Eskom MYPD4

Revenue Application

Focus on

Changes in Sales, Production Plan and

Regulatory Asset Base

Nersa Public Hearings

Gauteng – Soweto

1 February 2019

Depreciation

1

The MYPD methodology through the allowable revenue formula was applied

+ + + + + =

Primary

Energy(incl imports and

DMP)

IPPsOperating

expenditure(incl R &D)

Integrated

Demand

Management

Return on

AssetsRevenue

+

Tax &

Levies

Return on assets = % cost of capital allowed X depreciated replacement asset value

𝐴𝑅= (𝑅𝐴𝐵×𝑊𝐴𝐶𝐶)+𝐸+𝑃𝐸+𝐷+𝑅&𝐷+𝐼𝐷𝑀±𝑆𝑄𝐼+𝐿&𝑇±𝑅𝐶𝐴

Eskom will provide changes to assumptions since this application was made

Eskom allowed revenue application for 3 year period is R763 billion

Allowable Revenue (R'million) AR FormulaApplication

2019/20

Application

2020/21

Application

2021/22

Regulated Asset Base (RAB) RAB 1 268 310 1 336 120 1 401 506

WACC % ROA X -1.32% -0.21% 1.45%

Returns -16 687 -2 765 20 314

Expenditure E + 56 619 59 820 62 663

Primary energy PE + 73 386 75 876 79 561

IPPs (local) PE + 29 590 34 324 41 002

International purchases PE + 3 533 3 734 3 957

Depreciation D + 64 651 72 919 75 649

IDM I + 189 193 202

Research & Development R&D + 176 187 198

Levies & Taxes L&T + 8 272 8 198 8 147

RCA RCA +

Total R'm 219 730 252 485 291 692

Corporate Social Investment (CSI) - - 192 - 193 - 151

Total Allowable Revenue 219 537 252 292 291 542

2

NERSA has requested impact of changes in conditions of Eskom’s environment since MYPD 4 application was made

3

Sales forecast

Regulatory Asset Base

Production Planning assumptions (incl

primary energy and capital expenditure

Operational expenditure

Impacted by change

in environment

During public hearings, NERSA panel requested details and impact of changes in assumptions

made in MYPD 4 application

The following changes in assumptions have occurred since the initial preparation

of submission made by Eskom approximately a year ago

Impact of changes in allowed revenue and average tariff will be demonstrated

Changes of sales forecast

Sales forecast have been reviewed with latest available information

5

Sales volume changes mainly due to discontinuance of non-paying

international customer and new contract not materialising.

Marginal changes in standard tariff sales

Sales volumes (GWh)MYPD 4 application Changes Impact of changes

2019/20 2020/21 2021/22 2019/20 2020/21 2021/22 2019/20 2020/21 2021/22

Standard tariff sales 189 584 190 218 191 699 1 344 1 860 2 346 188 240 188 358 189 353

NPA 9 777 9 750 9 750 0 0 0 9 777 9 750 9 750

Export sales 16 146 16 227 16 843 3 210 3 323 3 939 12 936 12 904 12 904

Total Sales External 215 507 216 196 218 292 4 554 5 184 6 285 210 953 211 012 212 007

Year-on-year growth

(GWh)2 770 689 2 095 1 468 -212 1 910 1 302 901 185

Year-on-year growth (%) 1.31% 0.32% 0.97% 0.6% -0.2% 0.9% 0.7% 0.5% 0.1%

Changes in Regulatory Asset Base (RAB)

Units in Extended Inoperability and Reserve Storage

7

Duvha u3 and Hendrina u3

• have experienced significant failures and are not able to return to service in the short-term.

• Have been placed in Extended Inoperability and removed from the RAB

Grootvlei, Hendrina and Komati

• Are lowest on merit order (have highest unit costs of production) and are not required to operate to

meet demand as availability improves and new capacity comes on line.

• Approaching planning end of life.

• Ten units have reached stage where significant investment (mostly Capex) is required for them to

continue operating. Have been shut down and placed in Reserve Storage.

