principle is demonstrated by computing the impact on load shedding had Eskom operated the OCGTs only during peak hours. Peak hours are defined as weekdays between 6am to 9am and 5pm to 7pm. The illustration reflects that load shedding would have increased the 54 GWh by 2586 GWh. Effectively South Africans would have experienced regular load shedding between April 2013 and March 2014 as illustrated in the figure below.

87 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 87 of 205 Figure 8: Load shedding with OCGTs limited to peak hours The overall increase in load shedding would have resulted in the different levels of load shedding intensity based on average hours per day as illustrated in table below. Table 39: Load shedding intensity - OCGTs limited to peak 14.3 Cheaper alternatives were maximised and utilised by Eskom Eskom did consider cheaper alternatives and their utilisation before embarking on operating the OCGTs at volumes above that assumed in the MYPD3 decision. Eskom pursued and employed a combination of demand and supply levers which included local and regional IPPs, demand response initiatives and new options of supply were considered. These are summarised below.

88 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 88 of Supply side options Local IPPs Eskom increased local short term IPP supply through MTPPP and STPPP as well as connecting the renewable IPPs per the DOE programme. During 2013/14 Eskom procured all available local options except for Tswhane (generators were out for maintenance) Regional supply Eskom secured regional emergency supply from Aggreko during the year Green/brown field options Eskom explored the possibilities of adding 3000MW of capacity; whether independent power producers or Eskom to provide sufficient capacity to allow planned maintenance to take place. New coal, nuclear, gas and renewable options were investigated. Given that the focus was on addressing issues (poor performance) in the shorter term; scale and time to implement were key focus points in selecting an option. Coal and nuclear options were eliminated as they have long lead times and are rather considered longer term solutions. Gas options like CCGT and OCGT have short lead times and were considered as short term solutions, however, Greenfield options would require new site selection and site studies which makes any Greenfield CCGT or OCGT options medium term solutions. Renewables were deemed intermittent and not a base load option on which could be relied on to increase planned maintenance without having load shedding. The options left to add additional units were to consider brownfields sites for OCGT or CCGT; Ankerlig or Gourikwa as no site selection would be required and infrastructures already existed. Transmission integration issues that exist at Gourikwa would only be resolved by 2020 and therefore the only short term option left was to add 4 units of OCGT at Ankerlig by earliest 2016.

89 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 89 of 205 In the short term diesel is selected as fuel source until sufficient gas is secured to possibly convert OCGTs to CCGTs in the medium to long term. From a commercial perspective, adopting an open market approach would now make the addition of OCGTs to Ankerlig a medium term solution and thus not assist with the short term energy shortage to address backlog of maintenance Demand side options Demand response In the MYPD3 application, Eskom had assumed demand response programmes which required a total cost of R million over the five year horizon. The major component of the funds requested was to cover the Demand Response aggregator programme. This programme was meant to unlock and aggregate smaller dispatchable DR loads in SA (beyond the Key Industrial load) based on market potential at the time. NERSA granted demand response R 2.0 bn spread over the first two years. Thereafter no amounts were assumed for demand response programmes between April 2015 and March 2018 in the MYPD3 determination. In response to the NERSA decision, the aggregator programme fell away, and focus was back on the key industrial load. In terms of DR, Eskom is of the opinion that opportunities for further contributions are limited from the Key Industrial Customers (KIC). A higher rate would possibly obtain some additional MWs but not significant. The current economic climate and a steady decline in the demand of KIC over recent periods makes it even more difficult to obtain further demand response from these customers. During winter, KIC reduce load significantly in response to the high winter tariffs, and therefore are unable to participate in DR, specifically supplemental. Generally, only furnace type operations lend themselves to demand response programs. Therefore the pool for this type of DR is limited.

90 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 90 of 205 The Power Buyback option was pursued as a lever to contribute to balancing supply and demand with R1 117m more being spent compared to the assumptions for purposes of the MYPD3 decision Energy efficiency and demand side management (EEDSM) Eskom made use of EEDSM lever to help balance supply and demand. Eskom has exceeded its internal targets for demand savings on a regular basis demonstrating the organisation s commitment to demand side management as presented below. Figure 9: Trend in DSM savings 14.4 OCGTs allowed in MYPD 3 for 2013/14 For purposes of its revenue decision NERSA assumed R2 537m for OCGT fuel cost for the MYPD3. 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.

91 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 91 of 205 Table 40: OCGTs decision from MYPD3 R'm 2012/13 Approved Expenditure 2013/ / / / /18 MYPD 3 Total OCGT Costs Applied For OCGT Costs Adjustments (1 055) (548) (280) (299) (332) (2 514) Approved OCGT Costs Allowed OCGTs for 2013/14 is R2 537m 14.5 Actual OCGTs costs in 2013/14 The actual OCGTs energy produced by Eskom during 2013/14 exceeded the assumed usage levels by 2 565GWh during 2013/14 disclosed in the figure below Figure 10: OCGTs production in 2013/14 The higher volumes culminated in Eskom spending R10 561m on OCGTs in 2013/14. A summary of the costing and volumes relating to the four gas turbines is outlined in table below.

92 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 92 of 205 Table 41: Summary of OCGTs results Power Stations Costs 2013/14 Actuals R m 2013/14 Decision R m Variance R m Ankerlig Gourikwa Acacia Port Rex Total costs (R m) Power Station volumes 2013/14 Actual GWh 2013/14 Decision GWh Variance in GWh Ankerlig Gourikwa Acacia Port Rex Total GWh Fuel Burn (litres) Actuals Actual R/Litres Average Litres per MWh Ankerlig * 315 Gourikwa * 317 Acacia Port Rex Total litres Actual Rand per litres costs - for Ankerlig and Gourikwa is after Government gazette rebate of R2.94 / litres (2013/14) and wholesale discounts. Only Ankerlig and Gourikwa receive diesel rebates linked to their fuel source. Acacia is sourced with jet fuel and Port Rex is sourced with kerosene. The standard/design fuel consumption for Ankerlig and Gourikwa = 320 L/MWh and for Acacia and Port Rex = 350L/MWh.

93 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 93 of 205 Source extract from AFS March 2014, Page 10 Actual OCGTs costs incurred in 2013/14 reconciled to AFS is R10 561m 14.6 Security of supply by the System Operator performance The OCGTs are one component of the generating fleet, available to assist in meeting the demand, providing reserves and ensuring system security. Due to their high cost they are typically utilised after cheaper options are generating, but due to certain technical constraints there will be times when other plant will not be at maximum output while OCGTs are already running. As a result of the intense logistics required for high load factor operation of the OCGTs, particularly due to fuel transport and handling, there are times when their usage is restricted due to lack of available fuel. This document initially describes the process to determine the amount of generating plant required to meet the demand and provide sufficient operating reserves. The various generating sources used to meet this requirement are given and some of the primary energy constraints associated with each is highlighted. The various demand side management options are also mentioned as well as their limitations Generating capacity to meet the demand and ensure system security When determining the required generating capacity, an hourly average demand forecast is calculated. Currently this forecast is used to determine the amount of dispatchable plant required from the conventional Eskom fleet (including firm imports from Apollo). Thus the assumed output from IPPs including renewable generators is considered inherently in the forecast.

94 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 94 of 205 The Ancillary Services Technical Requirements determine on an annual basis the amount of operating reserve required from generation. The current required value and that used for planning purposes is 2000 MW. This implies that in addition to meeting the hourly average demand, 2000 MW extra capacity should be available to deal with uncertainties and instantaneous demand variations within an hour. Uncertainties catered for include variations of demand from that forecast (as a result of natural demand variation or variation in renewable generation from that assumed) as well as variation in generating plant availability. On the day in real time, this amount of reserve may be reduced to about 1000 MW as there is less uncertainty in a shorter time frame. Operating reserves are critical to ensure that if any event occurs on the power system, there are adequate means to respond immediately and prevent a cascading failure or operating for periods of time in a compromised condition. It is essential that the power system manager is always confidently in control of the system and compromised operation can quickly result in a loss of control. In planning mode, the available generating capacity considers the installed capacity, the planned generation outages and an assumption around forced or unplanned outages. In addition the firm imports via Apollo are considered. In real time, the actual unplanned outages are taken into account as well as generation capacity not available due to primary energy constraints Available generation capacity The Eskom system comprises of MW of conventional power plant with about 103 MW of renewable generation (wind). Together with this we consider up to 1500 MW of firm imports via the HVDC scheme from Apollo. Of this, 1400 MW is provided by pumped storage stations, 600 MW by hydro stations and 2409 MW from OCGTs (including small gas turbines). Each of these three categories has particular constraints with respect to primary energy such that even if the plant is physically available it may not be able to generate.

95 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 95 of Pumped storage generation Pumped storage generation is hydro generation technology that allows water to be used for generation during periods of high demand and allows the water to be pumped back (as load) during periods of low demand. This process is about 70% efficient (implying that more hours are required for pumping back the water than could be utilised for generation). In addition, one of the pump storage schemes is also used as a water transfer scheme at certain times and may require additional water to be transferred upcountry (i.e. requiring additional pumping hours) other than the normal operation. The number of hours required for generation in any given day is typically higher than that available to pump. Thus on a Monday morning, maximum generation capacity is required to ensure that during the course of the week this capacity remains available. During summer periods or when these generators are required to operate for many hours a day, by the middle to the end of the week the available generation capacity may be severely constrained and this capacity may not be available to generate with. To ensure maximum generation capacity on a Monday morning, it is necessary to reduce reliance on generation over the weekend and also pump back the water during this time. Depending on the available generating capacity on the system, this may require less economic options such as running the OCGTs or even load shedding to enable this. However the implication of not doing so would be an additional shortfall of capacity in the following week. As Drakensberg is also one of our Black Start facilities there is a restriction on the minimum number of generating hours that can be reached as some water must be maintained for black start purposes in such an event.

96 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 96 of 205 Figure 11: Typical profile of generating hours at Drakensberg and Palmiet in a week Hydro generation The 600 MW of hydro generation is from two dams of which the water releases are controlled by the Department of Water Affairs and Sanitation. Depending on the water situation in the country at the time, the levels of the dam, the season as well as other factors DWS will restrict or instruct the applicable water releases from generation. Under emergency conditions, these may be extended slightly but it is typically not possible to run these two stations constantly as base load plant. It is common to only have a few unit hours (equivalent to one or two station hours) of available generation from each station OCGTs While the OCGTs are capable of running at high load factors, the impact on fuel logistics is extremely challenging. Not only is fuel transport and handling difficult, but also the timing of orders and reliance on external service providers to provide certainty as to what will be available when. When operating at lower load factors, these challenges are a lot more manageable. Thus there are also periods of time when although the generators themselves may be available, the level of available fuel (and expected deliveries) requires more prudent operation by reducing the output from these facilities.

97 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 97 of Demand Response Options Limited demand response options exist to assist in managing the shortfall. Supplemental reserve (scheduled day ahead and dispatched on the day), results in a demand reduction over specified hours. Depending on the time of year this may be between 100 MW and 500 MW for about 2 3 hours per week day. In addition, instantaneous demand response of between 300 and 900 MW may automatically reduce if the system frequency drops below a specified frequency for a fixed time period. This demand only stays off for ten minutes after which it restores. The last emergency demand response available is referred to as Interruptible Load Shedding. This provides about 2000 MW for a maximum of about two hours per week, in short intervals. This demand reduction can be implemented immediately by National Control (NC) (simply opening a breaker) and is also restored on instruction of NC. All of these options assist in ensuring system security when there is insufficient generation to balance the requirements. Due to the relatively low energy availability of the options, they are not normally considered in longer term planning but are dispatched on the day as required Scheduling and dispatch of generation resources Economic dispatch is performed through the scheduling programme which National Control runs daily on a day-ahead basis. The output of the program is based on the bids provided by generation in terms of plant availability (and other technical parameters) as well as cost. Scheduling is done to meet both the energy (from certified resources) and operating reserve requirements. In the current environment, there is not always adequate capacity to meet both these requirements. The scheduling process optimizes the plant schedules for the day ahead and the water resources for the week with specific boundaries set such as minimum dam levels and the requirement to have full dams on a Monday morning. The OCGTs are currently not part of this scheduling process as they will only be used when all other cheaper options have been utilised.

