Eskom MYPD4 Revenue Application Focus on Regulatory Asset … · 2019-12-13 · Duvha u3 and...

Eskom MYPD4

Revenue Application

Focus on

Regulatory Asset Base,

Capital Expenditure,

Network Business

Nersa Public Hearings

Mbombela

25 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

Regulatory Asset Base (RAB)

The asset valuation is in compliance with the MYPD methodology

Outcome of the valuation of assets as at 31 March 2016

EXTRACT OF THE

MYPD

METHODOLOGY

Revaluation of existing Regulatory Asset Base

• Revaluation of the existing RAB

undertaken by independent entity

• Is based on benchmarks of similar plant

constructed globally under equitable

conditions

• Is not a factor of Eskom’s actual costs,

Eskom projections, Eskom’s overrruns

• Replacement costs are depreciated in

accordance with the age of the plant

• Replacement cost new (RCN) refers to the

cost if the plant were to be replaced with a

new plant

• Depreciated Replacement Cost (DRC) –

replacement costs are adjusted for ages of

plants to arrive at DRC values

Regulatory Asset Base determined in accordance with NERSA MYPD Methodology

Response to MYPD methodology requirements Compliance to MYPD

methodology requirements

Eskom has undertaken independent valuation exercise for

existing RAB as at 31 March 2016. The value of the RAB has

been rolled forward with assumptions on CPI for value during

application period

Yes

Have included the capex costs and owner development costs –

which are capitalised

Yes

RAB includes capex related to generation, transmission and

distribution of electricity

Yes

Costs have been capitalised, included in RAB, IDC not included Yes

Connections funded by customers excluded Yes

Working capital such as coal stockpiles included Yes

All RAB capex will be subjected to prudency reviews through the

RCA process

Yes

Composition of Regulatory Asset Base

7

-200 000

0

200 000

400 000

600 000

800 000

1 000 000

1 200 000

1 400 000

1 600 000

FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024

Ran

d m

illi

on

Assets funded upfront Asset purchases Working capital

WUC Completed assets post 2016 Fixed assets as per valuation

8

Reconciliation of the asset valuation of R853bn in FY2016 to

the overall average RAB value of R1.3 trillion in FY2020

Items Rand (bn)

Asset Valuation as at 31 March 2016 854

Add: Inflation indexing to 2020 193

Less: Depreciation to 2020 - 214

Total for Valuated assets in FY2020 833

Add: Completed assets post 2016 251

Add: WUC balance in FY2020 177

Add: Working capital balance in FY2020 44

Add: Asset purchases balance in FY 2020 2

Less: Assets funded upfront -44

Add: Adjustment from annual closing balance to

average closing balance

5

TOTAL RAB in FY2020 (average) 1 268

Units in Extended Inoperability and Reserve Storage

9

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 the merit order (have the highest unit costs of production) and are thus not expected to

be required to operate to meet demand as availability of Eskom’s fleet improves and new capacity

comes on line.

• Approaching their planning end of life.

• Ten units of these stations have reached stage where significant investment (mostly Capex) is

required for them to continue operating. Have thus been shut down and placed in Reserve Storage.

• The remaining units at these 3 stations (14) will be reaching dead stop dates, where significant

investment will be required for them to continue operating, in next 4 years. They will also be shut

down and placed in Reserve Storage. 2 units are only expected to be shut down after MYPD4

period.

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

on anticipated shutdown date.

However, these plans are based on various assumptions so should the system require these units in

future, they will be returned to service and changes will be reflected in an RCA and or in future MYPDs.

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

10

Station Unit Capacity Shutdown

date

Duvha u3 575 MW 30/03/2014

Hendrina u3 185 MW 22/05/2018

Hendrina u1 160 MW 01/12/2017

Komati u1 91 MW 01/12/2017

Komati u2 91 MW 12/08/2018

Komati u3 84 MW 30/08/2018

Komati u6 114 MW 21/12/2017

Komati u8 114 MW 22/06/2018

Hendrina u9 185 MW 29/09/2018

Grootvlei u4 190 MW 22/09/2017



7 units from Grootvlei and Komati reach dead-stop dates in the next 4 years and expected to be shut down and placed in Reserve Storage

11

Station Unit Capacity Dead-stop

date




Komati u4 91 MW 08/09/2021

Komati u5 91 MW 03/04/2019

Komati u7 91 MW 28/05/2019

Komati u9 114 MW 05/07/2022

Key insights

Dead-stop dates are determined from allowable turbine operating hours before complete

refurbishment is required.

For some Units, additional statutory works on pressure vessels are also required prior to

the turbine dead-stop dates.

Komati u9 expected to be shut down after MYPD4 period.

7 units from Hendrina reach their dead-stop dates in the next 4 years and are expected to be shut down and placed in Reserve Storage

12

Station Unit Capacity Dead-stop

date

Hendrina u2 190 MW 08/11/2022

Hendrina u4 190 MW 04/08/2021

Hendrina u5 190 MW 12/10/2021

Hendrina u6 190 MW 01/03/2022

Hendrina u7 158 MW 23/01/2021

Hendrina u8 190 MW 18/06/2019

Hendrina u10 185 MW 13/07/2020

Key insights

Dead-stop dates determined from allowable turbine operating hours before

complete refurbishment is required.

For some Units, additional statutory works on pressure vessels also required prior to

turbine dead-stop dates.

Hendrina u2 expected to be shut down after MYPD4 period.

Impact of excluding units in extended inoperability

and reserve storage on RAB

13

Decrease in the Average

RAB (R'million)

2019/20 2020/21 2021/22

Application 1 268 310 1 336 120 1 401 506

Revised RAB 1248 018 1 311 056 1 374 448

Decrease in the RAB (20 293) ( 25 064) (27 058)

Return on assets is kept at -1.32%, -0.21% and 1.45% as per MYPD 4 application

Above change in RAB translates into following changes in revenue requirement

Impact on the revenue

requirement (R’million)

2019/20 2020/21 2021/22

Depreciation (2 760) (3 327) (4 025)

Return on assets 267 52 (392)

Change in the revenue

requirement

(2 493) (3 275) (4 417)

Removing assets in extended inoperability and reserve storage from RAB results in:

14

Conclusion on Regulatory Asset base

The regulatory asset base was determined in accordance with MYPD methodology.

