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Submitted to DoE on 25 October 2018Submitted to DoE on 25 October 2018
Formal comments on Integrated Resource Plan (IRP) 2018
CSIR Energy CentrePretoria. 25 October 2018v1.2
Jarrad WrightJWright@csir.co.za
Joanne CalitzJRCalitz@csir.co.za
Ntombifuthi NtuliPNtuli@csir.co.za
Mpeli RampokanyoMRampokanyo@csir.co.za
Pam KameraPKamera@csir.co.za
Ruan FourieRFourie@csir.co.za
2
Submitted to DoE on 25 October 2018
Word Cloud (DoE, IRP 2010, 2011)
(Design: JG. Wright, using word_cloud, https://github.com/amueller/word_cloud)
Word Cloud (DoE, IRP 2010 Update, 2013)
(Design: JG. Wright, using word_cloud, https://github.com/amueller/word_cloud)
Word Cloud (DoE, Draft IRP 2016, 2016)
(Design: JG. Wright, using word_cloud, https://github.com/amueller/word_cloud)
Word Cloud (DoE, Draft IRP 2018, 2018)
(Design: JG. Wright, using word_cloud, https://github.com/amueller/word_cloud)
3
Submitted to DoE on 25 October 2018
Word Cloud (DoE, Draft IRP 2018)
(Design: JG. Wright, using word_cloud, https://github.com/amueller/word_cloud)
4
Submitted to DoE on 25 October 2018
System services and technical considerations6
Draft IRP 2018 energy planning risks and opportunities5
Draft IRP 2018 employment impacts4
Draft IRP 2018 scenarios3
Background2
Executive Summary1
Formal comments on Draft IRP 2018
5
Submitted to DoE on 25 October 2018
System services and technical considerations6
Draft IRP 2018 energy planning risks and opportunities5
Draft IRP 2018 employment impacts4
Draft IRP 2018 scenarios3
Background2
Executive Summary1
Formal comments on Draft IRP 2018
6
Submitted to DoE on 25 October 2018
• Key Messages
• Draft IRP 2018 is a very different plan to the Draft IRP 2016 and establishes solid principles
• VRE (PV and wind) with flexibility1 confirmed as least-cost energy mix as existing coal fleet decommissions;• This energy mix also exhibits the least CO2 emissions and least water usage
• Demand growth impacts the timing of new-build capacity but energy mix remains largely unchanged
• New-build coal only post-2030 if CO2 emissions are not too restrictive and new-build VRE is constrained
• New-build nuclear only post-2030 if CO2 emission are restrictive and new-build VRE is constrained
Key Messages
1 Natural gas fired peaking and mid-merit capacity considered as a proxy for this.
NG - Natural gas; PV – Solar Photovoltaics; VRE – Variable renewable energy; EAF – Energy Availability Factor; RoCoF – Rate of Change of Frequency
7
Submitted to DoE on 25 October 2018
• To 2030 - outcomes similar across most scenarios but notable risks;• Eskom coal fleet EAF (and decommissioning schedule), completion of new-build coal, stationary storage and DSR
• No system integration issues foreseen pre-2030 but an informed and co-ordinated work program is necessary tosufficiently prepare for post-2030 relatively high VRE penetration levels
• Key Messages
• To 2030, in the Recommended Plan, expect net employment increase (as system grows) but net decrease in coal
• Natural gas risk relatively small and can be replaced by appropriate domestic flexibility sources or stationary storage
• Post 2030 - key drivers include VRE new build limits, decommissioning, demand growth, stationary storage
Key Messages
1 Natural gas fired peaking and mid-merit capacity considered as a proxy for this.
NG - Natural gas; PV – Solar Photovoltaics; VRE – Variable renewable energy; EAF – Energy Availability Factor; RoCoF – Rate of Change of Frequency
8
Submitted to DoE on 25 October 2018
At a glance
Previous CSIR contributions have notably impacted and are mentioned throughout the Draft IRP 2018
• Demand forecast: CSIR (Built Environment) provide this as an input to DoE
• Principles raised by CSIR comments on Draft IRP 2016 have been explicitly considered
• These were: New-build limits removed (IRP1), RE costs aligned with REIPPPP, least-cost Base Case established
CSIR have engaged with key stakeholders in the 60 day public consultation period
• Bilateral engagements: DoE, SALGA, EIUG, Nersa, Eskom
• Attendance at IRP workshops: EE Publishers, FFF, NIASA (requested feedback)
• Tentative: Parliament Portfolio Committee (Energy)
9
Submitted to DoE on 25 October 2018
Draft IRP 2018 scenario summaries – this is a very different plan to the Draft IRP 2016 and establishes solid principles
• Least-cost confirmed as combination of PV, wind and flexible capacity1 as coal decommissions – also exhibits lowest CO2 emissions and water usage by 2050
• Technology new-build limits (PV, wind) mean post-2030 deployment is constrained with new-build coal and gas replacing it (assuming less restrictive CO2 constraints)
• Higher NG price means less NG usage (notable capacity for system adequacy) and increased new-build coal
• More strict CO2 emissions (Carbon Budget) with RE new-build limits means less new-build coal and deployment of nuclear instead
• Higher NG price and more strict CO2 emissions (Carbon Budget) with RE new-build limits means less NG and coal, increased nuclear instead
• Higher/Lower demand forecast means same mix of new-build of PV, wind and flexibility1 just earlier/later
At a glance
1 Natural gas fired peaking and mid-merit capacity considered as a proxy for this; NG - Natural gas; PV – Solar Photovoltaics
10
Submitted to DoE on 25 October 2018
Energy mix by 2030 similar across scenarios as coal dominates, IRP1 is ≈R15bn/yr cheaper than Rec. Plan, IRP7 lowest CO2 emissions
11
4
25
14
15
42 2
IRP5
8 2
7
15
3
199 (63%)
202 (64%)IRP1
2
4
4
22
4
4413
22
9
197 (63%)IRP3
4
15
22
2
26
44
2
13199 (63%)IRP6
14
4
15
4
444
11
3
3
15192 (61%)IRP7
2
244
14
3528815
6 (2%)
206 (64%)Rec.
23
Energy Mixin 2030
Demand: 313 TWh
Coal Gas - CCGT Other Storage
Coal (New)
Nuclear
Nuclear (new)
Peaking
Gas - CCGE Hydro+PS
Wind
CSP
Solar PV
Biomass/-gas DR
Costin 2030
Total system cost1 (R-billion/yr)
360
361
367
362
373
375
Environmentin 2030
CO2 emissions (Mt/yr)
Water usage (billion-litres/yr)
217
215
213
215
207
215
199
199
198
199
191
199
2030
Sources: DoE Draft IRP 2018; Eskom on Tx, Dx costs; CSIR analysis; flaticon.com
11
Submitted to DoE on 25 October 2018
Least-cost mix confirmed as new-build solar PV, wind and flexible capacity (NG) - ≈R15-55 bn/yr cheaper than alternative scenarios
Energy Mixin 2040
Demand: 353 TWh
Costin 2040
Total system cost1 (R-billion/yr)
441
466
473
477
494
Environmentin 2040
CO2 emissions (Mt/yr)
Water usage (billion-litres/yr)
123
153
168
116
119
59
66
70
56
58
2040
104 (29%)
4
12
54
90
IRP5
21291523
5
12
107 (30%)IRP1
42902914
15
11
14
Rec.
15
33 (9%)
106 (30%)
IRP7
4
IRP3
4
47
4728929
47
15
5
51 (14%)
3015
9 (2%)
29025
29
IRP6 33 4
424399 (28%)
15
47
353
97 (27%)
PeakingCoal
Coal (New) Nuclear (new)
Nuclear
Gas - CCGE
Gas - CCGT
Hydro+PS
Wind
CSP
Solar PV
Biomass/-gas
Other Storage
DR
Sources: DoE Draft IRP 2018; Eskom on Tx, Dx costs; CSIR analysis; flaticon.com
12
Submitted to DoE on 25 October 2018
By 2050 - Least-cost mix is 70% solar PV and wind, ≈R30-60 bn/yrcheaper than alternatives, least CO2 emissions and least water usage
78
3
66 (17%)
IRP1
31
16417 31
107
63
64
IRP5
110
13
31
58 (15%)
IRP6
831
80 (20%)
IRP3
6432
106
67
5102 (26%)
64 (16%)
3
3106
22 (6%)
12
17
3
55
13 (3%)
57 (15%)
29
13
31
68 (17%)
IRP7
Rec.
47
3
76
Sources: DoE Draft IRP 2018; Eskom on Tx, Dx costs; CSIR analysis; flaticon.com
Energy Mixin 2050
Demand: 392 TWh
Nuclear (new)
Solar PVCoal Gas - CCGTNuclear
Coal (New) Gas - CCGE
Peaking
Hydro+PS Biomass/-gas
Wind
CSP
Other Storage
DR
Costin 2050
Total system cost1 (R-billion/yr)
529
560
564
580
591
Environmentin 2050
CO2 emissions (Mt/yr)
Water usage (billion-litres/yr)
82
160
178
92
90
36
54
59
36
38
2050
13
Submitted to DoE on 25 October 2018CO2 emissions trajectories for PPD Moderate never binding (only CB) while water use declines as expected as coal fleet decommissionsScenarios from Draft IRP 2018
CO2 emissions Water usage
82
160
178
92
275 275
210
0
50
100
150
200
250
300
2015 2020 2025 2030 2035 2040 2045 2050
Electricity sector CO2 emissions[Mt/yr]
36
59
0
50
100
150
200
250
300
2015 2020 2025 2030 2035 2040 2045 2050
Electricity sector Water usage[bl/yr]
IRP1
IRP6
IRP3
IRP5
IRP2
IRP7
IRP4
PPD (Moderate)
IRP1
IRP3
IRP6
IRP5
IRP7
IRP2
IRP4
Carbon Budget 2750 Mt 1800 Mt 920 Mt
PPD equiv. > 2750 Mt 2720 Mt 2325 Mt
15
Submitted to DoE on 25 October 2018
At a glance
Jobs impact of Recommended Plan – reduced role of coal whilst growth in other sectors is expected
• If the Recommended Plan is implemented, there is an employment reduction expected in coal pre-2030
• Overall jobs grow as the power system grows – in solar PV, wind and gas sectors
• This transition needs sufficient preparation – our comments attempt to assist to quantify effects
EAF – Energy Availability Factor
Sources: Eskom; CER
16
Submitted to DoE on 25 October 2018
450
200
0
500
50
100
150
250
300
350
400 10(3%)
2027
42
Jobs (net)(construction + operations)[’000]
2020
3(1%)
367(2%)
36(10%)
287(81%)
22
245
14
25
107
36
3
385
2021
7
258
3
36
297
44
2022
36
270280
2023
12
2024
393
420
33
36
2025
41
300
4
60
36
2026
42
7
5
64
49
36
233
43
14(4%)
5
62
62
202
36
217
2028
44
75
61
47
36
2029
45(12%)
4 5(1%)
62(16%)
56(14%)
36(9%)
183(47%)
2030
357 350334
353
389
428 428 426
394 386
GasSolar PV EG (PV) NuclearWind Coal
Net reduction of jobs in coal of ≈100k but net gain overall as gas grows to ≈55k jobs towards 2030, RE contributes up to ≈110k by 2030
Sources: Draft IRP 2018; CSIR Energy Centre analysisNote: Job potential includes direct, indirect and induced jobs; Nuclear is estimated based on existing experience at Koeberg (KPMG, 2017)
17
Submitted to DoE on 25 October 2018
At a glance
Key energy planning risks – Existing fleet low EAF, stationary storage, DSR, further RE learning
• Existing fleet Low EAF: Earlier new-build (2023), outcomes return to IRP1 if low demand and low coal fleetperformance
• Storage: Decreasing stationary storage costs (batteries) results in deployment pre-2030, less NG usage andincreased solar PV
• DSR: A more responsive demand-side test via electric water heating and EVs delays some capacity investmentand deploys slightly more solar PV
• Further RE learning: Increased solar PV and wind post-2030 with timing pre-2030 unchanged, no import hydro
• A risk adjusted scenario: Combining storage, DSR and further RE learning results in increased new-build wind, PV,storage and further lower NG use
•
EAF – Energy Availability Factor; DSR – Demand Side Response; Evs – Electric Vehicles
Sources: Eskom; Tesla; BNEF; CSIR
18
Submitted to DoE on 25 October 2018Draft IRP 2018 (IRP1) - Least-cost deploys considerable wind, solar PV and NG capacity to 2030 and beyond as the coal fleet decommissionsInstalled capacity and electricity supplied from 2016 to 2050 as planned in the Draft IRP 2018
Sources: Draft IRP 2018. CSIR Energy Centre analysis
Installed capacity Energy mix
80
60
40
0
100
20
120
140
160
1
52
2016
23
2030
31
38
1
78
3
0
5
17
3
Total installed capacity (net) [GW]
5 81
38
2
8
32
25
10
3
42
2020
58 1
5
12
410
25
32 11
21
1
2040
119
50
13
10
2050
148
Gas - CCGT
Nuclear
DR
Other Storage
Solar PV
Biomass/-gas
Wind
CSP
Nuclear (new)Hydro+PS
Peaking
Gas - CCGE Coal (new)
Coal
200
0
100
300
400
14
2
15
Electricity production [TWh/yr]
2
53
14 34
2030
3
203
2016
2
29
2
15
202214
42
4
2020
3
25
39
13
4
315
127
1423
8
15
107
2040
3
78
164
311
5
68
2050
245262
309
350
392
6
17
8%(20 TWh/yr)
70%(274 TWh/yr)
RE
14%(35 TWh/yr)
70%(274 TWh/yr)
CO2 free(RE + nuclear)
25%(79 TWh/yr)
30%(94 TWh/yr)
19
Submitted to DoE on 25 October 2018
40
160
0
60
20
140
180
80
100
200
120
20
20
3.45.1
13.1
17.1
7.2
5.15.1
20
30
6.3
1.5 0.5
Total installed capacity (net) [GW]
1.5
8.75.1
4.4
1.9 1.9
41.7
31.737.4
20
50
0.6
45.6
20
16
1.916.9
20
45
11.8
20
25
20.7
4.8
0.6
0.6
63.0
20
35
63.8
15.3
12.8
20
40
13.6
1.2
9.9
51.657.8 60.5
87.3
112.8
147.2
177.3
196.8
Installed capacity Energy mix
DR CSP
Hydro+PS
Other Storage
Biomass/-gas
Solar PV Peaking
Wind
Gas
Nuclear (new)
Nuclear
Coal (New)
Coal Demand: Median
First new-builds:PV (2027) 6.5 GWWind (2027) 2.1 GWOCGT (2024) 1.9 GWStorage (2027) 1.1 GW