98 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 98 of 205 In real time, the controllers at National Control have to respond to the various changes on the network and in this context the loss or addition of generation is considered against the plan. They have a live indication of which plants are cheaper/more expensive to manipulate if it is necessary to instruct a change to the schedule. The Automatic Generation Control (AGC) algorithm automatically does this for units certified and on AGC. The usage of supplemental and emergency reserves is done in accordance with a constantly updated merit order, depending on the availability of the various options in terms of MW and duration. However the focus is always on ensuring security of supply and at times this may be in conflict with pure economic dispatch Technical issues impacting OCGT generation Impact of daily load profile on resultant OCGT load factor The impact of the daily load profile plays a significant role in the actual load factor of the OCGTs. Although the daily peak demand is higher in winter than in summer, the lower demand in summer allows the opportunity for additional maintenance. Hence the system is planned to be run at an approximately constant level of margin or tightness over peaks throughout the year. [There are exceptions to this such as over the Christmas period when the demand is significantly lower for a few days and short-term maintenance fills the gap ]. This approximately constant level of margin should translate to a relatively consistent number of OCGTs at peak. The normal significant difference in load factor between summer and winter arises as a result of the relative flat load profile during the day during summer. While in winter if OCGTS are required for peak they may be brought on between 16:00 and 17:00 and taken off between 20:00 and 21:00, in summer the requirement is quite different. It is highly likely that they may be required from 06:00 right through to 21:00 and even after this, with additional units being required to assist in meeting the peak demand. Winter 2014 has also resulted in unusually high OCGT load factors due to the fact that the peak was often managed

99 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 99 of 205 (reduced) through load reduction and OCGTs were then required to be run throughout the whole day. It is not only the OCGTs that are impacted by the flatter load profile. All peaking plant is required to run at higher load factors and this has a substantial impact on the pumped storage stations. While on a typical winter s day they may only be required to run about 6 8 hours per day, thus allowing adequate opportunity to pump back the water at night, during summer they may be required to run up to 16 hours per day which cannot be replenished during the evenings. This places greater reliance on OCGTs to replace the water (energy) from the pumped storage stations and introduces the requirements to have to utilize OCGTS at the weekend in preference to water to ensure that the full generating capability is restored at the beginning of each week Speed of response of generators Not all generators are able to respond to system changes at the same speed. Not only do they have different ramp rates but also different times to start up from different modes. While it is assumed that currently all available coal generation is on line the differentiation must be considered for the various peaking plants. Hydro generators (including pumped storage units) are able to start up in a few minutes. They are able to respond from synchronizing to full output within a further few minutes. Hence they are invaluable in terms of responding to quick changes and sudden contingencies. Their minimum stable generation is about 200 MW for Drakensberg and 150 MW for Palmiet so once on line they offer limited movement per unit (but a total of about 300 MW in total). The OCGTs on the other hand can take about 20 minutes to start up (depending on their mode of operation prior to the event). It is also not possible to simultaneously start a number of machines and it is therefore critical to ensure that the plants expected to be required for evening peak are on line before the peak starts. While they are able to operate in a stable mode at about 80 MW per unit they also take some time to respond from this output to full load even if they are on AGC. It must be noted that the efficiency of the plants is reduced at

100 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 100 of 205 these lower values. When an OCGT unit has been taken off line, it requires approximately 2 hours cooling down before it can be safely restarted. Hence it is important not to take them off if it is likely or even possible that they will be required again within 2 hours OCGTs role during demand variations The OCGTS maybe also be used to assist in controlling the system during load shedding. Large blocks of load being shed and restored in a short time frame can result in substantial frequency deviations which plant such as the OCGTS are able to respond to. After evening peak, it also takes some time to physically shut down all the OCGTs and frequency control during this time may be provided by the pumped storage plants particularly as they go from generating into pump Factors influence choice of plant to dispatch Considerations from the control room when making decisions regarding plant choice (particularly between water and OCGTs): Expected peak demand and amount of plant required to meet this. This is strongly influenced by weather forecasts and other events such as school holidays. The rate of change of demand expected at various times of the day Variations in demand from the forecast throughout the day (hourly averages) Comparisons with previous profiles on similar days (4 second data) Existing risks on the rest of the fleet in terms of partial reductions as well as likely loss of plant Possible risk on power imports Possible limitation on output at Matimba due to ambient temperatures Existing and predicted risks on the coal availability for the various units The time taken for the OCGTS to start and the time required for each to be started in sequence The dam levels at the pumped storage stations The day of the week and the type of load profile Remaining demand side resources such as Interruptible Load Shedding (ILS)

101 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 101 of 205 Expected outlook for the rest of the week Key events which may require additional focus on security of supply such as political or sporting events. There is sometimes a network or regional constraint requiring the generation to be used from a location perspective Licence conditions for Ankerlig and Gourikwa To implement the above requires acknowledgement and support that OCGTs will, as was expected when they were commissioned, have to be utilised beyond their normal peaking function for some time still. Eskom s licence applications for Ankerlig and Gourikwa submitted in 2006 already indicated that within the first five year period their annual load factors might exceed 7%, and NERSA also said in its December 2007 Reasons For Decision document, "A much higher level of gas turbine operation during the period of plant shortage would be expected due to gas turbine capacity that has been increased to improve the supply / demand balance. Pass-through of gas turbine cost would be a reasonable mitigating factor over the next five years". This will contribute to creating space for maintenance, once all other demand and supply side options have been fully utilised Summary of a system operations perspective The use of OCGTs must be considered in combination with all other available options to manage the power system. In order to provide reserves and be able to respond fast enough to incidents, the OCGTs have to be on line. Reduced usage of the OCGTs would increase the incidents, duration and severity of load shedding and longer term would have an impact on the decision making regarding planned maintenance. The knock on effect of this would be worsening plant performance and a longer time period to return to a more normal state of operation. There are number of technical challenges which may marginally increase the use of the OCGTs but the marginal changes in usage do not justify the increased system security risk which would result.

102 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 102 of Conclusion on OCGT s It is submitted that Eskom has dispatched OCGTs in accordance with the NERSA MYPD methodology. The variances between the assumptions in the decision and actuals for the first year of the MYPD 3 period illustrate the need for the use of OCGTs to the extent required to minimise load shedding. The economic impact of load shedding has thus been minimised OCGTs variance for 2013/14 RCA OCGTs variance = OCGTs Actuals OCGTs decision Eskom incurred OCGTs actual costs of R10 561m compared to the assumed costs in MYPD3 decision of R2 537m which results in a variance of additional expenditure of R8 024m included in the 2013/14 RCA submission. This was effectively prefunded in the year, Eskom seeking to recover variance subject to NERSA prudency assessments. Eskom believes that based on the conditions of the day and choices which were available in 2013/14, the efficient and prudent option of operating the OCGTs in and outside of peak hours was the correct decision for the country. Hence the prefunding which was undertaken by the organisation needs to be recouped through this RCA submission System operator was impacted by delays in new build and Generation plant performance. Noting that the primary drivers in OCGT usage are the de facto imperative to keep the lights on was influenced by capacity constraints attributable to the levels of generating plant availability and delays in commissioning of new build capacity. It is important to put plant performance and delays in new build into perspective. Eskom accepts that there will always be room for improvement in the management and operation of its power stations, even under very difficult system capacity conditions. However this does not imply that the operation and management was not prudent or not

103 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 103 of 205 efficient, under the circumstances. Prudence is not a test for perfection but rather a reasonableness test taking cognizance of the context and circumstances. The Generation Sustainability Strategy was initiated to assist in addressing the key areas for improvement, namely Plant (including an accelerated focus on partial load losses and performing the required philosophy maintenance), People (primarily complement and competence in key positions), and Systems and Processes. The underlying cause of the deterioration in the fleet s performance is, however, the lack of sufficient system capacity, which since 2003 have both limited the space for maintenance as well as necessitated very high load factors on the existing power stations. This situation was aggravated by the onset of age and usage-related equipment failures. About 80% of the existing fleet s capacity is now in that period where they require major equipment replacements in order to restore the plants economic life. Deferring this work in the recent past due to lack of maintenance space on the system is a major cause of the escalation in plant breakdowns 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 However, the approval for Eskom to embark on the build programme was made in late 2004, 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).

104 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 104 of Reasons for delays in new build capacity Eskom generation expansion plan used in the MYPD3 application submitted in October 2012 was based on a capacity as at 1 April 2012 which contained the following commissioning date assumptions as stated below. Table 42: Eskom Generation expansion plan MYPD 3 Application MYPD3 2012/ / / / / / /19 TOTAL Grootvlei Komati Camden Medupi Kusile Ingula Sere Total MW Interventions are in progress to potentially accelerate the schedules, which will assist in potential cost savings. These cost savings will primarily be derived from the earlier demobilisation of project resources and the reduction of potential claims Medupi : Schedule delays Since inception of the Medupi Project, schedule delays have been experienced due to the following: Boiler steelworks issues. Delayed civil access. Site accessibility and configuration issues. Labour instability. Design scope changes. Control and Instrumentation (C&I) and Boiler quality issues.

105 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 105 of Kusile : Schedule delays Since inception of the Kusile Project, schedule delays have been experienced due to the following: Industrial actions in 2011, 2013 and Quality issues / welding repairs in boiler. Design change and increased scope due to permitting requirements. Culvert permits delays. Failed Contractors (COSIRA and NIC Failures), Overall poor productivity by all contractors with Hitachi and GLTA being the largest contributors Ingula : Schedule delays The Ingula Project has experienced significant schedule delays in terms of completing the waterways. The delays are mainly due to the following: The fatal accident in the Inclined High Pressure Shaft (IPHS) 3&4 on 31 October 2013 that resulted in a total of 6 fatalities and 7 injured personnel. Production on site had been stopped due to the accident on the inclined shafts, which would impact on the project completion date. In terms of the Mines Health and Safety Act (MHSA), the Department of Mineral Resources (DMR) issued 2 Section 54 notices (No for the General Works and No for the IPHS) on 06 November Section 54 No was lifted on 19 September 2014 but No remained in effect and was only conditionally lifted on 26 February The safe work procedures, risk assessments and documentation approval relating to the 31 October 2013 incident in the IHPS had to be revised and approved by the DMR prior to the full upliftment of the associated Section 54 notice. Due to the Section 54 notices on the IHPS section of the works remaining in effect, the completion of the upstream waterways (IHPS) became the critical path for the project schedule followed by the completion of the lower waterways (surge chambers).

106 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 106 of 205 Construction related activities on other parts of the site continued as per normal with only the activities in the IHPS affected by the Section 54 Notice. As part of the conditions to be met which would result in the full upliftment of the section 54 No. 4970, the following had to be completed: - Removal of the old equipment in the IHPS s. - Installation of new equipment in the IHPS s. - New work methodologies have to be employed which would result in a progress rate of approximately 50% slower than before, i.e. a slowing of work in the Surge Chambers due to restrictions on the use of more than one platform. The outstanding documentation on safe work procedures and risk assessments and MHSA exemptions were finally accepted by the DMR on 19 September 2014 after numerous iterative engagements between Eskom, the principal contractor and the DMR. The cumulative schedule delays of the Section 54 notices combined with the revised work methodologies to be employed for the remaining work to be done in the IHPS amount to a schedule slippage of 12 months on the commercial operation dates for the units Evaluation of delay in Eskom new- build projects that impact sustained usage of OCGTs Understanding the challenges facing the delivery of Eskom s new build programme is critical in placing into context the use of further OCGTs during the financial year. The first unit of Medupi, Ingula and Sere were scheduled to be in commercial operation during the 2013/14 financial year. This did not materialise as planned. Lazard's Levelized Cost Of Energy Analysis Version 7.0 of August 2013 gives typical coal power station construction time as 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

107 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 107 of 205 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 month period to SA for purposes of establishing an efficient norm (not an exhaustive list): Locality: Electricity companies in the US are in closer proximity (thus shorter transport distances) from many suppliers, with well-developed local infrastructure, highly skilled local labour etc. Project management and construction capacity: The ongoing construction activities of such power plants in the US since 2004 have served to maintain the local project management and construction capacity for executing such projects. E.g. 10 power stations of total of MW were commissioned just in 2010, with another >6 000 MW commissioned over the preceding three years, and a further MW under construction and due over 2011 and A further MW was announced / near construction or had already received permits, for In total there are around MW of coal power plant projects either already completed or in construction or planned, over the period Learning curve: With MW already completed between 2004 and 2012 and a further MW in planning or being executed for the period up to 2018, the US industry remains well advanced on the learning curve i.e. they have progressed sufficiently from the commencement point. Up-front planning and preparatory work: It is highly unlikely that a power plant owner and investor in such new projects in the US would be pressured to short-cut the crucial up-front planning and preparatory work. Total projects portfolio: In general the projects since 2004 have been spread over many utilities i.e. the individual electricity companies were not each doing multiple projects but each company respectively did one or perhaps two units, of less than 850 MW total, at any one time.

108 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 108 of Compared to Eskom/SA, regarding these same five factors: 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 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 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 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.

