1

Renewable Energy Systems 714 Individual Assignment 2014

Compton Saunders compton.saunders@gmail.com

079 176 3020

Name: Compton Saunders

Student Number: 13718436 Degree: PGD Sustainable Development

Module: Renewable Energy Systems 714 Lecturers: Prof Ben Sebitosi & Mr Ulrich Terblanche

Total words: 8900 Due Date: 2 June 2014

ii

Table of Contents

List of Figures ......................................................................................................................................... iii

List of Tables .......................................................................................................................................... iv

List of Abbreviation and Acronyms ......................................................................................................... v

The Continuing Evolution of the South African Integrated Resource Plan (IRP) .................................... 1

1. Introduction ........................................................................................................................................ 1

2 Integrated Resource Plan (IRP) Policy-Adjusted Scenario ................................................................... 2

3 The Renewable Energy Independent Power Producer Programme (REIPPPP) ................................... 4

4 Moving South Africa Forward to an Alternate Power Plan .................................................................. 7

5 Basis for the Alternate Power Plan .................................................................................................... 11

5.1 Power Plant Retirement and Planning Timeline ......................................................................... 11

5.2 Ministerial Determinations ......................................................................................................... 12

5.3 Energy Demand Projection ......................................................................................................... 13

5.4 Reserve Margin and Contribution to Peak Demand ................................................................... 14

5.5 Capital Investment Costs ............................................................................................................ 14

5.6 Nuclear Power ............................................................................................................................. 14

5.7 Renewable Energy Technologies ................................................................................................ 15

5.7.1 Wind Technology ................................................................................................................. 17

5.7.2 Solar Technology ................................................................................................................. 17

5.8 Big Gas ......................................................................................................................................... 19

5.9 Assumption on Fuel Cost ............................................................................................................ 20

5.10 Greenhouse Gas Emissions ....................................................................................................... 21

5.11 The Levelised Cost of Energy .................................................................................................... 22

6 Alternate Scenarios – Sensitivity Analysis. ......................................................................................... 24

6.1 South African Energy Demand .................................................................................................... 24

6.2 Cost of Energy Production .......................................................................................................... 26

7 Conclusion .......................................................................................................................................... 27

APPENDIX A ........................................................................................................................................... 28

APPENDIX B ........................................................................................................................................... 29

APPENDIX C ........................................................................................................................................... 30

Bibliography .......................................................................................................................................... 32

iii

List of Figures Figure 1: IPR Process Overview. Source (DOE 2011a). ........................................................................... 2

Figure 2: Predicted and Real Energy Demand - South Africa .................................................................. 7

Figure 3: Annual New Build Capacity According To Policy Adjusted IRP 2010 ....................................... 8

Figure 4: Total Installed Capacity According To Policy Adjusted IRP 2010. ............................................ 8

Figure 5: Alternate Power Plan installed capacity on left axis including the following on right axis:

System peak demand (GW), Available peak capacity (GW), Capacity reserve margin (%), Total annual

energy requirement (TWh), Greenhouse gas emissions (Mt CO2 eq) .................................................... 9

Figure 6: Alternate Power Plan New Build Capacity ............................................................................. 10

Figure 7: Capacity Retirement Schedule. Data Source Energy Research Centre (2014). ..................... 11

Figure 8: Total Retired Capacity Until 2040 .......................................................................................... 12

Figure 9: Ministerial Determinations .................................................................................................... 13

Figure 10: South African Energy Demand Projection ........................................................................... 14

Figure 11: 2010 Overnight Capital Cost For Nuclear Power Plants ($/Kw) From Numerous Sources.

Source (DOE 2013a). ............................................................................................................................. 14

Figure 12: Annual Cost Reduction Based On Learning Rates for Solar PV. ........................................... 16

Figure 13: Annual Cost Reduction Based On Learning Rates for CSP. .................................................. 16

Figure 14: Annual Cost Reduction Based On Learning Rates for Wind................................................. 17

Figure 15: World Map of Global Horizontal Irradiation. Source SOLARGIS (2014). .............................. 18

Figure 16: Alternate Power Plan New Build Gas Generation Capacity. ................................................ 20

Figure 17: Projections of Fuel Cost. ...................................................................................................... 21

Figure 18: Emissions Reduction Trajectory. Source (DEA 2014). .......................................................... 22

Figure 19: LCOE with A Discount Rate Of 8%. ....................................................................................... 23

Figure 20: Breakdown of LCOE With A Discount Rate Of 8%. ............................................................... 23

Figure 21: IRP installed capacity on left axis including the following on right axis: System peak demand

(GW), Available peak capacity (GW), Capacity reserve margin (%), Total annual energy requirement

(TWh), Greenhouse gas emissions (Mt CO2 eq). .................................................................................. 24

Figure 22: Alternate Power Plan installed capacity on left axis including the following on right axis:

System peak demand (GW), Available peak capacity (GW), Capacity reserve margin (%), Total annual

energy requirement (TWh), Greenhouse gas emissions (Mt CO2 eq) .................................................. 25

Figure 23: High Demand Energy Plan installed capacity on left axis including the following on right axis:

System peak demand (GW), Available peak capacity (GW), Capacity reserve margin (%), Total annual

energy requirement (TWh), Greenhouse gas emissions (Mt CO2 eq ................................................... 25

Figure 24: New Build Capacity Of Alternate Power Plan And High Demand Scenarios........................ 26

Figure 25: Cost Of Electricity For IRP, Alternate Power Plan, High Demand And Fixed Nuclear Schedule

Build According To IRP 2010. ................................................................................................................ 26

iv

List of Tables Table 1: Policy Adjusted IRP. Source (DOE 2011a).................................................................................. 3

Table 2: Generation Capacity in South Africa. Source DME (2003a). ..................................................... 4

Table 3: IRP 2010 Updated Technology Base Case. Source DOE (2013a). .............................................. 5

Table 4: New Build Capacity Outlined By the Minister of Energy to Be Procured By the REIPPPP. ....... 5

Table 5: Economic Development Elements Weighting in REIPPPP. Source (SAPVIA 2012). .................. 5

Table 6: Local Content Investment (R’million). Source (DOE 2013b). .................................................... 6

Table 7: Ministerial Determinations. Source Data DOE (2011a). ......................................................... 12

Table 8: Cost on Renewable Technologies Based In Window 2 of the REIPPP. Source (DOE 2012). ... 15

Table 9: Capacity Allocations of REIPPPP round 1, 2 and 3 .................................................................. 18

Table 10: Job created by REIPPPP. Source (ALTGEN 2013). .................................................................. 19

Table 11: Cost of Gas Assumptions ....................................................................................................... 21

Table 12: Levelised Cost of Gas Infrastructure. Source Energy Research Centre (2014). .................... 21

Table 13: Capacity Factor Used. ............................................................................................................ 23

Table 14: Actual Energy Demand - South Africa. Source (STATS SA 2014). .......................................... 28