Draft IRP 2018 IRP1 with storage, DSR and lower RE costs results in increased new-build wind, solar PV, storage and less NGInstalled capacity and electricity supplied from 2016 to 2050 for IRP1 with storage, DSR and higher RE cost reductions
Notes: NG = Natural gas
Sources: Draft IRP 2018. CSIR Energy Centre analysis
0
100
200
300
400
4
20
25
209
18
20
20
4417
38(9%)
20
16
14
31
20
30
18
202
77
20
40
20
35
17(4%)
4
14
2
122
4
103
20
45
107(27%)
160(40%)
7(2%)
20
50
Electricity production [TWh/yr]
66(17%)
4(1%)
271
298320
341361
383399
249
20
Submitted to DoE on 25 October 2018
Sources: Draft IRP 2018. CSIR Energy Centre analysis
Installed capacity Energy mix
Demand: Median
First new-builds:PV (2023) 0.4 GWWind (2023) 0.2 GWOCGT (2023) 1.9 GW
Risk-adjusted scenario with Low EAF requires earlier new-build around 2023 too and increased absolute levels of new-build by 2030Installed capacity and electricity supplied from 2016 to 2050 for Risk-adjusted scenario with low coal fleet EAF
60
180
20
0
160
40
200
80
100
140
120
0.6
9.45.1
31.7
3.4 13.75.1
0.6
1.9
Total installed capacity (net) [GW]
41.4
1.51.55.1
1.937.4
51.8
6.3
7.2
1.9
20
40
20
45
20
20
0.7
16.9
61.0
20.167.90.5
5.1
21.4
13.2
12.1
20
35
9.9
20
50
51.657.8
69.4
20
16
119.3
153.6
180.8
198.3
21.1
20
25
1.2
20
30
11.64.4
97.7
CSPDR
Solar PV
Gas
Biomass/-gas
Other Storage Wind
Hydro+PS
Peaking
Nuclear (new)
Nuclear
Coal (New)
Coal
200
0
100
300
400
4
208
20
16
20
20
20
25
36
61
17
174
20
45
18
90
15
66(17%)
33(8%)
180
20
30
20
50
20
35
17(4%)
169(42%)
77
135
2
4
320
20
40
4(1%)
104(26%)
147(2%)
Electricity production [TWh/yr]
249271
298
340361
382399
21
Submitted to DoE on 25 October 2018
At a glance
Descriptive inputs/comments – new-build limits, NG import risk and embedded generation
• Technology new-build limits: Still unjustified, constant as power system grows, misaligned with international experience today
• Coal capacity: Investigations reveal that older existing coal capacity could be decommissioned earlier, parts of under construction capacity could be replaced by alternatives and it is not economically optimal to build new coal
• Natural gas import risk: Small role in energy mix (up to 5% pre-2030, 15% by 2050) - can be mitigated by range of domestic options (as well as stationary storage if costs decline)
• Embedded generation: Planning for this is not yet explicit and will need to change (implicit as negative demand)
• Demand profile will change further as different sectors grow, use energy differently and deploy EG for self-use
22
Submitted to DoE on 25 October 2018
System services and technical considerations
• System adequacy consistent across all scenarios i.e. reserve requirements included
• System non-synchronous penetration: No barriers pre-2030. Only above 25% from 2028 and 37% by 2030 for 10% of the time but at above 80% by 2050 i.e. system integration focus becomes important post-2030
• A critical indicator (inertia): No barriers pre-2030. Post-2030 worst case mitigating solution cost is ≈1% of total system cost
• Evolution of other system services need to be investigated for post-2030 transition expected (reactive power and voltage control, system strength)
• Variable resource forecasting will become more important - SO should be equipped will relevant tools and skills
At a glance
23
Submitted to DoE on 25 October 2018Submitted to DoE on 25 October 2018
• Need to have transparency in input assumptions, model and outcomes comprehensively and consistently published
• Investigate and establish the need for annual technology new-build limits;• Remove annual new-build limits until further investigations establish the need for them
• Develop and implement an integrated program of work on long-term system integration topics i.e. stability, systemstrength, reactive power/voltage control (CSIR already initiated CIGRE WG including Eskom and international SOs)
• Better understanding the cost trajectory of all technologies for domestic application on a periodic basis
• Focussed consideration and investigation into domestic flexibility options
• Improved approaches to better understanding demand (sector shifts, load profile shape, price elasticity of demand)
• Optimise the existing coal fleet while remaining cognisant of opportunity cost of capital expenditure on older assets(retrofitting for improved reliability, efficiency and flexibility)
• Improvements for future IRPs
Going forward – Recommendations
• Inclusion of economic impacts of scenarios. At the very least – employment impacts
24
Submitted to DoE on 25 October 2018Submitted to DoE on 25 October 2018
• Investigate approaches to include geospatial component of IRP – supply/network/demand (co-optimisation)
• Integrating national and local level energy planning for improved co-ordination and leveraging of opportunities
• Sector-coupling opportunities across the full energy sector (not just electricity)
• Further understanding just transition to address labour and socio-economic impacts in the energy sector
• Formally establishing a set of links/triggers between IRP and MTSAO processes (or equivalent)• Periodic updating of the IRP should be prioritised to address dynamic planning environment
• Long-term – structural and strategic
Going forward – Recommendations
• Further investigations into impacts/opportunities of new/emerging technologies e.g. stationary storage, EVs, DSR
25
Submitted to DoE on 25 October 2018
System services and technical considerations6
Draft IRP 2018 energy planning risks and opportunities5
Draft IRP 2018 employment impacts4
Draft IRP 2018 scenarios3
Background2
Executive Summary1
Formal comments on Draft IRP 2018
26
Submitted to DoE on 25 October 2018
Planning / simulation
world
Actuals / real world
Integrated Resource Plan (IRP): Process for power generation capacity expansion in South Africa
IRP modelling framework (PLEXOS®)
LT1 techno-economic least-cost optimisation
MT/ST2 production cost testing system adequacy
(security of supply)
OutputPer scenario:• Total system costs• Capacity expansion (GW) • Energy share (TWh)• CO2 emissions• Water usage• Jobs in the electricity sector
After policy adjustment: • Final “IRP” for
promulgation• Key questions answered:
o What to build (MW)?o When to build it (timing)?
Procurement(competitive tender
e.g. REIPPPP, coal IPPPP)
Inputs• Ministerial
Determinations for new technology specific generation capacity
Inputs1) Demand Forecast2) Existing Supply Forecast:• Plants under construction• Preferred bidders• Decommissioning• Plant performance3) New Supply Options:• Technology costs
assumptions• Technology technical
characteristics4) Constraints:• CO2 limits• Security/adequacy of
supply level
Outcomes• Preferred bidders• MW allocation• Technology costs
actuals (Ø IPP tariffs)
1 LT = Long-term2 MT/ST = Medium-term/Short-term
27
Submitted to DoE on 25 October 2018Submitted to DoE on 25 October 2018
Tx network (shallow)
Distribution network
(Dx)
[bR/yr]
System services (other)
Other(metering,
billing, customer services,
overheads)
Generation (Gx)
System services
(reserves)
Tx network (deep)
Total system
cost
The IRP currently optimises for the dominant generation costs, system reserves (adequacy) and shallow grid cost components of total system cost
Optimised in PLEXOS model
• CAPEX (plant level)• FOM1
• VOM2
• Fuel• Shallow grid connection
costs
• Gx: Externalities e.g. CO2
emissions costs• Gx: Decommissioning costs• Gx: Waste management
and/or rehabilitation• Gx: Major mid-life overhaul• Tx: Deep costs• Other system services• Dx: Distribution network
costs• Other costs
1 FOM = Fixed Operations and Maintenence costs; 2 VOM = Variable Operations and Maintenence costs; 3 Typically referred to as Ancillary Services includes services to ensure frequency stability, transient stability, provide reactive power/voltage control, ensure black start capability and system operator costs.
Not optimised in PLEXOS modelling framework(Assumption consistent for all scenarios = 0.20 R/kWh)
Not considered
Partially considered previously
(quantified for system inertia)
Not considered
Not considered
Costs excluded in optimisation model:
Costs included in optimisation model:
28
Submitted to DoE on 25 October 2018
IRP process as described in the Department of Energy’s Draft IRP 2016 document: least-cost Base Case is derived from technical planning facts
Least CostBase Case
Scenario 2Scenario 1
Scenario 3
Case Cost
Base Case Base
Scenario 1 Base + Rxx bn/yr
Scenario 2 Base + Ryy bn/yr
Scenario 3 Base + Rzz bn/yr
… …
Constraint: RE limits
Constraint: e.g. forcing in of nuclear, CSP, biogas, hydro, others
Constraint: Advanced CO2
cap decline
1. Public consultationon costed scenarios
2. Policy adjustment of Base Case
3. Final IRP for approval and gazetting
PlanningFacts
Sources: Based on Draft IRP 2018
29
Submitted to DoE on 25 October 2018
Reminder: IRP 2010 planned the electricity mix until 2030Installed capacity and electricity supplied from 2010 to 2030 as planned in the IRP 2010
Installed capacity Energy mix
5%(12 TWh/yr)
14%(62 TWh/yr)
RE
50
0
100
150
125
75
25
1.8
0.0
2025
0.5
35.9
2010
0.7
9.2
0.03.4
7.3
1.5
2020
4.85.8
2030
2.8
Total installed net capacity [GW]
8.4
2.1
1.2
4.8
6.3
34.8
2.4
43.0
62.7
9.6
86.6
2.4
0.00.0
1.8
73.6
10%(25 TWh/yr)
34%(149 TWh/yr)
CO2 free
230284
261237
45
75
422
4
2412
0
100
200
300
400
500
600
4
14
Electricity supplied
[TWh]
1313
2010
10
2020
14
2025
6
12
2030
259
343
392
441
00
21
Note: Installed capacity and electricity supplied excludes pumped storage; Renewables include solar PV, CSP, wind, biomass, biogas, landfill and hydro (includes imports). Sources: DoE IRP 2010-2030; CSIR Energy Centre analysis
OtherSolar PV
Wind
CSP
Coal (new)
Hydro
Peaking
Gas
Nuclear (new)
Nuclear
Coal
30
Submitted to DoE on 25 October 2018
Draft IRP 2016 Base Case planned until 2050Installed capacity and electricity supplied from 2016 to 2050 as planned in the Draft IRP 2016 Base Case
Installed capacity Energy mix
10%(25 TWh/yr)
29%(152 TWh/yr)
RE
10%(40 TWh/yr)
57%(300 TWh/yr)
CO2 free
Note: Installed capacity and electricity supplied includes pumped storage; Renewables include solar PV, CSP, wind, biomass, biogas, landfill and hydro (includes imports). Sources: DoE Draft IRP 2016; CSIR Energy Centre analysis
150
50
125
0
100
75
25
0.7
0.33.4
15.8
0.4
16.8
12.8
4.1
1.9
7.5
36.8
1.9
49.8
2016
135.7
6.1
1.111.1
21.3
0.08.90.2
7.6
7.3
0.05.3
0.7
2050
12.41.1
2.7
30.4
14.3
0.5
2030 2040
13.8
22.0
82.5
7.6
15.0
20.4
17.210.2
108.7
Total installed net capacity [GW]
1.5 1.3
32.6
1.9
0.0
Coal
Solar PV Other storage
CSP
Wind
Other
Peaking
Gas
Hydro+PS
Nuclear (new)
Nuclear
Coal (new)
100
0
300
400
200
500
600
2
93
22
2
66
00
36
2016
5
13
5 116
15
33
0
5
2015
203
2030
5
1
1
33
15
117
2040
28
49
105
148
101
2050
434
528
45
24
3
246
200
34
350
Electricity supplied
[TWh]
72
31
Submitted to DoE on 25 October 2018
System services and technical considerations6
Draft IRP 2018 energy planning risks and opportunities5
Draft IRP 2018 employment impacts4
Draft IRP 2018 scenarios3
Background2
Executive Summary1
Formal comments on Draft IRP 2018
32
Submitted to DoE on 25 October 2018Submitted to DoE on 25 October 2018
A range of scenarios have been assessed as part of the Draft IRP 2018 with key parameter changes
33
Submitted to DoE on 25 October 2018Draft IRP 2018 (IRP1) - Least-cost deploys considerable wind, solar PV and NG capacity to 2030 and beyond as the coal fleet decommissionsInstalled capacity and electricity supplied from 2016 to 2050 as planned in the Draft IRP 2018
Sources: Draft IRP 2018. CSIR Energy Centre analysis
Installed capacity Energy mix
60
0
80
20
120
40
160
100
140
38 42
528
0 2523
21
2016
Total installed capacity (net) [GW]
3
78
11
2050
1
1
10
25
38
2
3
17
25
2040
1
3
2020
112
54
10
13
32
2030
1
10
5
31
8
3
50
58
119
148
DR
Biomass/-gas
Other Storage Wind
Solar PV
CSP
Hydro+PS
Peaking
Gas - CCGE
Nuclear (new)
Gas - CCGT
Nuclear
Coal (new)
Coal
0
100
300
200
400
4
14
Electricity production [TWh/yr]
5
2
78
2
202
34
31
8
3
4
15
203
2016
3
2
313
2
15
315
1215
7
2020
252
42
2030
1415
15
4
164
54
15
129
23
107
3
17
29
68
2050
245264
353
391
2040
8%(20 TWh/yr)
70%(274 TWh/yr)
RE
14%(35 TWh/yr)
70%(274 TWh/yr)
CO2 free(RE + nuclear)
26%(83 TWh/yr)
31%(98 TWh/yr)
34
