MYPD 3
(Year 2013/14)
Regulatory Clearing Account
Submission to NERSA
November 2015
MYPD3 2013/14 RCA Submission to NERSA
November 2015
Page 2 of 205
TABLE OF CONTENTS
1
PREFACE ....................................................................................................................................... 15
1.1
The basis of submissions ........................................................................................................ 15
1.2
The structure of 2013/14 RCA Submission ............................................................................. 16
2
OBJECTIVE ................................................................................................................................... 18
3
OVERVIEW OF THE 2013/14 RCA SUBMISSION ....................................................................... 19
3.1
Revenue...................................................................................................................................... 20
3.2
Primary energy .......................................................................................................................... 20
3.3
Environmental levy ................................................................................................................... 21
3.4
Net position of Southern African Energy (SAE) ..................................................................... 21
3.5
Capital expenditure variance ................................................................................................... 21
3.6
Operating costs ......................................................................................................................... 22
3.7
Integrated demand management ............................................................................................. 22
3.8
Other income ............................................................................................................................. 22
3.9
Inflation adjustments ................................................................................................................ 22
3.10
Service Quality Incentives .................................................................................................... 23
3.11
Reasonableness test ............................................................................................................. 23
3.12
Conclusion .............................................................................................................................. 23
4
4.1
FACTORS IMPACTING ON 2013/14 RCA SUBMISSION ............................................................ 24
Timeline for application and decision ..................................................................................... 24
MYPD3 2013/14 RCA Submission to NERSA
4.2
5
November 2015
Page 3 of 205
Changes in fundamental assumptions since MYPD3 application ....................................... 24
REVENUE VARIANCE .................................................................................................................. 27
5.1
Reasons for revenue variance ................................................................................................. 28
5.2
Allowed revenue ........................................................................................................................ 28
5.2.1
Step 1 – Understanding the standard tariff impacts ....................................................... 28
5.2.2
Step 2 – Matching costs and revenue .............................................................................. 30
5.2.3
Step 3 – Understanding the other customer impacts ..................................................... 32
5.2.4
Step 4 – Subsequently, NERSA revised the allowed revenue for standard tariff
customers ......................................................................................................................................... 32
5.2.5
Step 5 - Confirmation of standard tariff volumes via MYPD2 RCA implementation
decision ............................................................................................................................................ 33
5.2.6
Step 6 – Revised allowed regulated revenue for MYPD3 in 2013/14 ............................. 34
5.2.7
Step 7 – Actual standard tariff selling price in 2013/14 .................................................. 35
5.2.8
Step 8 – Revenue RCA variance in 2013/14 ..................................................................... 35
5.3
Actual revenue ........................................................................................................................... 36
5.3.1
Reporting allowed and actual revenue on an equivalent basis ..................................... 36
5.3.2
Adjustments to AFS values to achieve the equivalent revenue for RCA...................... 38
5.4
Calculation of revenue variance for the year ......................................................................... 41
5.5
Sales variance explanation ...................................................................................................... 42
5.5.1
Background ......................................................................................................................... 42
5.5.2
The process in deriving the 5 year forecast .................................................................... 43
5.5.3
Critical assumptions relevant during 2011 in deriving forecasts .................................. 43
5.5.4
Sales volume variance explanation for FY2014 ............................................................... 43
5.6
Load shedding in 2013/14 ......................................................................................................... 50
5.6.1
Estimated Load shedding & Load Curtailment impact for YR 2013/14 ......................... 50
5.7
Other income ............................................................................................................................. 51
5.8
Conclusion of revenue variance .............................................................................................. 51
6
FACTORS WHICH INFLUENCE ESKOM PRODUCTION PLANS .............................................. 52
MYPD3 2013/14 RCA Submission to NERSA
November 2015
Page 4 of 205
7
PRIMARY ENERGY ....................................................................................................................... 53
8
INDEPENDENT POWER PRODUCERS ....................................................................................... 56
8.1
Medium-term Power Purchase Programme (MTPPP) ............................................................ 56
8.2
Municipal Base-load Purchases .............................................................................................. 56
8.3
Short-term Power Purchases Programme (STPPP) .............................................................. 56
8.4
Wholesale Electricity Pricing System (WEPs) programme ................................................... 56
8.5
Long-term IPP programmes ..................................................................................................... 57
8.5.1
IPP open cycle gas turbine (“Peaker”) programme ........................................................ 57
8.5.2
Renewable Energy Independent Power Producer (RE-IPP) procurement programme57
8.6
Legal basis for IPPs per the MYPD Methodology .................................................................. 58
8.7
IPP Approvals ............................................................................................................................ 58
8.8
Regulatory rules for power purchase cost recovery ............................................................. 58
8.9
IPP allowed costs for 2013/14 .................................................................................................. 59
8.9.1
MTPPP allowed costs in MYPD 3 for 2013/14 .................................................................. 59
8.9.2
Short Term IPPs allowed costs in MYPD 3 for 2013/14................................................... 59
8.9.3
Renewable IPPs allowed costs in MYPD 3 for 2013/14 ................................................... 60
8.9.4
DOE Peaking allowed costs in MYPD 3 for 2013/14 ........................................................ 60
8.10
Actual IPP costs for 2013/14 ................................................................................................. 60
8.10.1
Reasons for IPP variances in 2013/14 ........................................................................... 62
8.11
IPP variance for 2013/14 RCA ............................................................................................... 64
8.12
Regional IPPs - Aggreko ....................................................................................................... 64
9
9.1
COAL BURN COST ....................................................................................................................... 67
Extract of MYPD Methodology on Coal adjustments ............................................................ 67
MYPD3 2013/14 RCA Submission to NERSA
November 2015
Page 5 of 205
9.2
Extract of MYPD3 Reasons for Decision on Coal costs ........................................................ 68
9.3
Coal burn RCA variance impact............................................................................................... 69
9.4
Coal burn cost variance explanations .................................................................................... 69
9.4.1
Lower electricity production from coal fired stations ..................................................... 70
9.4.2
Different mix and efficiency of power stations generating electricity .......................... 70
10
10.1
OTHER PRIMARY ENERGY ...................................................................................................... 71
Allowed other primary energy in 2013/14 ............................................................................ 71
10.1.1
Start –up gas and oil allowed for 2013/14 ..................................................................... 71
10.1.2
Nuclear costs allowed for 2013/14 ................................................................................. 72
10.1.3
Coal handling costs allowed for 2013/14 ...................................................................... 72
10.1.4
Water costs allowed for 2013/14 .................................................................................... 72
10.1.5
Fuel procurement costs allowed for 2013/14 ................................................................ 73
10.2
Actual other primary energy in 2013/14 ............................................................................... 73
10.2.1
Reasons for start-up gas and oil costs variance ......................................................... 74
10.2.2
Correlation between start-up gas and oil and UCLF ................................................... 74
10.2.3
Reasons for nuclear costs variance .............................................................................. 75
10.2.4
Reasons for coal handling costs variance ................................................................... 76
10.2.5
Reasons for water costs variance ................................................................................. 77
10.2.6
Reasons for fuel procurement costs variance ............................................................. 78
10.3
Other primary energy variance in 2013/14 RCA .................................................................. 78
11
ROAD MAINTENANCE .............................................................................................................. 79
12
ENVIRONMENTAL LEVY ........................................................................................................... 80
13
NET POSITION OF SOUTHERN AFRICAN ENERGY (SAE) ................................................... 81
14
OPEN CYCLE GAS TURBINES (OCGTS) ................................................................................ 82
14.1
Reasons for OCGTs variance ............................................................................................... 83
MYPD3 2013/14 RCA Submission to NERSA
14.2
November 2015
Page 6 of 205
Avoidance of load shedding ................................................................................................. 83
14.2.1
Power system emergencies and rotational load shedding ......................................... 83
14.2.2
Declared Emergencies during FY 2014 ......................................................................... 84
14.2.3
Rotational load shedding on 6 March 2014 .................................................................. 84
14.2.4
Actual OCGTs usage and load shedding in 2013/14.................................................... 85
14.2.5
Impact on load shedding if OCGTs were restricted to Peak hours ............................ 86
14.3
Cheaper alternatives were maximised and utilised by Eskom ......................................... 87
14.3.1
Supply side options ........................................................................................................ 88
14.3.2
Demand side options ...................................................................................................... 89
14.4
OCGTs allowed in MYPD 3 for 2013/14 ................................................................................ 90
14.5
Actual OCGTs costs in 2013/14 ............................................................................................ 91
14.6
Security of supply by the System Operator performance ................................................. 93
14.6.1
Generating capacity to meet the demand and ensure system security .................... 93
14.6.2
Available generation capacity ........................................................................................ 94
14.6.3
Pumped storage generation ........................................................................................... 95
14.6.4
Hydro generation ............................................................................................................. 96
14.6.5
OCGTs .............................................................................................................................. 96
14.6.6
Demand Response Options............................................................................................ 97
14.6.7
Scheduling and dispatch of generation resources ...................................................... 97
14.7
Technical issues impacting OCGT generation ................................................................... 98
14.7.1
Impact of daily load profile on resultant OCGT load factor ........................................ 98
14.7.2
Speed of response of generators .................................................................................. 99
14.7.3
OCGTs role during demand variations ....................................................................... 100
14.7.4
Factors influence choice of plant to dispatch ............................................................ 100
14.8
Licence conditions for Ankerlig and Gourikwa ................................................................ 101
14.9
Summary of a system operations perspective ................................................................. 101
14.10
Conclusion on OCGT’s ........................................................................................................ 102
14.11
OCGTs variance for 2013/14 RCA ...................................................................................... 102
MYPD3 2013/14 RCA Submission to NERSA
14.12
November 2015
Page 7 of 205
System operator was impacted by delays in new build and Generation plant
performance. ..................................................................................................................................... 102
14.12.1
Delays in new build capacity ........................................................................................ 103
14.12.2
Reasons for delays in new build capacity .................................................................. 104
14.13
Evaluation of delay in Eskom new- build projects that impact sustained usage of
OCGTs 106
14.13.1
Compared to Eskom/SA, regarding these same five factors: ................................... 108
14.13.2
Factors contributing to Generation plant performance ............................................ 110
14.13.3
Lack of philosophy based maintenance ..................................................................... 111
14.13.4
Ageing fleet .................................................................................................................... 111
14.13.5
Actual Plant performance in 2013/14 ........................................................................... 114
14.13.6
Maintenance backlog reduction strategies ................................................................. 118
14.13.7
Benchmarking ................................................................................................................ 125
14.13.8
Energy efficiency improvement programme .............................................................. 128
14.13.9
Managing supply-and-demand constraints ................................................................ 128
15
15.1
CAPITAL EXPENDITURE CLEARING ACCOUNT (CECA) ................................................... 131
Regulated asset base adjustment for CECA ..................................................................... 131
15.1.1
Step 1: Computing change in RAB .............................................................................. 131
15.1.2
Step 2: Computing return impact of change in RAB ................................................. 133
15.2
MYPD3 decision ................................................................................................................... 134
15.3
Capital expenditure reprioritised ........................................................................................ 134
15.3.1
To address the key challenges Eskom allocated funding as follows ...................... 135
15.3.2
Reasons for variance .................................................................................................... 137
15.4
Capex actuals in 2013/14 ..................................................................................................... 137
15.5
Delivering on capital expansion ......................................................................................... 139
15.5.1
Medupi ............................................................................................................................ 139
15.5.2
Kusile .............................................................................................................................. 141
15.5.3
Ingula .............................................................................................................................. 141
15.6
New Build Cost Changes..................................................................................................... 142
MYPD3 2013/14 RCA Submission to NERSA
November 2015
Page 8 of 205
15.6.1
Medupi: Cost overruns ................................................................................................. 142
15.6.2
Kusile : Cost overruns .................................................................................................. 143
15.6.3
Ingula : Cost overruns .................................................................................................. 143
15.7
16
Conclusion on capex ........................................................................................................... 143
INFLATION ADJUSTMENT...................................................................................................... 145
16.1
Operating costs .................................................................................................................... 145
16.2
Regulatory Asset Base ........................................................................................................ 145
16.3
Inflation adjustment on RAB – revenue impact ................................................................ 149
16.3.1
17
17.1
Summary: ....................................................................................................................... 149
INTEGRATED DEMAND MANAGEMENT ............................................................................... 152
Demand-side management: ................................................................................................ 152
17.1.1
The demand-response programme ............................................................................. 152
17.1.2
The residential mass roll-out programme ................................................................... 152
17.2
Energy-efficiency measures ............................................................................................... 153
17.3
Methodology ......................................................................................................................... 153
17.3.1
Allowed EEDSM for 2013/14 ......................................................................................... 154