109 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 109 of 205 Total projects portfolio: In parallel with the programme to construct the MW Medupi base load coal plant, Eskom also: o Embarked on the programme to construct the MW Kusile; o Started and have since completed the refurbishment and re-commissioning of three older coal fired power stations (23 units of MW in total over the period July 2005 to October 2013); o Constructed and commissioned 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 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 months US norm very quickly becomes months or more, in this context. Due to the already apparent generating capacity constraints, the original time period to Commercial Operation of Medupi s first unit (i.e. Oct 2007 to Sep 2011) was optimistically hoped to emulate not only the US norm but an even quicker month period that had been established in China where however over a three year period, generation capacity in the order of MW of plant was commissioned. That may have been overly optimistic and the reason for the incorrect project duration estimates and delays. The current estimates for project duration however do not so much reflect poor project management and construction performance but rather inaccurate initial estimations, which created unrealistic expectations. The rushed design phase (based on virtual designs) obviously held risk, which amongst others manifested as: Geo-technical challenges, turbine base design challenges and boiler seismic design challenges which added 15 months to the initial 48 months (thus total of 63 months, CO date moved to Dec 2012)

110 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 110 of 205 Structural steel problems encountered on the boiler in 2011 which added a further 12 months (thus total of 75 months, CO date moved to Dec 2013) Further under-performance by key contractors on the boilers and on the Control and Instrumentation contracts, which added a further 6 months (thus total of 81 months, CO date moved to June 2014). Woven through these issues is the estimated cumulative time of 9 months lost due to labour unrest. Commentators often provide opinions such as that the form of the contract management should have been different, turn-key contracts should have been established but the industry realities at the time of contracting was that suppliers were not willing to accept that level of risk, and much of this still prevails. 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. The (now apparent) optimistic and unrealistic initial construction time estimates merely exacerbated the situation Factors contributing to Generation plant performance The second contributor is the resulting deteriorating Generator plant performance of existing plant. Over the past 10 years, but particularly since the 2010 World Cup, the lack of system capacity limited the time available for maintenance outages and thus caused the necessary philosophy maintenance to be delayed in ascribing to the strategy of keeping the lights on. The lack of system capacity also necessitated very high load factors, already from 2005 and This high utilisation of aging plant and deteriorating condition created the cycle of lower availability. Despite some improvements due to efficiency and effectiveness of operations and maintenance, this cycle can only be broken once there are adequate funds

111 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 111 of 205 and system space to perform the required maintenance, and plant load factors reducing to normal levels. The system already reflected constrained space for maintenance from 2004 there was insufficient capacity to enable a 7% annualized PCLF without having to take special supply and demand side measures, or without incurring some risk of being unable to meet demand. In addition, due to the very high load factors at which the plant had been running since 2004 and especially since 2006, nothing that many of the power stations were entering their midlife refurbishment phases, the requirement for maintenance had increased beyond the 7% annualized PCLF that was appropriate whilst the load factor EUF was under 70% and the plant newer. At that stage the UCLF on the coal fleet, although higher than the <4% range before 2003, was still relatively low averaging 5.07% over the period 2004 to 2011, which compared well to peer group data e.g. the VGB median in 2011 was 6.1%. However from 2012 onwards the plant reliability started decreasing further as indicated by the UCLF on the coal fleet increasing to 9.03% in 2012, and higher each year thereafter which further constrained maintenance space Lack of philosophy based maintenance In conclusion, the decreasing amount of proactive maintenance and the very high load factors are the direct result of the constrained system, now aggravated by the reduced plant reliability and also by capital expenditure constraints. Eskom is convinced that the only way to restore plant reliability is to reduce the load factors and to put emphasis on proactive maintenance, which includes refurbishment. If this is done, availability should improve, but if outages continue to be deferred in order to keep the lights on or are deferred due to lack of finances, availability can be expected to deteriorate further Ageing fleet Eskom believes that space must be created to perform all of the planned design-based maintenance essential for the sustainable operation of the coal fleet. The fleet is ageing,

112 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 112 of 205 which means that lengthy outages for extensive mid-life refurbishments are required, while high load factors are resulting in high wear and tear on plant components. Significant investment, in both capital and time for outages, is required before sustained performance improvement can be expected. This is exacerbated by the fact that the plant is ageing. Power plants have very long operational lives; however, most of the major components have design lives of much shorter than the overall operational life of the power station. If major components are replaced / refurbished according to their engineering design parameters it could be possible to avoid a significant decline in technical performance as the power station ages. However, if the major components are not replaced or refurbished when due, it would increase the risk of incurring a significant decline in technical performance. It is, however, typical regarding major components that their replacement or refurbishment requires extensive outage time, and obviously would be expensive to do. The need for replacement / refurbishment is not solely a function of operating hours or age e.g. replacement is also a function of technical condition which is established through ongoing assessment and monitoring which could indicate the need for earlier or later replacement or refurbishment. However, the age of the plant and of the major components is a very useful indicator. The graph below reflects the ages of Eskom s coal fleet. 60% of Eskom power stations are older than the recommended design life of 30 years. The graph indicates that eight power stations are more than 30 years old more precisely, 34 or more years old. An ageing fleet results in an increase in unplanned failures, more mechanical maintenance failures, increased outage duration and the requirement for specialist engineering all of which implies reduced availability and increased cost. An analysis of the power stations that contributed the most to the UCLF in both the 2013 and 2014 financial years (eight stations) shows that seven of the eight stations that are above 30 years old are on that list.

113 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 113 of 205 Figure 12: Coal Power station ages The graph below reflects the engineering design life vs. the actual operating hours (left hand axis). The yellow line indicates the actual operating hours as a percentage of the engineering design life (right hand axis). Figure 13: Turbine design vs operating hours

114 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 114 of 205 From the figure above 60%, i.e. 8 of the 13 fossil plants have exceeded their turbine design life. The figures reflects a similar situation as regarding the overall station lives namely that the major components of the five power stations completed in the late 1980 s / early 1990 s are the only ones still below 100% of engineering design life, with the exception of the Lethabo boilers at nearly 200%. More effective and efficient maintenance must be performed. Eskom will only be able to keep the lights on if it is allowed and supported to undertake the minimum design-based maintenance and to fully execute the maintenance plan Actual Plant performance in 2013/14 Generation technical plant performance will focus on four measures viz. UCLF, PCLF, EAF and EUF in this section. Table 43: Technical performance for the year to 31 March 2014 Measure Actual 2013/14 EAF, % Normal UCLF, % Less: Constrained UCLF, % Underlying UCLF% % Normal PCLF, % Underlying PCLF, % Normal OCLF, % Underlying OCLF, % UAGS/7 000, ratio 5.24 EUF, EUF 83.55

115 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 115 of 205 Measure EAF Normal UCLF Constrained UCLF Underlying UCLF Normal PCLF Descriptions Measures plant availability including planned and unplanned unavailability and energy losses not under plant management control Measures the lost energy due to unplanned energy losses resulting from equipment failures and other plant conditions. This is UCLF that was a result of emissions and short-term related UCLF due to system constraints to meet the Keeping the lights on objective. This is apportioned between PCLF and OCLF This is the UCLF that is the difference between normal and constrained UCLF and that is still within Generation control is energy loss during the period because of planned shutdowns Underlying PCLF The sum of the normal PCLF and the constrained PCLF (the apportionment of the constrained UCLF (1. above) that is assigned to PCLF) Normal OCLF Underlying OCLF EUF is energy loss during the period because of unplanned shutdowns due to conditions that are outside Generation management control The sum of the normal OCLF and the constrained OCLF (the apportionment of the constrained UCLF (1. above) that is assigned to OCLF) UAGS / indicates the ratio of unplanned unit trips per operating hours Measures the degree to which energy was produced compared to the extent to which it could have been produced. The utilisation of available plant capacity (EUF) was significantly higher than the target and higher than the previous four years due to the increased loading of available plant to match the demand. The overall fleet EUF was at 83.55% (2012/13: 81.87%). The utilisation of the coal-fired units for the year to 31 March 2014 was 92.73%, nuclear achieved 99.52% and peaking (including the OCGT stations) achieved 20.72%.

116 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 116 of 205 Eskom did not meet its EAF target, mostly due to an increase in unplanned plant unavailability and energy losses due to incorrect quality of coal being delivered, mainly at Tutuka and Arnot power stations. The unplanned capability loss factor (UCLF) for the year to March 2014 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 2013/14 was 12.61% compared to 12.12% in 2012/13 and 7.97% in 2011/12. An impact of 1.63% on the UCLF arose due to management decisions to ensure security of supply, regarding the emissions control and short-term outages previously not undertaken. The partial load losses continue to contribute significantly to the system total unplanned losses, and keep increasing. The UCLF due to these losses was 5.24%, contributing 42% to the system UCLF. The main reasons for the load losses were problems at the draught plant, coal mills, turbines, gas cleaning and feed-water systems. Boiler-tube failures are typically the result of welding repair damage, corrosion, fly ash erosion, etc. During the year, 210 UCLF boiler-tube failures were recorded, with a UCLF of 2.18%, contributing 17% to the system UCLF. This is higher in both number and UCLF contribution compared to the previous year when a total of 191 failures and UCLF contribution of 1.95% were recorded. 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 conversion rate 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 44: Average Eskom coal power station heat rate for period 2011/12 to 2013/ / / /12 Average coal power station heat rate, MJ/kWh The heat rate improvements in 2012/13 have not been sustained, with 2.1% deterioration in 2013/14 compared to 2012/13. This deterioration is attributed to the deferment of outages

117 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 117 of 205 that have impacted the execution of technical plan projects, as well as coal qualities at certain power stations Planned capability loss factor (PCLF) Between 2008 and 2012, Eskom had no option but to defer certain planned maintenance on its generating fleet to ensure security of supply. This backlog, coupled with the burning of below standard coal and the high utilisation of the plant, resulted in wear and tear on plant and negatively impacted the health of the ageing fleet. In 2013/14, Eskom started rolling out the Generation sustainability strategy that involved increasing the fleet s planned capability loss factor (PCLF) that is, planned down time for maintenance and refurbishment to an annualised 10% of overall energy availability. Historically more maintenance is scheduled for the summer months, when the electricity demand is lower. The effect is that in order to achieve an annualized 10% PCLF, up to 15.5% would have to be done in the summer months. However in 2013/14, more maintenance was scheduled in the winter months than ever before in order to reduce the backlog. See the graph on the next page which demonstrates the increase in planned maintenance over the previous three years. Figure 14: Planned maintenance performance

118 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 118 of 205 As of March 2014, PCLF (reflecting the energy loss during the year because of planned shutdowns) was 10.77% (including constrained UCLF) and 10.50% (excluding the constrained UCLF) against a target of 10.00%. On average, more planned maintenance has been done this year than in the previous six years, resulting in a higher PCLF. Although the PCLF has increased, the bulk of the planned maintenance that was executed was risk-based unscheduled maintenance rather than design-based preventative maintenance. As seen below, the monthly PCLF has increased over the winter months when traditionally minimal planned maintenance was performed Maintenance backlog reduction strategies Eskom s coal-fired generating units require routine maintenance to ensure that they meet the technical performance requirements, are safe to operate and do not violate environmental laws Unplanned capability loss factor Figure 15: Unplanned capability loss factor (UCLF) Annual Results March 2014 The unplanned capability loss factor (UCLF) for the year to March 2014 is slightly higher than previous years, indicative of ageing plant and related deteriorating plant health conditions as well as the increased utilisation of the plant. The UCLF for 2013/14 was 12.61% compared to 12.12% in 2012/13 and 7.97% in 2011/12.

119 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 119 of 205 Table 45: Breakdown of system UCLF (%) 1 Actual Mar 2014 Actual Mar 2013 Normal UCLF Less: Constrained UCLF Underlying UCLF Less: Total major/significant incidents Underlying UCLF excluding other major/significant events Less: Outage slips Underlying UCLF excluding other major/significant events and outage slips The figure below sets out the monthly UCLF % over the last 3 financial years: Figure 16: Monthly UCLF for last 3 years

120 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 120 of The main contributors to UCLF were as follows: 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 5.24%, contributing 42% of the system UCLF. The main power stations that contributed to these energy losses to date were: Duvha (24%) Kriel (15%) Majuba (13%) Arnot (12%) The main reasons for the partial load losses were problems at the draught plant (23%), mills (16%), turbine (14%), gas cleaning (10%) and feed water (10%) Boiler tube failures Boiler tube failures are typically the result of welding repair damage, corrosion, fly ash erosion, etc. In the year to March 2014, there were 210 boiler tube failures, with a UCLF of 2.18%, contributing 17% to the system UCLF. This is higher in both number and UCLF contribution when compared to the previous year when a total number of 191 failures and a UCLF contribution of 1.95% were recorded. The main power stations that contributed in the current year were, in order of energy loss: Kriel (19%) Duvha (13%) Matla (13%) Lethabo (11%) Majuba (10%)

121 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 121 of Energy utilisation factor (EUF) Energy utilisation of the available plant is reflected at high levels with coal fleet being utilised above design levels. Figure 17: Monthly Energy Utilisation Factor in 2013/14 The utilisation of available plant capacity (EUF) was significantly higher than target and higher than the previous four years due to the increased loading of available plant to match the demand. The overall fleet EUF was at 83.55% (2012/13: 81.87%). The utilisation of the coal-fired units for the year to 31 March 2014 was 92.73%; nuclear at 99.52% and peaking stations (including the OCGT stations) achieved 20.72% Relationship between EUF and UCLF 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.

