Submitted to DoE on 25 October 2018
Formal comments on Integrated Resource Plan (IRP) 2018 CSIR Energy Centre Pretoria. 25 October 2018
1
Jarrad Wright
Joanne Calitz
Ntombifuthi Ntuli
[email protected]
[email protected]
[email protected]
Mpeli Rampokanyo
Pam Kamera
Ruan Fourie
[email protected]
[email protected]
[email protected]
Submitted to DoE on 25 October 2018
2
Word Cloud (DoE, IRP 2010, 2011)
Word Cloud (DoE, IRP 2010 Update, 2013)
(Design: JG. Wright, using word_cloud, https://github.com/amueller/word_cloud)
(Design: JG. Wright, using word_cloud, https://github.com/amueller/word_cloud)
Word Cloud (DoE, Draft IRP 2016, 2016)
Word Cloud (DoE, Draft IRP 2018, 2018)
(Design: JG. Wright, using word_cloud, https://github.com/amueller/word_cloud)
(Design: JG. Wright, using word_cloud, https://github.com/amueller/word_cloud)
Submitted to DoE on 25 October 2018
Word Cloud (DoE, Draft IRP 2018) 3
(Design: JG. Wright, using word_cloud, https://github.com/amueller/word_cloud)
Submitted to DoE on 25 October 2018
Formal comments on Draft IRP 2018
1 Executive Summary 2 Background 3 Draft IRP 2018 scenarios 4 Draft IRP 2018 employment impacts 5 Draft IRP 2018 energy planning risks 6 System services and technical considerations
4
Submitted to DoE on 25 October 2018
Formal comments on Draft IRP 2018
1 Executive Summary 2 Background 3 Draft IRP 2018 scenarios 4 Draft IRP 2018 employment impacts 5 Draft IRP 2018 energy planning risks 6 System services and technical considerations
5
Submitted to DoE on 25 October 2018
Key Messages
• Key Messages
1
6
•
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
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
Submitted to DoE on 25 October 2018
Key Messages
• Key Messages
1
7
• •
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
•
To 2030, in the Recommended Plan, expect net employment increase (as system grows) but net decrease in coal
•
Post 2030 - key drivers include VRE new build limits, decommissioning, demand growth, stationary storage
•
Natural gas risk relatively small and can be replaced by appropriate domestic flexibility sources or stationary storage
•
No system integration issues foreseen pre-2030 but an informed and co-ordinated work program is necessary to sufficiently prepare for post-2030 relatively high VRE penetration levels
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
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)
8
Submitted to DoE on 25 October 2018
At a glance 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
9
1
Natural gas fired peaking and mid-merit capacity considered as a proxy for this; NG - Natural gas; PV – Solar Photovoltaics
Submitted to DoE on 25 October 2018
Energy mix by 2030 similar across scenarios as coal dominates, IRP1 is ≈R10bn/yr cheaper than next best IRP3, IRP7 lowest CO2 emissions 2030 Energy Mix
Cost
in 2030
in 2030
202 (64%)
15 14 42 2
37
IRP3
197 (63%)
199 (63%)
158 13 44 2
15
14
199 (63%)
15
13
44 2
192 (61%)
15 4 26
44 2
206 (64%)
44 2
217
199
4
361
215
199
4
367
213
198
4
362
215
199
373
207
191
375
215
199
4 23
15 8 28 6 (2%) 3
10
360
22
3
Rec.
4
22
4 11
IRP7
Water usage (billion-litres/yr)
22
4 11
IRP6
CO2 emissions (Mt/yr)
25
9
IRP5
in 2030
Total system cost1 (R-billion/yr)
Demand: 313 TWh
IRP1
Environment
35 2
2
14
Coal
Nuclear
Gas - CCGT
Peaking
Wind
Solar PV
Other Storage
Coal (New)
Nuclear (new)
Gas - CCGE
Hydro+PS
CSP
Biomass/-gas
DR
Sources: DoE Draft IRP 2018; Eskom on Tx, Dx costs; CSIR analysis; flaticon.com
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 2040 Energy Mix
Cost
in 2040
in 2040
107 (30%)
in 2040
Total system cost1 (R-billion/yr)
Demand: 353 TWh
IRP1
Environment
15 23 15
129
2
CO2 emissions (Mt/yr) 441
54
4
90
2 47
4
466
89
2 47
4
473
90
2 47
4
477
90
2 47
4
123
Water usage (billion-litres/yr) 59
5
IRP3
106 (30%)
151414 29
153
66
33 (9%)
IRP5
104 (29%)
15 11 29
168
70
51 (14%) 4
IRP6
97 (27%)
IRP7
99 (28%)
15 33
15 9 (2%)
25 12 30
43
12 29
353
494
116
56
119
58
5
Rec.
11
Coal
Nuclear
Gas - CCGT
Peaking
Wind
Solar PV
Other Storage
Coal (New)
Nuclear (new)
Gas - CCGE
Hydro+PS
CSP
Biomass/-gas
DR
Sources: DoE Draft IRP 2018; Eskom on Tx, Dx costs; CSIR analysis; flaticon.com
Submitted to DoE on 25 October 2018
By 2050 - Least-cost mix is 70% solar PV and wind, ≈R30-60 bn/yr cheaper than alternatives, least CO2 emissions and least water usage 2050 Energy Mix
Cost
in 2050
in 2050
68 (17%)
IRP3
66 (17%)
in 2050
Total system cost1 (R-billion/yr)
Demand: 392 TWh
IRP1
Environment
29 17 31
164
78
CO2 emissions (Mt/yr) 529
3
82
31 8 31
110
63
3
560
13 32
107
64
3
564
106
67
3
106
64
3
Water usage (billion-litres/yr) 36
160
54
80 (20%)
IRP5
64 (16%) 102 (26%)
IRP6 57 (15%)
55
47
178
59
5
12 31
580
92
36
90
38
13 (3%)
IRP7 58 (15%)
76
22 (6%)
17
31
591
13
Rec.
12
Coal
Nuclear
Gas - CCGT
Peaking
Wind
Solar PV
Other Storage
Coal (New)
Nuclear (new)
Gas - CCGE
Hydro+PS
CSP
Biomass/-gas
DR
Sources: DoE Draft IRP 2018; Eskom on Tx, Dx costs; CSIR analysis; flaticon.com
Submitted to DoE on 25 October 2018 CO2 emissions trajectories for PPD Moderate never binding (only CB) while water use declines as expected as coal fleet decommissions
Scenarios from Draft IRP 2018
CO2 emissions
Water usage
Electricity sector CO2 emissions [Mt/yr]
Electricity sector Water usage [bl/yr]
300
275
300
275
250
250 210
200 150
178 IRP1
160
IRP3
200 150
IRP5
100
IRP3 92 82
IRP6 IRP7
50
IRP2 IRP4 PPD (Moderate)
13
PPD equiv.
100
2750 Mt
1800 Mt
920 Mt
> 2750 Mt
2720 Mt
2325 Mt
IRP5 IRP6
50
0 2015 2020 2025 2030 2035 2040 2045 2050 Carbon Budget
IRP1
IRP7 IRP2 IRP4
0 2015 2020 2025 2030 2035 2040 2045 2050
59
36
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
14
EAF – Energy Availability Factor Sources: Eskom; CER
Submitted to DoE on 25 October 2018
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 Jobs (net) (construction + operations) [’000] 500
400 350 300
437
436
450 10 (3%) 365 3 (1%) 14 (4%) 44 (12%) 7 (2%)
398
394 14 3 25 7
359
3 4 3
7 44
44
342
7 4
7 44
362
39
22 10 4 12
20
44
33 44
250
41
42 4
4
60 42 44
434
64
403
43 5
5
44 5
62 61
49 44
62 47
44 44
200 150
287 (79%)
300
297
280
270
258
245
100
395 45 (11%) 5 (1%) 62 (16%) 56 (14%) 44 (11%)
233
217
202
183 (46%)
2027
2028
2029
2030
50 0
2020 Solar PV
15
2021 EG (PV)
2022 Wind
2023 Gas
2024
2025
Nuclear
2026 Coal
Sources: Draft IRP 2018; CSIR Energy Centre analysis Note: Job potential includes direct, indirect and induced jobs; Nuclear is estimated based on existing experience at Koeberg (KPMG, 2017)
Submitted to DoE on 25 October 2018
At a glance Key energy planning risks – Existing fleet low EAF, stationary storage, DSR, further RE learning • • • • •
16
Existing fleet Low EAF: Earlier new-build (2023), outcomes return to IRP1 if low demand and low coal fleet performance Storage: Decreasing stationary storage costs (batteries) results in deployment pre-2030, less NG usage and increased solar PV DSR: A more responsive demand-side test via electric water heating and EVs delays some capacity investment and 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
Submitted to DoE on 25 October 2018 Draft IRP 2018 (IRP1) - Least-cost deploys considerable wind, solar PV and NG capacity to 2030 and beyond as the coal fleet decommissions
Installed capacity and electricity supplied from 2016 to 2050 as planned in the Draft IRP 2018
Installed capacity
Energy mix
Total installed capacity (net) [GW]
Electricity production [TWh/yr]
160
148 1
140 119
120
3
350
31
309
1
1
245
50
38
10
60
58
52 2 1 3
5 2
40 20
2
3 3
5
0
38
42
200
1 5
5 8
10
23 3
32
17
0
2016
2020
2030
2040
25
10
Coal (new)
Other Storage
Wind
Gas - CCGT
Coal
Biomass/-gas
Hydro+PS
Nuclear (new)
Sources: Draft IRP 2018. CSIR Energy Centre analysis
100
78
53 2
39 13 15
6 3
127
164
203
214
202
14 23 5 15
31 1 17 29
107 68
0
2050
Gas - CCGE
Nuclear
15
2
11
CSP
Peaking
8
2 2 4 3 14
13
DR
Solar PV
262
25
4
8
12 4
2 14 3 3 15 4
78
80
4
300
21
100
17
392
400
RE CO2 free (RE + nuclear)
2016
2020
2030
2040
2050
8%
25%
70%
(20 TWh/yr)
(79 TWh/yr)
(274 TWh/yr)
14%
30%
70%
(35 TWh/yr)
(94 TWh/yr)
(274 TWh/yr)
to DoE on 25 October 2018 Draft IRP 2018 IRP1 with Submitted storage, DSR and lower RE costs results in increased new-build wind, solar PV, storage and less NG
Installed capacity and electricity supplied from 2016 to 2050 for IRP1 with storage, DSR and higher RE cost reductions
Installed capacity
Energy mix
Total installed capacity (net) [GW]
Electricity production [TWh/yr]
196.8
200
7.2
177.3
180 160
20.7 0.6
400
4.4 11.8
63.0
0.6
87.3
80 51.6
40 20
60.5
5.1 13.1 6.3
107 (27%)
77
271
2 44 17 4 14
160 (40%)
122
18 4 18 5.1 12.8 1.9
13.6 9.9
16.9
Solar PV
Peaking
Coal (New)
2050
Nuclear
14
2045
Hydro+PS
2040
Biomass/-gas
0
2035
Nuclear (new)
17 (4%) 7 (2%) 38 (9%) 66 (17%)
103
2030
Wind
202
2025
Other Storage
Coal
209
2020
Gas
100
2016
CSP
2050
2045
2040
2035
2030
DR
Notes: NG = Natural gas Sources: Draft IRP 2018. CSIR Energy Centre analysis
(1%)
4
63.8
45.6
31.7
2025
2020
18
2016
0
1.5 57.8 1.5 5.1 3.4 1.9 37.4
399 4
31
200
4.8 0.6 17.1 0.5 15.3 5.1 8.7 1.2 1.9
341
320
249
41.7
100
298
300
112.8
120
60
361
147.2
140
383
Demand: Median First new-builds: PV (2027) Wind (2027) OCGT (2024) Storage (2027)
6.5 GW 2.1 GW 1.9 GW 1.1 GW
Submitted to DoE on 25 October 2018 Risk-adjusted scenario with Low EAF requires earlier new-build around 2023 too and increased absolute levels of new-build by 2030
Installed capacity and electricity supplied from 2016 to 2050 for Risk-adjusted scenario with low coal fleet EAF
Installed capacity
Energy mix
Total installed capacity (net) [GW] 198.3
200
160
153.6
140
11.6
400
61.0
0.6
298
300
271
80
69.4 57.8 51.6 1.5 1.5 5.1 3.4 1.9 37.4
40 20
5.1 9.4 1.2 1.9
5.1 13.7 6.3
31.7
1.9
12.1 9.9
16.9
Solar PV
Peaking
Coal (New)
Sources: Draft IRP 2018. CSIR Energy Centre analysis
2050
Nuclear
2045
Hydro+PS
14
2040
Biomass/-gas
2035
Nuclear (new)
0
2030
Wind
17 (4%) 7 (2%) 33 (8%) 66 (17%)
90
2025
Other Storage
Coal
180
2020
Gas
169 (42%)
135
17 4 18
208
2016
CSP
2050
2045
2040
2035
2030
2025
2020
2016 DR
100
77
17 4 15
67.9
5.1 13.2
104 (26%)
2
200 51.8
(1%)
4
61
97.7 0.6 20.1 0.5 21.4
340
399 4
36
249
41.4
382
361 320
119.3
100
19
21.1 0.7
4.4
120
0
7.2
180.8
180
60
Electricity production [TWh/yr]
Demand: Median First new-builds: PV (2023) Wind (2023) OCGT (2023)
0.4 GW 0.2 GW 1.9 GW
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
20
Submitted to DoE on 25 October 2018
At a glance 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
21
Submitted to DoE on 25 October 2018
Going forward – Recommendations
22
•
Improvements for future IRPs
•
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
•
Optimise the existing coal fleet while remaining cognisant of opportunity cost of capital expenditure on older assets (retrofitting for improved reliability, efficiency and flexibility)
•
Inclusion of economic impacts of scenarios. At the very least – employment impacts
•
Improved approaches to better understanding demand (sector shifts, load profile shape, price elasticity of demand)
•
Better understanding the cost trajectory of all technologies for domestic application on a periodic basis
•
Develop and implement an integrated program of work on long-term system integration topics i.e. stability, system strength, reactive power/voltage control (CSIR already initiated CIGRE WG including Eskom and international SOs)
•
Focussed consideration and investigation into domestic flexibility options
Submitted to DoE on 25 October 2018
Going forward – Recommendations
23
•
Long-term – structural and strategic
• •
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
•
Further understanding just transition to address labour and socio-economic impacts in the energy sector
•
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)
•
Investigate approaches to include geospatial component of IRP – supply/network/demand (co-optimisation)
•
Further investigations into impacts/opportunities of new/emerging technologies e.g. stationary storage, EVs, DSR
Submitted to DoE on 25 October 2018
Formal comments on Draft IRP 2018
1 Executive Summary 2 Background 3 Draft IRP 2018 scenarios 4 Draft IRP 2018 employment impacts 5 Draft IRP 2018 energy planning risks 6 System services and technical considerations
24
Submitted to DoE on 25 October 2018
Integrated Resource Plan (IRP): Process for power generation capacity expansion in South Africa Inputs
Planning / simulation world
1) Demand Forecast 2) Existing Supply Forecast: • Plants under construction • Preferred bidders • Decommissioning • Plant performance 3) New Supply Options: • Technology costs assumptions • Technology technical characteristics 4) Constraints: • CO2 limits • Security/adequacy of supply level
Inputs
Actuals / real world
1
25
2
LT = Long-term MT/ST = Medium-term/Short-term
• Ministerial Determinations for new technology specific generation capacity
Output IRP modelling framework (PLEXOS®) LT1 techno-economic least-cost optimisation MT/ST2 production cost testing system adequacy (security of supply)
Procurement (competitive tender e.g. REIPPPP, coal IPPPP)
Per 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)?