• Remaining units (14) will reach dead stop dates, where significant investment will be required for

them to continue operating, in next 4 years. Will also be shut down and placed in Reserve Storage.

• 2 units only expected to be shut down after MYPD4 period.

Units that are expected to shut down during MYPD4 period will be removed from the RAB, based on

anticipated shutdown date.

Definition: Shutdown – Unit has been brought down to zero power, taken out of installed base, skeletal staff remains for

security, ash dam maintenance and services to local communities (water & sanitation)

2 units (Duvha u3 and Hendrina u3) in Extended Inoperability10 units in Reserve Storage

8

Power station Unit MWs FY14 FY15 FY16 FY17 FY18 FY19 FY20 FY21 FY22 FY23 FY24

Duvha 3 575 575

Hen

drin

a

1 160 160

2 190 190

3 185 185

4 190 190

5 190 190

6 190 190

7 158 158

8 190 190

9 185 185

10 185 185

Kom

ati

1 91 91

2 91 91

3 84 84

4 91 91

5 91 91

6 114 114

7 91 91

8 114 114

9 114 114

Gro

otvl

ei

1 190 190

2 190 190

3 190 190

4 190 190

5 180 180

6 180 180

Shutdown date

Changes in production plan and Generation Operations

Generation

10

Limpopo

Kwazulu-Natal

Eastern Cape

Western

Cape

Northern

Cape

North West

Free State

8

Cape Town

16

1

2

3

41

MpumalangaGauteng

12

345

67

9

10

Johannesburg

1513

11

12

9

7

8

56

2

Eskom currently operates 26 stations throughout South Africa (installed capacity on completion shown)

1 Klipheuwel Windfarm –

3MW (decommissioned)

Renewable energy

Nuclear Power Station

Koeberg – 1 940 MW

Camden – 1 510 MW

Arnot – 2 352 MW1

2

3

4

5

6

7

8

9

10

Duvha – 3 600 MW

Hendrina – 2 000 MW

Kendal – 4 116 MW

Kriel – 3 000 MW

Lethabo – 3 708 MW

Majuba – 4 110 MW

Matimba – 3 990 MW

Matla – 3 600 MW

Tutuka – 3 654 MW

Base load stations

11

12 Grootvlei – 1 200 MW

Komati – 940 MW13

1

2

4

3

Acacia - 171 MW

Port Rex -171 MW

Ankerlig - 1 338 MW

Gourikwa - 746 MW

Peak demand stations

5 Gariep - 360 MW

6 Vanderkloof - 240 MW

7 Drakensburg - 1 000 MW

8 Palmiet - 400 MW

14 Kusile - 4 788 MW

15 Medupi - 4 800 MW

New build stations

9 Ingula - 1 332 MW

2 Sere Windfarm - 100 MW

(Sustainability)

Eskom coal stations

New Build coal stations

Peaking Stations

Renewable Energy

Koeberg Nuclear

Power Station

11

Eskom operates an ageing Generation fleet, notwithstanding the new stations under construction

12

More than half of the stations and more than half of the coal-fired stations will be over 37 years

old by the beginning of the MYPD 4 period.

Eskom’s availability (EAF) better than or in line with peers until rise in UCLF from 2013

13

• The general trend, for both Eskom and the VGB benchmark units is that of reducing

availability. This is consistent with the expectation due to ageing fleet with few or no new

units being commissioned in this period.

• Improvement in 2016 and 2017 due to decrease in UCLF.

Eskom’s Unplanned Energy Loss Factor (UCLF) was better than peers up to 2010

14

• General trend, for both Eskom and VGB benchmark units is that of increasing UCLF. Is

consistent with expectation due to ageing fleet with few or no new units being

commissioned in this period.

• Many influencing factors, but root cause is consistently running at high utilisation over many

years due to late start in building new capacity.

Eskom has consistently executed less planned maintenance (PCLF) than its peers over many years

15

• Eskom executed less planned maintenance than its peers up to 2013.

