Eskom MYPD4

Revenue Application

Focus on Coal and Independent

Power Producer Costs

Nersa Public Hearings

Durban

17 January 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 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

PRIMARY ENERGY COAL COSTS

Eskom is navigating a dynamic coal environment with many challenges to manage

Cost of mining coal

consistently increasing above

inflation and export prices

influence on the domestic

market

Flexibility in coal

procurement to match older

power stations production

ramp down

Coal supply shortfall at

several power stations with

long term contracts coming

to an end

Competition by the export

market for Eskom grade coal

within the 4200-5500kcal range

Growing Renewable Energy

sector disrupting Eskom’s

business model and no

demand growth

Increased pressure from local

communities for localization of

Eskom goods and services

procurement

Lack of new mining

investment in large

scale coal mines

and execution of

current mining rights

Investors and Funders migration

away from coal technology. Signal -

disinvestment in the South African

coal industry by multinationals

5

Within this environment -

Eskom has three primary objectives

Optimal cost of coal

Security of coal supply

Contribute to the lowest cost per MWh sent-out

for Eskom by delivering pit to boiler optimal

coal costs

Meet volume requirements with a safety

margin above coal demand to enhance

flexibility in absorbing burn variance

Eskom will continue to support transformation of

its coal procurement spend in line with the

Mining Charter and implemented through

compliance to the Preferential Procurement

Policy Framework Act and Broad-Based Black

Economic Empowerment Act

Support

transformation in coal

procurement spend

Critical success factors for objectives to be met

include

6

The NERSA tariff determination based on market cost of mining and coal prices

Availability of capital funding for investment in cost plus mines

Eskom’s ability to send a strong signal to procure coal on a long term basis to achieve prices projected in the application

Policy and legislation certainty to stimulate investment in new coal mines

4547

52

6466

69

FY22FY17 FY21FY18 FY19* FY20

+10%

Cost of coal burn to generate electricity over FY20 – FY22

period is projected to be R198.5bn

Coal burn

volumes (Mt) 113.74 115.49 112.93 116.16 113.81 113.54 Coal

purchases

volumes (Mt) 120.25 115.25 120.44 118.44 116.07 116.18

(Rbn)

* FY19 YE projection as at end Nov 2018

Demand as per 11 year supply plan

The difference in volumes

between coal purchases and

coal burn in:

FY19:

– Due to contractual

volumes at Lethabo &

Medupi exceeding burn

requirements

– Building stock at individual

power stations

FY20 – FY22:

– Primarily due to

contractual coal volumes

at Lethabo & Medupi

Power Stations being

higher than the burn

requirement

Insights

0

5

10

15

20

25

30

35

40

45

50

55

60

65

70

75

80

85

90

95

100

105

110

115

120

20452020 2025 2030 20502035 2040

Demand as per 11 year supply plan

Eskom needs to procure coal by:

▪ Providing long term large volume RFP’s to the

market, to trigger long term contracts with mines

and investments into coal mining

▪ Revitalising and continuing investment in

cost-plus mines

▪ Managing flexibility of demand will be done

through Medium term contracts. These

contracts may be at market related prices,

however it provides flexibility for Eskom to

navigate risks involved

Shortfall with cost plus investments as per

draft IRP – 1095Mt

▪ For foreseeable future Eskom is largely

contracted at:

– Matimba - fixed price

– Medupi - fixed price

– Duvha - fixed price

▪ Lethabo (New Vaal) will require investment &

extension

Secured contracts fixed and cost plus Secured Supply – WITH Cost-plus CAPEX

Mtpa

Eskom needs to secure up to 1318 Mt of coal in long term, (if no Cost Plus investments are made) and 1095 Mt should investments in Cost Plus mines are possible and made

Cost plus

Shortfall

Cost plus with investment

Medium term

Fixed price

Shortfall reduces from

1 318 to 1 095 Mt with cost

plus mine investments

Additional 223Mt secured

through cost plus

investments

In 2018, Eskom has secured 91.8Mt of additional coal to be supplied over a number of years

9

98%

78% 76%71% 68%

18%18%

26% 29%

100

2021

1002% 4%

2020

4%

2022 2023 2024

100 100 100

PipelineFlexibilityUncontracted Secured

Demand as per 11 year supply plan

Coal requirement compared to that

contracted will always fluctuate depending on

a number of factors including:

▪ Electricity demand and outlook.