17.3.2
Actual EEDSM for 2013/14 ............................................................................................ 154
17.3.3
Computation of EEDSM for the RCA ........................................................................... 155
17.4
Demand Market Participation and Power Buy Backs ....................................................... 156
17.4.1
Allowed DMP and Power Buy Backs in 2013/14 ......................................................... 156
17.4.2
Actual DMP and Power Buy Backs in 2013/14............................................................ 157
17.4.3
Power buy-backs ........................................................................................................... 157
17.4.4
Demand market participation (DMP) ........................................................................... 158
17.4.5
DMP and Power buy back variance in 2013/14 ........................................................... 158
17.5
18
Total IDM impact for RCA in 2013/14 ................................................................................. 159
OPERATING COSTS ................................................................................................................ 160
MYPD3 2013/14 RCA Submission to NERSA
18.1
November 2015
Page 9 of 205
Allowed operating costs in 2013/14 ................................................................................... 160
18.1.1
Allowed employee costs in 2013/14 ............................................................................ 160
18.1.2
Allowed maintenance costs in 2013/14 ....................................................................... 161
18.1.3
Allowed arrear debts in 2013/14 ................................................................................... 161
18.1.4
Allowed cost of cover in 2013/14 ................................................................................. 161
18.1.5
Allowed corporate costs in 2013/14 ............................................................................ 161
18.2
Actual operating costs in 2013/14 ...................................................................................... 162
18.3
Reasons for variance in other operating costs ................................................................ 163
18.3.1
Employee benefits ......................................................................................................... 163
18.3.2
Maintenance ................................................................................................................... 164
18.3.3
Arrear debt ..................................................................................................................... 164
18.3.4
Cost of cover .................................................................................................................. 169
18.3.5
Other operating costs ................................................................................................... 170
18.4
Operating cost variance for 2013/14 RCA ......................................................................... 172
18.5
Why symmetrical treatment of operating costs is needed .............................................. 172
19
INTEREST ON RCA BALANCE ............................................................................................... 176
20
SERVICE QUALITY INCENTIVES ........................................................................................... 177
20.1
Transmission service quality incentives (SQI) for 2013/14 ............................................. 177
20.2
Distribution Service Quality Incentive Scheme (SQI) for 2013/14 ................................... 179
21
REASONABILITY TESTS ........................................................................................................ 181
21.1
EBITDA-To-Interest Cover Ratio (EBITDA / Interest Payments) ..................................... 181
21.2
MYPD2 RCA Balance Implementation Plan ....................................................................... 181
21.3
Understanding the ratio....................................................................................................... 182
21.4
Interest cover ratio ............................................................................................................... 184
MYPD3 2013/14 RCA Submission to NERSA
November 2015
Page 10 of 205
21.5
Debt service cover ratio (Interest + Capital) ...................................................................... 184
21.6
Computation of ratios for FY 2014 ..................................................................................... 184
21.7
EBIT Interest cover ratio...................................................................................................... 186
21.8
EBITDA: Total debt service ratio ........................................................................................ 186
22
CONCLUSION .......................................................................................................................... 187
ANNEXURES: .................................................................................................................................... 189
Annexure 1: Income Statement in AFS 2014 .................................................................................. 189
Annexure 2: Revenue note 32 from AFS (p81) ............................................................................... 190
Annexure 3: Revenue from divisional report 2014 (P47) .............................................................. 190
Annexure 4: Key financial statistics FY 2014 ................................................................................. 191
Annexure 5: The Eskom energy wheel (Integrated report P22) ................................................... 191
Annexure 6: Sales volumes GWh (Divisional report page 88) ..................................................... 192
Annexure 7: Primary Energy Note (AFS FY 2014 page 91) ........................................................... 193
Annexure 8: Actual Energy Procured through IPP Programmes in 2013/2014 (Integrated Report
FY2014 page 145) .............................................................................................................................. 193
Annexure 9: EEDSM Annual report for 2013/14 ............................................................................. 194
Annexure 10: Supplementary report 2014, page 48 ...................................................................... 196
Annexure 11: Annual Financial Statement 2014 ............................................................................ 196
Annexure 12: Annual Financial Statement 2014 ............................................................................ 197
Annexure 13: Finance cost extract (AFS FY 2014 page 93) .......................................................... 197
23
ABBREVIATIONS ..................................................................................................................... 198
MYPD3 2013/14 RCA Submission to NERSA
24
November 2015
Page 11 of 205
GLOSSARY AND TERMS ........................................................................................................ 202
Figure 1: Time lag between application and actuals ....................................................................... 24
Figure 2: Accounting policy - Deferred income in AFS for March 2014 ........................................ 40
Figure 3: Accounting Policy - Payments received in advance in AFS for March 2014 ................ 40
Figure 4: GDP Vs Sales growth ......................................................................................................... 42
Figure 5: Production FY 2014 ............................................................................................................ 52
Figure 7: Correlation between fuel oil costs (Rand m) and UCLF ................................................. 74
Figure 8: Load shedding impact in 2013/14 ..................................................................................... 86
Figure 9: Load shedding with OCGTs limited to peak hours ......................................................... 87
Figure 10: Trend in DSM savings ...................................................................................................... 90
Figure 11: OCGTs production in 2013/14 ......................................................................................... 91
Figure 12: Typical profile of generating hours at Drakensberg and Palmiet in a week ............... 96
Figure 13: Coal Power station ages ................................................................................................ 113
Figure 14: Turbine design vs operating hours............................................................................... 113
Figure 15: Planned maintenance performance .............................................................................. 117
Figure 16: Unplanned capability loss factor (UCLF) – Annual Results March 2014 .................. 118
Figure 17: Monthly UCLF for last 3 years ....................................................................................... 119
Figure 18: Monthly Energy Utilisation Factor in 2013/14 .............................................................. 121
Figure 19: EUF increased by approx. 38% from 2002 ................................................................... 122
Figure 20: Energy Availability Factor (EAF) ................................................................................... 123
Figure 21: Benchmarking EAF % all coal sizes 2000-2012 .......................................................... 126
Figure 22: Benchmarking UCLF % all coal sizes 2000-2012......................................................... 126
Figure 23: Benchmarking PCLF % all coal sizes 2000-2012 ......................................................... 127
Figure 24: Benchmarking EUF % all coal sizes 2000-2012 ........................................................... 127
Figure 25: Summer and Winter Load Profiles ............................................................................... 130
Figure 26: NERSA determination vs. Eskom Allocation ............................................................... 135
Figure 27: Projected BPP savings ................................................................................................... 171
Figure 28: Time lapse between application and MYPD2 decision ............................................... 172
Figure 29: Transmission system minutes (<1) ............................................................................... 178
Figure 30: EBITDA-To-Interest Cover Ratio ................................................................................... 181
Table 1: Summary of 2013/14 RCA Submission .............................................................................. 19
Table 2: Key assumptions which have changed ............................................................................. 24
Table 3: Revenue allowed in MYPD3 decision ................................................................................. 29
MYPD3 2013/14 RCA Submission to NERSA
November 2015
Page 12 of 205
Table 4: Sales volumes in MYPD3 decision ..................................................................................... 29
Table 5: Revenue building blocks in MYPD3 decision .................................................................... 30
Table 6: Primary energy costs assumed in MYPD3 decision ......................................................... 31
Table 7: Derived allowed NPA revenue in MYPD3 decision ........................................................... 32
Table 8: Revised standard tariff revenue in MYPD3 decision ........................................................ 33
Table 9: MYPD2 RCA implementation decision ............................................................................... 33
Table 10: Standard tariff volumes revised for MYPD3 .................................................................... 34
Table 11: Revised allowed revenue for MYPD3 ............................................................................... 34
Table 12: Allowed revenues, standard average prices and percentage price increases (revised)
.............................................................................................................................................................. 34
Table 13: Actual standard tariff results in 2013/14 .......................................................................... 35
Table 14: Adjusting AFS Revenue to MYPD RCA equivalent for FY2014 ..................................... 38
Table 15: Revenue note from AFS for March 2014 .......................................................................... 38
Table 16: International revenue for RCA adjustment ...................................................................... 39
Table 17: AFS- Revenue ..................................................................................................................... 39
Table 18: MYPD3 Sales volume ......................................................................................................... 43
Table 19: GDP forecast assumptions during year 2011 .................................................................. 43
Table 20: Change in assumptions relating to 2013/14 .................................................................... 44
Table 21: Sales volume variances for RCA ...................................................................................... 46
Table 22: MYPD3 FY 2014 sales volume comparison ..................................................................... 46
Table 23: Recon of Total Sales from MYPD 3 Application to Actuals Sales ................................. 47
Table 24: Estimated Load Shedding & Load Curtailment impact for 2013/14 .............................. 50
Table 25: Recon of primary energy from AFS to RCA (Extract: AFS FY 2014) ............................. 53
Table 26: Primary energy actual costs per note 33 in the AFS of 2014 ......................................... 54
Table 27: Primary energy variances for 2013/14 RCA .................................................................... 54
Table 28: IPPs costs and volumes ................................................................................................... 61
Table 29: Actual energy procured through IPP programme in 2013/14 ........................................ 62
Table 30: The net cost to be included in the RCA ........................................................................... 69
Table 31: MYPD 3 Assumptions vs. Actual FY14 ............................................................................ 69
Table 32: Start-up gas and oil - MYPD3 Decision ............................................................................ 71
Table 33: Nuclear Costs - MYPD3 Decision...................................................................................... 72
Table 34: Coal handling – MYPD3 Decision ..................................................................................... 72
Table 35: Approved Water Costs for MYPD3 .................................................................................. 72
Table 36: NERSA allowed R258m for fuel procurement for 2013/14. ............................................ 73
Table 37: Other Primary Energy ........................................................................................................ 73
MYPD3 2013/14 RCA Submission to NERSA
November 2015
Page 13 of 205
Table 38: Summary of net SAE position ........................................................................................... 81
Table 39: Load shedding intensity - OCGTs limited to peak .......................................................... 87
Table 40: OCGTs decision from MYPD3 ........................................................................................... 91
Table 41: Summary of OCGTs results .............................................................................................. 92
Table 42: Eskom Generation expansion plan – MYPD 3 Application .......................................... 104
Table 43: Technical performance for the year to 31 March 2014 ................................................. 114
Table 44: Average Eskom coal power station heat rate for period 2011/12 to 2013/14 ............. 116
1
Table 45: Breakdown of system UCLF (%) .................................................................................... 119
Table 46: Typical maintenance schedule for a coal-fired power station ..................................... 124
Table 47: Calculation average capex .............................................................................................. 132
Table 48: CECA Calculation- Return due to/by Eskom ................................................................. 133
Table 49: Regulatory asset base for 2013/14 ................................................................................. 134
Table 50: Returns and percentage allowed in 2013/14 .................................................................. 134
Table 51: Capital expenditure in 2013/14 ........................................................................................ 134
Table 52: Approved capex portfolio mix ......................................................................................... 136
Table 53: Reconciliation between Capex shown in the integrated report and CECA calculation
............................................................................................................................................................ 138
Table 54: Capital Expenditure (excluding capitalised borrowing costs) per division ............... 138
Table 55: Inflation adjustment ......................................................................................................... 145
Table 56 : Summary of RAB inflation adjustments ....................................................................... 150
Table 57: Return on assets .............................................................................................................. 150
Table 58: Regulatory asset base ..................................................................................................... 151
Table 59: EEDSM – MYPD3 Decision .............................................................................................. 154
Table 60: Recon between demand savings MWs used in RCA Calculation ............................... 155
Table 61: EEDSM in 2013/14 ............................................................................................................ 155
Table 62: Actual DMP and Power Buy Backs in 2013/14 .............................................................. 157
Table 63: Actual Costs and Performance of PBB .......................................................................... 158
Table 64: The allowed employee costs for Generation, Transmission and Distribution .......... 160
Table 65: Allowed Maintenance Costs ............................................................................................ 161
Table 66: Allowed Arrear Debts ....................................................................................................... 161
Table 67: Allowed Cost of Cover ..................................................................................................... 161
Table 68: Allowed Corporate Costs ................................................................................................ 161
Table 69: Summary of Operating costs in 2013/14 ........................................................................ 162
Table 70: Trend in actual employee benefits ................................................................................. 163
Table 71: Summary of SQI performance in 2013/14 ..................................................................... 177
MYPD3 2013/14 RCA Submission to NERSA
November 2015
Page 14 of 205
Table 72: Transmission SQI performance in 2013/14 .................................................................................... 177
Table 73: Transmission number of major incidents (>1SM).......................................................................... 178
Table 74: Line faults / 100km............................................................................................................................ 179
Table 75: Distribution SQI performance in 2013/14 ........................................................................................ 180
Table 76: Financial information for ratios in FY 2014 .................................................................................... 185
Table 77: EBIT Interest Cover .......................................................................................................................... 186
Table 78: EBITDA- Total debt serviced ........................................................................................................... 186
MYPD3 2013/14 RCA Submission to NERSA
1
November 2015
Page 15 of 205
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
2015.
