Multi-Year Price Determination 4

Revenue application

NERSA Public Hearings

Midrand Day 1

4 February 2019

Robust sales forecasting

process requires regular

updates

• Eskom is satisfied with the robustness of its sales forecasting process.

• However, due to the lag between the completion of the forecast and the timing of the submission it is important that the forecast is revised closer to the decision date.

• NERSA MYPD methodology, applicable from 2019 year allows for review of sales forecast closer to decision date – this contributes to addressing the challenge.

• Eskom provided the revised sales forecast during the Rustenburg public hearings and it will be confirmed during the Gauteng public hearings.

• NERSA is afforded to undertake its own verification process before their final decision.

• The decision then forms the reference point of the RCA process.

• In addition, consideration by NERSA to review the ERTSA methodology that will allow NERSA to make sales volume adjustments on an annual basis based on latest available projections – will avoid increasing divergence.

Eskom maintains its sales forecasting process is sufficiently robust

2

NERSA methodologies should allow for adjustments on a regular basis

Actual Standard tariff sales trend compared to average tariff adjustment from 2007

• In 2008, 3,9% decrease YOY sales volumes was linked

to load shedding, ECS, crash in global economy etc.

• Recovery in 2009 attributed to growth in construction

industries with building of stadiums for World cup,etc

• Marikana, in 2012 impacting the Platinum sector

compounded by closure of ArcelorMittal in van der Bijl,

reduction at Samancor and closure of Silicon

Technologies in Newcastle.

• Subsequent periods reflect a general decline in

construction industry, especially steel &cement industry.

Key PointsAverage Tariff adjustments

Difficult to conclude on any correlation indicating other influencing factors

GWh sales

3

Specific reasons for drop in sales in Industrial sector provided by Eskom customers

• Low economic growth due to Global factors , e.g. Recession, Exchange rates, , Trade

barriers, etc.

• Decline in Commodities / Metal demand

• Implementing energy efficient technologies

• Mechanisation

• Labour/Industrial relations

• Changes in the structure of SA economy,

from Energy intensive Sectors ( Mining & Manufacturing) to the Services sector

• Government policy/legislation uncertainty

• Electricity supply reliability & availability

• Transport/logistics challenges

• Recycling of scrap

• Crime & Illegal Mining

The price of electricity alone is unlikely to reverse the deterioration

in the economy; it would require a holistic approach

4

Price and Income Elasticity

of Demand implications

National Treasury indicates impact of 15% increases

GDP is expected to deviate by an average

of 0.1 percentage point from the baseline

growth forecast.

Energy intensive sectors like mining are

anticipated to experience the most adverse

effects.

The gold and uranium sub-sector is

projected to be particularly sensitive given

the structural vulnerabilities that already

exist in the sector.

The electricity sector will be directly

affected by weaker demand of electricity.

Weaker demand for electricity is projected

across all household income groups.

The price elasticity of electricity demand is

estimated to be less than -0.5

NB: These results are based on a 15%

annual tariff increase over the MYPD 4

period.

Key Points

National Treasury study estimates price elasticity of demand to be less than

-0.5 with 15% increases

6

Extract from 2009 price elasticity study by external

consulting economists: matrix of possibilities, showing

estimated responses to potential changes……

7

• This matrix table explores the possible changes in

electricity consumption given different changes in

output and price, and is based upon the elasticity

estimates for the period 2003m1 – 2009m4.

• The changes in output and price are real (after

normal inflation/PPI has been removed). The darker

sections show where there is an increase in

consumption, the lighter sections show decreases.

This analysis assumes a linear demand curve

without threshold levels

• The table must be interpreted as the medium-

term change in price and output (6-7 years)

• I.e. for manufacturing a 75% real increase in price

coupled with a 20% increase in output is estimated

to result in a 3.7% decrease in electricity

consumption. However for only a 30% real increase

in price and a 20% increase in output results in

increase in consumption of nearly 10%

• For metals the contraction is to be less responsive

to price – but a similar scenario could see a

reduction around 8%.

• CAVEAT: The real increase in price is after inflation

– one must remember that electricity price hikes

have an impact on inflation

• The impact of a price increase must always be read

in conjunction with the impact of an increase in

gross value added.

