Eskom 2018/19 Revenue

Application

Stakeholder Discussion (With page numbers)

20 September 2017

Where we are coming from Page 9

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

• The allowed revenue resulted in an average increase of 2.2% due to base adjustments 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 in electricity 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 MYPD methodology of 2016, with a phasing - in of return on assets being applied

• This revenue application does not include any RCA applications for the MYPD 3 period. Eskom awaits guidance from NERSA on the processing of RCAs for years 2, 3 and 4 of the MYPD 3 period.

1

Depreciation

Allowed revenue in accordance with MYPD methodology is increased by 3.6% for Standard Tariff Customers - Page 10

2

• 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

+ + + + + =

Primary

Energy (incl imports and

DMP)

IPPs Operating

expenditure (incl R &D)

Integrated

Demand

Management

Return on

Assets Revenue

R62.6bn R34.2bn R62.4bn R0.5bn R29.1bn R22.7bn R219.5bn

+

Tax &

Levies

R8.0bn + + + + + = +

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

Based on the MYPD Methodology the total allowable revenue is R219.5 billion for FY2018/19 Page 10

3

• 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

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 Page 29

4

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

224 752

211 721

244 318

140000

160000

180000

200000

220000

240000

260000

19

94

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95

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96

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97

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98

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99

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Eskom Sales Trend (GWh)

Historic actual sales 10 Year Sales Forecast MYPD3 Budget

Declining sales trend over MYPD 3 period indicates requirements to rebase due to sales volumes – Page 42

Source: Forecasting consolidation.

Key drivers for declining sales

• Decrease in reliance on Eskom electricity

• Lower competitiveness of SA industries internationally

• Low investor confidence (Eskom & SA), system

constraints, price elasticity, IDM initiatives, weak GDP

growth, low commodity prices & cheap imports

resulted in a decline in consumption & customer

closures since 2012

5

MYPD3 Decision

Realistic Forecast

Even with a 0% increase in Allowable Revenue - rebasing of sales from MYPD 3 results in a 9.4% price increase Page 31

6

• The ERTSA methodology does not adjust for volume changes during a MYPD cycle

• It is only at the next cycle that adjustments can be made

• Thus the sales volume gap of about 30TWh would need to be implemented in the 2018/19 decision

• Assuming the same allowed revenue in 2018/19 as was for 2017/18; recovered over lower volume (of

30TWh) results in 9.4% price increase (after incorporating primary energy savings)

• MYPD methodology requires recovery of allowed revenue (consisting of fixed and variable costs)

through assumed sales volume

• If sales volume drop the related fixed costs are not recovered (primary energy costs are saved)

• The converse is true if the sales volume is higher than assumed

22

3.2

19

19

2 9

53

20

6.4

12

20

8.4

42

2015/16 2013/14 2016/17 2014/15 2017/18

21

3.5

45

19

4.7

62

19

5.2

58

19

2.0

89

18

9.8

45

21

8.1

94

GWh Act/Proj Std

Tariff sales

MYPD 3

Sales Decision Standard tariff revenue as at FY18

Savings on PE due to lower sales

Revised standard tariff for FY19

198 954

Standard tariff volumes (GWh) 223 217

Standard tariff ave electricity price

(revenue/sales volumes - c/kWh)

89.13

Price adj for rebasing sales volumes

198 954

-10 812

188 142

192 953

97.50

9.4%

Decision vs actual standard tariff sales Rebasing of sales volumes (R’m)

2017/18 2018/19

In order to increase sales volumes Eskom has implemented

a local demand stimulation strategy – Page 48

7

Factors influencing the overall price increase - Page 30

8

19.9%

30

26

5 G

Wh

R2

69

74

mR

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

Electricity price impact in 2018/19 Page 14

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.

9

Standard tariff price impact Unit

MYPD3

Decision

2017/18

Application

2018/19

Standard tariff revenue R'm 198 954 206 205

Standard tariff sales volumes GWh 223 217 192 953

Standard tariff price c/kWh 89.13 106.87

Standard tariff price adjustments % 2.2% 19.9%

Conservative assumption have been used for RAB, migration of WACC and depreciation Page 59 to 62

10

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 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

RAB has not changed

significantly.

• MYPD methodology allows for

ROA as proxy for interest

costs and equity return to the

shareholder

• In accordance with Nersa

decision and EPP, migration of

WACC is phased over a longer

period.

• NERSA MYPD 3 decision of

4,7% is reduced to 2.97%.

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 29 140 Generation

Transmission

Distribution

549 527

109 371

104 691

Primary energy costs reflects CAGR 8.5% p.a. but the position improves when local IPPs are excluded Page 66

11

• Between 2013/14 to 2018/19 , primary energy costs escalate with CAGR of 1.5% p.a.

