Eskom 2018/19

Revenue Application

Nersa Public Hearings

Klerksdorp

13 November 2017

Where we are coming from

• This revenue application is being made for the year 2018/19, after the EnergyRegulator maintained its revenue decision made in 2013 for the 2017/18 year, whereit approved total allowable revenue of R205 billion.

• The allowed revenue resulted in an average increase of 2.2% due to baseadjustments made in preceding years following approved RCA balances for Eskom(12.69% for 2015/16 for MYPD2 and 9.4% for 2016/17 for first year of MYPD3).

• The 2.2% average increase resulted in consumers receiving an effective decrease inelectricity prices, in a situation where costs to produce electricity are increasing.

• Eskom, in this revenue application for the 2018/19 year has applied the NERSA MYPDmethodology of 2016, with a phasing-in of return on assets being applied

• Allowed revenue and price adjustments decisions will be applicable from 1 April 2018

• This revenue application does not include any RCA applications for the MYPD 3period. Eskom understands that NERSA will process RCAs for years 2, 3 and 4 of theMYPD 3 period at a later stage. The adjustments will be applicable from 1 April 2019onwards in a phased manner

1

Eskom’s revenue application is completed within the legislative and NERSA’s regulatory framework

2

Electricity Pricing Policy

(EPP)

Electricity Regulation

Act (ERA)

Municipal Finance

Management Act

(MFMA)

Multi-Year Price

Determination (MYPD)

Methodology

Eskom Retail Tariff &

Structural Adjustment

(ERTSA) Methodology

Provides guidelines to NERSA in approving prices and tariffs for the

electricity supply industry

• Enable an efficient licensee to recover full cost of its licensed activities,

including a reasonable margin

• Avoid undue discrimination between customer categories

• May permit cross subsidy of tariffs

• Only implement tariffs determined by NERSA

• Eskom consults with SALGA & National Treasury prior to submission to

NERSA

• Municipal tariffs tabled in Parliament by 15 Mar for 1 July

implementation

• Determines allowable revenue (AR) for efficient costs and fair return

where 𝐴𝑅 = (𝑅𝐴𝐵×𝑊𝐴𝐶𝐶)+𝐸+𝑃𝐸+𝐷+𝑅&𝐷+𝐼𝐷𝑀±𝑆𝑄𝐼+𝐿&𝑇±𝑅𝐶𝐴• RCA not included in this revenue application

• Allows for NERSA determined allowed revenue to be recovered by the

assumed volume of sales for each year of the revenue period.

• Determines rate adjustments to tariffs applicable to customer groups

and schedule of standard prices applicable to different Eskom tariffs

Notes: Regulatory asset base (RAB); Primary energy (PE); Service Quality incentives (SQI); Expenditure (E); Levies & Taxes (L&T);

Research & Development (R&D); Weighted Average Cost of Capital (WACC); Integrated Demand Management (IDM); Regulatory Clearing

Account (RCA)

Framework Requirements

Depreciation

The MYPD methodology through the allowable revenue formula was applied

3

+ + + + + =

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

Based on the MYPD Methodology the total allowable revenue is R219.5 billion for FY2018/19

4

• Absolute Revenue

increase of R14.3 bn

(7%) from previous

Nersa decision

• Standard tariff

customers contribute

to 3.6% increase in

allowed revenue

• Export and NPA

revenues account for

3.4% increase in

allowed revenue

• About 15% of allowed

revenue related to IPP

costs

Regulated Asset Base

WACC (%)

Returns

Expenditure

Primary energy

IPPs (local)

International purchases

Depreciation

IDM

Research & development

Levies and taxes

RCA

Total Allowable Revenue

763 589

2.97%

22 690

62 221

59 340

34 209

3 216

29 140

511

193

7 994

-

219 514

×

+

+

+

+

+

+

+

+

+

RAB

ROA

E

PE

PE

PE

D

I

R&D

L&T

RCA

Allowable Revenue (AR) Application

FY2018/19 (R’m)Fx

Application of the NERSA Allowable Revenue formula indicates a revenue growth of R14.3 billion

5

Increases in allowed revenue when compared to MYPD 3 (2017/18) decision mainly due to:

↑ Increases in IPP costs due to additional IPP programmes; marginal increase in other PE costs

↑ Increases in operating costs (compared to previous MYPD decision – close to inflation increases for actuals

