eskom mypd4 revenue application systems operations and ... · the role of the system operator...
TRANSCRIPT
Eskom MYPD4
Revenue Application
Systems Operations and
Generation
Nersa Public Hearings
Port Elizabeth
16 January 2019
Depreciation
1
The MYPD methodology through the allowable revenue formula was applied
+ + + + + =
Primary
Energy(incl imports and
DMP)
IPPsOperating
expenditure(incl R &D)
Integrated
Demand
Management
Return on
AssetsRevenue
+
Tax &
Levies
Return on assets = % cost of capital allowed X depreciated replacement asset value
𝐴𝑅= (𝑅𝐴𝐵×𝑊𝐴𝐶𝐶)+𝐸+𝑃𝐸+𝐷+𝑅&𝐷+𝐼𝐷𝑀±𝑆𝑄𝐼+𝐿&𝑇±𝑅𝐶𝐴
Eskom allowed revenue application for 3 year period is R763 billion
Allowable Revenue (R'million) AR FormulaApplication
2019/20
Application
2020/21
Application
2021/22
Regulated Asset Base (RAB) RAB 1 268 310 1 336 120 1 401 506
WACC % ROA X -1.32% -0.21% 1.45%
Returns -16 687 -2 765 20 314
Expenditure E + 56 619 59 820 62 663
Primary energy PE + 73 386 75 876 79 561
IPPs (local) PE + 29 590 34 324 41 002
International purchases PE + 3 533 3 734 3 957
Depreciation D + 64 651 72 919 75 649
IDM I + 189 193 202
Research & Development R&D + 176 187 198
Levies & Taxes L&T + 8 272 8 198 8 147
RCA RCA +
Total R'm 219 730 252 485 291 692
Corporate Social Investment (CSI) - - 192 - 193 - 151
Total Allowable Revenue 219 537 252 292 291 542
System Operations
3
The Role of the System Operator
System operator is defined as the legal entity licensed to be responsible for short-term reliability of the IPS, which is in charge of controlling and operating the TS and dispatching generation (or balancing the supply and demand) in real time (SA Grid Code)
4
SO Business Objectives:
• Ensuring system reliability, safety and security.
• Dispatching generation.
• Operating the interconnected power system.
• Acquiring ancillary services for reliable operation.
• Undertaking various technical activities to support the above.
• Development of the Grid Code and monitoring compliance thereto by the ESI.
• Testing and certification (compliance validation) of power producers.
• Providing operational information to key stakeholders
275684-01-SADC-v01-11Apr11-DP-pf-CPT.ppt5
Eskom Grid is Integrated with most SADC countries
Uganda
Libya
Mali
DRC
Zambia
Egypt
Ethiopia
Kenya
Nigeria
Tanzania
Namibia
Botswana
Zimbabwe
Angola
Zambia:
• Eskom sells non-firm power
Mozambique:
• Cahora Bassa: Eskom purchases
1 150MW
• Motraco: Eskom owns one-third of
Motraco transmission company
and sells 950MW
• EDM: Eskom wheels 300MW to
EDM from Cahora Bassa
Uganda:
• Eskom operates
concessions on two
hydro power stations
Zimbabwe:
• Eskom sells non-firm
power
Botswana:
• Eskom sells firm and non-firm
power
Namibia:
• Eskom sells firm and non-firm
power
• Eskom sells directly to two
mining companies in Namibia
Swaziland:
• Eskom sells firm
power
Lesotho:
• Eskom sells firm power and buys
non-firm power
System Operator’s Role
Generation makes
the electricity
Transmission & Distribution transports the electricity
Customer Services
sells the electricity
System Operator ensures
continuous delivery of quality
electricity by maintaining a
stable network (in real-time,
every second)
The System Operator is
the electricity transport
and distribution
supervisor.
South African Demand Distribution
Province
Provincial demand
at time of 2018
System Peak
Eastern Cape 2 059 MW
Free State 1 557 MW
Gauteng 10 244 MW
KZN 6 336 MW
Limpopo 2 284MW
Mpumalanga 3 714MW
North West 3 841MW
Northern Cape 1 448 MW
Western Cape 3 846 MW
10 244
1 557
2 059
6 336
2 284
3 714
3 841
1 448
3 846
SA Generation Resources (January 2018 – 50 598 MW)
Arnot Power Station
Ankerlig Power Station
Gariep Power Station
Type Number Nominal capacity
Coal-fired 15 stations 38 023 MW
Gas/liquid fuel turbine 4 stations 2 409 MW
Hydroelectric 6 stations 661 MW
Pumped storage 3 stations 2 724 MW
Nuclear 1 station 1 860 MW
Wind energy 1 station 100 MW
Renewable IPP 64 stations 3 811 MW
Dispatchable IPP 2 stations 1 010 MW
Wind IPP 22 stations 1 998 MW
Solar PV IPP 33 stations 1 482 MW
CSP IPP 4 stations 300 MW
Total Eskom 30 stations 45 777 MW
Small Hydro IPP 2 stations 14 MW
Landfill IPP 3 stations 17 MW
Biomass IPP 0 stations 0 MW
Cost of generation
Demand forecast
Unconstrained
schedule
(Cheapest mix)
Network constraints
Day ahead contract
Generation scheduling process
Operating reserves
Renewable Forecast
Unconstrained schedule
(Least cost)
Constrained schedule
Meeting Demand on a Typical Day
• The bulk of the demand is met by base load coal, nuclear and imports via HVDC
• OCGTs and Pumped Storage plants are mainly required to manage peak demand
• The renewable generators are starting to make a substantial contribution