• Primary energy costs peaked during FY2015 & FY2016 when OCGTs were utilised to

minimise load shedding

• IPPs played vital role during supply challenges – however under the current

environment the growth in IPPs are displacing Eskom power stations

• Total primary energy costs reflects CAGR of 8.7% p.a. once local IPPs are incorporated

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

2014/15 2013/14

R’’m

2012/13

+8.7%

2018/19 2017/18 2015/16 2016/17

IPPs

Gx Primary Energy 1.5%

Primary Energy costs assumptions Page 66

12

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

8.658 8.156

2017/18

24.450

45 642

34.209

7.994

Other Eskom PE

OCGT Fuel Cost

Coal

IPPs

Environmental Levy

International Purchases

Ra

nd

mill

ion

s

IPP portfolio mix assumptions Page 68

13

Assumptions on IPP

portfolio mix for

2018/19:

• DOE Peaker

projects –

contractual

assumptions

• REIPP - seven bid

windows (bid

window 1, 2, 3,

3.5, 4, 4.51 and the

first bid window of

the Smalls

programme)

• Eskom WEPS

programme

(STPPP/MTPPP)

20.000

15.000

10.000

5.000

0

2018/19

424

17.828

2017/18

424

11.661

2016/17

4.235

7.227

2015/16

3.968

5.002

2014/15

3.005

3.017

2013/14

3.421

250

GWh

STPPP/MTPPP

Renewables

DOE Peakers

Note: 1) NERSA to review the assumption of up to BW 4,5 and will require an alignment to the DoE Ministers decision of up to BW 4

Average delivered coal costs for FY2018/19 is forecasted to be ~8% Page 77

14

• Consists of ex-mine cost of coal

(majority of cost) and transport cost

• Other costs, such as take or pay

payments and laboratory fees,

comprise about 2%.

• The average increase in FY2018/19

is 8%.

- The increase in long term cost

plus coal is 8%,

- long term fixed price coal is

14%,

- and short/medium term coal is

8%.

335

58

370342

5156

393 398

+5%

2016/17 2018/19

430

9

2017/18

Transport Ex-mine Other*

Planned average delivered coal costs

(R/t)

Change 1% 8%

Operating Costs increase by average of 7.3% over the period Page 88

15

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

declining staff complement

• O&M costs escalate by CAGR of 7.3% after normalising for once off transactions

• 2019 Opex – Employee benefit of R28.3bn (46%); Maintenance of R17.7bn (29%);

Other opex of R15.8bn (25%)

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

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

7.3%

2018/19 2012/13

R’m

2013/14

Employee benefits

Operations & Maintenance

4.9%

Employee benefit costs will escalate by 5% to FY2018/19 Page 93

16

• 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 payroll

& non-payroll expenses (indirect costs such as

training and 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

Nu

mb

er

Staff complement Employee benefits

Macroeconomic impacts of alternative scenarios to meet Eskom’s five-year revenue requirement – Deloitte Page 118

17

• Annual tariff increase of 19% is expected to have a slightly negative impact on GDP and employment

growth relative to the baseline scenario (tariffs rise by 8% a year and government borrows shortfall).

• Eg, under 19% tariff scenario (1B),

• GDP forecast to expand at average rate of 2.0% y/y, 0.3 percentage points lower than 2.3% y/y

growth forecast in baseline (BAU1).

• Total employment is expected to grow at average rate of 0.9% y/y under 19% tariff increase

compared to 1.2% y/y in BAU1. This implies that under a 19% tariff increase scenario, 137000

fewer jobs will be created and sustained annually over period 2017 to 2021, relative to BAU1.

0.0

1.0

2.0

3.0

4.0

201

2

201

4

201

6

201

8

202

0

202

2

202

4

202

6

202

8

203

0

y/y

%

Real GDP growth

1A: 13%, debt

1B: 19%, tariff

BAU2: 8%, downgrade

3A: 8%, VAT

BAU1: 8%, debt

The impact of the 5 scenarios were modelled and the outcomes are illustrated below

0.0%

0.2%

0.4%

0.6%

0.8%

1.0%

1.2%

1.4%

1.6%

1.8%

20

16

20

18

20

20

20

22

20

24

20

26

20

28

20

30G

row

th in

to

tal e

mp

loym

ent

(y/y

%)

Employment growth

Back-up slides

Eskom’s revenue application is completed within the legislative and NERSA’s regulatory framework Page 15

19

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

Potential macroeconomic, environmental, and social consequences of energy subsidies Page 121

• Energy subsidies crowd-out growth-enhancing or pro-poor public spending. such as on social welfare, health, and education) and place an unnecessary burden on public finances. Energy subsidies (unless specifically targeted) are a poor instrument for distributing wealth relative to other types of public spending.

• Energy subsidies discourage investment in the energy sector and can precipitate supply- crises. Energy subsidies artificially depress the price of energy which results in lower profits for producers or outright loses. This makes it difficult for state-owned enterprises to sustainably expand production and removes the incentive for private sector investment. The result is often an underinvestment in energy capacity by both the public and private sector that results in an energy supply crisis which in turn hampers economic growth. These effects have been felt in SA.

• Energy subsidies create harmful market distortions. By keeping the cost of energy artificially low, they promote investment in capital-intensive and energy-intensive industries at the expense of more labour-intensive and employment generating sectors.

• Energy subsidies stimulate demand, encourage the inefficient use of energy and unnecessary pollution. Subsidies on the consumption of energy derived from fossil fuels leads to the wasteful consumption of energy and generate unnecessary pollution. Subsidies on fossil-fuel derived energy also reduces the incentive for firms and households to invest in alternative more sustainable forms of energy.

• Energy subsidies have distributional impacts. Energy subsidies tend to disproportionately benefit higher-income households who consume far more energy than lower income groups. Energy subsidies directed at large industrial consumers of energy benefit the shareholders of these firms at the expense of the average citizen.

20