Table 15: IRP 2010 Policy Adjusted - New Build Investment Plan. ....................................................... 29

Table 16: Demand Side Management Considerations as Per IRP 2010. Source (DOE 2011a). ............ 29

Table 17: Data Used For IPR 2010 Summary Graph On Installed Capacity And Other Parameters. .... 29

Table 18: Alternate Power Plan New Build Investment Plan. ............................................................... 30

Table 19: High Demand Plan New Build Investment Plan. ................................................................... 30

Table 20: New Capacity General Data .................................................................................................. 31

v

List of Abbreviation and Acronyms

DOE Department of Energy

APP Alternate Power Plan

bbl a barrel (unit)

CSP Concentrated Solar Power

Dti Department of Trade and Industry

EEDSM Energy Efficiency Demand-side Management

GW Gigawatt

GWh Gigawatt hour

IPP Independent Power Producers

IRP Integrated Resource Plan

km2 Square kilometre

kWh Kilowatt hour

LCOE Levelised Cost Of Energy

m2 Square meter

Mton Megaton

MW Megawatt

MWh Megawatt hour

Photovoltaic PV

REIPPPP Renewable Energy Independent Power Producer procurement programme

SAPVIA the South African Photovoltaic Industry Association

TW Terawatt

TWh Terawatt hour

WWF World Wide Fund for Nature South Africa

1

The Continuing Evolution of the South African Integrated

Resource Plan (IRP)

1. Introduction

Since the industrial revolution energy has and will be one of the dominant contributing aspects to development of

nations from a social and economic perspective. The development of South Africa has been no exception as economic

growth has largely been coupled with the availability of energy which has provided power to large industries, small

businesses, transportation and communication systems, and households. The energy sector has greatly been

influenced and driven by the political landscape which sought to advance the country’s economy and social state and

to this end had a significant effect on the development of energy policies.

There are three distinct periods which can be identified when assessing the countries energy policy history. According

to Davidson, Winkler, Kenny, Prasad, Nkomo, Sparks, Howells and Alfstad (2006) the first period, from 1948 to 1994,

called the apartheid era; the second post-apartheid era from 1994 to 2000; and thirdly the period after 2000 up until

today, have seen all the hype of democracy make way for real issues related to rebuilding a country (Davidson et al.

2006).

All three of the periods mentioned shaped energy policy in vastly different ways. Energy security was of utmost

importance during the apartheid era which resulted in substantial investment in liquid fuel production facilities such

as Mossgas (Trollip 1996). The Escom Act of 1987, and the Electricity Act of 1987 reinforced this by aiming to benefit

the privileged few (Davidson et al. 2006). After democracy, energy policy turned its focus on correcting the social and

economic injustices imposed by the apartheid era by promoting justice and equity. The landscape proceeding the year

2000 saw energy policy formalising goals and timeframes which it sought to achieve in terms of promoting the creation

of jobs, economic security, social development and sustainable development.

In terms of achieving post-apartheid energy objectives, South Africa has made leaps and bounds in terms of developing

its energy policies and integrated energy and resource planning over the past two decades. Some of these major

strategic collaborations include the White Paper on the Energy Policy of the Republic of South Africa (WPEP) (DME

1998); Integrated Energy Plan for the Republic of South Africa (IEP) (DME 2003a); White Paper on the Renewable

Energy of the Republic of South Africa(WPRE) (DME 2003b); and the Integrated Resource Plan (IRP) (DOE 2011a).

The Integrated Resource Plan (IRP) will function as a point of departure for this study which will provide a brief

summary of the present energy mix in the Republic of South Africa as well as the near future in the context of post-

apartheid South Africa. SNAPP (Sustainable National Accessible Power Planning), which is a spreadsheet based energy

system modelling tool which was born from ongoing work by the University of Cape Town’s Energy Research Centre

(ERC) (Energy Research Centre 2014) is used to model and investigate possible alternate scenarios to that of the IRP

2010.

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2 Integrated Resource Plan (IRP) Policy-Adjusted Scenario

A number of far reaching conditions are placed on the development of the Integrated Resource Plan (IRP) by the

Electricity Regulations Act of 2006 on new generation capacity. Some of these conditions include modelling possible

scenarios which is based on assumptions that were made during planning; following policy objectives set out by

government for the diversification of the energy generation mix; and determining energy demand forecasts (DOE

2009).

The IRP for South Africa, which was promulgated in the Government Gazette No. 34263 (South Africa 2011), is noted

as a “living plan” having a dynamic nature which would adapt to the changing energy, political and socio economic

landscape of the country (DOE 2011a). The process involved in developing the IPR is very dynamic and by nature needs

to be iterative due to constant updates and reviews. Generally, extensive lead times associated with the process and

ever changing landscape often results in vacillation on decisions thus prolonging capacity build and having a knock-on

effect on the economy. The three major development stages of the IRP, as seen in Figure 1, includes the agreement

of input parameters; the modelling of various scenarios and their analyses; and then followed by the development of

the IRP built on conclusions of the preceding analysis process.

Figure 1: IPR Process Overview. Source (DOE 2011a).

In an attempt to promote critical input into the IPR, a stakeholder consultation from a sundry constituency was

incorporated into the development of the IRP opposed to considering comment after publication. Deliberation by

stakeholders were considered around the input parameters included in modelling as well as the initial balanced

scenario draft. The Revised Balanced Scenario (RBS) of the IRP, published in October 2010, was the result of an initial

public participation process started in June 2010. The RBS was based on optimising cost for building and establishing

new power generation facilities while considering qualitative aspects such as employment, emission reductions and

economic development. After additional public participation in December 2010, additional changes to the cost-

optimal model were made, such as to disaggregate technologies of renewable energy production; learning rates which

is mostly associated with renewable energy; and amendment to the nuclear investment cost. Policy considerations

such as acceleration of renewable energy installs; increase of nuclear new build capacity to account for renewable

energy pricing uncertainties; emission constraints and Energy Efficiency Demand-side Management (EEDSM) lead to

the Policy-Adjusted IRP.

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As recently as 2009, the ESKOM (2009) annual report indicates that about 90% of South Africa’s power was generated

by burning coal with 27 operational power stations constituting 40.7 gigawatt (GW) of the South African electrical

generation capacity. A total capacity of about 43.5 GW was obtained by importing power from Independent Power

Producers (IPP) (ESKOM 2009). As seen in Table 1 and Table 15 in APPENDIX B, the Policy Adjusted IRP indicates adding

new built capacity of 45 637 megawatt (MW) with the allocation of 17 800 MW to renewable energy technologies

including wind; solar photovoltaic (PV); concentrating solar power (CSP); 6250 MW for coal; 9600 MW nuclear power

and about 8900 MW of other generation technology. The new build capacity combined with current capacity would

result in total generation capacity of around 89000 MW or 89 GW (DOE 2011a).

Table 1: Policy Adjusted IRP. Source (DOE 2011a).