• The general trend, for the top quartile, for both Eskom and the VGB benchmark units is that of

increasing PCLF. This is consistent with the expectation due to ageing fleet with few or no new

units being commissioned in this period.

• Since 2012, Eskom PCLF for top quartile units increased significantly until 2017 when planned

maintenance again decreased.

Eskom coal units have been consistently run harder than the coal units of the other VGB members over a number of years.

16

• EUF measures “how hard” units are being run – an indicator of stress on systems and

components.

• Since 2012, even Eskom’s lowest quartile stations have been running in “red zone” - at a higher

utilisation than VGB highest quartile.

• High utilisation means plant systems required to operate at limits, leading to strain, increasing

wear-and-tear and decreasing plant reliability.

Increased maintenance spend from FY2011 until FY2017 was a direct contributor to the improved performance in FY2017 and FY2018

84,682,0

77,775,1 73,7

71,1

77,3 78,0

72,2

8,0

9,110,5

9,913,0

12,1 10,4

9,6

6,1 8,0

12,6 15,2 14,9

9,9

16,6

1,3 1,0 1,1 1,8 1,1 1,0 0,7 1,5 1,7

65

70

75

80

85

90

95

100

105

15

30

0

20

5

10

25

10.2

FY

11

FY

16

9.1

FY

12

12.1

FY19

YTDFY

13

FY

18

FY

14

FY

15

FY

17

%

Capex & Maintenance Spend (Rbn real)OCLF (%)EAF (%) PCLF (%) UCLF (%)

Generation Performance over the past 10 years

Rbn

Note: FY2019 YTD is as at end Dec’18

Decreased maintenance spend, due to financial constraints, from FY2018 negatively impacted

performance from second half of FY2018.

Projection

17

18

15,29

6,49

1,56

1,61

0,931,33

2,79

0

2

4

6

8

10

12

14

16

PLLs

0.14

Total UCLFFLLs Outage Slip BTLs

5.64

0.44

Partial Load Losses (PLLs) and Full Load Losses (FLLs) contributed the most to UCLF for FY2019

to date

Outage slip and Boiler tube leaks (BTLs) together contribute about half of either FLLs or PLLs

Although the direct impact of last year’s industrial action is not classified as UCLF, the knock-on

impact is being felt here – especially in the partial load losses

If we exclude the 4 long-term forced outrages, UCLF would be 12.45%

KR 2

Other FLLs

DV 4

GV 2

LT 5

Build-up of UCLF for FY2019 YTD from major contributors

Key insights

Full and Partial Load Losses, and major incidents have been major contributors to increase in unplanned losses

18

Production Plan both requires numerous assumptions as input and is a key input into the costs of operations.

19

Current situation is different from assumptions in application therefore a changed Production Plan with updated assumptions

Changes in assumptions for updated Production

Plan include:

• Energy Forecast

• Generation plant availability

• Eskom New Build commissioning dates

• Eskom and IPP OCGTs optimization as per

system requirements

• Shut-down units at Grootvlei, Hendrina and

Komati are excluded

• Operating units from Grootvlei, Hendrina and

Komati are excluded from dead stop dates

New Build Medupi

Capacity

(MW)

Application

CO Dates

Revised CO

Dates

1st unit 720 Commercial Commercial

2nd unit 717 Commercial Commercial

3rd unit 720 Commercial Commercial

4th unit 722 31-Oct-18 30-Apr-19

5th unit 722 31-May-19 30-Apr-19

6th unit 722 31-May-19 30-Nov-19

New Build Kusile

Capacity

(MW)

Application

CO Dates

Revised CO

Dates

1st unit 720 Commercial Commercial

2nd unit 711 31-Oct-19 31-May-19

3rd unit 711 31-Aug-19 31-Dec-19

4th unit 711 31-Dec-20 31-Dec-20

5th unit 711 31-Aug-21 31-Aug-21

6th unit 711 30-Jun-22 30-Jun-22

Energy Availability

Factor2019/20 2020/21 2021/22

MYPD 4 application 78% 78% 78%

Impact of changes 71.5% 72.5% 73.5%

20

Production Plan for MYPD4 application showed that 3 stations were not required to generate electricity

21

• Based on assumptions used at the time,

the Production Plan showed that

Grootvlei, Hendrina and Komati would

not be required to meet demand for

duration of MYPD4 period.