2.
1.1
Information is supported by Eskom’s 2013/14 audited annual financial statements
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:
14.1.1 The nominal estimates of the regulated entity will be managed by adjusting for
changes in the inflation rate.
14.1.2 Allowing the pass-through of prudently incurred primary energy costs as per Section 8
of the Methodology.
14.1.3 Adjusting capital expenditure forecasts for cost and timing variances as per Section 6
of the Methodology.
1
st
See in particular sections 14.0, 8.0 and 9.0 of the Multi-Year Price Determination Methodology 1 Edition.
MYPD3 2013/14 RCA Submission to NERSA
November 2015
Page 16 of 205
14.1.4 Adjusting for prudently incurred under-expenditure on controllable operating costs as
may be determined by the Energy Regulator.
14.1.5 Adjusting for other costs and revenue variances where the variance of total actual
revenue differs from the total allowed revenue. In addition, a last resort mechanism is put in
place to trigger a re-opener of the price determination when there are significant variances in
the assumptions made in the price determination.”
The RCA is part of the overall MYPD Methodology 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.
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 3.1 - 3.12)
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.
MYPD3 2013/14 RCA Submission to NERSA
2
November 2015
Page 18 of 205
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 2012. 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.
MYPD3 2013/14 RCA Submission to NERSA
3
November 2015
Page 19 of 205
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
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
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.
MYPD3 2013/14 RCA Submission to NERSA
3.6
November 2015
Page 22 of 205
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 14.1.1 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.
MYPD3 2013/14 RCA Submission to NERSA
3.10
November 2015
Page 23 of 205
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.
3.11
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.
3.12
Conclusion
The RCA balance submission of R22 789 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.
MYPD3 2013/14 RCA Submission to NERSA
4
Factors impacting on 2013/14 RCA Submission
4.1
Timeline for application and decision
November 2015
Page 24 of 205
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
Eskom MYPD3 Application
Preparation (January 2012)
Eskom
Submitted
(November
2012)
13
Months
15
Months
27
Months
39
Months
51
Months
63
Months
75
Months
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
Sales forecast average growth
Sales forecast did not materialize
growth 2% p.a. with
0.9% p.a. with actual starting
as anticipated and forecasts could
starting value 217TWh
value 208TWh in March 2013 (-
have been on the optimistic side.
in March 2013
9TWh less in base)
Adverse economic situation exists
globally with markets not recovering
as expected.
MYPD3 2013/14 RCA Submission to NERSA
November 2015
Page 25 of 205
MYPD3 Application
Current Situation
Comment
Generation plant
Actual average EAF is
Board decision made in June 2013
performance (Energy
approximately 75%
(post the MYPD3 decision of
availability factor – EAF)
February 2013) to migrate from
assumed of between
present low levels towards the
82%~83% over MYPD3
80:10:10 levels by 2019 (80%
period
availability, 10% planned and 10%
unplanned capability loss).
New build commission
st
New build commission revised
st
Due to increased labour unrests,
dates for 1 units:
dates for 1 units:
contractor failures, and lack of
Medupi – June 2013
Medupi – August 2015
proper project management
Kusile - 2014/15
Kusile – July 2018
capability, the new build projects
Ingula – 2013/14
Ingula – Jan 2016
have been delayed.
Sere – 2013/14
Sere – CO 31 March 2015
Coal country compact of
Efficiency savings implemented
Savings will likely be less than the
annual coal price
through business productivity
MYPD3 assumption of 10% savings
increases of less than
programme.
10%
OCGTs – load factors
OCGTs – actual load factors
OCGTs were utilized as a last
assumed at 3% based
greater than 3% due to combined
measure to avoid load shedding
on other combined
assumptions made at the time of
and resulted in higher usage of
assumptions
the application not materialising
these supply options.
Capex – R337bn over
Capex – given the lower revenue
In response to MYPD3 revenue
the five year period
decision, Eskom reprioritized
decision Eskom has reprioritised its
capex to a projected portfolio of
capex spend which resulted in
R251bn over the five year period.
capex reallocations between
materialising
licensees.
Staff costs –
Revised staff outlook to cap
BPP savings initiative launched in
complement of 43 000
numbers at 42 000 and
the business
growing to 46 000
decreasing to 40 000 by 2018
MYPD3 2013/14 RCA Submission to NERSA
November 2015
Page 26 of 205
MYPD3 Application
Current Situation
Comment
Maintenance
More maintenance was
Addressing the reduced plant
undertaken than was initially
performance and maintenance
envisaged
backlog
Implemented BPP saving plan
Despite cost efficiency and saving
Other Opex
programme other operating cost
exceeded decision
MYPD3 2013/14 RCA Submission to NERSA
5
November 2015
Page 27 of 205
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 14.1.5 of the MYPD
Methodology as shown below.
14.1.5 “Adjusting for other costs (5) and revenue variances where the variance of total
actual revenue differs from the total allowed revenue….”
Footnote 5 as above: Includes but not limited to taxes and levies (as defined), sales volumes and
customer number variances.
The practical application of para 14.1.5 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 14.2.7 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
MYPD3 2013/14 RCA Submission to NERSA
5.1
November 2015
Page 28 of 205
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 12 521GWh 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.
5.2.1
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.
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 217890
GWh and so forth with 234519 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 206 587 GWh for 2013/14. The difference between the allowed revenue table
above and sales table is 11 303 GWh (217 890 GWh – 206 587 GWh) which is exactly the
volume linked to negotiated price agreements (local NPA).
Table 4: Sales volumes in MYPD3 decision
MYPD3 2013/14 RCA Submission to NERSA
5.2.2
November 2015
Page 30 of 205
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 53 753m. 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.
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.
5.2.2.1 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.
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).
5.2.3
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 R149 937m in 2013/14 and deducting the standard tariff revenue of R142 746m
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
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)
2013/14
142 746
149 937
7191
11303
63.6
2014/15
155 477
163 584
8107
11303
71.7
2015/16
171 838
180 332
8494
11333
74.9
2016/17
189 396
196 378
6982
11302
61.8
2017/18
209 025
216 322
7297
11302
64.6
MYPD 3
868 482
906 553
38 071
56543
5.2.4 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.
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)
2013/14
2014/15
2015/16
2016/17
2017/18
MYPD 3
Revenue from standard tariff customers
142 746
155 477
171 838
189 396
209 025
868 482
Revenue from standard tariff customers
135 226
147 481
163 179
180 070
198 954
824 910
Reduction in revenue affected only standard tariff customers- 7 520
- 7 996
- 8 659
- 9 326
- 10 071
- 43 572
5.2.5 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
MYPD3 2013/14 RCA Submission to NERSA
November 2015
Page 34 of 205
slight change under 2013/14 which now reflects 206411 GWh instead of original 206
587GWh.
Table 10: Standard tariff volumes revised for MYPD3
Impact on standard tariff volumes - (MYPD2 RCA
Implementation decision)
Revenue (R'm)
Standard tariff sales volumes (GWh)
Standard average price (c/kWh)
2013/14
2014/15
2015/16
2016/17
2017/18
MYPD 3
135 226
206 412
65.51
147 481
208 442
70.75
163 179
213 545
76.41
180 070
218 194
82.53
198 954
223 219
89.13
824 910
1 069 812
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.
5.2.6
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
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 3
2013/14
135 226
7 191
684
143 101
2014/15
147 481
8 107
469
156 057
2015/16
163 179
8 494
96
171 769
2016/17
180 070
6 982
-258
186 794
2017/18
198 954
7 297
-1 037
205 214
MYPD 3
824 910
38 071
-46
862 935
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)
2012/13
Forecasts sales to tariff customers (GWh)**
Revenue Standard Customers
Total Revenue from all customers
Average Tariff (c/kWh)
60.66
Increase in standard Tariffs
** base on page 7 of 102 (Part 2 MYPD3 Tariff submission)
2013/14
206 412
135 226
143 101
65.51
8%
2014/15
208 442
147 481
156 057
70.75
8%
2015/16
213 545
163 179
171 769
76.41
8%
Source: Reproduced from NERSA communication Table 1 (dated 8 March 2013)
2016/17
218 194
180 070
186 794
82.53
8%
2017/18 MYPD 3
223 219 1 069 812
198 954
824 910
205 214
862 935
89.13
8%
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 143 101m
5.2.7
Step 7 – Actual standard tariff selling price in 2013/14
During 2013/14 Eskom revenue from standard tariff customer was R127 963m from a
volume of 194 066GWh 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
Actual revenue from standard tariff (R'm)
Standard tariff sales volumes (GWh)
Actual average rate applied (c/kWh)
Allowed standard tariff (c/kWh)
5.2.8
2013/14
127 963
194 066
65.94
65.51
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 11 901GWh 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
11 901GWh 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.
MYPD3 2013/14 RCA Submission to NERSA
5.3
5.3.1
November 2015
Page 36 of 205
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 methodology2, 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)
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
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.
5.3.2
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)
Revenue
Less: Revenue excluded from RCA
International
Other revenue
External local revenue
FY2014
138 313 Refer step 1
7 375
5 931 Refer step 2
1 444 Refer step 3
130 938
Add: internal electricity revenue
Equivalent Revenue reconciled to AFS
416 refer step 4
131 354
Add: Revenue loss due to load shedding
Equivalent Revenue for RCA
24
131 378
5.3.2.1 Step 1: Revenue as reported in Eskom’s 2014 AFS
Revenue from continuing operations of R138 313m 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.
MYPD3 2013/14 RCA Submission to NERSA
November 2015
Page 39 of 205
5.3.2.2 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
5.3.2.3
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
MYPD3 2013/14 RCA Submission to NERSA
5.3.2.3.1
November 2015
Page 40 of 205
Treatment of non-electricity revenue excluded from revenue
In contrast to the AFS treatment as stated in the accounting policy note shown below, para
6.1.5 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 6.1.5 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.