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3 The Renewable Energy Independent Power Producer

Programme (REIPPPP)

South Africa is no exception to many other countries who are still dependent on fossil fuels to successfully run its

economy. This fossil fuel dependency, in combination with the energy crisis; a significantly high rate of unemployment

at 25.6 per cent (STATS SA 2013); deliberations from an ecological and climate change perspective; as well as the needs

of a budding economy, has born the requirement to use energy assets of a sustainable nature.

Over the past two decades South Africa has made leaps and bounds in terms of developing its energy policies and

integrated energy and resource planning. Some of these major strategic collaborations on framework development

include the IRP (DOE 2011a). These various frameworks have culminated to strive to achieve numerous objectives,

one of which is the aim to generate 10 000 gigawatt-hours (GWh) of energy from various renewables such as hydro,

wind, solar and biomass by the year 2013 (DME 2003b, DME 2003a). Reaching this goal was propelled into action by

an announcement by the Minister of Energy (DOE 2011b) on the 11th of August 2011 that 3725 MW of renewable

electricity generation capacity was to be constructed and commensurate with the IRP 2010.

In order to procure the required generation capacity an Independent Power Producer (IPP) Procurement Programme

was to be designed which would stimulate job creation, ecological preservation and socio-economic development as

well as the renewable energy sector (DOE 2011b). Renewable energy and its implementation via the numerous

available technologies in South Africa has had a lengthy run-up before astounding the world with its Renewable Energy

Independent Power Producer Programme (REIPPPP). The road from post-apartheid framework conception to

implementation has led South Africa to be an example to the rest of the world.

The Integrated Energy Plan (IEP), released in 2003, delineated the makeup of the South African electricity generation

capacity as seen in Table 2 (DME 2003a) where renewable energy was mostly represented by hydro with no mention

of solar or wind technologies.

Table 2: Generation Capacity in South Africa. Source DME (2003a).

This situation has changed considerably and will continue to change aimed at meeting renewable new build generation

capacity targets set out in the IRP (DOE 2011a). More recently, the IRP 2010 update (DOE 2013a) increased the initial

allocation for PV with 1330 MW with a sizable allocation jump of 2100 MW to 3300 MW for CSP as seen in Table 3.

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Table 3: IRP 2010 Updated Technology Base Case. Source DOE (2013a).

The allocation of new generation capacity by the Minster of Energy can be seen in Table 4 which is aimed at fulfilling

the target of 3725 MW in commercial operation by 2016. During the month of December 2012, an announcement was

made by the minister of energy to increase the determinations for new build electricity generation capacity by IPP’s.

An additional 3200 MW was allocated to the initial 3725 MW, bringing the total available generation capacity up for

procurement to 6925 MW (DOE 2013c). Table 4 indicates the allocation split between all the various renewable energy

technologies.

Table 4: New Build Capacity Outlined By the Minister of Energy to Be Procured By the REIPPPP.

MW Allocation in 2011 MW Allocation in 2012 Technology

1850 1470 Wind

1450 1075 Solar Photovoltaic

200 400 Concentrated Solar Power (CSP)

12.5 47.5 Biomass

12.5 47.5 Biogas

25 Landfill Gas

75 60 Small Hydro

100 Small projects (≤5MW)

3725 (Total) 3200 (Total)

Social and economic development has always been high on the agenda of legislative and policy frameworks post-

apartheid. In order to address the social and economic aspect referred to in the government framework for the

REIPPPP was specifically designed in such a manner that it would add to the sustainable growth in terms of socio-

economic and environmental development while stimulating the renewable energy industry (DOE 2013c). During the

bid process of the REIPPPP, bidders were provided with a prerequisite to bid not just on a tariff, but on socio-economic

development objectives, which were identified by the Department of Energy (DOE 2013c). The weighting allocation

by which the bids were assessed in Round 1 are indicated in Table 5.

Table 5: Economic Development Elements Weighting in REIPPPP. Source (SAPVIA 2012).

Job Creation 25%

Local Content 25%

Ownership 15%

Management Control 5%

Preferential Procurement 10%

Enterprise Development 5%

Socio-Economic Development 15%

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The investment flowing as a result of the required percentage local spend has significantly contributed to local

economic development. Local content spend has varied across the technology types with PV contributing R15 686

million, Wind R6.58 million and CSP R9 656 million. This equates to R38 392 million across all three rounds. This is a

phenomenal investment in local business. The potential however, is much greater as the remaining allocation of

renewable energy generation capacity to meet the 17 800 MW goal for 2030 and can realise a potential investment

into local content of R173 218.12 million. The REIPPPP programme has made a dramatic impact on the investment in

renewable energy technology as well stimulating the economy and will continue to play a critical role in the future.

Table 6: Local Content Investment (R’million). Source (DOE 2013b).

Technology Round 1

allocation

Round 2

allocation

Round 3

allocation

Local Content

Value

Total allocation

After Rounds 1 -3

(MW)

R/MW Remaining

(MW)

Potential Local Content

Value (R’ million)

PV R 6 261 R 5 727 R 3 698 R 15 686 1484 R 10.57 8286 R 87 583.69

WIND R 2 766 R 4 001 R 6 283 R 13 050 1984 R 6.58 2376 R 15 628.43

CSP R 2 391 R 1 638 R 5 627 R 9 656 400 R 24.14 2900 R 70 006.00

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4 Moving South Africa Forward to an Alternate Power Plan

A few years have passed and there are numerous assumptions made in the IRP 2010 which do not hold true or have

become obsolete and could lead to investment decisions which are not optimised. Following the existing promulgated

IRP 2010 could potentially lead to a capital heavy surplus generation capacity which would not be utilised. The policy-

adjusted IRP used the System Operator Moderate forecast on energy demand which predicted that the energy demand

in 2013 would exceed 280 terawatt-hours (TWh) (DOE 2011a). Figure 2 clearly shows that this has not been the case

as the actual total consumed energy was 249 TWh for the year 20131 (STATS SA 2014).

Figure 2: Predicted and Real Energy Demand - South Africa

New data regarding renewable energy prices have emerged due to the REIPPPP and additional possibilities regarding

the supply of natural gas have surfaced while nuclear costs are higher. The retirement age of numerous operational

coal power plants are getting closer and will need to be decommissioned between 2030 and 2040. It is imperative that

investment in new electrical generation capacity needs to be made looking into the future.

Figure 3 illiterates the new build capacity requirements outlined in the Policy Adjusted IRP 2010. It can clearly be seen

that there is a significant amount of nuclear provisioned after 2023 which was included due to the uncertainty of

pricing on renewable technology.

1 Total consumed energy was calculated using by (Purchased outside South Africa (import)) + (Consumed in power stations and

auxiliary systems) + (Electricity available for distribution in South Africa). See APPENDIX B.