Submitted to DoE on 25 October 2018Draft IRP 2018 (IRP3) – RE new-build limits mean post-2030 deployment of solar PV and wind is constrained with new-build coal and gas replacing itInstalled capacity and electricity supplied from 2016 to 2050 as planned in the Draft IRP 2018
Sources: Draft IRP 2018. CSIR Energy Centre analysis
Installed capacity Energy mix
20
80
40
60
0
140
100
12025
2050
12
9
2
125
14
1
2040
30
42
3
3
22
1
Total installed capacity (net) [GW]
10
712
5
1
3812
3
2016
26
2020
5
11
5
13
1
5
6
49
32
2030
18
8
1
17
8
11
17
5258
77
103
DR
Other Storage
Solar PV
Nuclear (new)Biomass/-gas
CSP
Wind
Hydro+PS
Peaking
Gas - CCGE
Gas - CCGT
Nuclear
Coal (new)
Coal
300
100
200
400
0
15
902263
47
110
2030
2
15
2016
203
Electricity production [TWh/yr]
3
4
214
2
138
4
14
2
9
8
15153
2020
4
44
15
197
4
245
14
33
10667
2040
63
3129
31
80
2050
313
353
393
22
8
8%(20 TWh/yr)
52%(203 TWh/yr)
RE
14%(35 TWh/yr)
52%(203 TWh/yr)
26%(80 TWh/yr)
30%(95 TWh/yr)
CO2 free(RE + nuclear)
35
Submitted to DoE on 25 October 2018Draft IRP 2018 (IRP5) – Market linked NG price means in less NG usage, notable capacity for system adequacy and increased new-build coalInstalled capacity and electricity supplied from 2016 to 2050 as planned in the Draft IRP 2018
Sources: Draft IRP 2018. CSIR Energy Centre analysis
Installed capacity Energy mix
140
0
60
20
100
40
80
120
832
1
2
2
5
2016
26
3
9
Total installed capacity (net) [GW]
3
5
58
18
3172
38
17
2
1
42
2020
52
1
1
1
9
25
1
13
6113
2030
8
6
2040
30
8
4
3
16
10
2050
77
104
125
20
DR
Solar PV
Gas - CCGT
Biomass/-gas
Other Storage
CSP
Wind Coal
Hydro+PS
Peaking
Gas - CCGE
Nuclear (new)
Nuclear
Coal (new)
200
400
100
0
300
4
104
2
2030
215
Electricity production [TWh/yr]
32
114
2040
15
203
2016
199
242
13
22
8153
15
2020
4
2452
44
14
154
29
3
2050
64
11
102
5
107
4
89
51
31364
264
353
391
47
15
8%(20 TWh/yr)
51%(202 TWh/yr)
RE
14%(35 TWh/yr)
51%(202 TWh/yr)
26%(81 TWh/yr)
30%(95 TWh/yr)
CO2 free(RE + nuclear)
36
Submitted to DoE on 25 October 2018Draft IRP 2018 (IRP6) – Carbon Budget limits new-build coal capacity and deploys new-build nuclear capacity insteadInstalled capacity and electricity supplied from 2016 to 2050 as planned in the Draft IRP 2018
Sources: Draft IRP 2018. CSIR Energy Centre analysis
Installed capacity Energy mix
40
60
0
100
140
20
80
120
55
1
2
4
5
2030
38
58
30
13
3
9
Total installed capacity (net) [GW]
17
1
1
2016
3
14
2
2
3
42
17
2020
32
19
1 813
93
22
1
18
1
26
85
2040
2
25
12
72
10
2050
52
77
103
125
DR
Other Storage
Peaking
Biomass/-gas
Coal
Solar PV
CSP
Wind
Hydro+PS
Gas - CCGE
Gas - CCGT
Nuclear (new)
Nuclear
Coal (new)
400
200
300
0
100 55
13
245
67
11
2030
3
4
153
15
2
2
Electricity production [TWh/yr]
2016
33
4
203
8 415
215
2020
47
2040
422
2
44
154
57
12
290
301225
15
97
106
199
47
13
2050
264
313
353
391
31
8%(20 TWh/yr)
52%(203 TWh/yr)
RE
14%(35 TWh/yr)
66%(258 TWh/yr)
26%(81 TWh/yr)
30%(96 TWh/yr)
CO2 free(RE + nuclear)
37
Submitted to DoE on 25 October 2018Draft IRP 2018 (IRP7) – Market linked NG price & Carbon Budget combines IRP 5&6 meaning less NG and coal capacity, increased nuclear new-buildInstalled capacity and electricity supplied from 2016 to 2050 as planned in the Draft IRP 2018
Sources: Draft IRP 2018. CSIR Energy Centre analysis
Installed capacity Energy mix
40
140
100
0
20
120
60
80
4
113
32
261
2
3
1
4
3
Total installed capacity (net) [GW]
25
2050
38
8
15
2016
1
42
2
5
6
3
6
2020
9
1
1
13
2
38
82
2030
18
85
2
18
17
2040
1
25
10
30
10
5258
77
104
125
DR
Solar PV
Other Storage
Biomass/-gas
Coal (new)CSP
Gas - CCGTWind
Hydro+PS
Peaking
Gas - CCGE
Nuclear (new)
Nuclear
Coal
0
100
200
400
300
2050
99
4
9
2
3
215
Electricity production [TWh/yr]
4
15
76
13
2016
23
15
42
313 47
8
2030
3
2020
2
44
2643
15
192
2
90
353
29
203
125
4317
31
14
64
2040
22
58
245264
391
4
15
106
8%(20 TWh/yr)
51%(201 TWh/yr)
RE
14%(35 TWh/yr)
70%(277 TWh/yr)
30%(95 TWh/yr)
35%(110 TWh/yr)
CO2 free(RE + nuclear)
38
Submitted to DoE on 25 October 2018Draft IRP 2018 (IRP2) – Upper Demand forecast with similar outcomes to IRP3 just with earlier first new-build and more new-build overallInstalled capacity and electricity supplied from 2016 to 2050 as planned in the Draft IRP 2018
Sources: Draft IRP 2018. CSIR Energy Centre analysis
Installed capacity Energy mix
120
40
0
20
100
140
80
60
16
14
3
1
9
6
38
2040
1
8
30
8
9
Total installed capacity (net) [GW]
3
1
1
25
2
10
53
2
52
2016
2
53
42
2020
1126
7
2
32
18
2030
8
6 18
2
17
15
1
15
10
2050
58
79
108
130
DR
Other Storage
Solar PV
Coal
Biomass/-gas
CSP
Wind
Gas - CCGE
Hydro+PS
Peaking
Gas - CCGT
Coal (new)
Nuclear (new)
Nuclear
0
100
200
400
300
15
198
911
Electricity production [TWh/yr]
3
111
2016
4
68
15
31
2040
203
3
2452
4
108
2
17
153
21
28
217
2
39
2020
4
4
438
266
814
2030 2050
46
2
19
32
48
64
103
321
378
428
91
8%(20 TWh/yr)
48%(207 TWh/yr)
RE
14%(35 TWh/yr)
48%(207 TWh/yr)
29%(94 TWh/yr)
33%(108 TWh/yr)
CO2 free(RE + nuclear)
39
Submitted to DoE on 25 October 2018Draft IRP 2018 (IRP4) – Lower Demand forecast with similar outcomes to IRP3 just with later first new-build and less new-build overallInstalled capacity and electricity supplied from 2016 to 2050 as planned in the Draft IRP 2018
Sources: Draft IRP 2018. CSIR Energy Centre analysis
Installed capacity Energy mix
0
100
20
120
80
140
60
40 17
2 5
Total installed capacity (net) [GW]
1
4
10
1
53
2
38
6
832
8
12
2016
2123
53
25
2040
8
42
2020
30
2317
1
3
2
2030
1
7
16
1
25
11
96
17
1
10
2050
5258
69
121
DR
Biomass/-gas
Gas - CCGE
Other Storage
Solar PV
CSP
Wind
Nuclear
Hydro+PS
Peaking
Gas - CCGT
Nuclear (new)
Coal (new)
Coal
0
300
100
200
400
11
4
8
2050
4
208
63
Electricity production [TWh/yr]
15
33
203
20202016
8
28
41
2
14 153
33
81
162
2
15
112
514
193
2030
4
4
29
256
15
15
33
10565
3
30
54
245
290
333
372
2040
8%(20 TWh/yr)
55%(204 TWh/yr)
RE
14%(35 TWh/yr)
55%(204 TWh/yr)
23%(66 TWh/yr)
28%(80 TWh/yr)
CO2 free(RE + nuclear)
40
Submitted to DoE on 25 October 2018Draft IRP 2018 (Recommended Plan) includes RE new-build limits and policy adjustment for new-build coal and imported hydroInstalled capacity and electricity supplied from 2016 to 2030 as planned in the Draft IRP 2018
Sources: Draft IRP 2018. CSIR Energy Centre analysis
Installed capacity Energy mix
80
20
0
60
40
100
5.1
1.5
20
20
20
18
37.6
0.6
1.9
20
29
20
16
20
17
20
19
20
21
1.6
20
24
57.8
20
22
20
25
20
23
20
26
3.4
Total installed capacity (net) [GW]
8.1
0.38.0
11.5
1.0
7.6
20
27
3.1
31.7
20
28
1.9
20
30
51.9
61.8
74.1
DR
Other Storage
Solar PV
Biomass/-gas
Gas - CCGE
Wind
CSP
Hydro+PS
Peaking
Gas - CCGT
Nuclear (new)
Nuclear
Coal (New)
Coal
0
400
100
200
300
203
20
16
292
20
17
6(3%)
20
21
217
20
26
20
20
20
22
20
23
20
24
20
25
20
29
20
27
14(7%)
231
31335(17%)
20
18
26428(14%)8(4%)
20
28
3(1%)15(7%)
20
19
Electricity production [TWh/yr]
199(97%)
20
30
245
First new-builds:Coal (2023) 1.0 GW PV (2025) 0.7 GWWind (2025) 0.2 GWCC-GE (2026) 2.3 GW
41
Submitted to DoE on 25 October 2018CO2 emissions trajectories for PPD Moderate never binding (only CB) while water use declines as expected as coal fleet decommissionsScenarios from Draft IRP 2018
CO2 emissions Water usage
82
160
178
92
275 275
210
0
50
100
150
200
250
300
2015 2020 2025 2030 2035 2040 2045 2050
Electricity sector CO2 emissions[Mt/yr]
36
59
0
50
100
150
200
250
300
2015 2020 2025 2030 2035 2040 2045 2050
Electricity sector Water usage[bl/yr]
IRP4
IRP1
IRP5
IRP6
IRP3
PPD (Moderate)
IRP7
IRP2 IRP7
IRP1
IRP3
IRP5
IRP6
IRP2
IRP4
Carbon Budget 2750 Mt 1800 Mt 920 Mt
PPD equiv. > 2750 Mt 2720 Mt 2325 Mt
42
Submitted to DoE on 25 October 2018
2015 2020 2025 2030 2035 2040 2045 20500.00
0.20
0.40
0.60
0.80
1.00
1.20
1.40
1.60
0.84
Average tariff in R/kWh (Jan-2017 Rand)
1.35
1.51
+12%
IRP1
IRP3
IRP5
IRP6
IRP7
Recommended Plan
Average tariff (without CO2 costs) across scenarios revealing how IRP1 (Least-cost) is 12% cheaper than the most expensive scenario (IRP7)
Note: Shift from 2017 to 2018 based on immediate move to cost reflectivity
Sources: Draft IRP 2018. CSIR Energy Centre analysis
43
Submitted to DoE on 25 October 2018
529
591
209
2015 2020 2025 2030 2035 2040 2045 20500
100
200
300
400
500
600
Total system cost (Jan-2017 Rand)[bR/yr]
+63(+12%)
IRP1
IRP3
IRP5
IRP7
IRP6
Recommended Plan
Total system cost increase as the power system grows (as expected) IRP1 is least-cost and ≈R60-bn/yr cheaper than IRP7 by 2050
Note: Shift from 2017 to 2018 based on immediate move to cost reflectivity
Sources: Draft IRP 2018. CSIR Energy Centre analysis
44
Submitted to DoE on 25 October 2018
Energy mix by 2030 similar across scenarios as coal still dominates while IRP1 is ≈R10bn/yr cheaper than IRP7, IRP7 lowest CO2 emissions
11
4
25
14
15
42 2
IRP5
8 2
7
15
3
199 (63%)
202 (64%)IRP1
2
4
4
22
4
4413
22
9
197 (63%)IRP3
4
15
22
2
26
44
2
13199 (63%)IRP6
14
4
15
4
444
11
3
3
15192 (61%)IRP7
2
244
14
3528815
6 (2%)
206 (64%)Rec.
23
Energy Mixin 2030
Demand: 313 TWh
Coal Gas - CCGT Other Storage
Coal (New)
Nuclear
Nuclear (new)
Peaking
Gas - CCGE Hydro+PS
Wind
CSP
Solar PV
Biomass/-gas DR
Costin 2030
Total system cost1 (R-billion/yr)
360
361
367
362
373
375
Environmentin 2030
CO2 emissions (Mt/yr)
Water usage (billion-litres/yr)
217
215
213
215
207
215
199
199
198
199
191
199
2030
Sources: DoE Draft IRP 2018; Eskom on Tx, Dx costs; CSIR analysis; flaticon.com
45
Submitted to DoE on 25 October 2018
Least-cost mix confirmed as new-build solar PV, wind and flexible capacity (NG) - ≈R15-55 bn/yr cheaper than alternative scenarios
Energy Mixin 2040
Demand: 353 TWh
Costin 2040
Total system cost1 (R-billion/yr)
441
466
473
477
494
Environmentin 2040
CO2 emissions (Mt/yr)
Water usage (billion-litres/yr)
123
153
168
116
119
59
66
70
56
58
2040
104 (29%)
4
12
54
90
IRP5
21291523
5
12
107 (30%)IRP1
42902914
15
11
14
Rec.
15
33 (9%)
106 (30%)
IRP7
4
IRP3
4
47
4728929
47
15
5
51 (14%)
3015
9 (2%)
29025
29
IRP6 33 4
424399 (28%)
15
47
353
97 (27%)
PeakingCoal
Coal (New) Nuclear (new)
Nuclear
Gas - CCGE
Gas - CCGT
Hydro+PS
Wind
CSP
Solar PV
Biomass/-gas
Other Storage
DR
Sources: DoE Draft IRP 2018; Eskom on Tx, Dx costs; CSIR analysis; flaticon.com
46
Submitted to DoE on 25 October 2018
By 2050 - Least-cost mix is 70% solar PV and wind, ≈R30-60 bn/yrcheaper than alternatives, least CO2 emissions and least water usage
78
3
66 (17%)
IRP1
31
16417 31
107
63
64
IRP5
110
13
31
58 (15%)
IRP6
831
80 (20%)
IRP3
6432
106
67
5102 (26%)
64 (16%)
3
3106
22 (6%)
12
17
3
55
13 (3%)
57 (15%)
29
13
31
68 (17%)
IRP7
Rec.
47
3
76
Sources: DoE Draft IRP 2018; Eskom on Tx, Dx costs; CSIR analysis; flaticon.com
Energy Mixin 2050
Demand: 392 TWh
Nuclear (new)
Solar PVCoal Gas - CCGTNuclear
Coal (New) Gas - CCGE
Peaking
Hydro+PS Biomass/-gas
Wind
CSP
Other Storage
DR
Costin 2050
Total system cost1 (R-billion/yr)
529
560
564
580
591
Environmentin 2050
CO2 emissions (Mt/yr)
Water usage (billion-litres/yr)
82
160
178
92
90
36
54
59
36
38
2050
47
Submitted to DoE on 25 October 2018
System services and technical considerations6
Draft IRP 2018 energy planning risks and opportunities5
Draft IRP 2018 employment impacts4
Draft IRP 2018 scenarios3
Background2
Executive Summary1
Formal comments on Draft IRP 2018
48
Submitted to DoE on 25 October 2018
CSIR have analysed selected scenarios from Draft IRP 2018 using a transparent, well established and understood tool - iJEDI
The International Jobs and Economic Development Impacts (I-JEDI) model is a freelyavailable economic tool to understand economic changes (jobs focus at this stage) forenergy technology choices
I-JEDI has been customised for application to the South African environment by the CSIRteam
CSIR utilised the developed I-JEDI tool for South Africa to assess the Recommended Plan inthe Draft IRP 2018 for a range of technologies including wind, solar, coal and natural gas(for now)… more in future
High-level approach• I-JEDI estimates economic impacts by characterising construction and operation of
energy projects in terms of expenditures and portion of these made within thecountry (localised)
• These are then used in a country-specific input-output (I-O) model to estimateemployment (amongst a range of other metrics)
An indicative analysis of jobs in nuclear is also provided (but not based on I-JEDI for now)
Analysis of other Draft IRP 2018 scenarios as well as those presented by CSIR to come1