↑ Change in MYPD methodology in treatment of cost of imports (with concomitant increase in import revenue)

Decrease in allowed revenue when compared to MYPD 3(2017/18) decision mainly due to :

↓ Further sacrifice in return on assets

↓ Decrease in environmental levy due to lower energy sent out

R219.5

MYPD3Revenue

2017/18

IPPs Operating Cost

Primary Energy

InternationalPurchases

R11.2b

Depreciation Returns Total Allowable

Revenue2018/19

Evironmentallevy

Rand

billi

ons

R205.2b

R13.2bR1.0b

R2.8b R0b

-R12b-R1.8b

Revenue requirement grows by R14.3 bn

Electricity price impact in 2018/19

Standard tariff revenue has increased by R7 251 million which equates to revenue increase of 3.6% from NERSA’s decision for the 2017/18 year.

As the revenue is recouped from a lower sales volume, the overall price increase required is 19.9% for 2018/19.

The 19.9% average increase translates to a 1 July 2018 local-authority tariff increase of 27.5% to municipalities.

– Municipalities continue to pay at the 2017/18 rates for the period 1 April 2018 to 30 June 2018.

– This is due to the Municipal Finance Management Act (MFMA) requiring Municipal tariff changes to be made only from 1 July each year.

6

Standard tariff revenue

Standard tariff sales volumes

Standard tariff price

198 954

Standard tariff price adjustment 2.2%

206 205

192 953

106.87

19.9%

2017/18 2018/19

223 217

89.13

R’m

%

Unit

GWh

c/kWH

Standard tariff

Factors influencing the overall price increase

7

19.9%

30

26

5

GW

hR

26

97

4m R

10

81

2m

Vo

Gro

Sales volumes

rebasing

IPPs International Purchases

9.4%

5.5%

1.4% 16.3%

Price before operating costs

changes

Generationown PE costs

7.0% 0.5% 23.8%

Opex Price after operating

costs

-6.0%

Adjustments Operating costs Depr , Returns , SPAs & Exports

Overall Price

Increase

Pri

ce Im

pact

%

SPAs &Exports

2.1%

Depr &Returns

With average 2.2% increase in 2017/18 and 19.9% proposed average increase in 2018/19

Average for two years is 11%

Conservative assumption have been used for RAB, migration of ROA towards WACC, and depreciation

8

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

• Opening RAB balance for

FY2019 is based on the MYPD

3 decision which is then

adjusted for the latest capital

expenditure forecasts for the

period FY2014 to FY2018.

• Eskom will revalue the RAB

for subsequent revenue

application in accordance with

Nersa condonation decision

In accordance with the MYPD

methodology, depreciation is

computed by dividing RAB over

remaining life of respective

assets. Therefore depreciation

amounts have remained

relatively similar to 2017/18 as a

similar RAB value is used for the

FY2018/19 revenue application

• MYPD methodology allows for

ROA as proxy for interest costs,

tax and equity return to the

shareholder

• In accordance with Nersa decision

migration of ROA towards full

WACC is phased over a longer

period.

• NERSA MYPD 3 decision of 4,7%

for FY2017/18 is reduced to

2.97% for FY2018/19 revenue

application.

Assets

Working capital & WUC

Eskom RAB

592 104

171 485

763 589

Regulatory Asset Base (R’m) Return on Assets (R’m) Depreciation (R’m)

Ave RAB

Return on Assets (ROA)

Returns

763 589

8.4%

64 142

Phased in ROA 2.97%

Phased in Returns 22 690

Returns sacrificed -41 452

Generation

Transmission

Distribution

19 062

3 833

6 245

Total Depreciation 29 140Generation

Transmission

Distribution

549 527

109 371

104 691

Primary Energy costs assumptions

9

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

50.000

90.000

60.000

80.000

70.000

110.000

20.000

100.000

40.000

0

10.000

30.000

8.087

49.991

2018/19

21.720

3.127

7.242

44.652

8.152

2.681

2016/17

3.216

8.6588.156

2017/18

24.450

45 642

34.209

7.994

Other Eskom PE

OCGT Fuel Cost

Coal

IPPs

Environmental Levy

International Purchases

Rand m

illio

ns

Further in- depth details to be shared at this public hearing

System Operations

Operating Costs

10

System Operator is in Process of Implementing Scheduling and Dispatch Rules (SDR)

• The process starts with the day-ahead hourly demand forecast:

• Key factors are historical seasonal demand profile, weather patterns, day of the week, public and school holidays, labor unrest etc.