• Coal and hydro are the main providers of flexibility at present
• This process is monitored real time from the two control centres
16000
18000
20000
22000
24000
26000
28000
30000
32000
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23
MW Thu 06-DecLandfill Gas
Small Hydro
CSP
PV
Wind
Dispatchable IPPs
Manual Load Reduction
IOS (Excl ILS)
ILS Usage
Pumped Water Actuals
Hydro Water Actuals
Gas Actuals
International Actuals
Nuclear Actuals
Thermal Actuals
Forecast
11
Summer and Winter Profiles
21000
22000
23000
24000
25000
26000
27000
28000
29000
30000
31000
32000
33000
34000
35000
00
:00
to 0
1:0
0
01
:00
to 0
2:0
0
02
:00
to 0
3:0
0
03
:00
to 0
4:0
0
04
:00
to 0
5:0
0
05
:00
to 0
6:0
0
06
:00
to 0
7:0
0
07
:00
to 0
8:0
0
08
:00
to 0
9:0
0
09
:00
to 1
0:0
0
10
:00
to 1
1:0
0
11
:00
to 1
2:0
0
12
:00
to 1
3:0
0
13
:00
to 1
4:0
0
14
:00
to 1
5:0
0
15
:00
to 1
6:0
0
16
:00
to 1
7:0
0
17
:00
to 1
8:0
0
18
:00
to 1
9:0
0
19
:00
to 2
0:0
0
20
:00
to 2
1:0
0
21
:00
to 2
2:0
0
22
:00
to 2
3:0
0
23
:00
to 0
0:0
0
MW
Hours
Actual 2018 Summer Profile for Residual Demand Actual 2018 Summer Profile for RSA Contracted Demand
Actual 2018 Winter Profile for Residual Demand Actual 2018 Winter Profile for RSA Contracted Demand
The system is expected to remain tight for the MYPD4 period resulting in an increase in the cost of production
MCR, all units to maximum continuous rated output
Emergency Level 1, some units exceed MCR for short
duration
Virtual Power Station, customers paid to reduce
Request mutual assistance from other power companies
Withdraw non-firm exports
Dispatch Open Cycle Gas Turbines (diesel)
Dispatch Gas Turbines
Use emergency hydro generation hours
Interruptible Load Shedding contracts
Declare SAPP emergency
Load curtailment (NRS048-9)
Load shedding (NRS048-9)
240 MW
* 700 MW
126 MW
Varies
3 086 MW
342 MW
600 MW
Varies
2 024 MW
2 hours
* 2 hours
Fuel
dependent
Fuel
dependent
Fuel
dependent
DWS
dependent
2 hours
Rotational
The merit
order varies
depending on
magnitude and
anticipated
duration of the
emergency
275684-01-SADC-v01-11Apr11-DP-pf-CPT.ppt13
Thermal Fleet Performance
14
Current Performance of Thermal Fleet is not Sustainable
and Needs Urgent Attention
1.1 0.7 0.4 0.5 0.9 0.9 1.1 0.7 2.6 3.2 2.6 2.8 0.8 0.7 2.5 1.7 3.5 2.2 1.3 0.9 1.4
50
55
60
65
70
75
80
85
90
95
100
105
69.6
No
v 1
77.7
14.2
Ju
n 1
7
9.6 9.6
8.1
Ma
y 1
7
6.37.6
86.1
5.9
8.2
Ju
l 1
7
82.3
Au
g 1
7
77.7
16.6
9.8
11.6S
ep
17
11.5
11.1
Oct 1
715.8
75.6
11.0
12.7
70.5
13.7D
ec 1
7
13.2
9.2
7.6
Fe
b 1
8
69.7
11.8
Ju
l 1
8
Ja
n 1
8
81.2
Ma
y 1
8
70.273.9
12.7
8.7
Ma
r 1
8
16.1
81.9
Ap
r 1
8
76.1
8.8
14.4
7.4
76.2
20.9
7.2
78.0
Ap
r 1
7
14.5
Ju
n 1
8
5.4
15.0
73.6
15.4
83.6
Au
g 1
8
72.3
9.8
Se
p 1
8
14.2
12.4
16.9
10.1
Oct 1
8
79.3
66.6
11.5
15.3
No
v 1
8
63.8
20.5
De
c 1
8
69.4
%
EAF (%)
PCLF (%) OCLF (%)
UCLF (%) GLF (%)
EUF (%)
Generation Performance FY2018
Note: OCLF- In FY2018 due to units in Extended Cold Reserve. In June and August 2018 due to industrial action.
275684-01-SADC-v01-11Apr11-DP-pf-CPT.ppt15
Renewable Energy
Contribution
Contribution of renewable generation
0
500
1,000
1,500
2,000
2,500
3,000
3,500
1-D
ec-1
8
1-D
ec-1
8
2-D
ec-1
8
3-D
ec-1
8
4-D
ec-1
8
4-D
ec-1
8
5-D
ec-1
8
6-D
ec-1
8
7-D
ec-1
8
7-D
ec-1
8
8-D
ec-1
8
9-D
ec-1
8
10
-De
c-1
8
10
-De
c-1
8
11
-De
c-1
8
12
-De
c-1
8
13
-De
c-1
8
13
-De
c-1
8
14
-De
c-1
8
15
-De
c-1
8
16
-De
c-1
8
16
-De
c-1
8
17
-De
c-1
8
18
-De
c-1
8
19
-De
c-1
8
19
-De
c-1
8
20
-De
c-1
8
21
-De
c-1
8
22
-De
c-1
8
22
-De
c-1
8
23
-De
c-1
8
24
-De
c-1
8
25
-De
c-1
8
25
-De
c-1
8
26
-De
c-1
8
27
-De
c-1
8
28
-De
c-1
8
28
-De
c-1
8
29
-De
c-1
8
30
-De
c-1
8
31
-De
c-1
8
31
-De
c-1
8
Technology contribution to renewable total
CSP
Solar PV
Onshore Wind
Example of Daily Renewable Generation in Nov 2018
20000
21000
22000
23000
24000
25000
26000
27000
28000
29000
30000
31000
0
200
400
600
800
1000
1200
1400
1600
1800
2000
20
-No
v-1
8 0
0:0
0
20
-No
v-1
8 0
1:0
0
20
-No
v-1
8 0
2:0
0
20
-No
v-1
8 0
3:0
0
20
-No
v-1
8 0
4:0
0
20
-No
v-1
8 0
5:0
0
20
-No
v-1
8 0
6:0
0
20
-No
v-1
8 0
7:0
0
20
-No
v-1
8 0
8:0
0
20
-No
v-1
8 0
9:0
0
20
-No
v-1
8 1
0:0
0
20
-No
v-1
8 1
1:0
0
20
-No
v-1
8 1
2:0
0
20
-No
v-1
8 1
3:0
0
20
-No
v-1
8 1
4:0
0
20
-No
v-1
8 1
5:0
0
20
-No
v-1
8 1
6:0
0
20
-No
v-1
8 1
7:0
0
20
-No
v-1
8 1
8:0
0
20
-No
v-1
8 1
9:0
0
20
-No
v-1
8 2
0:0
0
20
-No
v-1
8 2
1:0
0
20
-No
v-1
8 2
2:0
0
20
-No
v-1
8 2
3:0
0
Re
sid
ual
De
man
d (
MW
)
Re
new
able
s (M
W)
Residual Demand Wind PV CSP
18
Wind Generation and Load Factors
during 2017 and 2018
• High load factors over evening peaks in summer can be observed, dropping during the winter months.
• A similar behaviour can be observed over all hours in a week, however to a much lesser extent.