Key PointsManufacturing Matrix

Metals Matrix

Metals Matrix Price Elasticity: -0.31

Income Elasticity: 0.78

-15% -10% -5% 0% 2% 5% 10% 15% 20% 25% 30%

0% -11.7 -7.8 -3.9 0.0 1.6 3.9 7.8 11.7 15.6 19.5 23.4

5% -13.3 -9.4 -5.5 -1.6 0.0 2.4 6.3 10.2 14.1 18.0 21.9

10% -14.8 -10.9 -7.0 -3.1 -1.5 0.8 4.7 8.6 12.5 16.4 20.3

15% -16.4 -12.5 -8.6 -4.7 -3.1 -0.8 3.2 7.1 11.0 14.9 18.8

20% -17.9 -14.0 -10.1 -6.2 -4.6 -2.3 1.6 5.5 9.4 13.3 17.2

25% -19.5 -15.6 -11.7 -7.8 -6.2 -3.9 0.1 4.0 7.9 11.8 15.7

30% -21.0 -17.1 -13.2 -9.3 -7.7 -5.4 -1.5 2.4 6.3 10.2 14.1

50% -27.2 -23.3 -19.4 -15.5 -13.9 -11.6 -7.7 -3.8 0.1 4.0 7.9

75% -35.0 -31.1 -27.2 -23.3 -21.7 -19.4 -15.5 -11.6 -7.7 -3.8 0.1

100% -42.7 -38.8 -34.9 -31.0 -29.4 -27.1 -23.2 -19.3 -15.4 -11.5 -7.6Ch

an

ge i

n R

eal

Pri

ce l

evels

Change in Real Output levels

Manufacturing Matrix Price Elasticity: -0.30

Income Elasticity: 0.94

-15% -10% -5% 0% 2% 5% 10% 15% 20% 25% 30%

0% -14.1 -9.4 -4.7 0.0 1.9 4.7 9.4 14.1 18.8 23.5 28.2

5% -15.6 -10.9 -6.2 -1.5 0.4 3.2 7.9 12.6 17.3 22.0 26.7

10% -17.1 -12.4 -7.7 -3.0 -1.1 1.7 6.4 11.1 15.8 20.5 25.2

15% -18.6 -13.9 -9.2 -4.5 -2.6 0.2 4.9 9.6 14.3 19.0 23.7

20% -20.1 -15.4 -10.7 -6.0 -4.1 -1.3 3.4 8.1 12.8 17.5 22.2

25% -21.6 -16.9 -12.2 -7.5 -5.6 -2.8 1.9 6.6 11.3 16.0 20.7

30% -23.1 -18.4 -13.7 -9.0 -7.1 -4.3 0.4 5.1 9.8 14.5 19.2

50% -29.1 -24.4 -19.7 -15.0 -13.1 -10.3 -5.6 -0.9 3.8 8.5 13.2

75% -36.6 -31.9 -27.2 -22.5 -20.6 -17.8 -13.1 -8.4 -3.7 1.0 5.7

100% -44.1 -39.4 -34.7 -30.0 -28.1 -25.3 -20.6 -15.9 -11.2 -6.5 -1.8

Change in Real Output levels

Ch

an

ge i

n R

eal

Pri

ce l

evels

NERSA analysis in 2018 indicated growth of 1.8% increase in electricity sales with a 5.23% nominal increase in price

Projected increase in electricity sales as per NERSA decision did not

materialise as anticipated.

8

9

Cost of Alternative Energy

Solar PV cost are projected to

decrease by approximately 8% per

annum up to 2020 – thereafter could

slowdown – cost plateau.

Future tariffs will change the value

proposition of PV systems.

The structure of the tariff (to reflect

capacity costs) plays a significant role

in the attractiveness of solar PVs:

Cost reflective tariff structure will

reduce the commercial viability of

solar PVs.

Limitations to solar PVs as a large

scale alternative:

Low load factor.

Not available on demand.

Battery backup ~ not yet

commercially and technically viable –

for large scale deployment.