1 Time available was not not sufficient to do this in the 60 day public consultation period.
Sources: https://www.nrel.gov/analysis/jedi/about.html
49
Submitted to DoE on 25 October 2018
Coal dominant in jobs (as expected) but declines to 2030 in Recommended Plan as gas grows, notable gap for wind and PV
Sources: Draft IRP 2018; CSIR Energy Centre analysisNote: Job potential includes direct, indirect and induced jobs; Nuclear is estimated based on existing experience at Koeberg (KPMG, 2017)
500
400
0
150
50
350
200
100
250
300
450
26
1254
39
20
23
21
20
22
3
Construction jobs[‘000]
3
9
3
13
11
3721
20
20
20
29
20
21
3
20
24
3229 16
20
27
33
56
66
52
5
16
20
25
38
54
35
20
26
384
57
35
384
2245
20
28
384
52
24
384
24
20
30
31 36 39
82
131 134 141117 117
350
100
200
0
50
250
150
500
300
400
450
77
36
278
20
20
271
1
20
21
1
4
1
4
264
20
23
1
41
14
736
265
20
24
265
21 1
233
47
36
258
20
25
73
217
5
36
7
20
26
245
41
136714
20
27
36
36
20
22
1818
36
20
28
76
Operations jobs (net)[‘000]
2
1
923
36
202
536 7
36 2
3
1132
183
20
30
326 314 314297 285
270
20
29
Solar PV EG (PV) Wind Gas Nuclear Coal
50
Submitted to DoE on 25 October 2018
50
0
350
200
100
450
150
300
250
500
400
36
7 62
Jobs (net)(construction + operations)[’000]
10(3%)3(1%)14(4%)
7
7(2%)
245
36(10%)
20212020
143
4
2522
5
300
33
280
4
36
297
10
36
2022
7
2023
4
270
2024
39
287(81%)
420
33
36
258
2025
41
36
4
60 5(1%)
42
36
426
2026
42
49
56(14%)
36
233
2027
12
7
5
62
36
217
2028
44
64 5
61
47
36
202
2029
43
62(16%)
36(9%)
183(47%)
2030
357334
385
350 353
389
428 428
394 38645
(12%)
Solar PV NuclearEG (PV) Wind Gas Coal
Net job decrease in coal of ≈100k but net gain overall as gas grows to ≈55k jobs towards 2030, RE contributes up to ≈110k by 2030
Sources: Draft IRP 2018; CSIR Energy Centre analysisNote: Job potential includes direct, indirect and induced jobs; Nuclear is estimated based on existing experience at Koeberg (KPMG, 2017)
51
Submitted to DoE on 25 October 2018
Focus on coal: Emphasising impact of construction jobs via new-build (excl. Medupi/Kusile) and net decline in operations jobs to 2030
Sources: Draft IRP 2018; CSIR Energy Centre analysisNote: Job potential includes direct, indirect and induced jobs
200
50
100
400
150
250
300
350
0
450
500
20
25
20
22
20
26
20
27
20
28
20
29
20
30
929 32
16 5
Construction jobs[‘000]
20
20
20
23
20
24
20
21
200
50
150
0
100
250
350
300
400
450
500
20
20
20
21
20
24
20
25
20
26
20
27
20
28
217
20
29
20
30
278 265245
183
265
74
77 76 75 76 74 70 67 62 58 52
107112 109 107 107 104
20
22
9488
81
87 84 83 82 83
99
76 73 685763
20
23
79
Operations jobs (net)[‘000]
80
DirectInduced Indirect
52
Submitted to DoE on 25 October 2018
450
0
250
100
50
200
150
500
300
400
350
93
94
108
Jobs (net)(construction + operations)[’000]
217
778082
57
297
86
270
62
2022
99
2021
7074
115
90
2020 2025
120 118
94
112
85
88
2023
58
84
88
104
2024
63
80 76
74
73
67
2027
68
2028
81
2029
52
20302026
287300
280258
245 233
202183
-104(-36%)
Induced DirectIndirect
Net job losses in coal overall of ≈100k, direct jobs in coal shifting from ≈80k in 2016 to ≈50k by 2030
Sources: Draft IRP 2018; CSIR Energy Centre analysisNote: Job potential includes direct, indirect and induced jobs
53
Submitted to DoE on 25 October 2018
System services and technical considerations6
Descriptive comments5.2
Scenarios5.1
Draft IRP 2018 energy planning risks and opportunities5
Draft IRP 2018 employment impacts4
Draft IRP 2018 scenarios3
Background2
Executive Summary1
Formal comments on Draft IRP 2018
54
Submitted to DoE on 25 October 2018
System services and technical considerations6
Descriptive comments5.2
Existing coal fleet performancee
Risk-adjusted scenariod
Technology learningc
Impact of Demand Side Response (DSR)b
Impact of stationary storagea
Scenarios5.1
Draft IRP 2018 energy planning risks and opportunities5
Draft IRP 2018 employment impacts4
Draft IRP 2018 scenarios3
Background2
Executive Summary1
Formal comments on Draft IRP 2018
55
Submitted to DoE on 25 October 2018
System services and technical considerations6
Descriptive comments5.2
Existing coal fleet performancee
Risk-adjusted scenariod
Technology learningc
Impact of Demand Side Response (DSR)b
Impact of stationary storagea
Scenarios5.1
Draft IRP 2018 energy planning risks and opportunities5
Draft IRP 2018 employment impacts4
Draft IRP 2018 scenarios3
Background2
Executive Summary1
Formal comments on Draft IRP 2018
56
Submitted to DoE on 25 October 2018
Impact of stationary storage (scenario)
In the Draft IRP 2018 – no cost reductions are considered for stationary storage
What if stationary storage costs start to decline?
57
Submitted to DoE on 25 October 2018
2 100
0
100
200
300
400
500
600
700
800
900
1 000
0
2 000
4 000
6 000
8 000
10 000
12 000
14 000
2010 2015 2020 2025 2030 2035 2040 2045 2050
1 400
Overnight capital cost [R/kWh](Jan-2017-Rand) [USD/kWh]
2 800
-75%
-81%
IRP2018 (Li-Ion 1hr)
IRENA - High (2017)
Nykvuist - High (2015)
This scenario (Li-Ion 1hr)
IRP2018 (Li-Ion 3hr)
BNEF (2017)
This scenario (Li-Ion 3hr)
CSIRO - High (2015)
CSIRO - Low (2015)
Nykvuist - Low (2015)
IDC - 2016
USD:ZAR = 14.00; NOTE: Battery packs are assumed to make up 60% of total utility-scale stationary storage costs (from BNEF).Sources: StatsSA for CPI; Draft IRP 2018; CSIR; BNEF; CSIRO (2015); Nykvist (2015); IDC; IRENA (2017)
Stationary storage (excl. pumped storage):200 $/kWh (2030), 150 $/kWh (2040), 100 $/kWh (2050)
58
Submitted to DoE on 25 October 2018Draft IRP 2018 IRP1 with storage cost declines means notably less NG, with storage deployed from 2027, increased solar PV and windInstalled capacity and electricity supplied from 2016 to 2030 as planned in the Draft IRP 2018
Sources: Draft IRP 2018. CSIR Energy Centre analysis
Installed capacity Energy mix
30
0
10
60
100
20
90
40
70
50
80
20
21
37.4
1.9
13.3
20
20
20
29
20
25
20
16
20
17
20
18
20
19
20
22
20
24
5.1
20
26
20
27
Total installed capacity (net) [GW]
1.5
3.2
5.1
0.6
14.3
3.4
0.5
8.6
1.5
1.9
20
23
31.7
20
30
51.6
57.860.2
81.7
20
28
GasDR
Other Storage
Biomass/-gas
Solar PV Coal (New)Peaking
CSP
Wind
Hydro+PS
Nuclear (new)
Nuclear
Coal
250
200
400
100
0
300
50
150
350
209(64%)
18(5%)
38(12%)
20
23
20
17
209
298
20
20
Electricity production [TWh/yr]
20
29
20
22
20
16
20
18
20
19
20
21
271249
20
24
20
25
20
27
20
28
26(8%)
20
26
249227
14(4%)
7(2%)
20
30
326
Demand: Median
First new-builds:PV (2027) 6.2 GWWind (2027) 1.2 GWOCGT (2024) 1.9 GWStorage (2027) 1.3 GW
59
Submitted to DoE on 25 October 2018Draft IRP 2018 IRP1 with storage cost declines means less NG, increased solar PV and wind with considerable deployment post-2030Installed capacity and electricity supplied from 2016 to 2050 for IRP1 with Demand Side Response
Notes: Assumed capacity factors for wind and solar PV differ slightly to IRP1
Sources: Draft IRP 2018. CSIR Energy Centre analysis
Demand: Median
First new-builds:PV (2027) 6.2 GWWind (2027) 1.2 GWOCGT (2024) 1.9 GWStorage (2027) 1.3 GW
0
40
160
20
60
80
100
120
180
140
200
20
16
1.5
5.1
20
35
5.1
20
25
Total installed capacity (net) [GW]
0.6
20
20
7.7
3.2
3.41.937.4
0.614.3
7.6
32.2
39.4
1.9
11.9
13.3
16.9
20
40
20
45
0.5
19.7
2.6
0.6
1.9
48.9
31.7
56.2
20
30
7.6
11.0
10.4
57.81.5
15.8
8.6
9.9
20
50
51.660.2
81.7
103.8
129.1
151.2
169.1
DR
Solar PV
Other Storage
Biomass/-gas
CSP
Wind
Hydro+PS
Peaking
Gas
Nuclear
Nuclear (new)
Coal (New)
Coal
0
400
300
200
100
375
60
209
110
20
50
Electricity production [TWh/yr]
271
20
40
38
48(12%)
33
4
26
20
16
20
20
18
33(8%)
20
35
352
7
2
323
20
25
14
111
20
45
4(1%)
298
83(21%)
209
153(39%)
326
20
30
5(1%)
71(18%)
249
404429
14
Installed capacity Energy mix
60
Submitted to DoE on 25 October 2018
40
-50
0
-40
-30
-20
10
-10
30
50
20
3
-8
11
Difference - Total installed capacity (net) [GW]
-2-2-1
20
20
20
30
20
25
20
35
3
20
16
1
-3
20
40
20
45
20
2-2
-12
20
50
-9
12
Difference in installed capacity and energy mix with storage cost declines relative to IRP1, less NG with increased solar PVInstalled capacity and electricity supplied from 2016 to 2050 for IRP 1 with storage cost declines
Sources: Draft IRP 2018. CSIR Energy Centre analysis
-50
-30
-20
50
30
-10
0
10
40
20
-40
2
20
45
20
40
-2
63
-2-6
20
-6
41
-1
-17
-1
20
16
20
25
20
30
Difference - Electricity production [TWh/yr]
20
50
20
20
-4
20
35
Installed capacity Energy mix
CSPDR
Solar PV
Nuclear (new)Other Storage
Biomass/-gas
Gas
Wind
Hydro+PS Nuclear
Peaking Coal (New)
Coal
61
Submitted to DoE on 25 October 2018CO2 emissions trajectories for PPD Moderate never binding while water use declines as expected as coal fleet decommissionsIRP 1 with storage cost declines
CO2 emissions Water usage
82
78
275 275
210
0
50
100
150
200
250
300
2015 2020 2025 2030 2035 2040 2045 2050
Electricity sector CO2 emissions[Mt/yr]
36
35
0
50
100
150
200
250
300
2015 2020 2025 2030 2035 2040 2045 2050
Electricity sector Water usage[bl/yr]
IRP1
PPD (Moderate)
IRP1 with storage cost declines
IRP1 with storage cost declines
IRP1
Carbon Budget 2750 Mt 1800 Mt 920 Mt
PPD equiv. > 2750 Mt 2720 Mt 2325 Mt
62
Submitted to DoE on 25 October 2018
2015 2020 2025 2030 2035 2040 2045 20500
100
200
400
300
500
600
437
Total system cost in bR/yr (Jan-2017 Rand)
358
441
529
521
199
299
IRP1 with storage cost declinesIRP1
Total system cost: IRP1 with storage cost declines ≈R8 bn/year less expensive by 2050 than IRP1, marginal difference before 2030
Sources: Draft IRP 2018. CSIR Energy Centre analysis.
bR
IRP1 Storage cost
declines
4 018 4 005 -12(-0.3%)
Net Present Value System Cost
(2016 - 2050)Total System Cost
Note: Average tariff projections (and resulting total system cost) consider an offset representative of Tx/Dx/Other costs to align with starting point of 0.84 ZAR/kWh (0.20 ZAR/kWh). From 2017 to 2018, immediate cost reflectivity is considered too (as in Draft IRP 2018) i.e. 0.21 ZAR/kWh offset.
63
Submitted to DoE on 25 October 2018
System services and technical considerations6
Descriptive comments5.2
Existing coal fleet performancee
Risk-adjusted scenariod
Technology learningc
Impact of Demand Side Response (DSR)b
Impact of stationary storagea
Scenarios5.1
Draft IRP 2018 energy planning risks and opportunities5
Draft IRP 2018 employment impacts4
Draft IRP 2018 scenarios3
Background2
Executive Summary1
Formal comments on Draft IRP 2018
64
Submitted to DoE on 25 October 2018
Impact of demand response - EVs, warm water heating (scenario)
What if the demand side became more flexible and responsive i.e. Demand Side Response (DSR)
Similar to previous comments in Draft IRP 2016 with some updated analysis on DSR options
Warm-water heating (geysers)
Electric vehicles
65
Submitted to DoE on 25 October 2018
Majority of EV owners charge vehicles overnight in off-peak – this will have a relatively small impact on demand profile (beyond 2030)
0.00
0.02
0.04
0.06
0.08
0.10
0.12
0 2 4 6 8 10 12 14 16 18 20 22 24
Hour
Ch
argi
ng
Frac
tio
n (
%)
U.S Department of Energy (2014)
EPRI (2007)
California Energy Commission and NREL (2018)
NOTE: EVs assumed only light passenger vehicles for now.
Sources: Calitz (2018); Bedir, N. et. Al. (2018); U.S. Department of Energy (2014); EPRI (2007)
30
2
60
40
6 128 1614 22 24
50
10
20
20
40
100 18
Ho
url
y el
ectr
icit
y d
eman
d (
GW
)Hour
+2.2(+5%)
Base Case:No EVs
3 million electric vehicles (9-mln vehicle parc)
Typical EV charging profilesImpact of typical EV charging
on RSA demand profile
66
Submitted to DoE on 25 October 2018Submitted to DoE on 25 October 2018
Electric vehicle usage for demand side flexibility i.e. Vehicle-to-Grid (V2G)
Inclusion of a demand side flexibility resource in the form of mobile storage (electric motor vehicles)demonstrates impact on the power system as adoption increases
Considered with similar functionality as that of Electric Water Heating (EWH) demand shaping - a resourcewith intra-day controllability (can be dispatched as needed on any given day) based on power systemneeds i.e. vehicle-to-grid (V2G)
Key input parameters to estimate potential demand shaping via electric motor vehicles:• Current population
• Expected population growth to 2050
• Current number of motor vehicles
• Expected motor vehicles per capita
• Adoption rate of electric vehicles to 2050
• Electric vehicle fleet capacity (MW)
• Electric vehicle energy requirement (GWh/d)
• Proportion of electric vehicle fleet connected simultaneously
67
Submitted to DoE on 25 October 2018Submitted to DoE on 25 October 2018
Electric vehicle demand shaping can provide ~96 GW/4.2 GW (demand increase/decrease) with ~40 GWh/d of dispatchable energy by 2050
Sources: CSIR estimates; StatsSA; eNaTis
Property Unit 2016-2019 2020 2031 2040 2050
Population [mln] 0 - 0 58.0 61.7 64.9 68.2
Number of motor vehicles [mln] 7 - 8.2 8.5 12.3 16.2 20.5
EVs adoption [%] 0 - 0 1.5 8.1 28.5 48.9
Number of EVs [mln] 0 - 0 0.1 1.0 4.6 10.0
EVs energy requirement [TWh/a] - 0.5 3.7 17.1 37.0
EVs energy requirement [GWh/d] - 1.3 10.1 46.8 101.4
EVs (demand increase) [MW] - - 4 600 44 300 95 800
EVs (demand decrease) [MW] - - 400 2 000 4 200
68
Submitted to DoE on 25 October 2018Submitted to DoE on 25 October 2018
Demand shaping as a demand side resource - domestic electric heaters (EWHs)
Many opportunities for demand shaping in a number of end-use sectors (domestic, commercial, industrial)
In the scenarios assessed by CSIR - the intention of including one particular demand shaping opportunity(domestic electric water heating) is to demonstrate the significant impact this can have on the power system.