Outcomes • Preferred bidders • MW allocation • Technology costs actuals (Ø IPP tariffs)
Submitted to DoE on 25 October 2018
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
Not optimised in PLEXOS modelling framework (Assumption consistent for all scenarios = 0.20 R/kWh)
[bR/yr]
• CAPEX (plant level) • FOM1 • VOM2 • Fuel • Shallow grid connection costs
Not considered
Not considered
Partially considered previously (quantified for system inertia)
Costs included in optimisation model:
Not considered
Costs excluded in optimisation model:
Generation (Gx)
Tx network (shallow)
System services (reserves)
Tx network (deep)
System services (other)
Other Distribution (metering, network billing, customer (Dx) services,
Total system cost
• 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
overheads) 1
26
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.
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
Scenario 1 Scenario 2 Constraint: RE limits Planning Facts Least Cost Base Case
Constraint: e.g. forcing in of nuclear, CSP, biogas, hydro, others
Constraint: Advanced CO2 cap decline
Scenario 3 27
Sources: Based on Draft IRP 2018
Case
Cost
Base Case
Base
Scenario 1
Base + Rxx bn/yr
Scenario 2
Base + Ryy bn/yr
Scenario 3
Base + Rzz bn/yr
…
…
1. Public consultation on costed scenarios 2. Policy adjustment of Base Case 3. Final IRP for approval and gazetting
Submitted to DoE on 25 October 2018
Reminder: IRP 2010 planned the electricity mix until 2030 Installed capacity and electricity supplied from 2010 to 2030 as planned in the IRP 2010
Installed capacity
Energy mix
Total installed net capacity [GW]
Electricity supplied [TWh]
150
600
125
500 441 392
400
100 86.6 8.4
73.6
75
9.2
62.7
50
25
0
28
43.0 0.0 2.4 2.1 0.0 1.8 0.0 35.9
2010
5.8
0.7 2.8
4.8
9.6
6.3
12 4
75
1.2
300
259
4.8 7.3
0.5 3.4 0.0 1.5
343
4 6
24 22
13
2.4
200
4 13 0 0
10
14 21
14
12 45
1.8 284 230
100
261
237
34.8
2020
2025
0
2030
Solar PV
Other
Gas
Coal (new)
CSP
Hydro
Nuclear (new)
Coal
Wind
Peaking
Nuclear
RE CO2 free
2010
2020
2025
2030
5%
14%
(12 TWh/yr)
(62 TWh/yr)
10%
34%
(25 TWh/yr)
(149 TWh/yr)
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
Submitted to DoE on 25 October 2018
Draft IRP 2016 Base Case planned until 2050 Installed capacity and electricity supplied from 2016 to 2050 as planned in the Draft IRP 2016 Base Case
Installed capacity
Energy mix Electricity supplied [TWh]
Total installed net capacity [GW] 150
600
135.7
528
15.8
125
28
500
108.7 12.4 1.1
100 82.5 7.5
75
11.1
50
49.8
0.2 1.5 1.3 3.4 4.1 0.3 1.9 0.4
1.1 0.7 0.0
8.9 7.3 6.1 1.9 0.0 5.3
25 36.8
21.3 0.7 12.8 16.8 7.6 1.9 2.7 14.3
32.6 17.2
0
2016 Solar PV
29
2030
2040
Other storage
Gas
434 30.4
5
400
350
0.5 13.8
300 246
22.0
2 15 0
2
200
7.6
22
0
13 36 16 0
5 5 1 24 15
34
93 3
1 49
66 5 45
1
33
20
148
33 15
105 20.4
100
0.0 15.0
200
101
203 117
10.2
0
2050 Nuclear
CSP
Other
Hydro+PS
Coal (new)
Wind
Peaking
Nuclear (new)
Coal
RE CO2 free
2016
2030
2040
72
2050
10%
29%
(25 TWh/yr)
(152 TWh/yr)
10%
57%
(40 TWh/yr)
(300 TWh/yr)
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
Submitted to DoE on 25 October 2018
Formal comments on Draft IRP 2018
1 Executive Summary 2 Background 3 Draft IRP 2018 scenarios 4 Draft IRP 2018 employment impacts 5 Draft IRP 2018 energy planning risks 6 System services and technical considerations
30
Submitted to DoE on 25 October 2018
A range of scenarios have been assessed as part of the Draft IRP 2018 with key parameter changes
31
Submitted to DoE on 25 October 2018 Draft IRP 2018 (IRP1) - Least-cost deploys considerable wind, solar PV and NG capacity to 2030 and beyond as the coal fleet decommissions
Installed capacity and electricity supplied from 2016 to 2050 as planned in the Draft IRP 2018
Installed capacity
Energy mix
Total installed capacity (net) [GW]
Electricity production [TWh/yr]
160
148 1
140 119
120
353
31
313
1
1
245
50
38
10
60
58
52 2 1 3
5 2
40 20
2
3 3
5
0
38
42
200
1 5
5 8
10
23 3
32
17
0
2016
2020
2030
2040
25
10
Coal (new)
Other Storage
Wind
Gas - CCGT
Coal
Biomass/-gas
Hydro+PS
Nuclear (new)
Sources: Draft IRP 2018. CSIR Energy Centre analysis
100
78
54 2
42 14 15
7 3
129
164
203
215
202
15 23 5 15
31 17 1 29
107 68
0
2050
Gas - CCGE
Nuclear
15
2
11
CSP
Peaking
8
2 2 4 3 15
13
DR
Solar PV
264
25
4
3
8
12 4
2 14 3 3 15 4
78
80
4
300
21
100
32
391
400
RE CO2 free (RE + nuclear)
2016
2020
2030
2040
2050
8%
26%
70%
(20 TWh/yr)
(83 TWh/yr)
(274 TWh/yr)
14%
31%
70%
(35 TWh/yr)
(98 TWh/yr)
(274 TWh/yr)
Submitted to DoE on 25 October 2018
Draft 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 it Installed capacity and electricity supplied from 2016 to 2050 as planned in the Draft IRP 2018
Installed capacity
Energy mix
Total installed capacity (net) [GW]
Electricity production [TWh/yr]
140 125 1
120 103
353
25
313
1
100
300
18 1
77
80 52 2 1 3
5 2
40 20
38
2 5
3 3
9
1
58
13 5
4
8 7
1
14 6 5
32
17
0
2016
2020
4
2030
2040
12
10
100
44
13 15
203
214
Other Storage
Wind
Gas - CCGT
Coal
Biomass/-gas
Hydro+PS
Nuclear (new)
4 47 2 90
9 8 29 14 14 15 33
197
3 63
110
31 8 31 80
106 67
0
2050 Coal (new)
Sources: Draft IRP 2018. CSIR Energy Centre analysis
15
22
12
Gas - CCGE
Nuclear
8
2 2 4 3 15
17
CSP
Peaking
200
15
263
4 2
11
DR
Solar PV
245
26 8
9 2 42
30
1
1
60
33
393
400
RE CO2 free (RE + nuclear)
2016
2020
2030
2040
2050
8%
26%
52%
(20 TWh/yr)
(80 TWh/yr)
(203 TWh/yr)
14%
30%
52%
(35 TWh/yr)
(95 TWh/yr)
(203 TWh/yr)
Submitted to DoE on 25 October 2018 Draft IRP 2018 (IRP5) – Market linked NG price means in less NG usage, notable capacity for system adequacy and increased new-build coal
Installed capacity and electricity supplied from 2016 to 2050 as planned in the Draft IRP 2018
Installed capacity
Energy mix
Total installed capacity (net) [GW]
Electricity production [TWh/yr]
140 125 1
120 104
313 300
18 1
77
80
1
1
60
58
52 2 1 3
5 2
40
2 5
3 3
30
4 8
13 6
4 9 2
8 6
13
17
20 3
20
38
42
8
32
17
0
2016
2020
2030
2040
Coal (new)
Other Storage
Wind
Gas - CCGT
Coal
Biomass/-gas
Hydro+PS
Nuclear (new)
Sources: Draft IRP 2018. CSIR Energy Centre analysis
15
22 44
14
15
107
89
11 4 29 15
4 11
51
100
203
215
199
5
32 13
102
104
0
2050
Gas - CCGE
Nuclear
8
2 2 4 3 15
4 2
64
4 47 2
64 10
CSP
Peaking
200
15
264
16
DR
Solar PV
245
26
9
1
3
353
25
1
100
34
391
400
RE CO2 free (RE + nuclear)
2016
2020
2030
2040
2050
8%
26%
51%
(20 TWh/yr)
(81 TWh/yr)
(202 TWh/yr)
14%
30%
51%
(35 TWh/yr)
(95 TWh/yr)
(202 TWh/yr)
Submitted to DoE on 25 October 2018 Draft IRP 2018 (IRP6) – Carbon Budget limits new-build coal capacity and deploys new-build nuclear capacity instead
Installed capacity and electricity supplied from 2016 to 2050 as planned in the Draft IRP 2018
Installed capacity
Energy mix
Total installed capacity (net) [GW]
Electricity production [TWh/yr]
140 125 120
353
25
103
313
1
100
300
18
77
80 52 2 1 3
5 2
40 20
1
58
38
2 5
3 3
30
4
26
13 5
3 2
8 5
12
13
17
9
14
4
2
32
17
0
2016
2020
245
8
9 2 42
1 1 9
1
60
2030
2040
200
100
10
Gas - CCGE
Coal (new)
Other Storage
Wind
Gas - CCGT
Coal
Biomass/-gas
Hydro+PS
Nuclear (new) Nuclear
Sources: Draft IRP 2018. CSIR Energy Centre analysis
203
8 15
2 2 4 3 15
215
4 2
22 44
13
15
4 47 2 90
11 4
199
30 12 25 33 15 97
3 67
106
31 12 47 55
13 57
0
2050
CSP
Peaking
15
264
7
2
DR
Solar PV
35
391
400
1
RE CO2 free (RE + nuclear)
2016
2020
2030
2040
2050
8%
26%
52%
(20 TWh/yr)
(81 TWh/yr)
(203 TWh/yr)
14%
30%
66%
(35 TWh/yr)
(96 TWh/yr)
(258 TWh/yr)
Submitted to DoE on 25 October 2018