Key Points

Research indication of Small Scale Embedded Generation (SSEG) Photovoltaic penetration in SA for energy component of electricity

• Electricity is a multitude of value products per kWh – these are Peak capacity, dispatched ramping, Energy,

Sync Power, System strength, frequency, voltage

• End 2017 PV penetration ~285MW + 100MW growth ~385MW Solar PV penetration for 2018

• <1% of system installed generation capacity;

• Most likely future scenario 100MW p.a. additional SSEG solar PV

• Most likely expected Solar PV penetration by 2021: 700MW-800MW

SSEG PV projected to grow conservatively

10

Key Points on relatively inelastic price elasticity of demand

Various studies of price elasticity of electricity demand have estimated electricity demand to be relatively inelastic – However:

– Demand response has increased following significant real price increases in the last decade (in excess of 250% in nominal terms),

– Above inflation price increases during the MYPD 4 period will put pressure on electricity intensive sectors which could result in a reduction in electricity consumption in the long term,

– The proliferation of Distributed Generation (DG) (e.g. end-user solar panels) could result in an erosion of sales volumes,

A 13% (19%) annual tariff increase could result in a 0.1 (0.3) percentage point deviation in GDP growth as compared to the base case scenario.

Higher tariffs are bound to dampen demand. However a reluctance to raise prices towards cost reflectiveness will deny the utility the ability to fund investments and maintenance required to sustain an adequate security of supply.

An inadequate security of supply has more negative repercussions to economic growth and social welfare than a tariff increase.

A long term tariff path is required to facilitate long term investment decisions. This will assist both investors and consumers to adapt as the sector goes through a structural change.

11

Eskom supports protection of vulnerable sectors

Eskom has heard various stakeholders at the public hearings indicate that 15% price

increases will impact their businesses and households

− Eskom understands potential impacts of increases in certain vulnerable sectors

− Many industrial and other consumers require reliable electricity supply

− Low consumption residential users require protection

Average price increase Eskom has motivated should not be confused with protecting

vulnerable sectors.

Eskom has actively encouraged exploring policy options with government to protect

identified vulnerable sectors.

It is recognised that further interventions are urgently needed

This requires the co-ordination of various parties – led by Government

− NERSA has already approved two short-term incentives that addressed distressed industries successfully.

− This should be tight up with the country’s industrial policy and economic development strategy.

However, average price of electricity cannot continue to be below prudent

and efficient cost

12

Efficient Generation

revenue to be evaluated in

context of circumstances

Production Plan requires many assumptions as inputs and determines how much energy is expected to be produced by each station

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%

14

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

• 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 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 could be returned to service and changes

to costs may be reflected in future MYPDs.15

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

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

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

16

The avoided cost of not running Grootvlei, Hendrina and Komati is more than double the estimated cost of OCGT fuel

Based on the current outlook, utilising OCGTs is

more cost effective

17

Reviving STPPP and MTPPP requires business case and time for various approvals

• A business case would need to be undertaken to determine viability

• If determined to be viable, then process can be initiated

• Procurement processes would be in accordance with National

Treasury and Eskom processes

• Eskom governance, PFMA and NERSA approvals are needed

• NERSA may require to undertake a public consultation process in

accordance with its processes

• Commitment from NERSA of cost recovery is essential

• Estimated timeframe is between 6 to 10 months

18

Eskom did not consider this option when Production Planning changes were

made due mainly to the extended timeframe required. It could be considered

for 2021 onwards

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

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

ExecutingBase Plan Completed

14

FY20Deferred Cancelled Additional FY21 FY22

19

Post Outage unplanned losses is small contributor to total unplanned losses

•

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

20

Eskom coal stations below benchmark costs for non-fuel O&M

• Applicable to non-fuel O&M costs,

• Including capitalised maintenance costs

• “Real @ Applicable R/$” uses ave. exchange rate

applicable to each year

FY

FY

Benchmarks considered:

− EPRI: $60.60/kW per year

− IEA: $66.34/kW per year

− Sub-Saharan Electricity Sector

report: $63.94/kW per year

The median value was used as the

comparison to Eskom Generation

− Note benchmark reflects costs that

are ‘levelised’ over life cycle i.e.

which smooth benchmark,

whereas comparison is to Eskom

power station annual costs, bulk

of which are in mid-life cycle which

implies higher costs for mid-life

refurbishment etc.