• Due to uncertainties in assumptions,

they were required as backup or an

“insurance policy”.

• No Capex and reduced Opex for these

stations in application.

• 12 units not shut down – Duvha u3 and

11 units from Grootvlei, Hendrina and

Komati

• Additional 12 units from these 3 stations

will shut down (dead stop dates) in

MYPD4 period.

• Under current assumptions, these units

will not be able to return within 12

months so are taken out of RAB and

from Production Plan

• No Capex for these units and reduced

Opex – no change

Application Production Plan Updated Production Plan

However, these plans are based on various assumptions so should Eskom require

these units in future, they will be returned to service and changes to costs may be

reflected in future MYPDs.

Changed Production Plan shows less energy supplied by Eskom stations - mainly due to lower demand assumption

0

215,000

220,000

225,000

FY2022FY2018 FY2024FY2023FY2019 FY2020 FY2021

-3.2%

Application Eskom GWh Changed Eskom GWh

Projected energy required to be supplied by Eskom decreases significantly from

application. Lower assumed availability of Eskom stations requires higher OCGT usage

which is 10% in FY2020, dropping to about 5% and then around 1%

Note: Production does not equal demand as it also

includes losses, pumping, etc..

Updated production plan FY20 FY21 FY22 FY23 FY24

OCGT LF (%) 10.3 4.9 2.4 1.4 1.2

A 9 point recovery programme has been put in place to address our key operational challenges

Fixing coal stock piles

Prepare for increased

OCGT usage

Fixing human capital

Prepare for rain

Fixing new plant

Fixing outage duration

and slips

Fixing units on long-

term forced outages

Fixing full load losses

and trips

Partial losses and

Boiler tube leaks

1

3

4

2

5

7

8

6

9

Each of the 9 points has an dedicated lead person and is backed up by detailed action plans.

Key Issues Impacting Performance at Medupi and Kusile

Medupi

25

Unit 6 Unit 5

In COUnit 4

In CO

U3

U2

U1

South & North

Chimneys

(220m)

Water

Treatment

Plant

Station

Services

Building

Aux. Boiler

Bulk Fuel Oil

Handling

Ash Handling

Plant

Coal

Conveyors

South Aux.

CoolingFire Pump

House9595

Air Cooled

Condenser

In CO

Kusile

10 May 2016 26

Unit 1

In CO

Flue Gas

Desulphurisation

700MW Super Critical Boiler

11

0m

hig

h

130

m h

igh

Mills

GAH1

Boiler

FFP

GAH2

27

28

FY2019 Medupi Energy Availability Factor (EAF) –Dec ’18

0

20

40

60

80

100

120

Apr-18 May-18 Jun-18 Jul-18 Aug-18 Sep-18 Oct-18 Nov-18 Dec-18 2019FYTD

2019 FYTD EAF

Unit 6 EAF % Unit 5 EAF % Unit 4 EAF % Stn Contract Target URS Target

User Requirement Specification (URS) Target - 92%

Station Contract Target 2019FY- 70%

29

FY2019 Medupi Unplanned Capability Loss Factor (UCLF) - Dec 18

0

5

10

15

20

25

30

35

40

45

50

Apr-18 May-18 Jun-18 Jul-18 Aug-18 Sep-18 Oct-18 Nov-18 Dec-18 2019FYTD

2019 FYTD UCLF

Unit 6 UCLF% Unit 5 UCLF % Unit 4 UCLF % Stn Contract Target URS Target

• Station Contract Target 2019FY - 18%

• URS Target - 2%

New Build Unit Trips YTD FY2019 as of 27 Jan 2019

“Medupi unit trips for current FYTD is 66 trips, although this figure at first glance looks high it should be noted that with every “New” unit coming online this is not out of the norm, it is expected. 66 trips equate to an average of 16 trips per Unit per annum, keeping in mind that U6 had 32 in first year and 22 in second year.

