formal comments on integrated resource plan (irp) 2018

1

Submitted to DoE on 25 October 2018Submitted to DoE on 25 October 2018

Formal comments on Integrated Resource Plan (IRP) 2018

CSIR Energy CentrePretoria. 25 October 2018v1.2

Jarrad [email protected]

Joanne [email protected]

Ntombifuthi [email protected]

Mpeli [email protected]

Pam [email protected]

Ruan [email protected]

2

Submitted to DoE on 25 October 2018

Word Cloud (DoE, IRP 2010, 2011)

(Design: JG. Wright, using word_cloud, https://github.com/amueller/word_cloud)

Word Cloud (DoE, IRP 2010 Update, 2013)


Word Cloud (DoE, Draft IRP 2016, 2016)


Word Cloud (DoE, Draft IRP 2018, 2018)


3


Word Cloud (DoE, Draft IRP 2018)


4


System services and technical considerations6

Draft IRP 2018 energy planning risks and opportunities5

Draft IRP 2018 employment impacts4

Draft IRP 2018 scenarios3

Background2

Executive Summary1

Formal comments on Draft IRP 2018

5






Background2

Executive Summary1


6


• Key Messages

• Draft IRP 2018 is a very different plan to the Draft IRP 2016 and establishes solid principles

• VRE (PV and wind) with flexibility1 confirmed as least-cost energy mix as existing coal fleet decommissions;• This energy mix also exhibits the least CO2 emissions and least water usage

• Demand growth impacts the timing of new-build capacity but energy mix remains largely unchanged

• New-build coal only post-2030 if CO2 emissions are not too restrictive and new-build VRE is constrained

• New-build nuclear only post-2030 if CO2 emission are restrictive and new-build VRE is constrained

Key Messages

1 Natural gas fired peaking and mid-merit capacity considered as a proxy for this.

NG - Natural gas; PV – Solar Photovoltaics; VRE – Variable renewable energy; EAF – Energy Availability Factor; RoCoF – Rate of Change of Frequency

7


• To 2030 - outcomes similar across most scenarios but notable risks;• Eskom coal fleet EAF (and decommissioning schedule), completion of new-build coal, stationary storage and DSR

• No system integration issues foreseen pre-2030 but an informed and co-ordinated work program is necessary tosufficiently prepare for post-2030 relatively high VRE penetration levels

• Key Messages

• To 2030, in the Recommended Plan, expect net employment increase (as system grows) but net decrease in coal

• Natural gas risk relatively small and can be replaced by appropriate domestic flexibility sources or stationary storage

• Post 2030 - key drivers include VRE new build limits, decommissioning, demand growth, stationary storage

Key Messages

1 Natural gas fired peaking and mid-merit capacity considered as a proxy for this.

NG - Natural gas; PV – Solar Photovoltaics; VRE – Variable renewable energy; EAF – Energy Availability Factor; RoCoF – Rate of Change of Frequency

8


At a glance

Previous CSIR contributions have notably impacted and are mentioned throughout the Draft IRP 2018

• Demand forecast: CSIR (Built Environment) provide this as an input to DoE

• Principles raised by CSIR comments on Draft IRP 2016 have been explicitly considered

• These were: New-build limits removed (IRP1), RE costs aligned with REIPPPP, least-cost Base Case established

CSIR have engaged with key stakeholders in the 60 day public consultation period

• Bilateral engagements: DoE, SALGA, EIUG, Nersa, Eskom

• Attendance at IRP workshops: EE Publishers, FFF, NIASA (requested feedback)

• Tentative: Parliament Portfolio Committee (Energy)

9


Draft IRP 2018 scenario summaries – this is a very different plan to the Draft IRP 2016 and establishes solid principles

• Least-cost confirmed as combination of PV, wind and flexible capacity1 as coal decommissions – also exhibits lowest CO2 emissions and water usage by 2050

• Technology new-build limits (PV, wind) mean post-2030 deployment is constrained with new-build coal and gas replacing it (assuming less restrictive CO2 constraints)

• Higher NG price means less NG usage (notable capacity for system adequacy) and increased new-build coal

• More strict CO2 emissions (Carbon Budget) with RE new-build limits means less new-build coal and deployment of nuclear instead

• Higher NG price and more strict CO2 emissions (Carbon Budget) with RE new-build limits means less NG and coal, increased nuclear instead

• Higher/Lower demand forecast means same mix of new-build of PV, wind and flexibility1 just earlier/later

At a glance

1 Natural gas fired peaking and mid-merit capacity considered as a proxy for this; NG - Natural gas; PV – Solar Photovoltaics

10


Energy mix by 2030 similar across scenarios as coal dominates, IRP1 is ≈R15bn/yr cheaper than Rec. Plan, IRP7 lowest CO2 emissions

11

4

25

14

15

42 2

IRP5

8 2

7

15

3

199 (63%)

202 (64%)IRP1

2

4

4

22

4

4413

22

9

197 (63%)IRP3

4

15

22

2

26

44

2

13199 (63%)IRP6

14

4

15

4

444

11

3

3

15192 (61%)IRP7

2

244

14

3528815

6 (2%)

206 (64%)Rec.

23

Energy Mixin 2030

Demand: 313 TWh

Coal Gas - CCGT Other Storage

Coal (New)

Nuclear

Nuclear (new)

Peaking

Gas - CCGE Hydro+PS

Wind

CSP

Solar PV

Biomass/-gas DR

Costin 2030

Total system cost1 (R-billion/yr)

360

361

367

362

373

375

Environmentin 2030

CO2 emissions (Mt/yr)

Water usage (billion-litres/yr)

217

215

213

215

207

215

199

199

198

199

191

199

2030

Sources: DoE Draft IRP 2018; Eskom on Tx, Dx costs; CSIR analysis; flaticon.com

11


Least-cost mix confirmed as new-build solar PV, wind and flexible capacity (NG) - ≈R15-55 bn/yr cheaper than alternative scenarios

Energy Mixin 2040

Demand: 353 TWh

Costin 2040


441

466

473

477

494

Environmentin 2040



123

153

168

116

119

59

66

70

56

58

2040

104 (29%)

4

12

54

90

IRP5

21291523

5

12

107 (30%)IRP1

42902914

15

11

14

Rec.

15

33 (9%)

106 (30%)

IRP7

4

IRP3

4

47

4728929

47

15

5

51 (14%)

3015

9 (2%)

29025

29

IRP6 33 4

424399 (28%)

15

47

353

97 (27%)

PeakingCoal

Coal (New) Nuclear (new)

Nuclear

Gas - CCGE

Gas - CCGT

Hydro+PS

Wind

CSP

Solar PV

Biomass/-gas

Other Storage

DR


12


By 2050 - Least-cost mix is 70% solar PV and wind, ≈R30-60 bn/yrcheaper than alternatives, least CO2 emissions and least water usage

78

3

66 (17%)

IRP1

31

16417 31

107

63

64

IRP5

110

13

31

58 (15%)

IRP6

831

80 (20%)

IRP3

6432

106

67

5102 (26%)

64 (16%)

3

3106

22 (6%)

12

17

3

55

13 (3%)

57 (15%)

29

13

31

68 (17%)

IRP7

Rec.

47

3

76


Energy Mixin 2050

Demand: 392 TWh

Nuclear (new)

Solar PVCoal Gas - CCGTNuclear

Coal (New) Gas - CCGE

Peaking

Hydro+PS Biomass/-gas

Wind

CSP

Other Storage

DR

Costin 2050


529

560

564

580

591

Environmentin 2050



82

160

178

92

90

36

54

59

36

38

2050

13

Submitted to DoE on 25 October 2018CO2 emissions trajectories for PPD Moderate never binding (only CB) while water use declines as expected as coal fleet decommissionsScenarios from Draft IRP 2018

CO2 emissions Water usage

82

160

178

92

275 275

210

0

50

100

150

200

250

300

2015 2020 2025 2030 2035 2040 2045 2050

Electricity sector CO2 emissions[Mt/yr]

36

59

0

50

100

150

200

250

300

2015 2020 2025 2030 2035 2040 2045 2050

Electricity sector Water usage[bl/yr]

IRP1

IRP6

IRP3

IRP5

IRP2

IRP7

IRP4

PPD (Moderate)

IRP1

IRP3

IRP6

IRP5

IRP7

IRP2

IRP4

Carbon Budget 2750 Mt 1800 Mt 920 Mt

PPD equiv. > 2750 Mt 2720 Mt 2325 Mt

15


At a glance

Jobs impact of Recommended Plan – reduced role of coal whilst growth in other sectors is expected

• If the Recommended Plan is implemented, there is an employment reduction expected in coal pre-2030

• Overall jobs grow as the power system grows – in solar PV, wind and gas sectors

• This transition needs sufficient preparation – our comments attempt to assist to quantify effects

EAF – Energy Availability Factor

Sources: Eskom; CER

16


450

200

0

500

50

100

150

250

300

350

400 10(3%)

2027

42

Jobs (net)(construction + operations)[’000]

2020

3(1%)

367(2%)

36(10%)

287(81%)

22

245

14

25

107

36

3

385

2021

7

258

3

36

297

44

2022

36

270280

2023

12

2024

393

420

33

36

2025

41

300

4

60

36

2026

42

7

5

64

49

36

233

43

14(4%)

5

62

62

202

36

217

2028

44

75

61

47

36

2029

45(12%)

4 5(1%)

62(16%)

56(14%)

36(9%)

183(47%)

2030

357 350334

353

389

428 428 426

394 386

GasSolar PV EG (PV) NuclearWind Coal

Net reduction of jobs in coal of ≈100k but net gain overall as gas grows to ≈55k jobs towards 2030, RE contributes up to ≈110k by 2030

Sources: Draft IRP 2018; CSIR Energy Centre analysisNote: Job potential includes direct, indirect and induced jobs; Nuclear is estimated based on existing experience at Koeberg (KPMG, 2017)

17


At a glance

Key energy planning risks – Existing fleet low EAF, stationary storage, DSR, further RE learning

• Existing fleet Low EAF: Earlier new-build (2023), outcomes return to IRP1 if low demand and low coal fleetperformance

• Storage: Decreasing stationary storage costs (batteries) results in deployment pre-2030, less NG usage andincreased solar PV

• DSR: A more responsive demand-side test via electric water heating and EVs delays some capacity investmentand deploys slightly more solar PV

• Further RE learning: Increased solar PV and wind post-2030 with timing pre-2030 unchanged, no import hydro

• A risk adjusted scenario: Combining storage, DSR and further RE learning results in increased new-build wind, PV,storage and further lower NG use

•

EAF – Energy Availability Factor; DSR – Demand Side Response; Evs – Electric Vehicles

Sources: Eskom; Tesla; BNEF; CSIR

18

Submitted to DoE on 25 October 2018Draft IRP 2018 (IRP1) - Least-cost deploys considerable wind, solar PV and NG capacity to 2030 and beyond as the coal fleet decommissionsInstalled capacity and electricity supplied from 2016 to 2050 as planned in the Draft IRP 2018

Sources: Draft IRP 2018. CSIR Energy Centre analysis

Installed capacity Energy mix

80

60

40

0

100

20

120

140

160

1

52

2016

23

2030

31

38

1

78

3

0

5

17

3

Total installed capacity (net) [GW]

5 81

38

2

8

32

25

10

3

42

2020

58 1

5

12

410

25

32 11

21

1

2040

119

50

13

10

2050

148

Gas - CCGT

Nuclear

DR

Other Storage

Solar PV

Biomass/-gas

Wind

CSP

Nuclear (new)Hydro+PS

Peaking

Gas - CCGE Coal (new)

Coal

200

0

100

300

400

14

2

15

Electricity production [TWh/yr]

2

53

14 34

2030

3

203

2016

2

29

2

15

202214

42

4

2020

3

25

39

13

4

315

127

1423

8

15

107

2040

3

78

164

311

5

68

2050

245262

309

350

392

6

17

8%(20 TWh/yr)

70%(274 TWh/yr)

RE

14%(35 TWh/yr)

70%(274 TWh/yr)

CO2 free(RE + nuclear)

25%(79 TWh/yr)

30%(94 TWh/yr)

19


40

160

0

60

20

140

180

80

100

200

120

20

20

3.45.1

13.1

17.1

7.2

5.15.1

20

30

6.3

1.5 0.5


1.5

8.75.1

4.4

1.9 1.9

41.7

31.737.4

20

50

0.6

45.6

20

16

1.916.9

20

45

11.8

20

25

20.7

4.8

0.6

0.6

63.0

20

35

63.8

15.3

12.8

20

40

13.6

1.2

9.9

51.657.8 60.5

87.3

112.8

147.2

177.3

196.8


DR CSP

Hydro+PS

Other Storage

Biomass/-gas

Solar PV Peaking

Wind

Gas

Nuclear (new)