21

Generation staffing: aligned to average for USA coal-fired electricity generation industry

• Preliminary research indicates that average ratio for all US coal stations is 3.38MW per employee vs Eskom’s coal stations of 3.46MW per employee

• For Eskom Generation the 2016 World Bank report implied a ratio of 9.53MW per employee. This is significantly higher than their average for Africa of 2.3MW (of various technologies) per employee and 2.44MW per employee for coal (e.g. in the case of Botswana).

• At a ratio for Eskom coal plant of 3.46MW per employee (similar to the US actual data and 42% better than the WB’s ratio for Botswana coal stations), plus peaking and nuclear plant staffing, it translates to 13575 employees for Eskom Generation (as opposed to 4 648 per World Bank report).

• The assumptions used in the 2016 World Bank report seem flawed. If 9.53MW per employee was plausible to the USA it would imply that the US coal fired electricity industry’s current staffing is 2.8 times what it should be

22

Addressing fraud and

corruption

Eskom’s Board is committed to rooting our fraud

and corruption

14 implicated senior executives exited. Finalisation of outstanding disciplinary hearings

relating to senior executives being accelerated

12 criminal cases opened, five of which involve nine senior executives

Total of 1 049 outstanding cases since April 2018, of which 934 have been finalised,

resulting in 115 under consideration

As at 31 December 2018, a total 295 whistle blow cases are under investigation, 140 cases

have been completed.

Lifestyle audits of senior management in progress. There is effective declaration of

interest

Investigated all irregular supplier contracts (so far, five are no longer doing business with Eskom). Recovered R902 million from McKinsey with an additional R99 million recovered relating to interest

Cooperating with eight regulatory bodies conducting major investigations

These are: National Treasury procurement investigations, Zondo Commission, Hawks, SIU, Parliamentary

Inquiry, National Director of Public Prosecutions, Standing Committee on Public Accounts and SAPS

Eskom will provide NERSA with details as soon as developments occur

24

Eskom will provide further details to NERSA as developments occur

Eskom’s actual and

projected electricity price

from 2010 to 2024 compared

to external references

NERSA’s estimate of Future Price Path (FPP)Reasons for Decision June 2009

Indication of the Future Price Path

Figure 1: 5 Year Expected Price Cone

Source: NERSA Modelling of Price Path 26

MYPD 2, 3, 4 revenue applications vs. NERSA’s FPP (constant 2009 Rands)

All three MYPD revenue applications plateaued (once they reached prices reflective of prudent and

efficient costs) around midway between FPP’s upper / lower cost-reflectivity boundaries:

MYPD2,3,4 revenue applications’ final years within FPP cost-reflective boundaries27

‘Benchmarking’ of NERSA’s FPP(constant 2018/19 Rands)

‘Lower boundary’ of US$ 8.5c/kWh is very low by any international benchmark. EIUG / BUSA’s

proposals to NERSA for MYPD3’s 5th year 2017/18 reached same level (although not yet cost-

reflective). IRP, World Bank report aligned to mid / upper boundary:

135c/kWh or

US$10c/kWh*

114c/kWh or

US$8.5c/kWh*

* @ R13.50:$1

EIUG proposed

104 -118c for MYPD3

BUSA 108c

IRP2018

Current ave. price

is 89.4c/kWh

(US$ 6.6c/kWh**)

World Bank

report

FPP’s upper / lower boundaries confirmed by numerous recent benchmarks28

Draft IRP and REIPPPP BW4 confirm NERSA’s FPP

FPP vs. MYPDs, BW4, IRP, BUSA / EIUG’s proposals and World Bank: all provide outcomes within

NERSA FPP upper/lower boundary regarding price required for financial sustainability:

Note : all three graphs have been

calibrated to the same tariff scale

Although there would be some

vulnerable industries, if it was true that

no industry can tolerate prices higher

than Eskom’s current ave.price of

89.4c/kWh (US$ 6.4c/kWh) it makes the

IRP totally academic

IRP ‘least cost’ scenario ~fits within FPP boundaries, other scenarios higher29

• The World Bank undertook an analysis of electricity utilities in 39 countries in Sub-Saharan Africa, which included an assessment of their opex and capex.

