NATIONAL ENERGY REGULATOR OF SOUTH AFRICA

NATIONAL ENERGY REGULATOR OF SOUTH AFRICA

In the matter regarding Concurrence with the ministerial determination on the procurement of new generation capacity from Renewables (Wind and PV), Storage, Gas and Coal technologies

By DEPARTMENT OF MINERAL RESOURCES AND ENERGY (DMRE)

REASON FOR DECISION

Concurrence with the ministerial determination on the procurement of new generation capacity from Renewables (Wind and PV), Storage, Gas and Coal technologies

2

TABLE OF CONTENTS

ABBREVIATIONS ................................................................................................. 3

DEFINITIONS ....................................................................................................... 4

1. LEGAL MANDATE ..................................................................................... 7

2. BACKGROUND AND INTRODUCTION ..................................................... 9

3. THE DECISION-MAKING PROCESS ...................................................... 11

4. STAKEHOLDER COMMENTS ................................................................. 12

5. ANALYSIS OF DETERMINATION ........................................................... 13

6. CONCLUSISON ....................................................................................... 57

APPENDIX A: Draft Determination ..................................................................... 59

APPENDIX B: Stakeholder Comments ............................................................... 59


3

ABBREVIATIONS

BW Bid Window

CAES Compressed Air Energy Storage CCGT Closed Cycle Gas Turbine

CCS Carbon Capture and Storage

COD Commercial Operation Date

DEA Department of Environmental Affairs

DMRE Department of Mineral Resources and Energy

DTI Department of Trade and Industry

DUoS Distribution Use-of-System

EPRI Electric Power Research Institute

FGD Flue Gas Desulfurisation

GHG Greenhouse Gas

GW Gigawatt

GWh Gigawatt hour

HELE High Efficiency Low Emissions

IPP Independent Power Producer

IRP Integrated Resource Plan

kV Kilovolt

kWh Kilowatt hour

LAES Liquid Air Energy Storage

LCOE Levelised cost of energy/electricity

LNG Liquefied Natural Gas

LPG Liquefied Petroleum Gas

MT Medium Term

MYPD4 Fourth Multi-Year Price Determination

MW Megawatt

NERSA National Energy Regulator of South Africa

OCGT Open Cycle Gas Turbine

O&M Operating and Maintenance

PC Pulverised Coal

PV Photovoltaic

PPA Power Purchase Agreement

RfD Reasons for Decision

RFI Request for Information

RFP Request for Proposal

REIPPPP Renewable Energy Independent Power Producer Procurement

Programme

RE Renewable Energy

SARB South African Reserve Bank

SED Socio-Economic Development

ST Short Term

SO System Operator

SOE State-Owned Enterprise

UoS Use-of-System


4

DEFINITIONS

In this document, any word or expression shall have the meaning assigned below,

unless the context indicates otherwise.

‘Ancillary services’ means services supplied to the national transmission

company by generators, which are necessary for the reliable and secure transport

of electricity from generators to distributors and customers.

‘Base Load Generation’ means the generating facilities within a utility system that

are operated to the greatest extent possible to maximise system mechanical and

thermal efficiency, and minimise system operating cost. A typical example is often

found in coal power stations.

‘Buyer’ means, in relation to a new generation capacity project, any organ of state

designated by the Minister in terms of section 34(1)(c) and (d) of the Electricity

Regulation Act, 2006 (Act No. 4 of 2006) (‘the Act’).

‘Capacity’ means, in relation to a Unit or the Facility, at any time and from time to

time, the output power (expressed in megawatts or MW) of such unit, as the case

may be.

‘Dispatch’ means the scheduling, coordination and management of the flow of

electricity produced by generation facilities or consumed by the demand-side

resource into and out of the national transmission power system, including the

start-up and shut-down of those facilities.

‘Dispatchable’ means the System Operator (SO) is authorised to influence the

dispatch of the generator or demand-side resource, and the generator or demand-

side resource is able to respond to automatic or manual SO dispatch instructions.

‘Energy’ means the electricity produced by, flowing through or supplied by an

electric circuit over a particular time interval, being integral with respect to the time

of the instantaneous power, measured in units of watt-hours (Wh) or standard

multiples thereof, i.e.:

a) 1 000 Wh = 1kWh

b) 1 000 kWh= 1 MWh

c) 1 000 MWh= 1 GWh

d) 1 000 GWh = 1 TWh


5

‘Energy Storage’ means a complete electric storage system that can be

connected to the Grid. It comprises two major subcomponents: storage and the

power conversion electronics. It mediates between variable sources and variable

loads.

‘Eskom’ means Eskom Holdings Limited contemplated in section 3(1) of the

Eskom Conversion Act, 2001 (Act No.13 of 2001.

‘Government’ means the Government of the Republic of South Africa.

‘Independent Power Producer (IPP)’ means any person in which the

Government or any organ of state does not hold a controlling ownership interest

(whether directly or indirectly), which undertakes or intends to undertake the

development of new generation, pursuant to a determination made by the Minister

in terms of section 34(1) of the Act.

‘Minister’ means the Minister of Mineral Resources and Energy.

‘National transmission company’ or ‘NTC’ means the person licensed to

execute the national transmission responsibility, in its capacity as such, including

the transmission network service provider, which maintains and develops the

transmission network, but excluding the system operator.

‘New generation capacity’ means:

a) electricity generation capacity other than the capacity of existing generation

facilities;

b) the electricity derived from the capacity referred to in (a); and

c) ancillary services relating thereto, individually or in any combination thereof,

and including an increase in the electricity generation capacity of existing

generation facilities.

‘New generation capacity project’ means a project for the development of new

generation capacity, pursuant to a determination made by the Minister in terms of

section 34 of the Act.

‘Organ of state’ bears the meaning ascribed to it in section 239 of the Constitution.

‘Power Purchase Agreement (PPA)’ means an agreement concluded between a

generator and a buyer for the sale and purchase of new electricity generation

capacity or electricity derived therefrom, or both.


6

‘Procurer’ means the person designated by the Minister in terms of section 34 of

the Act as being responsible for the preparation, management and implementation

of the activities related to procurement of new generation capacity under an IPP

procurement programme, including the negotiation of the applicable power

purchase agreements. The procurer may or may not be a buyer.

‘Self-dispatch’ refers to an operating regime where a generating unit or facility

output is determined by the generator under normal system conditions, except

where curtailment rules apply.

‘The Act’ means the Electricity Regulation Act, 2006 (Act No.4 of 2006).


7

1. LEGAL MANDATE

1.1. Section 4(c) of the National Energy Regulator Act, 2004 (Act No. 40 of

2004) empowers the National Energy Regulator of South Africa

(NERSA) with the responsibility to undertake the functions detailed in

section 4 of the Electricity Regulation Act, 2006 (Act No. 4 of 2006) (‘the

Act’).

1.2. The Act sets out the powers and functions of NERSA. In accordance

with section 34 of the Act, the Minister of Mineral Resources and Energy

(‘the Minister’) may, in consultation with the Energy Regulator:

a) determine that the new generation capacity is needed to ensure the

continued uninterrupted supply of electricity;

b) determine the types of energy sources from which electricity must

be generated, and the percentages of electricity that must be

generated from such sources;

c) determine that the electricity thus produced may only be sold to the

persons or in the manner set out in such notice;

d) determine that electricity thus produced must be purchased by the

persons set out in such notice; and

e) require that new generation capacity must:

i. be established through a tendering procedure which is fair,

equitable, transparent, competitive and cost-effective, and

ii. provide for private sector participation.

1.3. In performing its mandated functions, NERSA is required to ensure that

the following objects are achieved:

a) the efficient, effective, sustainable and orderly development and

operation of electricity supply infrastructure in South Africa;

b) that the interests and needs of present and future electricity

customers and end users are safeguarded and met, having regard

to the governance, efficiency, effectiveness and long-term

sustainability of the electricity supply industry within the broader

context of economic energy regulation in the Republic;

c) that investment in the electricity supply industry is facilitated;

d) that universal access to electricity is facilitated;

e) that the use of diverse energy sources and energy efficiency is

promoted; and

f) that competitiveness and customer and end-user choice are

promoted.


8

1.4. The powers entrusted to the Energy Regulator by the Act are

complemented by NERSA’s skills and competence in the regulation of

the electricity supply industry. NERSA is better positioned to decide,

influence and guide the direction that the electricity supply industry is

supposed to take. This is established through rules, guidelines and

codes of practice.

1.5. The Act has enjoined NERSA to fully participate in the establishment of

the new generation capacity. Failure by the Minister to receive NERSA’s

concurrence may result in the determination being unlawful and open

to legal challenge. NERSA’s role in the development of new generation

capacity is critical.

1.6. The Act further requires that any generation licence application should

be in line with the Integrated Resource Plan (IRP), otherwise such an

application shall be subject to approval by the Minister. It is widely

accepted that the IRP shall be implemented through a determination

made by the Minister in terms of section 34 of the Act. It is in this regard

that the participation of NERSA is central to the finalisation of a

determination.

1.7. In the past, NERSA used to receive draft determinations from the

Minister and concurred with the draft without observing the provisions

of section 10 of the National Energy Regulator Act. The practice was

challenged in the Western Cape High Court under the Earthlife case.

The court decided, among others, that the concurrence process that

must be observed by NERSA must be independent from the ministerial

process and it must observe the requirements of the National Energy

Regulator Act, read with the provisions of the Promotion of

Administrative Justice Act, 2000 (Act No.3 of 2000) (‘PAJA’).

1.8. Pursuant to the judgement, NERSA is now following the legally

permissible process, which insulates the decision-making process of

the Energy Regulator. This process should be appropriately recognised

as the end part of implementing the IRP and not the development,

amendment or review of such a policy. Part of the expectation that

NERSA should reflect in its consideration of the draft determination is

detailed in section 34(1), in terms of economic impact, public interest

and striking a fair balance between the interests of customers and end

users; and licensees and investors in the electricity supply industry.


9

1.9. The process that NERSA has undertaken satisfies the dictates of the

National Energy Regulator Act and PAJA, rendering the decision-

making process lawful. No deviation has taken place, as PAJA

recognises ‘notice and comment’ and ‘public hearings’ as stakeholder

participation processes.

2. BACKGROUND AND INTRODUCTION

2.1. On 21 February 2020, NERSA received the proposed determination

from the Minister in terms of section 34 of the Act, as detailed below

and attached hereto as Annexure A.

Determination under section 34(1) of the Electricity Regulation Act,

2006 (Act No. 4 of 2006)

2.2. The Minister, in consultation with NERSA, acting under section 34(1) of

the Electricity Regulation Act, 2006 (Act No. 4 of 2006) (as amended)

(the ERA) and the Electricity Regulations on New Generation Capacity

(published as GNR. 399 in Government Gazette No. 34262 dated 4 May

2011 (‘the Regulations’), has determined as follows:

2.3. That new generation capacity needs to be procured to contribute

towards energy security, accordingly:

2.3.1. 6 800 megawatts (MW) should be procured to be generated from

renewable energy sources [Photovoltaic (PV) and Wind], which

represents the capacity allocated under the headings ‘PV’ and

‘Wind’, for the years 2022 to 2024, in Table 5 of the Integrated

Resource Plan for Electricity 2019 – 2030 (published as GN 1360 of

18 October 2019 in Government Gazette No. 42784 (‘IRP 2019’).

2.3.2. 513MW should be procured to be generated from storage, which

represents the capacity allocated under the heading ‘Storage’, for the

year 2022, in Table 5 of the Integrated Resource Plan for Electricity

2019 – 2030 (published as GN 1360 of 18 October 2019 in

Government Gazette No. 42784 (‘IRP 2019’).