Modelled as a resource with intra-day controllability (can be dispatched as needed on any given day) based onpower system needs
Key input parameters to estimate potential demand shaping via EWH:• South African population (to 2050)
• Number of households (current)
• Number of persons per household (future)
• EWHs (current)
• EWHs per household (future)
• Adoption rate of demand shaping via EWHs (future)
• Calibration for power (MW) and energy (TWh) used for electric water heating (existing)
• Movement to EWH technologies i.e. heat pumps vs electric geysers (future)
69
Submitted to DoE on 25 October 2018Submitted to DoE on 25 October 2018
Demand shaping can provide ~24 GW/3 GW (demand increase/decrease) with ~70 GWh/d of dispatchable energy by 2050
Sources: CSIR estimates; StatsSA; AMPS survey; Stastista; Eskom; Draft IRP 2016
Property Unit 2016-2019 2020 2030 2040 2050
Population [mln] 55.7 - 57.5 58.0 61.7 64.9 68.2
Number of HHs [mln] 16.9 - 18.1 18.5 22.4 26.0 27.3
Residents per HH [ppl/HH] 3.29 - 3.17 3.13 2.75 2.50 2.50
HHs with EWH [%] 28 - 33 34 50 75 100
HHs with EWH [mln] 4.7 - 5.9 6.3 11.2 19.5 27.3
Demand shaping adoption [%] - 2 25 100 100
Demand shaping [TWh/a] - 0.4 5.4 28.3 26.4
Demand shaping [GWh/d] - 1.1 14.9 77.4 72.3
Demand shaping (demand increase) [MW] - 371 4 991 25 970 24 265
Demand shaping (demand decrease) [MW] - 46 620 3 226 3 015
70
Submitted to DoE on 25 October 2018
60
0
160
20
40
180
100
80
120
200
140
13.4
1.9
20
16
1.5
20
30
29.3
0.612.8
5.1
1.9
37.4
0.5
3.410.7
20
20
4.1
94.3
51.6
37.3
20
40
31.7
4.4
16.9
20
25
0.6
20.2
1.9
20
45
Total installed capacity (net) [GW]
7.2
1.5
0.7
20
35
58.2
37.4
10.7
7.67.6
5.1 22.2
9.9
23.8
60.5
20
50
57.8
81.3
128.7
149.1
167.0
Notes: NG = Natural gas
Sources: Draft IRP 2018. CSIR Energy Centre analysis
Demand: Median
First new-builds:PV (2027) 5.2 GWWind (2027) 1.1 GWOCGT (2024) 1.9 GW
Installed capacity Energy mix
Draft IRP 2018 IRP1 with DSR impact marginal, shift in timing of import hydro, wind & PV (2030-2040)Installed capacity and electricity supplied from 2016 to 2050 for IRP1 with Demand Side Response
DR
Biomass/-gas
CSP
Other Storage
PeakingSolar PV
Wind
Hydro+PS
Coal (New)
Gas
Nuclear (new)
Nuclear
Coal
0
400
100
300
200
54
20
16
20
40
Electricity production [TWh/yr]
30
14
39
20
30
209
20
20
20
25
65(16%)
23
209
18
20
35
4
2
104
298
353
320
271
20
45
71(18%)
1014
4(1%)64(16%)
158(40%)
114
339
34(9%)3(1%)
20
50
249
360379
398
71
Submitted to DoE on 25 October 2018Difference in installed capacity and energy mix with DSR relative to IRP1 marginal, shift in timing of import hydro, wind & PV (2030-2040)Installed capacity and electricity supplied from 2016 to 2050 for IRP1 with Demand Side Response
Sources: Draft IRP 2018. CSIR Energy Centre analysis
Installed capacity Energy mix
-20
-10
20
40
10
0
30
-50
50
-30
-40
Difference - Total installed capacity (net) [GW]
20
45
20
30
20
35
4-1
-1
20
40
20
25
1 7
20
50
20
20
-1 1
20
16
Other Storage
DR
Coal (New)Solar PV
Wind
Biomass/-gas
CSP
Hydro+PS
Peaking
Gas
Nuclear (new)
Nuclear
Coal
-20
20
-30
10
0
40
-40
-10
30
50
-50
2
20
40
20
30
-3 11
-4
1
-1
20
20
20
35
Difference - Electricity production [TWh/yr]
20
16
20
45
2
20
25
1
20
50
72
Submitted to DoE on 25 October 2018CO2 emissions trajectories for PPD Moderate never binding while water use declines as expected as coal fleet decommissionsIRP 1 with Demand Side Response
CO2 emissions Water usage
82
82
275 275
210
0
50
100
150
200
250
300
2015 2020 2025 2030 2035 2040 2045 2050
Electricity sector CO2 emissions[Mt/yr]
36
36
0
50
100
150
200
250
300
2015 2020 2025 2030 2035 2040 2045 2050
Electricity sector Water usage[bl/yr]
IRP1
IRP1 with DSR
PPD (Moderate)
IRP1
IRP1 with DSR
Carbon Budget 2750 Mt 1800 Mt 920 Mt
PPD equiv. > 2750 Mt 2720 Mt 2325 Mt
73
Submitted to DoE on 25 October 2018
2015 2020 2025 2030 2035 2040 2045 2050
400
0
100
200
300
500
600
Total system cost in bR/yr (Jan-2017 Rand)
299
360
441
440
529
199
IRP1 IRP1 with DSR
Sources: Draft IRP 2018. CSIR Energy Centre analysis. Eskom on Tx, Dx costs
IRP1
bR
4 018
DSR
4 015 -2(0.1%)
Net Present Value System Cost
(2016 - 2050)Total System Cost
Total system cost: IRP1 with DSR marginal difference in total system cost relative to IRP1
Note: Average tariff projections (and resulting total system cost) consider an offset representative of Tx/Dx/Other costs to align with starting point of 0.84 ZAR/kWh (0.20 ZAR/kWh). From 2017 to 2018, immediate cost reflectivity is considered too (as in Draft IRP 2018) i.e. 0.21 ZAR/kWh offset.
74
Submitted to DoE on 25 October 2018Generally – additional EV demand met by least-cost mix of wind, solar PV and gas whilst V2G shifts this mix more towards solar PV and less gasImpact on least-cost capacity mix
EVs as a demand shaping resource(V2G i.e. implicit in demand)
• Increase in proportion of new solar PV vs. wind
• Less gas capacity i.e. lower gas energy share
• Relative reduction in total system cost
EVs typical configuration (G2V i.e. additional demand)
• For 1-mln EVs, increase of ≈3 TWh/yr
• For 1-mln EVs, increase ≈1 GW peak demand
• New build capacity to meet charging demand is
mostly wind, solar PV and gas
• Most charging demand met by wind and gas
2030
G2V - Grid to vehicle V2G - Vehicle to grid
75
Submitted to DoE on 25 October 2018
System services and technical considerations6
Descriptive comments5.2
Existing coal fleet performancee
Risk-adjusted scenariod
Technology learningc
Impact of Demand Side Response (DSR)b
Impact of stationary storagea
Scenarios5.1
Draft IRP 2018 energy planning risks and opportunities5
Draft IRP 2018 employment impacts4
Draft IRP 2018 scenarios3
Background2
Executive Summary1
Formal comments on Draft IRP 2018
76
Submitted to DoE on 25 October 2018
3.85
2.29
1.23
0.65
0.220.22
1.060.89
0.72
0.79
0.54
2010 2015 2020 2025 2030 2035 2040 2045 2050
2.00
4.00
0.00
1.00
3.00
0.39
Equivalent tariff,Jan 2017, [ZAR/kWh]
0.96
1.29-40%
-66%
Actuals: REIPPPP (BW1-4Exp)
Assumptions: IRP 2016 (Upper)
Assumptions: IRP 2016 (Lower)
Assumption for further RE cost reductions
Assumptions: IRP 2018 (Upper)
Assumptions: IRP 2018 (Lower)
BW1 BW 4 (Expedited)Notes: REIPPPP = Renewable Energy Independant Power Producer Programme; BW = Bid Window; bid submissions for the different BWs: BW1 = Nov 2011; BW2 = Mar 2012; BW 3 = Aug 2013; BW 4 = Aug 2014; BW 4 (Expedited) = Nov 2015Sources: StatsSA for CPI; IRP 2010; South African Department of Energy (DoE); DoE IPP Office; CSIR analysis . Learning rate - Bloomberg New Energy Outlook 2017
Solar PV learning assumptions in Draft IRP 2018Actual solar PV tariffs and forecasted tariff trajectory
77
Submitted to DoE on 25 October 2018
1.60
1.25
0.92
0.73
0.65
0.35
1.16
0.78
0.81
0.60
2010 2015 2020 2025 2030 2035 2040 2045 20500.00
0.80
0.40
1.20
1.60
2.00
Equivalent tariff,Jan 2017, [ZAR/kWh]
0.87
0.47
0.35
1.04
-28% -47%
Assumption for further RE reductions
Actuals: REIPPPP (BW1-4Exp)
Assumptions: IRP 2016 (Lower)
Assumptions: IRP 2016 (Upper)
Assumptions: IRP 2018 (Upper)
Assumptions: IRP 2018 (Lower)
Notes: REIPPPP = Renewable Energy Independant Power Producer Programme; BW = Bid Window; bid submissions for the different BWs: BW1 = Nov 2011; BW2 = Mar 2012; BW 3 = Aug 2013; BW 4 = Aug 2014; BW 4 (Expedited) = Nov 2015Sources: StatsSA for CPI; IRP 2010; South African Department of Energy (DoE); DoE IPP Office; CSIR analysis . Learning rate - Bloomberg New Energy Outlook 2017
BW1 BW 4 (Expedited)
Wind cost learning assumptions in Draft IRP 2018Actual wind tariffs and forecasted tariff trajectory
78
Submitted to DoE on 25 October 2018
2.652.65
1.75
1.36
3.28
2.12
2.89
2.49
1.14
2010 2015 2020 2025 2030 2035 2040 2045 20500.00
1.00
2.00
3.00
4.00
3.30
Equivalent tariff,Jan 2017, [ZAR/kWh]
3.74
3.50
3.07
1.32
1.75
1.36
-36%
Assumptions: IRP2010 - high
Assumptions: IRP2010 - low
Assumptions: IRP2016 - high
Assumptions: IRP2016 - low
Assumptions for further RE reductions
Actuals: REIPPPP (BW1-4Exp)
Assumptions: IRP2018 - high
Assumptions: IRP2018 - low
Notes: REIPPPP = Renewable Energy Independant Power Producer Programme; BW = Bid Window; bid submissions for the different BWs: BW1 = Nov 2011; BW2 = Mar 2012; BW 3 = Aug 2013; BW 4 = Aug 2014; BW 4 (Expedited) = Nov 2015; For CSP bid window 3, 3.5 and 4 Exp, weighted average tariff of base and peak tariff calculated on the assumption of 64%/36% base/peak tariff utilisation ratio; Sources: StatsSA for CPI; IRP 2010; South African Department of Energy (DoE); DoE IPP Office; CSIR analysis
BW1 BW 4 (Expedited)
Input assumptions for CSP from Draft IRP 2018 and further cost declinesToday’s latest tariff as starting point, same cost decline as per IRP 2010
79
Submitted to DoE on 25 October 2018
20
60
120
0
160
80
200
40
180
100
140
20
45
27.6
20
16
1.5
20
25
5.13.4 2.6
31.7
1.9
107.2
37.4
60.2
20
20
12.05.1
0.613.9
15.8
Total installed capacity (net) [GW]
20
30
20
35
20
40
49.2
20
50
69.1
7.6
20.2
1.5
9.9
51.657.8
84.0
142.8
164.8
184.2
Sources: Draft IRP 2018. CSIR Energy Centre analysis
Demand: Median
First new-builds:PV (2027) 5.9 GWWind (2027) 2.8 GWOCGT (2024) 1.9 GW
Installed capacity Energy mix
Draft IRP 2018 IRP1 with further RE cost reductions, increased solar PV and wind from 2030 onwards, timing unchanged, no import hydroInstalled capacity and electricity supplied from 2016 to 2050 for IRP1 with higher RE cost reductions
Biomass/-gas
Peaking
DR CSP
Coal (New)
Gas
Other Storage
Solar PV
Wind
Hydro+PS
Nuclear (new)
Nuclear
Coal
0
100
200
400
300
20
50
209
20
16
20
20
20
25
25
46271
66(17%)
Electricity production [TWh/yr]
4
128614
18
204
20
30
20
35
14
66321
2
103
249
185
22
20
40
298
4(1%)
84(21%)
172(43%)
20
45
17(4%)5(1%)51(13%)
342361
381399
80
Submitted to DoE on 25 October 2018Difference in installed capacity and energy mix with higher RE cost reductions relative to IRP1, higher RE & peaking gas, less mid-merit gasInstalled capacity and electricity supplied from 2016 to 2050 for IRP1 with higher RE cost reductions
Sources: Draft IRP 2018. CSIR Energy Centre analysis
Installed capacity Energy mix
-30
-40
-10
-50
30
-20
40
0
10
50
20
-1 -3
11
20
16
-3-2
Difference - Total installed capacity (net) [GW]
20
30
20
20
20
25
21 510
2
20
40
12
20
35
-4
20
50
20
45
6
Solar PV
Biomass/-gas
Other Storage Nuclear
Wind
DR Hydro+PS
CSP Peaking
Gas
Nuclear (new)
Coal (New)
Coal
20
10
50
-50
-30
40
-40
30
-20
-10
0
20
25
213
22
02
0
-2
-13
-4
20
30
20
35
20
50
Difference - Electricity production [TWh/yr]
-16
-7-1
-10
3
20
40
1221
-4
12
-17
20
16
2
20
45
81
Submitted to DoE on 25 October 2018CO2 emissions trajectories for PPD Moderate never binding while water use declines as expected as coal fleet decommissionsIRP 1 with higher RE cost reductions
CO2 emissions Water usage
82
76
275 275
210
0
50
100
150
200
250
300
2015 2020 2025 2030 2035 2040 2045 2050
Electricity sector CO2 emissions[Mt/yr]
36
33
0
50
100
150
200
250
300
2015 2020 2025 2030 2035 2040 2045 2050
Electricity sector Water usage[bl/yr]
PPD (Moderate)
IRP1
IRP1 with further RE cost reductions
IRP1 with further RE cost reductions
IRP1
Carbon Budget 2750 Mt 1800 Mt 920 Mt
PPD equiv. > 2750 Mt 2720 Mt 2325 Mt
82
Submitted to DoE on 25 October 2018
2015 2020 2025 2030 2035 2040 2045 2050
300
0
100
200
400
500
600
356
Total system cost in bR/yr (Jan-2017 Rand)
199
441
418
529
487360
299
IRP1 IRP1 with further RE cost reductions
Sources: Draft IRP 2018. CSIR Energy Centre analysis. Eskom on Tx, Dx costs
IRP1 RE cost reductions
bR
4 018 3 951 -67(-2%)
Net Present Value System Cost
(2016 - 2050)Total System Cost
Total system cost: IRP1 with higher RE cost reductions would result in lower system cost
Note: Average tariff projections (and resulting total system cost) consider an offset representative of Tx/Dx/Other costs to align with starting point of 0.84 ZAR/kWh (0.20 ZAR/kWh). From 2017 to 2018, immediate cost reflectivity is considered too (as in Draft IRP 2018) i.e. 0.21 ZAR/kWh offset.