Whilst all units in extended inoperability and reserve storage have been excluded

from RAB, it is important to note that should the system require these units in future,

they will be returned to service and changes will be reflected in an RCA and or in

future MYPDs.

The units that reach shutdown date in MYPD 3 window (i.e. FY2014 to FY2018) are

not factored into MYPD 3 RCA’s as MYPD methodology only allows for capital

expenditure variances in computation of CECA. These units are: Duvha u3,

Hendrina u1, Komati u1 and 6, Grootvlei u4 and 5

Generation New Build Capex

Generation Capital Requirement FY20-22

1. New build and major projects:

Construction of Medupi and Kusile (coal power

stations) and other major projects including

environmental projects.

2. Technical plan projects:

Generating plant requires large initial

investment and significant further expenditure

to continue operations over its intended life.

The technical plan projects reflect the

modifications and improvements that may be

required to address any changes in plant

condition, operation, capacity, legislative

requirements (safety, health and environment),

primary energy supply and operational

lifespan.

3. Outages:

There are numerous cyclical maintenance

interventions required on a power station. If an

activity is required at least twice in the life of a

station and will require plant shutdown, it is

referred to as an outage.

4. Future Fuel

Coal future fuel is the capital requirement for

the cost plus coal mines.

Nuclear future fuel is the nuclear fuel purchase

costs for Koeberg

16

14 150

82 148

532

23 230

8 073

New Build projects

Renewables

Technical plan projects

Outages

Equipment&vehicles

Future fuel

Total Generation Capex

(Rm)

Application

2019/20

Application

2020/21

Application

2021/22

New build and major

projects

35 557 23 732 22 859

Outage capex 7 340 7 890 8 000

Technical plan capex 4 847 4 919 4 384

Renewables 11 39 23

Future fuel 1 597 3 301 3 175

Nuclear future fuel 605 1 186 665

Coal future fuel 992 2 115 2 510

Asset purchases 169 178 185

Total Gx License Capex-

NERSA

49 521 40 058 38 627

Geographical overview of current New Build Programme

17

Limpopo

Kwa-Zulu Natal

Mpumalanga

MEDUPI POWER STATION PROJECTDESCRIPTION: Supercritical, coal-fired power stationLOCATION: Lephalale, LimpopoCAPACITY: 4,764MW (6 x 794MW)PROJECT COST (P80): R145 bn (excl. IDC)

KUSILE POWER STATION PROJECTDESCRIPTION: Supercritical, coal-fired power station

LOCATION: Witbank, MpumalangaCAPACITY: 4,800MW (6 x 800MW)PROJECT COST (P80): R161.4 bn (excl. IDC)

INGULA PUMPED STORAGE SCHEME DESCRIPTION: Pumped Storage SchemeLOCATION: Drakensberg mountain range, near Ladysmith CAPACITY: 4 X 333 MW Units = 1,332 MWPROJECT COST (P80): R29.8bn (excl. IDC)

Gourikwa OCGT(746 MW)

Western Cape

Northern Cape

Eastern Cape

North West

• Majuba Rail Project (68km railway)• Generation Coal and Emission Projects• Majuba Silo Recovery• Return to Service Programme (3,741 MW)

Wind Facility Hydro PowerCoal-Fired Power Plant Rail Gas Power

Ankerlig OCGT(1,338MW)

TRANSMISSION (Power Delivery) ProjectsPROJECT COST: R65.2 billion (excl. IDC)

Free State

PDP Transmission Lines

• Koeberg Steam Generator Replacement Project

• Ankerlig Transmission Koeberg Second Supply (ATKSS)

• Open Cycle Gas Turbine (OCGT) dual fuel conversion

• Koeberg Unit 2 improved efficiency (30MW)

Sere Wind Facility(100MW)

Medupi Flue Gas Desulphurisation (FGD) retrofit project

Battery Storage Phase 1: 800MWhPhase 2: 640MWh

Completed project

https://www.google.co.za/url?sa=i&rct=j&q=&esrc=s&source=images&cd=&cad=rja&uact=8&ved=2ahUKEwiv6L6W_sTeAhVMyxoKHSavA3wQjRx6BAgBEAU&url=https://www.vexels.com/png-svg/preview/129344/battery-icon&psig=AOvVaw3CdBUpcSBIxZdhYr01Tr6v&ust=1541773006564637





25-Jan-19 18

17 67034 390

2 5253 580 3 790 2 090 2 435 2 300 540

37 440

Inceptionto Mar-11

Mar-12 Mar-13 Mar-14 Mar-15 Mar-16 Mar-17 Mar-18 Mar-19 Total todate

FY 18/19 target: 1 040 MVA

Substation capacity commissioned, MVA

3 268 7 470631,0

787,0 811,0 319,0 346,0 585,4 722,3 334,0

7 804FY 18/19target: 595.8km

Generation capacity commissioned, MW

5 221 535261 120 100 794

1 332

2 387 0

10 750

• To date, the construction work that has been completed has added ~ 10 750MW of capacity, ~ 7 804km oftransmission network and ~ 37 440 of MVAs

FY 18/19 target: 800 MW

2 510

Transmission and other lines built, km

A large amount of construction work has been

completed from the start of the build programme in

2005 to date…

9 312

7 804

1 508

Target Completed Remaining

Remaining construction work over the next five years until financial year 2024

19

17 132

10 750

6 382


MVAs Commissioned

Substations

Km Lines builtTransmission

MWs Commissioned

Megawatts

1 Target refers to the target of the total capacity expansion programme

FY

20

18

–F

Y 2

02

3

(Me

du

pi, K

usile

)

FY

20

18

–F

Y 2

02

4

FY

20

18

–F

Y 2

02

4

• Once completed by 2023FY, Eskom’s capacity

expansion programme will increase generation

capacity by 17,132MW, transmission lines by

9,312km and substation capacity by 42,850MVA.

• This will enable Eskom to provide security of

electricity supply to South African homes and

businesses, powering economic expansion and

extending electricity to millions of households

who currently rely on other fuel sources for

domestic cooking and heating.