Nuclear

Coal (New)

Coal Demand: Median

First new-builds:PV (2027) 6.5 GWWind (2027) 2.1 GWOCGT (2024) 1.9 GWStorage (2027) 1.1 GW

Draft IRP 2018 IRP1 with storage, DSR and lower RE costs results in increased new-build wind, solar PV, storage and less NGInstalled capacity and electricity supplied from 2016 to 2050 for IRP1 with storage, DSR and higher RE cost reductions

Notes: NG = Natural gas


0

100

200

300

400

4

20

25

209

18

20

20

4417

38(9%)

20

16

14

31

20

30

18

202

77

20

40

20

35

17(4%)

4

14

2

122

4

103

20

45

107(27%)

160(40%)

7(2%)

20

50


66(17%)

4(1%)

271

298320

341361

383399

249

20




Demand: Median

First new-builds:PV (2023) 0.4 GWWind (2023) 0.2 GWOCGT (2023) 1.9 GW

Risk-adjusted scenario with Low EAF requires earlier new-build around 2023 too and increased absolute levels of new-build by 2030Installed capacity and electricity supplied from 2016 to 2050 for Risk-adjusted scenario with low coal fleet EAF

60

180

20

0

160

40

200

80

100

140

120

0.6

9.45.1

31.7

3.4 13.75.1

0.6

1.9


41.4

1.51.55.1

1.937.4

51.8

6.3

7.2

1.9

20

40

20

45

20

20

0.7

16.9

61.0

20.167.90.5

5.1

21.4

13.2

12.1

20

35

9.9

20

50

51.657.8

69.4

20

16

119.3

153.6

180.8

198.3

21.1

20

25

1.2

20

30

11.64.4

97.7

CSPDR

Solar PV

Gas

Biomass/-gas

Other Storage Wind

Hydro+PS

Peaking

Nuclear (new)

Nuclear

Coal (New)

Coal

200

0

100

300

400

4

208

20

16

20

20

20

25

36

61

17

174

20

45

18

90

15

66(17%)

33(8%)

180

20

30

20

50

20

35

17(4%)

169(42%)

77

135

2

4

320

20

40

4(1%)

104(26%)

147(2%)


249271

298

340361

382399

21


At a glance

Descriptive inputs/comments – new-build limits, NG import risk and embedded generation

• Technology new-build limits: Still unjustified, constant as power system grows, misaligned with international experience today

• Coal capacity: Investigations reveal that older existing coal capacity could be decommissioned earlier, parts of under construction capacity could be replaced by alternatives and it is not economically optimal to build new coal

• Natural gas import risk: Small role in energy mix (up to 5% pre-2030, 15% by 2050) - can be mitigated by range of domestic options (as well as stationary storage if costs decline)

• Embedded generation: Planning for this is not yet explicit and will need to change (implicit as negative demand)

• Demand profile will change further as different sectors grow, use energy differently and deploy EG for self-use

22


System services and technical considerations

• System adequacy consistent across all scenarios i.e. reserve requirements included

• System non-synchronous penetration: No barriers pre-2030. Only above 25% from 2028 and 37% by 2030 for 10% of the time but at above 80% by 2050 i.e. system integration focus becomes important post-2030

• A critical indicator (inertia): No barriers pre-2030. Post-2030 worst case mitigating solution cost is ≈1% of total system cost

• Evolution of other system services need to be investigated for post-2030 transition expected (reactive power and voltage control, system strength)

• Variable resource forecasting will become more important - SO should be equipped will relevant tools and skills

At a glance

23


• Need to have transparency in input assumptions, model and outcomes comprehensively and consistently published

• Investigate and establish the need for annual technology new-build limits;• Remove annual new-build limits until further investigations establish the need for them

• Develop and implement an integrated program of work on long-term system integration topics i.e. stability, systemstrength, reactive power/voltage control (CSIR already initiated CIGRE WG including Eskom and international SOs)

• Better understanding the cost trajectory of all technologies for domestic application on a periodic basis

• Focussed consideration and investigation into domestic flexibility options

• Improved approaches to better understanding demand (sector shifts, load profile shape, price elasticity of demand)

• Optimise the existing coal fleet while remaining cognisant of opportunity cost of capital expenditure on older assets(retrofitting for improved reliability, efficiency and flexibility)

• Improvements for future IRPs

Going forward – Recommendations

• Inclusion of economic impacts of scenarios. At the very least – employment impacts

24


• Investigate approaches to include geospatial component of IRP – supply/network/demand (co-optimisation)

• Integrating national and local level energy planning for improved co-ordination and leveraging of opportunities

• Sector-coupling opportunities across the full energy sector (not just electricity)

• Further understanding just transition to address labour and socio-economic impacts in the energy sector

• Formally establishing a set of links/triggers between IRP and MTSAO processes (or equivalent)• Periodic updating of the IRP should be prioritised to address dynamic planning environment

• Long-term – structural and strategic

Going forward – Recommendations

• Further investigations into impacts/opportunities of new/emerging technologies e.g. stationary storage, EVs, DSR

25






Background2

Executive Summary1


26


Planning / simulation

world

Actuals / real world

Integrated Resource Plan (IRP): Process for power generation capacity expansion in South Africa

IRP modelling framework (PLEXOS®)

LT1 techno-economic least-cost optimisation

MT/ST2 production cost testing system adequacy

(security of supply)

OutputPer scenario:• Total system costs• Capacity expansion (GW) • Energy share (TWh)• CO2 emissions• Water usage• Jobs in the electricity sector

After policy adjustment: • Final “IRP” for

promulgation• Key questions answered:

o What to build (MW)?o When to build it (timing)?

Procurement(competitive tender

e.g. REIPPPP, coal IPPPP)

Inputs• Ministerial

Determinations for new technology specific generation capacity

Inputs1) Demand Forecast2) Existing Supply Forecast:• Plants under construction• Preferred bidders• Decommissioning• Plant performance3) New Supply Options:• Technology costs

assumptions• Technology technical

characteristics4) Constraints:• CO2 limits• Security/adequacy of

supply level

Outcomes• Preferred bidders• MW allocation• Technology costs

actuals (Ø IPP tariffs)

1 LT = Long-term2 MT/ST = Medium-term/Short-term

27


Tx network (shallow)

Distribution network

(Dx)

[bR/yr]

System services (other)

Other(metering,

billing, customer services,

overheads)

Generation (Gx)

System services

(reserves)

Tx network (deep)

Total system

cost

The IRP currently optimises for the dominant generation costs, system reserves (adequacy) and shallow grid cost components of total system cost

Optimised in PLEXOS model

• CAPEX (plant level)• FOM1

• VOM2

• Fuel• Shallow grid connection

costs

• Gx: Externalities e.g. CO2

emissions costs• Gx: Decommissioning costs• Gx: Waste management

and/or rehabilitation• Gx: Major mid-life overhaul• Tx: Deep costs• Other system services• Dx: Distribution network

costs• Other costs

1 FOM = Fixed Operations and Maintenence costs; 2 VOM = Variable Operations and Maintenence costs; 3 Typically referred to as Ancillary Services includes services to ensure frequency stability, transient stability, provide reactive power/voltage control, ensure black start capability and system operator costs.

Not optimised in PLEXOS modelling framework(Assumption consistent for all scenarios = 0.20 R/kWh)

Not considered

Partially considered previously

(quantified for system inertia)

Not considered

Not considered

Costs excluded in optimisation model:

Costs included in optimisation model:

28


IRP process as described in the Department of Energy’s Draft IRP 2016 document: least-cost Base Case is derived from technical planning facts

Least CostBase Case

Scenario 2Scenario 1

Scenario 3

Case Cost

Base Case Base

Scenario 1 Base + Rxx bn/yr

Scenario 2 Base + Ryy bn/yr

Scenario 3 Base + Rzz bn/yr

… …

Constraint: RE limits

Constraint: e.g. forcing in of nuclear, CSP, biogas, hydro, others

Constraint: Advanced CO2

cap decline

1. Public consultationon costed scenarios

2. Policy adjustment of Base Case

3. Final IRP for approval and gazetting

PlanningFacts

Sources: Based on Draft IRP 2018

29


Reminder: IRP 2010 planned the electricity mix until 2030Installed capacity and electricity supplied from 2010 to 2030 as planned in the IRP 2010


5%(12 TWh/yr)

14%(62 TWh/yr)

RE

50

0

100

150

125

75

25

1.8

0.0

2025

0.5

35.9

2010

0.7

9.2

0.03.4

7.3

1.5

2020

4.85.8

2030

2.8

Total installed net capacity [GW]

8.4

2.1

1.2

4.8

6.3

34.8

2.4

43.0

62.7

9.6

86.6

2.4

0.00.0

1.8

73.6

10%(25 TWh/yr)

34%(149 TWh/yr)

CO2 free

230284

261237

45

75

422

4

2412

0

100

200

300

400

500

600

4

14

Electricity supplied

[TWh]

1313

2010

10

2020

14

2025

6

12

2030

259

343

392

441

00

21

Note: Installed capacity and electricity supplied excludes pumped storage; Renewables include solar PV, CSP, wind, biomass, biogas, landfill and hydro (includes imports). Sources: DoE IRP 2010-2030; CSIR Energy Centre analysis

OtherSolar PV

Wind

CSP

Coal (new)

Hydro

Peaking

Gas

Nuclear (new)

Nuclear

Coal

30


Draft IRP 2016 Base Case planned until 2050Installed capacity and electricity supplied from 2016 to 2050 as planned in the Draft IRP 2016 Base Case


10%(25 TWh/yr)

29%(152 TWh/yr)

RE

10%(40 TWh/yr)

57%(300 TWh/yr)

CO2 free

Note: Installed capacity and electricity supplied includes pumped storage; Renewables include solar PV, CSP, wind, biomass, biogas, landfill and hydro (includes imports). Sources: DoE Draft IRP 2016; CSIR Energy Centre analysis

150

50

125

0

100

75

25

0.7

0.33.4

15.8

0.4

16.8

12.8

4.1

1.9

7.5

36.8

1.9

49.8

2016

135.7

6.1

1.111.1

21.3

0.08.90.2

7.6

7.3

0.05.3

0.7

2050

12.41.1

2.7

30.4

14.3

0.5

2030 2040

13.8

22.0

82.5

7.6

15.0

20.4

17.210.2

108.7

Total installed net capacity [GW]

1.5 1.3

32.6

1.9

0.0

Coal

Solar PV Other storage

CSP

Wind

Other

Peaking

Gas

Hydro+PS

Nuclear (new)

Nuclear

Coal (new)

100

0

300

400

200

500

600

2

93

22

2

66

00

36

2016

5

13

5 116

15

33

0

5

2015

203

2030

5

1

1

33

15

117

2040

28

49

105

148

101

2050

434

528

45

24

3

246

200

34

350

Electricity supplied

[TWh]

72

31






Background2

Executive Summary1


32


A range of scenarios have been assessed as part of the Draft IRP 2018 with key parameter changes

33

Submitted to DoE on 25 October 2018Draft IRP 2018 (IRP1) - Least-cost deploys considerable wind, solar PV and NG capacity to 2030 and beyond as the coal fleet decommissionsInstalled capacity and electricity supplied from 2016 to 2050 as planned in the Draft IRP 2018



60

0

80

20

120

40

160

100

140

38 42

528

0 2523

21

2016


3

78

11

2050

1

1

10

25

38

2

3

17

25

2040

1

3

2020

112

54

10

13

32

2030

1

10

5

31

8

3

50

58

119

148

DR

Biomass/-gas

Other Storage Wind

Solar PV

CSP

Hydro+PS

Peaking

Gas - CCGE

Nuclear (new)

Gas - CCGT

Nuclear

Coal (new)

Coal

0

100

300

200

400

4

14


5

2

78

2

202

34

31

8

3

4

15

203

2016

3

2

313

2

15

315

1215

7

2020

252

42

2030

1415

15

4

164

54

15

129

23

107

3

17

29

68

2050

245264

353

391

2040

8%(20 TWh/yr)

70%(274 TWh/yr)

RE

14%(35 TWh/yr)

70%(274 TWh/yr)


26%(83 TWh/yr)

31%(98 TWh/yr)

34

Submitted to DoE on 25 October 2018Draft IRP 2018 (IRP3) – RE new-build limits mean post-2030 deployment of solar PV and wind is constrained with new-build coal and gas replacing itInstalled capacity and electricity supplied from 2016 to 2050 as planned in the Draft IRP 2018