30

Eskom knows exactly where challenges are and detailed plans are now in

place to reduce unit trips

UAGS Trips FY2018 vs FY2019

Station FY2018 UAGS Trips FY2019 UAGS Trips

Ingula 3 3

Kusile 0 18

Medupi 20 66

Total 23 87

Major issues include design/technical and people/process related are common to both Medupi and Kusile

31

1. Boiler/spray water system: Boiler design results in high temperatures at reheater.

Spray water system unable to cope under certain operating conditions. Results in

trips.

2. Fabric Filter Plant (FFP): Design causes excessive wear of bags and ash

accumulation. Resulting in frequent bag replacements, ash blockages, trips, load

losses and emissions related load losses. Also impacted by coal quality

3. Milling Plant: At Medupi none of the mills in commercial operation meet technical

requirements. Require servicing every 8000 to 12000hrs which is half of design period.

Similar situation at Kusile. Results in additional PCLF requirements. Also impacted by

coal quality.

4. Gas Air Heater Performance and Fouling: does not meet requirements i.t.o

temperature gradient, erosion, failures, ash carryover to clean air side

5. Dust handling plant: High ash accumulation, leaks, poor commissioning and lack of

spares due to OEM business constraints. Plant requires more frequent maintenance.

Also impacted by coal quality variation.

6. Distributed Control System (DCS)-M4 to M6: Hardware failure causes plant trips and

performance does not meet technical requirements. Corrective maintenance

programmes ineffective.

7. High vibrations on generator auxiliary cooling loop: Result of undamped connections

to turbine

8. People/Spares availability/Maintenance: Plants still under construction creating

logistics and planning complexities; Ongoing training.

Medupi and Kusile Major Defects – How to fix?

32

• 9 point recovery plan has devoted one item to `Fix New Plant. Technical Eskom specialistteams have been assembled to develop solutions to rectify major defects;

• Workstreams established with contractors (e.g. MHPS) to jointly evaluate solutions;

• Major defects receiving urgent attention include:

• Progress on technical solutions being developed are tracked on a weekly basis;

• Continuing with project technical support holding Contractors accountable as per contracts:

• Defects Notification Period (up to 18 months after CO): Root Cause Analysis is done by

Contractor and rectification of defects

• Latent Defects Notification Period (>18 month after CO): Root Cause Analysis for

Eskom. Contractor/Eskom to rectify based on Root Cause Analysis outcome.

• Low Performance Damages for commercial units (e.g. for Reheater Spray Flow)

• Withholding % of Interim Payment certificates (GAH and PJFF

1. Reheater (RH) Spray Flow / Furnace Exit Gas

(FEGT) Temperature

2. Pulse Jet Fabric Filter (PJFF)

3. Mill Plant Issues 4. Dust handling plant

5. Gas Air Heater (GAH)/Performance/Fouling 6. High vibrations on generator auxiliary cooling loop

7. Medupi: Repeated Distributed Control System Card Failures (Unit 6 – 4 and Balance of Plant)

Progress to date

Open1

1. Reheater (RH) Spray Flow

/Furnace Exit Gas (FEGT)

Temperature

2. Pulse Jet Fabric Filter (PJFF)

3. Mill Plant Issues

4. Dust handling plant

5. Gas Air Heater (GAH)

Performance/Fouling

6. High vibrations on generator

auxiliary cooling loop

7. Medupi: Repeated Distributed

Control System Card Failures

(Unit 6 – 4 and Balance of Plant)

1. Boiler Erosion (Screens)

2. Burner – modifications being

monitoring.