42 850

37 440

5 410


A single Engineer, Procure, Construct (EPC) contract (Turnkey)

10 to 12 EPC-type contracts

Multiple packages - 30 to 40 furnish and erect packages

Multiple contracts involving 60 to 70 packages

Four contracting strategies were considered for the execution of Medupi and Kusile, ultimately pursuing a multiple packages strategy

20

• Most of the objectives were best met with multiple packages, but it also determined that the personnelresource constraints would limit the number of packages

• Nominally, the 30 to 40 package scenario was chosen

Eskom resources Meet project objectivesContracting Strategies

Least

Most

Least

Most

• Minimize life-cycle cost

• Maximize reliability

• Generate competition within construction, equipment and material markets

• Compress schedule for earlier 1st unit CO date

• Fully use available Eskom engineering personnel and other resources

• Meet/exceed BEE goals

• Maximize benefits to the SA economy

• Develop contracting model for future projects

• Shifting/managing risk

• Eskom’s depleted resource base having experience implementing generation projects of this type and magnitude

• Lack of resource depth in the South African construction and equipment supply markets that service power plant projects

• Heavy workload worldwide in the Power Industry

• Complexity of global economy and financial markets

The projects created risk-adjusted schedules to provide a more realistic view on schedule and funding, including our Priority 1 risks

21

We continue to monitor and manage our Priority 1 risks…

Stability atConstruction Sites

Partnership Agreement driven together with the external and internal stability plan

Strict monitoring of compliances by contractors and employees to agreed processes

Visibility of Employee Relations (ER) personnel on the ground External Stakeholder engagement Skills development and transfer programmes Internal and External stability plans in place

Inadequate Capacity, Productivity and / or Competency amongst Contractors

Productivity improvement initiatives, including focused contractors management

Increased on site contract management resources to improve associated processes such as claims management and contract oversight

Increased Technical Oversight Monitoring & Assurance being instituted throughout projects

Risk-adjusted schedules developed to cater for the major risks that the projects are currently facing.

It is based on the current contractor performance and risk provision for risks outside the control of the project (e.g. Weather, Political situation like National Elections), based on historical events.

A P80 schedule is provided when cost certainty is critical, the portfolio is not capital constrained, and the portfolio typically comes in under budget.

P80 refers to a 80% chance of these risks materializing.

P80 Schedule

Contractors’ non-financial viability

Obtain market/business/project intelligence on the identified high risk contracted companies.

Assess industry economic trends and perform financial analysis on the high risk companies.

Play monitoring and oversight role to identify potential related issues and assisting with the necessary mitigating actions to reduce/eliminate the impact on the business.

Inability to execute the Capital Programme

Eskom Project Life Cycle Model (PLCM) Project development readiness assessment (PDRA) Investment structures (committees) Project development and design framework / standards

Medupi Project

22

The Medupi Project near Lephalale in the Limpopo

Province is a green-fields coal-fired power plant

comprising of six units rated in total at 4 764MW

installed capacity.

Medupi incorporates super critical technology with its

boilers and turbines, which is able to operate at higher

temperatures and pressures than Eskom’s previous

generation plant, and most importantly operates with

greater efficiency, resulting in better use of natural

resources, for example, water and coal, and will have

improved environmental performance. The plant uses

direct dry-cooling due to the water scarcity in the area. In

this process, all the water will be re-used in the electricity

generation process.

Once completed, the power station will be the fourth

largest coal-fired plant and the largest dry-cooled

power station in the world. The planned operational life

of the power station is 50 years.

Unit Six (6) achieved commercial operation on the 23

August 2015, Unit Five (5) on 3 April 2017 and Unit Four

(4) on 28 Nov 2017.

PROJECT Unit

MYPD 4

Application

CO Date

Latest

Forecast

CO Date

Medupi Unit 3 31-Oct-18 30-Apr-19

Medupi Unit 2 31-May-19 30-Apr-19

Medupi Unit 1 31-May-20 30-Nov-19

Medupi

Percentage completion as at December 2018

Unit 1 Overall progress 84.54%






23

Kusile Project is a greenfield coal fired power plant

project comprising 6 units with a total installed

capacity of 4 800 MW. The Kusile site is about 1 355

hectares in size, and is situated on the Hartbeesfontein

and Klipfontein farms in the Nkangala District of the

Mpumalanga Province.

Kusile will be the first power station in South Africa to

have Flue Gas Desulphurization (FGD) installed. FGD

is the current state of the art technology used to remove

oxides of sulphur (SOx), e.g. sulphur dioxide (SO2), from

the exhaust flue gases in power plants that burn coal or

oil. This technology is fitted as an atmospheric emission

abatement technology, in line with current international

practice, to ensure compliance with air quality standards,

especially since the power station located in a priority

airshed.

Unit One (1) achieved commercial operation on the 30

August 2017.

PROJECT Unit

MYPD 4

Application

CO Date

Latest

Forecast

CO Date

Kusile Unit 2 31-Oct-18 31-May-19

Kusile Unit 3 31-Aug-19 31-Dec-19

Kusile Unit 4 31-Dec-20 31-Dec-20

Kusile Unit 5 31-Aug-21 31-Aug-21

Kusile Unit 6 30-Jun-22 30-Jun-22

Kusile

Percentage completion as at December 2018







Kusile Project

Comparing costs of constructing different power plants is challenging, due to difference in size, construction time, inflation, technology, location, etc.

Overnight cost is an internationally accepted method used to compare the construction cost of different power plants on a common basis.

Includes costs associated with civils and construction, mechanical equipment, electrical work, control and instrumentation, project management and

development. Interest capitalised to the project is excluded

Is defined as the cost incurred if a power plant could be built overnight

Cost is expressed in terms of USD cost per kilowatt of installed capacity converted to the same base year, thereby enabling a like-for-like comparison. To ensure

like-for-like comparisons, international benchmarks are adjusted to a common base.

Efficiency of Eskom Generation New Build is best measured by overnight cost of construction

24

25

Power Station unit technology type was

either supercritical or ultra-supercritical

The size of the units were between

800 and 900 MW

Sufficient data was available to

make a comparison

The technology used was consistent

throughout the build (all units were

the same technology type)

Only 3 of the 22 power stations built in the same period

allowed a fair comparison with Medupi Power Station

Units constructed in the same period (2006-2015)

as Medupi unit 1 and that meet five criteria were

considered

Criteria include:

A set of four criteria was used to evaluate projects

constructed in the same period for comparison

• Basic (base) value of the project; dictated in the main by scope and price in the market.

