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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
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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
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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
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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
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‘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.
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‘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).
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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.
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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.
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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’).
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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
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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.
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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
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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.
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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
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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.
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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
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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.
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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).
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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.
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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
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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
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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]
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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.
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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.
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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.
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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.
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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
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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.
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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
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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.
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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.
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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
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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.
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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
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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.
Stakeholder Comments
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
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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).
Stakeholder Comments
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.
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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.
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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
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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.
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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
Stakeholder Comments
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.
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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
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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
Stakeholder Comments
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.
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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
Stakeholder Comments
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.
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Cost Associated with Coal Technology
Stakeholder Comments
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.
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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
Stakeholder Comments
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.
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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
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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.
Stakeholder Comments
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
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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.
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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.
Stakeholder Comments
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.
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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.
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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.
Stakeholder Comments
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.
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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.
Stakeholder Comments
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
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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
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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
Stakeholder Comments
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.
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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.
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Stakeholder Comments
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.
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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,
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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.
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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