10

2.3.3. 3 000MW should be procured to be generated from gas, which

represents the capacity allocated under the heading ‘Gas and

Diesel’, for the years 2024 to 2027, in Table 5 of the Integrated

Resource Plan for Electricity 2019 – 2030 (published as GN 1360 of

18 October 2019 in Government Gazette No. 42784 (‘IRP 2019’).

2.3.4. 1 500MW should be generated from coal, which represents the

capacity allocated under the heading ‘Coal’, for the years 2023 to

2027, in Table 5 of the Integrated Resource Plan for Electricity 2019

– 2030 (published as GN 1360 of 18 October 2019 in Government

Gazette No. 42784 (‘IRP 2019’).

2.4. Electricity produced from the new generation capacity (‘the electricity’)

shall be procured through one or more tendering procedures that are

fair, equitable, transparent, competitive and cost-effective and shall

constitute Independent Power Producer (IPP) procurement

programmes as contemplated in the Regulations (‘procurement

programmes’).

2.5. The procurement programmes shall target connection to the Grid for the

new generation capacity as soon as reasonably possible in line with the

timetable set out in Table 5 of the IRP 2019. Deviations from the

timetable set out in Table 5 are permitted to the extent necessary, taking

into account all relevant factors, including prevailing energy security

risks, the time required for efficient procurement and the required

construction timelines for such new generation capacity facility.

2.6. The electricity may only be sold to the entity designated as the buyer in

paragraph 2.9 below, and only in accordance with the power purchase

agreements and other project agreements to be concluded in the course

of the procurement programmes.

2.7. The procurer in respect of the procurement programmes will be the

Department of Mineral Resources and Energy.

2.8. The role of the procurer will be to conduct the procurement

programmes. This includes preparing any requests for proposals and/or

related and associated documentation, negotiating the power purchase

agreements, facilitating the conclusion of the other agreements and


11

facilitating the satisfaction of any conditions precedent to financial close

that are within its control.

2.9. The electricity must be purchased by Eskom Holdings SOC Limited.

2.10. The electricity must be purchased from Independent Power Producers.

3. THE DECISION-MAKING PROCESS

3.1. On 21 February 2020, NERSA received a proposed determination for

the procurement of new generation capacity from Renewables (Wind

and PV), Storage, Gas and Coal technologies from the Minister in terms

of section 34 of the Act.

3.2. On 16 March 2020, NERSA’s Electricity Subcommittee (ELS), through

a round robin process, approved the NERSA Consultation Paper on the

proposed procurement of new generation capacity.

3.3. On 18 March 2020, NERSA published the consultation paper,

requesting stakeholders to submit written comments. This enabled

NERSA to appropriately apply its regulatory reviews and decision

making prior to concurrence with the Minister.

3.4. The closing date for the submission of comments was 7 May 2020.

3.5. It was envisaged that the process would include public hearings,

however the COVID-19 pandemic made it difficult for this to be possible.

The Energy Regulator made a decision to suspend its public hearings

until government indicates that it is safe to conduct them.

3.6. Furthermore, due to the comprehensive submissions from stakeholders

and the detailed questions in the consultation paper, NERSA ensured

that the written comments were sufficient to assess the information from

stakeholders

3.7. The Energy Regulator made its decision regarding this Ministerial

Determination on 29 July 2020.


12

4. STAKEHOLDER COMMENTS

4.1. NERSA received 44 written stakeholder comments in response to the

Consultation Paper.

4.2. Comments were received from, among others, Eskom, IPPs,

municipalities, energy specialists, energy developers, mining houses,

environmentalists, and consulting engineers/lawyers.

4.3. The written comments were taken into consideration during the

consideration of the determination and are also recognised in this

Reasons for Decision (RfD) document. The written comments, as well

as NERSA’s analysis thereof, is attached as Annexure B: Summary

of stakeholder comments.

4.4. Below is a list of all stakeholders who submitted written comments:

1. Eskom

2. City Power

3. Subsolar Energy Holdings

4. Sustainable Energy Africa (SEA)

5. Cobra South Africa

6. Siemens Energy Proprietary

7. Accoina Energy South Africa Global (AESAG)

8. LWS Family Office

9. Africa Energy Storage Solutions (AESS)

10. Wartsila

11. Project 90

12. York Timbers Energy

13. The Green Connection

14. Organisation undoing Tax Abuse (OUTA)

15. Green Cape

16. Minerals Council South Africa

17. IX Engineers

18. Frans Electrical Engineering Consulting (FEEC)

19. Centre for Environmental Rights

20. G7 Renewable Energies

21. General Electric SA (GE)

22. City of Cape Town

23. Wind Lab SA

24. Mhlathuze Energy


13

25. Enel

26. Building Energy SA (BESA)

27. Monetizing Gas Africa

28. Mainstream Renewable Power SA

29. RESA Group

30. Gravitricity

31. Fieldstone

32. South African Wind Energy Association (SAWEA)

33. Energy Exchange of SA

34. ED Platform

35. Ministry of Finance and Economic Opportunities

36. COEGA Development Corporation

37. European Union

38. South African Photovoltaic Industry Association

39. Enercon

40. Vantage Greenx (VGX)

41. Green Peace Africa

42. Total Mulilo Consortium

43. South African Independent Power Producers Association

(SAIPPA)

44. Lesedi

5. ANALYSIS OF DETERMINATION

5.1. Introduction

5.1.1. The IRP 2019 published on 18 October 2019 contained the following

new generation plan until 2030, as depicted in Table 1 below.


14

Table 1: The IRP 2019 to 2030 results

5.1.2. The Integrated Resource Plan (IRP) is a strategic electricity plan for

the country to meet the forecast annual peak and energy demand,

plus an established reserve margin, through a combination of supply-

side and demand-side resources over a specified future period. It is

developed to ensure security of electricity supply for the country

when looking into the future at least cost to the consumer, while

ensuring a balance of multiple country policy objectives.

5.1.3. As a portion of the Eskom fleet is reaching its end of life, 5 400MW

will be decommissioned by 2022; this will increase to 10 500MW by

2030. Furthermore, the coal fleet’s plant performance has declined

over the past decade, which has resulted in a loss of security of

electricity supply to the country.

5.1.4. The poor performance of the Eskom fleet (currently and in the recent

past) combined with the upcoming decommissioning of some of the

coal fleet that is reaching its end of life, as well as the environmental

commitments that the country has made to reduce greenhouse gas

emissions, is resulting in an energy transition within the electricity

sector. New capacity is needed to continue to meet the current and

future demand. The environmental targets call for cleaner

technologies to be included in the energy mix by closing the supply

Coal

Coal

Decomm Nuclear Hydro Storage Wind CSP

Gas &

Diesel

Other (DG, CoGen,

Biomass, Landfill

Current Balance 37 149 1 860 2 100 2 912 1 980 300 3 830 499

2019 2 155 -2 373 244 300

2020 1 433 -557 300

2021 1 433 -1 403 818

2022 711 -844 513 400 1 000 1 600

2023 750 -555 1 600 500

2024 1 860 1 600 1 000 500

2025 1 600 500

2026 -1 219 1 600 500

2027 750 -847 1 600 2 000 500

2028 -475 1 600 500

2029 -1 694 1 575 1 600 500

2030 -1 050 2 500 1 600 500

Total Installed by 2030

(MW) 1 860 4 600 5 000 17 742 600 6 830

% Total Installed Capacity

(% of MW) 2,36 5,84 6,35 22,53 0,76 8,1

% Annual Energy

Contribution (% of MWh) 4,5 8,4 1,2 17,8 0,6 1,3

Installed Capacity

Committed / Already Contracted Capacity

Capacity Decommissioned

New Additional Capacity

Extension of Koeberg Plant Design Life

Includes Distributed Generation Capacity for own use

7 288

10,52

6,3

PV

33 364

43

58,8

Allocation to the

extent of the short

term capacity and

energy gap

1 474

114

300

1 000

1 000

1 000

1 000

1 000


15

gap and being aligned to the policy position of diversifying energy

sources.

5.1.5. This concurrence is aimed at ensuring that, at any given time when

looking at the short/medium to long term, the supply–demand

balance is maintained. The procured capacity must therefore be built

on time, thereby promoting the orderly development of the electricity

industry, as well as guaranteeing security of supply. Furthermore,

NERSA must assess that the capacity to be procured is still

appropriate and aligned to both country imperatives and global best

practices.

5.1.6. The IRP divided results into immediate-term results, as well as long-

term results. The immediate-term plan was implemented through the

first determination for the procurement of 2000MW for various energy

sources to cover electricity supply shortages for the period 2019 to

2020. The long-term plan is as outlined in Table 1 above.

5.1.7. Table 2 below shows a summary of the capacity as determined by

the Minister.

Table 2: Summary of Determinations as received from DMRE

TECHNOLOGY CAPACITY (MW) TIME HORIZON IN IRP 2019

PV & Wind 6 800 2022 - 2024

Storage 513 2022

Gas & Diesel 3 000 2024 - 2027

Coal 1 500 2023 - 2027

Total 11 813 MW

5.2. Renewable Capacity (Wind & PV) Analysis

5.2.1. The draft determinations determined that 6 800 megawatts (MW)

should be procured to be generated from renewable energy sources

(PV and Wind), which represents the capacity allocated under the

headings ‘PV’ and ‘Wind’, for the years 2022 to 2024, in Table 5 of

the IRP 2019.


16

System Impact of RE Stakeholder Comments

5.2.2. The majority of stakeholders agree with the draft Ministerial

Determination that 6 800MW should be procured to be generated

from renewable energy sources (PV and Wind).

5.2.3. Some stakeholders indicated that this 6 800MW should be procured,

provided that there is backup generation.

5.2.4. Some stakeholders indicated that 6 800MW is not enough and are

proposing that higher capacities for Solar PV and Wind be procured

until 2030.

5.2.5. Stakeholders had mixed views, as some agreed that it is possible for

solar PV and Wind plants to reach the Commercial Operating Date

(COD) by 2022, while others were of the opinion that for projects to

be operational by 2022, the procurement should have already

commenced.

NERSA Analysis

5.2.6. The recently gazetted IRP2019 went through a full consultation

process, over a period of more than three years, therefore the

analysis and modelling conducted was adequate to determine the

new energy sources and the timing of bringing online new generation

capacity.

5.2.7. Assumptions used during the development of the IRP2019 have

considered the demand projections and the associated costs of

technology options. A number of scenarios were considered in the

modelling, and in the end, a least cost and policy adjusted option was

selected.