• This behaviour is consistent, even with increase in wind generation.
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
0.0%
10.0%
20.0%
30.0%
40.0%
50.0%
60.0%
70.0%
08
/Jan
/20
17
22
/Jan
/20
17
05
/Feb
/20
17
19
/Feb
/20
17
05
/Mar
/20
17
19
/Mar
/20
17
02
/Ap
r/2
01
71
6/A
pr/
20
17
30
/Ap
r/2
01
71
4/M
ay/2
01
72
8/M
ay/2
01
71
1/J
un
/20
17
25
/Ju
n/2
01
70
9/J
ul/
20
17
23
/Ju
l/2
01
70
6/A
ug/
20
17
20
/Au
g/2
01
70
3/S
ep/2
01
71
7/S
ep/2
01
70
1/O
ct/2
01
71
5/O
ct/2
01
72
9/O
ct/2
01
71
2/N
ov/
20
17
26
/No
v/2
01
71
0/D
ec/2
01
72
4/D
ec/2
01
70
7/J
an/2
01
82
1/J
an/2
01
80
4/F
eb/2
01
81
8/F
eb/2
01
80
4/M
ar/2
01
81
8/M
ar/2
01
80
1/A
pr/
20
18
15
/Ap
r/2
01
82
9/A
pr/
20
18
13
/May
/20
18
27
/May
/20
18
10
/Ju
n/2
01
82
4/J
un
/20
18
08
/Ju
l/2
01
82
2/J
ul/
20
18
05
/Au
g/2
01
81
9/A
ug/
20
18
02
/Sep
/20
18
16
/Sep
/20
18
30
/Sep
/20
18
14
/Oct
/20
18
28
/Oct
/20
18
11
/No
v/2
01
82
5/N
ov/
20
18
09
/Dec
/20
18
23
/Dec
/20
18
Summer WinterAverage Weekly Wind Generation over Peak Average Weekly Wind Load FactorAverage Weekly Wind Load Factor over Peak Average Weekly Wind Load Factor over Night MinimumPoly. (Average Weekly Wind Load Factor) Poly. (Average Weekly Wind Load Factor over Peak)Poly. (Average Weekly Wind Load Factor over Night Minimum)
Increasing average contribution of Renewables over system peak
19
• This diagram is indicative of the increasing installed capacity but also highlights the
magnitude of the variability (particularly from wind).
• Some seasonal behaviour can be observed.
• Forecasting helps in the short term but not for planning purposes.
0
200
400
600
800
1,000
1,200
1,400
1,600
1-A
ug-
18
2-A
ug-
18
3-A
ug-
18
4-A
ug-
18
5-A
ug-
18
6-A
ug-
18
7-A
ug-
18
8-A
ug-
18
9-A
ug-
18
10
-Au
g-1
8
11
-Au
g-1
8
12
-Au
g-1
8
13
-Au
g-1
8
14
-Au
g-1
8
15
-Au
g-1
8
16
-Au
g-1
8
17
-Au
g-1
8
18
-Au
g-1
8
19
-Au
g-1
8
20
-Au
g-1
8
21
-Au
g-1
8
22
-Au
g-1
8
23
-Au
g-1
8
24
-Au
g-1
8
25
-Au
g-1
8
26
-Au
g-1
8
27
-Au
g-1
8
28
-Au
g-1
8
29
-Au
g-1
8
30
-Au
g-1
8
31
-Au
g-1
8
Technology contribution to peak
Solar PV
Onshore Wind
CSP
Hydro
Landfill gas
1200MW difference between renewable generation over evening peaks of two consecutive days
20
PV Forecast Accuracy during 2018
YTD Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
MAPE 31.8% 22.8% 28.1% 33.1% 36.9% 37.6% 31.8% 24.5% 31.4% 41.2% 36.2% 28.9% 28.1%
NMAPE 4.9% 4.7% 5.3% 5.5% 7.7% 4.6% 3.0% 5.0% 4.6% 7.6% 4.1% 3.0% 3.5%
MAE 50.4 56.5 59.7 61.0 65.0 45.3 31.0 46.7 47.1 68.9 46.3 36.1 41.8
50.4
56.559.7 61.0
65.0
45.3
31.0
46.7 47.1
68.9
46.3
36.1
41.8
0.0
10.0
20.0
30.0
40.0
50.0
60.0
70.0
80.0
0.0%
5.0%
10.0%
15.0%
20.0%
25.0%
30.0%
35.0%
40.0%
45.0%
21
Wind Forecast Accuracy during 2018
YTD Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
MAPE 18.9% 13.8% 18.3% 19.4% 22.8% 20.7% 16.5% 23.1% 17.8% 20.6% 20.8% 15.9% 16.4%
NMAPE 10.2% 7.8% 9.9% 9.8% 12.2% 10.9% 9.5% 12.3% 9.9% 12.1% 11.7% 8.4% 7.5%
MAE 99.2 90.4 106.8 88.4 101.1 91.1 92.7 119.5 85.7 109.4 119.3 97.8 88.7
99.2
90.4
106.8
88.4
101.1
91.1 92.7
119.5
85.7
109.4
119.3
97.8
88.7
0.0
20.0
40.0
60.0
80.0
100.0
120.0
140.0
0.0%
5.0%
10.0%
15.0%
20.0%
25.0%
275684-01-SADC-v01-11Apr11-DP-pf-CPT.ppt22
Current State of the System
(Performance Indicators)
23
Total Monthly PCLF, UCLF and OCLF Trend(April 2015 – Dec 2018)
Insights:
The combined
unavailability of
PCLF, UCLF
and OCLF are
reaching similar
levels
experienced
during the load
shedding period
in 2015.
At the beginning
of summer 2018
this is showing
an increasing
trend.
16
29
42
3 16
29
42
3 16
29
42
3 16
29
42
0
1,500
3,000
4,500
6,000
7,500
9,000
10,500
12,000
0%
5%
10%
15%
20%
25%
30%
35%
40%
Ap
r-2
01
5
Jun
-20
15
Au
g-2
01
5
Oct
-20
15
De
c-2
01
5
Feb
-20
16
Ap
r-2
01
6
Jun
-20
16
Au
g-2
01
6
Oct
-20
16
De
c-2
01
6
Feb
-20
17
Ap
r-2
01
7
Jun
-20
17
Au
g-2
01
7
Oct
-20
17
De
c-2
01
7
Feb
-20
18
Ap
r-2
01
8
Jun
-20
18
Au
g-2
01
8
Oct
-20
18
De
c-2
01
8
Weeks
Tota
l Mo
thly
Ou
tage
s (G
Wh
)
Months
Monthly OCLF % Monthly UCLF % Monthly PCLF % Total Mothly Outages (GWh)
24
Open Cycle Gas Turbine (OCGT) and Gas Turbine Trend (April 2015 – Dec 2018)
Insights:Extremely high
OCGT usage was
needed during the
load shedding in
2015.