5.3.2.3.2
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
MYPD3 2013/14 RCA Submission to NERSA
5.3.2.4
November 2015
Page 41 of 205
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 131 378m
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 R131 378m and allowed revenue
of R143 101m, 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
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
5.5.1
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
MYPD3 2013/14 RCA Submission to NERSA
November 2015
Page 43 of 205
Table 18: MYPD3 Sales volume
Total Eskom Sales (GWh)
2012/13
2013/14
MYPD3 Sales Decision
% Growth
222 756
-1.1%
227 796
2.21%
Actual Sales
217 022
218 368
% Growtrh
-3.63%
2014/15
2015/16
229 645
0.81%
234 810
2.20%
2016/17
2017/18
239 405
1.92%
244 318
2.01%
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%.
5.5.2
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.
5.5.3
Critical assumptions relevant during 2011 in deriving forecasts
Table 19: GDP forecast assumptions during year 2011
2 0 10
MYPD GDP Growth %

3.1
2 0 11
3.7
2 0 12
2 0 13
4.0
4.0
2 0 14
4.0
2 0 15
4.5
2 0 16
5.0
2 0 17
5.0
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.
5.5.4
Sales volume variance explanation for FY2014
Eskom has adjusted the sales volume variance by the load shedding impact.
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 3 680 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 62.88 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 5 220
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
MYPD3 2013/14 RCA Submission to NERSA
November 2015
Page 45 of 205
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 4 283 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.
Large Co-gen projects that are in an advanced
Co-generation projects for Sasol SSF were taken
stage in the commissioning process have been
into account and it was mostly on target. Sasol
included in the budget.
infra Chem also started up a very successful gas
co-generation plant which displaced 466 GWh and
this was not included in the forecast.
High probability new projects are included.
The Mining category realized a drop in
Commodity price assumptions were made
consumption as compared to the forecast of 3 637
while expecting some growth.
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 2 159 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 1 353 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.
MYPD3 2013/14 RCA Submission to NERSA
November 2015
Page 46 of 205
Table 21: Sales volume variances for RCA
Sales volumes (GWh)
Actual volume variance
Less Load shedding impact
Adjusted volume variance after load shedding
2013/14
-11 901
54
-11 847
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 11.901
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:
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
MYPD3 Application Sales (GWh)
MYPD 3 YoY Forecasted sales growth (%)
2013/14
227 776
2.3%
Redistributors
Ethekwini Electricity
City of Tshwane Metro
City of Cape Town
City Power of Johannesburg
Rustenburg Local Municipality
Ekurhuleni Metro
Nelson Mandela Metro
Emfuleni Local Municipality
Other
(3 680)
(130)
(391)
(627)
(472)
(486)
(103)
(308)
(75)
(1 087)
Industrial
Iron & Steel Sector
Ferro Chrome Sector
Ferro Manganese Sector
Ferro Silicon Sector
Paper & Pulp
Steam & Hot water Supply
Manufacturing of basic Chemicals
Aluminium
Other
(5 156)
(1 081)
(2 146)
(645)
(411)
(464)
(308)
(216)
52
63
Mining
Platinum
Gold
Other
(3 555)
(2 159)
(1 353)
(43)
International
Other
2 492
490
Total Actual/Projection sales (GWh)
Actual YoY sales growth (%)
218 368
0.6%
5.5.4.1 Redistributors: 3 680 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.
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.
5.5.4.2 Industrial: 5 156 GWh unfavourable
This category was most affected and is mainly due to:

Power Buy Back’s that were implemented - 1 355 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 4 282 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.
5.5.4.3 Mining: 3 555 GWh unfavourable
This category was also severely affected and it is mainly due to the Gold and Platinum
sectors:

The Platinum sector realized a 2 159 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.
MYPD3 2013/14 RCA Submission to NERSA

November 2015
Page 49 of 205
The gold sector realized a 1 353 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.
5.5.4.4 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.
5.5.4.5 International: 2 492 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
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.
5.6.1
Estimated Load shedding & Load Curtailment impact for YR 2013/14
Table 24: Estimated Load Shedding & Load Curtailment impact for 2013/14
GWh
Apr-13
May-13
Jun-13
Jul-13
Aug-13
Sep-13
Oct-13
Nov-13
Dec-13
Jan-14
Feb-14
Mar-14
Total
Revenue (Rm)
-
3
3
48
54
energy C/KWh
1
41.3
1
39.2
21
44.3
24
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.
estimated
This
gives
maximum
consumption
impact
an
energy
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
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 14.1.5.
MYPD3 2013/14 RCA Submission to NERSA
6
November 2015
Page 52 of 205
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 2014
Production FY 2014
Sales (TWh)
MYPD3 227
Actuals 218
Production Volumes (GWh)
270 000
260 000
250 000
OCGTs
240 000
New build
230 000
IPPs
220 000
Imports
210 000
Other
200 000
Coal
190 000
180 000
MYPD3
Actuals
MYPD3 2013/14 RCA Submission to NERSA
7
November 2015
Page 53 of 205
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
Own generation costs
Environmental levy
International electricity purchases
Independent power producers
Other
Total Primary energy per AFS
FY2014
54 186
8 530
3 311
3 266
519
69 812
Adjustments for RCA :
Exclude : International electricity purchases
Include : Aggrekko IPP
-2 175
-3 311
1 136
Total Primary energy for RCA (R'millions)
67 637
Primary energy costs of R69 812m incurred in 2013/14 is seen in the extract from the AFS of
March 2014 as outlined below.
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)
Coal burn
Coal volume
Coal price
Independent Power Producers (IPPs)
Regional IPP
Open cycle gas turbines (OCGTs)
Other primary energy
Environmental levy
Road repairs
Primary Energy
R millions
2 000
-1 378
3 378
580
1 136
8 024
2 491
-312
169
14 087
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.
MYPD3 2013/14 RCA Submission to NERSA
8
November 2015
Page 56 of 205
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
MYPD3 2013/14 RCA Submission to NERSA
November 2015
Page 57 of 205
2013/14 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.
8.5.1
IPP open cycle gas turbine (“Peaker”) programme
Power purchase agreements (PPAs) of 1 005MW for the Avon and Dedisa plants were
entered into during June 2013 and became effective on 29 August 2013. Commissioning of
Dedisa is expected in the second half of 2015, while Avon is expected during the first half of
2016. These did not produce energy during 2013/14 as anticipated.
8.5.2
Renewable Energy Independent Power Producer (RE-IPP) procurement
programme
The DoE launched the RE-IPP Programme during 2011, which called for 3 725MW of
renewable energy technologies in commercial operation between mid-2014 and the end of
2016. Developers were invited to submit proposals for the financing, construction, operation,
and maintenance of any onshore wind, solar thermal, solar photovoltaic, biomass, biogas,
landfill gas, or small hydro technologies.
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.
MYPD3 2013/14 RCA Submission to NERSA
8.6
November 2015
Page 58 of 205
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.
9.10 The variances (i.e. difference between MYPD allowed costs and actual incurred costs) together with
reasons shall be presented to the Energy Regulator. After the review, the variance will be debited/credited to
the RCA.
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.
17.2
For the avoidance of doubt, the review process set out in rule 16 is limited to reconciling cost
variances and draw-down of the power purchase account balance, and is not a retrospective review
of the general authorisation or the basis on which cost effectiveness was established.
MYPD3 2013/14 RCA Submission to NERSA
8.9
November 2015
Page 59 of 205
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 2013/14.
8.9.1
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).
8.9.2
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.
MYPD3 2013/14 RCA Submission to NERSA
8.9.3
November 2015
Page 60 of 205
Renewable IPPs allowed costs in MYPD 3 for 2013/14
6.3.2 Renewable Energy IPPs
Table 31: Approved Renewable Energy Costs for MYPD3
2012/13
Approved
Expenditure
R'm
Renewable Applied For
Renewable Adjustments
Approved Renewable
-
2013/14 2014/15 2015/16 2016/17 2017/18
1 428
8 987
13 879
16 249
17 353
(1 428)
(4 747)
(636)
137
2 336
4 240
13 243
16 386
19 689
MYPD3
Total
57 896
4 338
53 558
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.
8.9.4
DOE Peaking allowed costs in MYPD 3 for 2013/14
Table 32: Approved DoE Costs Peaking for MYPD3
R'm
DoE Peaking Applied For
DoE Peaking Adjustments
Approved DoE Peaking
2012/13
Approved
Expenditure
-
2013/14 2014/15 2015/16 2016/17 2017/18
1 001
2 841
3 147
3 160
3 191
(1 001)
(2 841)
(1 952)
(374)
313
1 195
2 786
3 504
MYPD3
Total
13 340
(5 855)
7 485
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.
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
Non-renewable programs
Costs (R'million)
Volumes GWh
Average R/MWh
Actuals Decision Variance
Actuals Decision Variance
Actuals
Decision
NOTE
REF #
2 877
2 545
332
3 421
3 266
155
841
779
MTPPP
1 218
1 523
-305
1 478
2 083
-605
824
731
A
STPPP (including Munics)
1 588
1 022
566
1 804
1 183
621
880
864
B
72
-
72
139
-
139
520
0
C
389
-
389
250
-
250
1557
0
389
-
389
250
-
250
1557
0
-
-
-
-
-
-
3 266
2 545
721
141
-141
2 686
580
WEPS
Renewable IPP's
Renewable IPP's - energy
Renewable IPP's - deemed
energy payment
DOE Peaker
Total IPP energy costs
IPP ancilliary costs
Total IPP costs
3 266
D
D
-
-
3 671
3 266
405
890
822
E
3 671
3 266
405
The costs of R3266 m incurred in 2013/14 is highlighted in the extract form Eskom‘s
Integrated Report 2014 below:
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
8.10.1 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.
MYPD3 2013/14 RCA Submission to NERSA
B.
November 2015
Page 63 of 205
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).
MYPD3 2013/14 RCA Submission to NERSA
November 2015
Page 64 of 205
There were no deemed energy payments to IPPs during 2013/14.
8.11 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 2014. 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.
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).
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
MYPD3 2013/14 RCA Submission to NERSA
9
Coal Burn Cost
9.1
Extract of MYPD Methodology on Coal adjustments
November 2015
Page 67 of 205
“Criteria for Allowing Primary Energy Costs
8.1
All rules applicable to operating expenditure shall apply to the primary energy costs.
8.2
In considering the allowable primary energy costs, the Energy Regulator will consider
the most appropriate generation mix that can be achieved practically to the best
interest of both the customer and the supplier.
8.3 Coal Costs
8.3.1 Coal will be treated as a single cost centre without differentiating between the various
coal sources (for example cost plus contracts, fixed price contracts, short-term
contracts and long-term contracts).
8.3.2 The Energy Regulator will determine and approve the coal benchmark cost (i.e. an
average cost of coal R/ton), and Alpha for each year will be determined as part of the
MYPD3 final decision.
8.3.3 The coal benchmark price is determined by the Energy Regulator in order to be used
in comparison with the actual coal cost for the purpose of determining pass-through
costs.
8.3.4 The coal benchmark price will be compared to Eskom’s actual cost of coal burn
(R/ton) using a Performance Based Regulation (PBR) formula. The PBR formula is
the maximum amount to be allowed for pass-through, calculated by applying the
following formula
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
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.