• It is possible to include claims in this component.

• Inflationary adjustment to the basic plant cost and is applicable to the variable portion of the basic plant cost and can be in a local or foreign currency.

• CPA adjustments are driven by market volatility such as general increases in labour cost, steel prices, material cost, fuel cost etc.

• Positive or negative cost adjustment of the foreign portion of a contract.

• Calculated as the movement in cost from the tender/contract exchange rate to the spot cover rate when the foreign currency exposure is hedged and the commitment finally paid.

• Forward premium that is payable when the foreign component of a contract is hedged against foreign currency fluctuations.

• This premium is determined by adjusting the spot cover rate with the interest rate differential between SA and the foreign country. The foreign currency fluctuation risk is mitigated through hedging once the contracts are placed.

• For unplaced contracts with foreign components, the business remains exposed to currency fluctuations.

• Allocation of interest to a project during the construction phase.

• The interest allocation is calculated by applying a pre-determined interest percentage, based on Eskom’s gearing, on the project inception to date balance until the project is transferred to commercial operation.

• Cost to the owner to establish and manage the project.

• These include project management, project engineering and the utilisation of resources to oversee the project.

• Risk allowance for unknown future costs.

• Contingency forecasts are done by project management based on the perceived risk in the project.

RATE OF EXCHANGE ADJUSTMENT COST OF COVER

INTEREST DURING CONSTRUCTION (IDC)

CONTINGENCY PROVISIONOWNERS DEVELOPMENT COST

(ODC)DESIGNS

ESCALATION OR COST PRICE

ADJUSTMENT

Total Project Cost Components

26

The Medupi overnight cost are within the range of the international benchmarks provided by Lazard

and the International Energy Agency (IEA). Medupi is higher than the benchmarks for EPRI and the

World Bank. (For World Bank it is not clear if the benchmark value include or exclude FGD)27

Benchmark Medupi overnight cost of

construction excluding FGD

The Kusile overnight cost are within the range of the international benchmarks provided by Lazard and

EPRI. Kusile is higher than the benchmarks for IEA & World Bank. (For World Bank it is not clear if the

benchmark value include or exclude FGD)

28

Kusile overnight cost of construction including

FGD

Levelised cost evaluates overall cost of electricityincluding financing and fuel cost – challenge to obtain accurate benchmarks

Ad-

vantage

• Good way to evaluate the overall unit cost of

electricity from a particular type of a plant and

is thus useful to compare the economic

feasibility of different technologies

Disad-

vantage

• Direct comparisons of electricity cost per unit

are dependent on assumptions about costs,

technical performance and electricity

production over the full operational life cycle

Desc-

ription

• Calculates the present-value cost of energy

production and includes capital cost, as well

as fuel and all fixed and variable operating and

maintenance costs expressed in USD/ MWh.

Interest rates1/cost of capital, inflation and

taxation are also taken into account

Levelised Cost of Electricity (LCOE)

• Varying assumptions (technology, plant design, base year, exchange rate, etc.) and commercially sensitive numbers

• Changing/Increasing costs (rising demand for equipment; movement in commodity prices

• Contextual issues (localisation, supply chain, economic cycles/ para-meters, economies of scale)

• Life cycle operational costs, technical performance and electricity production required for calculation of LCOE (in addition to total capital cost /investment)

Challenge to obtain

consistent and accurate

benchmarks

1 Taken into account through the discount rate

The projected levelised cost for Medupi and Kusileare below available international benchmarks –comparability is a challenge

Projected levelised cost comparison, USD/MWh, as at 2016 values

KusileMedupi

Lazard

IEA

P80

Min Max

9586

EPRI

Projected levelised costs for Medupi and Kusile are below available international benchmarks.

Levelised cost numbers were not provided in the World Bank report.

Min Max

7871

Min Max

15065

Min Max

15065

Min Max

10776

Min Max

10776

Approach taken in comparable projects shows investment in front end engineering and design reduces execution time and increases schedule certainty

Medupi

(800MWx 6)

Concept to

1st Unit CO

Tata Mundra

PS India

(800MW x 5)

Concept to

1st Unit CO

Project schedule

and estimates

change resulting

in loss of

confidence

Repeatability

and forward

planning

produced better

cost and

schedule

certainty

FEED

start

Construction

start1st unit

CO

1 yr development Est. 8.5 yrs for construction

2006 2007 2015

FEED

start

Construction

start

1st unit

CO

3 yrs development 4 yrs for construction

Opole PS,

Poland

(900MW x 2)

Concept to

1st Unit CO

Forward

planning

produced better

cost and

schedule

certainty

FEED

start

Construction

start

1st unit

CO

5 yrs development 4.5 yrs for construction

GKM AG,

Germany

(900MW x 1)

Concept to

1st Unit CO

Forward

planning

produced better

cost and

schedule

certainty

FEED

start

Construction

start

1st unit

CO

4 yrs development 6 yrs for construction

Tech.

Type

Super

critical

Super

critical

Rapid

development

with shortcuts

taken in design

and

engineering

inevitably

cause

uncertainty,

design

changes,

integration

issues and

accompanying

delay and cost

escalation

Cost and

schedule

confidence

can be

achieved with

sufficient

development

time

Ultra-

super

critical

Super

critical

and

ultra-

super

critical

The programme is continuing to have a significant impact on local industry, skills, jobs, infrastructure and regional development

A large share of Medupi, Kusile

and Ingula spend goes into

the economy

(*contribution of 0,72% to

national GDP)

The build programme has fueled demand

for relevant graduates and artisans and have grown SA’s wide

required skill base of

engineers, artisans, R&D

and project management

experts

Across Medupi, Kusile, Ingula

and Power Delivery

Projects new employment opportunitieshave touched

the lives of thousands of

people

> 42 000 total employees and

contractors employed at

peak of construction

Medupi, Kusile & Ingula

supports the national & local infrastructure

E.g. roads & maintenance, trains, water,

catering & workforce supplies,

hotels, housing, water,

sanitation, local transport, social

facilities

Each project will impact the

local towns through local

spend & investment

Lephalale (Medupi) – 95%

Delmas (Kusile) – 25%

Ladysmith (Ingula) – 7%

Local

ContentLocal Skills

Development Jobs InfrastructureRegional

Development

Sufficient Front-end engineering and

development (FEED)

Funding and stakeholder plans

Governance and internal processes

Less reliance on the contractors

Additional owner’s oversight

Additional owner’s supervisory requirements

Adopt international benchmarked project

management methodologies,

processes & systems

Suitably capacitated contract management

capability

Established monitoring, oversight and assurance

function

Adequate project pipeline to prevent the

loss of skills and capabilities

Engage international asset creation

community

Improved Labour Management

33

Key lessons learned from the New Build

Programme

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Eskom Emission Reduction Plan and associated costs

Legislation

• 1 April 2010, Minimum Emission Standards (MES) were published in terms of the

National Environmental Management: Air Quality Act (NEM:AQA)

• Standards took effect on 1 April 2015 (‘existing plant limits’) and 1 April 2020 (‘new

plant limits’). Existing plants to comply with new plant limits by 1 April 2020.