▪ Demand forecast per power station and

variations to that demand on a daily,

weekly, monthly and any other periodic

basis.

▪ Performance of contracted coal suppliers.

▪ Realization of projected coal purchases

that are not yet contracted at time of

presentation

Insights

Percentage contribution of contracted coal vs. requirement

10

Recovery base plan and projection up to March 2020

KEY INSIGHTS

Base plan is official recovery plan and tracked on a weekly basis.

• Actual stock days end Dec 27.5 days vs base plan of 21.8 due to new contracts accelerated delivery and lower burn from

(Gx plant performance)

• Based on high confidence new contracts, forecast to end F2019 at 32 days (5 stations below 20 days but none below 10

days)

• All power stations recover to expected levels between Sep 2019 and Mar 2020

11

10 power stations are currently below prescribed

minimum stock days

Coal fleet stock levels on 13 January 2019 Below Minimum level

Power station

Arnot

Camden

Duvha

Grootvlei

Hendrina

Kendal

Komati

Kriel

Kusile

Lethabo

Majuba

Matla

Matimba

Medupi

Tutuka

Total System*

Above minimum level

26 30 35 Dec 2019

20 20 25 Oct 2019

22 26 30 Mar 2020

20 23 25 Feb 2020

20 25 30 Feb 2020

25 30 35 Sep 2019

7 7 11 Sep 2019

32 38 44 Mar 2020

25 30 35 N/A

24 27 30 N/A

40 45 50 Nov 2019

27 31 35 Dec 2019

20 24 28 N/A

20 24 28 N/A

32 36 40 Nov 2019

26 30 37

Minimum Alarm Expected Recovery Date

* Total System excludes Medupi and Kusile

• 10 Power Stations are below the prescribed Minimum level

• 5 stations (viz Arnot, Camden, Hendrina, Kriel and Matla) are below 10 days

• Total stock excluding Medupi and Kusile = 27.3 days

SA’s historic bituminous coal production = local + export sales. (No surplus availability)

Burn vs Purchases (Mt)

62 59 60 68 71 65 67 63 65 60 60 53 52 50 47 40 42 41

28 29 3030 31

31 31 31 30 30 3031 29 28 31

33 33 31

16 20 2638

31 37 40 45 44 44 46 45 44

120

• FY02 FY14

71

FY17FY15

1

• FY00• FY01

120113

2

• FY03

122

93 11

• FY04• FY06• FY07• FY08FY09 FY10 FY11 FY12 FY13 FY16

105

FY18

92 89

124

112117

133122 126 126 122

115119

• No surplus coal in system. All bituminous coal

produced is either sold locally or exported.

• Production in 2016 is almost the same as in

2006, but export volume is higher

• ‘This is after five years of confusion, after five

years of the mining moratorium because no one

was going to invest...’ Sikonathi Mantshantsha,

deputy editor at Financial Mail, on intention to

revoke MPRDA amendment bill.

• Exports facilitated by increasing Transnet rail

capacity to RBCT .

South African Coal Roadmap steering committee

chairperson Ian Hall:

• ‘From 2013 to 2019, 120-million tons of new

capacity need(ed)to come on stream’. This did

not occur

• ‘The current coal supplies to State electricity

utility Eskom will decline rapidly after 2015,

when existing large-scale mines' suppliers

reach the end of their lives and require

(expansion) recapitalisation’.

• SA’s exports expanded from India & China to

include The Netherlands, Italy, Morocco, Egypt

& Senegal.

ST/MT CPFP Burn

69 69 6971

68 71 68 6759

60 66 6875 73 73 74 72

223 222 219238 242 243 245 245 251 249 255 248 256 253 258

249 248

0

50

100

150

200

250

300

20062001 2016

182157154

20082000

168152

20032002

178

2004

173

2005

176 182

2007

196 184

2009

185

20122010

177

2011

184

2013

181

2014

177

2015

180

Sales vs Production of bituminous coal (Mt)

Production

Export sales

Local sales

Eskom purchases

Eskom burn

Comments

Source: SAMI; Eskom PED

Furthermore, bulk of export grade coal competes with Eskom’s boiler specifications