8.3.5 The pass-through component of the coal burn cost is equal to the coal burn volume
variance plus Alpha times the coal burn cost variance:
Pass through coal burn cost = PBR cost (Rand) minus Allowed Coal burn cost (Rand)
= Coal burn Volume variance + Alpha
Where: Actual Cost = Actual unit cost of coal burn in a particular financial year Benchmark
Price = Allowed coal burn cost/coal burn volume (R/ton) Actual Coal Burn Volume = Actual
ton of coal burn in a particular financial year Alpha = Alpha is the factor that determines the
ratio in which risks in coal burn expenditure is divided: i.e. those that are passed through to
the customers, and those that must be carried by Eskom. Any number of the alpha between
0 and 1, set to share the risk of the coal cost variance between licensees and its customers.
8.3.6 The coal benchmark price will be used to determine the resulting allowed actual coal
burn cost (R/ton) and transferred to the RCA. The amount transferred to the RCA will
therefore be calculated as the difference between the PBR amount and the amount
forecast/allowed in the MYPD decision.
8.3.7 The coal stock level (stock days) will be reviewed by the Energy Regulator when
necessary”.
9.2
Extract of MYPD3 Reasons for Decision on Coal costs
“Table 18: Approved Coal Burn Costs for MYPD3
MYPD3 2013/14 RCA Submission to NERSA
November 2015
Page 69 of 205
54. 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 MYPD3.”
9.3
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
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)
9.4
FY2014
3 378
-1 378
2 000
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
Actual FY14
Cost Plus and Fixed Price mines produce at
expected levels, except for Arnot
New long term mines are producing
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
Prices from future medium term contracts
have been based on existing contractual
MYPD3 2013/14 RCA Submission to NERSA
November 2015
Page 70 of 205
MYPD3 FY14 Assumptions
Actual FY14
delivered cost.
Coal qualities have been adjusted to reflect
the impact of the washing plants.
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.
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).
9.4.1
Lower electricity production from coal fired stations
Total coal burnt was 4 860kt less than planned. The coal fired power stations generated
11 035MWh less than have planned. This resulted in the positive volume variance.
9.4.2
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.
MYPD3 2013/14 RCA Submission to NERSA
10
November 2015
Page 71 of 205
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
8.5.1 Other primary energy costs such as nuclear, hydro, and sorbent, will be allowed as
pass-through costs.
8.5.2 Primary energy costs at the coal-fired power stations, for example water treatment,
start-up fuel and coal handling costs will be allowed as a pass-through and will be
reviewed by the Energy Regulator based on the percentage cost increase (inflation
forecast).
10.1
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.
10.1.1 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
MYPD3 2013/14 RCA Submission to NERSA
November 2015
Page 72 of 205
10.1.2 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
10.1.3 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
10.1.4 Water costs allowed for 2013/14
Table 35: Approved Water Costs for MYPD3
MYPD3 2013/14 RCA Submission to NERSA
November 2015
Page 73 of 205
10.1.5 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
Water
Startup Gas & Oil
Coal Handling
Water treament
Nuclear
Fuel procurement
Sorbent
Other Primary energy (R'millions)
MYPD3
Decision
2013/14
1 746
1 511
1 056
250
387
258
5 208
Actuals
2013/14
1 451
3 060
1 433
305
1 271
179
7 699
Actual other primary costs incurred in 2013/14 was R7699 m
RCA
-295
1 549
377
55
884
-79
2 491
MYPD3 2013/14 RCA Submission to NERSA
November 2015
Page 74 of 205
10.2.1 Reasons for start-up gas and oil costs variance
Heavy fuel oil starts and shuts down a coal fired power station and stabilizes the boiler flame
on occasion e.g. when operating at low load. The number of starts are driven by the number
of outages (planned and unplanned) and the number of trips (UAGS) at the units of a station.
The number of unplanned outages and trips were significantly higher in 2013/14 than what
was anticipated at the time of the MYPD3 application and hence the use of fuel oil increased
significantly as well.
10.2.2 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.
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
10.2.3 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.
10.2.3.1

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
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 2010.

The other costs (encapsulation, repository, transportation etc.) reflect normal cost
escalation in line with the inflation rate.
10.2.4 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.
10.2.4.1
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.
10.2.4.2
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.
10.2.4.3
Grootvlei
The strategic stock pile had to be re-built; additional yellow plant was hired in December
2013. Furthermore, 2x rollers were added in January 2014. 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.
MYPD3 2013/14 RCA Submission to NERSA
10.2.4.4
November 2015
Page 77 of 205
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.
10.2.5 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.
10.2.5.1
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.
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 Mm3 less than assumed.
10.2.6 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.
10.3
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
MYPD3 2013/14 RCA Submission to NERSA
11
November 2015
Page 79 of 205
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
MYPD3 2013/14 RCA Submission to NERSA
12
November 2015
Page 80 of 205
Environmental levy
The MYPD methodology allows for (under)/over recovery to be adjusted through the RCA
mechanism as presented in the extract below:
13. Taxes and Levies (not income taxes)
13.1 The Government imposes certain taxes and levies that are payable by Eskom.
13.2 Levies are any charges that the Government may impose and payable by Eskom
arising from its licensed activity.
13.3 Taxes are any amount arising from an enacted legislation that the Government
may require Eskom to pay which amount will be calculated in terms of such
legislation.
13.4 Principles regarding taxes and levies
13.4.1 The taxes and levies are exogenous and will be treated as a pass-through cost
in the MYPD.
13.4.2 Taxes and levies will be treated as a separate account in the Eskom revenue
determination.
13.4.3 Eskom must ensure that the cost of the taxes and levies is specified and that
the calculation thereof is clear and concise.
13.4.4 The amount provided for the taxes and levies must be ring-fenced and any
over or 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
MYPD3 2013/14 RCA Submission to NERSA
13
November 2015
Page 81 of 205
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
Import (GWh)
Export (GWh)
Net Import/(Export) GWh
Net Import/(Export) Costs R'm
Decision
11 450
9 513
1 937
611
Actuals
8 157
11 531
-3 374
-1 372
Note the above volumes on exports and imports exclude en route volumes.
Variance
-3 293
2 018
-5 311
-1 982
MYPD3 2013/14 RCA Submission to NERSA
14
November 2015
Page 82 of 205
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 8.4.1 “costs will be allowed as a full pass-
through cost, but limited conditional to volumes allowed by the Energy Regulator,
except where such use is necessary to ensure security of supply…” .
`This situation is further reinforced in para 8.4.2 “Capacity constraints shall be mitigated
by gas turbine generation as a last resort. For avoidance of doubt, gas turbine
generation should be employed before implementation of load shedding activities”.
The MYPD methodology does state that the OCGTs usage is a last resort after cheaper
alternatives have been investigated and utilised.
Para 8.4.3 “ … any variances in the operation of the gas turbine, the reasonableness of such
expenses will be subject to review by the Energy Regulator to determine the efficiency and
prudency review in which Eskom has to demonstrate that it has maximised the availability
and utilisation of cheaper resources such as Integrated Demand Management (IDM) and
Demand Market Participation (DMP). “
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
MYPD3 2013/14 RCA Submission to NERSA
14.1
November 2015
Page 83 of 205
Reasons for OCGTs variance
During the 2013/14 financial year Eskom utilised OCGTs at 2 565 GWh more than was
assumed in the MYPD3 decision with the main intention to avoid load shedding. This is
clearly stated in the MYPD Methodology para 8.4.2.
“For avoidance of doubt, gas
turbine generation should be employed before implementation of load shedding
activities”.
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 2014. 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.
14.2
Avoidance of load shedding
14.2.1 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
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 2014. 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.
14.2.2 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 1 160 MW during March 2014.
14.2.3 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 3 226 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 5 000 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.
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.
14.2.4 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.
MYPD3 2013/14 RCA Submission to NERSA
November 2015
Page 86 of 205
Figure 7: Load shedding impact in 2013/14
14.2.5 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.
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.
MYPD3 2013/14 RCA Submission to NERSA
November 2015
Page 88 of 205
14.3.1 Supply side options
14.3.1.1
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).
14.3.1.2
Regional supply
Eskom secured regional emergency supply from Aggreko during the year.
14.3.1.3
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.
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.
14.3.2 Demand side options
14.3.2.1
Demand response
In the MYPD3 application, Eskom had assumed demand response programmes which
required a total cost of R11 345 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.
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.
14.3.2.2
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.
MYPD3 2013/14 RCA Submission to NERSA
November 2015
Page 91 of 205
Table 40: OCGTs decision from MYPD3
R'm
OCGT Costs Applied For
OCGT Costs Adjustments
Approved OCGT Costs
2012/13
Approved
Expenditure
657
2013/14
3 592
(1 055)
2 537
2014/15
3 258
(548)
2 710
2015/16
1 788
(280)
1 508
2016/17
1 898
(299)
1 599
2017/18 MYPD 3 Total
2 056
12 592
(332)
(2 514)
1 724
10 078
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.
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
6 651.4
1 662.3
4989.1
Gourikwa
3 389.4
799.8
2590.0
Acacia
241.2
37.6
203.6
Port Rex
278.6
37.7
240.9
10 560.6
2 536.9
8 023.7
Total costs (R’m)
Power Station volumes
2013/14 Actual
GWh
2013/14 Decision
GWh
Variance in GWh
Ankerlig
2 358
689
1 669
Gourikwa
1 133
337
796
Acacia
56
15
41
Port Rex
73
15
58
3 621
1 056
2 565
Total GWh
Fuel Burn (litres)
Actuals
Actual R/Litres
Average
Litres per MWh
Ankerlig
743 002 970
8.88 *
315
Gourikwa
359 674 015
9.42 *
317
Acacia
19 876 164
12.14
354
Port Rex
25 976 901
10.72
355
Total litres
1 148 530 050
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.
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.
14.6.1 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.
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.
14.6.2 Available generation capacity
The Eskom system comprises of 41 995 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.
MYPD3 2013/14 RCA Submission to NERSA
November 2015
Page 95 of 205
14.6.3 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.
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
14.6.4 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.
14.6.5 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.
MYPD3 2013/14 RCA Submission to NERSA
November 2015
Page 97 of 205
14.6.6 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.
14.6.7 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.
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.
14.7
Technical issues impacting OCGT generation
14.7.1 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
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.
14.7.2 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
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.
14.7.3 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.
14.7.4 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)
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.
14.8 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.
14.9
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.
MYPD3 2013/14 RCA Submission to NERSA
November 2015
Page 102 of 205
14.10 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.
14.11 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.
14.12 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
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.
14.12.1
Delays in new build capacity
The first contributor to the capacity shortage is the delays of new build capacity. According to
the 1998 Energy White Paper the investment decision for new base load power stations
needed to be made by, not later than, 1999 in order to meet increasing demand by 2007.
However, the approval for Eskom to embark on the build programme was made in late 2004,
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).
MYPD3 2013/14 RCA Submission to NERSA
14.12.2
November 2015
Page 104 of 205
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
2012/13
Grootvlei
30
Komati
200
Camden
30
2013/14
Medupi
2014/15
2015/16
2016/17
2017/18
300
100
30
794
1 588
794
794
Kusile
800
800
800
800
Ingula
1 332
Total MW
4 764
1 600
994
4 800
1 332
100
100
260
TOTAL
30
794
Sere
2018/19
2 926
2 388
1 594
1 594
1 600
11 356
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.
14.12.2.1
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.
MYPD3 2013/14 RCA Submission to NERSA
14.12.2.2
November 2015
Page 105 of 205
Kusile : Schedule delays
Since inception of the Kusile Project, schedule delays have been experienced due to the
following:
•
Industrial actions in 2011, 2013 and 2014.
•
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.
14.12.2.3
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. 4971 for the General Works and No.
4970 for the IPHS) on 06 November 2013.
•
Section 54 No. 4971 was lifted on 19 September 2014 but No. 4970 remained in effect
and was only conditionally lifted on 26 February 2014.
•
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).
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.
14.13
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 60-66 months. However this is mostly based on US data.