20

80

40

60

0

140

100

12025

2050

12

9

2

125

14

1

2040

30

42

3

3

22

1


10

712

5

1

3812

3

2016

26

2020

5

11

5

13

1

5

6

49

32

2030

18

8

1

17

8

11

17

5258

77

103

DR

Other Storage

Solar PV

Nuclear (new)Biomass/-gas

CSP

Wind

Hydro+PS

Peaking

Gas - CCGE

Gas - CCGT

Nuclear

Coal (new)

Coal

300

100

200

400

0

15

902263

47

110

2030

2

15

2016

203


3

4

214

2

138

4

14

2

9

8

15153

2020

4

44

15

197

4

245

14

33

10667

2040

63

3129

31

80

2050

313

353

393

22

8

8%(20 TWh/yr)

52%(203 TWh/yr)

RE

14%(35 TWh/yr)

52%(203 TWh/yr)

26%(80 TWh/yr)

30%(95 TWh/yr)


35

Submitted to DoE on 25 October 2018Draft IRP 2018 (IRP5) – Market linked NG price means in less NG usage, notable capacity for system adequacy and increased new-build coalInstalled capacity and electricity supplied from 2016 to 2050 as planned in the Draft IRP 2018



140

0

60

20

100

40

80

120

832

1

2

2

5

2016

26

3

9


3

5

58

18

3172

38

17

2

1

42

2020

52

1

1

1

9

25

1

13

6113

2030

8

6

2040

30

8

4

3

16

10

2050

77

104

125

20

DR

Solar PV

Gas - CCGT

Biomass/-gas

Other Storage

CSP

Wind Coal

Hydro+PS

Peaking

Gas - CCGE

Nuclear (new)

Nuclear

Coal (new)

200

400

100

0

300

4

104

2

2030

215


32

114

2040

15

203

2016

199

242

13

22

8153

15

2020

4

2452

44

14

154

29

3

2050

64

11

102

5

107

4

89

51

31364

264

353

391

47

15

8%(20 TWh/yr)

51%(202 TWh/yr)

RE

14%(35 TWh/yr)

51%(202 TWh/yr)

26%(81 TWh/yr)

30%(95 TWh/yr)


36

Submitted to DoE on 25 October 2018Draft IRP 2018 (IRP6) – Carbon Budget limits new-build coal capacity and deploys new-build nuclear capacity insteadInstalled capacity and electricity supplied from 2016 to 2050 as planned in the Draft IRP 2018



40

60

0

100

140

20

80

120

55

1

2

4

5

2030

38

58

30

13

3

9


17

1

1

2016

3

14

2

2

3

42

17

2020

32

19

1 813

93

22

1

18

1

26

85

2040

2

25

12

72

10

2050

52

77

103

125

DR

Other Storage

Peaking

Biomass/-gas

Coal

Solar PV

CSP

Wind

Hydro+PS

Gas - CCGE

Gas - CCGT

Nuclear (new)

Nuclear

Coal (new)

400

200

300

0

100 55

13

245

67

11

2030

3

4

153

15

2

2


2016

33

4

203

8 415

215

2020

47

2040

422

2

44

154

57

12

290

301225

15

97

106

199

47

13

2050

264

313

353

391

31

8%(20 TWh/yr)

52%(203 TWh/yr)

RE

14%(35 TWh/yr)

66%(258 TWh/yr)

26%(81 TWh/yr)

30%(96 TWh/yr)


37

Submitted to DoE on 25 October 2018Draft IRP 2018 (IRP7) – Market linked NG price & Carbon Budget combines IRP 5&6 meaning less NG and coal capacity, increased nuclear new-buildInstalled capacity and electricity supplied from 2016 to 2050 as planned in the Draft IRP 2018



40

140

100

0

20

120

60

80

4

113

32

261

2

3

1

4

3


25

2050

38

8

15

2016

1

42

2

5

6

3

6

2020

9

1

1

13

2

38

82

2030

18

85

2

18

17

2040

1

25

10

30

10

5258

77

104

125

DR

Solar PV

Other Storage

Biomass/-gas

Coal (new)CSP

Gas - CCGTWind

Hydro+PS

Peaking

Gas - CCGE

Nuclear (new)

Nuclear

Coal

0

100

200

400

300

2050

99

4

9

2

3

215


4

15

76

13

2016

23

15

42

313 47

8

2030

3

2020

2

44

2643

15

192

2

90

353

29

203

125

4317

31

14

64

2040

22

58

245264

391

4

15

106

8%(20 TWh/yr)

51%(201 TWh/yr)

RE

14%(35 TWh/yr)

70%(277 TWh/yr)

30%(95 TWh/yr)

35%(110 TWh/yr)


38

Submitted to DoE on 25 October 2018Draft IRP 2018 (IRP2) – Upper Demand forecast with similar outcomes to IRP3 just with earlier first new-build and more new-build overallInstalled capacity and electricity supplied from 2016 to 2050 as planned in the Draft IRP 2018



120

40

0

20

100

140

80

60

16

14

3

1

9

6

38

2040

1

8

30

8

9


3

1

1

25

2

10

53

2

52

2016

2

53

42

2020

1126

7

2

32

18

2030

8

6 18

2

17

15

1

15

10

2050

58

79

108

130

DR

Other Storage

Solar PV

Coal

Biomass/-gas

CSP

Wind

Gas - CCGE

Hydro+PS

Peaking

Gas - CCGT

Coal (new)

Nuclear (new)

Nuclear

0

100

200

400

300

15

198

911


3

111

2016

4

68

15

31

2040

203

3

2452

4

108

2

17

153

21

28

217

2

39

2020

4

4

438

266

814

2030 2050

46

2

19

32

48

64

103

321

378

428

91

8%(20 TWh/yr)

48%(207 TWh/yr)

RE

14%(35 TWh/yr)

48%(207 TWh/yr)

29%(94 TWh/yr)

33%(108 TWh/yr)


39

Submitted to DoE on 25 October 2018Draft IRP 2018 (IRP4) – Lower Demand forecast with similar outcomes to IRP3 just with later first new-build and less new-build overallInstalled capacity and electricity supplied from 2016 to 2050 as planned in the Draft IRP 2018



0

100

20

120

80

140

60

40 17

2 5


1

4

10

1

53

2

38

6

832

8

12

2016

2123

53

25

2040

8

42

2020

30

2317

1

3

2

2030

1

7

16

1

25

11

96

17

1

10

2050

5258

69

121

DR

Biomass/-gas

Gas - CCGE

Other Storage

Solar PV

CSP

Wind

Nuclear

Hydro+PS

Peaking

Gas - CCGT

Nuclear (new)

Coal (new)

Coal

0

300

100

200

400

11

4

8

2050

4

208

63


15

33

203

20202016

8

28

41

2

14 153

33

81

162

2

15

112

514

193

2030

4

4

29

256

15

15

33

10565

3

30

54

245

290

333

372

2040

8%(20 TWh/yr)

55%(204 TWh/yr)

RE

14%(35 TWh/yr)

55%(204 TWh/yr)

23%(66 TWh/yr)

28%(80 TWh/yr)


40

Submitted to DoE on 25 October 2018Draft IRP 2018 (Recommended Plan) includes RE new-build limits and policy adjustment for new-build coal and imported hydroInstalled capacity and electricity supplied from 2016 to 2030 as planned in the Draft IRP 2018



80

20

0

60

40

100

5.1

1.5

20

20

20

18

37.6

0.6

1.9

20

29

20

16

20

17

20

19

20

21

1.6

20

24

57.8

20

22

20

25

20

23

20

26

3.4


8.1

0.38.0

11.5

1.0

7.6

20

27

3.1

31.7

20

28

1.9

20

30

51.9

61.8

74.1

DR

Other Storage

Solar PV

Biomass/-gas

Gas - CCGE

Wind

CSP

Hydro+PS

Peaking

Gas - CCGT

Nuclear (new)

Nuclear

Coal (New)

Coal

0

400

100

200

300

203

20

16

292

20

17

6(3%)

20

21

217

20

26

20

20

20

22

20

23

20

24

20

25

20

29

20

27

14(7%)

231

31335(17%)

20

18

26428(14%)8(4%)

20

28

3(1%)15(7%)

20

19


199(97%)

20

30

245

First new-builds:Coal (2023) 1.0 GW PV (2025) 0.7 GWWind (2025) 0.2 GWCC-GE (2026) 2.3 GW

41

Submitted to DoE on 25 October 2018CO2 emissions trajectories for PPD Moderate never binding (only CB) while water use declines as expected as coal fleet decommissionsScenarios from Draft IRP 2018


82

160

178

92

275 275

210

0

50

100

150

200

250

300

2015 2020 2025 2030 2035 2040 2045 2050


36

59

0

50

100

150

200

250

300

2015 2020 2025 2030 2035 2040 2045 2050


IRP4

IRP1

IRP5

IRP6

IRP3

PPD (Moderate)

IRP7

IRP2 IRP7

IRP1

IRP3

IRP5

IRP6

IRP2

IRP4


PPD equiv. > 2750 Mt 2720 Mt 2325 Mt

42


2015 2020 2025 2030 2035 2040 2045 20500.00

0.20

0.40

0.60

0.80

1.00

1.20

1.40

1.60

0.84

Average tariff in R/kWh (Jan-2017 Rand)

1.35

1.51

+12%

IRP1

IRP3

IRP5

IRP6

IRP7

Recommended Plan

Average tariff (without CO2 costs) across scenarios revealing how IRP1 (Least-cost) is 12% cheaper than the most expensive scenario (IRP7)

Note: Shift from 2017 to 2018 based on immediate move to cost reflectivity


43


529

591

209

2015 2020 2025 2030 2035 2040 2045 20500

100

200

300

400

500

600

Total system cost (Jan-2017 Rand)[bR/yr]

+63(+12%)

IRP1

IRP3

IRP5

IRP7

IRP6

Recommended Plan

Total system cost increase as the power system grows (as expected) IRP1 is least-cost and ≈R60-bn/yr cheaper than IRP7 by 2050

Note: Shift from 2017 to 2018 based on immediate move to cost reflectivity


44


Energy mix by 2030 similar across scenarios as coal still dominates while IRP1 is ≈R10bn/yr cheaper than IRP7, IRP7 lowest CO2 emissions

11

4

25

14

15

42 2

IRP5

8 2

7

15

3

199 (63%)

202 (64%)IRP1

2

4

4

22

4

4413

22

9

197 (63%)IRP3

4

15

22

2

26

44

2

13199 (63%)IRP6

14

4

15

4

444

11

3

3

15192 (61%)IRP7

2

244

14

3528815

6 (2%)

206 (64%)Rec.

23

Energy Mixin 2030

Demand: 313 TWh

Coal Gas - CCGT Other Storage

Coal (New)

Nuclear

Nuclear (new)

Peaking

Gas - CCGE Hydro+PS

Wind

CSP

Solar PV

Biomass/-gas DR

Costin 2030


360

361

367

362

373

375

Environmentin 2030



217

215

213

215

207

215

199

199

198

199

191

199

2030


45


Least-cost mix confirmed as new-build solar PV, wind and flexible capacity (NG) - ≈R15-55 bn/yr cheaper than alternative scenarios

Energy Mixin 2040

Demand: 353 TWh

Costin 2040


441

466

473

477

494

Environmentin 2040



123

153

168

116

119

59

66

70

56

58

2040

104 (29%)

4

12

54

90

IRP5

21291523

5

12

107 (30%)IRP1

42902914

15

11

14

Rec.

15

33 (9%)

106 (30%)

IRP7

4

IRP3

4

47

4728929

47

15

5

51 (14%)

3015

9 (2%)

29025

29

IRP6 33 4

424399 (28%)

15

47

353

97 (27%)

PeakingCoal

Coal (New) Nuclear (new)

Nuclear

Gas - CCGE

Gas - CCGT

Hydro+PS

Wind

CSP

Solar PV

Biomass/-gas

Other Storage

DR


46


By 2050 - Least-cost mix is 70% solar PV and wind, ≈R30-60 bn/yrcheaper than alternatives, least CO2 emissions and least water usage

78

3

66 (17%)

IRP1

31

16417 31

107

63

64

IRP5

110

13

31

58 (15%)

IRP6

831

80 (20%)

IRP3

6432

106

67

5102 (26%)

64 (16%)

3

3106

22 (6%)

12

17

3

55

13 (3%)

57 (15%)

29

13

31

68 (17%)

IRP7

Rec.