122 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 122 of 205 Figure 18: EUF increased by approx. 38% from 2002 The graph above indicates that the utilisation / load factors (EUF Energy Utilisation Factor) increased from around 67% in 2002 to over 85% from 2007, and over 90% from As a proportion of previous EUF the increase is around 38% (93/67). 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 Energy Availability Factor (EAF) The EAF trend has been decreasing over the past few years as disclosed in figure below.

123 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 123 of 205 Figure 19: Energy Availability Factor (EAF) Energy availability factors are an outcome of the planned and unplanned maintenance which has occurred. However when coal plants are available they are operated at high levels of utilisation factors as highlighted earlier UAGS/7 000 Unplanned automatic grid separations (UAGS) per operating hours is a reliability indicator. For the year to 31 March 2014, the UAGS/7 000 ratio is 5.24, with 527 unplanned automatic grid separations trips. (2012/13: UAGS/7 000 ratio of 4.09 and 409 UAGS trips) OCLF The unplanned unavailability percentage due to factors outside of management control (OCLF) for the year to 31 March 2014 was 3.11% (including constrained UCLF) and 1.75% (excluding the constrained UCLF). This is mainly the result of coal-related load losses experienced mainly at Tutuka and Arnot power stations, due to coal supply and coal quality challenges The power station enhancement project The power station enhancement project quick win actions have almost been completed: All waves were rolled out by the end of June 2013, as per schedule Majuba, Kendal, Matla and Matimba have implemented 100% of their quick win actions Kriel, Hendrina, Tutuka and Lethabo have completed between 80 and 96% of its quick win actions

124 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 124 of 205 Implementation of quick wins for wave four commenced as per schedule Medium and long-term actions are outage dependent and are therefore impacted by the deferment of outages. While this project operated as a stand-alone project in 2012/13, it has now been incorporated within the Generation sustainability strategy and implementation is continuing. Eskom s coal-fired generating units require routine maintenance to ensure that they meet its technical performance requirements, are safe to operate and do not violate environmental laws. Maintenance tasks that need to be performed regularly (see the table below) can take anywhere from a week or two for a boiler inspection (which must be performed every 12 to 18 months) or up to two months for a general overhaul (which should be done every 6 to 12 years). During this time, the generating unit is taken out of service, which means that the rest of the generating fleet needs to compensate for the commensurate decrease in generating capacity Maintenance schedule for a coal-fired power station Table 46: Typical maintenance schedule for a coal-fired power station Activity Cycle time (years) Duration (days) General (major) overhaul Interim repairs Mini general overhaul 6 28 Boiler inspection Statutory inspection and test 6 35 Main steam pipe work ad hoc 120 In recent years, the margin between supply and demand has been too narrow for Generation to be able to take generating units off-line at the pace required in order to keep up with the required maintenance schedules while also undertaking unscheduled repairs. This is in the context of aging plant (which imply that more maintenance time is required) and high EUF (which also imply that more maintenance time is required). As a result, a maintenance backlog has developed.

125 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 125 of 205 More maintenance than ever before was scheduled in the winter months in order to reduce the backlog. This measure tracks the status of approved scheduled backlog maintenance. (The measure would be greater than zero if the outage has not yet started by the scheduled start date). During the year to March 2014, the nine maintenance outages scheduled have been completed. The backlog of scheduled technical governance related outages as at 31 March 2014 was thus zero, against the target of zero Benchmarking Coal-fired stations Generation benchmarks the performance of its coal-fired power stations against those of the members of VGB (Vereinigung der Großkesselbesitzer e.v), a European-based technical association for electricity and heat generation industries. VGB s objective is to provide support to and facilitate the improvement of operating safety, environmental compatibility and the availability and efficiency of power plants used to generate electricity and heat generation, either in operation or under construction. When interpreting the results of the benchmark, it should be noted that the operating regimes of the other utilities contributing to the VGB database may not be the same as those of Eskom. The graphs that follow illustrate the results of the benchmarking for the 2000 to 2012 calendar years (the VGB results for 2013 are not yet available). The VGB data for 2012 reflects information gathered from 123 VGB member generating units, but does not include data from Eskom s units. The Eskom data on the graphs has been plotted to the end of the 2013 calendar year to show the trend. The trend in Eskom s performance continues to be worse than the VGB benchmark. The availability of the top performing stations in the VGB benchmark has historically been consistent, with a slight decline in The availability of the stations in the median and worst quartiles has been declining. Adequate reliability and design-based maintenance is in

126 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 126 of 205 general the context under which most if not all of the VGB units operate, and in terms of which their benchmarks are established. Figure 20: Benchmarking EAF % all coal sizes Figure 21: Benchmarking UCLF % all coal sizes However, the UCLF trend is not at the same level. In the 2012 calendar year Eskom s units performance was worse than the VGB benchmark on all quartiles, with the trend for 2013 indicating that Eskom units will perform even worse than the benchmark. With the very tight demand versus supply situation and the need to keep the lights on, Eskom has focused on risk-based and statutory maintenance rather than the reliability and design-based maintenance needed to improve the UCLF performance.

127 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 127 of 205 Figure 22: Benchmarking PCLF % all coal sizes The benchmarking information indicates that Eskom units are on a par with the VGB benchmark with respect to planned maintenance in the median and low quartiles. The PCLF of Eskom s best performing units was significantly better than that of VGB benchmark units. Figure 23: Benchmarking EUF % all coal sizes With respect to the use of available plant (energy utilisation factor), all Eskom coal-fired units are performing at a level close to, and in many cases above the VGB best quartile. This indicates that Eskom is running its power station units much harder than the VGB benchmark units, negatively impacting on plant performance. Although the mix in the loading has changed with the European utilities, no longer running on coal base load. The trend is indicating that Eskom units have consistently maintained a high EUF. In fact the EUF benchmark comparison shows Eskom trending significantly higher than VGB compared to the previous years, due to the need to load available plant more to meet demand.

128 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 128 of Energy efficiency improvement programme 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 conversion rate 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. The heat rate gap analysis at each station has been converted into equivalent MW electricity for units sent out (MWe USO) into the grid. Measurement and verification studies were conducted using the services of independent accredited SANS institutions by comparing MWe USO to a known baseline of performance. While some stations have attained and sustained heat rate performance improvement gains, the overall heat rate (plant performance) improvements in 2012/13 have not been sustained, with 2.1% deterioration in 2013/14 compared to 2012/13. This deterioration is attributed to the deferment of outages that have impacted the execution of technical projects as well as coal qualities at certain power stations Managing supply-and-demand constraints During 2013/14 Eskom performed more planned maintenance than usual as a result of implementing the Generation sustainability strategy which deals with maintenance in further detail. While implementing this strategy is critical to ensure the long-term sustainability of the generating assets, it has inevitably created more pressure on the already tight supply/demand balance. Although there was sufficient capacity to meet the demand during the day in winter, on a number of evenings the power system was tight with all available generation in service and contracted demand reduction used to reduce load. The average available operating reserves over the peak period in June 2013 was under 3% as depicted on the graph. Eskom has managed to meet the daily peak demand with the support of customers with interruptible load agreements (the Bayside, Hillside and Mozal aluminium smelters), demand market participation (DMP) customer support, emergency DMP, demand-side management

129 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 129 of 205 (DSM), tariffs (more expensive tariffs during peak periods encourage customers to reduce demand during peak periods), municipality assistance, independent power producers (IPPs) as well as utilising the open-cycle gas turbines (OCGTs). The 2012/13 power buyback programme impacted the GWh sold in April and May 2013, however, the cost of this programme was provided for in the 2012/13 financial year. A lower than normal reduction in sales volumes to key customers in the winter periods to offset the growth in sales to the remainder of the customer base did not manifest itself as strongly this year, resulting in additional demands on the OCGT fleet. Electricity demand during the peak periods of 17:00 to 21:00 was still significant, hence the requirement for OCGT generation during peak periods. As generation units are taken off-load for maintenance, it also necessitated the increased usage of these expensive diesel burning OCGT stations. OCGTs were used in winter as well as summer to ensure security of supply. The total production by OCGTs reached GWh (2012/13: GWh). The actual load factor on the plant for the year to 31 March 2014 was 17.16%, (2012/13: 9.03%). Summer and winter have very different load profiles. Unlike winter, where the demand increases during the evening peak, the demand profile during summer is much flatter ( Table Mountain profile as depicted in the figure below) with an increased demand profile throughout the day, primarily due to air-conditioning and geysers. The outlook for the coming year is predicted to be very tight due to the maintenance required by the generating fleet, resulting in Eskom on occasion being up to 1 000MW short to meet the evening peak over the winter period. The summer period shortage may not be as high but was for longer periods.

130 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 130 of 205 Figure 24: Summer and Winter Load Profiles Keeping the lights on Keeping the lights on refers to Eskom s ability to ensure that sufficient generating units are on line, and, during periods of generation constraints, to balance the power supply and demand by using demand-savings initiatives to reduce energy usage. Keeping the lights on is about asking all customers to use electricity more sparingly, especially during peak hours, when demand at times exceeds supply, or when abnormal events occur that impact on the available supply. Previously, Eskom had no choice but to defer power station maintenance in order to keep the lights on, which was not a sustainable approach. At the end of 2012, Eskom s board approved the Generation sustainability strategy. The plan spans five years, with 2013/14 being the first full year that the plan has been in place. The keeping the lights on strategy now also includes managing the demand such that the Generation sustainability strategy can be achieved, while avoiding rotational load shedding, as well as tracking the status of reduction in the maintenance backlog. Eskom s keeping the lights on performance is also assessed in terms of verified energy savings and reductions in the maintenance backlog.

131 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 131 of 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 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 2013/14 was R57 555m compared to MYPD3 decision assumption of R50 772m thus resulting in a variance of R6 783m. However, only capex changes that affect the RAB are adjusted for CECA purposes. The total variance of R6 783m comprises Generation capex overspend by R11 906m, Transmission underspend by R4 679m and Distribution underspend by R412m. 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 R5710m Step 1: Computing change in RAB The change in RAB is determined in terms of rule as shown below 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: Eskom will annually report to the Energy Regulator on its capital expenditure programme, providing information on timing and cost variances 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 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.

132 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 132 of 205 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 R268m. Table 47: Calculation average capex FY 2014 CECA Calculation -Variance between actual and allowed capex Calculation ref Eskom Regulated divisions Allowed MYPD capital expenditure Less: Allowed capital expenditure excluded for CECA purposes A (14 830) Future fuel (2 740) Technical and refurbishment capital expenditure (12 090) Capex subject to re-measurement for CECA B Actual MYPD capital expenditure Less: Actual capital expenditure excluded for CECA purposes C (21 077) Future fuel (2 675) Payment received in advance recognised to revenue (1 444) Technical and refurbishment capital expenditure (16 958) Actual Capex subject to re-measurement for CECA D Annual difference (5 710) Technical and refurbishment capital expenditure excluded for CECA purposes C - A (6 246) Capex subject to CECA for re-measurement D - B 536 Average capital expenditure difference for CECA calculation (D-B)/2 268 Allowed Return - NERSA MYPD 3 decision E 3.4%

133 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 133 of Step 2: Computing return impact of change in RAB The RAB adjustment of R268m, as shown in table 50 below is multiplied by the allowed return on assets of 3.36% which equates to R9m CECA impact for inclusion in the RCA. This is in accordance with rule shown below: Balances on the CECA will be adjusted as follows in the Regulatory Clearing Account (RCA) as follows: 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. Table 48: CECA Calculation- Return due to/by Eskom FY 2014 CECA Calculation : Return due to/(by) Eskom Calculation ref Eskom Regulated divisions MYPD3 Regulatory assets base Add /(Deduct): Current year average capex variance 268 Add/ (Deduct): Cumulative prior year capex variances 0 Adjusted RAB A MYPD3 allowed return on assets B Return on adjusted RAB A * C Increase / (Decrease) in return for RCA (A*C)-B 9 MYPD3 allowed return expressed as a percentage of the rate base C 3.36%

134 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 134 of MYPD3 decision Below are extracts from MYPD3 decision reflecting approved RAB of R699bn and returns on asset at 3.4%, generating returns of R23 477m and capital expenditure of R50 772m. Table 49: Regulatory asset base for 2013/14 Table 50: Returns and percentage allowed in 2013/14 Table 51: Capital expenditure in 2013/ Capital expenditure reprioritised After the NERSA revenue decision Eskom had to reprioritise its capital projects over the MYPD3 period. Key challenges that are facing Eskom in the CAPEX portfolio: Eskom s MYPD3 revenue application assumed capex of R337bn over the five years The NERSA revenue determination was based on an assumption of R230bn capex. After Eskom had analyzed its funding situation and re-prioritized its capex projects it decided on a portfolio of R251bn Generation sustainability requires increased refurbishment to improve plant performance and availability in order to balance supply and demand