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Figure 3: Annual New Build Capacity According To Policy Adjusted IRP 2010

Figure 4 shows the total installed capacity up until 2030 following the Policy Adjusted IRP 2010 and which amounts to

about 89 GW and accounts for the decommissioning of coal production units. The peak power demand is at 67 GW

with the energy demand reaching 454 terawatt-hour (TWh) are obtained from the System Operator Moderate forecast

in the IRP 2010 (DOE 2011a).

Figure 4: Total Installed Capacity According To Policy Adjusted IRP 2010.

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The Alternate Power Plan proposed in this study is depicted in Figure 5 and Figure 6 and reveals what a potential new

power plan could entail if consideration is given to new data that has since become available after the IRP 2010 and

some of the basic assumption are updated while still enforcing the 2011 ministerial determinations.

Due to the lower demand projections used in the Alternate Power Plan the installed capacity in 2030 is 76 GW instead

of 89 GW. There is substantial overinvestment before 2020 taking the reserve margin above 30% after which there is

a slight dip in capacity investment up until 2024. The imported hydro, assumed to be available as from 2020 is kept in

place as per the IRP 2010 irrespective of overinvestment due to low pricing fluctuating from 13.6c/kWh to 38.2 c/kWh.

The investment plan of the proposed Alternate Power Plan is available in APPENDIX C Table 18.

Figure 5: Alternate Power Plan installed capacity on left axis including the following on right axis: System peak demand (GW), Available peak

capacity (GW), Capacity reserve margin (%), Total annual energy requirement (TWh), Greenhouse gas emissions (Mt CO2 eq)

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Figure 6: Alternate Power Plan New Build Capacity

In the Alternate Power plan the new build capacity from 2025 to 2040 is dominated by the investment in new build

gas based technology with 10.35 GW allocated to open cycle gas turbine (OCGT) and 17.06 GW to combined cycle gas

turbine (CCGT) technology which is 27.414 GW in total by 2040. Renewable energy technologies share the majority of

the additional new build capacity with the allocation for Wind of 9.6 GW, Solar PV of 10.8 GW and Concentrated Solar

Power with storage of 6.3 GW. A mixture of coal, hydro, gas and diesel based technologies contribute about 18 GW of

new build capacity. Even though the Copenhagen commitments in terms of CO2 emissions can be met without adding

nuclear power the alternate power plan allocates 9.6 GW of new build nuclear capacity which drastically reduce CO2

emissions, but sustain a good margin of reserve capacity with nuclear plants coming online between 2034 and 2040.

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5 Basis for the Alternate Power Plan

The following sections outline more details on assumptions that were made in deriving a new proposed energy plan.

There are various assumptions made in the Alternate Power Plan (APP) and modelled in the SNAPP tool which differ

from that of the IPR 2010. A lower energy demand is projected; nuclear costs are assumed to be higher; pricing for

renewable energy technology is adjusted in line with the REIPPPP; and fuel prices – particularly that of gas – is also

raised.

5.1 Power Plant Retirement and Planning Timeline

The timeline considered was extended to 2040 in order to account for the replacement of retiring largely coal fired

power plant. The schedule is based on data obtained from the IRP 2010 (DOE 2011a), IRP 2010 Update (DOE 2013a)

and the Energy Research Centre (2014). The IRP update does not follow a strict lifetime decommissioning schedule

but for this study the power plants presumed lifetime and commissioning year is used to determine when it will be

retired as illustrated in Figure 7.

Figure 7: Capacity Retirement Schedule. Data Source Energy Research Centre (2014).

The general assumption made around the lifespan of power plants is 50 years which means that by the year 2038

about 32 GW of existing capacity will be retired as seen in Figure 8. The bulk of capacity decommissioning will happen

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PWR nuclear Existing Sasol Infrachem Sasol SSF

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between 2028 and 2040. Koeberg nuclear power plant will be included within this bulk decommissioning and will be

retired in 2034 if its lifespan is also assumed to be 50 years and it was commissioned in 1984.

Figure 8: Total Retired Capacity Until 2040

5.2 Ministerial Determinations

Table 7 and Figure 9 show the determination made by the ministry in 2011 and 2012 as well as existing commitments

from Eskom before the IRP. The determinations made in 2011 will be included in all scenarios, but the determinations

made in 2012 will be considered when performing sensitivity analysis.

Table 7: Ministerial Determinations. Source Data DOE (2011a).

Technology description

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

Open-Cycle Gas Turbine diesel 1020 805 805 805

Micro hydro 25 25

Landfill gas 75

Supercritical Coal 722 1444 722 2168 723 1446 723 250 250

Combined Cycle Gas Turbine - Sasol 260 130

Wind high resource 400 400 400 400 400 400 400 400 400

Solar Central Receiver 14 hours storage 0 0 100 100 100 100 100 100 100

Solar PV centralised non-concentrated 300 300 300 300 300 300 300 300 300

Combined Cycle Gas Turbine 237 237 237

Fluidised Bed Combustion Coal 500 500 250 250 250 250 250

Kafue hydro import 1143 1183 283

Pumped Storage New 333 999

Eskom commitments (pre IRP)

Determinations made in 2011

Determinations made in 2012

13

Figure 9: Ministerial Determinations

5.3 Energy Demand Projection

Figure 10 illustrates a range of assumptions regarding South Africa’s energy demand growth over the considered

planning period. All of the scenarios already subtract demand side management (DSM) consideration as stated in the

IRP 2010 and seen in APPENDIX B, Table 16. Considering Figure 10, the System Operator Moderate forecast (“SO Mod”)

was used by the IRP 2010 for its “Policy Adjusted Scenario” assumptions while the “MYPD3 Ext” case uses data from

the MYPD3 application by ESKOM (2012) for years 2012 to 2018.

The MYPD3 Extended (“MYPD3 Ext”) energy demand growth and requirement is used for the APP. Assumption start

in 2012 by following the growth trend presented by the MYPD3 projections up until 2017 after which it starts following

the System Operator Low forecast (“SO Low”) of the IRP 2010 until 2035 and assumes a steady rate of 0.8% up to 2040

as seen in Figure 10.

Another alternate scenario which will be considered during the sensitivity analysis shown in Figure 10 is MYPD3 flat

rate (“MYPD3 flat”) which assumes a slightly higher rate of energy demand increase by tracking the above the MYPD3

growth rate till 2017 after which it starts following “SO Low” up to 2021 and thereafter assumes a steady growth rate

of 2% up till 2040. The result of this is that the MYPD3 flat rate ends up with energy demand requirements between

the System Operator Moderate forecast (“SO Mod”) and System Operator Low forecast (“SO Low”) of the IRP 2010.