5.2.8. The IRP2019 that was gazetted on 18 October 2019, is the only

approved plan that the Minister uses when making Determinations,

in line with section 34 of the Electricity Regulation Act. Regarding

the use of annual limits for Wind and PV, NERSA’s position is that

other long-term models being proposed by stakeholder would need

to be subjected to a comprehensive public consultation process to be


17

acceptable. Therefore, NERSA is of the view that this Ministerial

Determination is in line with the approved IRP2019.

5.2.9. Based on the approved IRP2019, for the Short-Term (ST) and

Medium-Term (MT), the determined capacity will be able to ensure

uninterrupted supply of electricity. Indications from page 85 of the

IRP2019 is that imposing annual build limits on Renewable Energy

(RE) will not affect the total cumulative installed capacity and the

energy mix for the period up to 2030.

5.2.10. Renewable Energy projects that are at advanced stages of

development (i.e. have acquired environmental permits) can achieve

COD in the planned period. Furthermore, lessons learned from

existing Renewable Energy Independent Power Producer

Procurement Programme (REIPPPP) projects could be used to fast-

track the implementation of the IRP2019 and the development of

projects.

RE Technology Analysis

Stakeholder Comments

5.2.11. Most stakeholders indicated that the deployment of these

technologies is in line with best practices and that these technologies

also serve to ensure that there is security of power supply in the

country.

5.2.12. Some stakeholders indicated that this is line with best practice,

because these technologies have continually demonstrated a

reduction in costs.

5.2.13. The views of the stakeholders are divided on the inclusion of storage

of these technologies to assist the power system during peak

periods. Most stakeholders agree that storage should be considered

for Wind and Solar PV, but have indicated that it should not be used

as a criterion to select projects.

5.2.14. Some stakeholders indicated that storage should not be included

with these technologies because, by nature, they are dispatchable.

Some stakeholders indicated that storage requirements will be

determined by the system operator.


18

5.2.15. Stakeholders are divided on whether the sources should be

dispatchable. Most stakeholders indicated that dispatchability will be

good for backing up generation from PV and Wind, but it should not

be a requirement for these technologies as they are not dispatchable

by nature. A few stakeholders indicated that dispatchability is not

needed for these technologies.

NERSA Analysis

5.2.16. Wind and solar PV technologies were determined using the best

practices relevant during the IRP development process. One of the

outcomes of IRP2019 is aimed at diversifying energy sources and

energy efficiency. The 2008 White Paper for Renewable Energy

identified these technologies as energy sources the country will

utilise going forward.

5.2.17. Storage is important in ensuring that the security of power supply is

maintained during peak periods. The combination of Wind and Solar

PV in REIPPP projects has shown that solar is available during the

hours of the day, but it is not available for the evening peak. Wind

power is available during the day and night, but it is variable. Storage

could be used to smooth out the variability and assist the system

when solar PV output is diminishing towards the evening.

5.2.18. Dispatchability is important for the power system’s stability. The

current annual output of RE is around 7%, which is lower than the

RE penetration level of 20% that the system operator indicated as a

level that would begin to introduce complexities in the power system1.

Based on the above response provided by the DMRE on risk

considerations of variable resources in the IRP2019, having

dispatchability (or storage) for each RE power plant should not be

used as a requirement for selecting solar PV and wind power plants.

However, if project developers are willing to include storage within

the power plant, they should be incentivised for storage, since it can

be used for ancillary services. Furthermore, storage systems would

have to be based on the system operator’s requirement to ensure

that they are dispatched when needed, and would be also able to

recover the costs of investment.

1 Response to IRP comments by DMRE on Risk Considerations of Variable Capacity from Renewable Sources

impacting on System Security and Stability, IRP2019 (page 46 of 94).


19

Risks Associated with RE Stakeholder Comments

5.2.19. Most stakeholders indicated that technologies have minimal risks,

but indicated that risks are possible procurement delays, and capital

costs that are exposed to foreign exchange risks due to the

requirement to import significant content for power plant materials.

They also stated that the uncertain economic outlook in South Africa

and the deteriorating sovereign credit rating pose risks to the

international appetite.

5.2.20. A few stakeholders indicated that Wind and Solar PV technologies

present risks because its resource is intermittent.

NERSA Analysis

5.2.21. Project risks during the procurement process can be managed, as

the country has gained experience from operating the REIPPPP

projects. Provided that there are no delays in the procurement

process, risks associated with foreign exchange exposure should be

manageable. The risks associated with economic outlook are,

however, difficult to predict as they are affected by global market

forces. The Request for Proposal (RFP) will address the issue of the

bid validity period beyond which IPP costs would have to be revised

to adjust for delayed procurement.

5.2.22. The risks around the intermittency of Wind and Solar PV were raised

during the development of the IRP 2019. The response from the

DMRE was that at low levels of penetration, fluctuating renewable

energy will only have a marginal impact on the system. The DMRE

further responded that considering the South African energy

generation mix and demand profile, there is a point at which an

isolated system would have to adjust the power system and network

operations if not configured to cater for the variability of this energy.

The system operator indicated that at about 20% of renewable

energy in the energy mix, ancillary service requirements would start

to increase.


20

RE Generator Size Stakeholder Comments

5.2.23. Some stakeholders indicated that RE generators could be any size,

but it will depend on the availability of the grid, at the point of

connection. Some stakeholders stated that the minimum size should

be 75MW and the maximum cap should be removed.

NERSA Analysis

5.2.24. Since the connection of power plants is dependent on the availability

of capacity at various substations, the suitability of power plants sizes

should be determined by the network owner, taking into account the

availability of capacity at the point of connection and the

requirements of the Grid Code. Bid Window 4 and small-scale REIPP

projects have demonstrated that it is possible to strike a balance

between capacity, size and cost for RE projects.

Socio-Economic Impact of RE Stakeholder Comments

5.2.25. Most stakeholder indicated that both technologies have potential for

job creation. Others indicated that opportunities should be explored

to develop manufacturing of renewable energy components locally.

5.2.26. Some stakeholders have indicated that RE created very few jobs in

South Africa.

NERSA Analysis

5.2.27. Based on the IPP Office’s Quarterly Reports2, RE has the potential

to create many Socio-Economic Development (SED) benefits

through localisation of manufacturing, construction and steady jobs.

5.2.28. The highlights of the report were that:

a) The REIPPP programme resulted in an investment to the value of R209.7 billion, of which 41.8 billion was from foreign markets.

2 IPP Office Report (31 March 2019), Independent Power Producers Procurement Programme (IPPPP): An

Overview


21

b) REIPPP created 40 134 job-years for South African citizens to date.

c) To date, the programme has contributed R860.1 million towards socio-economic development.

d) The programme has contributed 276.7 million towards enterprise development.

5.2.29. The potential to increase local manufacturing and assembling plants

exists, since there are already manufacturing companies in the

country, such as Tenesol Pty (Ltd) (PV module manufacturer); ART

Solar in Durban, and ILB solar (PV manufacturer).

5.2.30. Experiences gained from the current REIPPPP could be used and

improvements on SED goals can be achieved in future procurement

programs to implement the IRP2019.

Cost Associated with RE Stakeholder Comments

5.2.31. All stakeholders indicated that the costs of RE have dropped over the

years. This was demonstrated in the REIPPPP bid windows and CSIR studies.

NERSA Analysis

5.2.32. The 2019 International Renewable Energy Agency (IRENA) report

indicates that the price of solar PV has decreased from

US$0.378/KWh in 2010 to US$0.068/kWh in 2019. This represents

82% decrease in solar PV energy prices over the nine-year period.

For onshore wind technology, the same report indicates that the

global average energy prices have decreased by 38% from

US$0.086/kWh in 2010 to $0.053/kWh in 2019.

5.2.33. Furthermore, data from licensees obtained by NERSA also indicate

that the costs of Wind and Solar PV technologies have decreased

substantially over the past ten years. Figure 1 from the DMRE IPP

Office report illustrates how the average prices have decreased from

2011, when large-scale RE was introduced into the country, until the

last bidding phase conducted in 2015.

5.2.34. The introduction of cheaper RE options, as demonstrated in Bid

Window 4 of the REIPPP, together with flexible options, such as


22

storage and gas in IRP2019, while using a least cost plan, will result

in sustainable energy industry for the future.

Figure 1: Portfolio price trends in April 2019. [Source: DMRE IPP Office

December 2020]

5.2.35. Figure 2 shows the impact of the lower prices of BW4 on the overall

price of RE on the grid. As a result of the low price and high energy

output of BW4 power projects (shown in Figure 1), the average real

price of renewables in the Multi-Year Price Determination 4 (MYPD4)

of Eskom is expected to decrease over the next three years.

Figure 2: Average price of RE over the Multi-Year Price Determination

periods [Source: NERSA analysis, February 2020]


23

5.3. Storage Capacity Analysis

5.3.1. The draft determinations concluded that 513 MW should be procured

to be generated from storage, which represents the capacity

allocated under the heading ‘Storage’, for the year 2022, in Table 5

of the IRP 2019. The NERSA consultation paper asked stakeholders

to provide written comments on the issues that were raised under

storage.

System Impact of Storage Stakeholder Comments

5.3.2. Several stakeholders agreed that 513 MW should be procured to be

generated from storage to cover short-term variations in electricity

generated capacity to meet the demand.

5.3.3. Stakeholders also indicated that storage should be considered in

combination with renewable technologies like Wind and PV so that it

can provide hybrid solutions to store excess energy from renewables

during off-peak periods and use it as a dispatchable load to balance

the system when it is needed most.

5.3.4. Stakeholders had mixed views. Some agreed that it is possible for

energy storage plants to reach the COD by 2022, while others were

of the opinion that for projects to be operational by 2022, they should

have already commenced with construction.

NERSA Analysis

5.3.5. The system requirements present an opportunity to diversify the

energy mix. The set capacity procured under energy storage will also

contribute to ancillary services to ensure that system stability is not

compromised.

5.3.6. Furthermore, the traditional power delivery model is being disrupted

by technological developments related to energy storage, therefore

more renewables can be harnessed in a complementary relationship

between energy storage and self-dispatchable renewable energy

technologies like Wind and PV.


24

5.3.7. Therefore, the System Operator is encouraged to conduct network

studies that are aimed at ensuring that the energy storage

technologies can contribute positively to minimise forced outages

and partial load losses, and be used as hybrid solution to renewable

energy technologies and as reserve requirements.

5.3.8. The system requires battery storage that can be used as a

complementary resource for renewables from IPPs, especially Wind

and PV. The System Operator can use the historic profiles from year

2013 to 2019 of all contracted build of REIPP from Bid Window 1 to

Bid Window 4, to create a median profile that will determine how

much energy can be stored during periods of low demand, to be used

later during peak hours.

5.3.9. The system requires reserves to balance the system when

unexpected events occur, such as customer demand fluctuations,

changes in the availability of supply capacity, and generation

variations from intermittent plant. Therefore, energy storage from the

system perspective can play a major role in providing these reserves.

5.3.10. The energy storage can also help the system from a stability

perspective. This would result in a reduced need for demand

response that the System Operator normally utilises by reducing

certain loads by instruction, thereby increasing Eskom’s sales.

5.3.11. NERSA is of the view that some energy storage can achieve COD

by 2022 as energy storage technologies can easily be integrated into

the existing renewable plants and the national Grid. This can be

achieved by utilising the increased output from the existing plants,

which is in line with the definition of the new generation capacity.