135 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 135 of 205 Generation environmental compliance requires projects in line with the partial compliance approach The revised estimates of costs to completion of the New Build Programme indicated significant variation from the original business case figures that were in the MYPD submission Taking the above into consideration, Exco went through a robust process of determining critical projects within the capital portfolio. A portfolio of R300bn was approved by the Board. The capital expenditure portfolio of R300bn comprises: - R251bn ( funded portfolio) - R49bn ( unfunded) Figure 25: NERSA determination vs. Eskom Allocation To address the key challenges Eskom allocated funding as follows Given that the revised capital expenditure portfolio is R300bn versus the available funding of R251bn, Eskom determined criteria to optimally allocate the limited funds. Funding available

136 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 136 of 205 was allocated to projects to the value of R230bn at concept, definition and execution phase as follows: Projects with Execution Release Approval (ERA) with contractual commitments where the cost of cancellation and legal implications would outweigh the benefit of cancellation to fund other highly critical projects Projects with ERA but no contractual commitments provided they are still critical : a project with ERA approval has passed the hurdles such as final business case, costbenefit analysis, servitude acquisition and environmental approvals compared to a project at pre-planning phase which may not pass these hurdles and thus not proceed to execution Projects that were at concept and definition phase with high probability of progressing to execution, were allocated ERA funds so as not to impede project development The balance of the R21bn available was allocated as per the Board resolution according to the criteria below: Transmission N-1 Compliance in order to maintain Transmission Operating License Distribution grid code compliance in order to maintain Distribution Operating License Generation Environmental Compliance to prevent legal contravention Concentrated Solar Power to fulfill World Bank project specific lending requirements Independent Power Producers (IPP s) to enable adequate integration to the network and in support the DOE IPP programme This resulted in a residual unfunded portfolio of R49bn (R300bn less R251bn) Table 52: Approved capex portfolio mix Capital Expenditure FY2014~2018 MYPD3 decision Reprioritised Variance Generation new build R70bn R112bn R42bn Generation other R58bn R64bn R6bn Transmission R51bn R35bn - R16bn Distribution R44bn R26bn - R18bn Corporate R7bn R14bn R7bn Total R230bn R251bn R21bn

137 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 137 of Reasons for variance Generation new build is R42bn above the amount in the decision due to higher, and subsequently further revised, estimates for costs to completion Generation other is R6bn above the decision amount due to the increase in refurbishment to improve plant performance and availability, and for environmental compliance Transmission is R16bn below the amount in the determination due to the proportion of projects at pre-planning phase compared to those at concept, design & execution phases. Distribution is R18bn below the amount of the determination due to proportion of projects that will get concept approvals in year 4 & 5 of MYPD3 compared to earlier years. Furthermore, Corporate services is R7bn above the determination to cater for critical strategic projects: - Sustainability R6bn - Eskom Real Estate R2bn - Group IT R5bn - Fleet R1bn 15.4 Capex actuals in 2013/14 Eskom spends approximately half of capital expenditure on new build projects through the Goup 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 (table 56 below) and amount used in the CECA calculation.

138 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 138 of 205 Table 53: Reconciliation between Capex shown in the integrated report and CECA calculation Reconciliation between Eskom Integrated Report capex and CECA disclosures FY 2014 Group capital Generation Transmission Distribution Subtotal Adjustments : Exclude DOE capex included as part of Distribution Include Future fuel capex Include Corporate and other Total per CECA disclosure Table 54: Capital Expenditure (excluding capitalised borrowing costs) per division

139 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 139 of Delivering on capital expansion Eskom started the capacity expansion programme in 2005 to build new power stations and high-voltage transmission power lines to meet South Africa s rising demand for electricity and also to diversify our energy mix. The programme, which started with the return-toservice (RTS) programme and is currently expected to be completed by 2021, will increase generation capacity by MW, transmission lines by 9 756km and substation capacity by MVA. Since inception, the capacity expansion programme has resulted in additional generation capacity of MW, mainly through the RTS programme, km of transmission lines and MVA of substation capacity. The programme has cost R265bn to date (excluding capitalised borrowing costs), while the total cost-to-completion of the programme is currently estimated at R361bn (excluding capitalised borrowing costs). Delays at Medupi The cumulative cost incurred on Medupi as at 31 March 2014 is R77.0bn against a total budget of R105.0bn (excluding capitalised borrowing costs) The project schedule recovery processes are already showing good results. Project cost, time and commercial reviews are aligned with the integrated schedule and preliminary milestones are in place to achieve the planned synchronisation dates, as well as the revision of their estimated cost at completion There are technical issues surrounding welding on the Unit 6 boiler and recovery strategies have been put in place to implement solutions to the post-weld heat treatment. The weld procedure qualification record re-qualification exercise is substantially complete with all welds procedures verified and accepted by Eskom engineering and the approved inspection authority. Remedial work is in progress at the boiler and for welds identified as being defective. Boiler re heater work is complete and has been signed off by Eskom. The control and instrumentation contractor has progressed well in some areas while they still remain late in other areas. Site access is also a major contributing factor to current delays. The factory acceptance test in this regard was conducted and passed. There are still outstanding distributed control system related defects that will be dealt with via site acceptance testing.

140 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 140 of 205 The control and instrumentation solution and mitigation strategy is in place: Eskom has decided to step-in under sub-clause 17.7 (employer s step-in rights and additional remedies) of the Medupi control and instrumentation system works contract, and has placed a contract with an alternative contractor for engineering and manufacturing of the boiler protection system for Units 6 and 5, up to factory acceptance test stage. This contractor is currently busy with the pre-factory acceptance tests on the boiler-protection system Units 1 to 4: Initiated commercial process for a closed enquiry to selected group of suppliers for initially an early work order and then a complete work enquiry for the full solution. All 64 air-cooled condenser fans have been commissioned and are undergoing optimisation. The coal-conveyor system is ready to take coal from the mine. A review of the current R105bn budget is underway and entails the following: An independent review of the deep dives of the control/cost logs of each contract package and owner development costs in order to quantify the cost impact The refinement of the integrated project schedule for Units 5 to 1. The organisational structure has been reworked, with some reorganisation done for Units 5 to 1. A new unit based organisation is in place, which includes package-based commercial management. The first synchronisation of Medupi Unit 6 occurred in March The Medupi partnership agreement between Eskom, principal contractors and organised labour has been signed, with 69 site-specific issues that were agreed. Eskom has taken the initiative in facilitating the establishment of the Medupi leadership initiative to address the consequence of demobilisation of workers and the impacts on the community and the local economy of Lephalale. More than 250 opportunities were identified, six were prioritised and funding was committed by the collaborating partners to kickstart the initiative.

141 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 141 of Kusile The cumulative cost incurred on Kusile as at 31 March 2014 is R66.6bn against a total budget of R118.5bn (excluding capitalised borrowing costs). The Kusile power station project has also been impacted by overall poor contractor performance. The Unit 1 boiler continues to impact several of the top 10 critical paths for Unit 1 synchronisation. Specifically, access has been delayed to other contractors for the installation of the Unit 1auxiliary transformers, the transverse ash conveyor foundations, the fabric filter electrical building, and the compressed air building. The Unit 1 target date for first synchronisation is first half of This date is driven by the release of the area by the boiler contractor and the start of construction by its subcontractors appointed for the compressor building. Compressed air is required for Unit 1 commissioning. The Kusile team continues to work with the boiler contractor in these areas and with followon contractors to develop mitigation strategies for the work Ingula The cumulative cost incurred on Ingula as at 31 March 2014 is R19.4bn against a total budget of R25.9bn (excluding capitalised borrowing costs). Safety continues to remain a key focus at Ingula, especially following the accident in the inclined high-pressure shaft 3 4 on 31 October The Mine Health and Safety Inspectorate of the Department of Mineral Resources issued a work stoppage instruction in terms of section 54 of the Mines Health and Safety Act (MHSA) in the inclined high-pressure shafts as a result of the incident. It remains in effect in that no work is allowed to commence and continue in the inclined high-pressure shafts. The safe work procedures, risk assessments and documentation approval relating to the above accident are being finalised. The MHSA section 54 work stoppage instructions has not been completely lifted, but has been conditionally lifted to allow for cleaning of the inclined high-pressure shafts - It is estimated that work will restart during June This has set back the completion schedule at Ingula.

142 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 142 of 205 Although no construction work is allowed to commence and continue in the inclined high pressure shafts, work on other parts of the site continues. The aforesaid documentation was submitted to them for approval at the end of April The full impact of the accident on the schedule at Ingula is currently being assessed by the project team. As a result the projected forecast dates (after the accident) for the first unit (Unit 3) synchronisation is the second half of The accident will also impact the remaining units synchronisation dates New Build Cost Changes On the back of the new build delays in commissioning as discussed earlier, there have been costs increases in these projects when compared to the MYPD3 decision. Interventions are in progress to potentially accelerate the schedules, which will assist in potential cost savings. These cost savings will primarily be derived from the earlier demobilisation of project resources and the reduction of potential claims Medupi: Cost overruns The project experienced budget 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.

143 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 143 of 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. These interventions 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 Ingula : Cost overruns 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 Conclusion on capex A number of key strategic challenges exist that require an Eskom Capital Portfolio of R300bn, as opposed to NERSA assumption of R230bn for purposes or the MYPD3 revenue

144 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 144 of 205 decision. 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. The Board exercised due diligence and prudence in: Approving the portfolio of R300bn Allocating the limited funds to projects with existing commitments and highly critical areas The government support package provides an additional R29bn of funding (above the R251bn) which will be allocated to critical risk areas in line with criteria to be approved by the board, which will enable the execution of R280bn of the approved R300bn. In order to address the remaining R20bn funding gap the following is being pursued: The portfolio is being continuously scrubbed and optimised to identify efficiencies Mitigating controls, risk treatment plans and other alternatives are being developed to ensure that the residual risks are effectively managed. In the event that the risks cannot be adequately mitigated, the executive committee and the Board will be required to effect tough decisions on projects, including cancellations, within an acceptable risk appetite.

145 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 145 of Inflation adjustment The RCA submission makes use of the two inflation adjustments linked to para in the MYPD methodology relating to operating costs which are included in the RCA. Principles around the inflation linked to regulated asset base have not been included in the RCA submission but are explained below for NERSA consideration Operating costs In compiling the inflationary adjustment, the cost of cover and arrear debts are excluded in the computation. Operating costs are subject to an adjustment for inflation. 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 55: Inflation adjustment Inflation variance adjustment Decision Actuals Inflation 5.60% 5.70% Inflation index Given the higher inflation profile over the period, operating costs were adjusted upwards by R33m (R34 876/1.056 * less R34 876) Regulatory Asset Base Eskom s opinion is that there is alignment to the MYPD methodology for inflation adjustments linked to the regulatory asset base and recommends that NERSA take this into consideration as explained below. The MYPD Methodology requires the RAB to be valued at Modern Equivalent Asset Value (MEAV). Rule of the MYPD Methodology states Each year the MEAV value will change. Because it is not practical to conduct an entire MEAV study every year, the value

146 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 146 of 205 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. The annual indexation of the RAB is required due to the use of a real (rather than a nominal ) rate of return thus, the inflation impact that would otherwise be reflected in the value of the nominal rate of return (which is higher than the real rate, by the rate of inflation) and thus in a higher revenue in that year, is instead reflected through the annual inflation indexing of the RAB, which then results in a higher future revenue stream (through depreciation and ROA) in order to recover the shortfall in the return of that original year by spreading it over the remaining operational life of the asset. Therefore, in the event that a real rather than a nominal 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. Due however to the 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. Therefore 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. Rule of the Methodology acknowledges that the RAB would be valued at the depreciated MEAV, and the Rule envisages that the RAB value as based on MEAV would likely change annually. However given that it is quite onerous to perform a complete MEAV every year, Rule provides for the option to annually inflate 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 in fact, it can be argued that the MEAV is a proxy for annual inflation indexing in the first place, thus to use annual inflation indexing would merely reflect the original concept. Annual inflation indexing (throughout the operational life or in between formal MEA-type revaluations) is also the approach followed by many regulators worldwide, where the methodology is based on real return / revalued assets. An MEAV study is usually done with respect to a specific historical date rather than with respect to a future date. In fact to perform an MEAV study with respect to a future date will

147 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 147 of 205 usually entail rolling forward, using a forecasted inflation rate, from a MEAV study of a specific historical date. Therefore, in the context of an MYPD revenue decision, clearly the application of rule requires that a forecast be made of the future annual PPI. The usual process will entail a forecast being made by Eskom in terms of its revenue application, which Nersa will review and adjust it if chooses. Neither Eskom nor Nersa will be certain of the future annual PPI at the time of making the revenue application and the revenue decision, and neither entity will have any control over the actual outcome in terms of the PPI rate. However, in terms of sound regulatory practice globally, variables over which the regulated entity has no control are typically remeasured and adjusted for through revenue, after the fact. In this context, changes between forecasted inflation rates and actual inflation rates can either be established through annual retrospective MEAV studies (which would be very onerous and expensive) or by measurement of the variances between forecasted inflation rates and actual inflation rates, until another formal periodical MEAV study is performed, with the revenue changes required due to such variances being implemented through some type of retrospective revenue adjustment mechanism. Nersa acknowledges and adheres to this global norm of sound regulatory practice (of retrospectively adjusting the originally allowed revenue, based on remeasurement of forecasted variables over which the regulated entity has no control) and has since the establishment of the regulatory methodology (including from the first MYPD methodology) incorporated the remeasurement of actual inflation rates vs. those assumed for purposes of the revenue decision, with the originally allowed revenue being adjusted for the effects of any such inflation rate variances. Such adjustments have taken effect through the various clawback, correction factor and clearing account mechanisms. The current Methodology includes this concept under Rule : 14.1 Risk Management Device The risk of excess or inadequate returns 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:

148 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 148 of The nominal estimates of the regulated entity will be managed by adjusting for changes in the inflation rate. In terms of the above rule 14.1 and , the excess or inadequate return is managed through adjustments to allowed revenue, by means of the RCA. The difference between the actual nominal inflation rates vs. the rates as assumed for purposes of the revenue decision is one of the items for which allowed revenue is adjusted by means of the RCA. Therefore, to understand how a change in inflation rate results in an adjustment to allowed revenue, it is necessary to consider the regulatory formula for allowed revenue as set out in the Methodology s section 3: The Allowable Revenue (AR) for Eskom for the MYPD period must be determined by applying the AR formula. The following formula must be used to determine the AR: AR = (RAB x WACC) + E +PE + D + TNC + R&D + IDM + SQI + L&T +/- RCA The elements of the AR formula which are subject to changes in the inflation rates would thus be adjusted for the effect of such change in inflation rate. Given that the value of AR is a function of the sum of the values of the individual elements, the adjustment to those elements would thus change the AR. The mechanism by which the AR is changed is the RCA, in which all potential adjustments to Eskom s allowed revenue.. is accumulated, therefore the adjustment in the element due to the change in the inflation rate is accumulated in the RCA. The application of Rule to operating costs ( E in the above AR formula) implies retrospective adjustment to the amount of operating costs as originally assumed for purposes of the revenue decision, with the revenue effect of a change to that element of AR (i.e. to that revenue building block ) and thus also to AR, being recovered through the RCA. As discussed above, the RAB is also adjusted for inflation in terms of the regulatory Methodology rule The value of RAB is however not directly summed in the AR formula, but it is embedded in the calculation of the amount of ROA (through the AR element of RAB x WACC ) and it is embedded in the amount of depreciation i.e. D in the

149 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 149 of 205 AR formula, which both are directly summed in the AR formula. Therefore, any variances in the RAB value due to differences between the actual nominal inflation rates vs. the rates as assumed for purposes of the revenue decision would translate to changes in the amounts of the AR elements of ROA (i.e. RAB x WACC ) and D, i.e. the revenue building blocks of depreciation and return. Similarly to operating costs, the revenue effect of changes to those two revenue building blocks are recovered through the RCA, in which all potential adjustments to Eskom s allowed revenue.. is accumulated. Rule requires that the value of the RAB will be increased by the Producer Price Index, each year. Analysing the MYPD3 revenue decision reflects that nil annual inflation was assumed for purposes of valuing the annual RAB. Therefore the inflation rate variance applicable to the valuation of the RAB for year 2013/14 is equal to the actual inflation rate (in this case, PPI) for 2013/14. The adjustment to the amount of depreciation and return which results from the adjustment to the RAB is thus reflected in Eskom s calculation of the RCA balance as at 31 March The MYPD3 Reasons for Decision also confirms that the RAB would be subject to periodic revaluation. If a periodic revaluation is performed during the MYPD3 cycle it would then be a substitute for annual indexation or annual inflation adjustment for that year on which date the periodic revaluation is performed, as is required by the MYPD Methodology (presumably with such revaluation again being subject to Nersa verification and approval). However in the years between the formal periodic revaluations, the previous RAB value will be adjusted at the PPI rate, as required by Rule Inflation adjustment on RAB revenue impact Summary: According to Rule the RAB must be indexed annually at the PPI rate. The adjustment to AR comprises of the adjustment to ROA (i.e. RAB x WACC ) as well as to D :

150 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 150 of 205 Table 56 : Summary of RAB inflation adjustments Inflation adjustments relating to regulatory asset base 2013/14 R m Return on assets increase due to change in inflation rates 661 Depreciation increase due to change in inflation rates TOTAL increase in RCA for 2013/ The table below compares the percentage that was used for annual indexation of the RAB, to the actual percentage. The table also sets out the adjustment to the RAB due to this variance. The variance in the RAB indexation does not translate to a direct revenue adjustment but translates to an adjustment to the amount or Return as well as the amount of Depreciation. The table sets out those adjustments as well, which flow into the RCA, and reconciles to the total RCA adjustment as per above. Table 57: Return on assets MYPD3 decision _ No indexing MYPD3 decision _ Including indexing MYPD3 Variance _ Index Vs No Index Return on assets (ROA) 2013/ / /14 Return on assets (R'm) _ Assets multplied by ROA% Generation Transmission Distribution Depreciation Generation Transmission Distribution

151 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 151 of 205 Table 58: Regulatory asset base MYPD3 decision MYPD3 Variance MYPD3 decision _ Including _ Index Vs No _ No indexing indexing Index Eskom Regulated MYPD3 Regulated Asset Base (RAB) 2013/ / /14 Closing RAB Generation Transmission Distribution Average RAB Generation Transmission Distribution

152 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 152 of Integrated demand management 17.1 Demand-side management: Demand side management is divided into two broad programmes, as discussed below: 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 R350m on demand market participation, the reduction from previous year mainly as a result of a significant decrease in the power buyback programme 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 compact fluorescent lamps (CFL) programme phase 2 of the CFL roll-out has been completed, with 1.2 m bulbs installed, realising verified savings of 65 MW in 2013/14.The CFL roll-out phase 3 began in February The solar water-heater programme Eskom contributes to the government s solar water heating initiative, which aims to install one million solar water heaters. Over the year ended 31 March 2014, a total of solar water heaters were installed, bringing the total for the rebate programme and residential contracts to since its inception in 2009

153 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 153 of 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 lightings 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. Eskom s integrated demand management for FY 2013/14 constituted under-expenditure for both DMP of R905m and EEDSM of R316m. In addition Eskom incurred R1 117m for power buyback programmes 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 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

154 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 154 of Allowed EEDSM for 2013/14 The allowed rate for EEDSM savings is R3.84m/MW with 379MW savings being assumed which will cost R1455m. Table 59: EEDSM MYPD3 Decision Funding ` 2012/13 Approved Expenditure 2013/ / /16 Applied for Approved Applied for Approved Applied for Approve Programmes - Peak Demand Savings(MW) Programmes - Annualised Energy Savings(GWh) Programme Costs Operating Costs including Depreciation Other costs R/MW R/kWh (183) - (191) - (204) Actual EEDSM for 2013/14 Demand-side management (DSM) encourages customers to limit their electricity usage. Demand-side management initiatives support national security of supply and minimise the negative economic consequences of a power shortage for the country. During 2013/14, Eskom spent R1.36 bn on DSM whereas the MYPD 3 decision for the 2013/14 financial year was R1.46 bn. The progammes installed resulted in 409MW of savings during the year MW savings used for EEDSM calculation 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.

155 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 155 of 205 Table 60: Recon between demand savings MWs used in RCA Calculation The table above strips out the DOE funded EEDSM programmes of 12.1 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 FY2014 of 7.1 MW are included in the RCA. Lastly savings which were installed but not yet verified of are excluded for the RCA analysis. Hence the total capacity verified for FY2014 after all the adjustments is MW as is reflected in the M&V report submitted to NERSA. A summary of EEDSM results comprising costs, capacity (MW) and rate per MW are presented below. Table 61: EEDSM in 2013/14 EEDSM in 2013/14 MYPD3 Decision Actuals Variance Demand savings target (MW) 379 MW MW MW DSM costs (R m) R1 455m R1 356m - R99m Rate (R/MW) R3.84m R4.57m - R0.73m Computation of EEDSM for the RCA Eskom has computed the IDM impact for the RCA purposes on the basis of MW saved compared to the decision at the assumed decision rate (R/MW). In 2013/14 the total IDM impact for purposes of the RCA is R316m penalties.

156 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 156 of 205 Due to the lower capacity of 82.3 MW being saved when compared to the target, the variance is multiplied by the allowed rate of R3.84/MW resulting in a penalty of R316m as presented below. Amount to be included in the RCA balance is computed below: EEDSM = R3.84m/MW X MW = - R316m The costs incurred of R1 356m, compared to assumed costs for purposes of the revenue decision of R1 455m, equates to lower expenditure of R99m Demand Market Participation and Power Buy Backs Allowed DMP and Power Buy Backs in 2013/14 NERSA allowed R1167m for demand market participation costs in 2013/14. Furthermore, except for an allowance of R688m for 2014/15, no costs were assumed from April 2015 onwards until March 2018 due to the assumption of new build capacity being added timeously per the MYPD3 reasons for decision under paragraph 70. Lastly, the Regulator indicated that no allowance was made for power buyback as the initiative is covered by DMP. Para 77 According to the IRP 2010, beyond 2015/16 there will be enough capacity due to the introduction of Medupi and Kusile power stations on the national grid. Therefore it was necessary to adjust the DMP and power buy-back programmes accordingly. It should be noted that the power buy-backs programme is disallowed as the initiative is covered by the DMP.

157 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 157 of Actual DMP and Power Buy Backs in 2013/14 Eskom spent R1379m on DMP and PBB combined in 2013/14 comprising R262m for DMP and R1 117m for power buy backs. This resulted in an over spend of R212m. Table 62: Actual DMP and Power Buy Backs in 2013/14 Demand Response MYPD3 Decision Actuals Variance Demand Market Participation (R'm) Power Buyback (R'm) Power Buyback - Income statement 2014 (R'm) Power Buyback - Carry forward from 2013* R'm) DMP and PBB costs (R'm) DMP -Demand savings (MW) * A provision was raised for all contractual obligations in These services was only rendered and paid for in the 2014 financial year Power buy-backs Included in the costs associated with Demand Response are costs incurred for power buyback programmes during the summer months of April, May and November The following table provides a summary of the actuals costs and performance over the PBB contractual period.

158 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 158 of 205 Table 63: Actual Costs and Performance of PBB Month Demand Reduction (MW) Cost 13-Apr 13-May Nov/Dec-13 Total 915 R 488.9m 877 R 488.4m 497 R 139.6m R m Based on the MYPD2 RCA decision where NERSA disallowed the entire amount for power buybacks, Eskom has assumed that principle will be applied for this submission. Therefore the expenditure R1116.9m is removed for RCA purposes. These projects did provide demand relief and Nersa should consider a form of cost recovery Demand market participation (DMP) Demand market participation was underspent by R905m during the year as presented in the Actual DMP and power buybacks in 2013/14 table. The Demand Market Participation experienced challenges in uptake. Key reasons for these are mainly for industrial customers, a threshold seems to have been reached where further uptake does not seem to be materialising DMP and Power buy back variance in 2013/14 DMP variance = Actual DMP Allowed DMP Eskom spent R1 379m on for DMP and PBB combined compared to the decision of R1 167m equating to an over expenditure by Eskom in 2013/14 of R212m. However for RCA purposes only DMP is being submitted and thus the net impact is an under spend of R905 million which is due to the consumers.

159 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 159 of Total IDM impact for RCA in 2013/14 In 2013/14 the total IDM impact reflected under expenditure for the RCA was R104 million in favour of the consumer which comprised R316 m for EEDSM and R905 m relating to demand market participation programmes.

160 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 160 of Operating costs Operating costs comprises employee benefits, maintenance and other operating costs. It excludes IDM which is treated separately for RCA purposes. Operating costs The nominal estimates of the regulated entity will be managed by adjusting for changes in the inflation rate Adjusting for prudently incurred under-expenditure on controllable operating costs as may be determined by the Energy Regulator Allowed operating costs in 2013/14 The MYPD3 decision comprised the building blocks for allowed revenue per the MYPD Methodology as described. Therefore the allowed operating costs disclosed allowed for revenue of R906bn over the five year horizon. However, following the subsequent revision of the revenue from R906bn to R863bn was attributable to operating cost component and thus reduced to cater for the revision. Some of the cost categories within operating costs are presented below. The allowed operating costs are R39 703m as highlighted in the table below. Allowed operating costs in 2013/14 is R39 703m Allowed employee costs in 2013/14 Table 64: The allowed employee costs for Generation, Transmission and Distribution

161 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 161 of Allowed maintenance costs in 2013/14 Table 65: Allowed Maintenance Costs Allowed arrear debts in 2013/14 Table 66: Allowed Arrear Debts Allowed cost of cover in 2013/14 Table 67: Allowed Cost of Cover Allowed corporate costs in 2013/14 Table 68: Allowed Corporate Costs

162 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 162 of Actual operating costs in 2013/14 During 2013/14 Eskom incurred operating costs excluding IDM of R48 352m which compares to the MYPD3 assumption of R37 784m resulting in over expenditure of R10 568m. As there is an overall over expenditure position, Eskom operating costs don t qualify for the RCA adjustment except for the inflation adjustment. Eskom has exceeded the assumed costs for operating activity in 2013/14 by R10 568m which is driven by staff costs of R3 442m, other income of -R1 504m, net impairment loss of R790m, cost of cover of R750m and other operating costs of R7 090m as summarized below. Table 69: Summary of Operating costs in 2013/14 FY 2014 FY 2014 Allowed AFS actuals Regulatory adjustments RCA actuals RCA balance Employee benefits Other opex Other income Net impairment loss Cost of cover Operating costs (R'm) To derive the RCA actuals, adjustments are made to the amounts disclosed in the AFS for the following items: 1. DSM costs in each line item is removed as it is measured separately on the MWs achieved and not actual less decision 2. SAE and Telecomms are excluded as it is not regulated. 3. Internal revenue is reclassified out of other opex and shown as part of revenue for regulatory purposes.