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2010201120122013201420152016201720182019202020212022202320242025

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Capacity Determinations by Ministry

Open-Cycle Gas Turbine diesel Micro hydro

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Combined Cycle Gas Turbine - Sasol Wind high resource

Solar Central Receiver 14 hrs storage Solar PV centralised non-concentrated

Combined Cycle Gas Turbine Fluidised Bed Combustion Coal

Kafue hydro import Pumped Storage New

14

Figure 10: South African Energy Demand Projection

5.4 Reserve Margin and Contribution to Peak Demand

All of the scenarios considered in the APP use a reserve margin of at least 15% of firm capacity. This is in line with the

14% to 19% that is recommended in the Energy Security Master Plan (DME 2007). The firm capacity of 1 is assumed

for all thermal, solar thermal with storage, hydro and pumped storage units while a conservative assumption of 0.15

is made for wind and zero for solar PV or solar thermal without storage.

5.5 Capital Investment Costs

The cost associated with numerous renewable as well as nuclear have been updated to that in the IRP 2010 to echo

the experience in the REIPPPP. The cost for conventional coal, gas, hydro, nuclear and biomass technologies have all

been updated as per the Power Generation Technology Data for Integrated Resource Plan of South Africa (EPRI 2012)

as seen in APPENDIX B, Table 20.

5.6 Nuclear Power

Figure 11: 2010 Overnight Capital Cost For Nuclear Power Plants ($/Kw) From Numerous Sources. Source (DOE 2013a).

The IRP 2010 initially assumed the cost of nuclear plants to be in the region of $3500 per kW. However this was

drastically increased by around 40% after consultation and input from numerous stakeholders to provision for new

technology, waste management and decommissioning (DOE 2013a). The IPR2010 then used the values in the region

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300 000

400 000

500 000

600 000

20

10

20

13

20

16

20

19

20

22

20

25

20

28

20

31

20

34

20

37

20

40

Ener

gy D

eman

d G

row

th (

Gw

h)

Annual Energy Demand

SO Low SO Mod

MYPD3 Ext MYPD3 flat

15

of $5000 per kW despite the fact that during the 2008 bidding process Areva provided Eskom with pricing of around

$6000 per kW (Thomas 2010). According to Harris, Heptonstall, Gross and Handley (2012) overnight costs for nuclear

power plants are in the region of $7000 per kW and will be used for this study while the sensitivity analysis will consider

a cost of $5000 per kW. All other parameters are updated to be in line with the IRP Update Report (DOE 2013a).

5.7 Renewable Energy Technologies

The experienced gained from the past REIPPPP bid windows or rounds shed some light on the actual cost of

implementing renewable energy projects in South Africa. Table 8 indicates the total capacity and project costs for

Wind, PV and CSP projects of Round 2 of the REIPPPP (DOE 2012). Considering this data allows the estimation of the

2010 overnight costs for these technologies which can be used in the model.

Table 8: Cost on Renewable Technologies Based In Window 2 of the REIPPP. Source (DOE 2012).

Wind PV CSP

Total Project cost mR(2012) 10897 12048 4483

Capacity MW 563 417 50

Project Cost 2012 R/kW 19355 28892 89660

Project Cost 2010 R/kW 16592 24768 76861

Lead Time years 2 1 3

IDC 0.12 0.08 0.17

Overnight Cost 2010 R/kW 14772 22933 65766

Overnight Cost 2010 $/kW 1996 3099 8887

The cost of renewable energy technologies are still in decline and predicted to continue with this trend as global

installed capacity continues to grow. The modelling in the IRP 2010 makes the assumption that South Africa is currently

still a price taker of the renewable cost trends and that technology learning rates would still be highly dependent on

the global market instead of the local market. The reduction of technology and project costs based on technology

learning will likely also be driven by global markets exogenously.

In order to consider the effect of technology learning within the modelling analysis, three cost reduction scenarios are

considered which are “optimistic”, “conservative “and “pessimistic” respectively. All of the technology, solar PV, CSP

and wind, assume an “optimistic” price reduction trend based on the IRP 2010 as seen on the left in Figure 12, Figure

13 and Figure 14. In all the cases, irrespective of the technology, there is about a 30-50% reduction in overnight cost

between the “optimistic”, “conservative “and “pessimistic” scenarios. Using the project costs based in REIPPPP values

in Table 8. Considering the overnight cost value based on the REIPPPP window 2 in Table 8 it can be seen in Figure 12

that the PV “pessimistic” view tracks below that of Vealth and NREL (2012). In the case of CSP in Figure 13, the 6 hour

storage system cost assumed by Vealth and NREL (2012) straddles the “pessimistic” view. Figure 14 shows that the

prediction from Vealth and NREL (2012) closely tracks the cost of the “pessimistic” scenario. The Alternate Power Plan

scenario will however assume a conservative view regarding technology learning while the sensitivity analysis will

consider more optimistic trends.

16

Figure 12: Annual Cost Reduction Based On Learning Rates for Solar PV.

Figure 13: Annual Cost Reduction Based On Learning Rates for CSP.

17

Figure 14: Annual Cost Reduction Based On Learning Rates for Wind.

5.7.1 Wind Technology

Wind energy is one of the world largest contributors to renewable energy. South Africa has good wind resources and

according to Van der Linde and Sayigh (1999), wind can supply about 6% of the energy demand in South Africa.

A more recent report suggests that theoretically wind energy could supply up to 184 terawatt-hour (TWh) which is

significant considering that South Africa uses about 220 TWh per year (Energy Research Centre 2010). However

according to Hagemann (2008), a realistic projection based on technical potential for wind is 80 TWh with an installed

capacity of around 30.6 GW. The Western Cape with portions of the Eastern and Northern Cape poses some of the

best wind potential (Energy Research Centre 2010). The IRP 2010 update (DOE 2013a) allocated 4360 MW capacity to

wind placing the technology at 45.5% of its 2030 goal. However, the APP proposes new build capacity of 9600 MW

which is well within the resource capability estimated with a potential of 30 000 MW by Hagemann (2008).

5.7.2 Solar Technology

South Africa is said to poses one of the greatest solar resources in the world (Fluri 2009). According to the Integrated

Energy Policy (IEP) “South Africa experiences some of the highest levels of solar radiation in the world and this

renewable resource holds great potential for the country” (DME 2003a). According to the DOE (2013d), and as seen

in Figure 15, the daily irradiation South Africa receives ranges from 4.5 to 6.5 kWh/m2 which is greater than the levels

experienced in two regions where solar technology is vastly implemented namely Europe (2.5 kWh/m2) and the United

States (3.6 kWh/m2 ). South Africa has large areas of about 194,000 km2 that experience very high intensities of

irradiation with the Northern Cape being one of the greatest solar resources globally (DOE 2013d).

18

Figure 15: World Map of Global Horizontal Irradiation. Source SOLARGIS (2014).

In South Africa in 2011, large scale solar PV facilities have gone from non-existent to having 1484 MW of capacity

within the process of procurement, construction and in operation after the three rounds of the REIPPPP. Table 9

provides a summary of the capacity allocated to preferred bidders in the first three rounds of the REIPPPP.