Source: IHS Markit

1018 17 17 17 17

1825

35 36 36 35 34

5239

26 25 24 24 23

0

20202016

06

2

00

2021

2

2015

0

22

0

2017

2

2018

2

0

276

2019

7882 80 79 78 77

<4,200 kcal/kg, NAR>6,200 kcal/kg, NAR 5,000-5,600 kcal/kg, NAR

4,200-5,000 kcal/kg, NAR5,600-6,200 kcal/kg, NAR

South African thermal coal exports – from all ports

Million ton

Eskom Grade Coal

• Minerals Council of SA (nee Chamber of Mines) Coal Strategy 2018, forecasts that India’s coal demand will continue to

increase in the foreseeable future, best case will be that exports remain constant

• Investment capital may also not be available in the future, as financing for coal based energy is reducing, thus coal

mining investment is uncertain which will further constrain coal supply as Eskom will be competing against the export

market for this limited supply

• Eskom must guard itself in this limited supply environment by signing long term coal supply agreements which will

ensure security of coal supply and hedge against price fluctuations

Eskom faces a coal supply shortfall, however has a plan to remedy the problem on long term basis

Causes of coal supply shortages Long term coal strategy pillars

• Unsuccessful negotiations to extend Arnot

Power Station tied colliery coal supply

agreement

• Kusile long term tied colliery coal contracts did

not materialize (makes up the bulk of the 1

318Mt shortfall)

• Contract negotiations to extend the Hendrina

tied colliery coal contract discontinued

• Lack of capital investment in the at four of the

five cost plus mines resulting in reduced

production – mines producing at 68% of

contractual

• Limited investment in RSA in opening new

large scale mines

• Increased export volume of Eskom grade coal

• Extension of cost plus mines for total reserves

to match power stations life.

• Investment in cost plus mines to access

remaining reserves for contractual volumes

• Extension of the tied long term fixed price

collieries

• Expansion of domestic rail infrastructure for

Eskom by Transnet

• Coal open tenders to source coal for the

remaining life of power stations

It is critical for Eskom to recapitalise cost plus

mines to stem the production decline…

R bn

0,16

0,260,43

0,80

0,110,08

FY23FY21

0,08 0,07

FY17

0,88

0,10

0,18

2,58

FY22

0,12

0,12

0,05

0,92

0,02

FY20

2,01

2,43

FY19

2,13

3,79

FY18

0,05 0,050,08

FY24

0,19

1,23

0,94

3,93

1,31

R5.65bn

Logistics

Reinvestment in mines

Reinvestment in equip

Beneficiation

Water treatment

Other

• With investment in CP mines, an additional 34.6 Mt is forecast over FY20 – FY24

• More than 90% of capital expenditure over FY20 – FY22 is for reinvestment in the cost plus mines.

• Investing in cost plus mines is integral to Eskom’s long term coal strategy.

• Investment in cost plus mines and extension of cost plus agreements is required to secure coal volume. Steady state

coal supply and costs is anticipated from about FY23/24 based on investments taking place as planned

• Impact of not investing in cost plus mines will result in further reduction in coal from these mines and an increase in

expenditure on short/medium term coal.

FY23

1,93

FY20

32,70

6,65

27,70

FY21

8,13

30,20

FY22

8,55

28,30

38,33

9,34

26,09

FY24

34,63 34,3535,43

36,85

No investment

Investment

CP production (Mtons)

…and manage increases in cost of coal burnt to

generate electricity

• RSA has experienced limited investment in new coal mines, especially new large mines.

• Eskom has been increasingly competing for coal with other buyers, especially seaborne.

• Annual increases in coal R/ton cost have been impacted by lower production at cost plus

mines and increasing costs of replacement coal due to associated transport costs.

• Eskom intends to:

• Increase or contract coal from suppliers closest to the Eskom Power Stations

• Invest in Cost Plus mines

• Secure long term coal contracts through life of Power Station open tenders

• Procure coal through transparent coal procurement mechanisms in line with

Preferential Procurement Policy Framework Act regulations.