Draft IRP 2018 (IRP7) – Market linked NG price & Carbon Budget combines IRP 5&6 meaning less NG and coal capacity, increased nuclear new-build Installed capacity and electricity supplied from 2016 to 2050 as planned in the Draft IRP 2018
Installed capacity
Energy mix
Total installed capacity (net) [GW]
Electricity production [TWh/yr]
140 125 1
120
353
25
104
300
18 1
77
80
1
60
52 2 1 3
5 2
40
3
38
8
8 5
13
8
15
18
3
42
4
2016
2020
2030
6 2
17
0
2040
10 4 10
CSP
Gas - CCGE
Coal (new)
Other Storage
Wind
Gas - CCGT
Coal
Biomass/-gas
Hydro+PS
Nuclear (new)
Peaking
Nuclear
Sources: Draft IRP 2018. CSIR Energy Centre analysis
100
15
8 15
2 2 4 3 15
4 2
23 44 26
15
90 3 4
29 5 12
64
106
31 13 17
203
215
192
9
14
76 22
99 58
0
2050
DR
Solar PV
200
264
3
43
6
2
32
245 4
8
2
20
30
26
13
2 5
3
9
1
58
1
4 47 2
313
1
100
36
391
400
RE CO2 free (RE + nuclear)
2016
2020
2030
2040
2050
8%
30%
51%
(20 TWh/yr)
(95 TWh/yr)
(201 TWh/yr)
14%
35%
70%
(35 TWh/yr)
(110 TWh/yr)
(277 TWh/yr)
Submitted to DoE on 25 October 2018 Draft IRP 2018 (IRP2) – Upper Demand forecast with similar outcomes to IRP3 just with earlier first new-build and more new-build overall
Installed capacity and electricity supplied from 2016 to 2050 as planned in the Draft IRP 2018
Installed capacity
Energy mix
Total installed capacity (net) [GW]
Electricity production [TWh/yr]
140
1
120
108
100
60
58
52 2 1 3
5 2
40 20
1
38
2 5
3 3
321
18 30
9
2016
2020
200
15
8
15
6
28 14
3 8
2030
217
31 9 39
103
198
2040
108 68
10
0
2050 Coal (new)
Other Storage
Wind
Gas - CCGT
Coal
Biomass/-gas
Hydro+PS
Nuclear (new)
Sources: Draft IRP 2018. CSIR Energy Centre analysis
100
203
15
Gas - CCGE
Nuclear
32 11 19 17
2
8
32
111 91
43
48 15
CSP
Peaking
4
2 4 2 3 15
64
4 46 2
21
18
DR
Solar PV
266
16
17
0
300
8
8 6
7 10 2
42
378
4 2
26
14 3
400
25
245
1 9
1
3
1
1
79
80
37
428
130
RE CO2 free (RE + nuclear)
2016
2020
2030
2040
2050
8%
29%
48%
(20 TWh/yr)
(94 TWh/yr)
(207 TWh/yr)
14%
33%
48%
(35 TWh/yr)
(108 TWh/yr)
(207 TWh/yr)
Submitted to DoE on 25 October 2018 Draft IRP 2018 (IRP4) – Lower Demand forecast with similar outcomes to IRP3 just with later first new-build and less new-build overall
Installed capacity and electricity supplied from 2016 to 2050 as planned in the Draft IRP 2018
Installed capacity
Energy mix
Total installed capacity (net) [GW]
Electricity production [TWh/yr]
140 121 1
120
333
1
60
58
52 2 1 3
5 2
40
7 2 5
3 3
10 3
38
42
23
5
8 7
6
2
20
1 1 1
17 2
2016
2020
2030
200
100
15
14
33 15 14
203
208
Coal (new)
Other Storage
Wind
Gas - CCGT
Coal
Biomass/-gas
Hydro+PS
Nuclear (new) Nuclear
4 41 2
63
81
112
29 15 8 15 33
30 11 33
2 8 5
193
54
105 65
0
2050
Gas - CCGE
Sources: Draft IRP 2018. CSIR Energy Centre analysis
38
2040
10
CSP
Peaking
8
3
11
DR
Solar PV
4
4
8 17
0
16
2 4 2 3 15
12
12 4 5
32
8
256
245
30
1
69
290
300
16
80
372
25
96
100
400
RE CO2 free (RE + nuclear)
2016
2020
2030
2040
2050
8%
23%
55%
(20 TWh/yr)
(66 TWh/yr)
(204 TWh/yr)
14%
28%
55%
(35 TWh/yr)
(80 TWh/yr)
(204 TWh/yr)
Submitted to DoE on 25 October 2018
Draft IRP 2018 (Recommended Plan) includes RE new-build limits and policy adjustment for new-build coal and imported hydro Installed capacity and electricity supplied from 2016 to 2030 as planned in the Draft IRP 2018
Installed capacity
Energy mix
Total installed capacity (net) [GW]
Electricity production [TWh/yr]
100 400 80
60
74.1 61.8
57.8
7.6 3.1 8.1 1.9 1.0
1.6 5.1 3.4 1.9
20
292
300
264
245
200
100
37.6
231
217
203
31.7
1.0 GW 0.7 GW 0.2 GW 2.3 GW
2030
2029
Nuclear
First new-builds: Coal (2023) PV (2025) Wind (2025) CC-GE (2026)
2028
Peaking
2027
Solar PV
2026
Nuclear (new)
2025
Hydro+PS
2024
Biomass/-gas
2023
Coal
2022
Gas - CCGT
2021
Wind
2020
Other Storage
2019
Coal (New)
2018
Gas - CCGE
2017
CSP
2016
2030
2029
2028
2027
2026
2025
2024
2023
2022
2021
2020
2019
2018
2017
2016
0
DR
Sources: Draft IRP 2018. CSIR Energy Centre analysis
39
0.3 8.0 0.6 11.5
51.91.5
40
0
14 (7%) 35 313(17%) 28 (14%) 8 (4%) 3 (1%) 15 (7%) 6 (3%) 199 (97%)
Submitted to DoE on 25 October 2018 CO2 emissions trajectories for PPD Moderate never binding (only CB) while water use declines as expected as coal fleet decommissions
Scenarios from Draft IRP 2018
CO2 emissions
Water usage
Electricity sector CO2 emissions [Mt/yr]
Electricity sector Water usage [bl/yr]
300
275
300
275
250
250 210
200 150
178 IRP1
160
IRP3
200 150
IRP5
100
IRP3 92 82
IRP6 IRP7
50
IRP2 IRP4 PPD (Moderate)
40
PPD equiv.
100
2750 Mt
1800 Mt
920 Mt
> 2750 Mt
2720 Mt
2325 Mt
IRP5 IRP6
50
0 2015 2020 2025 2030 2035 2040 2045 2050 Carbon Budget
IRP1
IRP7 IRP2 IRP4
0 2015 2020 2025 2030 2035 2040 2045 2050
59
36
Submitted to DoE on 25 October 2018
Average tariff (without CO2 costs) across scenarios revealing how IRP1 (Least-cost) is 12% cheaper than the most expensive scenario (IRP7) Average tariff in R/kWh (Jan-2017 Rand) 1.60
1.51
1.40
1.35
+12%
1.20 1.00 0.80
0.84
IRP1 IRP3 IRP5 IRP6 IRP7 Recommended Plan
0.60 0.40 0.20 0.00 2015
2020
2025
Note: Shift from 2017 to 2018 based on immediate move to cost reflectivity Sources: Draft IRP 2018. CSIR Energy Centre analysis
41
2030
2035
2040
2045
2050
Submitted to DoE on 25 October 2018
Total system cost increase as the power system grows (as expected) IRP1 is least-cost and ≈R60-bn/yr cheaper than IRP7 by 2050 Total system cost (Jan-2017 Rand) [bR/yr] 591
600
529
+63 (+12%)
500 400 300 200
IRP1 IRP3 IRP5 IRP6 IRP7 Recommended Plan
209
100 0 2015
2020
2025
Note: Shift from 2017 to 2018 based on immediate move to cost reflectivity Sources: Draft IRP 2018. CSIR Energy Centre analysis
42
2030
2035
2040
2045
2050
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 2030 Energy Mix
Cost
in 2030
in 2030
202 (64%)
15 14 42 2
37
IRP3
197 (63%)
199 (63%)
158 13 44 2
15
14
199 (63%)
15
13
44 2
192 (61%)
15 4 26
44 2
206 (64%)
44 2
217
199
4
361
215
199
4
367
213
198
4
362
215
199
373
207
191
375
215
199
4 23
15 8 28 6 (2%) 3
43
360
22
3
Rec.
4
22
4 11
IRP7
Water usage (billion-litres/yr)
22
4 11
IRP6
CO2 emissions (Mt/yr)
25
9
IRP5
in 2030
Total system cost1 (R-billion/yr)
Demand: 313 TWh
IRP1
Environment
35 2
2
14
Coal
Nuclear
Gas - CCGT
Peaking
Wind
Solar PV
Other Storage
Coal (New)
Nuclear (new)
Gas - CCGE
Hydro+PS
CSP
Biomass/-gas
DR
Sources: DoE Draft IRP 2018; Eskom on Tx, Dx costs; CSIR analysis; flaticon.com
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 2040 Energy Mix
Cost
in 2040
in 2040
107 (30%)
in 2040
Total system cost1 (R-billion/yr)
Demand: 353 TWh
IRP1
Environment
15 23 15
129
2
CO2 emissions (Mt/yr) 441
54
4
90
2 47
4
466
89
2 47
4
473
90
2 47
4
477
90
2 47
4
123
Water usage (billion-litres/yr) 59
5
IRP3
106 (30%)
151414 29
153
66
33 (9%)
IRP5
104 (29%)
15 11 29
168
70
51 (14%) 4
IRP6
97 (27%)
IRP7
99 (28%)
15 33
15 9 (2%)
25 12 30
43
12 29
353
494
116
56
119
58
5
Rec.
44
Coal
Nuclear
Gas - CCGT
Peaking
Wind
Solar PV
Other Storage
Coal (New)
Nuclear (new)
Gas - CCGE
Hydro+PS
CSP
Biomass/-gas
DR
Sources: DoE Draft IRP 2018; Eskom on Tx, Dx costs; CSIR analysis; flaticon.com
Submitted to DoE on 25 October 2018
By 2050 - Least-cost mix is 70% solar PV and wind, ≈R30-60 bn/yr cheaper than alternatives, least CO2 emissions and least water usage 2050 Energy Mix
Cost
in 2050
in 2050
68 (17%)
IRP3
66 (17%)
in 2050
Total system cost1 (R-billion/yr)
Demand: 392 TWh
IRP1
Environment
29 17 31
164
78
CO2 emissions (Mt/yr) 529
3
82
31 8 31
110
63
3
560
13 32
107
64
3
564
106
67
3
106
64
3
Water usage (billion-litres/yr) 36
160
54
80 (20%)
IRP5
64 (16%) 102 (26%)
IRP6 57 (15%)
55
47
178
59
5
12 31
580
92
36
90
38
13 (3%)
IRP7 58 (15%)
76
22 (6%)
17
31
591
13
Rec.