Table 9: Capacity Allocations of REIPPPP round 1, 2 and 3

Technology Round 1

allocation

(MW)

Round 2

allocation

(MW)

Round 3

allocation

(MW)

Total allocation After

Rounds 1 -3 (MW)

% of Base Case Base Case IRP 2010 update

(MW)

Remaining

(MW)

PV 632 417 435 1484 15.1 9770 8286

CSP 150 50 200 400 12.1 3300 2900

WIND 634 563 787 1984 45.5 4360 2376

The independent report by WWF (2013) also indicates the most geographic localisation of solar PV amongst all the

other renewable technologies as it can be developed in and throughout South Africa on a relatively low capital scales

and thus providing a multiplicity of and diversity of ownership while introducing distributed economic and market

benefits opposed to one central location (WWF 2013). Davin Chown, chairperson of SAPVIA, said “Solar PV can deliver

serious benefits for the National Development Plan in terms of employment and the spread of diversified capital

investment right across the country – every province can benefit from investment in this form of energy.” (WWF 2013)

Although there is great economic and social potential for wind and solar, CSP however remains to be the most

intriguing technology. CSP has four global key technologies which are Parabolic Trough, Linear Fresnel, Solar Tower

and the Solar Dish. CSP, which includes thermal storage offers a benefit above other technologies due to the fact that

energy can be stored and dispatched on demand making its power delivery more predictable. This also enables the

technology to provide power in the evening peak within South Africa as well as improving the levelised cost of energy

(LCOE). Considering the data in Table 10, CSP offers a multitude of jobs at 26 jobs per MW of capacity and also

contributes significantly towards local content spend at R24 million per MW. CSP plants generally have a long lifespan

of about 60 years which is in line with legacy coal fired power stations (SASTELA 2013) . Although CSP is an expensive

immature technology, the cost of CSP plants could be significantly reduced by up to 40% by improvements in

manufacturing processes, technology and economy of scale. South Africa is currently in a good position to advance

19

research and development into the technology and possibly to capture a slice of the global equipment supply market.

The South African Department of Energy (DOE) also recently announced that there would be an additional incentive

for CSP plants with thermal storage in during peak hours in the form of a Time of Day (TOD) tariff which is 270% above

the base tariff making this technology even more attractive.

Table 10: Job created by REIPPPP. Source (ALTGEN 2013).

Technology Round 1

allocation

(MW)

Round 2

allocation

(MW)

Round 3

allocation

(MW)

Total allocation

After Rounds 1 -

3 (MW)

% of

Base

Case

Total Jobs Jobs

/(MW)

Base

Case

IRP

2010

update

(MW)

Remaining

(MW)

Potential

Jobs2

PV 632 417 435 1484 15.1 24209 16.31 9770 8286 135172.4

CSP 150 50 200 400 12.1 10421 26.05 3300 2900 75552.25

WIND 634 563 787 1984 45.5 19414 9.79 4360 2376 23249.83

5.8 Big Gas

Currently, a much debated and controversial topic in the South African energy and ecological arenas is the recovery

of shale gas via hydraulic fracturing (fracking) which is a proses whereby chemical, sand and pressurised water is

pumped into the ground in order to free gas which is trapped within rock. Numerous companies planned to launch

exploration campaigns in order to extract and exploit shale gas reserves in the Karoo but have been met with

determined opposition from various fraternities who are mostly concerned with the possible detrimental ecological

effect such as the contaminating underground water reservoirs. The South African government initially restricted the

exploration of shale gas but the Minister of Minerals and Energy lifted the moratorium in 2012 which was followed by

draft regulations around governing additional exploration and fracking (Business Day 2012).

According to Econometrix (2012), the largest independent macro-economic consulting company in South Africa, shale

gas extraction in the southern Karoo of South Africa could potentially create hundreds of thousands of employment

opportunities while greatly boosting the economy of the country (Econometrix 2012). The potential annual revenue

that the South African government could gain from 20 trillion cubic feet (TCF) is R35 Billion and from 50 TCF production

is R90 Billion while 300 000 to 700 000 jobs could be created over a 25 year period (Econometrix 2012). The South

African GDP would receive an injection of R80 billion (20 TCF) and R200 billion (50 TCF) which equates to the region of

3.3% and 9.6% of the 2010 GDP (Econometrix 2012). This view was echoed by Deputy President Kgalema Motlanthe

who said that scientific advice offered to government indicated that hydraulic fracturing would essentially “be a game

changer for the South African economy” (Business Day 2012).

South Africa is globally ranked in 5th position for possibly having shale gas resources which can be recovered. The

southern Karoo is projected as having 485 trillion cubic feet (TCF) of recoverable shale gas reserves (Kuuskraa, Stevens,

Van Leeuwen and Moodhe 2011). In order to put this in perspective and comparing South Africa to the other countries

who are known to have large natural gas reserves such as Qatar (905 TCF), Russia (1680 TCF), Saudi Arabia (252 TCF)

and Nigeria (184 TCF) shows the potential the country holds (Mkhabela and Laing 2012). Sasol GTL plants that have

20

been fuelled by the Pande and Tamane gas fields which are 2.3 TCF in size which assist showing the potential the

southern Karoo holds. A base-load CCGT (combined cycle gas turbine) power plant with the capacity of 1000 MW can

be fuelled for 25 years by just 1 TCF of shale gas (Mkhabela and Laing 2012). Considering the large potential resource

buried within the South Africa it easy to understand why it can be seen as a “game changer” even if only a small

percentage of the southern Karoo resource could be technically recoverable. The extraction and utilisation of shale

gas will provide the South African economy with a low carbon, compared to coal, source of energy which can support

growing demand for the energy sector as well as other industries.

In the IRP 2010 (DOE 2011a) the MTRMP (Medium Term Risk Mitigation Plan) determination included 474 MW of

natural gas new build capacity between 2019 and 2020 (DOE 2011a) . IRP 2010 (DOE 2011a) also has 7761 MW base

load determination which includes 2652 MW of new build capacity between 2021 and 2025 for generation via

Liquefied Natural Gas (LNG) or Natural Gas using CCGT and open cycle gas turbines (OCGT) (DOE 2011a).

The APP considers gas based electricity generation technology to significant contribute to the South African energy

mix by 2030 and 2040. The APP commences the incorporation of new build gas by 2013 as according to Shell the

production of shale gas based fuels is possible within ten years (Karoo Space 2013). There is also a debate expected

around the switching of fuel types of the already existing OCGT generation to natural gas. The APP allocates 10.35 GW

to OCGT and 17.06 GW CCGT technology which is 27.414 GW new build capacity as seen in Figure 16. This is an

optimistic perspective of and according to Eardley-Taylor and Green (2013) a possible variation on what was achieved

in the UK “dash for gas” where 20 GW capacity was built in 10 years by Independent Power Producers.

Figure 16: Alternate Power Plan New Build Gas Generation Capacity.