In 2016/17 the
OCGTs were run
mostly to honour
contractual and
reliability
requirements.
There has been a
sudden increase
in Eskom and IPP
OCGT usage to
support demand
and reserve.0
0
0
0
0
1
1
1
1
1
1
0
50
100
150
200
250
300
350
400
450
500
550
600
650
700
Ap
r 2
01
5
Jun
20
15
Au
g 2
01
5
Oct
20
15
Dec
20
15
Feb
20
16
Ap
r 2
01
6
Jun
20
16
Au
g 2
01
6
Oct
20
16
Dec
20
16
Feb
20
17
Ap
r 2
01
7
Jun
20
17
Au
g 2
01
7
Oct
20
17
Dec
20
17
Feb
20
18
Ap
r 2
01
8
Jun
20
18
Au
g 2
01
8
Oct
20
18
Dec
20
18
GWh
Total Monthly OCGT (Eskom+IPP) and GT Energy Utilisation
Total IPP OCGT Total Eskom OCGT+GT
25
Supplemental Demand Response (VPS) Trend (April 2015 – Dec 2018)
Insights:
There has been
an increase in
the amount of
SDR scheduled
and this trend
has continued
and escalated
further in
2018/19.
Have utilised
(and payed) for
more demand
side energy in
past quarter
than at any point
in past 3 years
(including the
load-shedding
period of 2015).
26
Interruptible Load Usage (ILS) Trend(April 2015 – Dec 2018)
Insights:Following the load
shedding of 2015,
there was a
dramatic decrease
in the amount of
ILS used.
At the start of FY
2018/19, there
has been a
noticeable upturn
in the ILS used.
The amount of
incidents and
energy shed is at
it’s highest level
since August
2015, with a drop
in December 2018
due to lower
demand.
Pumped Storage Generation Hours in October and November 2018
Insights:
Since beginning
of October dam
levels at pumped
storage stations
have not been
able to recover to
full levels at
beginning of each
week.
Significant
amount of
generating hours
from these
stations have
been required to
manage demand,
especially with
flatter summer
profile.
0.0
20.0
40.0
60.0
80.0
100.0
120.0
Mo
n 0
1-O
ct-1
8 0
0:0
0Tu
e 02
-Oct
-18
00
:00
Wed
03
-Oct
-18
00
:00
Thu
04
-Oct
-18
00
:00
Fri 0
5-O
ct-1
8 0
0:0
0Sa
t 0
6-O
ct-1
8 0
0:0
0Su
n 0
7-O
ct-1
8 0
0:0
0M
on
08
-Oct
-18
00
:00
Tue
09-O
ct-1
8 0
0:0
0W
ed 1
0-O
ct-1
8 0
0:0
0Th
u 1
1-O
ct-1
8 0
0:0
0Fr
i 12
-Oct
-18
00
:00
Sat
13
-Oct
-18
00
:00
Sun
14
-Oct
-18
00
:00
Mo
n 1
5-O
ct-1
8 0
0:0
0Tu
e 16
-Oct
-18
00
:00
Wed
17
-Oct
-18
00
:00
Thu
18
-Oct
-18
00
:00
Fri 1
9-O
ct-1
8 0
0:0
0Sa
t 2
0-O
ct-1
8 0
0:0
0Su
n 2
1-O
ct-1
8 0
0:0
0M
on
22
-Oct
-18
00
:00
Tue
23-O
ct-1
8 0
0:0
0W
ed 2
4-O
ct-1
8 0
0:0
0Th
u 2
5-O
ct-1
8 0
0:0
0Fr
i 26
-Oct
-18
00
:00
Sat
27
-Oct
-18
00
:00
Sun
28
-Oct
-18
00
:00
Mo
n 2
9-O
ct-1
8 0
0:0
0Tu
e 30
-Oct
-18
00
:00
Wed
31
-Oct
-18
00
:00
Thu
01
-No
v-18
00
:00
Fri 0
2-N
ov-
18
00
:00
Sat
03
-No
v-1
8 0
0:0
0Su
n 0
4-N
ov-
18 0
0:0
0M
on
05
-No
v-1
8…
Tue
06-N
ov-
18
00
:00
Pu
mp
-Sto
rage
Un
it H
ou
rs
Drakensberg Gen Unit Hours Palmiet Gen Unit Hours
Ingula Gen Unit Hours Drakensberg Required Hours on a Monday Morning
Palmiet Required Hours on a Monday Morning Ingula Required Hours on a Monday Morning
Drakensberg Minimum Hours Palmiet Minimum Hours
Ingula Minimum Hours
Monday
28
Weekly Pumped Storage Generation Hours from 2015 to 2018 - at Friday Night
Insights:During load shedding period
in 2015, pumped storage
gen unit hours was very low
at end of week due to
significant usage.
This usage decreased during
2016 and 2017.
During winter months of
2018, pumped storage
stations was used primarily
for peaking purposes,
leading to higher dam levels.
Since September 2018,
pumped storage has been
utilised throughout summer
days, resulting in low dam
levels on a Friday night. This
together with limited
reserves for weekend
pumping has resulted in less
pump storage energy
available for following week.