According to the IRP 2019 Electric Power Research Institute (EPRI)

report, plant lead time for battery storage is one year. The 2022 COD

is therefore achievable, provided there are no procurement delays.

Storage Technology Analysis Stakeholder Comments

5.3.12. Stakeholders agreed that energy storage was determined in line with

best practices as it will reduce the carbon footprint caused by coal-

fired power stations.


25

5.3.13. Stakeholders also proposed that the energy storage technology

should be informed by network studies to determine whether it can

be used instead of Open Cycle Gas Turbines (OCGTs) to reduce

peak demand and load shedding.

5.3.14. Some stakeholders proposed that the best practice should allow

municipalities to also install energy storage on their network so that

they can reduce the cost of bulk supply from Eskom.

5.3.15. Stakeholders disagreed that storage must only be limited to battery

technology, as there are many other types of storage technologies

that are more mature than battery storage, such as pumped hydro

technology.

5.3.16. Stakeholders proposed the consideration of other energy storage

technologies that include hydro pumped storage, crane storage, CSP

plants with storage, compressed air energy storage (CAES), and

liquid air energy storage (LAES).

5.3.17. Some stakeholders proposed that thermal plants, like cogeneration

and biomass, should be given preference over energy storage

because they are more commercialised and mature.

NERSA Analysis

5.3.18. The energy storage was determined in line with best practices, as it

can play a major role in the provision of reliable energy generation

that the System Operator can dispatch according to the scheduling

and dispatch rules. These include:

a) Demand smoothing and energy arbitrage. This concept promotes

storing of excess energy produced by renewables to be used later

when it is needed most, such as during peak-periods. Energy

arbitrage lowers the cost of dumped energy in take-or-pay Power

Purchase Agreements and reduces the need to generate more

electricity or to use expensive peaking plants like OCGTs.

b) Ancillary services:

i. Spinning reserves: This is a generating capacity or demand

side managed load fully available within 10 seconds to arrest

frequency excursion outside of the frequency dead-band.


26

The reserve response must be sustained for at least 10

minutes. It is needed to arrest the frequency at an acceptable

level following a contingency, such as a generator trip, or a

sudden surge in load.

ii. Black start: This is a facility that must be able to start on its

own when certain parts of the power system were

interrupted, energising a portion of the transmission network

and starting up other connected base load generators as part

of the restoration of interrupted power system. Black start

facilities are also a Grid Code requirement for the System

Operator.

iii. Islanding: This is a facility/generator that is capable of

maintaining its own stability and supplying its own auxiliaries

while being disconnected from the interrupted power system.

iv. Reactive power supply and voltage control: Reactive

power supply and voltage control form part of the ancillary

services required by the System Operator to efficiently

perform its main function of supplying electric power while

maintaining the required levels of supply quality and security.

v. Constrained Generation: This is a requirement that a

System Operator must manage in real time when the system

is constrained so that it operates within safe operating limits.

It requires multiple outages of a credible nature to be studied

to ensure that the operation of the system protects against

cascading outages for such an event. The System Operator

is required to identify the system constraints over a 5-year

horizon in line with the Multi Year Price Determination

(MYPD) and thereafter draw conclusions on the need for this

service.

c) Complementing renewables and reducing emissions: In this

case, energy storage is used as a solution to store energy from

renewable energy sources, such as Wind and Solar power, that

are intermittent and variable, so that when the wind is not blowing

and the sun is not shining, they can still produce clean energy that

has been stored, thus reducing emissions caused by fossil fuels.


27

5.3.19. The above roles of energy storage are the best practices relevant at

the time and ensure the mandate of security of supply. It also meets

the objective of ensuring the use of diverse energy sources and

energy efficiency.

5.3.20. The System Operator is then empowered by the Grid Code to

develop a medium-term view in the 5-year term horizon of the plants

that will be required to perform these functions. It is also capable of

contributing to meeting the demand response and becoming

available at the instruction of the System Operator, as set out in

Table 3.

Table 3: Reserves requirements (MW)

Source: Eskom’s Medium-Term System Adequacy Outlook 2019

5.3.21. Energy storage will play a crucial role in enabling the next phase of

energy transition due to the expected decommissioning of

approximately 24 100 MW of coal power plants in the period beyond

2030, until 2050.

5.3.22. The practice of allowing municipalities to install energy storage is

supported. However, this will follow a different procurement process.

The DMRE has recently gazetted the draft amendments to the

electricity regulations on new generation capacity that are aimed at

receiving stakeholder inputs so that municipalities can establish new

generation capacity in line with the IRP. They would have to meet the

requirements of the Public Finance Management Act (PFMA), as well

as undertake feasibility studies in respect of such new generation

capacity requirements.

Type Season Period 2019/20 2020/21 2021/22 2022/23 2023/24

Instanteneous Peak 650 650 650 650 650

Off Peak 850 850 850 850 850

Peak 650 650 650 650 650

Off Peak 850 850 850 850 850

Regulating Peak 450 450 450 450 450

Off Peak 450 450 450 450 450

Peak 550 550 550 550 550

Off Peak 550 550 550 550 550

Ten minute Peak 1 100 1 100 1 100 1 100 1 100

Off Peak 900 900 900 900 900

Peak 1 000 1 000 1 000 1 000 1 000

Off Peak 800 800 800 800 800

Summer 1 000 1 000 1 000 1 000 1 000

Winter 800 800 800 800 800

Supplemental

Demand Response 300 300 300 300 300

1 900 1 900 1 900 1 900 1 900

Peak Load

Reduction

Instanteneous

Demand Response

Emergency Reserves

Summer

Winter

Summer

Winter

Summer

Winter


28

5.3.23. This will then support the ‘behind the Eskom’s meter’ applications to

increase the municipal self-consumption of decentralised generation,

thus reducing the amount of power obtained from Eskom.

5.3.24. The system requirements present an opportunity to diversify the

energy storage technologies in order to meet the country’s policy

goals for secure, reliable and affordable energy.

5.3.25. The following energy storage technologies can provide a real-time

balance of supply and demand to ensure an equilibrium that

maintains the voltage and frequency of the alternative current

system.

Table 4: The types and the role of energy storage

Technology Type Role in system operation

Pumped hydro

CAES & LAES

Provision of inertia and long duration of storage

Batteries

Flywheels

Fast frequency response

Batteries

Flywheels

Pumped hydro

Operational reserves

CAES & LAES

Pumped hydro

Flow batteries

Load following and time shifting

5.3.26. The IRP 2019 took into consideration the latest available information

and ran scenarios that resulted in energy storage being allocated

513 MW by 2022. Therefore, it cannot be replaced by biomass and

cogeneration, as these technologies have their own allocation in the

IRP 2019.

Storage Generator Size Stakeholder Comments

5.3.27. Stakeholders indicated that the plant size should vary between

10 MW and 100 MW per IPP, but should not exceed 160 MW,

because it will require a full environmental impact assessment (EIA)

that normally takes more than two years to obtain. As a result, the

COD of 2022 would be missed.


29

5.3.28. Some stakeholders proposed that there be should no plant size limit

and preference should be given to small installations that will be

distributed all over the national Grid.

NERSA Analysis

5.3.29. Preference should be given to plant sizes that will bring one of the

following network benefits to the national Grid at different business

wires (Generation, Transmission and Distribution), as detailed in

Table 5 below.

Table 5: Roles and benefits of energy storage across three business wires

*** Source: Madison, C. Richard, L.R. Burcin, U. April 2018. Managing the future of Energy storage by New York University

5.3.30. The minimum and maximum plant size should be based on the

system needs and the benefits each storage technology will bring to

the national Grid, either at Generation, Transmission or Distribution

level. These needs should be based on network studies that must be

conducted by the designated buyer.

Management of take or pay resources

To store excess capacity (dumped energy) when the demand is low

and using it during peak periods, thus reduce the over usage of

OCGTs.

Resource adequacy

Charging during off-peak hours and discharge during peak hours and

thus reduce the need of additional capital expenditure (Capex) for

infrastructure investment.

Variable resource integrationWhen storage is used as a hybrid solution with renewables. It will

help by using the much needed energy during peak-periods

Frequency regulationGrid instability is prevented by ensuring that generation is matched

with consumer demand

Ramping It counteracts the effects of varying renewable generation

Spinning reservesIt provides extra generation in the event of unexpected energy

shortfall.

Voltage supportTo maintain required levels of voltage in order to match the demand

or work as a voltage regulator.

Improve performanceIt can work as a voltage regulator to those parts of the network that

experience low voltage

Frequency regulation, ramping and voltage

supportAs explained at Generation level

Mitigation of outagesStorage can be discharged in the event of a power outage of short-

duration.

Distribution infrastructure deferralIt can delay the need of additional capital expenditure (Capex) for

infrastructure investment.

Frequency regulation, ramping and voltage

supportAs explained at Generation level

At Generation level

At Transmission level

At Distribution level


30

5.3.31. Therefore, the System Operator and Eskom should determine the

minimum and the maximum energy storage plant sizes after having

conducted the system requirement studies.

Risk Associated with the Storage technology Stakeholder Comments

5.3.32. Stakeholders elaborated on the initial operational understanding of

energy storage technologies as one of the major risks that may delay

the uptake of energy storage.

5.3.33. Stakeholders also expressed the risks associated with not correctly

specifying the energy storage size that will meet different system

needs.

5.3.34. Other stakeholders elaborated on the risk associated with network

studies not being conducted on time, which will result in energy

storage plants being connected where they are not most critically

needed by the Grid.

5.3.35. Some stakeholders elaborated on the risk associated with the short-

term Power Purchase Agreements (PPAs), which will make projects

not bankable.

NERSA Analysis

5.3.36. NERSA agrees with the stakeholders that some challenges will be

encountered with the initial operational understanding of energy

storage plants, however there are existing regulatory tools to militate

against any non-compliance with licence conditions.

5.3.37. Network studies will be required to correctly identify those parts of

the network that will require energy storage plants.

5.3.38. Furthermore, the network studies should indicate whether energy

storage can be used for an off-grid system or to energise certain

areas of the network under planned or unplanned outages.


31

5.3.39. NERSA only notes the PPA and approves the tariff therein. However,

history has shown that PPAs signed by IPPs and Eskom in South

Africa have a fair risk allocation.

Cost Associated with Storage technology Stakeholder Comments

5.3.40. Stakeholders indicated that when the energy storage technologies

are used as complementary resources to the existing renewables,

their tariff is in the margin of R0.50 per kWh.

5.3.41. Stakeholders also indicated that the cost of energy storage is very

high, but could be more affordable than the utilisation of OCGTs, as

these costs decrease as the technology becomes more mature and

commercially available.

5.3.42. Some stakeholders proposed that the energy storage should not be

considered under the principles of levelised cost of electricity

(LCOE), but under the principles of levelised cost of storage (LCOS).

NERSA Analysis

5.3.43. NERSA agrees that the energy storage technologies can be used in

a number of different ways to strengthen the network, which includes

using them as a hybrid solution to renewables.