47

3

76


Energy Mixin 2050

Demand: 392 TWh

Nuclear (new)

Solar PVCoal Gas - CCGTNuclear

Coal (New) Gas - CCGE

Peaking

Hydro+PS Biomass/-gas

Wind

CSP

Other Storage

DR

Costin 2050


529

560

564

580

591

Environmentin 2050



82

160

178

92

90

36

54

59

36

38

2050

47






Background2

Executive Summary1


48


CSIR have analysed selected scenarios from Draft IRP 2018 using a transparent, well established and understood tool - iJEDI

The International Jobs and Economic Development Impacts (I-JEDI) model is a freelyavailable economic tool to understand economic changes (jobs focus at this stage) forenergy technology choices

I-JEDI has been customised for application to the South African environment by the CSIRteam

CSIR utilised the developed I-JEDI tool for South Africa to assess the Recommended Plan inthe Draft IRP 2018 for a range of technologies including wind, solar, coal and natural gas(for now)… more in future

High-level approach• I-JEDI estimates economic impacts by characterising construction and operation of

energy projects in terms of expenditures and portion of these made within thecountry (localised)

• These are then used in a country-specific input-output (I-O) model to estimateemployment (amongst a range of other metrics)

An indicative analysis of jobs in nuclear is also provided (but not based on I-JEDI for now)

Analysis of other Draft IRP 2018 scenarios as well as those presented by CSIR to come1

1 Time available was not not sufficient to do this in the 60 day public consultation period.

Sources: https://www.nrel.gov/analysis/jedi/about.html

https://www.nrel.gov/analysis/jedi/about.html

49


Coal dominant in jobs (as expected) but declines to 2030 in Recommended Plan as gas grows, notable gap for wind and PV


500

400

0

150

50

350

200

100

250

300

450

26

1254

39

20

23

21

20

22

3

Construction jobs[‘000]

3

9

3

13

11

3721

20

20

20

29

20

21

3

20

24

3229 16

20

27

33

56

66

52

5

16

20

25

38

54

35

20

26

384

57

35

384

2245

20

28

384

52

24

384

24

20

30

31 36 39

82

131 134 141117 117

350

100

200

0

50

250

150

500

300

400

450

77

36

278

20

20

271

1

20

21

1

4

1

4

264

20

23

1

41

14

736

265

20

24

265

21 1

233

47

36

258

20

25

73

217

5

36

7

20

26

245

41

136714

20

27

36

36

20

22

1818

36

20

28

76

Operations jobs (net)[‘000]

2

1

923

36

202

536 7

36 2

3

1132

183

20

30

326 314 314297 285

270

20

29

Solar PV EG (PV) Wind Gas Nuclear Coal

50


50

0

350

200

100

450

150

300

250

500

400

36

7 62


10(3%)3(1%)14(4%)

7

7(2%)

245

36(10%)

20212020

143

4

2522

5

300

33

280

4

36

297

10

36

2022

7

2023

4

270

2024

39

287(81%)

420

33

36

258

2025

41

36

4

60 5(1%)

42

36

426

2026

42

49

56(14%)

36

233

2027

12

7

5

62

36

217

2028

44

64 5

61

47

36

202

2029

43

62(16%)

36(9%)

183(47%)

2030

357334

385

350 353

389

428 428

394 38645

(12%)

Solar PV NuclearEG (PV) Wind Gas Coal

Net job decrease in coal of ≈100k but net gain overall as gas grows to ≈55k jobs towards 2030, RE contributes up to ≈110k by 2030


51


Focus on coal: Emphasising impact of construction jobs via new-build (excl. Medupi/Kusile) and net decline in operations jobs to 2030

Sources: Draft IRP 2018; CSIR Energy Centre analysisNote: Job potential includes direct, indirect and induced jobs

200

50

100

400

150

250

300

350

0

450

500

20

25

20

22

20

26

20

27

20

28

20

29

20

30

929 32

16 5

Construction jobs[‘000]

20

20

20

23

20

24

20

21

200

50

150

0

100

250

350

300

400

450

500

20

20

20

21

20

24

20

25

20

26

20

27

20

28

217

20

29

20

30

278 265245

183

265

74

77 76 75 76 74 70 67 62 58 52

107112 109 107 107 104

20

22

9488

81

87 84 83 82 83

99

76 73 685763

20

23

79

Operations jobs (net)[‘000]

80

DirectInduced Indirect

52


450

0

250

100

50

200

150

500

300

400

350

93

94

108


217

778082

57

297

86

270

62

2022

99

2021

7074

115

90

2020 2025

120 118

94

112

85

88

2023

58

84

88

104

2024

63

80 76

74

73

67

2027

68

2028

81

2029

52

20302026

287300

280258

245 233

202183

-104(-36%)

Induced DirectIndirect

Net job losses in coal overall of ≈100k, direct jobs in coal shifting from ≈80k in 2016 to ≈50k by 2030

Sources: Draft IRP 2018; CSIR Energy Centre analysisNote: Job potential includes direct, indirect and induced jobs

53



Descriptive comments5.2

Scenarios5.1




Background2

Executive Summary1


54




Existing coal fleet performancee

Risk-adjusted scenariod

Technology learningc

Impact of Demand Side Response (DSR)b

Impact of stationary storagea

Scenarios5.1




Background2

Executive Summary1


55









Scenarios5.1




Background2

Executive Summary1


56


Impact of stationary storage (scenario)

In the Draft IRP 2018 – no cost reductions are considered for stationary storage

What if stationary storage costs start to decline?

57


2 100

0

100

200

300

400

500

600

700

800

900

1 000

0

2 000

4 000

6 000

8 000

10 000

12 000

14 000

2010 2015 2020 2025 2030 2035 2040 2045 2050

1 400

Overnight capital cost [R/kWh](Jan-2017-Rand) [USD/kWh]

2 800

-75%

-81%

IRP2018 (Li-Ion 1hr)

IRENA - High (2017)

Nykvuist - High (2015)

This scenario (Li-Ion 1hr)

IRP2018 (Li-Ion 3hr)

BNEF (2017)

This scenario (Li-Ion 3hr)

CSIRO - High (2015)

CSIRO - Low (2015)

Nykvuist - Low (2015)

IDC - 2016

USD:ZAR = 14.00; NOTE: Battery packs are assumed to make up 60% of total utility-scale stationary storage costs (from BNEF).Sources: StatsSA for CPI; Draft IRP 2018; CSIR; BNEF; CSIRO (2015); Nykvist (2015); IDC; IRENA (2017)

Stationary storage (excl. pumped storage):200 $/kWh (2030), 150 $/kWh (2040), 100 $/kWh (2050)

58

Submitted to DoE on 25 October 2018Draft IRP 2018 IRP1 with storage cost declines means notably less NG, with storage deployed from 2027, increased solar PV and windInstalled capacity and electricity supplied from 2016 to 2030 as planned in the Draft IRP 2018



30

0

10

60

100

20

90

40

70

50

80

20

21

37.4

1.9

13.3

20

20

20

29

20

25

20

16

20

17

20

18

20

19

20

22

20

24

5.1

20

26

20

27


1.5

3.2

5.1

0.6

14.3

3.4

0.5

8.6

1.5

1.9

20

23

31.7

20

30

51.6

57.860.2

81.7

20

28

GasDR

Other Storage

Biomass/-gas

Solar PV Coal (New)Peaking

CSP

Wind

Hydro+PS

Nuclear (new)

Nuclear

Coal

250

200

400

100

0

300

50

150

350

209(64%)

18(5%)

38(12%)

20

23

20

17

209

298

20

20


20

29

20

22

20

16

20

18

20

19

20

21

271249

20

24

20

25

20

27

20

28

26(8%)

20

26

249227

14(4%)

7(2%)

20

30

326

Demand: Median


59

Submitted to DoE on 25 October 2018Draft IRP 2018 IRP1 with storage cost declines means less NG, increased solar PV and wind with considerable deployment post-2030Installed capacity and electricity supplied from 2016 to 2050 for IRP1 with Demand Side Response

Notes: Assumed capacity factors for wind and solar PV differ slightly to IRP1


Demand: Median


0

40

160

20

60

80

100

120

180

140

200

20

16

1.5

5.1

20

35

5.1

20

25


0.6

20

20

7.7

3.2

3.41.937.4

0.614.3

7.6

32.2

39.4

1.9

11.9

13.3

16.9

20

40

20

45

0.5

19.7

2.6

0.6

1.9

48.9

31.7

56.2

20

30

7.6

11.0

10.4

57.81.5

15.8

8.6

9.9

20

50

51.660.2

81.7

103.8

129.1

151.2

169.1

DR

Solar PV

Other Storage

Biomass/-gas

CSP

Wind

Hydro+PS

Peaking

Gas

Nuclear

Nuclear (new)

Coal (New)

Coal

0

400

300

200

100

375

60

209

110

20

50


271

20

40

38

48(12%)

33

4

26

20

16

20

20

18

33(8%)

20

35

352

7

2

323

20

25

14

111

20

45

4(1%)

298

83(21%)

209

153(39%)

326

20

30

5(1%)

71(18%)

249

404429

14


60


40

-50

0

-40

-30

-20

10

-10

30

50

20

3

-8

11

Difference - Total installed capacity (net) [GW]

-2-2-1

20

20

20

30

20

25

20

35

3

20

16

1

-3

20

40

20

45

20

2-2

-12

20

50

-9

12

Difference in installed capacity and energy mix with storage cost declines relative to IRP1, less NG with increased solar PVInstalled capacity and electricity supplied from 2016 to 2050 for IRP 1 with storage cost declines


-50

-30

-20

50

30

-10

0

10

40

20

-40

2

20

45

20

40

-2

63

-2-6

20

-6

41

-1

-17

-1

20

16

20

25

20

30

Difference - Electricity production [TWh/yr]

20

50

20

20

-4

20

35


CSPDR

Solar PV

Nuclear (new)Other Storage

Biomass/-gas

Gas

Wind

Hydro+PS Nuclear

Peaking Coal (New)

Coal

61

Submitted to DoE on 25 October 2018CO2 emissions trajectories for PPD Moderate never binding while water use declines as expected as coal fleet decommissionsIRP 1 with storage cost declines


82

78

275 275

210

0

50

100

150

200

250

300

2015 2020 2025 2030 2035 2040 2045 2050


36

35

0

50

100

150

200

250

300

2015 2020 2025 2030 2035 2040 2045 2050


IRP1

PPD (Moderate)

IRP1 with storage cost declines

IRP1 with storage cost declines

IRP1


PPD equiv. > 2750 Mt 2720 Mt 2325 Mt

62


2015 2020 2025 2030 2035 2040 2045 20500

100

200

400

300

500

600

437

Total system cost in bR/yr (Jan-2017 Rand)

358

441

529

521

199

299

IRP1 with storage cost declinesIRP1

Total system cost: IRP1 with storage cost declines ≈R8 bn/year less expensive by 2050 than IRP1, marginal difference before 2030

Sources: Draft IRP 2018. CSIR Energy Centre analysis.

bR

IRP1 Storage cost

declines

4 018 4 005 -12(-0.3%)

Net Present Value System Cost

(2016 - 2050)Total System Cost

Note: Average tariff projections (and resulting total system cost) consider an offset representative of Tx/Dx/Other costs to align with starting point of 0.84 ZAR/kWh (0.20 ZAR/kWh). From 2017 to 2018, immediate cost reflectivity is considered too (as in Draft IRP 2018) i.e. 0.21 ZAR/kWh offset.

63









Scenarios5.1




Background2

Executive Summary1


64


Impact of demand response - EVs, warm water heating (scenario)

What if the demand side became more flexible and responsive i.e. Demand Side Response (DSR)

Similar to previous comments in Draft IRP 2016 with some updated analysis on DSR options

Warm-water heating (geysers)

Electric vehicles

65


Majority of EV owners charge vehicles overnight in off-peak – this will have a relatively small impact on demand profile (beyond 2030)

0.00

0.02

0.04

0.06

0.08

0.10

0.12

0 2 4 6 8 10 12 14 16 18 20 22 24

Hour

Ch

argi

ng

Frac

tio

n (

%)

U.S Department of Energy (2014)

EPRI (2007)

California Energy Commission and NREL (2018)

NOTE: EVs assumed only light passenger vehicles for now.