163 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 163 of Reasons for variance in other operating costs Employee benefits Actual staff costs have exceeded the MYPD3 decision by R3 442m despite implementing the 5.6% average increase assumed in 2013/14. 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. In addition Eskom capitalises a significant amount of employee costs which averages between R4 000m to R5 000m over the last few years. This is important as for regulatory purposes as capitalised costs are recovered over the life of the assets. As the life of Eskom assets are long term in nature with new build projects being about 50 years, this will mean that Eskom only recovers capitalised labour costs over this long duration further placing pressure on Eskom s cash flow situation. A summary of employee benefits from 2009/10 to 2013/14 reflects that net employee benefits before capitalisation was R20 776m in 2012/13. The amount disclosed in the AFS is marginally higher than that used for regulatory purposes as a small portion relating to unregulated activities are excluded. Table 70: Trend in actual employee benefits Actual Employee costs 2013/ / / / /10 Net Employee costs (after capitalisation) Employee costs capitalised to assets Gross Employee costs (R'm) Therefore from a cash flow position Eskom incurred R28 069m for labour costs in 2013/14. With the balance above the amount allowed in the MYPD decision is being funded by debt.

164 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 164 of Maintenance Eskom spent R1 711m 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 Arrear debt Debt collection, especially from municipalities, is a challenge with arrear debt increasing significantly compared to the previous year. Arrear bad debt was 1.10% of external revenue for the year which is more than double the assumption of the MYPD3 decision (0.5%) resulting in a variance of R790m. The municipality arrear debt as well as residential arrear debt in Soweto continues to grow Soweto arrear debt Soweto s arrear debt continues to increase. Eskom supplies electricity to about households in Soweto and average payment for the year is 16% (2012/13: 16%). The total Soweto debt, as at 31 March 2014, stood at R3.6bn (31 March 2013: R3.2bn), excluding interest charged on overdue amounts. During the year, defaulting customers were disconnected, which is not enough to curb the debt. The implementation of the residential revenue management strategy, which includes Soweto revenue management, will assist to improve future revenue streams. Due to the high prevalence of illegal network connections, including the bypassing of Eskom meters, the situation has further resulted in an overloading of the network, high maintenance costs, a high volume of call-outs, poor quality of supply, and a considerable number of safety incidents. Non-technical energy losses are currently 49%.

165 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 165 of 205 Easy access to the Eskom network and a culture of non-payment are the two major contributing factors to the aforementioned challenges that Eskom faces Response Strategies From 2007, Eskom ran a split metering pilot project to customers in Chiawelo. This entailed vandal-proof technology, comprised of steel protective enclosures to house customer meters, with telecommunication software allowing Eskom to read each meter remotely for billing purposes. Eskom was also able to monitor any unauthorised access to the enclosure or the meter. As these new meters were installed, while contributing to operational efficiency by allowing for the remote reading, disconnection, and reconnection of meters, the technology delivered significant positive results: A reduction in non-technical energy losses from 64% to 20% A 40% reduction in total energy consumed A reduced number of outages due to improved quality of supply A reduction in the number of safety incidents Due to the success of the pilot, Eskom is proposing full implementation of the split metering technology, including the protective enclosures, for the greater Soweto service area. To mitigate the risk of resistance by the community (to the installations), Eskom is proposing that arrear Soweto debt R3.67 billion in capital debt and interest of R3.41 billion be written off. The current monthly interest charge on arrear debt is substantial as it represents up to 62% of current monthly charges where accounts are in arrears. The purpose of the Soweto Revenue Management Strategy is to arrest the growing debt trend, curb energy losses, encourage legal power usage, and ensure continued financial sustainability of the business. The strategy primarily entails payment of the current electricity debt and enabling support will come through the implementation of split metering technology and conversion to prepayment.

166 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 166 of 205 Implementation will also be supported by: The social marketing campaign to change customer behaviour and ensure legal power usage; Stakeholder management to secure community buy-in and political support and forge partnerships; Supplier development and localisation of economic activity and A debt intervention proposal to unlock the current stalemate on implementation of split metering technologies Municipal arrear debt Municipal arrear debt remains a concern. The top twenty defaulting municipalities make up ~80% of total municipal arrear debt with R1.2 billion (as at end March 2014) of the total arrear debt (>30days) being made up from the top six defaulting municipalities, namely Matjhabeng, Emalahleni, Ngwathe, Maluti a Phofung, Thaba Chweu and Lekwa Municipalities. Eskom makes every effort to ensure municipalities pay their current account and then also make payment towards the outstanding debt so that the debt situation does not worsen. Agreements are being reached with municipalities for all current bills to be honoured and for debt to be paid off within twelve months. However, there is some concern that some municipalities may not adhere to agreed payment plans and that they are using this as a way to buy time without any real commitment to pay. The rising municipal debt requires a more strategic approach as there are underlying causes which lead to non-payments and consequently requires a holistic strategy on these matters. Eskom has had numerous meetings with our shareholder (DPE) and National Treasury to discuss how to sustainably address the municipal debt issue and on implementing interventions over the longer term to assist in dealing with the challenges. The main municipal debt for Eskom is in the Mpumalanga, North West and Free State provinces. In October 2013, an agreement was reached with the Mpumalanga Member of

167 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 167 of 205 the Executive Council of CoGTA that all current bills will be honoured with immediate effect; and that debt is to be paid off within twelve months so Eskom should have received all outstanding debt by end October In March 2014, an agreement was reached with the North West Member of the Executive Council of CoGTA and MEC Finance that all defaulting municipalities will be given until 31 March 2015 to pay the outstanding debt. In the Free State, the steering committee (Provincial Treasury (Chair)) constituted for municipal debt is not delivering as expected and the debt is increasing. Eskom is engaging with the Free State Member of the Executive Council of CoGTA on this matter. Eskom adheres to and enforces Eskom s revenue management policy and procedures and conforms to legal (PFMA, MFMA, PAJA) and regulatory requirements. Eskom also consults National and Provincial Treasury and Co-operative Governance and Traditional Affairs Department (Cogta) on dealing with the matter of increasing municipal debt. Disconnection of supply is the last resort. Eskom works towards acquiring the defaulting municipality s payment commitment through obtaining a realistic payment plan, failing cooperation by the municipality Eskom then initiates the disconnection of the electricity supply process in line with the PAJA (Promotion of Administrative Justice Act No. 3 of 2000) process. Eskom has however been restricted in effecting disconnections. In this financial year, Eskom has initiated the disconnection of the electricity supply process in line with the PAJA process with some municipalities, namely the Lekwa, Msukaligwa and Thaba Chweu Municipalities (in Mpumalanga); the Maluti-a-Phofung, Ngwathe and Mafube Municipalities (in Free State); and other smaller defaulting municipalities. No disconnection of supply has taken place to date as appropriate action was taken by the municipalities following receipt of the disconnection notices from Eskom. Eskom provides regular feedback to National Treasury by reporting the municipal debt status as required in the Municipal Finance Management Act (MFMA). Historically, payments by municipalities are strongly correlated to them receiving the equitable share from National Treasury (payments in December, March, June and

168 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 168 of 205 September). Previously this funding was sufficient to settle outstanding electricity debt, but this is no longer the case with municipalities facing increased electricity prices and reduced funding. Disconnection of supply is the last resort for Eskom. In line with the Promotion of Administrative Justice Act (2000), the company sent disconnection notices to some of the defaulting municipalities during the year. No disconnections have yet been effected, as all the municipalities that received disconnection notices responded appropriately, with the exception of one municipality. This matter is the subject of litigation. The total municipal arrear debt (excluding Soweto) as at 31 March 2014 is R2.6bn and numerous meetings were held with the DPE and National Treasury to discuss sustainable ways to address municipal debt and implement longer-term interventions to deal with this challenge Response strategies Eskom s Group Customer Services Division is continuously monitoring payments received and is working towards developing strong relationships with municipalities and with metros, similar to that of Eskom's Key Industrial Customers. Eskom strives to assist struggling municipalities to become technically competent in regard to electricity tariff practices and managing losses and to have more efficient and effective revenue management processes Large power users arrear debt There has been a slight increase in the number of key industrial customers not honouring their payments on time, due to cash flow problems caused by the economic climate. All nonpayments are handled according to Eskom s credit-management policy, with the disconnection process being initiated where necessary

169 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 169 of Cost of cover The cost of cover costs incurred was R2 909m compared to decision of R2 159m resulting in over expenditure of R750m. Cost of cover has increased due to cost escalation in new build projects compared to that in the decision. Eskom only budgets for the premium portions (cost of cover / interest differential portion) of Forward Exchange Contract (FEC). Due to the volatility of the Rand we do not consider the spot to spot movements which should offset in any case as you will 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 Treasury s preferred hedging tool for foreign loans are Cross Currency Swaps. However Eskom can only enter into Cross Currency Swaps once we are sure of the repayment profile of the loans and/or the size of the loan on book 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 we try 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. What you do however need to be cognisant of is 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.

170 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 170 of Other operating costs Growth in insurance costs contributes significantly to other costs variance. This follows from the recent Generation plant incidents such as the Duvha unit s breakdowns as well as the fact that the insured asset base is expanding i.e. new assets are added to the insurance portfolio. Following the MYPD3 determination Eskom launched the Business Productivity Programme (BPP) aimed at delivering cost savings and efficiencies throughout the company, which also is investigating strategies to reduce insurance costs Business Productivity Programme (BPP) The Business Productivity Programme (BPP) aims to deliver cost saving opportunities in order to contribute to closing (from a cash perspective) the revenue shortfall that resulted mainly from NERSA s MYPD 3 tariff determination granting an average increase of 8% per annum. The programme focuses on the reduction of the cost base, increased productivity and enhanced efficiencies, and revisions of the Eskom business model and strategy, while the balance relates to cost avoidance. The balance of the cash shortfall is attempted to be closed through higher borrowings and government support initiatives. The initial phase of BPP that was completed on 31 March 2014 focused on the development of savings opportunities or value packages (which included deferment of capital and operating expenditure to beyond the MYPD3 period). Savings opportunities of R73 billion were approved, R13bn more than the R60bn target. Of the R73bn, R62bn comprised cash savings in relation to the February 2014 four year Business Plan. Some of the initiatives could have the effect of increasing costs in future e.g. might be of the nature of raising additional borrowings at higher borrowing costs i.e. at a premium compared to traditional / conventional sources of borrowing. Of the total of R73bn savings opportunities identified, R61.8bn has been cut from the budget. Stringent targets were set and in some cases activities will be discontinued. This could impact security of supply and long term business sustainability. Key trade-off

171 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 171 of 205 decisions need to be made and mitigating actions put in place to manage potential business risks. Figure 26: Projected BPP savings Reference point for MYPD3 operating costs A major reason for variances between actual expenditure for 2013/14 and the assumptions made for purposes of the MYPD3 revenue determination is that NERSA has, in making their MYPD3 revenue decision, considered the assumptions made for purposes of the MYPD2 revenue decision for 2012/13 (year 3 of MYPD2). These were used as the starting point to then escalate operating costs to 2013/14. Thus the time lapse between Eskom making the assumptions for MYPD2 and the end of MYPD3 window constitutes 116 months, nearly 10 years, and even for 2013/14 the time lapse is over 60 months. It is not realistic to expect that the original assumptions would remain valid over this period as disclosed below. This extended timeline provides reason for variances in operating costs relative to the assumptions made for the MYPD3 revenue determination to be adjusted subject to prudency reviews.