The typical coal power stations that have been constructed in the US over the last decade or
so were sized between 300MW to 850MW and consisted of, e.g. just in 2010 there were 10
such plants commissioned in the US. It might well be that it takes longer to get to
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 60-66
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 7 000 MW were commissioned just in 2010, with another >6 000 MW
commissioned over the preceding three years, and a further 7 000 MW under construction and due
over 2011 and 2012. A further 23 000 MW was announced / near construction or had already
received permits, for 2011-2018. In total there are around 44 000 MW of coal power plant projects
either already completed or in construction or planned, over the period 2004-2018.

Learning curve:
With 20 000 MW already completed between 2004 and 2012 and a further 23 000 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.
MYPD3 2013/14 RCA Submission to NERSA
14.13.1

November 2015
Page 108 of 205
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 1992. The industrial policy from 1997 to 2004 also prohibited
Eskom from further generating capacity investments. “Eskom is not allowed to invest in new
generation capacity in the domestic market”. The contractors’ local facilities and skills were also lost
over this period. Eskom thus had to completely re-establish its new-build project management
capability when the ESI policy changed in late 2004 and Eskom got approval to commence with the
build programme, as did many of the contractors. It would have also had to acquire new skills and
competencies based on the new technologies available.

Learning curve:
After a sixteen year interval, for Eskom the new-build process implied the starting point of the
learning curve again.

Up-front planning and preparatory work:
When the new-build task was restored to Eskom it was already apparent that there was a generation
capacity crisis. Commencing in 2005 the preparation of the ‘business cases’, the investment
decisions, the technical designs for the process of requesting tenders, and the adjudicating and
awarding of such tenders were completed. The approval of the first new base load capacity
investment (for 3x700 MW = 2100 MW) was made in December 2005 and revised by December
2006 to become the 4 764 MW ‘Medupi’ – all within less than two years from receiving the go-ahead.
Medupi’s main contracts were placed in October 2007, with Kusile shortly after. Time constraints did
not allow nearly enough planning and development work upfront – e.g. Eskom could not follow the
normal process for Medupi but went ahead with tendering and contracting based on ‘virtual’ designs
i.e. Eskom went to the market using the designs for the 4110MW Majuba power station, which had
been designed in the 1980s.
MYPD3 2013/14 RCA Submission to NERSA

November 2015
Page 109 of 205
Total projects portfolio:
In parallel with the programme to construct the 4 764 MW Medupi base load coal plant, Eskom also:
o
Embarked on the programme to construct the 4 800 MW Kusile;
o Started and have since completed the refurbishment and re-commissioning of three older coal
fired power stations (23 units of 3 500 MW in total over the period July 2005 to October 2013);
o
Constructed and commissioned 2 000 MW of OCGT capacity;
o
Commenced construction of 1332 MW Ingula pumped storage; and
o
Executed large Transmission projects
Starting with the US norm of 60-66 months, some months should be added for each factor to
arrive at a more realistic norm for the construction duration given the specific South African
and Eskom context. The 60-66 months US norm very quickly becomes 84-90 months or
more, in this context.
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 48-54 month period that had
been established in China – where however over a three year period, generation capacity in
the order of 120 000 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)
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.
14.13.2
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
2006. 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
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.
14.13.3
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.
14.13.4
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,
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.
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
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.
14.13.5
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
Actual
2013/14
Measure
EAF, %
75.13
Normal UCLF, %
12.61
Less: Constrained UCLF, %
Underlying UCLF% %
Normal PCLF, %
3
Underlying PCLF, %
Normal OCLF, %
UAGS/7 000, ratio
EUF, EUF
1.63
10.98
10.50
4
5
Underlying OCLF, %
2
1
10.77
1.75
6
3.11
5.24
83.55
MYPD3 2013/14 RCA Submission to NERSA
November 2015
Page 115 of 205
Measure
Descriptions
EAF
Measures plant availability including planned and unplanned
unavailability and energy losses not under plant management control
Normal UCLF
Measures the lost energy due to unplanned energy losses resulting
from equipment failures and other plant conditions.
Constrained
This is UCLF that was a result of emissions and short-term related
UCLF
UCLF due to system constraints to meet the “Keeping the lights on”
objective. This is apportioned between PCLF and OCLF
Underlying UCLF
This is the UCLF that is the difference between normal and
constrained UCLF and that is still within Generation control
Normal PCLF
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
is energy loss during the period because of unplanned shutdowns
due to conditions that are outside Generation management control
Underlying OCLF
The sum of the normal OCLF and the constrained OCLF (the
apportionment of the constrained UCLF (1. above) that is assigned
to OCLF) UAGS / 7 000 indicates the ratio of unplanned unit trips per
7 000 operating hours
EUF
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%.
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 2013/14
Average coal power station heat rate, MJ/kWh
2013/14
2012/13
2011/12
11.49
11.25
11.46
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
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.
14.13.5.1
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
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.
14.13.6
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.
14.13.6.1
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.
MYPD3 2013/14 RCA Submission to NERSA
November 2015
Table 45: Breakdown of system UCLF (%)1
Normal UCLF
Actual
Mar
2014
12.61
Actual
Mar
2013
12.12
Less: Constrained UCLF
1.63
3.41
Underlying UCLF
10.98
8.71
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
1.58
9.40
2.69
6.02
1.15
8.25
0.84
5.18
The figure below sets out the monthly UCLF % over the last 3 financial years:
Figure 16: Monthly UCLF for last 3 years
Page 119 of 205
MYPD3 2013/14 RCA Submission to NERSA
14.13.6.2
The main contributors to UCLF were as follows:
14.13.6.2.1
Partial load losses
November 2015
Page 120 of 205
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%).
14.13.6.2.2
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%)
MYPD3 2013/14 RCA Submission to NERSA
14.13.6.3
November 2015
Page 121 of 205
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%.
14.13.6.4
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.
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 2013. 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.
14.13.6.5
Energy Availability Factor (EAF)
The EAF trend has been decreasing over the past few years as disclosed in figure below.
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.
14.13.6.6
UAGS/7 000
Unplanned automatic grid separations (UAGS) per 7 000 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).
14.13.6.7
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.
14.13.6.8
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
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.
14.13.6.9
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
6 - 12
40 - 60
Interim repairs
2-3
14 - 35
6
28
1 - 1.5
7 - 14
6
35
ad hoc
120
Mini general overhaul
Boiler inspection
Statutory inspection and test
Main steam pipe work
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.
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.
14.13.7
Benchmarking
14.13.7.1
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 2012. The availability of the stations in the median and
worst quartiles has been declining. Adequate reliability and design-based maintenance is in
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 2000-2012
Figure 21: Benchmarking UCLF % all coal sizes 2000-2012
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.
MYPD3 2013/14 RCA Submission to NERSA
November 2015
Page 127 of 205
Figure 22: Benchmarking PCLF % all coal sizes 2000-2012
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
performing
Eskom’s
best
units
was
significantly better than that of
VGB benchmark units.
Figure 23: Benchmarking EUF % all coal sizes 2000-2012
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.
MYPD3 2013/14 RCA Submission to NERSA
14.13.8
November 2015
Page 128 of 205
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 50010 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.
14.13.9
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
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 3 621 GWh (2012/13: 1 905 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.
MYPD3 2013/14 RCA Submission to NERSA
November 2015
Page 130 of 205
Figure 24: Summer and Winter Load Profiles
14.13.9.1
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.
MYPD3 2013/14 RCA Submission to NERSA
15
November 2015
Page 131 of 205
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.
15.1 Regulated asset base adjustment for CECA
Capital expenditure will affect the value of the regulated asset base (RAB).
The actual capital expenditure for the RAB incurred during 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.
15.1.1 Step 1: Computing change in RAB
The change in RAB is determined in terms of rule 6.7.2.3 as shown below.
6.7.2 To accommodate the unstable environment in which the WUC cost will be
undertaken, the approach for adjusting works under construction for cost and timing
variances will be as follows:
6.7.2.1 Eskom will annually report to the Energy Regulator on its capital expenditure
programme, providing information on timing and cost variances.
6.7.2.2 At the end of each financial year, Eskom will provide the Energy Regulator with a
final reconciliation report of the actual works under construction incurred.
6.7.2.3 On receipt, the Energy Regulator will record all efficient works under construction
above or below the approved amount on the works under construction carryover account
(CECA) and quantify Eskom’s exposure.
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
Allowed MYPD capital expenditure
Less: Allowed capital expenditure excluded for CECA purposes
Future fuel
Technical and refurbishment capital expenditure
Capex subject to re-measurement for CECA
Actual MYPD capital expenditure
Less: Actual capital expenditure excluded for CECA purposes
Future fuel
Payment received in advance recognised to revenue
Technical and refurbishment capital expenditure
Actual Capex subject to re-measurement for CECA
Annual difference
Technical and refurbishment capital expenditure excluded for
CECA purposes
Capex subject to CECA for re-measurement
Average capital expenditure difference for CECA calculation
Allowed Return - NERSA MYPD 3 decision
Calculation Eskom Regulated
ref
divisions
50 772
A
(14 830)
(2 740)
(12 090)
B
35 942
C
(21 077)
57 555
(2 675)
(1 444)
(16 958)
D
36 478
(5 710)
C-A
D- B
(6 246)
536
(D-B)/2
268
E
3.4%
MYPD3 2013/14 RCA Submission to NERSA
November 2015
Page 133 of 205
15.1.2 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 6.7.3.1 shown below:
6.7.3 Balances on the CECA will be adjusted as follows in the Regulatory Clearing Account (RCA) as
follows:
6.7.3.1 At the end of the financial year, if there is any under-expenditure compared to forecasted
works under construction, the value of the RAB will be adjusted downwards for works under
construction not undertaken and the revenues for the subsequent financial year adjusted to
compensate for the return earned on unused funds in the previous MYPD. For any over-expenditure
approved by the Energy Regulator compared to forecasted works under construction, the balance will
be added to the RAB and Eskom will be allowed additional returns on the CECA balance to recover
the costs of the over-expenditure for that year. This approach will effectively minimise any potential
windfall losses or gains should the approved capital expenditure differ from the actual expenditure.
Table 48: CECA Calculation- Return due to/by Eskom
FY 2014
CECA Calculation : Return due to/(by) Eskom
Calculation Eskom Regulated
ref
divisions
MYPD3 Regulatory assets base
Add /(Deduct): Current year average capex variance
Add/ (Deduct): Cumulative prior year capex variances
Adjusted RAB
MYPD3 allowed return on assets
Return on adjusted RAB
Increase / (Decrease) in return for RCA
MYPD3 allowed return expressed as a percentage of the rate base
699 609
268
0
A
699 877
B
A*C
(A*C)-B
23 477
C
3.36%
23 486
9
MYPD3 2013/14 RCA Submission to NERSA
15.2
November 2015
Page 134 of 205
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 2013/14
15.3
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
performance and availability in order to balance supply and demand
improve
plant
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
15.3.1 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
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,
cost-
benefit 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
Generation other
Transmission
R70bn
R58bn
R51bn
R112bn
R64bn
R35bn
R42bn
R6bn
- R16bn
Distribution
Corporate
Total
R44bn
R26bn
R7bn
R230bn
R14bn
R251bn
- R18bn
R7bn
R21bn
MYPD3 2013/14 RCA Submission to NERSA
November 2015
Page 137 of 205
15.3.2 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:
15.4
-
Sustainability R6bn
-
Eskom Real Estate R2bn
-
Group IT R5bn
-
Fleet R1bn
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.
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
33 475
Generation
10 326
Transmission
1 516
Distribution
10 265
Subtotal
55 582
Adjustments :
Exclude DOE capex included as part of Distribution
1 973
-2 728
Include Future fuel capex
2 675
Include Corporate and other
2 026
Total per CECA disclosure
57 555
Table 54: Capital Expenditure (excluding capitalised borrowing costs) per division
MYPD3 2013/14 RCA Submission to NERSA
15.5
November 2015
Page 139 of 205
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 17 384 MW, transmission lines by 9 756km and substation capacity
by 42 470 MVA. Since inception, the capacity expansion programme has resulted in
additional generation capacity of 6 237 MW, mainly through the RTS programme, 5 816 km
of transmission lines and 29 655 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
15.5.1 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.