Sources: Calitz (2018); Bedir, N. et. Al. (2018); U.S. Department of Energy (2014); EPRI (2007)

30

2

60

40

6 128 1614 22 24

50

10

20

20

40

100 18

Ho

url

y el

ectr

icit

y d

eman

d (

GW

)Hour

+2.2(+5%)

Base Case:No EVs

3 million electric vehicles (9-mln vehicle parc)

Typical EV charging profilesImpact of typical EV charging

on RSA demand profile

66


Electric vehicle usage for demand side flexibility i.e. Vehicle-to-Grid (V2G)

Inclusion of a demand side flexibility resource in the form of mobile storage (electric motor vehicles)demonstrates impact on the power system as adoption increases

Considered with similar functionality as that of Electric Water Heating (EWH) demand shaping - a resourcewith intra-day controllability (can be dispatched as needed on any given day) based on power systemneeds i.e. vehicle-to-grid (V2G)

Key input parameters to estimate potential demand shaping via electric motor vehicles:• Current population

• Expected population growth to 2050

• Current number of motor vehicles

• Expected motor vehicles per capita

• Adoption rate of electric vehicles to 2050

• Electric vehicle fleet capacity (MW)

• Electric vehicle energy requirement (GWh/d)

• Proportion of electric vehicle fleet connected simultaneously

67


Electric vehicle demand shaping can provide ~96 GW/4.2 GW (demand increase/decrease) with ~40 GWh/d of dispatchable energy by 2050

Sources: CSIR estimates; StatsSA; eNaTis

Property Unit 2016-2019 2020 2031 2040 2050

Population [mln] 0 - 0 58.0 61.7 64.9 68.2

Number of motor vehicles [mln] 7 - 8.2 8.5 12.3 16.2 20.5

EVs adoption [%] 0 - 0 1.5 8.1 28.5 48.9

Number of EVs [mln] 0 - 0 0.1 1.0 4.6 10.0

EVs energy requirement [TWh/a] - 0.5 3.7 17.1 37.0

EVs energy requirement [GWh/d] - 1.3 10.1 46.8 101.4

EVs (demand increase) [MW] - - 4 600 44 300 95 800

EVs (demand decrease) [MW] - - 400 2 000 4 200

68


Demand shaping as a demand side resource - domestic electric heaters (EWHs)

Many opportunities for demand shaping in a number of end-use sectors (domestic, commercial, industrial)

In the scenarios assessed by CSIR - the intention of including one particular demand shaping opportunity(domestic electric water heating) is to demonstrate the significant impact this can have on the power system.

Modelled as a resource with intra-day controllability (can be dispatched as needed on any given day) based onpower system needs

Key input parameters to estimate potential demand shaping via EWH:• South African population (to 2050)

• Number of households (current)

• Number of persons per household (future)

• EWHs (current)

• EWHs per household (future)

• Adoption rate of demand shaping via EWHs (future)

• Calibration for power (MW) and energy (TWh) used for electric water heating (existing)

• Movement to EWH technologies i.e. heat pumps vs electric geysers (future)

69


Demand shaping can provide ~24 GW/3 GW (demand increase/decrease) with ~70 GWh/d of dispatchable energy by 2050

Sources: CSIR estimates; StatsSA; AMPS survey; Stastista; Eskom; Draft IRP 2016

Property Unit 2016-2019 2020 2030 2040 2050

Population [mln] 55.7 - 57.5 58.0 61.7 64.9 68.2

Number of HHs [mln] 16.9 - 18.1 18.5 22.4 26.0 27.3

Residents per HH [ppl/HH] 3.29 - 3.17 3.13 2.75 2.50 2.50

HHs with EWH [%] 28 - 33 34 50 75 100

HHs with EWH [mln] 4.7 - 5.9 6.3 11.2 19.5 27.3

Demand shaping adoption [%] - 2 25 100 100

Demand shaping [TWh/a] - 0.4 5.4 28.3 26.4

Demand shaping [GWh/d] - 1.1 14.9 77.4 72.3

Demand shaping (demand increase) [MW] - 371 4 991 25 970 24 265

Demand shaping (demand decrease) [MW] - 46 620 3 226 3 015

70


60

0

160

20

40

180

100

80

120

200

140

13.4

1.9

20

16

1.5

20

30

29.3

0.612.8

5.1

1.9

37.4

0.5

3.410.7

20

20

4.1

94.3

51.6

37.3

20

40

31.7

4.4

16.9

20

25

0.6

20.2

1.9

20

45


7.2

1.5

0.7

20

35

58.2

37.4

10.7

7.67.6

5.1 22.2

9.9

23.8

60.5

20

50

57.8

81.3

128.7

149.1

167.0



Demand: Median



Draft IRP 2018 IRP1 with DSR impact marginal, shift in timing of import hydro, wind & PV (2030-2040)Installed capacity and electricity supplied from 2016 to 2050 for IRP1 with Demand Side Response

DR

Biomass/-gas

CSP

Other Storage

PeakingSolar PV

Wind

Hydro+PS

Coal (New)

Gas

Nuclear (new)

Nuclear

Coal

0

400

100

300

200

54

20

16

20

40


30

14

39

20

30

209

20

20

20

25

65(16%)

23

209

18

20

35

4

2

104

298

353

320

271

20

45

71(18%)

1014

4(1%)64(16%)

158(40%)

114

339

34(9%)3(1%)

20

50

249

360379

398

71

Submitted to DoE on 25 October 2018Difference in installed capacity and energy mix with DSR relative to IRP1 marginal, shift in timing of import hydro, wind & PV (2030-2040)Installed capacity and electricity supplied from 2016 to 2050 for IRP1 with Demand Side Response



-20

-10

20

40

10

0

30

-50

50

-30

-40


20

45

20

30

20

35

4-1

-1

20

40

20

25

1 7

20

50

20

20

-1 1

20

16

Other Storage

DR

Coal (New)Solar PV

Wind

Biomass/-gas

CSP

Hydro+PS

Peaking

Gas

Nuclear (new)

Nuclear

Coal

-20

20

-30

10

0

40

-40

-10

30

50

-50

2

20

40

20

30

-3 11

-4

1

-1

20

20

20

35


20

16

20

45

2

20

25

1

20

50

72

Submitted to DoE on 25 October 2018CO2 emissions trajectories for PPD Moderate never binding while water use declines as expected as coal fleet decommissionsIRP 1 with Demand Side Response


82

82

275 275

210

0

50

100

150

200

250

300

2015 2020 2025 2030 2035 2040 2045 2050


36

36

0

50

100

150

200

250

300

2015 2020 2025 2030 2035 2040 2045 2050


IRP1

IRP1 with DSR

PPD (Moderate)

IRP1

IRP1 with DSR


PPD equiv. > 2750 Mt 2720 Mt 2325 Mt

73


2015 2020 2025 2030 2035 2040 2045 2050

400

0

100

200

300

500

600


299

360

441

440

529

199

IRP1 IRP1 with DSR

Sources: Draft IRP 2018. CSIR Energy Centre analysis. Eskom on Tx, Dx costs

IRP1

bR

4 018

DSR

4 015 -2(0.1%)



Total system cost: IRP1 with DSR marginal difference in total system cost relative to IRP1


74

Submitted to DoE on 25 October 2018Generally – additional EV demand met by least-cost mix of wind, solar PV and gas whilst V2G shifts this mix more towards solar PV and less gasImpact on least-cost capacity mix

EVs as a demand shaping resource(V2G i.e. implicit in demand)

• Increase in proportion of new solar PV vs. wind

• Less gas capacity i.e. lower gas energy share

• Relative reduction in total system cost

EVs typical configuration (G2V i.e. additional demand)

• For 1-mln EVs, increase of ≈3 TWh/yr

• For 1-mln EVs, increase ≈1 GW peak demand

• New build capacity to meet charging demand is

mostly wind, solar PV and gas

• Most charging demand met by wind and gas

2030

G2V - Grid to vehicle V2G - Vehicle to grid

75









Scenarios5.1




Background2

Executive Summary1


76


3.85

2.29

1.23

0.65

0.220.22

1.060.89

0.72

0.79

0.54

2010 2015 2020 2025 2030 2035 2040 2045 2050

2.00

4.00

0.00

1.00

3.00

0.39

Equivalent tariff,Jan 2017, [ZAR/kWh]

0.96

1.29-40%

-66%

Actuals: REIPPPP (BW1-4Exp)

Assumptions: IRP 2016 (Upper)

Assumptions: IRP 2016 (Lower)

Assumption for further RE cost reductions



BW1 BW 4 (Expedited)Notes: REIPPPP = Renewable Energy Independant Power Producer Programme; BW = Bid Window; bid submissions for the different BWs: BW1 = Nov 2011; BW2 = Mar 2012; BW 3 = Aug 2013; BW 4 = Aug 2014; BW 4 (Expedited) = Nov 2015Sources: StatsSA for CPI; IRP 2010; South African Department of Energy (DoE); DoE IPP Office; CSIR analysis . Learning rate - Bloomberg New Energy Outlook 2017

Solar PV learning assumptions in Draft IRP 2018Actual solar PV tariffs and forecasted tariff trajectory

77


1.60

1.25

0.92

0.73

0.65

0.35

1.16

0.78

0.81

0.60

2010 2015 2020 2025 2030 2035 2040 2045 20500.00

0.80

0.40

1.20

1.60

2.00


0.87

0.47

0.35

1.04

-28% -47%

Assumption for further RE reductions






Notes: REIPPPP = Renewable Energy Independant Power Producer Programme; BW = Bid Window; bid submissions for the different BWs: BW1 = Nov 2011; BW2 = Mar 2012; BW 3 = Aug 2013; BW 4 = Aug 2014; BW 4 (Expedited) = Nov 2015Sources: StatsSA for CPI; IRP 2010; South African Department of Energy (DoE); DoE IPP Office; CSIR analysis . Learning rate - Bloomberg New Energy Outlook 2017

BW1 BW 4 (Expedited)

Wind cost learning assumptions in Draft IRP 2018Actual wind tariffs and forecasted tariff trajectory

78


2.652.65

1.75

1.36

3.28

2.12

2.89

2.49

1.14

2010 2015 2020 2025 2030 2035 2040 2045 20500.00

1.00

2.00

3.00

4.00

3.30


3.74

3.50

3.07

1.32

1.75

1.36

-36%

Assumptions: IRP2010 - high

Assumptions: IRP2010 - low



Assumptions for further RE reductions




Notes: REIPPPP = Renewable Energy Independant Power Producer Programme; BW = Bid Window; bid submissions for the different BWs: BW1 = Nov 2011; BW2 = Mar 2012; BW 3 = Aug 2013; BW 4 = Aug 2014; BW 4 (Expedited) = Nov 2015; For CSP bid window 3, 3.5 and 4 Exp, weighted average tariff of base and peak tariff calculated on the assumption of 64%/36% base/peak tariff utilisation ratio; Sources: StatsSA for CPI; IRP 2010; South African Department of Energy (DoE); DoE IPP Office; CSIR analysis

BW1 BW 4 (Expedited)

Input assumptions for CSP from Draft IRP 2018 and further cost declinesToday’s latest tariff as starting point, same cost decline as per IRP 2010

79


20

60

120

0

160

80

200

40

180

100

140

20

45

27.6

20

16

1.5

20

25

5.13.4 2.6

31.7

1.9

107.2

37.4

60.2

20

20

12.05.1

0.613.9

15.8


20

30

20

35

20

40

49.2

20

50

69.1

7.6

20.2

1.5

9.9

51.657.8

84.0

142.8

164.8

184.2


Demand: Median



Draft IRP 2018 IRP1 with further RE cost reductions, increased solar PV and wind from 2030 onwards, timing unchanged, no import hydroInstalled capacity and electricity supplied from 2016 to 2050 for IRP1 with higher RE cost reductions

Biomass/-gas

Peaking

DR CSP

Coal (New)

Gas

Other Storage

Solar PV

Wind

Hydro+PS

Nuclear (new)

Nuclear

Coal

0

100

200

400

300

20

50

209

20

16

20

20

20

25

25

46271

66(17%)


4

128614

18

204

20

30

20

35

14

66321

2

103

249

185

22

20

40

298

4(1%)

84(21%)

172(43%)

20

45

17(4%)5(1%)51(13%)

342361

381399

80

Submitted to DoE on 25 October 2018Difference in installed capacity and energy mix with higher RE cost reductions relative to IRP1, higher RE & peaking gas, less mid-merit gasInstalled capacity and electricity supplied from 2016 to 2050 for IRP1 with higher RE cost reductions



-30

-40

-10

-50

30

-20

40

0

10

50

20

-1 -3

11

20

16

-3-2


20

30

20

20

20

25

21 510

2

20

40

12

20

35

-4

20

50

20

45

6

Solar PV

Biomass/-gas

Other Storage Nuclear

Wind

DR Hydro+PS

CSP Peaking

Gas

Nuclear (new)