5.3.44. According to technical data that is available from institutions like the

Electric Power Research Institution (EPRI), a certain number of

energy storage technologies have still not been commercialised and

are being piloted as demonstration plants. Once these demonstration

plants have been tested for operational flexibility and for Grid

compliance, they will be connected to the mainstream network with

minimal risk.

5.3.45. Table 6 provides a list of matured and commercially available energy

storage technologies that may reach the COD of 2022. This table is

not intended to compare technologies, but is provided as a guideline

of what can be expected as LCOE under 513 MW procurement.


32

Table 6: LCOE for technologies that may be considered under energy storage to reach the

COD of 2022

5.3.46. Table 6 does not only show the EPRI’s LCOE, but it also shows the

tariffs under the South African environment that were obtained by the

DMRE through its request for information (RFI) for projects that can

achieve a latest COD of December 2021.

5.3.47. The DMRE RFI revealed that there is approximately 1.7 GW of

capacity that can be made available at a tariff range of between

R0.55/kWh and R2.00/kWh on the existing renewable plants that can

just add energy storage for a 20-year PPA term.

5.3.48. It also revealed that approximately 300 MW of capacity from storage

can be connected to the South African Grid at a tariff that ranges

between R2.10/kWh and R2.71/kWh on a 20-year PPA term.

5.3.49. Therefore, these tariffs can ensure the long-term sustainability of the

electricity supply industry, as well as affordability in the South African

context. It must also be noted that the energy storage tariffs are

expected to decline in South Africa once they have undergone a

technology life cycle curve and learning curve, as they will be

commercialised, thus creating a competitive market within IPPs.

Technology Type

Specific Type of Technology Li-ion Li-ion CAES

Rated Capacity, MW net 3MW 3MW 180MW

Hours of Storage 3 6 9 12 1 3 8

Capacity Factor, % 39.5 51.0 60.3 69.7

Equivalent Availability 92 92 92 92 94.2 94.2 97.2

Economic Life 30 30 30 30 20 20 40

Fuel Cost (ZAR/MWh) 0 0 0 0 0 0 285.5

O&M (ZAR/MWh) 307.2 248.1 215.8 191.6 2,327.2 778.1 88.1

Capital Cost (ZAR/MWh) 3,659.9 3,485.9 3,340.6 3,230.7 4,994.7 3,980.4 1,445.5

EPRI LCOE, ZAR/MWh 3,967.1 3,734.0 3,556.4 3,422.3 8,654.7 6,141.3 2,738.5

DRME RFI LCOE for renewables

with storage, ZAR/kWh for a 20-

year PPA

DMRE RFI LCOE for energy

storage, ZAR/kWh for a 20-year

PPA 2.10 - 2.71

Central receiver

125MW

Solar Thermal Batteries powered by Wind Technology

0.55 - 2.00


33

Socio-economic impact of energy Storage plants Stakeholder Comments

5.3.50. Stakeholders indicated that energy storage plants create a very low

number of unskilled jobs, as it normally creates jobs for skilled

professionals during the design and manufacturing of energy storage

technologies.

5.3.51. Stakeholders also indicated that the potential for job creation is in the

manufacturing space of batteries and their components, but energy

storage technologies require very low maintenance during the plant

operation stage.

NERSA Analysis

5.3.52. NERSA is of the view that the energy storage technologies can

achieve other socio-economic objectives, even though it creates a

very low number of jobs. These include:

i. use of local content through, inter alia, increased local

manufacturing;

ii. fostering rural development and involving communities;

iii. enterprise development through the promotion of small

businesses packages for new entrants; and

iv. socio-economic development and participation by historically

disadvantaged citizens and marginalised regions in the

mainstream of the industry economy.

5.3.53. In conclusion, on the procurement of 513 MW from energy storage

technologies, NERSA did not receive any written comments from

stakeholders that object to the procurement of 513 MW from storage,

which represents the capacity allocated under the heading ‘Storage’,

for the year 2022, in Table 5 of the IRP 2019.

5.4. Gas and Diesel Capacity Analysis

5.4.1. The draft determinations determined that 3 000MW should be

procured to be generated from gas, which represents the capacity

allocated under the heading ‘Gas and Diesel’, for the years 2024 to

2027, in Table 5 of the IRP 2019.


34

Gas plants cost Stakeholder Comments

5.4.2. The majority of stakeholders raised concerns about the procurement

of gas power when there are alternatives in the market, such as

battery storage, that can play the same role in the power system

without the risk of uncertain imported Liquefied Natural Gas (LNG)

prices.

5.4.3. Most stakeholders questioned the viability of converting existing

diesel-fired OCGTs to LNG-fired gas turbines, with many issues that

can influence that decision, such as availability of LNG and existing

PPA conditions.

NERSA Analysis

5.4.4. According to IRP 2019 figures shown in Table 7 below, a wind plant

with 3 hours’ battery storage’s overnight cost is R27 432/kW. A Solar

thermal plant with 6 hours’ storage and 51% capacity factor’s

overnight cost is R107 135/kW. A Gas plant with Carbon Capture and

Storage (CCS) and 50% capacity factor’s overnight cost is

R22 262/kW. The average RFI tariff for a 20-year PPA gas plant is

R1.49/kWh, R1.78/kWh for solar/wind with storage and R3.43/kWh

for storage. When considering both the capital cost and RFI tariff, gas

generation is cheaper than the other technologies and therefore

more attractive.

Table 7: Overnight costs

5.4.5. The Inter-Connected Power System could still need more flexible gas

generation that can be run for extended periods as mid-

merit/baseload plants, thus providing more continuity of supply,

unlike battery storage, which has to recharge from time to time.

Technology type Storage CCGT without CCS CCGT with CCS ICE

Specific type of technology Lithium-Ion(Li-ion) Lithium-Ion(Li-ion)

Rated capacity,MW net 3 3 732 635 9.4

Storage hours 6 3 3

Capacity Factor % 51 50 50 50

Capital Cost R/kW 107135 27432 27432 10131 22262 15427

Capital Cost R/MWh 3485.9 3980.4 2597.6 339.1 734 454.2

LCOE EPRI,R/MWh 3734 6141.3 879.4 1451.8 1274

20yr PPA RFI R/MWh 34301250-2770 1060-1920

Solar Thermal Wind charged

Central receiver

125


35

5.4.6. Furthermore, Eskom is still developing a pilot battery storage plant to

enable the assessment and development of technical applications

and benefits. Regulatory tools that relate to a utility scale energy

storage technology are under development. This allocation will allow

for the enhancement of assumptions for future iterations of the IRP.

In the RFP, the System Operator should provide system

requirements to be met by energy storage and gas generation.

5.4.7. The business case to justify the conversion should be decided on a

case-by-case basis by the IPPs and Eskom. Issues such as load

factor of LNG Closed Cycle Gas Turbines (CCGT), changes to

existing PPA conditions and changes to existing PPA price would be

considered to make it economically viable for all parties. Decision 7

of IRP 2019 supported the conversion of existing diesel plants to gas

to support the development of gas infrastructure in the country, since

there will be increased gas consumption to justify new gas

infrastructure investments, while also reducing diesel fuel

expenditure.

Gas price uncertainty

5.4.8. The IRP final optimised model considered imported LNG at a price

of R63.9/GJ and it was projected that this price would not increase

beyond inflation. Exploration to assess the magnitude of local

recoverable shale and coastal gas are being pursued. Locally there

is enormous potential in the Brulpadda gas resource discovery in the

Outeniqua Basin, indigenous coal bed methane and shale gas.


5.4.9. All stakeholders raised concerns about the uncertain price of

imported gas, which depends on international commodity prices and

the ZAR/USD exchange rate fluctuations.

NERSA Analysis

5.4.10. The policy-adjusted IRP 2019 considered the economic

development needs of the country besides the technical least cost

optimisation for new generation resources. Development of the LNG

terminal and related infrastructure has other benefits to the country

in addition to producing electricity as per the Department of Trade


36

and Industry (DTI) Gas Industrialisation Policy and Gas Infrastructure

plan. The gas infrastructure investments will have a multiplier effect

to other economic sectors (industrial heating, petrochemicals,

transport, etc.).

5.4.11. It is therefore recommended that the PPA should consider the

imported gas price to be a pass-through cost to the consumer to

maximise efficiencies from international gas price and exchange rate

fluctuations. Furthermore, if domestic gas extraction projects

materialise, this would stimulate the growth of gas use because the

indigenous gas price will not be overly exposed to international

market forces.

Gas supply security

5.4.12. The IRP 2019 considered two options of gas supply in the short-

medium term, namely imported LNG, or piped-gas from the sub-

region (or domestic).


5.4.13. All stakeholders raised concerns about the lack of gas infrastructure

for the receiving, storage, transmission and distribution of gas to

ensure sufficient volumes for power generation. Furthermore,

stakeholders cited delayed implementation of gas-to-power projects

due to uncertainty in the development of gas infrastructure, which

would ultimately risk the country’s electricity security of supply.

NERSA Analysis

5.4.14. According to the DMRE the issue of gas supply will be addressed in

the Gas Infrastructure Plan. State-Owned Entities (SOEs) and other

government departments have conducted pre-feasibility studies on

the roll-out of gas infrastructure. It is therefore recommended that to

meet the 2024 deadline for grid connection of the first 1000MW,

temporary LNG infrastructure could be used (e.g. cryogenic

containers using road/rail transport). Liquefied Petroleum Gas (LPG)

could also be used while permanent LNG infrastructure is under

construction.


37

5.4.15. According to the 2019 McKinsey Energy Insight report, supply from

existing and under-construction facilities will peak around 2026 and

then remain largely flat as shown below. LNG demand growth will

increase significantly at 4.3% per annum over the next five years,

driven by Asia, and then slow down gradually, driven by new pipeline

additions and slow growth in gas demand.

5.4.16. Over 100 LNG projects totalling 100mtpa of capacity are competing

to fill the 125mtpa supply gap by 2035. Many of the marginal projects

are from the US. If SA domestic gas extraction projects materialise,

this reduced supply capacity post 2028 could be manageable both in

terms of volumes and price. Therefore, in the short to medium term,

there is a minimal risk of gas supply shortages for gas-to-power

projects in SA.

Figure 3: Global LNG available supply capacity and demand to 2035 (McKinsey Energy Insight 2019)

Gas Generator Size Stakeholder Comments

5.4.17. The acceptable minimum and maximum individual gas plant size

received a mixed reaction. Some stakeholders suggested a minimum

size of 800MW, because this is the optimum power plant size needed

to justify the importation of LNG on a large scale, assuming the gas

infrastructure is established. Others suggested plant sizes of

300MW–500MW per IPP, as this could allow healthy competition.


38

NERSA Analysis

5.4.18. It is recommended that the minimum plant size should be determined

by the IPP, after considering the available grid connection capacity,

the availability of gas volumes and ultimately, the competitiveness of

the IPP bid price. The lowest bid price to the customer is the key, so

if one IPP provides the most competitive bid for the whole 3000MW,

it should be allowed. The REIPPPP has already resulted in some

players winning bids in many bid rounds based on the strength of

their bid proposal. It could be argued that this is another form of

unhealthy competition.