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 2015. 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.
MYPD3 2013/14 RCA Submission to NERSA
November 2015
Page 141 of 205
15.5.2 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 2017. 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.
15.5.3 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 2013. 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 2014. This
has set back the completion schedule at Ingula.
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 2014. 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 2015. The accident will also impact the remaining units’
synchronisation dates.
15.6
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.
15.6.1 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.
MYPD3 2013/14 RCA Submission to NERSA
November 2015
Page 143 of 205
15.6.2 Kusile : Cost overruns
These schedule impacts have been the major driver of cost increases. Eskom has taken
critical steps to mitigate against some of the challenges at Medupi and Kusile.
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.
15.6.3 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.
15.7
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
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.
MYPD3 2013/14 RCA Submission to NERSA
16
November 2015
Page 145 of 205
Inflation adjustment
The RCA submission makes use of the two inflation adjustments linked to para 14.1.1. 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.
16.1
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
Inflation
Inflation index
Decision
Actuals
5.60%
5.70%
1.056
1.057
Given the higher inflation profile over the period, operating costs were adjusted upwards by
R33m (R34 876/1.056 * 1.057 less R34 876).
16.2
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 6.4.4 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
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 6.4.4 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 6.4.4 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
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 6.4.4
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 14.1.1:
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:
MYPD3 2013/14 RCA Submission to NERSA
November 2015
Page 148 of 205
14.1.1 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 14.1.1, 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 14.1.1 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 6.4.4. 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
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 6.4.4 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 2014.
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 6.4.4.
16.3 Inflation adjustment on RAB – revenue impact
16.3.1 Summary:
According to Rule 6.4.4 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’:
MYPD3 2013/14 RCA Submission to NERSA
November 2015
Page 150 of 205
Table 56 : Summary of RAB inflation adjustments
2013/14
R’m
Inflation adjustments relating to regulatory asset base
Return on assets – increase due to change in inflation rates
661
Depreciation – increase due to change in inflation rates
1 337
TOTAL increase in RCA for 2013/14
1 998
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
2013/14
2013/14
2013/14
Return on assets (R'm) _ Assets multplied by ROA%
23 477
24 138
661
Generation
16 422
16 888
465
Transmission
3 571
3 672
101
Distribution
3 484
3 579
95
Depreciation
25 733
27 069
1 337
Generation
Return on assets (ROA)
16 239
17 066
827
Transmission
3 796
3 991
195
Distribution
5 698
6 012
314
MYPD3 2013/14 RCA Submission to NERSA
November 2015
Page 151 of 205
Table 58: Regulatory asset base
MYPD3 decision
_ No indexing
MYPD3 decision
_ Including
indexing
MYPD3 Variance
_ Index Vs No
Index
Eskom Regulated MYPD3 Regulated Asset Base (RAB)
2013/14
2013/14
2013/14
Closing RAB
Generation
Transmission
Distribution
703 346
493 887
108 356
101 103
742 754
521 625
114 374
106 754
39 407
27 738
6 018
5 651
Average RAB
Generation
Transmission
Distribution
699 609
489 378
106 415
103 816
719 313
503 247
109 424
106 642
19 704
13 869
3 009
2 826
MYPD3 2013/14 RCA Submission to NERSA
17
Integrated demand management
17.1
Demand-side management:
November 2015
Page 152 of 205
Demand side management is divided into two broad programmes, as discussed below:
17.1.1 The demand-response programme
Consists of a range of sub-programmes which offers commercial and industrial customers
financial incentives to reduce their electricity requirements as and when needed. Before
being placed on hold, the requirements for taking up demand response programme products
(standard product and standard offering) were amended to allow smaller companies to
participate in the programme. Eskom spent R350m on demand market participation, the
reduction from previous year mainly as a result of a significant decrease in the power
buyback programme.
17.1.2 The residential mass roll-out programme
This Programme aims to reduce residential electricity usage by encouraging households to
use energy-efficient technologies. The programme is a significant lever to reduce demand
during periods of system constraint.
It includes the following sub-programmes:

The 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 2014.

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 47 020 solar water heaters were installed, bringing the
total for the rebate programme and residential contracts to 381 052 since its inception in
2009
MYPD3 2013/14 RCA Submission to NERSA
17.2
November 2015
Page 153 of 205
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.
17.3
Methodology
The MYPD methodology deals with demand side management and demand market
participation separately with their respective rules. The energy efficiency demand side
management is disclosed below.
IDM
11.1.1.8 IDM will incur penalties for under achieving their targets. In case of
non-performance, the penalty will be calculated as follows:
Penalty(R) = total allowed revenue /projected MW target X MW unsaved
= R/MW X MW unsaved
MYPD3 2013/14 RCA Submission to NERSA
November 2015
Page 154 of 205
17.3.1 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
`
2012/13 Approved
Expenditure
2013/14
2014/15
2015/16
Applied for Approved Applied for Approved Applied for Approve
2 941
1 455
2 709
953
1 862
8
2 351
Funding
Programmes - Peak Demand Savings(MW)
Programmes - Annualised Energy
Savings(GWh)
Programme Costs
Operating Costs including Depreciation
Other costs
R/MW
R/kWh
447
458
379
358
294
221
1
1 815
2 245
2 660
1 853
1 107
1 361
2 419
1 204
612
826
1 581
7
4
464
(183)
6.42
1.31
348
3.84
0.79
481
(191)
7.57
1.99
341
485
(204)
8.42
2.25
3
4
1
5.26
1.30
3.24
0.79
17.3.2 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.
17.3.2.1
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.
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 107.9 are excluded for the RCA analysis.
Hence the total capacity verified for FY2014 after all the adjustments is 296.7 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
296.7 MW
DSM costs (R’ m)
R1 455m
R1 356m
- R99m
Rate (R/MW)
R3.84m
R4.57m
- R0.73m
- 82.3 MW
17.3.3 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.
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 - 82.3MW = - 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.
17.4
Demand Market Participation and Power Buy Backs
17.4.1 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.”
MYPD3 2013/14 RCA Submission to NERSA
November 2015
Page 157 of 205
17.4.2 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
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)
MYPD3
Decision
1 167
-
Actuals
262
1 117
87
1 030
Variance
-905
1 117
87
1 030
1 167
3 108
1 379
1 361
212
-1 747
* A provision was raised for all contractual obligations in 2013. These
services was only rendered and paid for in the 2014 financial year.
17.4.3 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 2013. The
following table provides a summary of the actuals costs and performance over the PBB
contractual period.
MYPD3 2013/14 RCA Submission to NERSA
November 2015
Page 158 of 205
Table 63: Actual Costs and Performance of PBB
Month
13-Apr
13-May
Nov/Dec-13
Demand
Reduction
(MW)
Cost
915
R 488.9m
877
R 488.4m
497
R 139.6m
Total
R 1 116.9m
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.
17.4.4 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.
17.4.5 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.
MYPD3 2013/14 RCA Submission to NERSA
17.5
November 2015
Page 159 of 205
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.
MYPD3 2013/14 RCA Submission to NERSA
18
November 2015
Page 160 of 205
Operating costs
Operating costs comprises employee benefits, maintenance and other operating costs. It
excludes IDM which is treated separately for RCA purposes.
Operating costs
14.1.1 The nominal estimates of the regulated entity will be managed by adjusting for
changes in the inflation rate.
14.1.4 Adjusting for prudently incurred under-expenditure on controllable operating
costs as may be determined by the Energy Regulator.
18.1
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
18.1.1 Allowed employee costs in 2013/14
Table 64: The allowed employee costs for Generation, Transmission and Distribution
MYPD3 2013/14 RCA Submission to NERSA
18.1.2 Allowed maintenance costs in 2013/14
Table 65: Allowed Maintenance Costs
18.1.3 Allowed arrear debts in 2013/14
Table 66: Allowed Arrear Debts
18.1.4 Allowed cost of cover in 2013/14
Table 67: Allowed Cost of Cover
18.1.5 Allowed corporate costs in 2013/14
Table 68: Allowed Corporate Costs
November 2015
Page 161 of 205
MYPD3 2013/14 RCA Submission to NERSA
18.2
November 2015
Page 162 of 205
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
Employee benefits
Other opex
Other income
Net impairment loss
Cost of cover
Allowed
18 509
16 367
749
2 159
AFS actuals
22 384
24 340
-1 873
1 549
2 909
FY 2014
Regulatory
adjustments
-433
-883
369
-10
-0
37 784
49 309
-957
Operating costs (R'm)
RCA actuals
21 951
23 457
-1 504
1 539
2 909
48 352
RCA balance
3 442
7 090
-1 504
790
750
10 568
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.
MYPD3 2013/14 RCA Submission to NERSA
18.3
November 2015
Page 163 of 205
Reasons for variance in other operating costs
18.3.1 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
Net Employee costs (after capitalisation)
Employee costs capitalised to assets
Gross Employee costs (R'm)
2013/14
22 384
5 685
28 069
2012/13
20 776
5 054
25 830
2011/12
17 722
4 229
21 951
2010/11
15 360
3 685
19 045
2009/10
13 325
3 174
16 499
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.
MYPD3 2013/14 RCA Submission to NERSA
November 2015
Page 164 of 205
18.3.2 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.
18.3.3 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.
18.3.3.1
Soweto arrear debt
Soweto’s arrear debt continues to increase. Eskom supplies electricity to about 180 000
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, 4 838 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%.
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.
18.3.3.1.1
Response Strategies
From 2007, Eskom ran a split metering pilot project to 4 000 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.
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.
18.3.3.2
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
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 2014. 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
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.
18.3.3.2.1
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.
18.3.3.3
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
MYPD3 2013/14 RCA Submission to NERSA
November 2015
Page 169 of 205
18.3.4 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.
MYPD3 2013/14 RCA Submission to NERSA
November 2015
Page 170 of 205
18.3.5 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.
18.3.5.1
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.
could impact security of supply and long term business sustainability.
This
Key trade-off
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
18.3.5.2
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.
MYPD3 2013/14 RCA Submission to NERSA
November 2015
Page 172 of 205
Figure 27: Time lapse between application and MYPD2 decision
Months
0
15
18
20
32
44
Cumlulative
Months
116
56
MYPD2 period
Start
Process
Start
Eskom
MYPD2
application
November
Nersa
MYPD2
decision
February 2010
April
2010
End
March
2011
March
2012
Eskom
Commenced
preparation
for MYPD2
application
September
2008
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 2012/13.
18.4
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.
18.5
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
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 14.1.4 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 14.1.5 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 14.1.4.
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
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.”
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.
MYPD3 2013/14 RCA Submission to NERSA
19
November 2015
Page 176 of 205
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.
MYPD3 2013/14 RCA Submission to NERSA
20
November 2015
Page 177 of 205
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
SM<1
Major Incidents
Line Faults / 100km
Total (R’m)
Performance Result
Incentive / Penalty (-) (Rm)
Comment
3.05
0
Dead band
0
40
Reward
1.73
36
Reward
-
76
-
MYPD3 2013/14 RCA Submission to NERSA
Figure 28: Transmission system minutes (<1)
Table 73: Transmission number of major incidents (>1SM)
Note: Number of Major Incidents (>1SM)
November 2015
Page 178 of 205
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.