45
Coal
Nuclear
Gas - CCGT
Peaking
Wind
Solar PV
Other Storage
Coal (New)
Nuclear (new)
Gas - CCGE
Hydro+PS
CSP
Biomass/-gas
DR
Sources: DoE Draft IRP 2018; Eskom on Tx, Dx costs; CSIR analysis; flaticon.com
Submitted to DoE on 25 October 2018
Formal comments on Draft IRP 2018
1 Executive Summary 2 Background 3 Draft IRP 2018 scenarios 4 Draft IRP 2018 employment impacts 5 Draft IRP 2018 energy planning risks 6 System services and technical considerations
46
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 freely available economic tool to understand economic changes (jobs focus at this stage) for energy technology choices I-JEDI has been customised for application to the South African environment by the CSIR team CSIR utilised the developed I-JEDI tool for South Africa to assess the Recommended Plan in the 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 the country (localised) • These are then used in a country-specific input-output (I-O) model to estimate employment (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
47
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
Construction jobs [‘000]
Operations jobs (net) [‘000]
500
500
450
450
400
400
350
350
300
300
250
250
200
200
150
258
217
202
183
2030
233
2029
245
50
Sources: Draft IRP 2018; CSIR Energy Centre analysis Note: Job potential includes direct, indirect and induced jobs; Nuclear is estimated based on existing experience at Koeberg (KPMG, 2017)
2027
Coal
2026
Nuclear
2025
Gas
265
2028
0
264
2024
Wind
24
265
2023
2028
EG (PV)
24
271
2022
2027
2025
2024
48
2023
2022
2021
Solar PV
100
278
2021
35
45
38 4 52
1 1 323 1 3221 2 7 3 7 3053 4 294 4 7 1 7 1 7 1 7 1 5 6 278 1 44 1 4 4 4 44 7 4 7 44 44 1 44 14 44 2 5 7 18 8 2 44 23 9 44 32 11 44 44 44
2020
57
38 4 52
2030
31 93 21 3 36 1 22 3 39 36 37 3 54 16 21 35 32 3 16 3 5 5 26 11 9 29
54
12
150
2029
4
82
2026
38 3
66
2020
0
131 134 141 117 117 38 38 4
100 50
3341
Submitted to DoE on 25 October 2018
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 Jobs (net) (construction + operations) [’000] 500
400 350 300
437
436
450 10 (3%) 365 3 (1%) 14 (4%) 44 (12%) 7 (2%)
398
394 14 3 25 7
359
3 4 3
7 44
44
342
7 4
7 44
362
39
22 10 4 12
20
44
33 44
250
41
42 4
4
60 42 44
434
64
403
43 5
5
44 5
62 61
49 44
62 47
44 44
200 150
287 (79%)
300
297
280
270
258
245
100
395 45 (11%) 5 (1%) 62 (16%) 56 (14%) 44 (11%)
233
217
202
183 (46%)
2027
2028
2029
2030
50 0
2020 Solar PV
49
2021 EG (PV)
2022 Wind
2023 Gas
2024
2025
Nuclear
2026 Coal
Sources: Draft IRP 2018; CSIR Energy Centre analysis Note: Job potential includes direct, indirect and induced jobs; Nuclear is estimated based on existing experience at Koeberg (KPMG, 2017)
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
Construction jobs [‘000]
Operations jobs (net) [‘000]
500
500
450
450
400
400
350
350
300
300
250
250
200
200
150
87
100
107
107
107
245 104
99
217 94
183 88
83
80
76
73
74
68
63
57
79
77
76
75
76
74
70
67
62
58
52
2024
2025
2026
2027
2028
2029
2030
2030
Sources: Draft IRP 2018; CSIR Energy Centre analysis Note: Job potential includes direct, indirect and induced jobs
2029
Direct
2028
2027
2026
2025
2024
2023
2022
2021
Indirect
0
82
2023
5
83
2022
50
84
81
2021
29 32 16
Induced
50
109
265
2020
9 2020
0
112
265
150
100 50
278
Submitted to DoE on 25 October 2018
Net job losses in coal overall of ≈100k, direct jobs in coal shifting from ≈80k in 2016 to ≈50k by 2030 Jobs (net) (construction + operations) [’000] 500 450 400 -104 (-36%)
350 300 250
287
300 120
115
297 118
280 112
200 150
94
90
93
88
270 108
84
100 50 0
82
86
2020
2021
Induced
51
85
2022 Indirect
Sources: Draft IRP 2018; CSIR Energy Centre analysis Note: Job potential includes direct, indirect and induced jobs
258 104
80
245 99
76
233 94
73
217 88
202 81
68
63
183 74
57
80
77
74
70
67
62
58
52
2023
2024
2025
2026
2027
2028
2029
2030
Direct
Submitted to DoE on 25 October 2018
Formal comments on Draft IRP 2018
1 Executive Summary 2 Background 3 Draft IRP 2018 scenarios 4 Draft IRP 2018 employment impacts 5 Draft IRP 2018 energy planning risks 5.1 Scenarios 5.2 Descriptive comments 6 System services and technical considerations
52
Submitted to DoE on 25 October 2018
Formal comments on Draft IRP 2018
1 Executive Summary 2 Background 3 Draft IRP 2018 scenarios 4 Draft IRP 2018 employment impacts 5 Draft IRP 2018 energy planning risks 5.1 Scenarios a
Impact of stationary storage
b
Impact of Demand Side Response (DSR)
c
Technology learning
d
Risk-adjusted scenario
e
Existing coal fleet performance
5.2 Descriptive comments 6 System services and technical considerations
53
Submitted to DoE on 25 October 2018
Formal comments on Draft IRP 2018
1 Executive Summary 2 Background 3 Draft IRP 2018 scenarios 4 Draft IRP 2018 employment impacts 5 Draft IRP 2018 energy planning risks 5.1 Scenarios a
Impact of stationary storage
b
Impact of Demand Side Response (DSR)
c
Technology learning
d
Risk-adjusted scenario
e
Existing coal fleet performance
5.2 Descriptive comments 6 System services and technical considerations
54
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?
55
Submitted to DoE on 25 October 2018
Stationary storage (excl. pumped storage): 200 $/kWh (2030), 150 $/kWh (2040), 100 $/kWh (2050) Overnight capital cost [R/kWh] (Jan-2017-Rand) 14 000
IRP2018 (Li-Ion 1hr)
This scenario (Li-Ion 3hr)
CSIRO - Low (2015)
IDC - 2016
This scenario (Li-Ion 1hr)
BNEF (2017)
Nykvuist - Low (2015)
IRENA - High (2017)
IRP2018 (Li-Ion 3hr)
CSIRO - High (2015)
Nykvuist - High (2015)
[USD/kWh] 1 000 900
-81%
12 000
-75%
800
10 000
700 600
8 000
500 6 000
400
300
4 000 2 800
200
2 100
2 000 0 2010 56
1 400
2015
2020
2025
2030
2035
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)
2040
2045
100
0 2050
to DoE on 25 October 2018 Draft IRP 2018 IRP1 with Submitted storage cost declines means notably less NG, with storage deployed from 2027, increased solar PV and wind
Installed capacity and electricity supplied from 2016 to 2030 as planned in the Draft IRP 2018
Installed capacity
Energy mix
Total installed capacity (net) [GW]
Electricity production [TWh/yr]
100
400
90
350
81.7
80
3.2 0.6
70
14.3
60 50
60.2
57.8
0.5
1.5 5.1 3.4 1.9
5.1 8.6
37.4
31.7
10
150 209 (64%)
Demand: Median First new-builds: PV (2027) Wind (2027) OCGT (2024) Storage (2027)
6.2 GW 1.2 GW 1.9 GW 1.3 GW
2030
2029
2028
2027
2026
Coal (New)
2025
Peaking
2024
Solar PV
2023
Nuclear
2022
Hydro+PS
2021
Biomass/-gas
2020
Nuclear (new)
2019
Wind
2018
Other Storage
Coal
2017
Gas
2016
CSP
249
227
209
50 0
2030
2029
2028
2027
2026
2025
2024
2023
2022
2021
2020
2019
2018
2017
2016
DR
Sources: Draft IRP 2018. CSIR Energy Centre analysis
57
200
100
20
271 249
1.9
30
0
250
(8%) 38 (12%) 18 (5%) 7 (2%) 14 (4%)
298
300
13.3
51.61.5
40
32626
to DoE on 25 October 2018 Draft IRP 2018 IRP1 with Submitted storage cost declines means less NG, increased solar PV and wind with considerable deployment post-2030
Installed capacity and electricity supplied from 2016 to 2050 for IRP1 with Demand Side Response
Installed capacity
Energy mix
Total installed capacity (net) [GW]
Electricity production [TWh/yr]
200
429
180
400
169.1
160
151.2
140
129.1
120
11.0
103.8
57.8 51.6 1.5
60.2
1.5 5.1 3.4 1.9 37.4
40 20
298
48.9
271 249
200
3.2 0.6 14.3 0.5 13.3 5.1 8.6 2.6 1.9
7.6 11.9 7.7
7.6 10.4 1.9
15.8 9.9
16.9
60 2
38 18 7 14
110
Solar PV
Peaking
Coal (New)
Notes: Assumed capacity factors for wind and solar PV differ slightly to IRP1 Sources: Draft IRP 2018. CSIR Energy Centre analysis
0
2050
Nuclear
111
2045
Hydro+PS
209
2040
Biomass/-gas
23 14
2035
Nuclear (new)
209
2030
Wind
100
2025
Other Storage
Coal
33 (8%) 5 (1%) 48 (12%) 71 (18%)
3
2020
Gas
153 (39%)
33
2016
CSP
2050
2045
2040
2035
2030
2025
DR
4
26
56.2
39.4
31.7
2020
2016
58
326 300
81.7
80
0
352
19.7 0.6
0.6
4 (1%) 83 (21%)
375
32.2
100
60
404
Demand: Median First new-builds: PV (2027) Wind (2027) OCGT (2024) Storage (2027)
6.2 GW 1.2 GW 1.9 GW 1.3 GW
Submitted to DoE on 25 October 2018 Difference in installed capacity and energy mix with storage cost declines relative to IRP1, less NG with increased solar PV
Installed capacity and electricity supplied from 2016 to 2050 for IRP 1 with storage cost declines
Installed capacity
Energy mix
Difference - Total installed capacity (net) [GW]
Difference - Electricity production [TWh/yr]
50
50
40
40
30
30 20
20 10 3 2 -2
-10
-3
-20
-12
-10
-8
-20
Solar PV
Peaking
Coal (New)
-6 -1
2050
Nuclear
-6
2045
Hydro+PS
2
2040
Biomass/-gas
3
-2
2035
Nuclear (new)
2030
Wind
2025
Other Storage
Coal
2020
Gas
-4 -1
2016
CSP
2050
2045
2040
2035
-50
2030
-50
2025
-40
2020
-40
DR
6 -2
-17
-30
2016
59
-2
0
-30
Sources: Draft IRP 2018. CSIR Energy Centre analysis
4 1
12
3 1 -9
-2 -1
20
10
11
0
20
to DoE on 25 October 2018 CO2 emissions trajectoriesSubmitted for PPD Moderate never binding while water use declines as expected as coal fleet decommissions
IRP 1 with storage cost declines
CO2 emissions
Water usage
Electricity sector CO2 emissions [Mt/yr]
Electricity sector Water usage [bl/yr]
300
275
300
275
250
250 210
200
200
150
150
100 50
82
IRP1
78
IRP1 with storage cost declines PPD (Moderate)
0 2015 2020 2025 2030 2035 2040 2045 2050 Carbon Budget 60
PPD equiv.
2750 Mt
1800 Mt
920 Mt
> 2750 Mt
2720 Mt
2325 Mt
100 50
IRP1 IRP1 with storage cost declines
0 2015 2020 2025 2030 2035 2040 2045 2050
36 35
Submitted to DoE on 25 October 2018
Total system cost: IRP1 with storage cost declines ≈R8 bn/year less expensive by 2050 than IRP1, marginal difference before 2030 Net Present Value System Cost
Total System Cost
(2016 - 2050)
Total system cost in bR/yr (Jan-2017 Rand)
bR
600 529 500
441
400
358
437
4 018
4 005
IRP1
Storage cost declines
299
300 200
521
-12 (-0.3%)
199
100 0 2015
61
2020
2025
2030
2035
2040
IRP1
IRP1 with storage cost declines
2045
2050
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. Sources: Draft IRP 2018. CSIR Energy Centre analysis.