5.4.19. It is also recommended that in the RFP, the System Operator should

provide the maximum plant size to manage inter-connected power

system security of supply and reliability in case of unplanned events

that could make a single plant unavailable.

Environmental pollution Stakeholder Comments

5.4.20. A sizeable number of stakeholders argued that the inclusion of gas

projects in the IRP would contribute to more carbon emissions

although at lower levels when compared to other technologies like

coal. Some stakeholders also stated that the extraction of natural gas

and shale gas have a negative economic and environmental impact

on fishing communities, underground water resource, etc.

Furthermore, stakeholders highlighted the availability of capital to

fund the gas power plants as a risk, due to the changing view towards

fossil fuel energy financing in international markets.

NERSA Analysis

5.4.21. The IRP placed a carbon dioxide (CO2) emissions constraint for the

period 2020 to 2030, based on South Africa’s commitments to reduce

emissions in the Paris Agreement. The costs associated with CO2

are not included, as the CO2 emissions constraint imposed already

indirectly imposes penalties or additional costs. The IRP model

achieved this by applying the CO2 constraints and choosing cleaner

electricity generation options even if they are options that are more


39

expensive. The extent of the gas contained in the IRP is within the

imposed emissions reduction trajectory, which was provided by the

Department of Environmental Affairs (DEA) and is in line with the

country’s policy.

5.4.22. The issues of the environmental impact of gas extraction projects will

be handled by the DEA and other relevant bodies. The potential

shortage of market capital to fund polluting gas power projects is a

risk best handled by IPPs after taking into account the IRP

commercial operation deadlines so as not to endanger the country’s

electricity security of supply.

5.5. Coal Capacity Analysis

5.5.1. The draft determinations determined that 1 500 MW should be

generated from coal, which represents the capacity allocated under

the heading ‘Coal’, for the years 2023 to 2027, in Table 5 of the

IRP 2019.

Coal System Impact Stakeholder Comments

5.5.2. Most IPPs and environmentalist stakeholders do not believe that coal

would ensure uninterruptable supply. They argue that South Africa is

currently encountering load shedding, yet the generation capacity is

dominated by coal. The utilities, Eskom and City Power, however

believe that coal will ensure uninterruptable electricity supply.

5.5.3. All stakeholders do not believe that new coal capacity will be

achieved by 2023 due to the long lead times required for coal plants,

as well as funding challenges for new coal-fired power plants. There

are also environmental litigations that remain a risk. Difficulties faced

by two coal IPPs, Khanyisa and Thabametsi, are often cited as

examples. These two IPPs are yet to be licensed by NERSA and

have not yet reached financial close due to environmental and

financial challenges. Eskom proposes the refurbishment and re-

purposing of old coal-fired power plants that are due for

decommissioning to meet the 750MW coal capacity by 2023.


40

NERSA Analysis

5.5.4. NERSA agrees with Eskom and City Power that new coal would

ensure uninterruptable electricity supply, but only if it can be brought

on line in 2023 as per the IRP 2019. The IPPs and the

environmentalists’ responses and reasoning that South Africa is

experiencing supply constraints despite the fact that generation is

dominated by coal is flawed in that it does not consider that the

problem is in the management of those power stations, not the

technology itself. Some stakeholders’ reasons for not believing that

coal will provide uninterruptable supply is due to the lead times

required from the procurement of coal power plants to the

commercial operation date. This will be dealt with in a later section.

5.5.5. NERSA agrees with stakeholders that no new coal capacity would

close the energy gap by 2024. Coal-fired power plants require long

lead times (4 – 9 years) and are prone to environmental litigations.

The lack of progress on two power plants, Khanyisa and Thabametsi,

that were announced as preferred bidders in October 2016, bears

testimony. Sufficient time must therefore be allowed for the

establishment of coal capacity.

Coal Technology Analysis


5.5.6. Stakeholders almost unanimously agree that coal is outdated and not

in line with the best practices. Most countries, including South Africa,

are committed to Green House Gas emission reduction and are

moving away from coal to renewable technologies. Where coal is

considered, only high efficiency, low emission (HELE) technologies

are considered. These are also sometimes classified as cleaner

technologies, although the Centre for Environmental Rights (CER)

and other stakeholders highlighted that there is no such thing as

clean coal. Stakeholders were further concerned that the

determination does not state that the proposed coal technology must

be clean. Renewable energy with storage, or gas, is advocated as

better solutions.


41

5.5.7. Stakeholders strongly object to any inclusion of coal in the

determination. They highlighted that it is in contradiction with the

government’s carbon emission reduction commitments and not in

line with global trends, where governments are moving away from

coal. Some stakeholders also pointed out that the Draft

Determination does not specify whether only clean technologies

would be considered. They further argued that even if clean

technologies are considered, they will make electricity more

expensive.

5.5.8. All stakeholders who commented on the type of project to be

considered for coal indicated that they prefer turnkey solutions due

to the problems encountered at Medupi and Kusile.

5.5.9. Most stakeholders recommended that coal be dispatchable. City

Power further suggested that these small power plants should be

able to ‘load follow’. Eskom wants the coal power plants to be both

dispatchable and able to provide ancillary services.

NERSA Analysis

5.5.10. The National Development Plan Vision 2030, as well as the National

Climate Change Response White Paper, indicates South Africa’s

commitments to reducing its carbon footprint. Electricity generation

is said to contribute almost 50% of the emissions in the country and

South Africa is said to be the world’s 14th largest emitter of green-

house gasses. It has therefore become imperative for the country to

move towards reducing its emissions, while ensuring that the socio-

economic impact of this move is minimised.

5.5.11. In the IRP model, a CO2 emissions constraint, Peak-Plateau-Decline

was placed for the entire horizon of the plan. This is based on South

Africa’s commitments to reduce emissions in the Paris Agreement.

This constraint ensured that the energy mix does not exceed the set

annual limit. It therefore ensures that emitting technologies are

limited and cannot violate the emissions limit (see page 36 and 37 of

98 of the IRP 2019).

5.5.12. The costs associated with CO2 are not included, as the CO2

emissions constraint imposed already indirectly imposes penalties or

additional costs. The extent of the coal contained in the IRP is within


42

the imposed emissions reduction trajectory, which was provided by

the DEA and is in line with the country’s policy.

5.5.13. It is therefore recommended that HELE coal technologies, including

underground coal gasification, integrated gasification combined

cycle, carbon capture utilisation and storage, and ultra-supercritical,

super critical and similar technologies, be deployed for the

exploitation of South African coal resources. Decision 6 of the

IPR 2019 also confirms that all new coal power projects must be

based on HELE technologies and other cleaner coal technologies.

5.5.14. In developing any energy plan for any country, several competing

factors are considered, and a trade-off is made to determine the best

energy mix. NERSA is satisfied that environmental emissions were

already considered as stated above. The IRP2019 also considered

only clean technologies. It is NERSA’s position that any new coal

must make use of HELE technologies.

5.5.15. NERSA believes that any coal power plant must be dispatchable,

load following and be able to provide ancillary services, especially

now that there is an energy mix with renewable energy power plants

that are not able to provide these services. Furthermore, the planned

decommissioning of Eskom’s older power stations leaves the

transmission system with an inadequate ancillary services reserve

and dispatchable reserves, making the operation of the power

system very difficult.

Coal Generator Size


5.5.16. IPPs, business associations and consulting firms object to the

inclusion of coal, but says if coal is to be included, smaller plants

between 300MW and 600MW are optimum, preferably with the ability

to perform load following. Eskom, however, advocates for larger

plants, with a maximum unit capacity of 800MW, and with the ability

to provide ancillary services. The other utility, City Power, prefers

smaller plants, should coal be included. There was an outright

rejection of coal by City of Cape Town, who did therefore not even

consider size.


43

NERSA Analysis

5.5.17. It is recommended that the minimum plant size should be determined

by the IPP after considering the available grid connection capacity,

availability of coal volumes and ultimate competitiveness of the IPP

bid price.

5.5.18. It is also recommended that in the RFP, the System Operator should

provide the maximum plant size to manage inter-connected power

system security of supply and reliability in case of unplanned events

that could make a single plant unavailable.

Risks Associated with the Coal technology


5.5.19. Stakeholders identified three main risks:

5.5.19.1. Long lead times for coal-fired power plants.

5.5.19.2. Funding risks, as most financial institutions no longer fund

new coal power plants. Standard Bank is one such financial

institution that has publicly made its position known.

5.5.19.3. Environmental litigations. Coal-fired power plants are likely

to be challenged by environmentalists. The CER has

already highlighted this in its submissions. It is already

litigating on the two coal-fired power plants, Khanyisa and

Thabametsi.

5.5.19.4. The environmental and health risks were also cited.

NERSA Analysis

5.5.20. NERSA agrees with the above stakeholder comments. The

comments are based on evidence and facts. These are, however,

manageable where information symmetry is ensured between the

procurer, buyer as well as project developer. Lessons learnt from

previous procurement programmes must also be taken into account

to ensure they sufficiently militated against.


44

Cost Associated with Coal Technology


5.5.21. All stakeholders, including Eskom, agree that the cost of coal might

not be comparable with those of renewable energy technologies. The

proposed carbon tax will increase the coal price. The proposed high

efficiency, low emission technologies, which may mitigate the

environmental and health damages, will also increase the coal

prices. Eskom also highlighted that the strict environmental emission

standards also make new coal-fired power plants unsustainable.

NERSA Analysis

5.5.22. NERSA agrees that carbon tax and stricter emissions legislation will

make coal more expensive than the current prices, and this must be

factored into the decision. This, however, was considered during the

development of the IRP2019 to determine the optimum energy mix

for the country. The decision must, however, also cost the benefit of

coal, including the socio-economic benefits.

Table 8: PC with FGD levelised cost of electricity

*** Source: Electric Power Institute (EPRI) Report used in the development of the IRP 2019

5.5.23. Table 8 shows the levelised cost of electricity for a coal plant with

Flue Gas Desulphurisation (FGD), while Table 9 shows the cost for

a coal plant with CCS. These cost are comparable with the rest of

the technologies in the energy mix. In the development of the IRP

2019, clean coal was assumed in the model.


45

Table 9: PC with carbon capture levelised cost of electricity

*** Source: Electric Power Institute (EPRI) Report used in the development of the IRP 2019

Socio-Economic Impact Associated with the technology


5.5.24. There was a split among the pro-renewable energy IPPs, with some

stating that more jobs are created by renewable energy projects than

coal, while the others conceded that coal create more jobs. Both,

however, agree that the environmental and health harm caused by

coal outweighs the economic benefits. Environmentalist believe that

renewable energy projects create more jobs if the whole value chain

is considered. The CSIR’s report is often cited to justify this

argument.

NERSA Analysis

5.5.25. Some socio-economic impact studies consider the full value chain of

electricity generation from coal; from coal mining, coal transportation,

power generation and associated plant component manufacturing

industries. Other studies only consider the number of jobs created in

the generation of electricity. If it is considered that most of the

renewable energy technologies are constructed outside the country,

the number of permanent jobs is higher for coal if the whole value

chain is considered.


46

5.5.26. However, coal and RE and different technologies that play differing

roles in the energy mix and should be analysed as such. NERSA is

of the view that both technologies have a positive impact that they

bring into the electricity industry, and the socio-economic targets set

by the procurer should reflect that.