0
10
20
30
40
50
60
70
80
90
100
Fri 0
3/0
4/2
01
5 2
0:0
0
Fri 1
5/0
5/2
01
5 2
0:0
0
Fri 2
6/0
6/2
01
5 2
0:0
0
Fri 0
7/0
8/2
01
5 2
0:0
0
Fri 1
8/0
9/2
01
5 2
0:0
0
Fri 3
0/1
0/2
01
5 2
0:0
0
Fri 1
1/1
2/2
01
5 2
0:0
0
Fri 2
2/0
1/2
01
6 2
0:0
0
Fri 0
4/0
3/2
01
6 2
0:0
0
Fri 1
5/0
4/2
01
6 2
0:0
0
Fri 2
7/0
5/2
01
6 2
0:0
0
Fri 0
8/0
7/2
01
6 2
0:0
0
Fri 1
9/0
8/2
01
6 2
0:0
0
Fri 3
0/0
9/2
01
6 2
0:0
0
Fri 1
1/1
1/2
01
6 2
0:0
0
Fri 2
3/1
2/2
01
6 2
0:0
0
Fri 0
3/0
2/2
01
7 2
0:0
0
Fri 1
7/0
3/2
01
7 2
0:0
0
Fri 2
8/0
4/2
01
7 2
0:0
0
Fri 0
9/0
6/2
01
7 2
0:0
0
Fri 2
1/0
7/2
01
7 2
0:0
0
Fri 0
1/0
9/2
01
7 2
0:0
0
Fri 1
3/1
0/2
01
7 2
0:0
0
Fri 2
4/1
1/2
01
7 2
0:0
0
Fri 0
5/0
1/2
01
8 2
0:0
0
Fri 1
6/0
2/2
01
8 2
0:0
0
Fri 3
0/0
3/2
01
8 2
0:0
0
Fri 1
1/0
5/2
01
8 2
0:0
0
Fri 2
2/0
6/2
01
8 2
0:0
0
Fri 0
3/0
8/2
01
8 2
0:0
0
Fri 1
4/0
9/2
01
8 2
0:0
0
Fri 2
6/1
0/2
01
8 2
0:0
0
Fri 0
7/1
2/2
01
8 2
0:0
0
Ge
n U
nit
Ho
urs
Gen Unit Hours at Pump Storage Stations at the end of the WeekDrakensberg Gen Unit Hours Palmiet Gen Unit Hours
Ingula Gen Unit Hours Poly. (Drakensberg Gen Unit Hours)Poly. (Palmiet Gen Unit Hours) Poly. (Ingula Gen Unit Hours)
29
Minimum Monthly Reserves over Evening Peaks from 2015 to 2018
Insights:
In 2015, available
reserves during
evening peaks were
extremely low. For most
days, was negative,
leading to load
reduction. These
reserves improved from
end of 2015 onwards.
In 2018, available
reserves decreased
continuously, moving
again into load
reduction space.
Presently, system is
very sensitive and any
significant event
pushes us into load
reduction, as was case
in June and July during
industrial action.
-4000
-3000
-2000
-1000
0
1000
2000
3000
4000
5000
6000
Ap
r 2
01
5
Jun
20
15
Au
g 2
01
5
Oct
20
15
De
c 2
01
5
Feb
20
16
Ap
r 2
01
6
Jun
20
16
Au
g 2
01
6
Oct
20
16
De
c 2
01
6
Feb
20
17
Ap
r 2
01
7
Jun
20
17
Au
g 2
01
7
Oct
20
17
De
c 2
01
7
Feb
20
18
Ap
r 2
01
8
Jun
20
18
Au
g 2
01
8
Oct
20
18
De
c 2
01
8
MW
Sh
ort
fall
Evening peak reserves over tightest day of the month
Poly. (Evening peak reserves over tightest day of the month)
30
Load Reduction Events during Nov and Dec 2018
Sun 18-Nov-2018
Load Shedding stage 1 from 12:15 to 19:00
Load Curtailment stage 1/2 from 12:15 to 19:00
Thu 29-Nov-2018
Load Shedding stage 1 from 12:00 to 21:00
Load Curtailment stage 1/2 from 14:00 to 21:00
Fri 30-Nov-2018
Load Shedding stage 2 from 09:00 to 20:30
Load Shedding stage 1 from 20:30 to 21:00
Load Curtailment stage 1/2 from 11:00 to 21:00
Sat 01-Dec-2018
Load Shedding stage 1 from 09:00 to 16:00
Load Shedding stage 2 from 16:00 to 20:47
Load Shedding stage 1 from 20:47 to 21:16
Sun 02-Dec-2018
Load Shedding stage 2 from 08:00 to 20:18
Load Shedding stage 1 from 20:18 to 20:48
Mon 03-Dec-2018
Load Shedding stage 2 from 09:00 to 20:30
Load Shedding stage 1 from 20:30 to 21:00
Load Curtailment stage 1/2 from 11:00 to 21:00
Tue 04-Dec-2018
Load Shedding stage 2 from 09:00 to 21:00
Load Shedding stage 1 from 21:00 to 21:30
Load Curtailment stage 1/2 from 11:00 to 21:30
Wed 05-Dec-2018
Load Shedding stage 2 from 09:00 to 21:00
Load Shedding stage 1 from 21:00 to 21:30
Load Curtailment stage 1/2 from 10:00 to 21:30
Thu 06-Dec-2018
Load Shedding stage 2 from 09:00 to 20:30
Load Shedding stage 1 from 20:30 to 21:00
Load Curtailment stage 1/2 from 10:00 to 21:00
Fri 07-Dec-2018
Load Shedding stage 1 from 09:00 to 21:00
Sat 08-Dec-2018
Load Shedding stage 1 from 09:00 to 21:38
Conclusion:The System is talking, are we listening?
The system is expected to remain tight for the duration of the MYPD4 period
We are currently running a very expensive power system and need to be addressed urgently (high utilization of emergency resources)
A tight system make it difficult to follow Scheduling and Dispatch Rules
The transmission network has also experienced unprecedented failures lately
The uncertainty of renewable energy is less of a concern at present
As more renewables (both grid-tied and behind-the-meter) are integrated, the role of essential (ancillary) services products is expected to increase and the costs thereof
Although the costs of balancing and flexibility are currently socialized, these may have to be explicit in future
31
Generation
32
Limpopo
Kwazulu-Natal
Eastern Cape
Western
Cape
Northern
Cape
North West
Free State
8
Cape Town
16
1
2
3
41
MpumalangaGauten
g12
345
67
9
10
Johannesburg
1513
11
12
9
7
8
56
2
Eskom currently operates 26 stations throughout South Africa (installed capacity on completion shown)
1 Klipheuwel Windfarm –
3MW (decommissioned)
Renewable energy
Nuclear Power Station
Koeberg – 1 940 MW
Camden – 1 510 MW
Arnot – 2 352 MW1
2
3
4
5
6
7
8
9
10
Duvha – 3 600 MW
Hendrina – 2 000 MW
Kendal – 4 116 MW
Kriel – 3 000 MW
Lethabo – 3 708 MW
Majuba – 4 110 MW
Matimba – 3 990 MW
Matla – 3 600 MW
Tutuka – 3 654 MW
Base load stations
11
12 Grootvlei – 1 200 MW
Komati – 940 MW13
1
2
4
3
Acacia - 171 MW
Port Rex -171 MW
Ankerlig - 1 338 MW
Gourikwa - 746 MW
Peak demand stations
5 Gariep - 360 MW
6 Vanderkloof - 240 MW
7 Drakensburg - 1 000 MW
8 Palmiet - 400 MW
14 Kusile - 4 788 MW
15 Medupi - 4 800 MW
New build stations
9 Ingula - 1 332 MW
2 Sere Windfarm - 100 MW
(Sustainability)
Eskom coal stations
New Build coal stations
Peaking Stations
Renewable Energy
Koeberg Nuclear
Power Station
Planning OverviewEskom applies asset management principles which include planning on how to ensure the optimal operating and maintenance of the existing fleet for the duration of its economic life
3
4
The LOPP is based on a codified preventive maintenance strategy for each power station. This prescribes what maintenance
interventions are required at what periodicity as well as the standard maintenance activities required.