• The analysis concluded

that Eskom’s unit costsare very low relative to other SSA utilities (3rd

lowest).

• Similarly, Eskom’s average price is very low relative to other SSA utilities – but they are all pricing their electricity at unsustainably low levels thus are in (or heading to) significant financial difficulties.

“median tariff in SSA was

US$ 0.15 / kWh, median cost US$

0.21 / kWh” (World Bank)

World Bank’s 2016 report says Eskom’s price should

be US$ 10c/kWh ‘at benchmark performance’

World Bank’s analysis shows that

Eskom’s price should be US$ 10c/kWh

‘at benchmark performance’

``

US$ c/kWh

700 10 20 30 40 50 60

WB says Eskom’s current low price of 6.5c/kWh is >80% due to underpricing30

Balance sheet impact due to price gap

Balance Sheet impact: actual prices vs. NERSA FPP lower boundary:

Revenue gap for 2018/19

= R39bn after tax

31

Balance sheet impact due to price gap

Balance Sheet impact: actual prices vs. NERSA FPP lower boundary to midway:

Total revenue shortfall = R339bn (incl. interest at 9% p.a. and deduction of Company Tax)

R339bn

= 68% of Eskom’s liabilities at

31 Mar 2018. Debt ratio could have

been 25% (or ~35% if dividends of

R10bn p.a. had been paid). SAIG** ct.

rating requires <55%. This is the main

cause of the high debt ….

…. in effect an electricity

price subsidy which has

been funded through

Eskom’s balance sheet

** SAIG = Stand

Alone Investment

Grade

32

Balance sheet impact due to price gap

Balance Sheet impact : MYPD4 application vs. NERSA FPP mid-boundary:

Total revenue shortfall = R107bn (incl. interest at 9% p.a. and deduction of Company Tax)

R107bn

Hence Eskom’s

debt will continue

to increase over

period to 2024,

before stabilizing

33

By end of MYPD4 the cumulative effect of pricing below FPP is ~R450bn

Cost-efficiency remains crucial but be viewed in overall context

Illustrated below is price effect of (beyond plausible) R15bn p.a. reduction in O&M and PE :

Reduces required

price from mid-point

between upper/lower

boundary, to closer

(but still above) lower

boundary …

Would reduce required price by ~8c/kWh (Rands of 2018), from ~124c to 116c/kWh

… thus potential

future efficiency

gains cannot be an

argument against

increasing price to

lower boundary

At benchmark performance the price required to cover efficient costs >114c/kWh34

Main cause of the required price increase is the phasing-out of the current price subsidy

Main cause of price increase

is not increasing cost but

because the current price

subsidy is being phased out

…. which does not preclude subsidization of specific targeted customer categories, through direct,

targeted and transparent subsidies, in a way that leaves Eskom revenue-neutral

… which does not

preclude

subsidization of

specific customer

categories in future

Eskom cannot any longer fund the price subsidy / underpricing with debt35

NERSA’s FPP vs. MYPD4 – conclusions (1 of 2)

1. Electricity is a highly capital/asset intensive, high fixed and sunk cost business (=75%

of cost) i.e. main cost driver is assets being operated

2. Eskom of 2018 is essentially the same as Eskom of 2009, just larger – same power

stations plus 6GW more, with construction programme underway for further 6GW;

same network plus 36000km more lines; same customer base plus 1.9 million more.

No reason that the FPP estimated in 2009 would be any lower in 2018

3. For lower boundary of FPP NERSA stipulated a number of conditions to be fulfilled – of

which virtually none has happened. In addition NERSA did not price-in the cost

increases due to REIPPPP BW1-3

4. However Eskom’s required price by 2024 is still around mid-way between upper

and lower boundaries of NERSA’s FPP (and very competitive with the lowest-cost

IRP scenario)

5. Further efficiency gains in future might at most reduce the level to which the price is

required to migrate by ~6%

36

NERSA’s FPP vs. MYPD4 – conclusions (2 of 2)

6. Whilst Eskom has not been perfect regarding fuel cost, operational cost, capital

expenditure or technical performance, objective analysis indicates that debt situation is

mainly (>80%) a function of having had to take responsibility for the build programme,

without the electricity price responding as was required. Even with a price path at the

lower boundary of NERSA’s FPP Eskom’s debt ratio would have been ~35% today

7. Phasing-out of overall price subsidy does not preclude subsidization of specific targeted

customer categories, through direct, targeted and transparent subsidies – i.e. fair revenue

for Eskom does not dictate the price to poor people in South Africa, or to certain

vulnerable industries.