172 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 172 of 205 Figure 27: Time lapse between application and MYPD2 decision Cumlulative Months Months MYPD2 period Process Start Eskom Commenced preparation for MYPD2 application September 2008 Eskom MYPD2 application November Nersa MYPD2 decision February 2010 Start April 2010 March 2011 March 2012 End March 2013 March 2018 By Nersa keeping to MYPD2 costs for year 3 of MYPD2 2012/13 as their refernce point for MYPD3, Nersa has ignored information that has occurred over 20 months since the decision or worst 50 months since Eskom commenced their MYPD2 process. Furthermore as this assumption is used over MYPD3 5 year period, the time lapse extends to 116months During the MYPD3 application process Eskom did provide two years of actuals (for 2010/11 and 2011/12) and year-end projections for 2012/ Operating cost variance for 2013/14 RCA Operating cost variance = Actual operating costs Allowed operating costs Based on RCA equivalent actual operating costs of R50 132m and allowed other operating costs in the decision of R39 703m, Eskom has incurred an additional R10 428m 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 Why symmetrical treatment of operating costs is needed 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

173 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 173 of 205 the RCA process, which violates the NERSA mandate in terms of the Electricity Regulation Act to allow utilities to recover full efficient costs. 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. The Methodology s rule 14.1 states with regard to Risk Management Device (e.g. RCA) that The risk of excess or inadequate returns is managed in terms of the RCA (own emphasis). Clearly the risk of excess returns, which are earned due to lower than assumed expenditure on operating cost, would be managed by Adjusting for prudently incurred under-expenditure on controllable operating costs... However, whilst excess returns will be managed through this rule, the non-symmetrical nature of rule will not enable it to address inadequate returns, which rule 14.1 states as part of the intention of the RCA. Although it could be argued that rule covers it with the statement Adjusting for other costs and revenue variances. i.e. that other cost variances includes prudently incurred higher expenditure on operating costs, it is Eskom s opinion that it would be preferable to clarify this issue in rule 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. 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 underexpenditure being clawed-back to the benefit of the consumer but the over-expenditure in

174 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 174 of 205 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. This would act as a severe disincentive to optimal and prudent management decisions and thus function as a 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 overexpenditure (when compared to assumptions made in the MYPD revenue decision) and thus act as sufficient incentive for efficiency. 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). Furthermore, given that most or all of Eskom s key financial metrics will be very weak for a number of years still, it is even more crucial that the assessment of regulatory framework and environment under which Eskom operates should be perceived to be sound and assessed at the strongest possible rating. Eskom raised this issue with NERSA and in 2013 NERSA indicated through correspondence with Eskom that it agreed with Eskom and hereby confirm the following:... The treatment of cost variances referred to in the Rules will apply both to over and under expenditure and the Rules will be amended to reflect this position.

175 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 175 of 205 It is on that basis i.e. in anticipation of such rule amendment being made in time for the 2013/14 RCA Submission that Eskom included over expenditure on operating cost in its original 2013/14 RCA submission of R38bn in February 2015 which would be subject to prudency assessments. However given that the rules have not yet formally been amended Eskom has revised its 2013/14 RCA Submission to exclude the recovery or prudently incurred higher expenditure on operating costs.

176 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 176 of Interest on RCA balance During the MYPD2 RCA process after having determined the RCA balance, the principle of the time value of money was not addressed. As part of the 2013/14 RCA Submission, Eskom has computed the interest on the MYPD2 RCA decision of R7818m using the prime rate, which equates to a claim of R653m. This amount would have been claimed in the year 1 RCA for MYPD3, but the current MYPD methodology does not cater for interest adjustments. Eskom believes that this is sound economic and regulatory principles which should be rectified in the future.

177 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 177 of Service Quality Incentives Eskom has had interactions with NERSA which reflects the service quality incentives for Distribution and Transmission below. Table 71: Summary of SQI performance in 2013/14 Licensee 2013/14 Distribution SQI R263m reward Transmission SQI R76m reward Total SQI for 2013/14 R339m reward 20.1 Transmission service quality incentives (SQI) for 2013/14 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 2013/14 as been finalized that summarizes the financial reward / penalty based on these results. The SQI reflects a reward of R40m for major incidents and a reward of R36m for line faults measure as reflected in the table below. Table 72: Transmission SQI performance in 2013/14 Measure Performance Result Incentive / Penalty (-) (Rm) Comment SM< Dead band Major Incidents 0 40 Reward Line Faults / 100km Reward Total (R m)

178 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 178 of 205 Figure 28: Transmission system minutes (<1) Table 73: Transmission number of major incidents (>1SM) Note: Number of Major Incidents (>1SM)

179 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 179 of 205 Table 74: Line faults / 100km 20.2 Distribution Service Quality Incentive Scheme (SQI) for 2013/14 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) and 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 the first two years of MYPD3 and earn an incentive reward for both years 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.

180 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 180 of 205 Table 75: Distribution SQI performance in 2013/14 Measure Incentive/Penalty(-) (Rm) March 2014 (Year 1) Totals (Rm) SAIDI SAIFI DSLI SQI Total

181 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 181 of Reasonability tests 21.1 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 illustrate 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 29: EBITDA-To-Interest Cover Ratio It seems that the figure above reflects around 2.60 for 2013/ MYPD2 RCA Balance Implementation Plan In par. 12 to 14 of NERSA s Reasons for Decision for The implementation plan of Eskom MYPD2 Regulatory Clearing Account (RCA) it confirms the above statement of the MYPD3 revenue decision i.e. The allowed returns were such that Eskom achieves an average EBITDA-to-Interest cover ratio in excess of 2 times over the MYPD3 period as illustrated in figure 1 below. Eskom was allowed these returns such that it is able to meet its debt obligations. The forecasted interest cover ratio for the first year of MYPD3 (2013/14) was in excess of 2.5 times. This in an important indicator referred to in the MYPD3 decision as a key measures of the entities ability to meet its debt obligations. Eskom in 2013/14

182 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 182 of 205 realised an actual interest cover of 1.43 times its EBITDA... [thus] not achieving the target EDITDA interest cover ratio (own emphasis). Source: Extract from MYPD2 RCA implementation The above extracts from the NERSA documents confirm that NERSA s intention was that the allowed returns will enable Eskom to meet its debt obligations. If that was the intention then it should be noted that this formula does not directly measure this ability as it only considers the interest cost portion of total debt obligations. To measure the ability to meet debt obligations the formula should be using the total debt service obligations i.e. interest plus debt principal, not just interest Understanding the ratio NERSA s ratio might be similar to Moody s ratio of CFO pre-wc + 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 2.6 for 2013/14 (reducing to below 2.5 by 2017/18, per the graph) 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 comment in the MYPD2 RCA implementation plan was that it is not expected to negatively affect the credit rating.

183 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 183 of 205 However, to achieve that, a value of >3 is probably required 2.6 (and below) would certainly be very negative 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 contribution 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 regulator needs to consult with commercial lenders when assessing the financial viability of the industry on an ongoing basis.

184 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 184 of 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 for loan principal repayment. Thus EBIT is used when one measures only interest cover 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 Computation of ratios for FY 2014 The financial information relating to debt obligations and the earnings for FY2014 is presented in table below showing EBITDA of R23 497m, EBIT of R11 563m account, net interest payments of R15 781m and total debt serviced of R23 269m.

185 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 185 of 205 Table 76: Financial information for ratios in FY 2014 Financial Information for ratios workings (R'm) FY 2014 Calculation of EBITDA EBITDA A Profit before net finance (cost)/ income - EBIT B Plus: Depreciation and amortisation expense Calculation of Total debt serviced Finance cost Debt securities and borrowings Less gov loan interest Derivatives IRS and CCS Provisions and Employee benefit obligations Finance lease payables Finance income C Investment in securities -823 Loans receivable -353 Net interest per AFS D Add / (deduct) items excluded for purposes of the framework : Provisions and Employee benefit obligations Finance lease payables Finance income Total interest used for calculation Add : Debt repaid Total debt serviced E Various ratios have been computed as summarized below. Eskom s 2013/14 AFS reports on such interest cover ratio and reflects it as 0.68 (not 1.43). However a minimum of 2.5 is 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 2013/14 was 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 2013/14 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

186 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 186 of 205 rating agencies set >3 as the minimum for lower investment grade, with <3 being rates as sub-investment grade EBIT Interest cover ratio The results reflects a EBIT interest cover ratio 0.68 which entails that Eskom did not generate sufficient earnings to cover its interest commitments. Table 77: EBIT Interest Cover EBIT Interest cover Calculation FY 2014 EBIT Interest cover B/D 0.68 EBIT Interest B D Using EBIT interest cover as the reasonableness test, then current 0.68 would change to 2.01 if the EBIT is increased by the RCA amount of R million. This revised EBIT interest cover ratio is within acceptable range of EBITDA: Total debt service ratio The results reflect an EBITDA: debt service ratio of 1.01 which means that Eskom literally covered it repayments due to the principal repayments being deferred during the year. Table 78: EBITDA- Total debt serviced EBITDA : Total debt serviced (Revised calculation to account for debt repaid) EBITDA : Total debt serviced EBITDA Total debt serviced Calculation reference FY 2014 B/E 1.01 B E Using EBITDA- Total debt service ratio as the reasonableness test, then current 1.01 would change to 1.99 if the EBITDA is increased by the RCA amount of R million. This revised ratio is below the acceptable of 3.Hence without the RCA adjustments the above reasonableness is well below NERSA own acceptable range of approximately 2.6 for 2013/14.

187 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 187 of Conclusion Eskom is facing several operational and financial challenges which make the task of meeting electricity demands even more difficult with one event of load shedding and 3 emergencies being declared in the 2013/14. Subsequently the challenges have become much tougher with rotational load shedding occurring from November 2014 on a more frequent basis. In order to reduce the level of interruptions to the economy, Eskom would need to arrest and reduce the unplanned outages of the Generation fleet, utilize supply options which are available (incl OCGTs), commission new build capacity and introduce more short term supply and demand response strategies to stabilise the electricity system. During the last few months several developments towards the stabilisation of Eskom have unfolded, the details of which are as follows: Government has committed to an equity injection in region of R20bn. Ratings agencies have downgraded Eskom which will place pressures on raising debt, Eskom has launched its BPP targeting savings of between R50bn~R60bn over the five year period, Eskom reprioritised its capital portfolio from R337bn to R300bn (of which R251bn can be funded through existing sources) which resulted in reduced allocations to network business and more for new build projects. Operational challenges escalated with Duvha unit 3 and Majuba silo incidents resulting in capacity being removed from the system. Rotational load shedding commenced since November Government has announced a turnaround plan and establishment of War Room. All of these initiatives will come at a cost which would need to be funded. Eskom s sources of funding comprise equity, debt, operational savings and revenue or a combination. 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 2013/14 RCA Submission of R million is driven substantially by revenue under recoveries, higher expenditure on coal burn, IPPs, OCGTs and other primary energy. The over expenditure relating operating costs don t

188 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 188 of 205 qualify for RCA as the MYPD Methodology does not cater for symmetrical treatment of operating costs. Ultimately the 2013/14 RCA Submission 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 2013/14. The need for a significant RCA adjustment is demonstrated by the actual debt cover ratios being well below acceptable norms. In conclusion, Eskom has utilised OCGTs extensively in FY2013, FY2014 and it is expected in FY 2015 as a last resort to limit the impact of load shedding on the economy. The load shedding event on 14 March 2014, reiterated that the most expensive electricity is having no electricity and that the cost of unserved energy to the economy is the most expensive cost for the economy far higher than the fuel cost for operating OCGTs. >>>>>>>>>>>>>>>>>>> >>>>>>>>>>>> END >>>>>>>>>>>>>>>>>>>>>>>>>>>>>>>>

189 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 189 of 205 Annexures: Revenue: Annexure 1: Income Statement in AFS 2014

190 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 190 of 205 Annexure 2: Revenue note 32 from AFS (p81) Annexure 3: Revenue from divisional report 2014 (P47)

191 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 191 of 205 Annexure 4: Key financial statistics FY 2014 Annexure 5: The Eskom energy wheel (Integrated report P22) **Note: All figures are in GWh unless otherwise stated.

192 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 192 of 205 Annexure 6: Sales volumes GWh (Divisional report page 88)

193 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 193 of 205 Primary Energy Annexure 7: Primary Energy Note (AFS FY 2014 page 91) Annexure 8: Actual Energy Procured through IPP Programmes in 2013/2014 (Integrated Report FY2014 page 145) Extracts from Annual Financial Statements FY2014 Integrated Report electronic version: Eskom has successfully connected 21 renewable energy independent power projects (RE IPP) (representing a total capacity of 1 076MW) to the grid. Of these projects a total of 467.3MW is currently available to the system. Total energy procured from IPPs for the year amounted to 3 671GWh at a cost of R3 266 m (averaging 88c/kWh) which is R721 m higher than the NERSA decision for 2013/14.

194 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 194 of 205 IDM Annexure 9: EEDSM Annual report for 2013/14

195 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 195 of 205 Of the MW that were installed, not verified at the end of FY 2014, 12 projects have since been verified. IDM claimed MW for these projects and the actual verified savings are MW (under achievement of 0.95 MW). The assessment reports for a further 15 projects (44.92 MW) is in the process of being finalised.

196 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 196 of 205 Operating costs Annexure 10: Supplementary report 2014, page 48 Annexure 11: Annual Financial Statement 2014

197 MYPD3 2013/14 RCA Submission to NERSA November 2015 Page 197 of 205 Other Income Annexure 12: Annual Financial Statement 2014 Reasonability test Annexure 13: Finance cost extract (AFS FY 2014 page 93)