NERSA’s Overall Comment on Coal

5.5.27. The Minerals Council of South Africa highlighted that South Africa

has coal resources that should last for over 100 years. They should

be used to the benefit of South Africa. It would therefore be

problematic to abandon coal for electricity generation due to the

mandate to reduce GHG, while still exporting coal to other parts of

the world where it is still producing GHG in its processing and/or use.

5.5.28. The employment of HELE technologies seems to be a reasonable

compromise. Every country uses its resources for the betterment of

its economy. Over 90% of Saudi Arabia’s electricity generation is

from gas, as it has abundant gas resources.

5.5.29. NERSA supports coal procurement in line with the IRP 2019, based

on its mandate as Energy Regulator. The role that coal will be playing

in the country as a whole in future must be supported by a country

coal master plan. This will provide direction for the country on how to

leverage a resource that is abundantly available in the country, while

still ensuring the sustainability thereof.

5.5.30. The objections to coal raised by stakeholders are similar to the ones

submitted to the DMRE during the public participation process for the

IRP 2019. The DMRE responded to each objection (Page 61–64 of

the IRP2019). NERSA is satisfied with the DMRE’s responses. By

having less coal, and more clean technologies, a balance between

achieving security of supply and mitigating the environmental and

health effects of coal generation was achieved. Cleaner coal

technologies are proposed and government made commitments that

Environmental legislation would be observed.

5.6. Procurement Process Analysis

5.6.1. The draft determination indicates that the new generation capacity

(‘the electricity’) shall be procured though one or more tendering


47

procedures that are fair, equitable, transparent, competitive and cost-

effective and shall constitute IPP procurement programmes as

contemplated in the Regulations (‘procurement programmes’).

5.6.2. They further highlight that the procurement programmes shall target

connection to the Grid for the new generation capacity as soon as

reasonably possible, in line with the timetable set out in Table 5 of

the IRP 2019. Deviations from the timetable set out in Table 5 are

permitted to the extent necessary, taking into account all relevant

factors, including prevailing energy security risks, the time required

for efficient procurement and the required construction timelines for

such new generation capacity facility.


5.6.3. A large number of stakeholders support the procurement process

followed under BWs 1 to 4, citing it as a successful and world-

renowned programme. Stakeholders therefore suggest that, given

the urgent need for the capacity, the well-established process

(DMRE through the IPP Office) must be used, as it has all the

resources and experience, as well as the ability to properly refine the

process due to lessons learnt from previous procurement rounds.

5.6.4. Eskom has highlighted some challenges with the procurement as it

stands, specifically the exclusion of Eskom, as the buyer, from many

of the decisions and other discussions leading up to the RFP phase,

as well as the lack of information on the financial models and

Implementation Agreements. This asymmetry of information often

puts Eskom at a disadvantage when faced with claims from IPPs.

The procurer has no responsibility to the consumers of South Africa,

while Eskom, as the buyer, takes full responsibility for the many

criticisms levelled at the cost of the programme.

5.6.5. The procurement is supported, provided that the procurement must

not fall prey to political interference. The buyer should not be allowed

to refuse to sign PPAs, and all information relating to the procurement

must be made available to the public to ensure transparency.

5.6.6. The National Treasury should be the procurer, rather than the DMRE,

as the former has more knowledge and experience with regard to

procurement matters. Alternatively, the IPP office could fulfil this


48

function on behalf of the DMRE. The procurement process should be

an expedited one, to allow the energy crisis to be timeously

addressed. The scope of works and qualification criteria should be

very clear, and should be focused on lead time and least cost. In

accordance with the law, the process must also be fully competitive.

5.6.7. Other stakeholders dispute that previous tender processes have

been fair, equitable, cost-effective and particularly, that they have

been transparent. Previous new generation procurement processes

were transparent only to industry, if at all, but certainly not to citizens.

There has been no transparency on, for example, the tender and

procurement requirements for the various IPP procurement

programmes; or the financial and commercial close deadlines. The

public should have full access to all of this information, and should

be notified of all stages of the processes. The DMRE, the IPP Office

and NERSA’s failures to ensure increased transparency and public

consultation in these processes has been unacceptable.

NERSA Analysis

5.6.8. NERSA notes and agrees with the notion of leveraging the

experience and resources already established so that continuous

improvement is ensured.

5.6.9. It is recommended that continuous engagement take place among

the DMRE, IPP Office and NERSA to ensure that information is

shared among them, as well as that discussions take place on how

to avoid the challenges experienced in previous rounds of the

procurement. To that end, several engagements have taken place

regarding this round of procurement and much headway has been

made in being aligned regarding critical matters. This alignment will

ensure that issues of contention do not bring the process to a halt.

5.6.10. Stakeholders have raised concerns regarding transparency, as well

as urgency. NERSA has and will endeavour to ensure transparency

and urgency in all matters under NERSA’s control. These concerns

will also be highlighted to the DMRE and the IPP Office to ensure

that transparency and urgency is actively pursued as far as possible

and to an extent that does not compromise the programme in terms

of competitiveness and quality control.


49

5.7. The Buyer

5.7.1. The draft determination stipulates that the electricity may only be sold

to the entity designated as the buyer, Eskom Holdings SOC Limited,

and only in accordance with the power purchase agreements and

other project agreements to be concluded in the course of the

procurement programmes.


5.7.2. Some stakeholders do not have a problem with Eskom being the

buyer, and highlight that current legislation does not make provision

for any other entity to buy electricity from IPPs. Stakeholders

however highlighted that the following must be taken into account if

Eskom is the designated buyer:

5.7.2.1. Government guarantees must be secured through the

National Treasury to ensure the bankability of the projects.

5.7.2.2. Eskom must make a commitment to connect the generators

to the Transmission or Distribution network before the

procurement process begins; that is, Eskom must make

sure that it plans and is able to connect plants in time.

5.7.2.3. The decision of the buyer must be made while taking into

account the pending unbundling of Eskom.

5.7.2.4. The decision of the buyer must be made after taking into

consideration the proposed amendments to New

Generation Regulation that propose that Municipalities can

become buyers of IRP capacity.

5.7.2.5. Other stakeholders have highlighted that Eskom should not

be the only buyer, as it would be in the position of the

poacher and the game keeper at the same time.

Stakeholders further indicated that this is an opportunity to

fast-track commitments to create an independent System

Operator to buy power from all generators in a transparent

and fair manner, with no perception of partiality.


50

5.7.3. Other stakeholders are of the view that in the short-to-medium term,

Eskom can continue to be the single buyer, however in the longer

term, a market should be opened to any chosen buyer of new

generation capacity through wheeling arrangements in the network.

5.7.4. A large number of stakeholders, including the City of Cape Town and

City of Johannesburg municipalities, indicated that the opportunity to

buy electricity should be expanded to allow municipalities to also be

buyers of their own power, as allocated in the IRP. Stakeholders

further suggest that any entity in good financial standing should be

allowed to procure its own power from IPPs. This diversification

would result in increased capacities and will reduce the reliance on

Eskom to provide power for the whole country, thereby reducing the

risk associated therewith.

5.7.5. Stakeholders are of the view that allowing private investors to risk

private capital and to sell the capacity to private off takers (or

municipalities if they are credit worthy), allows for the efficient

allocation of scarce resources in the sector in a manner that creates

capacity in the system while not forcing the tax payer to pay for it

(either via Eskom or a municipality).

NERSA Analysis

5.7.6. The New Generation Regulations define the Buyer as ‘any organ of

state designated by the minister in terms of section 34 1 (c) and (d)

of the Act’. Eskom, as an organ of state, has thus been designated

by the minister in section 34, as received by the Regulator in

February 2020.

5.7.7. NERSA notes the conditions highlighted by stakeholders under

which Eskom can be the buyer. Many of the issues raised can and

must be ironed out during engagements in the procurement process,

for example, the issue of government guarantees should be handled

by the DMRE, Department of Public Enterprises (DPE) and the

National Treasury. This will also be shared with Eskom and the

DMRE/IPP Office.


51

5.7.8. NERSA also notes and supports the notions shared regarding the

decision on who the buyer should be, which must be taken while

considering the upcoming changes in the electricity sector, the

unbundling of Eskom and well as New Generation Regulations

amendments. However, given that neither of these processes have

been finalised, it is NERSA’s position that for this allocation, Eskom

should remain the buyer. In the determinations that will follow after

the implementation of the IRP 2019, and once the New Generation

Regulations have been amended, municipalities can take part in

establishing New Generation within their municipalities.

5.7.9. Once the unbundling of Eskom has been completed and all decisions

regarding the role of the System Operator and the appropriate

placing of the mandate to buy power for the system has been

outlined, future determinations will take this into account as well.

5.8. The Procurer

5.8.1. The draft determinations indicate that the procurer, in respect of the

procurement programmes, will be the Department of Mineral

Resources and Energy.

5.8.2. It further elaborates that the role of the procurer will be to conduct the

procurement programmes. This includes preparing any requests for

proposals and/or related and associated documentation, negotiating

the power purchase agreements, facilitating the conclusion of the

other agreements and facilitating the satisfaction of any conditions

precedent to financial close that are within its control.


5.8.3. Stakeholders are largely in support of the DMRE being the procurer

through the IPP Office. The IPP Office would be able to draw from

experience gained from previous bidding rounds and ensure that the

challenges experienced then are militated against.

5.8.4. Other stakeholders suggest that the weighting in the REIPPPP can

be amended (% of foreign equity allowed, % of local content, local

community trust as a free-carry, etc.). The process itself has worked

very well and has attracted many developers, bidders and foreign

funding.


52

5.8.5. Some municipalities have indicated that they want to develop own

generation capacity, while others are already working on their own

proposals for a Municipal Finance Management Act (MFMA)

compliant power procurement process and are ready to engage with

the DMRE in that regard.

NERSA Analysis

5.8.6. NERSA notes and support the suggestions made by stakeholders.

These will be highlighted and shared with the DMRE to ensure they

are taken into account during the procurement programme. The role

of municipalities in this area again will become clearer when the New

Gen Regulations amendments have been finalised and promulgated.

5.9. The Project Developer

5.9.1. The draft determinations propose that the electricity must be

purchased from Independent Power Producers.


5.9.2. Stakeholders are in support of IPPs being the project developer for

this allocation, but more effort must be placed into efficiency and

transparency during the procurement process as run by IPP Office.

Others indicate that this programme has proven to be effective and

cost neutral to Eskom.

5.9.3. The IPPs, as builders of the 6800MW allocated between 2022 and

2024, should be viewed as a reliever of the electricity constraints

currently faced by Eskom. IPPs provide the sustainable and long-

term projects necessary to maintain security of supply. Furthermore,

IPPs have an extremely good track record of building projects on time

and on budget. Any risk of cost overruns is borne by the IPP and

does not affect the tariff, whereas with Eskom, cost overruns are

pushed into the tariff, which Eskom will recover from its revenues.