• Eskom was required to reduce Sulphur dioxide, particulate matter and Nitrous oxides

by 2015 and now stricter limits by 2020.

• Eskom has an emission reduction plan which is based on a phased approach which focuses on the control of particulate emissions.

• Given the high cost to control sulphur dioxide and taking into consideration the associated health impact, a cost benefit analysis and the remaining life of plant Eskom is proposing that only Medupi is retrofitted with FGD. Kusile is being commissioned with FGD.

• Eskom will submit an application for postponement, suspension or alternate limits according to the status of each power station by 31 March 2019. (two rounds of public participation took place in 2018)

35

Eskom Emission Reduction Plan

36

Power Station Retrofit 15/16 16/17 17/18 18/19 19/20 20/21 21/22 22/23 23/24 24/25 25/26 26/27 27/28 28/29 29/30 50-year life

Kusile Fully compliant

Medupi Flue Gas Desulphurisation 2064-

Majuba Low Nox Burners 2046-2051

Kendal HFPS +ESP upgrade 2038-2043

Kendal FGD-Pilot 2038-2043

Matimba FGD-Pilot 2037-2041

Kendal FGD 2038-2043

Matimba FGD 2037-2041

Matimba HFPS +ESP upgrade 2037-2041

Lethabo HFT +ESP / SO3 upgrade 2035-2040

Tutuka FFP 2035-2040

Tutuka LNB 2035-2040

Duvha (4 & 6) HFT +ESP upgrade 2030-2034

Duvha NH3 2030-2035

Matla HFT +ESP upgrade 2029-2033

Matla LNB D 2029-2033

Kriel HFPS +ESP upgrade D D D D 2026-2029

Arnot FFP installed D D D D D 2021-2029

Hendrina FFP installed SD SD SD SD SD D D D D 2020-2026

Camden FFP installed, LNB complete D D D D 2020-2023

Grootvlei FFP complete SD SD SD SD SD D D D D 2025-2028

Komati No commitments SD SD SD D D D D 2024-2028

Legend

Completed projects

Future projects

0% production 0%

Shut down/Decomissioning SD/D

Requested suspension

Legislation: Water and Ashing Facilities

• The National Waste Management Act 2008 and associated regulations require lining

for new or extended ashing facilities.

• Several power stations are required to extend or building new ashing facilities.

• Eskom has carried our several studies to ensure the most appropriate and cost

efficient liners are authorised by the Department of Environmental Affairs and

Department of Water Affairs. Decisions are expected over the next 6 – 12 months.

• Several water management projects must be implemented in accordance with the

conditions of Water Use Licenses issued to power stations.

37

Generation Emission project costs

38

Costs are based on Eskom’s proposed postponement application, if not approved the costs would

increase significantly due to the requirement to install flue gas desulphurisation at 7 power

stations@ R 20 – 30 billion per plant.

R million excl COC & IDC2017/18

Acual2018/19 2019/20 2020/21 2021/22 2022/23 2023/24

Total

19 - 23

Technical Plan Environmental Projects - Gx 14.5 327.0 544.8 1 203.9 786.9 48.0 - 2 910.6

Technical Plan Environmental Projects - New Build 943.6 1 889.9 2 949.2 2 071.7 366.0 2.0 - 7 278.8

Emissions Projects - New Build 270.1 904.5 4 267.8 6 788.2 13 092.7 14 509.8 17 743.3 39 563.0

TOTAL ENVIRONMENTAL PROJECTS 1 228.2 3 121.4 7 761.8 10 063.8 14 245.6 14 559.7 17 743.3 49 752.3

Transmission Licensee

Context & Key Aspects

• This revenue application is being made for a three year period (2019/20 –2021/22).

• This revenue application is aligned with the NERSA MYPD methodology, with aphasing-in of return on assets being applied

• It is recognized that there is a need for cost containment initiatives to limittariff impacts to customers

• Key aspects of the Transmission Revenue application includes:

• Operational Expenditure average annual escalation contained to 1.1%per annum relative to 2017/18 actual expenditure

• Capital investments of R 29.3 bn are planned for the MYPD4 period toenable new generation and customer connections and meet sustainabilityand compliance requirements

40

Transmission’s position in the electricity value chain

41

Transmission Licensee Scope includes

• Transmission Network Service Provider

• System Operator

• Grid Planning

Transmission system reliability performance

So what is a System Minute?

MW load lost x Duration in min

System annual peak in MW

System Minutes < 1: measures severity of smaller interruptions

No of Major Incidents: counts number of large interruptions of ≥1SM

42

Therefore, 1 System Minute lost = loss of entire Eskom system for 1

minute at the time of system peak

Primary KPI performance trends

Performance Improvement trends in recent years are attributed to system

strengthening (N-1), reduced number of line faults, effective maintenance execution

and human performance.

System Minutes < 1 Major Incidents

43

Transmission network service provider

Apollo is the only

HVDC transmission

scheme operational

in the country,

enabling the import of

power from

Mozambique

The Transmission

Grid consists of 168

substations and

±32 000km of

transmission lines

Maintenance is

planned based on

Asset Management

principles utilizing

specialized

equipment and skills

Committed towards

Safety, Environmental

management and

continuous

improvement

This includes

Engineering &

Project

Management to

renew and expand

the Grid

We operate,

maintain and

restore the

Transmission

Network on a

national basis

Asset age profile - the need for sustained high levels of maintenance and asset replacement

45

System Operator – balancing supply and demand

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

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

• In terms of the Scheduling and Dispatch Rules, 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 and constraints

• Emergency resources such as gas turbines are scheduled to manage system emergencies and Ancillary services reserves are optimised in order to minimize the total cost of production

46

47

System Operator - meeting demand on a typical day

Coal

HVDC

PV

Nuclear

PS &

HydroCSP

Wind

Ramp up Ramp down

• The bulk of demand is met by coal, nuclear and HVDC imports. Coal provides the primary capability to ramp up and down during the daily load cycle.