3. Gas Air Heater (GAH) Pin Rack

Crack (mod monitoring)

4. HP Fuel Oil Pump Failures –

closed based on modification of

pump

5. HP Piping Supports

6. PA Fan vibration (mod

monitoring)

7. Ingula Main Inlet Valve

Maintenance Seals

8. Internal Suspension Rods

Closed2

33

Outages Executed and Post Outage Performance

Of the 231 outages in the base plan (1 April 2016 –31 March 2019), 138 are either completed or in execution and 121 have been added

35

Outages were deferred or cancelled either due to units being shut down, or due to a change in

Eskom’s maintenance philosophy, from a time-based to a condition or risk-based maintenance regime.

Of the original 50 outages deemed to be in backlog, 45 outages have been completed, two are in

execution, while three have been cancelled as the units have been shut down.

231

46

121

124

47

63

76

82

Base Plan CancelledDeferred

14

ExecutingCompleted Additional FY20 FY21 FY22

Post Outage unplanned losses is small contributor to total unplanned losses

•

Post-outage UCLF performance was 0.60% of total UCLF (16.59%)

36

Conclusion

• Root cause of Generation’s current performance is “running in red zone” for many years due mainly to late decision on new capacity build

• 9 Point Recovery Programme to address 9 key issues (some related to capacity and financial constraints) – Focuses on plant issues and people and process issues

• Production Plan updated from Application to take latest data on assumptions into account

• Units at Grootvlei, Hendrina and Komati removed

• Will require more Capex for Generation

• Opex already accounted for in Application will be reallocated

• New build design issues known and being addressed

37

Impact of changes on Eskom allowed revenue

Impact of changes on allowed revenue

Allowable Revenue

(R'millions)ƒx

MYPD 4 application Changes Impact of changes

2019/20 2020/21 2021/22 2019/20 2020/21 2021/22 2019/20 2020/21 2021/22

Regulated Asset Base 1 268 310 1 336 120 1 401 506 - 15 310 - 12 984 - 10 764 1 253 000 1 323 136 1 390 742

WACC % x -1.32% -0.21% 1.45% -0.05% 0.11% 0.21% -1.36% -0.10% 1.66%

Returns + -16 687 -2 765 20 314 -394 1471 2741 -17 081 -1 294 23 055

Expenditure + 56 619 59 820 62 663 56 619 59 820 62 663

Primary energy + 73 386 75 876 79 561 1 758 1 175 267 75 144 77 051 79 828

IPPs (local) + 29 590 34 324 41 002 1 245 578 132 30 836 34 902 41 134

International purchases + 3 533 3 734 3 957 336 351 372 3 869 4 084 4 329

Depreciation + 64 651 72 919 75 649 - 2 710 - 3 322 - 3 222 61 942 69 597 72 427

IDM + 189 193 202 189 193 202

Research &

Development+ 176 187 198 176 187 198

Levies & Taxes + 8 272 8 198 8 147 - 236 - 253 - 290 8 036 7 945 7 857

RCA +

Subtotal 219 730 252 485 291 692 0 0 0 219 730 252 485 291 692

Corporate Social

Investment (CSI)- - 192 - 193 - 151 0 0 0 - 192 - 193 - 151

Total Allowable

Revenue219 537 252 292 291 542 0 0 0 219 537 252 292 291 542

Average standard tariff

price increase15.0% 15.0% 15.0% 2.1% 0.4% 0.5% 17.1% 15.4% 15.5%

39

Impact of changes on Eskom’s ability to cover debt service commitments

Allowable Revenue

(R'millions)

MYPD 4 application Changes Impact of changes

2019/20 2020/21 2021/22 2019/20 2020/21 2021/22 2019/20 2020/21 2021/22

Total Allowable Revenue219 537 252 292 291 542 0 0 0 219 537 252 292 291 542

Average standard tariff

price increase15.0% 15.0% 15.0% 2.1% 0.4% 0.5% 17.1% 15.4% 15.5%

40

Gap in debt service cover vs RoA + Depreciation 2019/20 2020/21 2021/22 Total MYPD4