5.9.4. Other stakeholders strongly recommend that procurement rounds be

done on a provincial basis, with a focus on the Mpumalanga

Province. This will alleviate the socio-economic issues that will affect

this province in particular, as the coal-fired plants will be


53

decommissioned leading up to 2030, leaving many communities with

significant unemployment rates. This would assist with and ensure

the ‘Just Transition’ to which the IRP 2019 alludes.

5.9.5. Eskom is gravely concerned that no feasibility studies were

undertaken to determine the best options for the country, thereby

ignoring Eskom’s value-adding opportunities and the requirement for

a ‘Just Transition’. Eskom can repurpose some of its power stations

to gas-fired plants and repower some of its power stations that are

scheduled to be shut down in the IRP.

5.9.6. Other stakeholders highlight that IPP supply is preferred due to the

many advantages over supply from regulated or government-owned,

vertically integrated utilities. Some of these advantages include:

a) construction cost overrun risk is shifted to the IPP;

b) operating cost overrun risk is shifted to the IPP;

c) operating availability risk is shifted to the IPP;

d) IPPs tend to have lower overhead costs; and

e) IPPs tend to have lower Operating and Maintenance (O&M)

costs.

5.9.7. Stakeholders highlighted the need for the unbundling of Eskom into

Generation, Transmission and Distribution to be expedited to enable

the movement towards a more open and deregulated market

structure. This will enable all generators to operate on equal footing,

thereby also allowing Eskom Generation to take part in future

capacity builds, particularly clean energy.

NERSA Analysis

5.9.8. NERSA notes and support the stakeholder views as articulated

above. The previous rounds of the REIPPPP have done significant

work to open up the electricity generation industry to independent

producers and distribute the risk that is inherent in vertically

integrated utilities. Although it had its challenges, it has been praised

as being a world-class programme.

5.9.9. Decision 4 in the IRP 2019 indicated the following: ‘For coherent

policy development in support of the development of a just transition

plan, consolidate into a single team the various initiatives being


54

undertaken on just transition’. Concerns raised by the utility are noted

as valid. The suggestion to bring some of the Renewable generation

into provinces where coal generation is dominant to reduce the

negative socio-economic impact is supported by NERSA. These

towns also have a transmission and distribution network backbone

that would reduce the cost of connection.

5.9.10. The pending Eskom unbundling must consider the role of the future

Eskom Generation division and its ability to take part in future

determinations as a project developer. This will require several

systems to be aligned, including regulatory tools. The Grid Code is

currently being amalgamated to ensure that there is a clear

separation of Generator, Transmitter and Distributor Codes. There

have also been discussions to expand the Balancing Section of the

Schedule and Dispatch Rules to enable a market within the

Generation space that also includes appropriate costing of all

generators, as well penalties when generators fail to meet their

commitments.

5.10. Socio-Economic Impact


5.10.1. Stakeholders highlighted that the South African government is yet to

perform a socio-economic study on the impact of moving away from

coal generation, to renewables. Until this study, which was deemed

an immediate necessity by the IRP, has been carried out, it remains

difficult to comment on socio-economic impact.

5.10.2. Eskom further highlighted that the absence of the study on the best

way to transition from coal to RE technologies, namely a ‘Just

Transition’, has not been considered, therefore this could cause

unnecessary job losses. The impact on Eskom and jobs reliant on

Eskom has not been considered.

5.10.3. Stakeholders indicate that socio-economic impact analysis should

not be limited to the choice of technology built, but should look further

into secondary industries built as a result of the energy sector

development and further still, to the impact on the whole economy as

a result of reliable and affordable electricity.


55

5.10.4. Stakeholders in the clean energy sector indicated that clean energy

not only allows for job creation, but also allows the surrounding

communities a chance to prosper in a secure and healthy

environment. It also gives the country the opportunity to flourish as a

result of maximised output.

5.10.5. The socioeconomic benefits could be seen both in terms of building

projects locally and in terms of exports, having used the local market

as a springboard for these. The impact would increase further if, on

a yearly basis, this technology’s procurement process would be

rolled out as planned in the IRP. Stakeholders further indicated that

the existing REIPPPP has had a positive socio-economic impact.

NERSA Analysis

5.10.6. Decision 4 of the IRP 2019, as highlighted above, outlines the

importance of ensuring a ‘Just Transition’. There is 10 500MW of coal

generation capacity that is to be decommissioned by 2030, and

35 000MW by 2050. The impact of this will be significant, especially

in the Mpumalanga and Limpopo regions. When implementing the

IRP 2019, this must be taken into account.

5.10.7. NERSA notes and supports the idea of viewing the social-economic

impact more widely than just the direct jobs. NERSA also notes and

supports the idea of ensuring that the signals that is sent to the

market are positive ones and that investor confidence is ensured.

Socio-economic impact per project is however supported, as was the

case in the previous rounds of procurement.

5.10.8. NERSA further supports that a steady and consistent roll-out of the

build will also ensure more localisation, as well as create secondary

industries that would assist with job creation. The IRP already applied

policy adjustment through annual build limits, as this provides smooth

rollout of RE, which helps sustain the industry.

5.11. Risks associated with the allocation

5.11.1. The consultation paper that solicited comments from stakeholders,

enquired what is viewed as risks associated with this determination.


56


5.11.2. Most stakeholders indicated that the biggest risk to this procurement

programme is delays in the procurement process. The RE capacity

in particular is already delayed and is meant to be online by 2022.

Delays in the governance and red tape around the processing of this

programme will exacerbate the energy crisis that the country is

facing.

5.11.3. The procurement of Coal and Gas IPPs has been highlighted by

stakeholders as highly risky. Coal, in particular, is a risk as it had

delays in reaching financial close and is yet to reach commercial

operation from a previous determination. Challenges from

environmental organisations is likely to delay these plants from

reaching commercial operation. Several stakeholders have

recommended that coal and gas allocation be removed from the

concurrence.

5.11.4. Eskom highlighted a number of risks, labelled as ‘Regulatory risks’,

associated with this procurement of new capacity, based on previous

experiences. These include:

a) deemed energy costs arising from municipal failures;

b) Force Majeure events affecting Eskom’s ability to connect IPPs

timeously;

c) UoS charges, grid delays or grid unavailability arising due to

Force Majeure evens;

d) risk of an inappropriate/untenable risk allocation;

e) risk of inadequate PPA drafting;

f) risk of delays arising due to governance delays;

g) risk of insufficient grid connection availability; and

h) risk of misalignment between the procurer and buyer.

5.11.5. Others highlight the previous interruptions in the programme,

especially where Eskom refused to sign the PPAs under the BW4

procurement, which the stakeholders labelled as a disruption to the

programme. This may have caused investors to be weary and their

confidence will need to be restored.


57

NERSA Analysis

5.11.6. NERSA notes the procurement time delay risks, as highlighted by

stakeholders. The first batch of Wind and PV is meant to be online in

2022, which is already impossible considering that is it already

mid-2020. The determination, however, does mention that

‘Deviations from the timetable set out in Table 5 are permitted to the

extent necessary taking into account all relevant factors including

prevailing energy security risks, the time required for efficient

procurement and the required construction timelines for such new

generation capacity facility’.

5.11.7. There is therefore room to allow deviation in the timing stipulated by

the IRP 2019.

5.11.8. The risk associated with the procurement of coal has been discussed

in previous sections. Transparency between stakeholders, i.e. the

procurer and the buyer, in the procurement process will mitigate most

of the risks that have been a hindrance in the past. Procurement of

coal technology must be in line with the country’s coal plan to best

exploit this particular resource for the benefit of the country, while

minimising any adverse effects.

5.11.9. Risks highlighted by Eskom should be addressed during the

development of RFP documents (PPAs, Transmission/Distribution

connection agreements, etc.) by the DMRE/IPP Office.

6. CONCLUSION

6.1. Stakeholders did not support the inclusion of multiple technologies in

one determination. NERSA, however, is of the view that it has taken too

much time for the IRP 2010 to be revised, so it became prudent for the

department to expedite the implementation of the gazetted country plan.

NERSA therefore understands the urgency around bringing this

capacity online. Furthermore, even though the technologies have been

combined, they were all analysed independently and in their own right.

6.2. Preliminary studies by SARB in the Monetary Policy Review April 2020

in light of the COVID-19 pandemic suggests 2020 GDP growth will be

in the range of -2% to -4%. Further, there is limited scope for a rebound,


58

but growth is unlikely to exceed 1% in 2021. Before the lockdown, the

current year’s economic growth forecast was -0.2%.

6.3. The IRP least-cost plan assumed a demand of 308TWh under the

median forecast scenario, based on an average 4.26% annual GDP

growth with an average electricity demand growth of 1.8% by 2030. The

lower than expected GDP growth has been exacerbated by the

COVID-19 pandemic and the pace of the implementation of the IRP may

require adjustment, especially if the local and global lockdowns are

extended.

6.4. The determination as received from the DMRE was in line with the

IRP 2019 as gazetted by the Minister of Mineral Resources and Energy,

as outlined in Table 1 in this reasons for decision document.

6.5. Stakeholders are supportive of the allocation from Wind and PV,

although many indicate that it is insufficient. NERSA is of the view that

there is an annual allocation for Wind and PV; these will follow in due

course as long as the IRP 2019 remains the gazetted energy policy

position of the country.

6.6. The allocation for battery storage will allow the country to start investing

in utility size battery storage, which provides backup to Wind and PV.

Batteries also have many benefits in terms of providing ancillary

services such as ensuring network stability. This technology is therefore

supported by many stakeholders.

6.7. Stakeholders raised concerns regarding the security of gas supply into

the country, as well as the price volatility that comes with an imported

commodity. The allocation of gas must be supported by a gas master

plan for the country in order to ensure the sustainability of the

technology in the energy mix.

6.8. A large number of stakeholders are against the inclusion of new coal in

the energy mix. NERSA recommends that any new coal should make

use of HELE technologies to ensure that emissions are reduced. From

the country’s perspective, there is room for coal in different industries

for the benefit of the country’s economy. A coal master plan must also

be developed to ensure that the roadmap for the role of coal in the

country’s economy is outlined and is for the benefit of the country.


59

6.9. NERSA recommends that the socio-economic impact commitment that

was part of the previous procurement processes must be upheld.

However, improvements can be made in terms of reporting and

ensuring that obligations made are upheld and must vary per

technology, taking into account the different roles played by the different

technologies in the energy mix.

6.10. Stakeholders highlighted that decisions on who the procurer, buyer and

project developer is should take into cognizance the pending

unbundling of Eskom, as well as the pending amendment of the New

Generation Regulations to allow municipalities to establish new

generation capacity. NERSA notes and is in agreement with this

recommendation and it will be taken into account once these processes

have been concluded.

6.11. It must be highlighted that currently, the scheduling and dispatch rules

do not include balancing rules. This means that the increase in cost

associated with having to use more expensive technology as a result of

failing to meet the day-ahead projection of a cheaper generator is still

being carried by the customers. The balancing rules would enable the

System Operator to penalise the generator responsible for the energy

shortfall.

APPENDIX A: DRAFT DETERMINATION

APPENDIX B: SUMMARY OF STAKEHOLDER COMMENTS

NATIONAL ENERGY REGULATOR OF SOUTH AFRICA

Documents

Transcript of NATIONAL ENERGY REGULATOR OF SOUTH AFRICA