Stations have specific requirements with respect to the numerous cyclical maintenance interventions required on a power plant.
However, generic rules exist:
• General Overhaul (GO): Every 10 – 12 years plant shutdown to do inspection and repair of turbine & generator.
• Mini GO: Every 5 - 6 years inspection of low pressure turbines, and statutory pressure test.
• Interim Repair (IR): 18 – 36 monthly plant is shutdown to inspect and repair the boiler components.
• Boiler Inspection (IN): Between IR’s an inspection is carried out to review condition of the boiler and scope the next outage.
Maintenance Planning is informed by what
maintenance needs to be performed, in terms of
replacement/refurbishment of components of the
assets as well as the routine outage maintenance
activities.
• Life of Plant Plan (LOPP), details these major
maintenance and refurbishment projects that are
required over the life of the plant.
• Technical Plan is a more refined extract of the
LOPP over a shorter period and the Maintenance
Plan is a listing of the outages required to
implement the LOPP and Technical Plans.
• Capacity Plan then takes a detailed view of the
first year of the Maintenance Plan to ensure that
all required outages are scheduled whilst
ensuring there is adequate capacity available to
meet demand.
• Production Planning describes how the required
energy demand is to be met on an hourly basis
whilst maintaining least-cost dispatch within
known constraints.
Capacity Outlook schedules required outages according to system constraintsThis is re-optimised typically on a weekly basis
Source: Tetris Plan V4.3 – 14 January 2019
20000
25000
30000
35000
40000
45000
50000
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar
2019 2020
Available Capacity Gas units Operating Reserves PCLF UCLF Peak Demand Installed Capacity
Summer UCLF7500 MW
Summer UCLF7500 MWWinter UCLF
6500 MW
UCLF
PCLF
Operating Reserve
Available Capacity
Gas
5000 MW
Average Planned Maintenance (PCLF)
MD03 CO
KS02 & MD02 COMD01 CO
KS03 CO
To execute this plan, OCGT usage is anticipated. The unplanned allowance is projected at 7 500 and 6 500
MW for summer and winter respectively.
Further optimisation possible from December 2019.
Production Planning plans optimal output from available power stations to reliably meet system demand at least cost, while recognising Generation, primary energy and any other technical constraints
3
6
• The key principle is for merit order dispatch within known constraints.
• Constraints may include emissions, coal shortages/surplus, water shortages and any other
technical constraints.
• Merit order dispatch - deriving the merit order from the primary energy costs (mainly coal and
diesel cost) resulting in an energy cost (R/MWh) ranking per station from the cheapest to the
most expensive.
• Coal and diesel costs are the major contributors to the variable cost of electricity
production, and on its own, results in an accurate relative merit order and optimum
dispatch.
• The Production Plan outcome provides the expected production level at each station which is
the basis of the Primary Energy (i.e. Coal, Water, Limestone, Nuclear, OCGT, Start-up Fuel,
Water Treatment, Coal Handling and Environmental Levy) cost projections.
Energy supplied by Eskom Stations is stagnant while that from IPPs grows significantly
37
25,000
215,000
0
10,000
15,000
5,000
20,000
225,000
220,000
FY2019 FY2020 FY2021FY2018 FY2022 FY2023 FY2024
+107.7%
+0.2%
International GWhEskom GWh IPPs GWh
Projected energy required to be supplied by Eskom is stagnant and actually decreases from FY2020.
Energy projected to be supplied by IPPs more than doubles in 6 years.
Production Plan both requires numerous assumptions as input and is a key input into the costs of operations
40
Costs for primary energy, maintenance etc. are dependent on the Production Plan
41
Other Gx EAF
Demand Gx new build
IPP capacity
Production Plan assumes:
• EAF of 78%.
• Best estimate for new build
• REIPP to BW 4.5
• Realistic demand growth
Result:
• Some stations not required
to produce electricity
Production Plan is dependant on a number of key
assumptions.
“Stress test” assumes:
• EAF of 75%.
• Conservative estimate for
new build
• REIPP to BW 4.5 (delayed)
• Stretch / Corporate plan
demand growth
High
uncertainty in
assumptions so
performed a
“Stress test”
Shut down units from Grootvlei,
Komati and Hendrina when
they require major Capex
injection to continue to run but
do not decommission; in
Reserve Storage as
“insurance” in case required.
Illustrative
assumptions
42
In first half of FY2018, maintenance was deferred due to funding
constraints. Capex and Opex for outages could not be released until
funding secured
1.1 0.7 0.4 0.5 0.9 0.9 1.1 0.7 2.6 3.2 2.6 2.8 0.8 0.7 2.5 1.7 3.5 2.2 1.3 0.9 1.4
50
55
60
65
70
75
80
85
90
95
100
105
69.6
No
v 1
77.7
14.2
Ju
n 1
7
9.6 9.6
8.1
Ma
y 1
7
6.37.6
86.1
5.9
8.2
Ju
l 1
7
82.3
Au
g 1
7
77.7
16.6
9.8
11.6S
ep
17
11.5
11.1
Oct 1
715.8
75.6
11.0
12.7
70.5
13.7D
ec 1
7
13.2
9.2
7.6
Fe
b 1
8
69.7
11.8
Ju
l 1
8
Ja
n 1
8
81.2
Ma
y 1
8
70.273.9
12.7
8.7
Ma
r 1
8
16.1
81.9
Ap
r 1
8
76.1
8.8
14.4
7.4
76.2
20.9
7.2
78.0
Ap
r 1
7
14.5
Ju
n 1
8
5.4
15.0
73.6
15.4
83.6
Au
g 1
8
72.3
9.8
Se
p 1
8
14.2
12.4
16.9
10.1
Oct 1
8
79.3
66.6
11.5
15.3
No
v 1
8
63.8
20.5
De
c 1
8
69.4
%
EAF (%)
PCLF (%) OCLF (%)
UCLF (%) GLF (%)
EUF (%)
Generation Performance FY2018
Note: OCLF- In FY2018 due to units in Extended Cold Reserve. In June and August 2018 due to industrial action.
Reduced maintenance up to October negatively impacted reliability and meant that
high PCLF was required for the remainder of the year.