5.9 Assumption on Fuel Cost

The pricing of fuel costs on fuel used by conventional power plants used in the foundation assumption are shown in

Figure 17. The assumptions used in the model regarding the price of gas and associated infrastructure can be seen in

Table 11 and Table 12 and assumes a 90% capacity factor. All of the other technology fuel cost have been left at the

values used in the IRP 2010 while only the price of coal and gas have been updated. The MYPD3 application was used

to update the coal price while the gas price is indexed to that of coal and increases accordingly. According to The

International Energy Outlook 2013 with Projections to 2040 (EIA 2013) the price of is predicted to increase from its

2010 value of around $80 per bbl to the region of $150 per bbl by the year 2040.

0

10000

20000

30000

0

500

1000

1500

2000

20

16

20

18

20

20

20

22

20

24

20

26

20

28

20

30

20

32

20

34

20

36

20

38

20

40

Tota

l New

Bu

ild (

MW

)

New

Bu

ild (

MW

)

New Build Gas - Alternate Power Plan

Open-Cycle Gas Turbine gas Combined Cycle Gas Turbine

Total New Build

21

Figure 17: Projections of Fuel Cost.

Table 11: Cost of Gas Assumptions

Oil Price Index $/Mbtu/$/bbl

Gas Indigenous Ibhubezi Piped 0.1

Gas Indigenous Piped Shale 0.08

Gas Northern Mozambique Piped 0.06

Gas LNG Fixed Terminal 0.112

Gas LNG FSRU 0.112

Table 12: Levelised Cost of Gas Infrastructure. Source Energy Research Centre (2014).

Levelised Infrastructure Costs 2010 R/GJ

Capacity Factor 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9

Gas Indigenous Ibhubezi Piped 64.1 42.7 32.0 25.6 21.4 18.3 16.0 14.2

Gas Indigenous Piped Shale 64.1 42.7 32.0 25.6 21.4 18.3 16.0 14.2

Gas Northern Mozambique Piped 320.3 213.6 160.2 128.1 106.8 91.5 80.1 71.2

Gas LNG Fixed Terminal 20.5 13.6 10.2 8.2 6.8 5.8 5.1 4.5

Gas LNG FSRU 33.4 22.2 16.7 13.3 11.1 9.5 8.3 7.4

5.10 Greenhouse Gas Emissions

One of the major environmental considerations was the high CO2 emissions caused by the primary use of coal for

energy production with 83% of total emissions due to energy production (Kohler 2013). In 2009, at the UNFCCC3

National Climate Summit, the President of South Africa made an announcement that the country would, due to its

legal obligations under the UNFCCC and its Kyoto Protocol, implement measures to obtain emissions reductions of

34% and 42% by the year 2020 and 2025 respectively opposed to the “Business As Usual” scenario (Republic of South

Africa 2011).

3 United Nations Framework Convention on Climate Change

22

Figure 18: Emissions Reduction Trajectory. Source (DEA 2014).

In order to comply with “Plateau and Decline” trajectory the same emissions decline will be perused as in the

“Advanced Decline scenario” of the IRP 2010 update (DOE 2013a) with CO2 emissions from power plants peaking at

275 Megaton (Mton) per annum in 2025 and start declining to 225 Mton per annum between 2035 and 2040 and

eventually reaching 140 Mton in 2050.

5.11 The Levelised Cost of Energy

The levelised cost of electricity (LCOE) for various technologies and over the lifespan of the power plant is shown Figure

19 and Figure 20. The LCOE which is provided in real terms (todays money), assuming a discount rate of 8%, considers

capitol, fuel, fixed operations and maintenance (O&M) and variable O&M cost as shown in Figure 20. The assumption

made is that cost are incurred in the beginning of the year while Table 13 shows the capacity factor that was considered

for each power plant technology.

Considering the LCOE of the various technologies in Figure 19 coal based power plants still offer the lowest LCOE of

the fossil fuel type technologies, with the highest capacity factor if we do not consider CO2 emissions. Imported hydro

offer a mix of very attractive LCOE while providing a capacity factor of 30 – 60%. As seen in Figure 19 around 2025

there is a convergence of LCOE for various technologies where solar PV and CSP costs are in-line with that of nuclear

which is assumed to have an overnight cost of $7000 per kW and even becoming more economical than gas based

technology. Wind still remains one of the most cost effective renewable technologies and comes very close to the

LCOE of supercritical coal.

23

Figure 19: LCOE with A Discount Rate Of 8%.

Figure 20: Breakdown of LCOE with A Discount Rate Of 8%.

Table 13: Capacity Factor Used.

Capacity Factor (%)

Wind high resource 30

Solar PV centralised non-concentrated 20

Solar Central Receiver 14 hours storage 70

Biomass bagasse 90

Landfill gas 50

Open-Cycle Gas Turbine gas 88.8

Combined Cycle Gas Turbine 88.8

Nuclear PWR higher cost 92

Supercritical Coal 91.7

Fluidised Bed Combustion Coal 90.4

Ithezi Tezhi hydro import 64

Boroma - Quedas Ocua hydro import 42

Kariba North Bank extension hydro import 38

Kafue hydro import 46

mini hydro existing 87.92

24

6 Alternate Scenarios – Sensitivity Analysis.

The sensitivity or degree in which the APP responds to changes in technology, increased demand and nuclear build

plan is explored in a limited scope due to the content restraints of this study. For the various sensitivity scenarios the

requirements in terms of new capacity, the cost of generation and emissions responsibilities are discussed. The cost

of generation includes capitol, fuel, variable, fixed and carbon costs while the cost of water and environmental levy is

not considered.

6.1 South African Energy Demand

A High Demand Scenario is developed in order to assess the effect on the price of electricity. The High Demand Energy

Plan shown is Figure 23 below with its build plan indicated in APPENDIX C, Table 19. The APP in Figure 22 assumes an

energy demand of 390 TWh having an installed capacity of about 84 GW by 2040 while the High Demand scenario in

Figure 23 assumes 440 TWh energy demand and 98 GW of installed capacity. In both cases there are major

contributions from renewables, nuclear and specifically gas. The High Demand scenario has the contributions to

installed capacity by 2040 of 21.1 GW Wind; 5.9 CSP, 9.6 Solar PV, 13.8 GW OCGT; 11.38 GW of CCGT; 9.42GW of

imported hydro and 14.4GW nuclear. A very small quantity of coal production capacity was added due to restrictions

on emissions and while adhering to the “Plateau and Decline” trajectory stated previously in the study. In the APP as

well as in the High Demand scenarios, nuclear plays a critical role in maintaining and reducing emission levels while

providing a sufficient capacity margin, but is built fairly late and have only started to come online after 2030.

Figure 21: IRP installed capacity on left axis including the following on right axis: System peak demand (GW), Available peak capacity (GW),

Capacity reserve margin (%), Total annual energy requirement (TWh), Greenhouse gas emissions (Mt CO2 eq).