• Renewable energy (as forecasted) is regarded as negative load, residual load is the net day-ahead forecast to be supplied by conventional generators.

• In terms of the SDR, thermal and hydro power plants are then optimized and dispatched based on economic merit order of each unit’s marginal cost of production, while considering system security

• Emergency resources such as ILS and gas turbines are scheduled by the SO to manage system emergencies and in line with other contractual obligations

• Ancillary services reserves (currently about 2000MW) are also co-optimised in order to minimize the total cost of production

• Night minimum load is managed through Mingen, Pumping and Curtailments

11

Cost of generation

Demand forecast

Unconstrained

schedule

(Cheapest mix)

Network constraints

Constrained schedule

Day ahead contract

Day-Ahead Generation Scheduling Process

Operating reserve requirement

Renewable Forecast

Reliability of Solar PV and Wind have an impact on generation dispatch

13

PV

Wind

Seasonal Load profile

• Outages are planned around the peak demand

• The summer load profile is a lot “flatter” than the winter profile

• In winter there is a higher probability of problems over the peak periods

• Peaking plant is required for many more hours during the day in summer than in winter due

to the high maintenance of base load units during the summer months and the flat load

profile

Meeting the demand on a typical day

• The bulk of the demand is met by base load coal, nuclear and imports via HVDC

• OCGTs and Pumped Storage plants are mainly required to manage peak demand

• The renewable generators are starting to make a substantial contribution, peaking

at just under 2500 MW (sent out) during 2017 (so far). Unfortunately Solar PV

disappears as we start climbing the evening peak

• Coal and hydro are the main providers of flexibility at present

20000

21000

22000

23000

24000

25000

26000

27000

28000

29000

30000

31000

32000

33000

34000

35000

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Monday 15 May 2017 - Actual Demand

16

Highest difference between peak demand and night minimum during winter 2017

The difference between

minimum and peak

demand was over 13 000

MW.

• The above graph illustrates the difference between the minimum and peak demand that needs

to be supplied by dispatchable plant

• Thermal plant will be reduced to minimum stable region to avoid shutting them down

• Pumping, two shifting and (on rare occasions) curtailment will be implemented to manage

night minimum

Emergency merit order deployment

MCR, all units to maximum continuous rated output

Emergency Level 1, some units exceed MCR for short

duration

Virtual Power Station, customers paid to reduce

Request mutual assistance from other power companies

Withdraw non-firm exports

Dispatch Open Cycle Gas Turbines (diesel)

Dispatch Gas Turbines

Use emergency hydro generation hours

Interruptible Load Shedding contracts

Declare SAPP emergency

Load curtailment (NRS048-9)

Load shedding (NRS048-9)

240 MW

* 700 MW

126 MW

Varies

3 086 MW

342 MW

600 MW

Varies

2 024 MW

2 hours

* 2 hours

Fuel

dependent

Fuel

dependent

Fuel

dependent

DWS

dependent

2 hours

Rotational

The merit

order varies

depending on

magnitude and

Anticipated

duration of the

emergency

Conclusion on SDR

• Generation dispatch is guided by the Grid Code – The Scheduling and Dispatch Rules (SDR)

• Economic dispatch is achievable but is also subject to network and generation plant constrains

• As more renewables (both grid-tied and behind-the-meter) are integrated, the role of the SO will become crucial and more challenging

• Currently the costs of balancing and flexibility are currently socialized, these may have to be explicit in future

• Additional resources will be required to fully meet the requirement of the SDR

18

19

Operating costs mix in 2018/19

25,00%

29,00%

46,00%

Other Opex

Maintenance

Employee benefit costs

• Almost half of the operating cost is attributable to

employee benefits (46%) with the maintenance

(29%) and other operating costs (25%) making up

the remainder

• Significant efficiencies would be achieved for

employee benefits over the period by reducing the

number of employees without compromising the

required skills

• As the business strives to accelerate maintenance

programmes, and with the ageing plant it is expected

that maintenance costs should increase. Eskom will

ensure that maintenance is carried out prudently

and efficiently.