Higher UCLF and PCLF = low EAF.
As E
AF
de
cre
ased, E
UF
in
cre
ase
d
= p
lan
t ru
nn
ing “
ha
rde
r”.
43
Revised Production PlanApplication
Current availability of Generation fleet is significantly below EAF
assumption in MYPD4 application and even less than the “stress test”
Thus a revised production plan was run - using assumptions based on latest information:
Application FY2020 FY2021 FY2022
EAF (%) 78 78 78
PCLF (%) 9.0 9.1 9.0
UCLF (%) 11.9 11.9 11.9
OCLF (%) 1.1 1.1 1.1
OCGT LF
Sales Forecast
Constrained to 1%
Moderate sales foorecast
Revised FY2020 FY2021 FY2022
EAF (%) 71.5 72.5 73.5
PCLF (%) 9.50 9.00 9.00
UCLF (%) 17.50 17.00 16.00
OCLF (%) 1.50 1.50 1.50
OCGT LF
Sales Forecast Revised, lower sales forecast
Unconstrained
New Build CO Date
Assumptions - ApplicationMedupi Kusile
1st unit Commercial Commercial
2nd unit Commercial October 2018
3rd unit Commercial August 2019
4th unit October 2018 December 2020
5th unit May 2019 August 2021
6th unit May 2020 June 2022
New Build CO Date
Assumptions - RevisedMedupi Kusile
1st unit Commercial Commercial
2nd unit Commercial May 2019
3rd unit Commercial December 2019
4th unit April 2019 December 2020
5th unit April 2019 August 2021
6th unit November 2019 June 2022
44
Revised Production Plan shows even less Energy supplied by
Eskom Stations - mostly due to the lower demand assumption
15,000
10,000
25,000
20,000
0
225,000
5,000
210,000
215,000
220,000
FY2018 FY2019 FY2024FY2020 FY2023FY2021 FY2022
-3.2%
+107.7%
Eskom GWh IPPs GWh International GWh
Projected energy required to be supplied by Eskom decreases significantly.
Energy projected from IPPs more than doubles in 6 years and will continue to assist in meeting demand.
The lower assumed availability of Eskom stations requires higher OCGT usage – over 15% in FY2020 but
dropping to about 6% and then around 1%.
Note: Production does not equal demand as it also includes losses, pumping, etc..
45
Result of constrained system, aggravated by low Generation
availability, was load shedding that started in November
The following 6 points show the reasons for unavailable capacity…
11.5% PCLF• Essential planned maintenance to address safety, statutory requirements and
performance related work to prevent even higher UCLF
• Approximately 5 000 MW not available on average
4 units on long-
term forced outage
• Lethabo u5, Duvha u4, Grootvlei u2, Kriel u2
• Total MW not available = 1 833 MW
• Duvha 4 returned during November but had multiple failures after return
Partial Load
Losses (PLLs)
(UCLF + OCLF)
• UCLF PLLs of 8.8% = 3 862MW on average
• OCLF PLLs of 1.0% = 437 MW
• More than 4 000 MW not available
12 units in
Extended
Inoperability or
Reserve Storage
• Extended Inoperability: Duvha u3; Hendrina u3 (760 MW)
• Reserve Storage: Grootvlei u4, u5, u6; Hendrina u1, u9;
Komati u1, u2, u3, u6, u8 (1389 MW)
• Total MW not available = 2 149 MW
Performance of
New Build
Medupi & Kusile
• High UCLF and PCLF partly to address design deficiencies at
Medupi (EAF = 59.2%) and Kusile (EAF = 17.1%)
• Almost 1 500 MW not available on average (note that some of this is included in
PCLF and PLLs above)
Full Load Losses• On average almost 5 200 MW not available due to full load losses
• This includes 4 units on long outages above and new build stations
Overview – Root cause of current Generation plant performance is capacity shortage, caused by:
• First contributor to capacity shortage is the delay of new capacity.
• Investment decision to build Medupi (and other stations) was needed by, not later than,
1999 to meet increasing demand by 2007.
• Investment decision (business case) only made in December 2006 => needed capacity not
available in time.
• This was exacerbated by delays in commissioning of both Medupi and Kusile.
• Second contributor was deteriorating plant performance of existing plant.
• Particularly since 2010 World Cup, necessary philosophy maintenance was delayed in
interests of avoiding load shedding
• Above led to very high load factors and limited time available for maintenance outages.
• High utilisation of deteriorated plant created the cycle of deteriorating availability.
• Despite some improvements due to efficiency and effectiveness of operations and
maintenance, cycle could only be broken with adequate funds and space in which to
perform required maintenance.
• Underlying cause of deterioration in fleet’s performance is lack of sufficient capacity, aggravated
by the onset of age and usage related equipment failures and insufficient available Capex
• By 2014, about 80% of existing fleet’s capacity was already in period where they required
major equipment replacements in order to restore plants’ economic life.
• Deferring this work was a major cause of escalation in plant breakdowns.
Energy Availability Factor (EAF) measures the availability of the generating fleet from a system point of view.
4
7
• Decline in availability (EAF) from
2013 contributed to constrained
system which required increased
OCGT usage for system security and
to minimise load shedding,
notwithstanding the improvement in
2016.
• Availability (EAF) better than or in
line with peers until rise in UCLF
from 2013
• The general trend, for both Eskom
and the VGB benchmark units is that
of reducing availability. This is
consistent with the expectation due
to ageing fleet with few or no new
units being commissioned in this
period.
• Decline in EAF primarily due to
increase in UCLF
• Nevertheless, in line with peers until
2013. Mostly due to lower PCLF.
• Improvement in 2016 due to
decrease in UCLF
Eskom coal units have been consistently run harder than the coal units of the other VGB members.
4
8
• EUF measures “how hard” the units
are being run and thus is an
indicator of stress on systems and
components.
• Since 2012, even Eskom’s lowest
quartile stations are running at a
higher utilisation than the VGB
highest quartile.
• Generation stations have been
running harder than other utilities
and in “red zone” for last 15 years.
• High utilisation means plant
systems required to operate at
limits, leading to strain, increasing
wear-and-tear and decreasing plant
reliability.
• *NERSA stated that “Eskom is
running power stations at higher
load factors than previously
expected and therefore incurs wear
and tear which will require
maintenance and repairs.