• Pumped Storage, Hydro & OCGT’s are mainly utilized to manage peak demand

• Renewable generators continue to make a valuable contribution throughout the day

Wind generation variability over system peak – emerging trend (2017 and 2018)

48

High load factors over evening peaks in summer can be observed, dropping during the

winter months

Depreciation

The MYPD methodology was applied through the relevant allowable revenue formula

49

++=

Operating


Return on

AssetsRevenue

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

𝐴𝑅= (𝑅𝐴𝐵×𝑊𝐴𝐶𝐶)+𝐸+𝐷±𝑆𝑄𝐼+𝐿&𝑇±𝑅𝐶𝐴

Depreciation

Review of planned operating expenditure

50

++=

Operating


Return on

AssetsRevenue


Transmission operating expenditure

includes:

• Employee Benefit Costs

• Maintenance Costs

• Other operating costs

• Corporate Overheads

Transmission operating expenditure –average annual escalation of 1.1%

51

World Bank report methodology - incorrect conclusions on Tx & Dx optimal staffing levels

52

Extract - 2016

World Bank ReportExtract - 2015 Eskom

Integrated Report

• A benchmark methodology based solely on number of customers per employee is flawed

• The WB Report conclusion that optimal Eskom Transmission and Distribution (T&D)

staffing should be 9 596 is therefore erroneous

• Based on WB report data, Eskom T&D’s 6.24 employees / 100 km of line compares

favorably with benchmark cluster average of 7.22

53

Employee expenditure (R’m) and Number

of employeesThe drivers for employee benefit cost

are the following:

• Employee benefit expenses consist

of both direct & indirect expenses

(such as training & development)

and are nett of capitalization

• A driver for employee benefit cost

increases is the outcome of

negotiations concluded with Trade

Unions in 2018

The workforce will reduce over the MYPD4 period whilst balancing operational requirements and

a growth in the Grid asset base

1 443 1 538 1 520 1 573

1 644

2 182

1 938 1 851 1 820 1 802

0

500

1 000

1 500

2 000

2 500

2017/18… 2018/19… 2019/20 2020/21 2021/22

Employee benefitcost

The application considered the

tariff impact and incorporated

additional efficiency improvements

resulting in Employee Benefit costs

escalating by 3.3% on average per

annum over the 5 year period

MYPD 4

Transmission operating expenditure -employee benefit costs escalate by 3.3% p.a.

54

Transmission Maintenance cost (R’m) The key drivers for the maintenance

expenditure are:

• Increased asset base with

associated increased operating,

inspection and maintenance

workload

• A high percentage of assets are

beyond mid-life requiring increased

maintenance

• Safe operation of network with

minimum impact to environment

The escalation is contained to a moderate inflation based increase of 5.5% p.a.

Notwithstanding the increased

asset base, the revenue application

pursued efficiency improvements to

contain the escalation.

MYPD 4

729 788

827 869

902

0

100

200

300

400

500

600

700

800

900

1 000

2017/18Actual

2018/19Proj

2019/20 2020/21 2021/22

Transmission operating expenditure –maintenance costs escalation contained to 5.5% p.a.

Transmission other operating costs

55

Other operating costs (R’m) The main contributors to Other

operating costs are the following:

• The main contributors to Other

operating costs includes:

o Insurance premiums (48%) –

Reduced premium proportioned to

Transmission

o Security cost - Guarding Services;

Access Control and patrols of

substation and national key points

(15%)

o Telecommunications – monitoring

and controlling of the network from

control centers (11%)

o Fleet and Travel cost – operational

transport cost (8%)

o Facilities and Leases – properties

rental/maintenance, utilities

rates/taxes (7%)

An average annual reduction of 3.3% is projected over the 5 year period

MYPD 4

626 617

535 556 570

0

100

200

300

400

500

600

700

800

900

1 000

2017/18Actual

2018/19Proj

2019/20 2020/21 2021/22

Depreciation

Review of planned capital expenditure

56

++=

Operating

expenditure

(incl R &D)

Return on

AssetsRevenue


• As per the MYPD 4 methodology, return on asset and depreciation (after assets are in commercial operation) has been included with the revenue application

• The following slides reviews planned Capital Expenditure over the MYPD4 period

Transmission Development Plan - planned capital investments

57

• The Transmission Development Plan (TDP) is published annually following consultation with NERSA, stakeholders and the public

• Public consultation was held on 26 October 2018

• The scope of the TDP includes planned capital investments in system strengthening, expansion, asset replacements, lands & rights and production equipment

• Planned capital expenditure conforms to the Grid Code investment criteria requirements

• Audits are conducted annually by NERSA to verify adherence

• A capital investment of R 29.4 bn is planned over the MYPD4 period

Transmission Development Plan - major projects planned for the period 2020 – 2029

•5858

Transmission Development Plan – planned capital expenditure of R 29.4bn over MYPD 4

• Primarily driven by reliability and strengthening requirements (+/- 54% of plan) as well as deep system strengthening for Generation and Customer connections (+/- 24% of plan)

• 12% of planned investments are for asset replacement / renewal

59

Asset replacement planning based on condition, criticality & risk

60

Plan Semi-constrained to

reflect bottle necks in the

Capital Plan value chain

• Starting point: assets identified

based on condition rolled up

per bay.

• Rolled up into substation

• Phased using criticality,

importance and impact

• Generated projects to cost and

enter into plan

In conclusion this application requires a balance between consumer interest & financial sustainability

• Eskom requires the recovery of efficient costs and reasonable return to be financially viable.

• There is a need for cost containment to limit tariff impacts on customers

• The Transmission Licensee revenue application for operational expenditure was contained well below inflation levels

• Planned capital investments are aligned with Grid Code compliance requirements and investment justification criteria

• Decisions with respect to return-on-asset and depreciation should consider Eskom’s cashflow requirements and ability to satisfy investor confidence on its ability to service such debts

61

Distribution Licensee

Distribution Licensee scope

63

The Licensee shall operate the Distribution System within the Licensed Area

of Supply subject to the provisions of the Act and the license conditions.