These two propositions can thus be true at the same time:

(a) Eskom needs to receive enough revenues to be sustainable, thus able to meet all

debt commitments and cover all prudent and efficient costs;

(b) poor people and vulnerable industries could be protected (this could include

government-funded production or consumption subsidies – which is of course a

matter of government policy)

8. However the model of Eskom accumulating the underpricing effect on its balance

sheet as debt is unsustainable and has reached its limit. It is crucial for the sake of

Eskom, the ESI and South Africa that this be rectified urgently – it cannot be

delayed beyond MYPD4

37

Eskom’s Revenue

Requirement for MYPD 4

Compounded annual growth rate (CAGR) for Primary energy from MYPD3 to MYPD4 – MYPD 4 Application

FY14

Act

FY15

Act

122,131

FY16

Act

FY17

Act

FY19

Proj

FY18

Act

FY21

App

FY22

App

83,426

69,811

85,069 84,723 87,185

102,541

114,781

132,667

FY20

App

37.20%

8.47%

6.26%

8.36%

Coal IPPs Other PE

CAGR

Co

al

IPP

sO

ther P

E

39

CAGR for Primary Energy from MYPD 3 to MYPD 4 – with changes made to production plan to reflect recent reality

56%

12%

5% 18%

10%

5%

9%

5%6%

15%

102,539

0%

FY2013/14

Actual

FY2017/18

Actual

3%10%

58%

24%

0%

11%

2%3%

4% 1%11%

59%

0%0%4%

FY2014/15

Actual

54%

10%

1%

83,426

0%

FY2015/16

Actual

3%

57%

26%

69,812

3%

2%

3%

FY2018/19

Projection

1%1%1%0%0%

55%

26%

7%

0%

2%

3%

FY2016/17

Actual

6% 0%

3%

57%

28%2%

3%

1% 1%

0% 3%

3% 0%

FY2020/21

Application

56%

31%

6%

87,184

59%

2%

3%

26%1%

8% 1%1%

FY2021/22

Application

10%

85,068 84,723

117,885123,982

133,148

FY2019/20

Application

8.41%

International purchasesCoal

IPPs Other PE

Environmental levy

Nuclear

OCGT

DMP

40

Primary energy CAGR increase is from 8.36 to 8.41

CAGR for employee benefits, maintenance and other expenses (excl other income & arrear debt)

24.9%

48.2%

25.0%

27.6%

FY18

Act

48.1%

FY14

Act

48.2%

26.1%

50,759

FY16

Act

27.6%

46.6%

29.9%

23.5%

FY17

Act

47,189

24.3%

49.0%

29.7%

FY19

Proj

47.8%

29.1%

FY20

App

23.1%

27.0%

47.0%

28.8%

24.2%

FY21

App

61,449

47.1%

22.7%

25.7%

30.2%

55,99455,354

47.4%

21.2%

FY22

App

51,276

FY15

Act

46,114

59,925 58,919

3.26%

2.14%

4.53%

+3.36%

Employee Benefits Maintenance Other (incl GTD, Cx, R&D, CSI & IDM)

Em

plo

yee

be

ne

fitsM

ain

ten

an

ce

Oth

er

41

CAGR for each component of Generation operating expenditure is below inflation

29.8%

FY20

App

FY15

Act

27.2%

29.7%

43.1%

FY16

Act

27.3%

25.8%

46.9%

33.6%

FY17

Act

31,305

32.9%

FY21

App

33.6%

FY18

Act

34.1%

FY19

Proj

30,737

34.8%

31.0%

26.0%

32.5%

36.5%

30.1%

31.5%

38.4%

30.3%

FY22

App

43.1%

27.3%

35.8%

30.9%

31.1%

FY14

Act

43.0%

25,737

35,688

33.9%

25,682

29,54328,585

33,34534,582

5.78%

5.01%

1.41%

Other (incl GTD, Cx, R&D, CSI & IDM)Employee Benefits Maintenance

CAGR

Em

plo

yee

be

ne

fitsM

ain

tenance

Oher

42

Average REIPPP prices per technology compared to Eskom Generation price

43

Eskom Generation Price is lower than all renewable technologies – even

with decreasing renewable prices

Impact of Eskom’s Revenue

Requirement

for MYPD 4

Application is based on recovering operating

costs and to achieve cash flow neutral position

by the 3rd year

With changes, Eskom is not requesting additional 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%