83
Submitted to DoE on 25 October 2018
System services and technical considerations6
Descriptive comments5.2
Existing coal fleet performancee
Risk-adjusted scenariod
Technology learningc
Impact of Demand Side Response (DSR)b
Impact of stationary storagea
Scenarios5.1
Draft IRP 2018 energy planning risks and opportunities5
Draft IRP 2018 employment impacts4
Draft IRP 2018 scenarios3
Background2
Executive Summary1
Formal comments on Draft IRP 2018
84
Submitted to DoE on 25 October 2018
40
160
0
60
20
140
180
80
100
200
120
20
20
3.45.1
13.1
17.1
7.2
5.15.1
20
30
6.3
1.5 0.5
Total installed capacity (net) [GW]
1.5
8.75.1
4.4
1.9 1.9
41.7
31.737.4
20
50
0.6
45.6
20
16
1.916.9
20
45
11.8
20
25
20.7
4.8
0.6
0.6
63.0
20
35
63.8
15.3
12.8
20
40
13.6
1.2
9.9
51.657.8 60.5
87.3
112.8
147.2
177.3
196.8
Installed capacity Energy mix
DR CSP
Hydro+PS
Other Storage
Biomass/-gas
Solar PV Peaking
Wind
Gas
Nuclear (new)
Nuclear
Coal (New)
Coal Demand: Median
First new-builds:PV (2027) 6.5 GWWind (2027) 2.1 GWOCGT (2024) 1.9 GWStorage (2027) 1.1 GW
Draft IRP 2018 IRP1 with storage, DSR and lower RE costs results in increased new-build wind, solar PV, storage and less NGInstalled capacity and electricity supplied from 2016 to 2050 for IRP1 with storage, DSR and higher RE cost reductions
Notes: NG = Natural gas
Sources: Draft IRP 2018. CSIR Energy Centre analysis
0
100
200
300
400
4
20
25
209
18
20
20
4417
38(9%)
20
16
14
31
20
30
18
202
77
20
40
20
35
17(4%)
4
14
2
122
4
103
20
45
107(27%)
160(40%)
7(2%)
20
50
Electricity production [TWh/yr]
66(17%)
4(1%)
271
298320
341361
383399
249
85
Submitted to DoE on 25 October 2018
20
60
0
-20
-40
-60
40
20
16
-11
20
30
-4
20
25
20
45
20
40
9
20
20
1
-5 -17-4
Difference - Electricity production [TWh/yr]
20
35
23
4
15
-10
44
1
-17
-27
20
50
0
-60
20
-40
-20
60
40
-8
1
-10
21
7
20
50
20
45
5
Difference - Total installed capacity (net) [GW]
20
16
20
35
4
12
-3
20
25
20
40
5
7
13
-2
20
20
5
20
30
-3
26
-9-4
Difference in installed capacity and energy mix Risk-adjusted scenario relative to IRP1, higher wind, PV & storage, less NGInstalled capacity and electricity supplied from 2016 to 2050 for IRP1 with storage, DSR and higher RE cost reductions
Sources: Draft IRP 2018. CSIR Energy Centre analysis
Installed capacity Energy mix
DR
Other Storage
Solar PV
Biomass/-gas
CoalCSP
Coal (New)
Wind
Hydro+PS
Peaking
Gas
Nuclear (new)
Nuclear
86
Submitted to DoE on 25 October 2018CO2 emissions trajectories for PPD Moderate never binding while water use declines as expected as coal fleet decommissionsIRP 1 with storage, DSR and higher RE cost reductions
CO2 emissions Water usage
82
72
275 275
210
0
50
100
150
200
250
300
2015 2020 2025 2030 2035 2040 2045 2050
Electricity sector CO2 emissions[Mt/yr]
36
320
50
100
150
200
250
300
2015 2020 2025 2030 2035 2040 2045 2050
Electricity sector Water usage[bl/yr]
IRP1
IRP1 Risk-adjusted scenario
PPD (Moderate)
IRP1
IRP1 Risk-adjusted scenario
Carbon Budget 2750 Mt 1800 Mt 920 Mt
PPD equiv. > 2750 Mt 2720 Mt 2325 Mt
87
Submitted to DoE on 25 October 2018
2015 2020 2025 2030 2035 2040 2045 2050
400
600
200
0
100
300
500 441
Total system cost in bR/yr (Jan-2017 Rand)
360
354
413
529
477
199
299
IRP1 Risk-Adjusted
Sources: Draft IRP 2018. CSIR Energy Centre analysis. Eskom on Tx, Dx costs
Risk-Adjusted
bR
IRP1
4 018 3 937 -81(-2%)
Net Present Value System Cost
(2016 - 2050)Total System Cost
Total system cost: Risk-adjusted scenario results in lower system cost than IRP1
Note: Average tariff projections (and resulting total system cost) consider an offset representative of Tx/Dx/Other costs to align with starting point of 0.84 ZAR/kWh (0.20 ZAR/kWh). From 2017 to 2018, immediate cost reflectivity is considered too (as in Draft IRP 2018) i.e. 0.21 ZAR/kWh offset.
88
Submitted to DoE on 25 October 2018
Demand and Supply in GW
30
10
0
50
20
40
60
Draft IRP 2018 IRP1: 2030
Monday Tuesday Wednesday Thursday Friday Saturday Sunday
Sources: CSIR analysis
Exemplary Week under Draft IRP 2018 IRP1
Curtailed solar PV and wind
CSPOther Storage
DR
GasBiomass/-gas
Solar PV
Wind
Hydro+PS
Peaking
Coal
NuclearElectricity demand
89
Submitted to DoE on 25 October 2018
Demand and Supply in GW
60
0
50
30
10
20
40
Risk-Adjusted Scenario: 2030
Monday Tuesday Wednesday Thursday Friday Saturday Sunday
Sources: CSIR analysis
Exemplary Week under Risk-Adjusted Scenario
Curtailed solar PV and wind
DR
Wind
Other Storage
Solar PV
Biomass/-gas
CSP Peaking
Hydro+PS
Gas
Coal
NuclearElectricity demand
90
Submitted to DoE on 25 October 2018
Demand and Supply in GW
10
50
0
20
30
40
70
60
80
Draft IRP 2018 IRP1: 2040
Monday Tuesday Wednesday Thursday Friday Saturday Sunday
Sources: CSIR analysis
Exemplary Week under Draft IRP 2018 IRP1
Curtailed solar PV and wind
NuclearPeaking
DR
Other Storage
Biomass/-gas
Solar PV
CSP
Wind
Hydro+PS
Gas
Coal Electricity demand
91
Submitted to DoE on 25 October 2018
Demand and Supply in GW
70
0
40
10
20
30
50
60
80
Risk-Adjusted: 2040
Monday Tuesday Wednesday Thursday Friday Saturday Sunday
Sources: CSIR analysis
Exemplary Week under Risk-Adjusted Scenario
Curtailed solar PV and wind Gas
DR Solar PV
Biomass/-gas
Other Storage
Wind
CSP
Hydro+PS
Peaking
Coal
NuclearElectricity demand
92
Submitted to DoE on 25 October 2018
Demand and Supply in GW
30
70
0
50
10
20
40
60
80
90
Draft IRP 2018 IRP1: 2050
Monday Tuesday Wednesday Thursday Friday Saturday Sunday
Sources: CSIR analysis
Exemplary Week under Draft IRP 2018 IRP1
Curtailed solar PV and wind
Solar PVDR
Biomass/-gas
Other Storage CSP
Wind
Hydro+PS
Peaking
Coal
Gas
NuclearElectricity demand
93
Submitted to DoE on 25 October 2018
Demand and Supply in GW
50
0
60
10
20
30
70
40
80
90
Risk-Adjusted: 2050
Monday Tuesday Wednesday Thursday Friday Saturday Sunday
Sources: CSIR analysis
Exemplary Week under Risk-Adjusted Scenario
Curtailed solar PV and wind
CSP
Biomass/-gas
DR
Other Storage
Solar PV
Wind
Hydro+PS
NuclearPeaking
Gas
Coal Electricity demand
94
Submitted to DoE on 25 October 2018
System services and technical considerations6
Descriptive comments5.2
Risk-adjusted with low coal fleet performancee.b
IRP1 with low coal fleet performancee.a
Existing coal fleet performancee
Risk-adjusted scenariod
Technology learningc
Impact of Demand Side Response (DSR)b
Impact of stationary storagea
Scenarios5.1
Draft IRP 2018 energy planning risks and opportunities5
Draft IRP 2018 employment impacts4
Draft IRP 2018 scenarios3
Background2
Executive Summary1
Formal comments on Draft IRP 2018
95
Submitted to DoE on 25 October 2018
System services and technical considerations6
Descriptive comments5.2
Risk-adjusted with low coal fleet performancee.b
IRP1 with low coal fleet performancee.a
Existing coal fleet performancee
Risk-adjusted scenariod
Technology learningc
Impact of Demand Side Response (DSR)b
Impact of stationary storagea
Scenarios5.1
Draft IRP 2018 energy planning risks and opportunities5
Draft IRP 2018 employment impacts4
Draft IRP 2018 scenarios3
Background2
Executive Summary1
Formal comments on Draft IRP 2018
96
Submitted to DoE on 25 October 2018
Eskom existing fleet performance – EAF (scenario)
If the existing coal fleet does not recover to the expected “Moderate“ EAF used in the Draft IRP 2018
“Low“ EAF of existing coal fleet is considered to test
2016 2018 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040 2042 2044 2046 2048 2050
84
76
78
82
80
88
0
70
72
74
86
90
74
Energy Availability Factor (EAF)[%]
80
83
72
8180
83
75
80
82
84
80
ModerateLow High
97
Submitted to DoE on 25 October 2018
140
0
80
200
120
100
20
40
60
180
160
1.5
0.6
5.1
12.1
16.6
20
40
20
20
3.4
1.91.937.4
20
16
20
25
0.6
18.30.5
20
35
11.1
31.7
1.9
7.6
20
30
39.1
18.5
20
45
5.1
16.9
30.5
7.6
32.7
1.5
62.5
6.324.4
Total installed capacity (net) [GW]
20.9
0.6
9.9
20
50
51.657.8
68.3
92.0101.7
127.1
144.1
158.6
Sources: Draft IRP 2018. CSIR Energy Centre analysis
Installed capacity Energy mix
Peaking
DR
Biomass/-gas
Other Storage Wind
Solar PV
CSP
Hydro+PS
Gas Coal
Nuclear (new)
Nuclear
Coal (New)
Demand: Median
First new-builds:PV (2023) 0.2 GWWind (2026) 3.6 GWOCGT (2023) 2.0 GW
Draft IRP 2018 IRP1 with Low EAF requires earlier new-build around 2023 and increased absolute levels of new-build by 2030Installed capacity and electricity supplied from 2016 to 2050 for IRP1 with low coal fleet EAF
0
100
300
200
400
102
57
20
40
20
45
18
59(15%)
170(43%)
4
13
320299
Electricity production [TWh/yr]
208
20
20
20
16
20
25
72(18%)
109
3
186
20
30
20
35
2
48
341
35
35
15
33
4(1%)56(14%)
20
50
34(8%)4(1%)
271
15
249
360380
398
98
Submitted to DoE on 25 October 2018Difference in capacity and energy mix with low EAF relative to IRP1, increased level of new-build, built earlier to cater for lower coal supplyInstalled capacity and electricity supplied from 2016 to 2050 for IRP1 with low coal fleet EAF
Sources: Draft IRP 2018. CSIR Energy Centre analysis
Installed capacity Energy mix
50
-50
10
20
-30
30
-40
40
-20
-10
0652
11
20
40
Difference - Electricity production [TWh/yr]
20
35
20
16
20
20
20
25
5
-11
20
30
-21
-7
10
20
50
-5
20
45
-40
-50
10
-30
20
-20
-10
0
50
30
40
20
20
6
20
35
-3
Difference - Total installed capacity (net) [GW]
3
20
16
20
25
20
50
20
30
-4
20
45
22
20
40
14
-3
1
DR
Coal (New)
Other Storage
Biomass/-gas
Solar PV
CSP
Wind
Hydro+PS
Peaking
Gas
Nuclear (new)
Nuclear
Coal
99
Submitted to DoE on 25 October 2018CO2 emissions trajectories for PPD Moderate never binding while water use declines as expected as coal fleet decommissionsIRP 1 with low coal fleet EAF
CO2 emissions Water usage
82
82
275 275
210
0
50
100
150
200
250
300
2015 2020 2025 2030 2035 2040 2045 2050
Electricity sector CO2 emissions[Mt/yr]
36
36
0
50
100
150
200
250
300
2015 2020 2025 2030 2035 2040 2045 2050
Electricity sector Water usage[bl/yr]
IRP1
IRP1 with low EAF
PPD (Moderate)
IRP1
IRP1 with low EAF
Carbon Budget 2750 Mt 1800 Mt 920 Mt
PPD equiv. > 2750 Mt 2720 Mt 2325 Mt
100
Submitted to DoE on 25 October 2018
2015 2020 2025 2030 2035 2040 2045 2050
300
0
100
200
400
500
600
441
445
Total system cost in bR/yr (Jan-2017 Rand)
360
371
529
199
299
IRP1 IRP1 Low EAF
Sources: Draft IRP 2018. CSIR Energy Centre analysis. Eskom on Tx, Dx costs
bR
IRP1 IRP1 Low EAF
4 018 4 067 +49(+1.2%)
Net Present Value System Cost
(2016 - 2050)Total System Cost
Total system cost: IRP1 with low EAF higher system cost than IRP1 due to additional capacity required
Note: Average tariff projections (and resulting total system cost) consider an offset representative of Tx/Dx/Other costs to align with starting point of 0.84 ZAR/kWh (0.20 ZAR/kWh). From 2017 to 2018, immediate cost reflectivity is considered too (as in Draft IRP 2018) i.e. 0.21 ZAR/kWh offset.
101
Submitted to DoE on 25 October 2018
System services and technical considerations6
Descriptive comments5.2
Risk-adjusted with low coal fleet performancee.b
IRP1 with low coal fleet performancee.a
Existing coal fleet performancee
Risk-adjusted scenariod
Technology learningc
Impact of Demand Side Response (DSR)b
Impact of stationary storagea
Scenarios5.1
Draft IRP 2018 energy planning risks and opportunities5
Draft IRP 2018 employment impacts4
Draft IRP 2018 scenarios3
Background2
Executive Summary1
Formal comments on Draft IRP 2018
102
Submitted to DoE on 25 October 2018
Sources: Draft IRP 2018. CSIR Energy Centre analysis
Installed capacity Energy mix
Demand: Median
First new-builds:PV (2023) 0.4 GWWind (2023) 0.2 GWOCGT (2023) 1.9 GW
Risk-adjusted scenario with Low EAF requires earlier new-build around 2023 too and increased absolute levels of new-build by 2030Installed capacity and electricity supplied from 2016 to 2050 for Risk-adjusted scenario with low coal fleet EAF
0
140
20
40
60
160
80
200
180
100
120
1.9
61.0
6.3
5.1
51.8
5.1
20
45
37.4
20
50
Total installed capacity (net) [GW]
0.6
0.51.51.5
21.4
20
16
9.4
1.91.2
31.7
20
30
20
35
41.4
5.113.7
20
40
16.9
0.7
20
20
20
25
67.9
0.6
5.113.2
20.1
12.1
3.4
9.9
51.657.8
69.1
97.1
116.9
149.2
174.9
191.0
1.9
DR
Other Storage
Biomass/-gas
Solar PV
CSP
Wind
Hydro+PS
Peaking
Gas
Nuclear (new)
Nuclear
Coal (New)
Coal
100
400
0
200
300
20
16
20
25
36
61
17
180
Electricity production [TWh/yr]
4
20
35
208
17
14
15
20
30
249
4
2
20
50
135
20
45
418
90
320
20
40
4(1%)
271
20
20
169(42%)
17(4%)7(2%)
104(26%)
77
66(17%)
298
340361
382399
33(8%)
103
Submitted to DoE on 25 October 2018Difference in capacity and energy mix with low EAF relative to IRP1, increased level of new-build, built earlier to cater for lower coal supplyInstalled capacity and electricity supplied from 2016 to 2050 for Risk-adjusted scenario with low coal fleet EAF
Sources: Draft IRP 2018. CSIR Energy Centre analysis
Installed capacity Energy mix
-60
-40
50
-10
0
10
-50
-20
20
30
60
40
70
-30
-70
Difference - Total installed capacity (net) [GW]
9
20
16
20
20
5
20
25
-9
-2
8
20
30
7
20
50
12
12
-3-3-7
-4
4
20
35
7
14
21
24
20
40
-12
20
45
Biomass/-gas
Coal (New)
DR CSP
Other Storage
Gas
Solar PV
Coal
Wind
Hydro+PS
Peaking
Nuclear (new)
Nuclear
30
20
-50
-30
-60
-40
40
-20
-10
50
0
60
10
70
-70 20
20
20
16
412
02
5
Difference - Electricity production [TWh/yr]
14
19
20
45
-32
20
35
20
30
-23
20
40
23
-18
-11
1
289
1
20
50
4
-17
-4
-27
-4
104
Submitted to DoE on 25 October 2018CO2 emissions trajectories for PPD Moderate never binding while water use declines as expected as coal fleet decommissionsRisk-adjusted scenario with low coal fleet EAF
CO2 emissions Water usage
82
71
275 275
210
0
50
100
150
200
250
300
2015 2020 2025 2030 2035 2040 2045 2050
Electricity sector CO2 emissions[Mt/yr]
36
310
50
100
150
200
250
300
2015 2020 2025 2030 2035 2040 2045 2050
Electricity sector Water usage[bl/yr]
IRP1
Risk-adjusted with low EAF
PPD (Moderate)
IRP1
Risk-adjusted with low EAF
Carbon Budget 2750 Mt 1800 Mt 920 Mt
PPD equiv. > 2750 Mt 2720 Mt 2325 Mt
105
Submitted to DoE on 25 October 2018
2015 2020 2025 2030 2035 2040 2045 2050
500
200
0
100
400
300
600
441
199
Total system cost in bR/yr (Jan-2017 Rand)
299
360
354
413
529
477
466
IRP1 Risk-Adjusted Low EAFRisk-Adjusted Mod EAF
Sources: Draft IRP 2018. CSIR Energy Centre analysis. Eskom on Tx, Dx costs
bR
3 937
Risk-Adj Mod EAF
Risk-Adj Low EAF
3 974 +37(+1%)
Net Present Value System Cost
(2016 - 2050)Total System Cost
Total system cost: Risk-Adjusted with low EAF results in higher system cost than mod EAF due to additional capacity required pre-2035
Note: Average tariff projections (and resulting total system cost) consider an offset representative of Tx/Dx/Other costs to align with starting point of 0.84 ZAR/kWh (0.20 ZAR/kWh). From 2017 to 2018, immediate cost reflectivity is considered too (as in Draft IRP 2018) i.e. 0.21 ZAR/kWh offset.