• The growth in other operating costs is less than

inflation after 2016/17. Included in this category are

costs such as insurance, information technology,

operating leases, materials, equipment repairs,

facility service costs, fleet costs, legal and audit

services, security, travel expenses, billing costs,

connection/disconnection costs, meter reading,

vending commission costs and telecoms.

(R28.3bn)

( R17.7bn)

(R15.8bn)

Operating Costs increase by average of 7.3% over the period

20

• Employee benefits- CAGR of 4.9% p.a. - 2013/14 to 2018/19 on back of declining staff complement

• Opex escalate by CAGR of 7.3% after normalising for once off transactions

• 2018/19 Opex – Employee benefit of R28.3bn (46%); Maintenance of R17.7bn (29%); Other opex of

R15.8bn (25%)

• 2018/19 Maintenance cost includes long duration outages for both Koeberg Units (R1.6bn)

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

2014/15 2015/16 2016/17 2017/18

7.3%

2018/192012/13

R’m

2013/14

Employee benefits

Operations & Maintenance

4.9%

21

• Eskom’s remuneration levels for (bargaining unit)

staff reflects packages which are higher than

combined market reference based on unions

requests being premised on improving living

standards of members.

• At managerial level Eskom is either tracking

market or below

• Total employee benefits costs: FY19 - R28.4bn

• Escalation of 1% to FY18 & 0.5% growth to FY19

• Employee benefit expenses consist of both direct &

indirect expenses (such as training &

development). Dividing gross employee benefit

expenses by permanent headcount would

overstate average cost per head.

• Gross employee benefit costs directly incurred for

capital projects are allocated to the projects

(capitalised) and recovered over life of capital asset

through amortisation when asset is depreciated

Level of remuneration is aligned to market

Employee benefit costs remain flat

28,363

39,186

2017/18

28,213

41,238

2016/17

27,902

41,940

2015/16

24,721

43,640

2018/19

R’m

Num

be

r

Staff complement Employee benefits

Employee benefit costs will escalate by 5% to FY2018/19

Opex (Rm)(nominal) Actual

2016/17

Projections

2017/18

Application

2018/19

Maintenance 14 087 15 610 17 665

Other operating costs 17 938 15 385 15 796

22

The trend in other operating costs have decreased over the three

year period as reflected in table. Included here Insurance, security,

transport, contractor costs, IT (information technology), fleet costs,

legal and audit services, security, travel expenses, billing costs,

connection/disconnection costs, meter reading, vending

commission costs, allocation of decommissioning costs and

telecoms.

Eskom maintenance and other operating cost trends

14

16

18

15

13

17

2017/182016/17 2018/19

Common feature for Eskom’s system is the ageing network and

power stations. As new power stations are commissioned they

initially require lower maintenance costs than older power stations.

Expansion of transmission and distribution network requires

additional maintenance costs. Accelerated electrification results in

additional assets that need to be maintained. A steady increase in

maintenance costs are evident over the three years. The 2018/19

Maintenance cost includes long duration outages for both Koeberg

Units (R1.6bn).

14

16

18

15

13

17

Maintenance

Other operating costs

23

• Operating costs reflect efficient costs with

0.2bn increase for 2019 from 2018 projections

• However there is a variance of R13bn

between MYPD 3 decision and projections for

2018 . The basis of MYPD 3 decision was

MYPD 2 decision,

- Not efficient cost through MYPD 2 period

- Certain opex in MYPD 3 were lower in

MYPD 3 than in MYPD 2 decisions

- Lower opex determination exacerbated over 5 year period

NERSA MYPD 3 decision for Operating costs - did not reflect efficient costs during MYPD 2 period - but maintained MYPD 2 decision as basis

In conclusion , Eskom will supply electricity which comes at a cost that needs be recovered

• Eskom has delivered R47billion of savings over the first 4 years of MYPD3

• We have continuously been striving to improve operations, commission new capacity assoon as possible and aim to extract cost efficiencies over the period

• Our business contains a substantial element of fixed costs that are not easily reduced in theshort term. This will require consideration and balancing of socio economic factors whichmust be considered before making a final decision

• Eskom’s debt commitments have increased significantly over the last few years with amajor portion that has been guaranteed by Government.

• Our debt maturities reflect a step change in the near term that requires a strong balancesheet to cover these commitments

• Eskom, believes that this revenue application has taken these factors into account in aimingto keep cost escalations close to inflation and phasing in of returns to mitigate impact on thecustomer

24

Thank you