25

Figure 22: Alternate Power Plan installed capacity on left axis including the following on right axis: System peak demand (GW), Available peak

capacity (GW), Capacity reserve margin (%), Total annual energy requirement (TWh), Greenhouse gas emissions (Mt CO2 eq)

Figure 23: High Demand Energy Plan installed capacity on left axis including the following on right axis: System peak demand (GW), Available

peak capacity (GW), Capacity reserve margin (%), Total annual energy requirement (TWh), Greenhouse gas emissions (Mt CO2 eq

26

Figure 24: New Build Capacity Of Alternate Power Plan And High Demand Scenarios.

6.2 Cost of Energy Production

The cost of electricity generation, before transmission, is shown in Figure 25. Between 2012 and 2020, in all the

scenarios, there is a steep rise in the cost of generation due to investment into the construction of power plants.

Considering the APP and the High Demand scenarios, there is a perceivable reduction in cost until 2030 due to the

overbuilt capacity in relation to the demand that was expected. Another contributing factor to the cost reduction

between 2020 and 2030 is the minimised new build capacity within this period. This cost reduction period is not seen

for the IRP 2010 or the APP and High Demand when nuclear build schedule and capacity is kept the same as the IRP

2010 for these scenarios. The commitment of building nuclear capacity during the period 2020 to 2030 would result

in an electric generation cost which is up to 20% higher than on the APP. After 2030 the cost of the APP and High

Demand scenarios starts rising as there is a need to start replacing conventional coal plants which are being retired in

order to cope with the increasing demand. The CO2 limitations are kept the same in all scenarios which results in less

allocation to coal technologies and more allocation to alternate technology such as nuclear, renewable and gas which

drive the cost up after 2030. The IRP 2010 assumes the System Operator moderate growth scenario and sustains

higher levels of investment, throughout the planning horison, in expensive technology such as nuclear and renewables

which have not yet enjoyed the benefits of technology learning cost reduction and results in higher cost of electricity.

Figure 25: Cost Of Electricity For IRP, Alternate Power Plan, High Demand And Fixed Nuclear Schedule Build According To IRP 2010.

27

7 Conclusion

It has been merely three years after the release of the IRP 2010 and the energy landscape in South Africa has already

significantly changed. The Alternate Power Plan (APP) is merely a single possibility of an alternate to the IRP 2010

Policy Adjusted Scenario and by no means definitive. The power generation options selected as part of the APP are

not outputs of the SNAPP model but selected based on consideration of the various input parameters and

assumptions. Additional scenarios were also modelled where consideration was given to higher energy demand and

IRP 2010 determined nuclear build slots.

This brief study highlights some of the reasoning behind the APP by considering parameters such as energy demand,

nuclear costs, capital costs, ministerial determinations, CO2 emissions and resource and technology prospects. The

lower energy demand, compared to the IRP 2010 assumptions, seen by considering available data and new

information on renewable energy and nuclear costs as well as the potential of shale gas has a clear impact on the path

a future energy plans.

The basic analysis that was performed awakens the realisation of the importance in updating the IRP 2010 by

deliberating and modelling new quantitative and qualitative parameters.

Ignorance of new information and the dynamic landscape in decision making will lead to poor decision making and

ultimately negatively affect the South African people and the economy. The study indicates that irrespective of

increased energy demand the need to build new nuclear capacity is only required around 2032 and not 2023 as per

the IRP 2010 giving the country more time to decide on whether or not to introduce additional nuclear. South Africa

has more time available than anticipated and can wait on nuclear until new information becomes available on shale

gas availability and costs; cost and capabilities of CSP technology; cost and technology updates on nuclear options;

understanding transmission capability considering large scale renewable rollouts and the effect of distributed

generation such as rooftop PV. These are merely a few parameters which will make a significant impact on the

constitution of a new energy plan.

28

APPENDIX A General Data

Table 14: Actual Energy Demand - South Africa. Source (STATS SA 2014).

20

10

20

11

20

12

20

13

Electricity available for distribution in South Africa 238431 240670 233870 233207

Electricity produced 259601 262538 257919 256073

Purchased outside South Africa (import) 12193 11890 10006 9428

Consumed in power stations and auxiliary systems 18851 18937 18716 18470

Sold outside South Africa (export) 14668 14964 15035 13929

Electricity available for distribution in South Africa 238272 240528 234174 233105

Electricity produced 251257 251746 247516 244851

Purchased outside South Africa (import) 12193 11890 10006 9428

Consumed in power stations and auxiliary systems 18070 18134 17870 17684

Sold outside South Africa (export) 14668 14964 15035 13929

Electricity available for distribution in South Africa 230709 230541 224620 222668

Electricity distributed by Eskom 222674 222710 217418 216354

Total consumed Energy in South Africa 260972 260565 252496 249780

Total consumed Energy in South Africa was calculated using by (Purchased outside South Africa (import)) + (Consumed in

power stations and auxiliary systems) + (Electricity available for distribution in South Africa) (STATS SA 2014).

29

APPENDIX B IRP 2010 Raw Data

Table 15: IRP 2010 Policy Adjusted - New Build Investment Plan.

Table 16: Demand Side Management Considerations as Per IRP 2010. Source (DOE 2011a).

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Comp Air Capacity (MW) 39 76 115 151 211 275 275 275 275 275 275

Energy (GWh) 297 581 881 1158 1619 2110 2110 2110 2110 2110 2110

Heat Pumps Capacity (MW) 3 35 110 282 463 522 581 640 640 640 640

Energy (GWh) 14 142 445 1137 1866 2104 2341 2579 2579 2579 2579

Lighting HVAC Capacity (MW) 106 137 169 199 233 271 271 271 271 271 271

Energy (GWh) 673 874 1074 1266 1482 1724 1724 1724 1724 1724 1724

New Initiatives Capacity (MW) - - - 17 38 68 68 68 68 68 68

Energy (GWh) - - - 123 275 492 492 492 492 492 492

Process Optimisation Capacity (MW) 81 151 210 293 384 467 467 467 467 467 467

Energy (GWh) 608 1137 1582 2208 2895 3521 3521 3521 3521 3521 3521

Shower Heads Capacity (MW) - 20 85 85 85 85 85 85 85 85 85

Energy (GWh) - 58 248 248 248 248 248 248 248 248 248

Solar Water Heating Capacity (MW) 26 78 123 287 556 910 1263 1617 1617 1617 1617

Energy (GWh) 76 227 360 838 1622 2656 3689 4722 4722 4722 4722

Total Capacity (MW) 254 496 811 1313 1969 2597 3009 3422 3422 3422 3422

Energy (GWh) 1669 3020 4590 6978 10007 12855 14126 15397 15397 15397 15397

Table 17: Data Used For IPR 2010 Summary Graph On Installed Capacity And Other Parameters.

30

APPENDIX C ALTERNATE POWER PLAN DATA

Table 18: Alternate Power Plan New Build Investment Plan.

Table 19: High Demand Plan New Build Investment Plan.

31

Table 20: New Capacity General Data

32

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