106
Submitted to DoE on 25 October 2018
System services and technical considerations6
Demand profilee
Planning for embedded generationd
Natural gasc
New-build and under-construction coal capacityb
Technology new-build limitsa
Descriptive comments5.2
Scenarios5.1
Draft IRP 2018 energy planning risks and opportunities5
Draft IRP 2018 employment impacts4
Draft IRP 2018 scenarios3
Background2
Executive Summary1
Formal comments on Draft IRP 2018
107
Submitted to DoE on 25 October 2018
System services and technical considerations6
Demand profilee
Planning for embedded generationd
Natural gasc
New-build and under-construction coal capacityb
Technology new-build limitsa
Descriptive comments5.2
Scenarios5.1
Draft IRP 2018 energy planning risks and opportunities5
Draft IRP 2018 employment impacts4
Draft IRP 2018 scenarios3
Background2
Executive Summary1
Formal comments on Draft IRP 2018
108
Submitted to DoE on 25 October 2018
Draft IRP 2018 investigated implications of unconstrained least-cost (IRP1) but RE new-build limits are maintained for all other scenarios
“The scenario without new-build limits provides the least-cost option by 2030“ [DoE, Draft IRP 2018, pp. 34 of 75]
“Imposing new-build limits on RE will not affect the total installed capacity and the energy mix for the period up to 2030“
[DoE, Draft IRP 2018, pp. 34 of 75]
“The scenario without RE annual build limits provides the least-cost option by 2050“ [DoE, Draft IRP 2018, pp. 35 of 75]
“The scenario without RE annual build limits provides the least-cost electricity path to 2050“ [DoE, Draft IRP 2018, pp. 35 of 75]
Why new-build limits (on any technology – needs justification)?
Could be various reasons
• Import/transport link limitations (infrastructure – ports, roads)
• Industry ability to deliver (skills, development, construction)
• Available Tx/Dx networks to evacuate power
• System security/stability
109
Submitted to DoE on 25 October 2018Submitted to DoE on 25 October 2018
Draft IRP 2018 RE annual new-build limits have thusfar not been justified
New-build limits on technologies means no more than these limits are allowed to be built in any given year
Limits have been applied to two technologies (others unlimited):
Solar PV
Wind
Limits are constant as power system grows
No justification provided for these limits
Sources: Scatec; Hopefield
110
Submitted to DoE on 25 October 2018Submitted to DoE on 25 October 2018
Solar PV is limited to 1000 MW annually resulting in a move from 2.5% of peak demand in 2020 to 1.7% of peak demand by 2050
Sources: Eskom; Draft IRP 2018; CSIR analysis
0
40 000
1 000
2 000
3 000
4 000
0
20 000
60 000
80 000
2016
Max. new-build capacity, annually [MW]
Peak demand [MW]
20252020 20352030 2040 2045 2050
IRP_2018_Median
Maximum allowed new-build solar PV (annually)
0
2
6
4
8
0
20 000
40 000
60 000
80 000
2.5
2025
Peak demand [MW]
Max. new-build capacity, annually [% of peak demand]
2.7
2016 2020
2.2 2.1
2030
2.0
2035
1.8
2040
1.7
2045
1.7
2050
Absolute Relative
111
Submitted to DoE on 25 October 2018Submitted to DoE on 25 October 2018
Wind is limited to 1600 MW annually resulting in a move from 4.0% of peak demand in 2020 to 2.7% of peak demand by 2050
Sources: Eskom; Draft IRP 2018; CSIR analysis
Absolute Relative
80 0004 000
0
1 000
2 000
3 000
0
20 000
40 000
60 000
20352020 20502040
Peak demand [MW]
Max. new-build capacity, annually [MW]
2016 2025 2030 2045
IRP_2018_Median
Maximum allowed new-build wind (annually)
80 000
0
4
2
60 0006
8
20 000
0
40 000
2025
4.0
2030
Peak demand [MW]
2035
Max. new-build capacity, annually [% of peak demand]
2016
4.3
2020
3.62.7
3.3 3.1 3.0
2040 2045
2.8
2050
112
Submitted to DoE on 25 October 2018
4%
2%
5%
9%10%
4%
3%
2% 2%
2%
1%
4%
2%
1%
1%
4%
7%
3%3%
6%
5%
2%
1%
2%
3%
4%
1%1%
1%
4%
6%
7%
5%
2%
2%
5%
8%
3%
6%
2%
0%
2011 2012
1%
2014 2017
1%
2030 (2.1%)2050 (1.7%)
2013
2%
2%
1%
2010
3%
17%
2015
1%1%
3%
1%
3%
2%
1%
3%
1%
2%
1%
4%
9%
2007 2008 2009 2016
1%
Germany
Spain
Italy
UK
Australia
Japan
China
India
South Africa
Already happening: Both leader, follower and 2nd wave countries installing more new solar PV per year than South Africa’s IRP limits for 2030/2050
New-build solar PV capacity, annually [% of peak demand]
RSA’s IRP relativenew-build limit
decreasesover time
Leader
Follower
Follower2nd wave
Sources: SolarPowerEurope; CIGRE; websites of System Operators; IRP 2016 Draft; CSIR analysis
RSA new-build limits in 2030 and 2050
113
Submitted to DoE on 25 October 2018
Already happening: Both leader and follower countries are installing more new wind capacity per year than South Africa’s IRP limits for 2030/2050
3%
2% 2%2%
2%
2%3%
4%
6%
7%
6%
8%
4%
8%
3%
6%
3% 3%
5%
5%
6%
4%
3%
7%
5% 5%5%
9%
3%
4%
3%
2%3%
4%
4%
3%
3%
2%
2% 2%
1%
2%
2%
0% 1%1%
2%2%
4%5%
3% 3%
1%
1%1%
2%
2050 (2.7%)
2030 (3.3%)
2012 2014 2015 20172006 2007 2016
2%
2008
1%
2010 2013
2%
2009 2011
1%1%
3%
1%2% 2%2%
1%
Germany
Ireland
Spain
India
China
Brazil
South Africa
RSA’s IRP relativenew-build limit
decreasesover time
Leader
RSA new-build limits in 2030 and 2050
Sources: GWEC; CIGRE; websites of System Operators; IRP 2016 Draft; CSIR analysis
Follower
New-build wind capacity, annually [% of peak demand]
114
Submitted to DoE on 25 October 2018
Solar PV penetration in leading countries already up to 1.3x levels expected in Draft IRP 2018 (constrained scenarios) by 2050
54
36
23
19
4
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
2005 2010 2015 2020 2025 2030 2035 2040 2045 2050
Year
Total solar PV capacityrelative to system peak demand
31
12
22
UK
China
Japan
India
Germany
South Africa
Spain
South Africa IRP 2016 Base Case
Draft IRP 2018 (Recommended)
Italy
Draft IRP 2018 (IRP1)
Draft IRP 2018 (Others)
Australia
Sources: SolarPowerEurope; CIGRE; websites of System Operators; IRP 2016 Draft; CSIR analysis
Leader
Follower
Follower2nd wave
115
Submitted to DoE on 25 October 2018
Wind penetration in leading countries is already at levels up to 1.4x Draft IRP 2018 (constrained scenarios) by 2050
70
60
67
27
20
6
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
2005 2010 2015 2020 2025 2030 2035 2040 2045 2050
Year
Total wind capacity relative to system peak load
21
Germany
Spain
Draft IRP 2018 (Others)
South Africa IRP 2016 Base Case
Ireland
China
India
Brazil
South Africa
Draft IRP 2018 (IRP1)
Draft IRP 2018 (Recommended)
Sources: GWEC; CIGRE; websites of System Operators; IRP 2016 Draft; CSIR analysis
Leader
Follower
116
Submitted to DoE on 25 October 2018
Some historical perspective - installed capacity reveals the considerable coal build-out South Africa pursued previously
Biomass/-gas
Solar PV
Wind
CSP
Gas
Hydro+PS
Peaking
Nuclear
Coal
Sources: Draft IRP 2018; CSIR analysis
0
15
5
10
20
25
30
45
35
40
50
55
60
2050
41
2010
27
2020
42
9
1985
Installed capacity [GW]
1965 1975 1995 2000 2005 2015 2030
41
2035
37
2040 2045
24
2025
58
47
59
16
49
22
44
117
Submitted to DoE on 25 October 2018
Initial smaller coal, followed by large 6-pack build-out, more recently Medupi & Kusile – most decommissions in Draft IRP 2018 time horizon
Sources: Draft IRP 2018; CSIR analysis
10
50
60
20
0
30
4036
35
2035
32
18
10
13
32
Installed capacity [GW]
20051965 1975
7
1985 1995 2000 2010 2015 2020 2025 2030 2040 2045 2050
35 35
42
26
40
17
Grootvlei
Arnot
Lethabo
Coal IPPs
Hendrina
MajubaWet
MajubaDry
Camden
Duvha
Matimba
Matla
Kendal
Medupi
Tutuka
Komati
Sasol
Kusile
Other
Kriel
118
Submitted to DoE on 25 October 2018
South Africa embarked on a significant new-build capacity programme previously… in coal – why not now in any other technologies?
Sources: Draft IRP 2018
New-build coal capacity, annually [MW]
555
187
847
1 050
575
1 178
1 793
2 433
3 048
640 610 610670 670
1 4811 411
2020
100
744
1 150 1 178
2 433
1 725
950
711
1965
1 150
555 559
1 150
746
555
1 303
1 135
1 895
670 722
931
706
20151990 19951980
100
1970
610
1975 20001985 2005 2010
1 148
119
Submitted to DoE on 25 October 2018
System services and technical considerations6
Demand profilee
Planning for embedded generationd
Natural gasc
New-build and under-construction coal capacityb
Technology new-build limitsa
Descriptive comments5.2
Scenarios5.1
Draft IRP 2018 energy planning risks and opportunities5
Draft IRP 2018 employment impacts4
Draft IRP 2018 scenarios3
Background2
Executive Summary1
Formal comments on Draft IRP 2018
120
Submitted to DoE on 25 October 2018
Even currently under-construction and committed capacity will be part of planned decommissioning and will require new-build
Sources: Draft IRP 2018; CSIR analysis
0
5
55
10
20
25
50
30
35
40
45
60
15
57
2035
16
20502040
Installed capacity [GW]
2010 2015 2025 2030 2045
4442
2020
58
49
27
22
47
CSP
Nuclear
Wind
Solar PV
Hydro+PS
Gas
Peaking
Biomass/-gas
Coal
121
Submitted to DoE on 25 October 2018
New-build largely driven by the planned decommissioning of the existing coal fleet - mostly post 2030
Sources: Draft IRP 2018; CSIR analysis
60
50
10
30
0
20
40
Installed capacity [GW]
36
20452020
17
13
2025 2030 2035 2050
32
2010
35
2015 2040
4240
26
10
-9.9(-24%)
-24.7(-59%)
-31.7(-76%)
-14.8(-47%)
-7.0(-41%)
Sasol
Arnot
MajubaWet
Camden
Duvha
Grootvlei
Kendal
Komati
Matimba
MajubaDry
Coal IPPs
Kusile
Matla
Other
Medupi
Lethabo
Tutuka
Kriel
Hendrina
122
Submitted to DoE on 25 October 2018
Should we freely optimise the decommissioning of the existing coal fleet or finish the last 2 units at Kusile?
Should we build new coal capacity in South Africa?
Should a freely optimised existing coal fleet be decommissioned any earlier/later?
Should the last 2 units at Kusile be completed in light of alternatives?
This has been studied in previous work
Steyn, G., Burton, J. & Steenkamp, M. Eskom’s financial crisis and the viability of coal-fired power in
South Africa. (2017).
Wright, J. G., Calitz, J., Bischof-Niemz, T. & Mushwana, C. The long-term viability of coal for power
generation in South Africa (Technical Report as part of "Eskom’s financial crisis and the viability of
coal-fired power in South Africa). (2017).
Summary of outcomes are presented here for reference
123
Submitted to DoE on 25 October 2018
System Alternate Value (SAV) approach attempts to obtain the present value of a power station over the full time horizon
Total discounted system costs[ZAR-billion]
Total(with PS
costs incl.)
PS costs Total (with PS costs
excl.)
Total (with PS costs
excl.)
Total(with PS
costs incl.)
PS costs Value difference[ZAR-billion]
Total energy (PS)
Total energy (discounted)[TWh]
Total energy (PS)
Energy difference[TWh]
./.
Equivalent value[R/kWh]
-
-
PS included PS excluded
Hydro
Coal
DR
Peaking
Nuclear
Gas Wind
CSP
Solar PV
Biomass/-gas
Pumped storage
Li-ion
124
Submitted to DoE on 25 October 2018
HendrinaKusile GrHeKoArnot Camden
0.50
0.58
Grootvlei Komati
0.50 0.49 0.48
0.570.53
Kusile Arnot GrHeKo
[R/kWh]
KomatiCamden HendrinaGrootvlei
0.61
0.50
0.36
0.47
0.41
0.48 0.47
Early decommissioning of oldest selected coal-fired power stations would result in significant savings and a cheaper power system
High demand SAV
Power station(s)
Low-demand SAV
Complete 6 units
vs. 4 units
Decom. EarlyOff from 1Apr20
Decom. EarlyOff from 1Apr18
Decom. EarlyOff from 1Apr18
Decom. EarlyOff from 1Apr19
Decom. EarlyOff from 1Apr20
Decom. all 3 early
Env. Retrofit O&M
Env. Retrofit Capex
VOM
Fuel
Water cost
FOM
SAV
Levelised costs
0.57
0.34
0.22
0.31
0.23
0.310.33
Max. allowed equivalent capex cost of remaining2 Kusile units
Will cost 0.11-0.17 R/kWh more from Grootvlei if not decommissioned early
Source: Wright (2017), Steyn (2017)
125
Submitted to DoE on 25 October 2018
System services and technical considerations6
Demand profilee
Planning for embedded generationd
Natural gasc
New-build and under-construction coal capacityb
Technology new-build limitsa
Descriptive comments5.2
Scenarios5.1
Draft IRP 2018 energy planning risks and opportunities5
Draft IRP 2018 employment impacts4
Draft IRP 2018 scenarios3
Background2
Executive Summary1
Formal comments on Draft IRP 2018
126
Submitted to DoE on 25 October 2018
Need for natural gas: Understanding domestic natural gas options
Natural gas source not critical in IRP at this stage but... whether it is domestic/imported is important
What is the energy security risk of importing all of the natural gas required in Draft IRP 2018 scenarios?