• Seek and strive to manage coal cost increases over MYPD application periods

estimated at less than 10% per annum on a CAGR basis

Independent Power

Producer Costs

Policy implementationRegulations for New Generation Capacity

2019/01/17 18

IPP

Eskom

Integrated Resource Plan

Developed

By DoE

DoE Accountable

Approved IRP

Cabinet Approval

Gazetted

Minister of Energy

Procurement

(bid evaluation, negotiating

PPAs)

Procurer- DoE,

Buyer - Eskom

Determination

Minster of Energy,

with Minister of Finance

Eskom procure or

build

Eskom responsible

for ownership,

engineering,

procurement and

construction

Principles of Section 34 procurement

– In Terms of Regulations of Electricity Regulation Act (ERA), Minister of Energy makes a determination that Eskom be buyer of energy from IPP’s

– Before signing a Power Purchase Agreement (PPA), the Regulations also require Eskom to ensure that it meets requirement for “value for money” and also ensure PPA meets requirements of Electricity Regulation Act, Public Finance Management Act, Companies Act and all applicable legislation before signing in line with Board’s fiduciary duties

– When Eskom makes an MYPD revenue application, Eskom estimates future costs of actual purchases of power from IPPs as well as administration costs (employee benefits, depreciation, travel and subsistence, legal costs, office costs).

– NERSA assesses costs as forecasted by Eskom for future period covered by the particular MYPD revenue application, and if NERSA deems it appropriate it will substitute a different assumption regarding these future costs, for the purpose of its revenue determination.

– IPP costs are included in the revenue allowance made to Eskom and are subsequently included in the calculations of the Eskom tariffs to customers. Therefore, Eskom recovers these costs through revenue when customers pay Eskom, same as for Eskom’s other costs.

– After the end of the financial year, when Eskom submits the Regulatory Clearance Account (RCA) application, a comparison is made of the assumed costs as included in the MYPD revenue determination versus the actual costs incurred i.e. payments to IPPs for the year, to determine if there was an over recovery or under recovery

– Eskom will be refunded (by virtue of an ‘add-on’ to future ‘allowed revenues’ thus tariffs) for an under recovery and for an over recovery Eskom will have a reduction of the RCA amount (thus a deduction from future ‘allowed

Primary energy indicates an increasing trend in IPPs and decreasing trend in coal

• Generation own primary energy costs have a compounded average growth rate (CAGR) of 6.4% per annum from 2018/19 to 2021/22

• Non-Eskom primary energy costs reflect a CAGR of 14.8% per annum between 2018/19 to 2021/22. Of this, local IPPs have a CAGR of 15.6%.

• Total primary energy reflects a CAGR of 9.0% per annum between 2018/19 to 2021/22

• Coal burn costs reflect a CAGR over the period of 7.8% per annum

20

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

1%

26%

6%7%0%

FY2019/20

60%

28%

7%3%1%

1%1%

0%

FY2020/21

58%

31%

62%

3%1%3% 0%

122,131

FY2021/22

1%

114,781

132,6679%

Nuclear

International purchases

Coal

IPPs

Environmental levy

OCGT

DMP

IPP portfolio mix assumptions – energy

21

Assumptions on IPP

portfolio mix for

MYPD4:

• DOE Peaker

projects –

contractual

assumptions

• REIPP - five bid

windows (bid

window 1, 2, 3,

3.5, 4)

• No short-term

Eskom

programmes

10.000

0

5.000

15.000

20.000

2018/19

GWh

0

67

18.577

12.01011.2829.479

7.228

4.235

2016/17

0

105

0

2019/202017/18

169

0

2020/21

88

88

14.947

0

88

2021/22

Renewables

STPPP/MTPPP

DoE Peakers

IPP portfolio mix assumptions – costs

22

IPP portfolio mix

Assumptions for MYPD 4

• DOE Peaker projects

– contractual

assumptions

• REIPP

- Signed (BW 1, 2, 3,

3.5 and 4) – using

PPA prices

&expected energy

• No short-term Eskom

programmes

45.000

10.000

0

15.000

5.000

25.000

20.000

35.000

30.000

40.000

R million

2.186

2019/20

15.582

3.952

2018/192016/17

2.291

19.008

2017/18

2.648

23.709

2.422

26.928

2.463

31.607

2020/21

2.513

38.220

2021/22

DOE Peakers

Renewables

STPPP/MTPPP

IPP programme details

Renewable IPP programme

• Five bid windows (bid window 1, 2, 3, 3.5, 4) concluded.

• Costs for BW 1 through 4 are based on finalised power purchase agreements (PPAs)

• Costs associated with the Small Renewable IPP programme are not included in this application

DoE Peaker

• The Peaker programme has been fully operational from 20 July 2016 with capacity of 1 005 MW.

• These power stations are compensated for available capacity on system and energy produced.

• They are fully dispatched by System Operator.

• Expected load factor of 2 stations is 1%, leading to an expected energy output of 88 GWh per year.