Coal (New)

Coal

20

10

50

-50

-30

40

-40

30

-20

-10

0

20

25

213

22

02

0

-2

-13

-4

20

30

20

35

20

50


-16

-7-1

-10

3

20

40

1221

-4

12

-17

20

16

2

20

45

81

Submitted to DoE on 25 October 2018CO2 emissions trajectories for PPD Moderate never binding while water use declines as expected as coal fleet decommissionsIRP 1 with higher RE cost reductions


82

76

275 275

210

0

50

100

150

200

250

300

2015 2020 2025 2030 2035 2040 2045 2050


36

33

0

50

100

150

200

250

300

2015 2020 2025 2030 2035 2040 2045 2050


PPD (Moderate)

IRP1

IRP1 with further RE cost reductions

IRP1 with further RE cost reductions

IRP1


PPD equiv. > 2750 Mt 2720 Mt 2325 Mt

82


2015 2020 2025 2030 2035 2040 2045 2050

300

0

100

200

400

500

600

356


199

441

418

529

487360

299

IRP1 IRP1 with further RE cost reductions


IRP1 RE cost reductions

bR

4 018 3 951 -67(-2%)



Total system cost: IRP1 with higher RE cost reductions would result in lower system cost


83









Scenarios5.1




Background2

Executive Summary1


84


40

160

0

60

20

140

180

80

100

200

120

20

20

3.45.1

13.1

17.1

7.2

5.15.1

20

30

6.3

1.5 0.5


1.5

8.75.1

4.4

1.9 1.9

41.7

31.737.4

20

50

0.6

45.6

20

16

1.916.9

20

45

11.8

20

25

20.7

4.8

0.6

0.6

63.0

20

35

63.8

15.3

12.8

20

40

13.6

1.2

9.9

51.657.8 60.5

87.3

112.8

147.2

177.3

196.8


DR CSP

Hydro+PS

Other Storage

Biomass/-gas

Solar PV Peaking

Wind

Gas

Nuclear (new)

Nuclear

Coal (New)

Coal Demand: Median


Draft IRP 2018 IRP1 with storage, DSR and lower RE costs results in increased new-build wind, solar PV, storage and less NGInstalled capacity and electricity supplied from 2016 to 2050 for IRP1 with storage, DSR and higher RE cost reductions



0

100

200

300

400

4

20

25

209

18

20

20

4417

38(9%)

20

16

14

31

20

30

18

202

77

20

40

20

35

17(4%)

4

14

2

122

4

103

20

45

107(27%)

160(40%)

7(2%)

20

50


66(17%)

4(1%)

271

298320

341361

383399

249

85


20

60

0

-20

-40

-60

40

20

16

-11

20

30

-4

20

25

20

45

20

40

9

20

20

1

-5 -17-4


20

35

23

4

15

-10

44

1

-17

-27

20

50

0

-60

20

-40

-20

60

40

-8

1

-10

21

7

20

50

20

45

5


20

16

20

35

4

12

-3

20

25

20

40

5

7

13

-2

20

20

5

20

30

-3

26

-9-4

Difference in installed capacity and energy mix Risk-adjusted scenario relative to IRP1, higher wind, PV & storage, less NGInstalled capacity and electricity supplied from 2016 to 2050 for IRP1 with storage, DSR and higher RE cost reductions



DR

Other Storage

Solar PV

Biomass/-gas

CoalCSP

Coal (New)

Wind

Hydro+PS

Peaking

Gas

Nuclear (new)

Nuclear

86

Submitted to DoE on 25 October 2018CO2 emissions trajectories for PPD Moderate never binding while water use declines as expected as coal fleet decommissionsIRP 1 with storage, DSR and higher RE cost reductions


82

72

275 275

210

0

50

100

150

200

250

300

2015 2020 2025 2030 2035 2040 2045 2050


36

320

50

100

150

200

250

300

2015 2020 2025 2030 2035 2040 2045 2050


IRP1

IRP1 Risk-adjusted scenario

PPD (Moderate)

IRP1

IRP1 Risk-adjusted scenario


PPD equiv. > 2750 Mt 2720 Mt 2325 Mt

87


2015 2020 2025 2030 2035 2040 2045 2050

400

600

200

0

100

300

500 441


360

354

413

529

477

199

299

IRP1 Risk-Adjusted


Risk-Adjusted

bR

IRP1

4 018 3 937 -81(-2%)



Total system cost: Risk-adjusted scenario results in lower system cost than IRP1


88


Demand and Supply in GW

30

10

0

50

20

40

60

Draft IRP 2018 IRP1: 2030

Monday Tuesday Wednesday Thursday Friday Saturday Sunday

Sources: CSIR analysis

Exemplary Week under Draft IRP 2018 IRP1

Curtailed solar PV and wind

CSPOther Storage

DR

GasBiomass/-gas

Solar PV

Wind

Hydro+PS

Peaking

Coal

NuclearElectricity demand

89



60

0

50

30

10

20

40

Risk-Adjusted Scenario: 2030



Exemplary Week under Risk-Adjusted Scenario


DR

Wind

Other Storage

Solar PV

Biomass/-gas

CSP Peaking

Hydro+PS

Gas

Coal


90



10

50

0

20

30

40

70

60

80






NuclearPeaking

DR

Other Storage

Biomass/-gas

Solar PV

CSP

Wind

Hydro+PS

Gas

Coal Electricity demand

91



70

0

40

10

20

30

50

60

80

Risk-Adjusted: 2040




Curtailed solar PV and wind Gas

DR Solar PV

Biomass/-gas

Other Storage

Wind

CSP

Hydro+PS

Peaking

Coal


92



30

70

0

50

10

20

40

60

80

90






Solar PVDR

Biomass/-gas

Other Storage CSP

Wind

Hydro+PS

Peaking

Coal

Gas


93



50

0

60

10

20

30

70

40

80

90

Risk-Adjusted: 2050





CSP

Biomass/-gas

DR

Other Storage

Solar PV

Wind

Hydro+PS

NuclearPeaking

Gas

Coal Electricity demand

94




Risk-adjusted with low coal fleet performancee.b

IRP1 with low coal fleet performancee.a






Scenarios5.1




Background2

Executive Summary1


95











Scenarios5.1




Background2

Executive Summary1


96


Eskom existing fleet performance – EAF (scenario)

If the existing coal fleet does not recover to the expected “Moderate“ EAF used in the Draft IRP 2018

“Low“ EAF of existing coal fleet is considered to test

2016 2018 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040 2042 2044 2046 2048 2050

84

76

78

82

80

88

0

70

72

74

86

90

74

Energy Availability Factor (EAF)[%]

80

83

72

8180

83

75

80

82

84

80

ModerateLow High

97


140

0

80

200

120

100

20

40

60

180

160

1.5

0.6

5.1

12.1

16.6

20

40

20

20

3.4

1.91.937.4

20

16

20

25

0.6

18.30.5

20

35

11.1

31.7

1.9

7.6

20

30

39.1

18.5

20

45

5.1

16.9

30.5

7.6

32.7

1.5

62.5

6.324.4


20.9

0.6

9.9

20

50

51.657.8

68.3

92.0101.7

127.1

144.1

158.6



Peaking

DR

Biomass/-gas

Other Storage Wind

Solar PV

CSP

Hydro+PS

Gas Coal

Nuclear (new)

Nuclear

Coal (New)

Demand: Median


Draft IRP 2018 IRP1 with Low EAF requires earlier new-build around 2023 and increased absolute levels of new-build by 2030Installed capacity and electricity supplied from 2016 to 2050 for IRP1 with low coal fleet EAF

0

100

300

200

400

102

57

20

40

20

45

18

59(15%)

170(43%)

4

13

320299


208

20

20

20

16

20

25

72(18%)

109

3

186

20

30

20

35

2

48

341

35

35

15

33

4(1%)56(14%)

20

50

34(8%)4(1%)

271

15

249

360380

398

98

Submitted to DoE on 25 October 2018Difference in capacity and energy mix with low EAF relative to IRP1, increased level of new-build, built earlier to cater for lower coal supplyInstalled capacity and electricity supplied from 2016 to 2050 for IRP1 with low coal fleet EAF



50

-50

10

20

-30

30

-40

40

-20

-10

0652

11

20

40


20

35

20

16

20

20

20

25

5

-11

20

30

-21

-7

10

20

50

-5

20

45

-40

-50

10

-30

20

-20

-10

0

50

30

40

20

20

6

20

35

-3


3

20

16

20

25

20

50

20

30

-4

20

45

22

20

40

14

-3

1

DR

Coal (New)

Other Storage

Biomass/-gas

Solar PV

CSP

Wind

Hydro+PS

Peaking

Gas

Nuclear (new)

Nuclear

Coal

99

Submitted to DoE on 25 October 2018CO2 emissions trajectories for PPD Moderate never binding while water use declines as expected as coal fleet decommissionsIRP 1 with low coal fleet EAF


82

82

275 275

210

0

50

100

150

200

250

300

2015 2020 2025 2030 2035 2040 2045 2050


36

36

0

50

100

150

200

250

300

2015 2020 2025 2030 2035 2040 2045 2050


IRP1

IRP1 with low EAF

PPD (Moderate)

IRP1

IRP1 with low EAF


PPD equiv. > 2750 Mt 2720 Mt 2325 Mt

100


2015 2020 2025 2030 2035 2040 2045 2050

300

0

100

200

400

500

600

441

445


360

371

529

199

299

IRP1 IRP1 Low EAF


bR

IRP1 IRP1 Low EAF

4 018 4 067 +49(+1.2%)



Total system cost: IRP1 with low EAF higher system cost than IRP1 due to additional capacity required


101











Scenarios5.1




Background2

Executive Summary1


102




Demand: Median


Risk-adjusted scenario with Low EAF requires earlier new-build around 2023 too and increased absolute levels of new-build by 2030Installed capacity and electricity supplied from 2016 to 2050 for Risk-adjusted scenario with low coal fleet EAF

0

140

20

40

60

160

80

200

180

100

120

1.9

61.0

6.3

5.1

51.8

5.1

20

45

37.4

20

50


0.6

0.51.51.5

21.4

20

16

9.4

1.91.2

31.7

20

30

20

35

41.4

5.113.7

20

40

16.9

0.7

20

20

20

25

67.9

0.6

5.113.2

20.1

12.1

3.4

9.9

51.657.8

69.1

97.1

116.9

149.2

174.9

191.0

1.9

DR

Other Storage

Biomass/-gas

Solar PV

CSP

Wind

Hydro+PS

Peaking

Gas

Nuclear (new)

Nuclear

Coal (New)

Coal

100

400

0

200

300

20

16

20

25

36

61

17

180


4

20

35

208

17

14

15

20

30

249

4

2

20

50

135

20

45

418

90

320

20

40

4(1%)

271

20

20

169(42%)

17(4%)7(2%)

104(26%)

77

66(17%)

298

340361

382399

33(8%)

103

Submitted to DoE on 25 October 2018Difference in capacity and energy mix with low EAF relative to IRP1, increased level of new-build, built earlier to cater for lower coal supplyInstalled capacity and electricity supplied from 2016 to 2050 for Risk-adjusted scenario with low coal fleet EAF



-60

-40

50

-10

0

10

-50

-20

20

30

60

40

70

-30

-70


9

20

16

20

20

5

20

25

-9

-2

8

20

30

7

20

50

12

12

-3-3-7

-4

4

20

35

7

14

21

24

20

40

-12

20

45

Biomass/-gas

Coal (New)

DR CSP

Other Storage

Gas

Solar PV

Coal

Wind

Hydro+PS

Peaking

Nuclear (new)

Nuclear

30

20

-50

-30

-60

-40

40

-20

-10

50

0

60

10

70

-70 20

20

20

16

412

02

5


14

19

20

45

-32

20

35

20

30

-23

20

40

23

-18

-11

1

289

1

20

50

4

-17

-4

-27

-4

104

Submitted to DoE on 25 October 2018CO2 emissions trajectories for PPD Moderate never binding while water use declines as expected as coal fleet decommissionsRisk-adjusted scenario with low coal fleet EAF


82

71

275 275

210

0

50

100

150

200

250

300

2015 2020 2025 2030 2035 2040 2045 2050


36

310

50

100

150

200

250

300

2015 2020 2025 2030 2035 2040 2045 2050


IRP1

Risk-adjusted with low EAF

PPD (Moderate)

IRP1

Risk-adjusted with low EAF


PPD equiv. > 2750 Mt 2720 Mt 2325 Mt

105


2015 2020 2025 2030 2035 2040 2045 2050

500

200

0

100

400

300

600

441

199


299

360

354

413

529

477

466

IRP1 Risk-Adjusted Low EAFRisk-Adjusted Mod EAF


bR

3 937

Risk-Adj Mod EAF

Risk-Adj Low EAF

3 974 +37(+1%)



Total system cost: Risk-Adjusted with low EAF results in higher system cost than mod EAF due to additional capacity required pre-2035


106



Demand profilee

Planning for embedded generationd

Natural gasc

New-build and under-construction coal capacityb

Technology new-build limitsa


Scenarios5.1




Background2

Executive Summary1


107



Demand profilee


Natural gasc




Scenarios5.1




Background2

Executive Summary1


108


Draft IRP 2018 investigated implications of unconstrained least-cost (IRP1) but RE new-build limits are maintained for all other scenarios

“The scenario without new-build limits provides the least-cost option by 2030“ [DoE, Draft IRP 2018, pp. 34 of 75]

“Imposing new-build limits on RE will not affect the total installed capacity and the energy mix for the period up to 2030“

[DoE, Draft IRP 2018, pp. 34 of 75]

“The scenario without RE annual build limits provides the least-cost option by 2050“ [DoE, Draft IRP 2018, pp. 35 of 75]

“The scenario without RE annual build limits provides the least-cost electricity path to 2050“ [DoE, Draft IRP 2018, pp. 35 of 75]

Why new-build limits (on any technology – needs justification)?