45

Change in % increase due mainly to recovery of efficient costs over realistic

sales volume

0

10

20

30

40

50

60

70

80

90

100

0

50 000

100 000

150 000

200 000

250 000

300 000

350 000

400 000

450 000

500 0002

00

7/0

8

20

08

/09

20

09

/10

20

10

/11

20

11

/12

20

12

/13

20

13

/14

20

14

/15

20

15

/16

20

16

/17

20

17

/18

20

18

/19

Pri

ce

c/k

Wh

Ra

nd

mil

lio

ns

Price levels and Debt increasing

Total debt (LHS) c/kWh (RHS)

Debt continues to increase even though price levels are increased – indicating too low prices

The average price has

increased 5 fold whereas

debt has grown by nearly

10 fold over the same

window

46

Significant losses continue even with MYPD 4 application

Eskom Holding - MYPD4 Application (R’milliions)Projections Application Application Application

FY2019 FY2020 FY2021 FY2022

Revenue 190 862 220 359 253 095 292 401

Primary Energy -75 991 -87 050 -89 080 -92 014

IPP costs -26 549 -30 836 -34 902 -41 134

Other income 1 127 1 206 1 244 1 301

Employee benefit expense -27 140 -26 762 -27 684 -28 935

Arrear Debt -4 436 -4 442 -3 647 -3 903

Other expenses -28 213 -29 231 -31 234 -32 514

Profit before depreciation 29 658 43 244 67 791 95 203

Depreciation -22 095 -27 926 -26 906 -29 950

Profit after depreciation 7 563 15 318 40 886 65 252

Net FV gains/(loss) on embedded derivatives and

financial instruments-222 -1 649 -1 926 -3 086

Net Finance costs -27 467 -33 392 -42 594 -48 112

Net (loss)/profit (20 125) (19 723) (3 635) 14 054

47

Capitalised interest not disclosed in Income Statement. Historic depreciation

included per accounting standards.

Eskom’s status as a going concern – in jeopardy

• As disclosed in Eskom’s recent Annual Financial statements, the going concern

status is highlighted as a emphasis of matter.

• This indicates that level of financial distress that Eskom is experiencing through its

inability to meet its financial commitments

• Eskom cannot solve financial and operational sustainability challenges that it faces

alone - the shortfall in tariff cannot be solved through cost reductions alone, and

further indebtedness adds to the problem

• If Eskom’s Audited Financial Statements are qualified by the auditors on a basis that Eskom is not a going concern this will trigger the following events:

• Lenders will recall their loans as Eskom will be in breach of the loan covenants

• Government will be liable to pay for the loan agreements that are guaranteed causing a run on a third of Government debt

• Eskom will also have to prepare the Audited Financial Statements on a liquidation basis

48

Co

nseq

uen

ces

Cu

rren

t sta

tus

In conclusion, Eskom’s financial situation is unsustainable

• Restoring financial sustainability will require:

• Eskom to continue maintaining cost escalations within inflation range

• Price increases of about 2% p.a. are required to cover IPPs costs growth

• Year 1 reaches 6,4% (4.4% from RCA liquidation decision + IPPs 2%)

• Balance sheet support from the shareholder

• Government support will be required to address the arrear debt recovery from

Municipalities

• Customers require reliable supply of electricity

• Efficiency and prudency evaluation must be cognisant of the operational context and

circumstances

• Restoring operational performance comes at a cost which must be funded and

recovered through revenue requirements

• Debt providers, rating agencies, auditors and other stakeholders will await this crucial

decision

• Ultimately a part of the solution will impact either the electricity consumer or the

taxpayer

49

THANK YOU