Sources: PetroSA; Eskom; Excellerate
127
Submitted to DoE on 25 October 2018
The role of natural gas in the energy mix (likely via imported LNG at this stage) is relatively small to 2030 (2-5%) and up to 15% by 2050
IRP3
Energy [TWh]
313
313
12 (4%)
10 (3%)
IRP1
7 (2%)
15 (5%)
15 (5%)
IRP5
15 (5%)
IRP6
IRP7
Rec.
313
313
311
313
NG Other
Energy [TWh]
14 (4%)
28 (8%)
353
29 (8%)
37 (10%)
17 (5%)
353
355
352
352
Energy [TWh]
393
47 (12%)
40 (10%)
19 (5%)
59 (15%)
31 (8%)
392
388
391
390
2030 2040 2050
Domestic sources of flexibility and/or storage could replace some/all of these relatively small volumes of (imported) natural gas in the electricity sector
e.g. UCG, CBM, shale gas, offshore, hydrogen, DSR, biomass/-gas, CSP, storage (pumped, batteries)NG – Natural gas; Sources: Draft IRP 2018
128
Submitted to DoE on 25 October 2018
Total system cost contribution of NG fuel requirements (likely via imported LNG at this stage) is 2-4% to 2030 and up to 10% by 2050
8 (2%)
Total system cost [bR/yr]
350 (97%)
362
10 (3%)
IRP1
Rec.
346 (96%)
15 (4%)
IRP5
IRP3
IRP7
351 (96%)
360
15 (4%)
347 (96%)
15 (4%)
367
IRP6
365 (98%)
364 (97%)
12 (3%)
361
373
375
NG (fuel) Other
495
Total system cost [bR/yr]
442
28 (6%)
29 (6%)
IRP1
IRP3
14 (3%)
466
IRP5
37 (8%)
IRP6
17 (3%)
IRP7
Rec.
473
477
Total system cost [bR/yr]
60 (10%)
47 (9%)
20 (3%)
40 (7%)
31 (5%)
529
560
564
580
591
2030 2040 2050
NG – Natural gas; Sources: Draft IRP 2018
129
Submitted to DoE on 25 October 2018
System services and technical considerations6
Demand profilee
Planning for embedded generationd
Natural gasc
New-build and under-construction coal capacityb
Technology new-build limitsa
Descriptive comments5.2
Scenarios5.1
Draft IRP 2018 energy planning risks and opportunities5
Draft IRP 2018 employment impacts4
Draft IRP 2018 scenarios3
Background2
Executive Summary1
Formal comments on Draft IRP 2018
130
Submitted to DoE on 25 October 2018
Just 5 years ago – power generation capacity was concentrated around Mpumalanga (coal) with some hydro, peaking and nuclear
Sources: Eskom; CSIR analysis
131
Submitted to DoE on 25 October 2018
By 2018 – generation capacity (albeit still small) has already started to distribute across the country - not only in Mpumalanga anymore
Sources: Eskom; CSIR analysis
132
Submitted to DoE on 25 October 2018
Munics.(Dx2)
IRP meets energy demand for RSA – expressed as equivalent demand (assumes EG as reduced demand)
Eskom(Tx2)
Eskom(Dx2)
Eskom1
(Gx)Imports ExportsIPPs1
(Gx)
EG = Embedded Generation; Gx = Generation; Tx = Transmission; Dx = Distribution1 Power generated less power station load; Minus pumping load (Eskom owned pumped storage); 2 Transmission/distribution networks incur losses before delivery to customers
Large customers
EG(Gx)
Customers(Dom/Com/Ind)
EG(Gx)
Customers(Dom/Com/Ind)
1 1Net sent out 1
2 Imports
3 Exports
32
Available for distribution in RSA
+ += + -1 32
Other(Gx)
Other(Gx)
1 1
133
Submitted to DoE on 25 October 2018From Jan-Dec 2016, 234 TWh of net electricity was sent out in SA with imports of almost 11 TWh means system load was 245 TWhActuals captured in wholesale market for Jan-Dec 2016 (i.e. without embedded plants)
Notes: “Net Sent Out“ = Total domestic generation (less auxillary load) minus pumping load of Eskom pumped storage stations (not shown seperately)
Sources: Eskom; Statistics South Africa
Available for distribution
in RSA
ExportsImports
Annualelectricity
in TWh
System Load (domestic and export load)
Net Sent Out
234.210.6 244.8
16.5
228.2
18.2
216.0
Other
Eskom + IPPs
134
Submitted to DoE on 25 October 2018
IRP 2018 expects demand growth to be more certain, slower - average growth from 2016 of 1.2-2.0%/yr to 2030, 1.2-1.7%/yr to 2050
Sources: StatsSA; Draft IRP 2018
135
Submitted to DoE on 25 October 2018
Lower demand forecast implies 3 things: Increased EE, fuel switching and... Embedded Generation – but how much?
”Due to the limited data at present and for the purpose of this IRP Update, these developments werenot modelled as standalone scenarios, but considered to be covered in the low-demand scenario. Theassumption was that the impact of these would be lower demand in relation to the median forecastdemand projection.”
[DoE, Draft IRP 2018, pp. 21 of 75]
In the Draft IRP 2018, it is clearly stated that the relative to the Median demand forecast, the Lower demand forecast is representative of a combination of:
Embedded Generation (likely mostly solar PV)
Energy efficiency (EE)
Fuel switching
Growth of embedded generation (EG) market being implicitly included can then be calculated based on:
Share of EG in the difference between Median and Lower demand forecasts
Almost all EG will likely be solar PV (with associated capacity factor)
136
Submitted to DoE on 25 October 2018
Between 1.1 - 5.8 GW of embedded generation (assumed to be PV dominated) is implicitly considered in the Draft IRP 2018 by 2030
5290
313
2450 0
245
2016 (TWh)
2909
313
Median demand forecast
EE/fuel switching
EG
Lower demand forecast 31319
290
2030 (TWh)
2030 (MW)
20% is EG
60% is EG
80% is EGSources: StatsSA; Draft IRP 2018; CSIR analysis
1100-1500 MW(80-100 MW/yr)
3300 – 4400 MW(230-310 MW/yr)
4400 - 5800 MW(310-420 MW/yr)
137
Submitted to DoE on 25 October 2018
System services and technical considerations6
Demand profilee
Planning for embedded generationd
Natural gasc
New-build and under-construction coal capacityb
Technology new-build limitsa
Descriptive comments5.2
Scenarios5.1
Draft IRP 2018 energy planning risks and opportunities5
Draft IRP 2018 employment impacts4
Draft IRP 2018 scenarios3
Background2
Executive Summary1
Formal comments on Draft IRP 2018
138
Submitted to DoE on 25 October 2018
Demand profile is assumed unchanged in Draft IRP 2018 – updated aproached to demand profile will need to be pursued in future
Demand profile will change as constituent components of the demand forecast change
Not just purely an energy demand forecast and fitted peak load (assuming similar demand profile)
Updated approaches will be required linking with EG to ensure sufficiently accurate capacity expansion
139
Submitted to DoE on 25 October 2018
Change in demand profile will result in very different capacity expansion options
Today Future
Weekday Weekend Weekday Weekend
EG TransComManDomAgri Min
140
Submitted to DoE on 25 October 2018
System services6.2
Networks6.1
System services and technical considerations6
Draft IRP 2018 energy planning risks and opportunities5
Draft IRP 2018 employment impacts4
Draft IRP 2018 scenarios3
Background2
Executive Summary1
Formal comments on Draft IRP 2018
141
Submitted to DoE on 25 October 2018
System services6.2
Networks6.1
System services and technical considerations6
Draft IRP 2018 energy planning risks and opportunities5
Draft IRP 2018 employment impacts4
Draft IRP 2018 scenarios3
Background2
Executive Summary1
Formal comments on Draft IRP 2018
142
Submitted to DoE on 25 October 2018
Good to include shallow grid connection costs explicitly in Draft IRP 2018 based on extensive grid planning experience at Eskom
Draft IRP 2018 includes collector network costs in the various Eskom Customer Load Networks (CLNs) as well as shallow grid connection costs for VRE (solar PV and wind) and all other technologies
This is a welcome inclusion and is a good starting point to start to incorporate technology specific network costs previously not considered
Good objectives:
• Avoid premature congestion at Eskom Main Transmission Substations (MTSs)
• Minimising absolute number of MTSs
• Connect more smaller VRE plants in a specific area
• Allow more orderly network development
and increased utilisation i.e. more efficient integration
Network costs based on unitised costing of individual equipment
Transmission substations, Satellite stations,
Transformers, Transmission/Distribution bays,
Overhead lines, Static VAr Compensators (SVCs)
143
Submitted to DoE on 25 October 2018
Deep network costs are not included in Irp but covered as part of periodic and well established TDP and SGP developed by Eskom
Deep network costs (backbone strengthening) not included in Draft IRP 2018 (or any previous IRP iteration) but instead established based on periodic TDPs and SGPs developed by Eskom Grid Planning
What is most important is how these deep network costs change on a relative basis across scenarios
Generally, these costs do not change significantly across scenarios and thus would not materially impact least-cost outcomes
In future iterations of the IRP, there should be a
continued pursuit to include geospatial components
of supply, networks and demand side options
(co-optimisation) where feasible and tractable
TDP – Transmission Development Plan; SGP – Strategic Grid Plan
144
Submitted to DoE on 25 October 2018
RoCoF and frequency stabilitya
System services6.2
Networks6.1
System services and technical considerations6
Draft IRP 2018 energy planning risks and opportunities5
Draft IRP 2018 employment impacts4
Draft IRP 2018 scenarios3
Background2
Executive Summary1
Formal comments on Draft IRP 2018
145
Submitted to DoE on 25 October 2018
RoCoF and frequency stabilitya
System services6.2
Networks6.1
System services and technical considerations6
Draft IRP 2018 energy planning risks and opportunities5
Draft IRP 2018 employment impacts4
Draft IRP 2018 scenarios3
Background2
Executive Summary1
Formal comments on Draft IRP 2018
146
Submitted to DoE on 25 October 2018
System services and ensuring security of supply to enable any range of future energy mixes
System services and security of supply
Frequency stability/control (system inertia and RoCoF) – particular focus in these comments
Transient stability and fault level (system strength)
Voltage and reactive power control
Variable resource forecasting
All of these should inform a programme of research and effort required by all key stakeholders to ensure any future energy mix is secure
147
Submitted to DoE on 25 October 2018
System operators are managing high non-synchronous penetration –Ireland SNSP limits and services to manage low inertia power systems
Sources: David Cashman (EirGrid), DS3 and beyond, 2017, IEA Working Group
SNSP [%] = System Non-Synchronous Penetration = (Wind/PV + Imports)/(Demand + Exports)
148
Submitted to DoE on 25 October 2018
Averaging window is important – for frequency stability typically a 500 ms averaging window for RoCoF is considered
Sources: EirGrid, SONI
The RocoF should not exceed a particular threshold within the pre-defined averaging window e.g. 500 ms
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The demand for system inertia is driven by two assumptions: the maximum allowable RoCoF & the largest assumed system contingency
Key assumptions:
Maximum allowed 𝑅𝑜𝐶𝑜𝐹: 0.5 Hz/s
Largest contingency (𝑃𝑐𝑜𝑛𝑡): 2 400 MW
Kinetic energy lost in contingency event 𝐸𝑘𝑖𝑛(𝑐𝑜𝑛𝑡.): 5 000 MWs
Term “inertia” is used a bit loosely to describe the amount of kinetic energy that is stored in the rotating masses of all synchronously connected power generators (and loads to be precise)
𝑓𝑛 = System frequency = 50 Hz
Sources: P. Kundur, Power System Stability and Control, 1994
Demand for inertia
𝐸𝑘𝑖𝑛.(𝑚𝑖𝑛) = 𝑃𝑐𝑜𝑛𝑡.𝑓𝑛
2(𝑅𝑜𝐶𝑜𝐹)+ 𝐸𝑘𝑖𝑛(𝑐𝑜𝑛𝑡.)
124 800 MW.s of system inertia are required at any given point in time in order for RoCoF to stay below 0.5 Hz/s in the first 500 ms after the largest system contingency occurred
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As a starting point – we have assessed system inertia on an hourly basis via UCED in PLEXOS and some high level assumptions
Depending on what mix of power stations is operational at any given point in time, the total actual system inertia will be different
For example, if 20 GW of old coal, 10 GW of new coal and 2 GW of nuclear are online, system inertia is:
≈20 GW * 4 MWs/MVA +
10 GW * 2 MWs/MVA + 2 GW * 5 MWs/MVA
= 110 000 MWs
If wind, PV and 5 GW of CCGTs are online, system inertia is only 47 000 MW.s
Sources: P. Kundur, Power System Stability and Control, 1994
Technology Inertia constant
[MWs/MVA]
Coal (old) 4.0
Coal (new) 2.0
OCGT/ICE 6.0
CCGT/CC-GE 6.0
Biomass 2.0
Hydro/PS 3.0
Imports 0.0
Nuclear 5.0
Wind 0.0
PV 0.0
CSP 2.0
DR 0.0
Supply of inertia
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SNSP levels in IRP1 of Draft IRP 2018 only above 25% from 2028 and 37% by 2030 for 10% of the time but above 80% by 2050
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System synchronous energy for IRP1 – confirmation that the power system really does only start to change until after 2030
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Minimal cost of ensuring acceptable RoCoF levels even at very high non-synchronous generation penetration levels
The worst-case cost to ensure RoCoF levels are acceptable post-2030 is at most ≈1% of total system costs
2 0 1 6 2 0 2 0 2 0 2 5 2 0 2 8 2 0 3 0 2 0 4 0 2 0 5 0
M i n i m u m i n e r t i a n e e d e d [ M W . s ]1 0 4 4 8 2 1 0 4 4 8 2 1 0 4 4 8 2 1 0 4 4 8 2 1 0 4 4 8 2 1 0 4 4 8 2 1 0 4 4 8 2
M i n i m u m i n e r t i a ( a c t u a l ) [ M W . s ]1 0 4 4 8 2 1 1 6 4 8 5 1 1 6 6 0 9 1 2 2 2 6 0 1 0 4 9 9 2 5 5 8 3 2 3 1 9 0 7
A d d i t i o n a l i n e r t i a n e e d e d [ M W . s ]- - - - - 4 8 6 5 0 7 2 5 7 5
N u m b e r o f h o u r s [ h r s ]2 4 - - - - 1 7 9 9 2 2 8 2
S h a r e o f h o u r s [ % ]0 . 3 % 0 . 0 % 0 . 0 % 0 . 0 % 0 . 0 % 2 0 . 5 % 2 6 . 1 %
R o t a t i n g s t a b i l i s e r s n e e d e d [ M W ] - - - - - 1 2 2 0 1 8 1 0
A n n u a l c o s t f o r r o t a t i n g s t a b i l i s e r s [ b R / y r ] - - - - - 3 . 7 5 . 6
( % o f s y s t e m c o s t s ) [ % ] 0 . 0 % 0 . 0 % 0 . 0 % 0 . 0 % 0 . 0 % 0 . 9 % 1 . 2 %
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Thank you
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