Submitted to DoE on 25 October 2018
Formal comments on Draft IRP 2018
1 Executive Summary 2 Background 3 Draft IRP 2018 scenarios 4 Draft IRP 2018 employment impacts 5 Draft IRP 2018 energy planning risks 5.1 Scenarios a
Impact of stationary storage
b
Impact of Demand Side Response (DSR)
c
Technology learning
d
Risk-adjusted scenario
e
Existing coal fleet performance
5.2 Descriptive comments 6 System services and technical considerations
62
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
63
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) Impact of typical EV charging on RSA demand profile
Typical EV charging profiles 0.12 Hourly electricity demand (GW)
60
Charging Fraction (%)
0.10 0.08 0.06 0.04 0.02 0.00
50 40 30 20 10 0
0
2
4
6
8 10 12 14 16 18 20 22 24
+2.2 (+5%)
0
2
4
6
8 10 12 14 16 18 20 22 24
Hour
Hour EPRI (2007)
Base Case: No EVs
California Energy Commission and NREL (2018)
3 million electric vehicles (9-mln vehicle parc)
U.S Department of Energy (2014)
64
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)
Submitted 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 resource with intra-day controllability (can be dispatched as needed on any given day) based on power system needs i.e. vehicle-to-grid (V2G) Key input parameters to estimate potential demand shaping via electric motor vehicles: • • • • • • • •
65
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
Submitted 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
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
[%]
0-0
1.5
8.1
28.5
48.9
[mln]
0-0
0.1
1.0
4.6
10.0
EVs adoption Number of EVs
66
EVs energy requirement
[TWh/a]
-
0.5
3.7
17.1
37.0
EVs energy requirement EVs (demand increase) EVs (demand decrease)
[GWh/d] [MW] [MW]
-
1.3 -
10.1 4 600 400
46.8 44 300 2 000
101.4 95 800 4 200
Sources: CSIR estimates; StatsSA; eNaTis
Submitted 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 on power system needs Key input parameters to estimate potential demand shaping via EWH: • • • • • • • •
67
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)
Submitted 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
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
[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
Residents per HH
Demand shaping adoption
68
[%]
-
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
Sources: CSIR estimates; StatsSA; AMPS survey; Stastista; Eskom; Draft IRP 2016
to DoE on 25 October 2018 Draft IRP 2018 IRP1 with Submitted 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
Installed capacity
Energy mix
Total installed capacity (net) [GW]
Electricity production [TWh/yr]
200 180
167.0
160
149.1
140
4.4 0.6
81.3
80 57.8 51.6 1.5
40 20
13.4 10.7
271
200
0.5 5.1
7.6
4.1 1.9
20.2
10.7
2
39 18 10 14
104
209
9.9
209
Solar PV
Peaking
Coal (New)
71 (18%)
2050
Nuclear
34 (9%) 3 (1%) 65 (16%)
2045
Hydro+PS
2040
Biomass/-gas
2035
Nuclear (new)
2030
Wind
2025
Other Storage
Coal
0
2020
Gas
158 (40%)
114
2016
CSP
2050
2045
2040
2035
2030
2025
DR
(1%) 64 (16%)
35 3 30 14
23.8
1.9
16.9
Notes: NG = Natural gas Sources: Draft IRP 2018. CSIR Energy Centre analysis
100
398 4
54
7.6 22.2
379
4
23
37.3
31.7
2020
69
2016
0
60.5
1.5 5.1 3.4 1.9 37.4
12.8
298
300 249
58.2 0.6
339
320
29.3
94.3
100
360
7.2 0.7 37.4
128.7
120
60
400
Demand: Median First new-builds: PV (2027) Wind (2027) OCGT (2024)
5.2 GW 1.1 GW 1.9 GW
Submitted to DoE on 25 October 2018 Difference 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
Installed capacity Difference - Total installed capacity (net) [GW]
Difference - Electricity production [TWh/yr]
50
50
40
40
30
30
20
20
10
10
0
-1 1
1 -1
7
4 -1
Nuclear
Solar PV
Peaking
Coal (New)
1 -1
2050
Hydro+PS
1
2045
Biomass/-gas
2040
Nuclear (new)
2035
Wind
2030
Other Storage
Coal
2025
Gas
2020
CSP
-3 1
-4
2016
-50
2050
-50
2045
-40
2040
-40
2035
-30
2030
-30
2025
-20
2020
-20
2016
-10
DR
1 2 2
0 -10
Sources: Draft IRP 2018. CSIR Energy Centre analysis
70
Energy mix
to DoE on 25 October 2018 CO2 emissions trajectoriesSubmitted for PPD Moderate never binding while water use declines as expected as coal fleet decommissions
IRP 1 with Demand Side Response
CO2 emissions
Water usage
Electricity sector CO2 emissions [Mt/yr] 300
Electricity sector Water usage [bl/yr] 275
300
275
250
250 210
200
200
150
150
100 50
82 82
IRP1
50
IRP1 with DSR PPD (Moderate)
0 2015 2020 2025 2030 2035 2040 2045 2050 Carbon Budget 71
PPD equiv.
100
2750 Mt
1800 Mt
920 Mt
> 2750 Mt
2720 Mt
2325 Mt
IRP1 IRP1 with DSR
0 2015 2020 2025 2030 2035 2040 2045 2050
36 36
Submitted to DoE on 25 October 2018
Total system cost: IRP1 with DSR marginal difference in total system cost relative to IRP1 Net Present Value System Cost
Total System Cost
(2016 - 2050)
Total system cost in bR/yr (Jan-2017 Rand)
bR
600
529
500
441 360
400
4 018
4 015
IRP1
DSR
-2 (0.1%)
299
300 200
440
199
100 0 2015
2020
2025 IRP1
72
2030
2035
2040
2045
2050
IRP1 with DSR
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. Sources: Draft IRP 2018. CSIR Energy Centre analysis. Eskom on Tx, Dx costs
Submitted to DoE on 25 October 2018
Generally – 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 gas Impact on least-cost capacity mix
EVs typical configuration (G2V i.e. additional demand)
EVs as a demand shaping resource (V2G i.e. implicit in demand)
• For 1-mln EVs, increase of ≈3 TWh/yr
• Increase in proportion of new solar PV vs. wind
• For 1-mln EVs, increase ≈1 GW peak demand
• Less gas capacity i.e. lower gas energy share
• New build capacity to meet charging demand is
• Relative reduction in total system cost
mostly wind, solar PV and gas • Most charging demand met by wind and gas
2030 G2V - Grid to vehicle 73
V2G - Vehicle to grid
Submitted to DoE on 25 October 2018
Formal comments on Draft IRP 2018
1 Executive Summary 2 Background 3 Draft IRP 2018 scenarios 4 Draft IRP 2018 employment impacts 5 Draft IRP 2018 energy planning risks 5.1 Scenarios a
Impact of stationary storage
b
Impact of Demand Side Response (DSR)
c
Technology learning
d
Risk-adjusted scenario
e
Existing coal fleet performance
5.2 Descriptive comments 6 System services and technical considerations
74
Submitted to DoE on 25 October 2018
Solar PV learning assumptions in Draft IRP 2018 Actual solar PV tariffs and forecasted tariff trajectory
Equivalent tariff, Jan 2017, [ZAR/kWh] 4.00
3.85 Actuals: REIPPPP (BW1-4Exp) Assumption for further RE cost reductions Assumptions: IRP 2016 (Upper) Assumptions: IRP 2016 (Lower)
3.00
Assumptions: IRP 2018 (Upper) Assumptions: IRP 2018 (Lower)
2.29
2.00
-66% -40% 1.29
1.00
1.23 0.96
1.06
0.89
0.72
0.65
0.00 2010
2015
0.79
0.39
2020
2025
2030
0.54
0.22
2035
2040
0.22
2045
2050
BW1 BW 4 (Expedited) 75
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 Sources: StatsSA for CPI; IRP 2010; South African Department of Energy (DoE); DoE IPP Office; CSIR analysis . Learning rate - Bloomberg New Energy Outlook 2017
Submitted to DoE on 25 October 2018
Wind cost learning assumptions in Draft IRP 2018 Actual wind tariffs and forecasted tariff trajectory
Equivalent tariff, Jan 2017, [ZAR/kWh] 2.00
Actuals: REIPPPP (BW1-4Exp) Assumption for further RE reductions
1.60
Assumptions: IRP 2016 (Upper)
1.60
Assumptions: IRP 2016 (Lower) Assumptions: IRP 2018 (Upper)
1.20
1.04
0.92
0.80
Assumptions: IRP 2018 (Lower)
1.16
1.25
0.87
0.81 -28%
0.73
0.60
0.47
0.65
0.35
0.40
0.00 2010
0.78
-47%
2015
2020
2025
2030
2035
2040
0.35
2045
2050
BW1 BW 4 (Expedited) 76
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 Sources: StatsSA for CPI; IRP 2010; South African Department of Energy (DoE); DoE IPP Office; CSIR analysis . Learning rate - Bloomberg New Energy Outlook 2017
Submitted to DoE on 25 October 2018
Input assumptions for CSP from Draft IRP 2018 and further cost declines Today’s latest tariff as starting point, same cost decline as per IRP 2010
Equivalent tariff, Jan 2017, [ZAR/kWh] 4.00
3.00
3.74 3.50 3.28 3.07
3.30
2.89
Assumptions: IRP2010 - high
Assumptions for further RE reductions
Assumptions: IRP2010 - low
Actuals: REIPPPP (BW1-4Exp)
Assumptions: IRP2016 - high
Assumptions: IRP2018 - high
Assumptions: IRP2016 - low
Assumptions: IRP2018 - low
2.65
2.65 2.49
-36% 2.12
2.00
1.75
1.75
1.32
1.36
1.36 1.14
1.00
0.00 2010
2015
BW1 BW 4 (Expedited)
77
2020
2025
2030
2035
2040
2045
2050
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
to DoE on 25 October 2018 Draft IRP 2018 IRP1 with Submitted further RE cost reductions, increased solar PV and wind from 2030 onwards, timing unchanged, no import hydro
Installed capacity and electricity supplied from 2016 to 2050 for IRP1 with higher RE cost reductions
Installed capacity
Energy mix
Total installed capacity (net) [GW]
Electricity production [TWh/yr]
200
184.2
180
400
164.8
160
361
49.2
84.0
80 51.6
40 20
60.2
27.6
100
209
14
204 103
Solar PV
Peaking
Coal (New)
2050
Nuclear
2045
Hydro+PS
2040
Biomass/-gas
2035
Nuclear (new)
2030
Wind
2025
Other Storage
Coal
2020
Gas
0
2016
CSP
2050
2045
2040
2035
2030
2025
2020
DR
17 (4%) 5 (1%) 51 (13%) 66 (17%)
18 5 22
20.2
31.7
172 (43%)
128
7.6
15.8 5.1 12.0 2.6
Sources: Draft IRP 2018. CSIR Energy Centre analysis
78
200
0.6 13.9
(1%) 84 (21%)
4
2
46 18 6 14
69.1
9.9
2016
0
1.5 57.8 1.5 5.1 3.4 1.9 37.4
271
399 4
66 25
249
107.2
100
60
298
300
120
342
321
142.8 140
381
Demand: Median First new-builds: PV (2027) Wind (2027) OCGT (2024)
5.9 GW 2.8 GW 1.9 GW
Submitted to DoE on 25 October 2018 Difference in installed capacity and energy mix with higher RE cost reductions relative to IRP1, higher RE & peaking gas, less mid-merit gas
Installed capacity and electricity supplied from 2016 to 2050 for IRP1 with higher RE cost reductions
Installed capacity Difference - Total installed capacity (net) [GW]
Difference - Electricity production [TWh/yr]
50
50
40
40
30
30
20
12 21
12
20
11
10
6
10
10 1 2
0
5 -3
2 -3 -2
-1
21 3 3
0
Nuclear
Biomass/-gas
Wind
Gas
Coal (New)
-7 -1 -10
-13 -4
2050
Peaking
-17
2045
CSP
-16
2040
Other Storage
Coal
2035
Nuclear (new)
2030
Hydro+PS
2025
Solar PV
2020
DR
2016
-50
2050
-50
2045
-40
2040
-40
2035
-30
2030
-30
2025
-20
2020
-20
2016
-10
12 2
2
-2 -4
-4
-10
Sources: Draft IRP 2018. CSIR Energy Centre analysis
79
Energy mix
to DoE on 25 October 2018 CO2 emissions trajectoriesSubmitted for PPD Moderate never binding while water use declines as expected as coal fleet decommissions
IRP 1 with higher RE cost reductions
CO2 emissions
Water usage
Electricity sector CO2 emissions [Mt/yr] 300
Electricity sector Water usage [bl/yr] 275
300
275
250
250 210
200
200
150
150
100 50
82
IRP1
76
IRP1 with further RE cost reductions PPD (Moderate)
0 2015 2020 2025 2030 2035 2040 2045 2050 Carbon Budget 80
PPD equiv.