Increased plant breakdowns result
in increased use of start-up fuel to
bring plant back into production.”*Reasons For Decision of 18 June 2008 on Eskom’s ‘Revision Application –
Price Increase Application for the 2008/09 financial year’,
Load factors / high utilisation
From 2003 Eskom’s coal fleet has been operating at very high output levels to meet rising demand
Energy Utilisation Factor (EUF) has been in the “red zone” above design parameters for more than a decade
Overloading and strain on components decreases plant reliability and increases unplanned breakdowns (UCLF)
UCLF went from around 5% between FY2008 and FY2011 to about 15% in FY2015 and FY2016 before improving in FY2017 and FY2018 which was short-lived with a deterioration to over 16% so far in FY2019
Direct correlation between high EUF and increased plant breakdowns
Result is a cumulative and compounding vicious circle threatening loss of control of plant performance
2019-01-16 49
50
Higher utilisation leads to additional stress on components
and thus to increasing breakdowns but only after a delay.
(Right Hand Axis)
70%
75%
80%
85%
90%
95%
0%
5%
10%
15%
20%
25%1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
Coal Unplanned Outage Rate EUF
EUF (Right hand axis)
UCLF (Left hand axis)
High utilisation in the “Red Zone”.
Years of high utilisation
led to increasing UCLF
51
From FY2011 until FY2017 there is a correlation noted
between Maintenance spend and Generation performance
8.79.5 9.0
8.0
9.1
9.99.6
5.14.4 5.1
6.1 8.0 9.9
1.4 0.8 0.7 1.3 1.0 1.1 1.8 1.1 1.0 1.5 1.7
65
70
75
80
85
90
95
100
105
6
22
10
2
14
0
4
8
12
16
18
20
24
26
28
12.1
FY
11
FY
12
12.1
FY
13
75.1
12.6
FY
14
73.777.7
15.2
82.0F
Y1
5
13.0
14.9
10.4
FY
16
FY
17
72.271.1
10.2
FY
18
16.6
77.3
FY19
YTD
84.9
10.5
78.0
0.7
FY
08
85.3
FY
10
FY
09
85.2 84.6
9.1
%
UCLF (%)
EAF (%) OCLF (%)
PCLF (%) Capex & Maintenance Spend (Rbn real)
Generation Performance over the past 10 years
Rbn
Note: FY2019 YTD is as at end Dec’18
Increased PCLF (planned maintenance) from
FY2014 was a contributing factor to the improved
availability in FY2017 and FY2018.
Projection
Eskom operates an ageing Generation fleet, notwithstanding the new stations under construction.
5
2
More than half of the stations and more than half of the coal-fired stations will be
over 37 years old by the beginning of the MYPD 4 period.
Constrained system leading to reduced maintenance was exacerbated by age of the stations – in 2014, most of Eskom’s coal stations were past or approaching 30 year life.
53
• Average age of the stations was 34 years and all except Majuba had reached or past that period
where they required major equipment replacements in order to restore the plants’ economic life.
• Replacement/refurbishment of major components requires extensive outage time, and is expensive.
• Primarily due to financial and capacity
• constraints, particularly to keep the lights on between 2008 and 2014, much of this refurbishment
could not be executed.
• Major components not being replaced or refurbished when due increases the risk of incurring a
significant decline in technical performance.
A 9 point recovery programme has been put in place to address our key operational challenges
Fixing coal stock piles
Prepare for increased
OCGT usage
Fixing human capital
Prepare for rain
Fixing new plant
Fixing outage duration
and slips
Fixing units on long-
term forced outages
Fixing full load losses
and trips
Partial losses and
Boiler tube leaks
1
3
4
2
5
7
8
6
9
Each of the 9 points has an dedicated lead person and is backed up by detailed action plans.
To expedite programme, timeous financial and outage space as well as government support need to be met
6 months (Apr’ 2018 – Oct’ 2019)
New plants
Timelines
Full load losses & trips
Units on long term
outages
Partials and tube leaks
Outage duration & slips
Human capital
Prepare for OCGT
usage
Prepare for rain
Fix coal stock piles
Phase 2- Steady operations
Phase 1- Firefighting
Conduct Tech &Forensic review,
& develop cost time estimates
▪ Develop detailed repair plans,
measures and approvals
4 months (Dec’ 2018 – Mar’ 2019)
Build capacity , spares
optimisation and resource linking
▪ Drive Operator sourcing,
development, and excellence
Return Grootvlei unit 2
Take decision for Duvha unit 3
▪ Bring back Duvha 4, Kriel unit
2 and Lethabo unit 5
Drive delivery of outage plan to
release 1st tranche of 1567MW¹
▪ Drive delivery of outage plan to
release 2nd tranche of
1605MW Source funding for FY20,
Allocate specialist resources
▪ Monitor, track and drive
continuous Improvement
Appoint GE Gx, PSM's and Tier 1
man. Relink functions to stations
▪ Tier 1 man. development,
operator app. and training
Place contracts and build source
min stock levels
▪ Sustain stock levels
Build 3 days strategic stock and
fuel oil stock
▪ Sustain fuel oil stock levels
Establish contracts and restore
coal stockpiles to 28.2 days
Phase 3- Sustain
▪ Implement changes
Nov’ 2019 onwards
▪ Sustain performance
▪ Decision required on bringing
back HD 9, GV 5 and 6
▪ Track, monitor and report
POU on 5 big outages
▪ Sustainable development of
all critical staff
▪ Ensure Plant sustainability
and minimum stock levels
▪ Track and monitor fuel oil
stock levels
▪ Restore coal stock piles to 51
days
▪ Replicate delivery lessons
learnt with further outages
▪ Continue to restore stockpiles
Achieved
Partially achieved
In progress
1. Figures derived as per the November 2018 Outage Listing
Conclusion on Generation Performance
• High and increasing reactive maintenance, and the resultant decreasing amount of proactive
maintenance, were the direct result of the constrained system, aggravated by the reduced plant
reliability and also by capital expenditure constraints.
• Increased maintenance from 2016, with an emphasis on proactive maintenance, which includes
refurbishment. If this had not been done (see increased maintenance from 2016) and outages had
continued to be deferred in order to keep the lights on, the availability would have continued to
deteriorate even further and the improvement from late 2015 would not have been possible.
• It was thus prudent that the OCGTs were, as was expected when they were commissioned, utilised
beyond their normal peaking function, during the 2015 and 2016 financial years, “to improve the supply /
demand balance … during the period of plant shortage” as NERSA said in December 2007.
• This contributed to creating space for maintenance and limiting the far more expensive load
shedding, once all other demand and supply side options had been fully utilised.
• The improved performance from late 2015 was, however, not sustained and breakdowns increased
again from the latter half of 2017.
• Sustained improvement is only possible with a motivated workforce with the required skills and
experience as well as the funding and space to execute the ideal level of effective maintenance
Thank you