Could be various reasons

• Import/transport link limitations (infrastructure – ports, roads)

• Industry ability to deliver (skills, development, construction)

• Available Tx/Dx networks to evacuate power

• System security/stability

109


Draft IRP 2018 RE annual new-build limits have thusfar not been justified

New-build limits on technologies means no more than these limits are allowed to be built in any given year

Limits have been applied to two technologies (others unlimited):

Solar PV

Wind

Limits are constant as power system grows

No justification provided for these limits

Sources: Scatec; Hopefield

110


Solar PV is limited to 1000 MW annually resulting in a move from 2.5% of peak demand in 2020 to 1.7% of peak demand by 2050

Sources: Eskom; Draft IRP 2018; CSIR analysis

0

40 000

1 000

2 000

3 000

4 000

0

20 000

60 000

80 000

2016

Max. new-build capacity, annually [MW]

Peak demand [MW]

20252020 20352030 2040 2045 2050

IRP_2018_Median

Maximum allowed new-build solar PV (annually)

0

2

6

4

8

0

20 000

40 000

60 000

80 000

2.5

2025

Peak demand [MW]

Max. new-build capacity, annually [% of peak demand]

2.7

2016 2020

2.2 2.1

2030

2.0

2035

1.8

2040

1.7

2045

1.7

2050

Absolute Relative

111


Wind is limited to 1600 MW annually resulting in a move from 4.0% of peak demand in 2020 to 2.7% of peak demand by 2050

Sources: Eskom; Draft IRP 2018; CSIR analysis

Absolute Relative

80 0004 000

0

1 000

2 000

3 000

0

20 000

40 000

60 000

20352020 20502040

Peak demand [MW]

Max. new-build capacity, annually [MW]

2016 2025 2030 2045

IRP_2018_Median

Maximum allowed new-build wind (annually)

80 000

0

4

2

60 0006

8

20 000

0

40 000

2025

4.0

2030

Peak demand [MW]

2035

Max. new-build capacity, annually [% of peak demand]

2016

4.3

2020

3.62.7

3.3 3.1 3.0

2040 2045

2.8

2050

112


4%

2%

5%

9%10%

4%

3%

2% 2%

2%

1%

4%

2%

1%

1%

4%

7%

3%3%

6%

5%

2%

1%

2%

3%

4%

1%1%

1%

4%

6%

7%

5%

2%

2%

5%

8%

3%

6%

2%

0%

2011 2012

1%

2014 2017

1%

2030 (2.1%)2050 (1.7%)

2013

2%

2%

1%

2010

3%

17%

2015

1%1%

3%

1%

3%

2%

1%

3%

1%

2%

1%

4%

9%

2007 2008 2009 2016

1%

Germany

Spain

Italy

UK

Australia

Japan

China

India

South Africa

Already happening: Both leader, follower and 2nd wave countries installing more new solar PV per year than South Africa’s IRP limits for 2030/2050

New-build solar PV capacity, annually [% of peak demand]

RSA’s IRP relativenew-build limit

decreasesover time

Leader

Follower

Follower2nd wave

Sources: SolarPowerEurope; CIGRE; websites of System Operators; IRP 2016 Draft; CSIR analysis

RSA new-build limits in 2030 and 2050

113


Already happening: Both leader and follower countries are installing more new wind capacity per year than South Africa’s IRP limits for 2030/2050

3%

2% 2%2%

2%

2%3%

4%

6%

7%

6%

8%

4%

8%

3%

6%

3% 3%

5%

5%

6%

4%

3%

7%

5% 5%5%

9%

3%

4%

3%

2%3%

4%

4%

3%

3%

2%

2% 2%

1%

2%

2%

0% 1%1%

2%2%

4%5%

3% 3%

1%

1%1%

2%

2050 (2.7%)

2030 (3.3%)

2012 2014 2015 20172006 2007 2016

2%

2008

1%

2010 2013

2%

2009 2011

1%1%

3%

1%2% 2%2%

1%

Germany

Ireland

Spain

India

China

Brazil

South Africa

RSA’s IRP relativenew-build limit

decreasesover time

Leader

RSA new-build limits in 2030 and 2050

Sources: GWEC; CIGRE; websites of System Operators; IRP 2016 Draft; CSIR analysis

Follower

New-build wind capacity, annually [% of peak demand]

114


Solar PV penetration in leading countries already up to 1.3x levels expected in Draft IRP 2018 (constrained scenarios) by 2050

54

36

23

19

4

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

2005 2010 2015 2020 2025 2030 2035 2040 2045 2050

Year

Total solar PV capacityrelative to system peak demand

31

12

22

UK

China

Japan

India

Germany

South Africa

Spain

South Africa IRP 2016 Base Case

Draft IRP 2018 (Recommended)

Italy

Draft IRP 2018 (IRP1)

Draft IRP 2018 (Others)

Australia

Sources: SolarPowerEurope; CIGRE; websites of System Operators; IRP 2016 Draft; CSIR analysis

Leader

Follower

Follower2nd wave

115


Wind penetration in leading countries is already at levels up to 1.4x Draft IRP 2018 (constrained scenarios) by 2050

70

60

67

27

20

6

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

2005 2010 2015 2020 2025 2030 2035 2040 2045 2050

Year

Total wind capacity relative to system peak load

21

Germany

Spain

Draft IRP 2018 (Others)

South Africa IRP 2016 Base Case

Ireland

China

India

Brazil

South Africa

Draft IRP 2018 (IRP1)

Draft IRP 2018 (Recommended)

Sources: GWEC; CIGRE; websites of System Operators; IRP 2016 Draft; CSIR analysis

Leader

Follower

116


Some historical perspective - installed capacity reveals the considerable coal build-out South Africa pursued previously

Biomass/-gas

Solar PV

Wind

CSP

Gas

Hydro+PS

Peaking

Nuclear

Coal

Sources: Draft IRP 2018; CSIR analysis

0

15

5

10

20

25

30

45

35

40

50

55

60

2050

41

2010

27

2020

42

9

1985

Installed capacity [GW]

1965 1975 1995 2000 2005 2015 2030

41

2035

37

2040 2045

24

2025

58

47

59

16

49

22

44

117


Initial smaller coal, followed by large 6-pack build-out, more recently Medupi & Kusile – most decommissions in Draft IRP 2018 time horizon


10

50

60

20

0

30

4036

35

2035

32

18

10

13

32


20051965 1975

7

1985 1995 2000 2010 2015 2020 2025 2030 2040 2045 2050

35 35

42

26

40

17

Grootvlei

Arnot

Lethabo

Coal IPPs

Hendrina

MajubaWet

MajubaDry

Camden

Duvha

Matimba

Matla

Kendal

Medupi

Tutuka

Komati

Sasol

Kusile

Other

Kriel

118


South Africa embarked on a significant new-build capacity programme previously… in coal – why not now in any other technologies?

Sources: Draft IRP 2018

New-build coal capacity, annually [MW]

555

187

847

1 050

575

1 178

1 793

2 433

3 048

640 610 610670 670

1 4811 411

2020

100

744

1 150 1 178

2 433

1 725

950

711

1965

1 150

555 559

1 150

746

555

1 303

1 135

1 895

670 722

931

706

20151990 19951980

100

1970

610

1975 20001985 2005 2010

1 148

119



Demand profilee


Natural gasc




Scenarios5.1




Background2

Executive Summary1


120


Even currently under-construction and committed capacity will be part of planned decommissioning and will require new-build


0

5

55

10

20

25

50

30

35

40

45

60

15

57

2035

16

20502040


2010 2015 2025 2030 2045

4442

2020

58

49

27

22

47

CSP

Nuclear

Wind

Solar PV

Hydro+PS

Gas

Peaking

Biomass/-gas

Coal

121


New-build largely driven by the planned decommissioning of the existing coal fleet - mostly post 2030


60

50

10

30

0

20

40


36

20452020

17

13

2025 2030 2035 2050

32

2010

35

2015 2040

4240

26

10

-9.9(-24%)

-24.7(-59%)

-31.7(-76%)

-14.8(-47%)

-7.0(-41%)

Sasol

Arnot

MajubaWet

Camden

Duvha

Grootvlei

Kendal

Komati

Matimba

MajubaDry

Coal IPPs

Kusile

Matla

Other

Medupi

Lethabo

Tutuka

Kriel

Hendrina

122


Should we freely optimise the decommissioning of the existing coal fleet or finish the last 2 units at Kusile?

Should we build new coal capacity in South Africa?

Should a freely optimised existing coal fleet be decommissioned any earlier/later?

Should the last 2 units at Kusile be completed in light of alternatives?

This has been studied in previous work

Steyn, G., Burton, J. & Steenkamp, M. Eskom’s financial crisis and the viability of coal-fired power in

South Africa. (2017).

Wright, J. G., Calitz, J., Bischof-Niemz, T. & Mushwana, C. The long-term viability of coal for power

generation in South Africa (Technical Report as part of "Eskom’s financial crisis and the viability of

coal-fired power in South Africa). (2017).

Summary of outcomes are presented here for reference

123


System Alternate Value (SAV) approach attempts to obtain the present value of a power station over the full time horizon

Total discounted system costs[ZAR-billion]

Total(with PS

costs incl.)

PS costs Total (with PS costs

excl.)

Total (with PS costs

excl.)

Total(with PS

costs incl.)

PS costs Value difference[ZAR-billion]

Total energy (PS)

Total energy (discounted)[TWh]

Total energy (PS)

Energy difference[TWh]

./.

Equivalent value[R/kWh]

-

-

PS included PS excluded

Hydro

Coal

DR

Peaking

Nuclear

Gas Wind

CSP

Solar PV

Biomass/-gas

Pumped storage

Li-ion

124


HendrinaKusile GrHeKoArnot Camden

0.50

0.58

Grootvlei Komati

0.50 0.49 0.48

0.570.53

Kusile Arnot GrHeKo

[R/kWh]

KomatiCamden HendrinaGrootvlei

0.61

0.50

0.36

0.47

0.41

0.48 0.47

Early decommissioning of oldest selected coal-fired power stations would result in significant savings and a cheaper power system

High demand SAV

Power station(s)

Low-demand SAV

Complete 6 units

vs. 4 units

Decom. EarlyOff from 1Apr20





Decom. all 3 early

Env. Retrofit O&M

Env. Retrofit Capex

VOM

Fuel

Water cost

FOM

SAV

Levelised costs

0.57

0.34

0.22

0.31

0.23

0.310.33

Max. allowed equivalent capex cost of remaining2 Kusile units

Will cost 0.11-0.17 R/kWh more from Grootvlei if not decommissioned early

Source: Wright (2017), Steyn (2017)

125



Demand profilee


Natural gasc




Scenarios5.1




Background2

Executive Summary1


126


Need for natural gas: Understanding domestic natural gas options

Natural gas source not critical in IRP at this stage but... whether it is domestic/imported is important

What is the energy security risk of importing all of the natural gas required in Draft IRP 2018 scenarios?