2750 Mt
1800 Mt
920 Mt
> 2750 Mt
2720 Mt
2325 Mt
100 50
IRP1 IRP1 with further RE cost reductions
0 2015 2020 2025 2030 2035 2040 2045 2050
36 33
Submitted to DoE on 25 October 2018
Total system cost: IRP1 with higher RE cost reductions would result in lower system cost Net Present Value System Cost
Total System Cost
(2016 - 2050)
Total system cost in bR/yr (Jan-2017 Rand)
bR
600 529 500
441 360
400
299
300 200
487
418
4 018
3 951
IRP1
RE cost reductions
-67 (-2%)
356
199
100 0 2015
2020
2025 IRP1
81
2030
2035
2040
2045
IRP1 with further RE cost reductions
2050
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. Sources: Draft IRP 2018. CSIR Energy Centre analysis. Eskom on Tx, Dx costs
Submitted to DoE on 25 October 2018
Formal comments on Draft IRP 2018
1 Executive Summary 2 Background 3 Draft IRP 2018 scenarios 4 Draft IRP 2018 employment impacts 5 Draft IRP 2018 energy planning risks 5.1 Scenarios a
Impact of stationary storage
b
Impact of Demand Side Response (DSR)
c
Technology learning
d
Risk-adjusted scenario
e
Existing coal fleet performance
5.2 Descriptive comments 6 System services and technical considerations
82
to DoE on 25 October 2018 Draft IRP 2018 IRP1 with Submitted storage, DSR and lower RE costs results in increased new-build wind, solar PV, storage and less NG
Installed capacity and electricity supplied from 2016 to 2050 for IRP1 with storage, DSR and higher RE cost reductions
Installed capacity
Energy mix
Total installed capacity (net) [GW]
Electricity production [TWh/yr]
196.8
200
7.2
177.3
180 160
20.7 0.6
400
4.4 11.8
63.0
0.6
87.3
80 51.6
40 20
60.5
5.1 13.1 6.3
107 (27%)
77
271
2 44 17 4 14
160 (40%)
122
18 4 18 5.1 12.8 1.9
13.6 9.9
16.9
Solar PV
Peaking
Coal (New)
2050
Nuclear
14
2045
Hydro+PS
2040
Biomass/-gas
0
2035
Nuclear (new)
17 (4%) 7 (2%) 38 (9%) 66 (17%)
103
2030
Wind
202
2025
Other Storage
Coal
209
2020
Gas
100
2016
CSP
2050
2045
2040
2035
2030
DR
Notes: NG = Natural gas Sources: Draft IRP 2018. CSIR Energy Centre analysis
(1%)
4
63.8
45.6
31.7
2025
2020
83
2016
0
1.5 57.8 1.5 5.1 3.4 1.9 37.4
399 4
31
200
4.8 0.6 17.1 0.5 15.3 5.1 8.7 1.2 1.9
341
320
249
41.7
100
298
300
112.8
120
60
361
147.2
140
383
Demand: Median First new-builds: PV (2027) Wind (2027) OCGT (2024) Storage (2027)
6.5 GW 2.1 GW 1.9 GW 1.1 GW
Submitted to DoE on 25 October 2018 Difference in installed capacity and energy mix Risk-adjusted scenario relative to IRP1, higher wind, PV & storage, less NG
Installed capacity and electricity supplied from 2016 to 2050 for IRP1 with storage, DSR and higher RE cost reductions
Installed capacity
Energy mix Difference - Electricity production [TWh/yr]
Difference - Total installed capacity (net) [GW] 60
7
40
60
21
40
26
20
4 23
12
20 13 5 5 1 -2
0
5
7 -3 -8 -4
-3 -9 -10
-20
0
9 1
15
-4 -5
-17
44
4
-20
1
-17
-11 -27
-10
-40
-40
-4
Solar PV
Peaking
Coal (New)
2050
Nuclear
2045
Hydro+PS
2040
Biomass/-gas
2035
Nuclear (new)
2030
Wind
2025
Other Storage
Coal
2020
Gas
-60
2016
CSP
2050
2045
DR
Sources: Draft IRP 2018. CSIR Energy Centre analysis
84
2040
2035
2030
2025
2020
2016
-60
to DoE on 25 October 2018 CO2 emissions trajectoriesSubmitted for PPD Moderate never binding while water use declines as expected as coal fleet decommissions
IRP 1 with storage, DSR and higher RE cost reductions
CO2 emissions
Water usage
Electricity sector CO2 emissions [Mt/yr] 300
Electricity sector Water usage [bl/yr] 275
300
275
250
250 210
200
200
150
150
100 50
82
IRP1
72
IRP1 Risk-adjusted scenario PPD (Moderate)
0 2015 2020 2025 2030 2035 2040 2045 2050 Carbon Budget 85
PPD equiv.
2750 Mt
1800 Mt
920 Mt
> 2750 Mt
2720 Mt
2325 Mt
100 50
IRP1 IRP1 Risk-adjusted scenario
0 2015 2020 2025 2030 2035 2040 2045 2050
36 32
Submitted to DoE on 25 October 2018
Total system cost: Risk-adjusted scenario results in lower system cost than IRP1 Net Present Value System Cost
Total System Cost
(2016 - 2050)
Total system cost in bR/yr (Jan-2017 Rand)
bR
600 529 500
441 360
400
299
300 200
477
413
4 018
3 937
IRP1
RiskAdjusted
-81 (-2%)
354
199
100 0 2015
2020
2025
2030 IRP1
86
2035
Risk-Adjusted
2040
2045
2050
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. Sources: Draft IRP 2018. CSIR Energy Centre analysis. Eskom on Tx, Dx costs
Submitted to DoE on 25 October 2018
Draft IRP 2018 IRP1: 2030 Exemplary Week under Draft IRP 2018 IRP1
Demand and Supply in GW
60 50
40 30 20 10 0 Monday
87
Tuesday
Wednesday
Thursday
Curtailed solar PV and wind
Biomass/-gas
Wind
Gas
DR
Solar PV
Hydro+PS
Coal
Other Storage
CSP
Peaking
Nuclear
Sources: CSIR analysis
Friday
Saturday
Electricity demand
Sunday
Submitted to DoE on 25 October 2018
Risk-Adjusted Scenario: 2030 Exemplary Week under Risk-Adjusted Scenario
Demand and Supply in GW
60 50
40 30 20 10 0 Monday
88
Tuesday
Wednesday
Thursday
Curtailed solar PV and wind
Biomass/-gas
Wind
Gas
DR
Solar PV
Hydro+PS
Coal
Other Storage
CSP
Peaking
Nuclear
Sources: CSIR analysis
Friday
Saturday
Electricity demand
Sunday
Submitted to DoE on 25 October 2018
Draft IRP 2018 IRP1: 2040 Exemplary Week under Draft IRP 2018 IRP1
Demand and Supply in GW
80 70 60 50 40 30 20 10 0 Monday
89
Tuesday
Wednesday
Thursday
Curtailed solar PV and wind
Biomass/-gas
Wind
Gas
DR
Solar PV
Hydro+PS
Coal
Other Storage
CSP
Peaking
Nuclear
Sources: CSIR analysis
Friday
Saturday
Electricity demand
Sunday
Submitted to DoE on 25 October 2018
Risk-Adjusted: 2040 Exemplary Week under Risk-Adjusted Scenario
Demand and Supply in GW
80 70 60 50 40 30 20 10 0 Monday
90
Tuesday
Wednesday
Thursday
Curtailed solar PV and wind
Biomass/-gas
Wind
Gas
DR
Solar PV
Hydro+PS
Coal
Other Storage
CSP
Peaking
Nuclear
Sources: CSIR analysis
Friday
Saturday
Electricity demand
Sunday
Submitted to DoE on 25 October 2018
Draft IRP 2018 IRP1: 2050 Exemplary Week under Draft IRP 2018 IRP1
Demand and Supply in GW
90 80 70
60 50 40 30 20 10 0 Monday
91
Tuesday
Wednesday
Thursday
Curtailed solar PV and wind
Biomass/-gas
Wind
Gas
DR
Solar PV
Hydro+PS
Coal
Other Storage
CSP
Peaking
Nuclear
Sources: CSIR analysis
Friday
Saturday
Electricity demand
Sunday
Submitted to DoE on 25 October 2018
Risk-Adjusted: 2050 Exemplary Week under Risk-Adjusted Scenario
Demand and Supply in GW
90 80 70
60 50 40 30 20 10 0 Monday
92
Tuesday
Wednesday
Thursday
Curtailed solar PV and wind
Biomass/-gas
Wind
Gas
DR
Solar PV
Hydro+PS
Coal
Other Storage
CSP
Peaking
Nuclear
Sources: CSIR analysis
Friday
Saturday
Electricity demand
Sunday
Submitted to DoE on 25 October 2018
Formal comments on Draft IRP 2018
1 Executive Summary 2 Background 3 Draft IRP 2018 scenarios 4 Draft IRP 2018 employment impacts 5 Draft IRP 2018 energy planning risks 5.1 Scenarios a
Impact of stationary storage
b
Impact of Demand Side Response (DSR)
c
Technology learning
d
Risk-adjusted scenario
e
Existing coal fleet performance e.a IRP1 with low coal fleet performance e.b Risk-adjusted with low coal fleet performance
5.2 Descriptive comments 6 System services and technical considerations
93
Submitted to DoE on 25 October 2018
Formal comments on Draft IRP 2018
1 Executive Summary 2 Background 3 Draft IRP 2018 scenarios 4 Draft IRP 2018 employment impacts 5 Draft IRP 2018 energy planning risks 5.1 Scenarios a
Impact of stationary storage
b
Impact of Demand Side Response (DSR)
c
Technology learning
d
Risk-adjusted scenario
e
Existing coal fleet performance e.a IRP1 with low coal fleet performance e.b Risk-adjusted with low coal fleet performance
5.2 Descriptive comments 6 System services and technical considerations
94
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 Energy Availability Factor (EAF) [%]
Low
Moderate
High
90 88
86 84 82
81
83
83
80
80
84 82 80
80 80
78
75
76 74
74
72
72 70
0 2016
95
2018
2020
2022
2024
2026
2028
2030
2032
2034
2036
2038
2040
2042
2044
2046
2048
2050
to DoE on 25 October 2018 Draft IRP 2018 IRP1 with Submitted Low EAF requires earlier new-build around 2023 and increased absolute levels of new-build by 2030
Installed capacity and electricity supplied from 2016 to 2050 for IRP1 with low coal fleet EAF
Installed capacity
Energy mix
Total installed capacity (net) [GW]
Electricity production [TWh/yr]
200 180
400 158.6
160
144.1
140
0.6
120
80
68.3 57.8 51.6 1.5 1.5 5.1 3.4 1.9 37.4
40 20
0.6 18.3 0.5 16.6 5.1 11.1 6.3
299
300
271 249
24.4
18.5
1.9
12.1
100
18 13 15
208
186
20.9
1.9
16.9
9.9
Solar PV
Peaking
Coal (New)
102
72 (18%)
2050
Nuclear
34 (8%) 4 (1%) 59 (15%)
2045
Hydro+PS
170 (43%)
35 3 35 15
2040
Biomass/-gas
2035
Nuclear (new)
2030
Wind
2025
Other Storage
Coal
2020
Gas
2016
CSP
2050
2045
2040
2035
2030
2025
DR
0
4
109
7.6
7.6
(1%) 56 (14%)
2
48
200
398 4
57 33
39.1
Sources: Draft IRP 2018. CSIR Energy Centre analysis
96
341
320
30.5 62.5
31.7
2020
2016
0
101.7
92.0
100
60
0.6 32.7
127.1
360
380
Demand: Median First new-builds: PV (2023) Wind (2026) OCGT (2023)
0.2 GW 3.6 GW 2.0 GW
to DoE on 25 October 2018 Difference in capacity andSubmitted energy mix with low EAF relative to IRP1, increased level of new-build, built earlier to cater for lower coal supply
Installed capacity and electricity supplied from 2016 to 2050 for IRP1 with low coal fleet EAF
Installed capacity
Energy mix
Difference - Total installed capacity (net) [GW]
Difference - Electricity production [TWh/yr]
50
50
40
40
30
30
20
20
10
6 3
0
2 -3
1
4 2
1
-4 -3
-10
-10
Peaking
Coal (New)
2050
Solar PV
-7
2045
Nuclear
-11
2040
Hydro+PS
10
-5
2035
Biomass/-gas
2030
Nuclear (new)
2025
Wind
2020
Other Storage
Coal
2 6
-21
2016
Gas
2050
2045
2040
-50
2035
-50
2030
-40
2025
-40
2020
-30
2016
-30
CSP
5 5
0
-20
Sources: Draft IRP 2018. CSIR Energy Centre analysis
97
10
-20
DR
11
to DoE on 25 October 2018 CO2 emissions trajectoriesSubmitted for PPD Moderate never binding while water use declines as expected as coal fleet decommissions
IRP 1 with low coal fleet EAF
CO2 emissions
Water usage
Electricity sector CO2 emissions [Mt/yr] 300
Electricity sector Water usage [bl/yr] 275
300
275
250
250 210
200
200
150
150
100 50
82 82
IRP1
50
IRP1 with low EAF PPD (Moderate)
0 2015 2020 2025 2030 2035 2040 2045 2050 Carbon Budget 98
PPD equiv.