Co-generation

• One contract was announced under the Co-generation programme but has never been finalised.

• Co-generation costs are not included in this application.

Base-load Coal

• Two preferred bidders were announced under the Coal programme but these contracts have not been

finalised.

• Costs associated with the Coal programme are not included in this application.

Wholesale Electricity Pricing System (WEPS) programme

• The application does not include any allowance for Eskom short term programmes.

23

Renewable Energy Independent Power

Producer Procurement Programme

(REIPP)

• 1st determination 2011 (3725 MW)

• 2nd determination 2012 (+ 3200 MW)

• 3rd determination 2015 (+ 6300 MW)

2011 determinations Eskom commitments (pre IRP)

2012 determinations

IRP 2010 capacities and status of

determinations to allocate them for implementation

2015 determinations

An

no

un

ce

d

Ap

pro

ve

d

Co

ntra

cte

d

Op

era

tion

al

TOTAL 8 127 6305 6305 3876

BW1 1425 1424 1424 1415

BW2 1040 1041 1041 1033

BW3 1457 1435 1435 1428

BW3.5 200 200 200 0

BW4, 4.5 2205 2205 2205 0

BW 5 1800 0 0 0

Smalls 1 49 0 0 0

Renewable energy determinationsMinister of Energy designates RE for IPPs; Eskom is Buyer

24

IPP procurement pricesSteady decline in Wind and PV costs

2019/01/17 25

Source: SBO estimated payment in April 2023 (when all operating), adjusted to 2018 ZAR. Some BW 2 and BW 3 projects have partial

indexation (leading to over-estimation of cost relative to others not using partial indexation). CSP average prices reflect expected

generation over peak which carries substantial price premium.

4 064 3 907

3 588 3 971

2 460

1 322

995

1 702

1 373

979 825

-

500

1 000

1 500

2 000

2 500

3 000

3 500

4 000

4 500

BW1 BW 2 BW 3 BW 4

Ave

rag

e e

nerg

y p

rice

(R

/MW

h,

20

18

ZA

R)

CSP PV Wind

Renewable Portfolio (for FY 2021/22)

Technology BW1 BW2 BW 3 + 3.5 BW 4 Total

Wind 1 973.40 1 741.93 2 803.80 3 960.96 10 480.10

Solar PV 1 324.57 988.70 959.56 2 133.10 5 405.93

CSP 502.28 232.94 1 584.73 0.00 2 319.95

Other 0.00 93.08 53.64 224.51 371.24

Total 3 800.26 3 056.66 5 401.74 6 318.57 18 577.22

26

Technology BW1 BW2 BW 3 + 3.5 BW 4 Total

Wind 1 702.17 1 373.08 978.68 825.29 1 122.50

Solar PV 3 970.80 2 459.71 1 321.57 995.40 2 050.14

CSP 4 063.84 3 907.45 3 588.33 - 3 723.32

Other - 1 470.59 1 289.53 1 777.53 1 630.05

Total 2 805.04 1 920.67 1 808.28 916.55 1 727.37

Expected energy output (GWh)

Average price (R/MWh) (2018 ZAR)

Note: Impact of additional CSP (200 MW) from BW 3.5 counters the price reduction in PV and Wind from BW 2 to BW 3

Additional cost of BW 4 at 91,7c/kWh (not R2.22/kWh mentioned in media)

REIPPP Bid Window Costs (Real)

27

0

0,5

1

1,5

2

2,5

3

-

5 000,00

10 000,00

15 000,00

20 000,00

25 000,00

30 000,00

35 000,00

Ave

rag

e R

EIP

PP

pri

ce

(R

/kW

h, 20

18

ZA

R)

An

nu

al

PP

A c

ost

(Rm

, 20

18

ZA

R)

BW 4+ BW4 BW3.5 BW3 BW2 BW1 Avg price (rhs)

Trends in IPP revenue increase (nominal)

CAGR increase of 15.6% over MYPD 4 application period

29

Seasonal output patterns - REIPPP

0

10

20

30

40

50

60

Jan-16 Apr-16 Jul-16 Oct-16 Jan-17 Apr-17 Jul-17 Oct-17 Jan-18 Apr-18 Jul-18 Oct-18

Cap

acit

y f

acto

r (%

)

REIPP Monthly Capacity Factor

CSP

Wind

PV

Average REIPPP prices per technology

30

Thank you