MYPD3 2013/14 RCA Submission to NERSA
Table 75: Distribution SQI performance in 2013/14
Incentive/Penalty(-) (Rm)
Measure
Totals (Rm)
March 2014 (Year 1)
SAIDI
145.9
291.8
SAIFI
116.72
233.44
DSLI
0
-29.18
SQI Total
262.62
496.06
November 2015
Page 180 of 205
MYPD3 2013/14 RCA Submission to NERSA
21
21.1
November 2015
Page 181 of 205
Reasonability tests
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 2013/14.
21.2
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
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.
21.3
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”.
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.”
MYPD3 2013/14 RCA Submission to NERSA
21.4
November 2015
Page 184 of 205
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.
21.5
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.
21.6
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.
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)
Calculation of EBITDA
EBITDA
Profit before net finance (cost)/ income - EBIT
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
Investment in securities
Loans receivable
Net interest per AFS
FY 2014
A
B
C
D
23 497
11 563
11 934
18 235
16 302
-2 044
1 523
2 338
116
-1 176
-823
-353
17 059
Add / (deduct) items excluded for purposes of the framework :
Provisions and Employee benefit obligations
Finance lease payables
Finance income
-1 278
-2 338
-116
1 176
Total interest used for calculation
15 781
Add : Debt repaid
Total debt serviced
7 488
E
23 269
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 1.01. 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
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.
21.7
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
EBIT Interest cover
EBIT
Interest
Calculation
B/D
B
D
FY 2014
0.68
11 563
17 059
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 R22 789 million. This revised EBIT
interest cover ratio is within acceptable range of 2.
21.8
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
B/E
B
E
FY 2014
1.01
23 497
23 269
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 R22 789 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.
MYPD3 2013/14 RCA Submission to NERSA
22
November 2015
Page 187 of 205
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 2014.

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 R22 789 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
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 >>>>>>>>>>>>>>>>>>>>>>>>>>>>>>>>
MYPD3 2013/14 RCA Submission to NERSA
Annexures:
Revenue:
Annexure 1: Income Statement in AFS 2014
November 2015
Page 189 of 205
MYPD3 2013/14 RCA Submission to NERSA
Annexure 2: Revenue note 32 from AFS (p81)
Annexure 3: Revenue from divisional report 2014 (P47)
November 2015
Page 190 of 205
MYPD3 2013/14 RCA Submission to NERSA
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.
November 2015
Page 191 of 205
MYPD3 2013/14 RCA Submission to NERSA
Annexure 6: Sales volumes GWh (Divisional report page 88)
November 2015
Page 192 of 205
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”.
MYPD3 2013/14 RCA Submission to NERSA
IDM
Annexure 9: EEDSM Annual report for 2013/14
November 2015
Page 194 of 205
MYPD3 2013/14 RCA Submission to NERSA
November 2015
Page 195 of 205
Of the 107.9 MW that were installed, not verified at the end of FY 2014, 12 projects have
since been verified. IDM claimed 63.06 MW for these projects and the actual verified savings
are 62.09 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.
MYPD3 2013/14 RCA Submission to NERSA
Operating costs
Annexure 10: Supplementary report 2014, page 48
Annexure 11: Annual Financial Statement 2014
November 2015
Page 196 of 205
MYPD3 2013/14 RCA Submission to NERSA
Other Income
Annexure 12: Annual Financial Statement 2014
Reasonability test
Annexure 13: Finance cost extract (AFS FY 2014 page 93)
November 2015
Page 197 of 205
MYPD3 2013/14 RCA Submission to NERSA
23
November 2015
Page 198 of 205
Abbreviations
BPP
Business Productivity Programme
Capex
Capital Expenditure
c/kWh
Cent per kilowatt hour
COD
Commercial Operation Date
CoGTA
Department of Cooperative Governance and
Traditional Affiars
COS
Cost of Supply
CPI
Consumer Price Index
CSP
Concentrated Solar Power
DoE
Department of Energy
DMP
Demand Market Participation
DPE
Department of Public Enterprises
DRC
Depreciated Replacement Cost
Dx
Distribution
EAF
Energy availability factor (see glossary)
EBITDA
Earnings before interest, taxation, depreciation and
amortisation
EPP
Electricity Pricing Policy
ERTSA
Eskom’s Retail Tariff Structural Adjustments
EUF
Energy utilisation factor (see glossary)
GDP
Gross Domestic Product
GW
Gigawatt = 1 000 megawatts
GWh
Gigawatt-hour = 1 000MWh
Gx
Generation
HVAC
Heating, Ventilation and Air Conditioning
IBT
Inclining Block Tariff
MYPD3 2013/14 RCA Submission to NERSA
November 2015
Page 199 of 205
IDC
Interest during construction
IDM
Integrated demand management
IPP
Independent power producer (see glossary)
IRP 2010
Integrated Resource Plan 2010-2030
KIC
Key industrial customers
Kt
Kiloton = 1 000 tons
Km
Kilometer
kV
Kilovolt
kWh
Kilowatt-hour = 1 000 watt-hours (see glossary)
L/USO
Litres per unit sent out
M&V
Measurement and Verification
Ml
Megalitre = 1 m litres
MKI
Medupi, Kusile and Ingula
Mt
M tons
MTPPP
Medium Term Power Purchase Programme
MVA
Megavolt-ampere
MW
Megawatt = 1 m watts
MWh
Megawatt-hour = 1 000kWh
MYPD
Multi-Year Price Determination
NERSA
National Energy Regulator of South Africa
O&M
Operations and Maintenance
OCGT
Open-Cycle Gas Turbine (see glossary)
OCLF
Other Capability Loss Factor
ODC
Owner’s Development Cost
Opex
Operating Expenditure
PE
Primary Energy
PPA
Power Purchase Agreement
MYPD3 2013/14 RCA Submission to NERSA
November 2015
Page 200 of 205
PPI
Producer Price Index
PCLF
Planned Capability Loss Factor
PAJA
Promotion of Administrative Justice Act, 2000
PFMA
Public Finance Management Act, 1999
R&D
Research and Development
R/kVA
Rand per kilovolt ampere
R/kWh
Rand per kilowatt hour
R/MW
Rand per Megawatt
R/MWh
Rane per Megawatt hour
R’m
Rand million
RAB
Regulatory Asset Base
RCA
Regulatory Clearing Account
RCN
Replacement Cost New
RTS
Return-to-Service
SADC
Southern African Development Community
SAIDI
System average interruption duration index
SAIFI
System average interruption frequency index
SBP
Single Buyer Procurement
SM
System Minutes
SQI
Service Quality Incentive
STPPP
Short Term Power Purchase Programme
SWH
Solar Water Heaters
TOU
Time-of-Use
Tx
Transmission
UAGS
Unplanned automatic grid separations
UCLF
Unplanned Capability Loss Factor (see glossary)
UOS
Use-of-System
MYPD3 2013/14 RCA Submission to NERSA
November 2015
WACC
Weighted Average Cost of Capital
WUC
Work Under Construction
Page 201 of 205
MYPD3 2013/14 RCA Submission to NERSA
24
November 2015
Page 202 of 205
Glossary and Terms
Base-load plant
Largely coal-fired and nuclear power stations, designed
to operate continuously
Cost of electricity (excluding
depreciation)
Electricity-related costs (primary energy costs, employee
benefit costs plus impairment loss and other operating
expenses) divided by total electricity sales in GWh
multiplied by 1 000
Daily peak
Maximum amount of energy demanded by consumers in
one day
Debt service cover ratio
Cash generated from operations divided by (net interest
paid from financing activities plus debt securities and
borrowings repaid)
Decommission
To remove a facility (e.g. reactor) from service and store
it safely
Demand side management
Planning, implementing and monitoring activities to
encourage consumers to use electricity more efficiently,
including both the timing and level of demand
Electricity EBITDA margin
Electricity revenue (excluding electricity revenue not
recognised due to uncollectability) as a percentage of
EBITDA
Electricity operating costs per
kWh
Electricity-related costs (primary energy costs, employee
benefit costs, depreciation and amortisation plus
impairment loss and other operating expenses) divided
by total electricity sales in kWh multiplied by 100
Electricity revenue per kWh
Electricity revenue (including electricity revenue not
recognised due to uncollectability) divided by total kWh
sales multiplied by 100
Measure of power station availability, taking account of
Energy availability factor (EAF) energy losses not under the control of plant
management and internal non-engineering constraints
MYPD3 2013/14 RCA Submission to NERSA
November 2015
Page 203 of 205
Energy efficiency
Programmes to reduce energy used by specific end-use
devices and systems, typically without affecting services
provided
Energy utilisation factor (EUF)
Utilisation of the available plant
Forced outage
Shutdown of a generating unit, transmission line or other
facility for emergency reasons or a condition in which
generating equipment is unavailable for load due to
unanticipated breakdown
Gross debt
Debt securities and borrowings plus finance lease
liabilities plus the after-tax effect of provisions and
employee benefit obligations
Gross debt/EBITDA ratio
Gross debt divided by earnings before interest, taxation,
depreciation and amortisation
Independent power producer
(IPP)
Any entity, other than Eskom, that owns or operates, in
whole or in part, one or more independent power
generation facilities
Interest cover
EBIT divided by (gross finance cost less gross finance
income)
Kilowatt-hour (kWh)
Basic unit of electric energy equal to one kilowatt of
power supplied to or taken from an electric circuit
steadily for one hour
Load
Amount of electric power delivered or required on a
system at any specific point
Load curtailment
Typically larger industrial customers reduce their
demand by a specified percentage for the duration of a
power system emergency. Due to the nature of their
business, these customers require two hours’ notification
before they can reduce demand
MYPD3 2013/14 RCA Submission to NERSA
November 2015
Page 204 of 205
Load shedding
Scheduled and controlled power cuts that rotate
available capacity between all customers when demand
is greater than supply in order to avoid blackouts.
Distribution or municipal control rooms open breakers
and interrupt load according to predefined schedules
Maximum demand
Highest demand of load within a specified period
MEAV
Modern equivalent asset value
Off-peak
Period of relatively low system demand
Liquid fuel turbine power station that forms part of peakOpen-cycle gas turbine (OCGT) load plant and runs on kerosene or diesel. Designed to
operate in periods of peak demand
Other capability loss factor
(OCLF)
Energy loss during the period because of unplanned
shutdowns due to conditions that are outside Generation
management control
Outage
Period in which a generating unit, transmission line, or
other facility is out of service
Peak demand
Maximum power used in a given period, traditionally
between 06:00–10:00, as well as 18:00–22:00 in
summer or 17:00-21:00 in winter
Peaking capacity
Generating equipment normally operated only during
hours of highest daily, weekly or seasonal loads
Peak-load plant
Gas turbines, hydroelectric or a pumped storage scheme
used during periods of peak demand
Planned capability loss factor
(PCLF)
Energy loss during the period because of planned
shutdowns
Primary energy
Energy in natural resources, e.g. coal, liquid fuels,
sunlight, wind, uranium and water
MYPD3 2013/14 RCA Submission to NERSA
November 2015
Page 205 of 205
Pumped storage scheme
A lower and an upper reservoir with a power
station/pumping plant between the two. During off-peak
periods the reversible pumps/turbines use electricity to
pump water from the lower to the upper reservoir. During
periods of peak demand, water runs back into the lower
reservoir through the turbines, generating electricity
Return on assets
EBIT divided by the regulated asset base, which is the
sum of property, plant and equipment, trade and other
receivables, inventory and future fuel, less trade and
other payables and deferred income
System minutes
Global benchmark for measuring the severity of
interruptions to customers. One system minute is
equivalent to the loss of the entire system for one minute
at annual peak. A major incident is an interruption with a
severity ≥ 1 system minute
Technical losses
Naturally occurring losses that depend on the power
systems used
Unit capability factor (UCF)
Measure of availability of a generating unit, indicating
how well it is operated and maintained
Unplanned capability loss
factor (UCLF)
Measures the lost energy due to unplanned energy
losses resulting from equipment failures and other plant
conditions