100
2750 Mt
1800 Mt
920 Mt
> 2750 Mt
2720 Mt
2325 Mt
IRP1 IRP1 with low EAF
0 2015 2020 2025 2030 2035 2040 2045 2050
36 36
Submitted to DoE on 25 October 2018
Total system cost: IRP1 with low EAF higher system cost than IRP1 due to additional capacity required Net Present Value System Cost
Total System Cost
(2016 - 2050)
Total system cost in bR/yr (Jan-2017 Rand)
bR
600 529 500
441
299
300 200
445
360
400
4 018
4 067
IRP1
IRP1 Low EAF
+49 (+1.2%)
371
199
100 0 2015
2020
2025
2030 IRP1
99
2035 IRP1 Low EAF
2040
2045
2050
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. Sources: Draft IRP 2018. CSIR Energy Centre analysis. Eskom on Tx, Dx costs
Submitted to DoE on 25 October 2018
Formal comments on Draft IRP 2018
1 Executive Summary 2 Background 3 Draft IRP 2018 scenarios 4 Draft IRP 2018 employment impacts 5 Draft IRP 2018 energy planning risks 5.1 Scenarios a
Impact of stationary storage
b
Impact of Demand Side Response (DSR)
c
Technology learning
d
Risk-adjusted scenario
e
Existing coal fleet performance e.a IRP1 with low coal fleet performance e.b Risk-adjusted with low coal fleet performance
5.2 Descriptive comments 6 System services and technical considerations
100
Submitted to DoE on 25 October 2018 Risk-adjusted scenario with Low EAF requires earlier new-build around 2023 too and increased absolute levels of new-build by 2030
Installed capacity and electricity supplied from 2016 to 2050 for Risk-adjusted scenario with low coal fleet EAF
Installed capacity
Energy mix
Total installed capacity (net) [GW]
Electricity production [TWh/yr]
200
191.0 174.9
180
400
361
0.7
160
149.2
140
0.6
116.9
120
80 60
0.6 20.1 0.5 21.4
69.1 57.8 51.6 1.5 1.5 5.1 3.4 1.9 37.4
40 20
5.1 13.7 6.3
5.1 13.2 1.9
12.1 9.9
16.9
2
Solar PV
Peaking
Coal (New)
2050
Nuclear
2045
Hydro+PS
14
2040
Biomass/-gas
0
2035
Nuclear (new)
17 (4%) 7 (2%) 33 (8%) 66 (17%)
90
2030
Wind
180
2025
Other Storage
Coal
208
169 (42%)
135
17 4 18
2020
Gas
104 (26%)
77
17 4 15
2016
CSP
2050
2045
2040
2035
2030
2025
DR
100
(1%)
4
61
67.9
51.8
31.7
Sources: Draft IRP 2018. CSIR Energy Centre analysis
101
271 249
41.4
399 4
36
200
5.1 9.4 1.2 1.9
2020
2016
0
298
300
97.1
100
340
320 61.0
382
Demand: Median First new-builds: PV (2023) Wind (2023) OCGT (2023)
0.4 GW 0.2 GW 1.9 GW
to DoE on 25 October 2018 Difference in capacity andSubmitted energy mix with low EAF relative to IRP1, increased level of new-build, built earlier to cater for lower coal supply
Installed capacity and electricity supplied from 2016 to 2050 for Risk-adjusted scenario with low coal fleet EAF
Installed capacity
Energy mix
Difference - Total installed capacity (net) [GW]
Difference - Electricity production [TWh/yr]
70
70
60
7
50
50 40
21
4 12
30 20 0
24
14
7
9
-3 -7 -4
-2
-10
-3 -9 -12
-20
41
10
Peaking
Coal (New)
2050
Solar PV
2045
Nuclear
2040
Hydro+PS
2035
Biomass/-gas
2030
Nuclear (new)
-4
2025
Wind
-11 -32
2020
Other Storage
Coal
-17
-18
-23
2016
Gas
2050
2045
2040
-70
2035
-70
2030
-60
2025
-60
2020
-50
2016
-50
9 4
1
-4 -27
-20 -40
CSP
1
-10
-40
28
19
0
-30
DR
14
20
-30
Sources: Draft IRP 2018. CSIR Energy Centre analysis
23
40 30
12
5 8
10
102
60
to DoE on 25 October 2018 CO2 emissions trajectoriesSubmitted for PPD Moderate never binding while water use declines as expected as coal fleet decommissions
Risk-adjusted scenario with low coal fleet EAF
CO2 emissions
Water usage
Electricity sector CO2 emissions [Mt/yr] 300
Electricity sector Water usage [bl/yr] 275
300
275
250
250 210
200
200
150
150
100 50
82
IRP1
71
Risk-adjusted with low EAF PPD (Moderate)
0 2015 2020 2025 2030 2035 2040 2045 2050 Carbon Budget 103
PPD equiv.
2750 Mt
1800 Mt
920 Mt
> 2750 Mt
2720 Mt
2325 Mt
100 50
IRP1 Risk-adjusted with low EAF
0 2015 2020 2025 2030 2035 2040 2045 2050
36 31
Submitted to DoE on 25 October 2018
Total system cost: Risk-Adjusted with low EAF results in higher system cost than mod EAF due to additional capacity required pre-2035 Net Present Value System Cost
Total System Cost
(2016 - 2050)
Total system cost in bR/yr (Jan-2017 Rand)
bR
600 500
441
466
360
400
299
300 200
529 477 3 937
3 974
413
+37 (+1%)
354
199
100 0 2015
2020 IRP1
104
2025
2030
2035
Risk-Adjusted Mod EAF
2040
2045
Risk-Adjusted Low EAF
2050
Risk-Adj Risk-Adj Mod Low EAF EAF
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. Sources: Draft IRP 2018. CSIR Energy Centre analysis. Eskom on Tx, Dx costs
Submitted to DoE on 25 October 2018
Formal comments on Draft IRP 2018
1 Executive Summary 2 Background 3 Draft IRP 2018 scenarios 4 Draft IRP 2018 employment impacts 5 Draft IRP 2018 energy planning risks 5.1 Scenarios 5.2 Descriptive comments a
Technology new-build limits
b
New-build and under-construction coal capacity
c
Natural gas
d
Planning for embedded generation
e
Demand profile
6 System services and technical considerations
105
Submitted to DoE on 25 October 2018
Formal comments on Draft IRP 2018
1 Executive Summary 2 Background 3 Draft IRP 2018 scenarios 4 Draft IRP 2018 employment impacts 5 Draft IRP 2018 energy planning risks 5.1 Scenarios 5.2 Descriptive comments a
Technology new-build limits
b
New-build and under-construction coal capacity
c
Natural gas
d
Planning for embedded generation
e
Demand profile
6 System services and technical considerations
106
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 107
Submitted 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
108
Sources: Scatec; Hopefield
Submitted 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 Absolute
Relative
Max. new-build capacity, annually [MW]
Peak demand [MW]
Max. new-build capacity, annually [% of peak demand]
4 000
80 000
8
80 000
3 000
60 000
6
60 000
2 000
40 000
4
40 000
1 000
20 000
2
20 000 2.7
0
2016
2020
2025
2030
2035
2040
2045
2050
IRP_2018_Median Maximum allowed new-build solar PV (annually)
109
Peak demand [MW]
Sources: Eskom; Draft IRP 2018; CSIR analysis
0
0
2016
2.5
2.2
2.1
2.0
1.8
1.7
1.7
2020
2025
2030
2035
2040
2045
2050
0
Submitted 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 Absolute
Relative
Max. new-build capacity, annually [MW]
Peak demand [MW]
Peak demand [MW]
4 000
80 000
8
80 000
3 000
60 000
6
60 000
2 000
40 000
4
40 000
1 000
20 000
2 4.3
0
2016
2020
2025
2030
2035
2040
2045
IRP_2018_Median Maximum allowed new-build wind (annually)
110
Max. new-build capacity, annually [% of peak demand]
Sources: Eskom; Draft IRP 2018; CSIR analysis
2050
0
0
2016
4.0
2020
3.6
2025
20 000
3.3
3.1
3.0
2.8
2.7
2030
2035
2040
2045
2050
0
Submitted to DoE on 25 October 2018
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]
Germany Spain
17% 10%
9%
9%
Italy UK Australia 8%
RSA new-build limits in 2030 and 2050
India
6%
6%
6%
4%
3% 2% 1%
1%
1%
1%
2007
111
2008
2009
1% 1%
2010
3% 3% 2%
2% 2%
1%
4% 4%
4%
4% 3%
2%
Follower 2nd wave
South Africa
5% 5% 5%
5%
4%
Follower
Japan China
7%
7%
4%
Leader
3% 3% 3% 2%
2%
2%
1%
1%
2011
1%
1% 1% 0%
1% 1%
2012
3%
2013
Sources: SolarPowerEurope; CIGRE; websites of System Operators; IRP 2016 Draft; CSIR analysis
2014
3% 2%
2% 1%
2%
2% 1%
2015
2%
2%
1%
2016
2017
RSA’s IRP relative new-build limit decreases over time 2030 (2.1%) 2050 (1.7%)
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
New-build wind capacity, annually [% of peak demand]
Germany Spain Ireland
9%
China
8%
South Africa
7%
5%
4% 4%
3%
3%
3% 3% 3%
3%
2%
2006
2% 2% 2%
2% 1%
1%
2007
2% 2% 2%
2%
2%
2% 2%
112
4%
4%
3%
3%
2009
2011
Sources: GWEC; CIGRE; websites of System Operators; IRP 2016 Draft; CSIR analysis
5% 5% 4%
4%
RSA’s IRP relative new-build limit decreases over time
5%
3% 3%
3% 2%
1%
1%
2010
2% 2%
1% 0%
2008
6%
6%
5% 4%
2012
Follower
Brazil
7%
6% 6%
5%
India
8%
RSA new-build limits in 2030 and 2050
1%
Leader
2% 2% 1%
2013
2%
2% 1%
1%
1%
1%
2014
3% 3% 3%
2015
2016
2017
2030 (3.3%) 2050 (2.7%)
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 Total solar PV capacity relative to system peak demand 100% Germany Leader Spain Italy UK Australia Follower Japan China Follower 2nd wave India South Africa South Africa IRP 2016 Base Case Draft IRP 2018 (IRP1) Draft IRP 2018 (Others) Draft IRP 2018 (Recommended)
90% 80% 70% 54
60% 50%
36
40%
31 23
30%
22 19
20%
12
10%
4
0% 2005
2010
2015
2020
2025
2030
Year 113
Sources: SolarPowerEurope; CIGRE; websites of System Operators; IRP 2016 Draft; CSIR analysis
2035
2040
2045
2050
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 Total wind capacity relative to system peak load 100% Germany Leader Spain Ireland China Follower India Brazil South Africa South Africa IRP 2016 Base Case Draft IRP 2018 (IRP1) Draft IRP 2018 (Others) Draft IRP 2018 (Recommended)
90% 80%
70 67
70%
60
60% 50% 40%
27
30%
21 20
20% 6
10% 0% 2005
2010
2015
2020
2025
2030
Year 114
Sources: GWEC; CIGRE; websites of System Operators; IRP 2016 Draft; CSIR analysis
2035
2040
2045
2050
Submitted to DoE on 25 October 2018
Some historical perspective - installed capacity reveals the considerable coal build-out South Africa pursued previously Installed capacity [GW] 59
60
58
55
50
49
47 44
45 41 40
42
41
37
35 30
Wind
27
CSP
24
25
22
Solar PV
20
16 15
Biomass/-gas Nuclear
5 0
Coal 1965
1975
Sources: Draft IRP 2018; CSIR analysis
115
Gas Peaking
9
10
Hydro+PS
1985
1995
2000
2005
2010
2015
2020
2025
2030
2035
2040
2045
2050
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 Installed capacity [GW]
Arnot
60
Camden Duvha Grootvlei
50
Hendrina Kendal 42
40 35
35
35
Komati
40
Kriel
36
Kusile 32
32 30
Lethabo MajubaDry
26
MajubaWet Matimba
20
18
Matla
17
Medupi
13 10
10
Tutuka Coal IPPs
7
Sasol Other 0
1965
1975
Sources: Draft IRP 2018; CSIR analysis
116
1985
1995
2000
2005
2010
2015
2020
2025
2030
2035
2040
2045
2050
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? New-build coal capacity, annually [MW] 3 048
2 433 2 433
1 895 1 793
1 725
1 481
1 411
1 303
1 178 1 178 1 135 1 150 1 150 1 150 1 050 950 847
931 555 555 555
117
746 640
575
559
722 711 706
610 670 670 670 610 610
187
100 100
1965
744
1 148
1970
Sources: Draft IRP 2018
1975
1980
1985
1990
1995
2000
2005
2010
2015
2020
Submitted to DoE on 25 October 2018
Formal comments on Draft IRP 2018
1 Executive Summary 2 Background 3 Draft IRP 2018 scenarios 4 Draft IRP 2018 employment impacts 5 Draft IRP 2018 energy planning risks 5.1 Scenarios 5.2 Descriptive comments a
Technology new-build limits
b
New-build and under-construction coal capacity
c
Natural gas
d
Planning for embedded generation
e
Demand profile
6 System services and technical considerations
118
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 Installed capacity [GW] 60
57
58
Wind
55
CSP
50 45
Solar PV
49
47
Hydro+PS
44
Gas
42
Peaking
40
Biomass/-gas 35
Nuclear
30
Coal
27
25
22
20
16 15 10 5 0
2010
2015
Sources: Draft IRP 2018; CSIR analysis
119
2020
2025
2030
2035
2040
2045
2050
Submitted to DoE on 25 October 2018
New-build largely driven by the planned decommissioning of the existing coal fleet - mostly post 2030 Installed capacity [GW]
Arnot
60
Camden Duvha Grootvlei Hendrina
50
-9.9 (-24%)
42 40 35
-24.7 (-59%)
-31.7 (-76%)
Kendal Komati
40
Kriel
-14.8 (-47%)
36
Kusile
32 30
Lethabo MajubaDry
26
MajubaWet -7.0 (-41%)
20
Matimba Matla
17
Medupi
13 10
10
Tutuka Coal IPPs
Sasol Other 0
2010
2015
Sources: Draft IRP 2018; CSIR analysis
120
2020
2025
2030
2035
2040
2045
2050
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
121
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 PS included
PS excluded
Equivalent value [R/kWh]
Total discounted system costs [ZAR-billion]
-
Total (with PS costs incl.)