The Licensee shall provide a Network Service, Distribute and Supply

electricity within the Licensed Area of Supply.

The Licensee shall not discriminate between categories of Customers,

regarding access, tariff or prices, conditions of service or conditions of Supply,

except for objectively justifiable and identifiable differences approved by the

NERSA

Licencee’s position in the electricity value chain

64

Distribution is at the heart of Eskom’s customer interface, connecting new

customers and providing safe and reliable electricity to South Africans.

Distribution has connected more than 200 000 customers per annum to the

network during the past few years.

Licensee operating footprint

65

Provincial footprint

Licensee activities in providing a service to the customer

66

Wires Business

(Engineering/Network)

Network master planning

Network designing

Network Construction

Network Maintenance and

refurbishment

Network strengthening

Network Operating

Provincial stakeholder

management

Customer Service

Quotations

Connections

Debt management

Disconnections and reconnections

Availability and quality of

supply

Support energy losses

management

Outage Management

Residential

Traction

Agriculture

Commercial

Redistributors

Prepaid

Mining & Industrial

Develop & Market Products &

Services

Optimise Customer Interaction

Acquire Customers

Manage Revenue

Cycle

Network Asset

Creation

Manage Availability of Supply

Maintain Network

Value Chain

Application salient aspects

67

Operational expenditure is contained to 1% increase per annum.

Capital investments of R18.4bn to enable, capacity for future growth,

maintaining network performance and compliance requirements.

Optimise the workforce while maintaining the critical and scarce skill

requirement.

The allowable revenue in the application translates to a 15% annual

increase, with a phased-in return on assets

Key aspects of this revenue application are:

Allowable revenue applied

Depreciation

++=

Operating

expenditure(incl. IDM)

Return on AssetsRevenue

Allowable Revenue = (RAB X WACC) + E +D + IDM ± RCA

Allowable Revenue (R'millions) AR Formula2019/20

Application

2020/21

Application

2021/22

Application

Regulated Asset Base (RAB) RAB 111 391 116 895 123 063

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

Returns -1 466 -242 1 784

Expenditure E + 23 584 24 787 26 342

Depreciation D + 6 903 7 422 8 029

IDM I + 189 193 202

RCA RCA + 0 0 0

Total Allowable Revenue R'm 29 210 32 161 36 356

Based on the MYPD Methodology the total allowable revenue

is R97.7billion

68

Growth in network asset and customers with associated performance

69

0

5

10

15

20

25

FY2014 FY2017FY2016FY2015 FY2018

0

50

100

150

200

250

300

350

400

450

FY2017FY2014 FY2016FY2015 FY2018

55.5

51.5

54.452.6

45.8

41.9

37.0 36.238.6 38.9 38.8

30

35

40

45

50

55

60

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

SAIDI

25.424.2 24.7 25.3

23.722.2

20.2 19.720.5

18.9 18.7

10

12

14

16

18

20

22

24

26

28

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

SAIFI

55.5

51.5

54.452.6

45.8

41.9

37.0 36.238.6 38.9 38.8

30

35

40

45

50

55

60

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

SAIDI

25.424.2 24.7 25.3

23.722.2

20.2 19.720.5

18.9 18.7

10

12

14

16

18

20

22

24

26

28

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

SAIFI

320 992

349 643

300 000

310 000

320 000

330 000

340 000

350 000

360 000

2012/13 2017/18

Lines & Cables (km)

320 089

382 842

300 000

320 000

340 000

360 000

380 000

400 000

2012/13 2017/18

Number of transformers

62 753 (20%)

89 959

134 632

0

25 000

50 000

75 000

100 000

125 000

150 000

2012/13 2017/18

Installed capacity (MVA)

44 673 MVA (50%)

2012/13 2017/18

Other 139 442 138 494

Residential 4 874 004 6 120 122

300 000

2 300 000

4 300 000

6 300 000

8 300 000

Number of customers

1.2m customers (25%)

28 651km (9%)

320 992

349 643

300 000

310 000

320 000

330 000

340 000

350 000

360 000

2012/13 2017/18

Lines & Cables (km)

320 089

382 842

300 000

320 000

340 000

360 000

380 000

400 000

2012/13 2017/18


62 753 (20%)

89 959

134 632

0

25 000

50 000

75 000

100 000

125 000

150 000

2012/13 2017/18


44 673 MVA (50%)

2012/13 2017/18

Other 139 442 138 494

Residential 4 874 004 6 120 122

300 000

2 300 000

4 300 000

6 300 000

8 300 000

Number of customers


28 651km (9%)

320 992

349 643

300 000

310 000

320 000

330 000

340 000

350 000

360 000

2012/13 2017/18

Lines & Cables (km)

320 089

382 842

300 000

320 000

340 000

360 000

380 000

400 000

2012/13 2017/18


62 753 (20%)

89 959

134 632

0

25 000

50 000

75 000

100 000

125 000

150 000

2012/13 2017/18


44 673 MVA (50%)

2012/13 2017/18

Other 139 442 138 494

Residential 4 874 004 6 120 122

300 000

2 300 000

4 300 000

6 300 000

8 300 000

Number of customers


28 651km (9%)

320 992

349 643

300 000

310 000

320 000

330 000

340 000

350 000

360 000

2012/13 2017/18

Lines & Cables (km)

320 089

382 842

300 000

320 000

340 000

360 000

380 000

400 000

2012/13 2017/18


62 753 (20%)

89 959

134 632

0

25 000

50 000

75 000

100 000

125 000

150 000

2012/13 2017/18


44 673 MVA (50%)

2012/13 2017/18

Other 139 442 138 494

Residential 4 874 004 6 120 122

300 000

2 300 000

4 300 000

6 300 000

8 300 000

Number of customers


28 651km (9%)

Eskom Distribution

World bank average (adjusted*)

Eskom Distribution

World bank average (adjusted*)

Benchmark Performance Network Performance - Quality Growth Asset & Customer

km of network per employee

No. of customers per employee

SAIDI improved by 35% from

2008

Target = 39 hrs

SAIFI improved by 42% from

2008

Target = 20 interruptions

* World Bank benchmark omitted 78% of Eskom T&D Line Assets

Customer satisfaction

Customer Service performance outcome

70

8,0 8,49,7 9,9

0,0

2,0

4,0

6,0

8,0

10,0

12,0

FY2015 FY2016 FY2017 FY2018

Customer Care

Customer performance outcome

comments

• Enhanced MaxiCare measures

customer satisfaction levels as rated

by customers in the Agricultural,

Commercial, Industrial, Residential

Billed & Prepaid segments

• Eskom Key Care measures customer

satisfaction levels of the key industrial

/ top customers.