Sources: PetroSA; Eskom; Excellerate

127


The role of natural gas in the energy mix (likely via imported LNG at this stage) is relatively small to 2030 (2-5%) and up to 15% by 2050

IRP3

Energy [TWh]

313

313

12 (4%)

10 (3%)

IRP1

7 (2%)

15 (5%)

15 (5%)

IRP5

15 (5%)

IRP6

IRP7

Rec.

313

313

311

313

NG Other

Energy [TWh]

14 (4%)

28 (8%)

353

29 (8%)

37 (10%)

17 (5%)

353

355

352

352

Energy [TWh]

393

47 (12%)

40 (10%)

19 (5%)

59 (15%)

31 (8%)

392

388

391

390

2030 2040 2050

Domestic sources of flexibility and/or storage could replace some/all of these relatively small volumes of (imported) natural gas in the electricity sector

e.g. UCG, CBM, shale gas, offshore, hydrogen, DSR, biomass/-gas, CSP, storage (pumped, batteries)NG – Natural gas; Sources: Draft IRP 2018

128


Total system cost contribution of NG fuel requirements (likely via imported LNG at this stage) is 2-4% to 2030 and up to 10% by 2050

8 (2%)

Total system cost [bR/yr]

350 (97%)

362

10 (3%)

IRP1

Rec.

346 (96%)

15 (4%)

IRP5

IRP3

IRP7

351 (96%)

360

15 (4%)

347 (96%)

15 (4%)

367

IRP6

365 (98%)

364 (97%)

12 (3%)

361

373

375

NG (fuel) Other

495


442

28 (6%)

29 (6%)

IRP1

IRP3

14 (3%)

466

IRP5

37 (8%)

IRP6

17 (3%)

IRP7

Rec.

473

477


60 (10%)

47 (9%)

20 (3%)

40 (7%)

31 (5%)

529

560

564

580

591

2030 2040 2050

NG – Natural gas; Sources: Draft IRP 2018

129



Demand profilee


Natural gasc




Scenarios5.1




Background2

Executive Summary1


130


Just 5 years ago – power generation capacity was concentrated around Mpumalanga (coal) with some hydro, peaking and nuclear

Sources: Eskom; CSIR analysis

131


By 2018 – generation capacity (albeit still small) has already started to distribute across the country - not only in Mpumalanga anymore

Sources: Eskom; CSIR analysis

132


Munics.(Dx2)

IRP meets energy demand for RSA – expressed as equivalent demand (assumes EG as reduced demand)

Eskom(Tx2)

Eskom(Dx2)

Eskom1

(Gx)Imports ExportsIPPs1

(Gx)

EG = Embedded Generation; Gx = Generation; Tx = Transmission; Dx = Distribution1 Power generated less power station load; Minus pumping load (Eskom owned pumped storage); 2 Transmission/distribution networks incur losses before delivery to customers

Large customers

EG(Gx)

Customers(Dom/Com/Ind)

EG(Gx)

Customers(Dom/Com/Ind)

1 1Net sent out 1

2 Imports

3 Exports

32

Available for distribution in RSA

+ += + -1 32

Other(Gx)

Other(Gx)

1 1

133

Submitted to DoE on 25 October 2018From Jan-Dec 2016, 234 TWh of net electricity was sent out in SA with imports of almost 11 TWh means system load was 245 TWhActuals captured in wholesale market for Jan-Dec 2016 (i.e. without embedded plants)

Notes: “Net Sent Out“ = Total domestic generation (less auxillary load) minus pumping load of Eskom pumped storage stations (not shown seperately)

Sources: Eskom; Statistics South Africa

Available for distribution

in RSA

ExportsImports

Annualelectricity

in TWh

System Load (domestic and export load)

Net Sent Out

234.210.6 244.8

16.5

228.2

18.2

216.0

Other

Eskom + IPPs

134


IRP 2018 expects demand growth to be more certain, slower - average growth from 2016 of 1.2-2.0%/yr to 2030, 1.2-1.7%/yr to 2050

Sources: StatsSA; Draft IRP 2018

135


Lower demand forecast implies 3 things: Increased EE, fuel switching and... Embedded Generation – but how much?

”Due to the limited data at present and for the purpose of this IRP Update, these developments werenot modelled as standalone scenarios, but considered to be covered in the low-demand scenario. Theassumption was that the impact of these would be lower demand in relation to the median forecastdemand projection.”

[DoE, Draft IRP 2018, pp. 21 of 75]

In the Draft IRP 2018, it is clearly stated that the relative to the Median demand forecast, the Lower demand forecast is representative of a combination of:

Embedded Generation (likely mostly solar PV)

Energy efficiency (EE)

Fuel switching

Growth of embedded generation (EG) market being implicitly included can then be calculated based on:

Share of EG in the difference between Median and Lower demand forecasts

Almost all EG will likely be solar PV (with associated capacity factor)

136


Between 1.1 - 5.8 GW of embedded generation (assumed to be PV dominated) is implicitly considered in the Draft IRP 2018 by 2030

5290

313

2450 0

245

2016 (TWh)

2909

313

Median demand forecast

EE/fuel switching

EG

Lower demand forecast 31319

290

2030 (TWh)

2030 (MW)

20% is EG

60% is EG

80% is EGSources: StatsSA; Draft IRP 2018; CSIR analysis

1100-1500 MW(80-100 MW/yr)

3300 – 4400 MW(230-310 MW/yr)

4400 - 5800 MW(310-420 MW/yr)

137



Demand profilee


Natural gasc




Scenarios5.1




Background2

Executive Summary1


138


Demand profile is assumed unchanged in Draft IRP 2018 – updated aproached to demand profile will need to be pursued in future

Demand profile will change as constituent components of the demand forecast change

Not just purely an energy demand forecast and fitted peak load (assuming similar demand profile)

Updated approaches will be required linking with EG to ensure sufficiently accurate capacity expansion

139


Change in demand profile will result in very different capacity expansion options

Today Future

Weekday Weekend Weekday Weekend

EG TransComManDomAgri Min

140


System services6.2

Networks6.1





Background2

Executive Summary1


141


System services6.2

Networks6.1





Background2

Executive Summary1


142


Good to include shallow grid connection costs explicitly in Draft IRP 2018 based on extensive grid planning experience at Eskom

Draft IRP 2018 includes collector network costs in the various Eskom Customer Load Networks (CLNs) as well as shallow grid connection costs for VRE (solar PV and wind) and all other technologies

This is a welcome inclusion and is a good starting point to start to incorporate technology specific network costs previously not considered

Good objectives:

• Avoid premature congestion at Eskom Main Transmission Substations (MTSs)

• Minimising absolute number of MTSs

• Connect more smaller VRE plants in a specific area

• Allow more orderly network development

and increased utilisation i.e. more efficient integration

Network costs based on unitised costing of individual equipment

Transmission substations, Satellite stations,

Transformers, Transmission/Distribution bays,

Overhead lines, Static VAr Compensators (SVCs)

143


Deep network costs are not included in Irp but covered as part of periodic and well established TDP and SGP developed by Eskom

Deep network costs (backbone strengthening) not included in Draft IRP 2018 (or any previous IRP iteration) but instead established based on periodic TDPs and SGPs developed by Eskom Grid Planning

What is most important is how these deep network costs change on a relative basis across scenarios

Generally, these costs do not change significantly across scenarios and thus would not materially impact least-cost outcomes

In future iterations of the IRP, there should be a

continued pursuit to include geospatial components

of supply, networks and demand side options

(co-optimisation) where feasible and tractable

TDP – Transmission Development Plan; SGP – Strategic Grid Plan

144


RoCoF and frequency stabilitya

System services6.2

Networks6.1





Background2

Executive Summary1


145


RoCoF and frequency stabilitya

System services6.2

Networks6.1





Background2

Executive Summary1


146


System services and ensuring security of supply to enable any range of future energy mixes

System services and security of supply

Frequency stability/control (system inertia and RoCoF) – particular focus in these comments

Transient stability and fault level (system strength)

Voltage and reactive power control

Variable resource forecasting

All of these should inform a programme of research and effort required by all key stakeholders to ensure any future energy mix is secure

147


System operators are managing high non-synchronous penetration –Ireland SNSP limits and services to manage low inertia power systems

Sources: David Cashman (EirGrid), DS3 and beyond, 2017, IEA Working Group

SNSP [%] = System Non-Synchronous Penetration = (Wind/PV + Imports)/(Demand + Exports)

148


Averaging window is important – for frequency stability typically a 500 ms averaging window for RoCoF is considered

Sources: EirGrid, SONI

The RocoF should not exceed a particular threshold within the pre-defined averaging window e.g. 500 ms

149


The demand for system inertia is driven by two assumptions: the maximum allowable RoCoF & the largest assumed system contingency

Key assumptions:

Maximum allowed 𝑅𝑜𝐶𝑜𝐹: 0.5 Hz/s

Largest contingency (𝑃𝑐𝑜𝑛𝑡): 2 400 MW

Kinetic energy lost in contingency event 𝐸𝑘𝑖𝑛(𝑐𝑜𝑛𝑡.): 5 000 MWs

Term “inertia” is used a bit loosely to describe the amount of kinetic energy that is stored in the rotating masses of all synchronously connected power generators (and loads to be precise)

𝑓𝑛 = System frequency = 50 Hz

Sources: P. Kundur, Power System Stability and Control, 1994

Demand for inertia

𝐸𝑘𝑖𝑛.(𝑚𝑖𝑛) = 𝑃𝑐𝑜𝑛𝑡.𝑓𝑛

2(𝑅𝑜𝐶𝑜𝐹)+ 𝐸𝑘𝑖𝑛(𝑐𝑜𝑛𝑡.)

124 800 MW.s of system inertia are required at any given point in time in order for RoCoF to stay below 0.5 Hz/s in the first 500 ms after the largest system contingency occurred

150


As a starting point – we have assessed system inertia on an hourly basis via UCED in PLEXOS and some high level assumptions

Depending on what mix of power stations is operational at any given point in time, the total actual system inertia will be different

For example, if 20 GW of old coal, 10 GW of new coal and 2 GW of nuclear are online, system inertia is:

≈20 GW * 4 MWs/MVA +

10 GW * 2 MWs/MVA + 2 GW * 5 MWs/MVA

= 110 000 MWs

If wind, PV and 5 GW of CCGTs are online, system inertia is only 47 000 MW.s

Sources: P. Kundur, Power System Stability and Control, 1994

Technology Inertia constant

[MWs/MVA]

Coal (old) 4.0

Coal (new) 2.0

OCGT/ICE 6.0

CCGT/CC-GE 6.0

Biomass 2.0

Hydro/PS 3.0

Imports 0.0

Nuclear 5.0

Wind 0.0

PV 0.0

CSP 2.0

DR 0.0

Supply of inertia

151


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

152


System synchronous energy for IRP1 – confirmation that the power system really does only start to change until after 2030

153


Minimal cost of ensuring acceptable RoCoF levels even at very high non-synchronous generation penetration levels

The worst-case cost to ensure RoCoF levels are acceptable post-2030 is at most ≈1% of total system costs

2 0 1 6 2 0 2 0 2 0 2 5 2 0 2 8 2 0 3 0 2 0 4 0 2 0 5 0

M i n i m u m i n e r t i a n e e d e d [ M W . s ]1 0 4 4 8 2 1 0 4 4 8 2 1 0 4 4 8 2 1 0 4 4 8 2 1 0 4 4 8 2 1 0 4 4 8 2 1 0 4 4 8 2

M i n i m u m i n e r t i a ( a c t u a l ) [ M W . s ]1 0 4 4 8 2 1 1 6 4 8 5 1 1 6 6 0 9 1 2 2 2 6 0 1 0 4 9 9 2 5 5 8 3 2 3 1 9 0 7

A d d i t i o n a l i n e r t i a n e e d e d [ M W . s ]- - - - - 4 8 6 5 0 7 2 5 7 5

N u m b e r o f h o u r s [ h r s ]2 4 - - - - 1 7 9 9 2 2 8 2

S h a r e o f h o u r s [ % ]0 . 3 % 0 . 0 % 0 . 0 % 0 . 0 % 0 . 0 % 2 0 . 5 % 2 6 . 1 %

R o t a t i n g s t a b i l i s e r s n e e d e d [ M W ] - - - - - 1 2 2 0 1 8 1 0

A n n u a l c o s t f o r r o t a t i n g s t a b i l i s e r s [ b R / y r ] - - - - - 3 . 7 5 . 6

( % o f s y s t e m c o s t s ) [ % ] 0 . 0 % 0 . 0 % 0 . 0 % 0 . 0 % 0 . 0 % 0 . 9 % 1 . 2 %

154


Thank you

formal comments on integrated resource plan (irp) 2018

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