PS costs
Total (with PS costs excl.)
Total (with PS costs incl.)
PS costs
Total (with PS costs excl.)
Value difference [ZAR-billion]
./.
Total energy (discounted) [TWh]
Total energy (PS)
122
Total energy (PS)
Coal
Peaking
CSP
Pumped storage
Nuclear
Hydro
Solar PV
Li-ion
Gas
Wind
Biomass/-gas
DR
Energy difference [TWh]
Submitted to DoE on 25 October 2018
Early decommissioning of oldest selected coal-fired power stations would result in significant savings and a cheaper power system
[R/kWh]
SAV
Will cost 0.11-0.17 R/kWh more from Grootvlei if not decommissioned early
High demand SAV
0.61 Max. allowed equivalent capex cost of remaining 2 Kusile units
0.58
0.57
0.57 0.53
0.50
0.50
0.49
0.47
0.48
0.48
0.47 Low-demand SAV
0.41 0.34
0.36 0.31
0.31
0.33
Power station(s)
0.23
0.22
Levelised costs Env. Retrofit Capex Env. Retrofit O&M Fuel Kusile
Arnot
Complete 6 units vs. 4 units
Decom. Early Off from 1Apr20
Source: Wright (2017), Steyn (2017)
123
Camden Decom. Early Off from 1Apr18
Grootvlei Decom. Early Off from 1Apr18
Hendrina Decom. Early Off from 1Apr19
Komati
GrHeKo
Decom. all 3 early
Decom. Early Off from 1Apr20
Water cost VOM FOM
Submitted to DoE on 25 October 2018
Formal comments on Draft IRP 2018
1 Executive Summary 2 Background 3 Draft IRP 2018 scenarios 4 Draft IRP 2018 employment impacts 5 Draft IRP 2018 energy planning risks 5.1 Scenarios 5.2 Descriptive comments a
Technology new-build limits
b
New-build and under-construction coal capacity
c
Natural gas
d
Planning for embedded generation
e
Demand profile
6 System services and technical considerations
124
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
125
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
2030 IRP1
2040
2050
313 10 (3%)
353 28 (8%)
IRP3
47 (12%)
313 15 (5%)
353 29 (8%)
IRP5
355 14 (4%)
IRP6 15 (5%)
352 37 (10%) 352 17 (5%)
Rec.
391 59 (15%)
311 7 (2%)
388 19 (5%)
313
IRP7
393 40 (10%)
313 15 (5%)
392
390 31 (8%)
313 12 (4%) Energy [TWh]
Energy [TWh] NG
Energy [TWh]
Other
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)s 126
NG – Natural gas; Sources: Draft IRP 2018
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
2030 IRP1
350 (97%)
2040 360
IRP1
10 (3%) IRP3
361 367
473 14 (3%)
347 (96%)
362
477 37 (8%)
365 (98%)
373
495 17 (3%)
364 (97%)
375
580 60 (10%)
IRP7
8 (2%)
564 20 (3%)
IRP6
15 (4%)
560 40 (7%)
IRP5
15 (4%)
Rec.
466 29 (6%)
351 (96%)
IRP7
529 47 (9%)
IRP3
15 (4%)
IRP6
442 28 (6%)
346 (96%)
IRP5
2050
591 31 (5%)
Rec.
12 (3%) Total system cost [bR/yr]
Total system cost [bR/yr]
NG (fuel)
NG – Natural gas; Sources: Draft IRP 2018
127
Other
Total system cost [bR/yr]
Submitted to DoE on 25 October 2018
Formal comments on Draft IRP 2018
1 Executive Summary 2 Background 3 Draft IRP 2018 scenarios 4 Draft IRP 2018 employment impacts 5 Draft IRP 2018 energy planning risks 5.1 Scenarios 5.2 Descriptive comments a
Technology new-build limits
b
New-build and under-construction coal capacity
c
Natural gas
d
Planning for embedded generation
e
Demand profile
6 System services and technical considerations
128
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
129
Sources: Eskom; CSIR analysis
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
130
Sources: Eskom; CSIR analysis
Submitted to DoE on 25 October 2018
IRP meets energy demand for RSA – expressed as equivalent demand (assumes EG as reduced demand) 1
1
2
Eskom1
IPPs1
(Gx)
(Gx)
3
Imports
Exports
1
Net sent out
2
Imports
3
Exports
Available for = 1 + + 2+ - 3 distribution in RSA
Eskom (Tx2)
1
Eskom
Munics.
(Dx2)
(Dx2)
Customers
EG
(Dom/Com/Ind)
(Gx)
Other (Gx)
Customers
EG
(Dom/Com/Ind)
(Gx)
1
Large customers
Other (Gx)
EG = Embedded Generation; Gx = Generation; Tx = Transmission; Dx = Distribution 1 Power generated less power station load; Minus pumping load (Eskom owned pumped storage); 2 Transmission/distribution networks incur losses before delivery to customers
131
Submitted to DoE on 25 October 2018 From Jan-Dec 2016, 234 TWh of net electricity was sent out in SA with imports of almost 11 TWh means system load was 245 TWh
Actuals captured in wholesale market for Jan-Dec 2016 (i.e. without embedded plants)
Annual electricity in TWh 234.2 18.2
10.6
244.8
16.5
216.0
228.2 Net Sent Out Other Eskom + IPPs
Imports
System Load (domestic and export load)
Exports
Available for distribution in RSA
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
132
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
133
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 were not modelled as standalone scenarios, but considered to be covered in the low-demand scenario. The assumption was that the impact of these would be lower demand in relation to the median forecast demand 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)
134
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 2016
2030
2030
(TWh)
(TWh)
(MW)
313 5
290
1100-1500 MW (80-100 MW/yr) 245
0
0
245
20% is EG 313 9
290
3300 – 4400 MW (230-310 MW/yr)
Median demand forecast EE/fuel switching
60% is EG
EG Lower demand forecast
313 19
290
4400 - 5800 MW (310-420 MW/yr) Sources: StatsSA; Draft IRP 2018; CSIR analysis
135
80% is EG
Submitted to DoE on 25 October 2018
Formal comments on Draft IRP 2018
1 Executive Summary 2 Background 3 Draft IRP 2018 scenarios 4 Draft IRP 2018 employment impacts 5 Draft IRP 2018 energy planning risks 5.1 Scenarios 5.2 Descriptive comments a
Technology new-build limits
b
New-build and under-construction coal capacity
c
Natural gas
d
Planning for embedded generation
e
Demand profile
6 System services and technical considerations
136
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
137
Submitted to DoE on 25 October 2018
Change in demand profile will result in very different capacity expansion options Future
Today Weekday
EG
138
Agri
Weekend
Dom
ComMan
Min
Weekday
Trans
Weekend
Submitted to DoE on 25 October 2018
Formal comments on Draft IRP 2018
1 Executive Summary 2 Background 3 Draft IRP 2018 scenarios 4 Draft IRP 2018 employment impacts 5 Draft IRP 2018 energy planning risks 6 System services and technical considerations 6.1 Networks 6.2 System services
139
Submitted to DoE on 25 October 2018
Formal comments on Draft IRP 2018
1 Executive Summary 2 Background 3 Draft IRP 2018 scenarios 4 Draft IRP 2018 employment impacts 5 Draft IRP 2018 energy planning risks 6 System services and technical considerations 6.1 Networks 6.2 System services
140
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) 141
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
142
Submitted to DoE on 25 October 2018
Formal comments on Draft IRP 2018
1 Executive Summary 2 Background 3 Draft IRP 2018 scenarios 4 Draft IRP 2018 employment impacts 5 Draft IRP 2018 energy planning risks 6 System services and technical considerations 6.1 Networks 6.2 System services a
143
RoCoF and frequency stability
Submitted to DoE on 25 October 2018
Formal comments on Draft IRP 2018
1 Executive Summary 2 Background 3 Draft IRP 2018 scenarios 4 Draft IRP 2018 employment impacts 5 Draft IRP 2018 energy planning risks 6 System services and technical considerations 6.1 Networks 6.2 System services a
144
RoCoF and frequency stability
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
145
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
SNSP [%] = System Non-Synchronous Penetration = (Wind/PV + Imports)/(Demand + Exports)
146
Sources: David Cashman (EirGrid), DS3 and beyond, 2017, IEA Working Group
Submitted to DoE on 25 October 2018
Averaging window is important – for frequency stability typically a 500 ms averaging window for RoCoF is considered
The RocoF should not exceed a particular threshold within the pre-defined averaging window e.g. 500 ms 147
Sources: EirGrid, SONI
Submitted to DoE on 25 October 2018
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 𝐸𝑘𝑖𝑛.(𝑚𝑖𝑛)
𝑓𝑛 = 𝑃𝑐𝑜𝑛𝑡. + 𝐸𝑘𝑖𝑛(𝑐𝑜𝑛𝑡.) 2(𝑅𝑜𝐶𝑜𝐹)
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
148
Sources: P. Kundur, Power System Stability and Control, 1994
Demand for inertia
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
Submitted to DoE on 25 October 2018
As a starting point – we have assessed system inertia on an hourly basis via UCED in PLEXOS and some high level assumptions
Technology Coal (old) Coal (new) OCGT/ICE CCGT/CC-GE Biomass Hydro/PS Imports Nuclear Wind PV CSP DR
149
Inertia constant [MWs/MVA] 4.0 2.0 6.0 6.0 2.0 3.0 0.0 5.0 0.0 0.0 2.0 0.0
Sources: P. Kundur, Power System Stability and Control, 1994
Supply of inertia 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
Submitted to DoE on 25 October 2018
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
150
Submitted to DoE on 25 October 2018
System synchronous energy for IRP1 – confirmation that the power system really does only start to change until after 2030
151
Submitted to DoE on 25 October 2018
Minimal cost of ensuring acceptable RoCoF levels even at very high non-synchronous generation penetration levels
2016
2020
2025
2028
2030
2040
2050
104 482
104 482
104 482
104 482
104 482
104 482
104 482
104 482
116 485
116 609
122 260
104 992
55 832
31 907
M in im u m in e rtia n e e d e d
[ M W .s ]
M in im u m in e rtia ( a ctu a l)
[ M W .s ]
A d d itio n a l in e rtia n e e d e d
[ M W .s ]
N u m b e r o f h o u rs
[ h rs ]
S h a re o f h o u rs
[% ]
R o ta tin g s ta b ilis e rs n e e d e d
[M W ]
-
-
-
-
A n n u a l co s t f o r ro ta tin g s ta b ilis e rs
[ b R / y r]
-
-
-
-
(% o f sy ste m co sts)
[% ]
24 0.3%
0.0%
-
-
-
-
48 650
72 575
-
-
-
-
1 799
2 282
20.5%
26.1%
-
1 220
1 810
-
3.7
5.6
0.9%
1.2%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
The worst-case cost to ensure RoCoF levels are acceptable post2030 is at most ≈1% of total system costs
152
Submitted to DoE on 25 October 2018
Thank you
153