99,7

96,4 95,897,7

108,7

104,3107,0 105,9

85,0

90,0

95,0

100,0

105,0

110,0

FY2015 FY2016 FY2017 FY2018

Enhanced MaxiCare Key care

Targets: MaxiCare = 93.7 & Key Care = 104

Target = 8.2

71

Cost management forecast, RmLicensee costs will be managed

optimally by:

0

5 000

10 000

15 000

20 000

25 000

30 000

2018/192019/202020/212021/22

Impairment costs

Corporate cost

Other cost

Maintenance


• Maintaining the network to deliver reliable

network performance to sustain revenue

streams

• Adequate maintenance spend in support

of regulatory compliance

• Optimise manpower cost through a

reduction of the workforce while

maintaining the critical and scarce skills.

• Improved productivity levels

• Impairments are limited to 1% of revenue

applied for.

The current impairment is 3% of

revenue. This translates to R4.4bn

over the MYPD4 period not included in

the application cost base

• The increasing cost of additional

electrification connection, to be funded

from internal efficiencies.

The Licensee intends to manage all cost optimally by limiting year on year growth below

inflation

CAGR 1.0%

Licensee Operational cost as per Methodology

72

Employee expenditure (R’m) and Number

of employeesThe drivers for employee benefit cost

are the following:

• Growth in network and customers of

approximately 9% over application period

• Sustaining operations of network and its

performance

• Customer operations in support of

improved service to the customer

• Remuneration of employees is a function

of employee numbers and annual salary

increases

The workforce is expected to reduce over the MYPD4 control period whilst balancing current

operations with a growth in customer numbers as well as satisfying customer expectations

10 454 10 290 10 541 11 033

17 710 16 841

16 198 16 027

0

2 000

4 000

6 000

8 000

10 000

12 000

14 000

16 000

18 000

20 000

2018/19 2019/20 2020/21 2021/22


Headcount

The average growth rate of the employee

benefit cost is 1.8% per annum while the

workforce reduce by 3.3% over the

MYPD4 planning period

Employee expenditure and number of employees

Maintenance cost

73

Maintenance cost (R’m) The key drivers for the maintenance

expenditure are:

• The span of the network and ability to

respond to customer outage within the

prescribed standards

• Sustained network performance

• Quality of supply to the customer

• Servicing the growing network and new

customers to ensure supply

• Safe operations of network with minimum

impact to environment

• Regulatory compliance is entrenched

within operations

The annual growth of 6% is in line with inflation

2 682 3 000 3 348 3 549

2 284 2 264

2 232 2 366

0

1 000

2 000

3 000

4 000

5 000

6 000

7 000

2018/19 2019/20 2020/21 2021/22

Planned/Unplanned maintenance

Planned Unplanned

4 9665 264

5 5805 915

HV Network 7% MV Network

12%

LV Network5%

Substation16%

Vegetation 7%

Wood Pole 7%

Major Mtce5%

Unplanned 41%

Maintenance by category(3 years)

Planned maintenance of assets is based

on prescribed standards

Unplanned maintenance addresses

interruption of supply

Other costs

74

Other costs (R’m) The main contributors to Other

operating costs are the following:

• Insurance cost – premium and repairs

• Security cost - safeguard assets/national

key points

• Information technology – cost of providing

information systems

• Facility cost – rental of properties,

water/lights, rates/taxes and maintenance

• Fleet and Travel cost – cost of travelling

across country mainly in deep rural areas

• Telecommunications – cost to transfer

data from network control centre to

equipment

• Customer related expenses:

− Vending commission – cost paid to

agents to sell prepaid electricity on

behalf of Eskom.

− Revenue management - customer

billing and meter reading expenses

The annual growth of 5.5% is in line with inflation.

3 223

3 399

3 592

3 785

2 000

2 500

3 000

3 500

4 000

2018/19 2019/20 2020/21 2021/22

Insurance22%

Business related expenses

3%

Security cost10%

Information technology costs

6%Fleet cost

11%

Facilities cost14%

Telecoms6%

Customer related28%

Other cost by category (3 years)

75

Capital expenditure (Rm) Contributory factors for capex are:

• Enabling capacity for future growth.

• Progressing towards regulatory and

statutory requirements.

• IPP Integration and technological

advancements.

• Capital for strengthening and refurbishing

of existing networks.

• Maintaining technical performance.

• Electrification is excluded – funded by

DOE

Capital investments of R 18.4 bn to enable, capacity for future growth, maintaining network

performance and compliance requirements

3 938

5 7836 284 6 332

0

1 000

2 000

3 000

4 000

5 000

6 000

7 000

2018/19 2019/20 2020/21 2021/22

IPP Connections3% Asset Purchases

7%

Direct Customers26%

Land & Rights1%

Strengthening42%

Refurbishment21%

Capex by category (3 years)

Capital expenditure

SAIFI measures the average number of supply interruptions experienced by a connected customer per annum.

SAIDI measures the average duration of supply interruptions experienced by a connected customer per annum.

76

• Network performance is a function of capital and maintenance vested in networks

• The SAIDI/SAIFI performance over the past number of years have improved arising from capital

and maintenance spend

Network performance vs capital expenditure

77

The Licensee overall operating cost is maintained to within the inflationary increase

except for impairment that is limited to 1% of revenue.

The workforce is expected to reduce over the period whilst balancing current

operations with a growth in customer numbers as well as satisfying customer

expectations.

The capital investment programme supports the establishment of the capacity to

meet the future electricity demand while the network is maintained at an acceptable

level of reliability and performance.

Summary of Licensee’s application

Eskom MYPD4 Revenue Application Focus on Regulatory Asset … · 2019-12-13 · Duvha u3 and...

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