Application: Variance in debt service cover -25 209 -24 912 491 -49 631

Increase/(Decrease) in RoA+Depreciation -3 104 -1 851 -481 -5 436

Impact of change : Variance in debt service cover -28 313 -26 763 10 -55 067

If the price increase is 15%x 3, the gap in debt service cover increases from

R50bn to R71bn over 3 years

Impact of changes on production plan, EAF and tech plan outage capex

41

Production Plan

GWh

MYPD 4 application Changes Impact of changes

2019/20 2020/21 2021/22 2019/20 2020/21 2021/22 2019/20 2020/21 2021/22

Coal 203 757 202 387 201 508 -6 995 -6 861 -5 825 196 762 195 527 195 684

Nuclear 14 902 14 155 13 655 -1 189 -636 -2 234 13 712 13 518 11 422

OCGT 211 211 211 1 963 823 291 2 174 1 034 502

Hydro 693 689 690 0 0 0 693 689 690

Pumped storage 5 069 5 164 5 091 -99 237 71 4 971 5 402 5 162

Sere 344 344 344 -30 -32 -32 314 312 312

Total Eskom Production 224 977 222 951 221 500 -6 350 -6 469 -7 729 218 626 216 482 213 771

IPPs 12 099 15 035 18 665 297 189 53 12 395 15 224 18 719

International trader 9 491 9 463 9 462 1 083 1 083 1 084 10 573 10 545 10 545

Gross Production 246 566 247 449 249 627 -4 971 -5 198 -6 592 241 595 242 251 243 035

Less-pumping -6 838 -6 965 -6 872 343 -106 114 -6 495 -7 071 -6 757

Nett Production 239 728 240 484 242 755 -4 628 -5 303 -6 478 235 100 235 180 236 278

Energy Availability Factor 78% 78% 78% -6.5% -5.4% -4.5% 71.5% 72.5% 73.5%

Tech plan, Outage CAPEX

R’ millions

MYPD 4 application Changes Application with changes

2019/20 2020/21 2021/22 2019/20 2020/21 2021/22 2019/20 2020/21 2021/22

Total 12 187 12 809 12 384 3 194 5 291 4 244 15 381 18 100 16 628

Impact of changes on primary energy

42

Total Primary Energy

R'million

MYPD 4 application Changes Impact of changes

2019/20 2020/21 2021/22 2019/20 2020/21 2021/22 2019/20 2020/21 2021/22

Coal burn 63 670 65 884 68 956 -4 338 -1 416 -378 59 332 64 468 68 578

Water costs 2 641 3 036 3 279 23 -147 -144 2 732 2 962 3 213

Fuel procurement costs 155 146 153 0 0 0 155 146 153

Coal handling 2 181 2 067 2 130 0 0 0 2 181 2 067 2 130

Water treatment 507 513 544 0 0 0 507 513 544

Start-up gas and oil 1 893 1 815 1 862 0 0 0 1 893 1 815 1 862

Limestone 138 210 319 -27 -13 -27 109 195 287

Black start facility(gas fired) 9 10 11 0 0 0 9 10 11

Total Coal 71 195 73 682 77 253 -4 343 -1 576 -548 66 919 72 176 76 778

Nuclear fuel burn 972 887 908 -61 -2 -158 911 885 750

OCGT fuel burn 880 948 1 019 6 095 2 683 901 6 975 3 631 1 919

Environmental levy 8 272 8 198 8 147 -236 -253 -290 8 036 7 945 7 857

Total Eskom Primary

Energy81 319 83 714 87 327 1 456 852 -96 82 841 84 637 87 304

Independent Power

Producers(IPPs)29 590 34 324 41 002 1 245 578 132 30 836 34 902 41 134

International Purchases

(Imports)3 533 3 734 3 957 336 351 372 3 869 4 084 4 329

Demand Response 339 359 381 0 0 0 339 359 381

Total Non-Eskom Primary

Energy33 462 38 417 45 340 1 582 928 504 35 044 39 345 45 844

Total Primary Energy 114 781 122 131 132 667 3 037 1 780 408 117 885 123 982 133 148

43