A VITAL AMBITION DETERMINING THE COST OF ADDITIONAL CO 2 EMISSION MITIGATION IN THE SOUTH AFRICAN ELECTRICITY SYSTEM July 2020 Version 1.06 [email protected]Adam Roff, Dr Grové Steyn, Dr Emily Tyler, Celeste Renaud, Rian Brand and Jesse Burton, in collaboration with the CSIR Energy Centre
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A VITAL AMBITIONDETERMINING THE COST OF ADDITIONAL CO2 EMISSION MITIGATION IN THE SOUTH AFRICAN ELECTRICITY SYSTEM
July 2020Version 1.06
[email protected] Roff, Dr Grové Steyn, Dr Emily Tyler, Celeste Renaud, Rian Brand and Jesse Burton, in collaboration with the CSIR Energy Centre
CONTENTS• Approach and methodology – system modelling is required
• Assumptions – latest public domain information, common to all scenarios
• Current policy reference scenario – projecting the IRP policy intent to 2050
• Least Cost – the most economic scenario in a theoretical world
• Understanding carbon emissions – how low do we need to go in the power sector?
• Optimised Mitigation Scenarios - least cost theoretical power systems under emission constraints
• Reality check – do the results survive in the real world outside of a model?
• Realistic Mitigation Scenarios – assessment of realistic power sector infrastructure build programmes
• Policy Implications
• Conclusion
• Appendix - includes glossary of terms, reference list and additional technical information.
We acknowledge the support of Agora Energiewende and the Children’s Investment Fund Foundation. This work was undertaken in collaboration with the Council of Scientific and Industrial Research (CSIR) Energy Centre.
This deck is accompanied by a detailed technical report: CSIR (2020) “Systems analysis to support increasingly ambitious CO2 emissions scenarios in the South African electricity system,” Technical Report, July 2020.
• Different technologies have different capacity1 and
energy2 profiles, and therefore direct cost
comparisons are not always valuable.
– Technologies are embedded in a system which has
to deliver power reliably & optimally using
characteristics of each generation source to meet
demand most economically.
• We therefore needed to consider credible possible
future evolutions (Scenarios) of the entire power
system using powerful system planning software
(Plexos3)
• The system planning model ensures that in all
Scenarios, electricity demand is met on an hourly,
daily, and seasonal basis - assessed by a ‘system
adequacy’ test.
• All power systems reported are adequate (i.e. meet
demand at all times with no load shedding)
A LEAST COST OPTIMISATION MODEL ENSURES ELECTRICITY DEMAND IS MET RELIABLY AND COST EFFICIENTLY
Least CostOptimization
(Plexos)
Costs and characteristics for all generation technologies
(including cost learning rates)
Hourly demand forecast(for representative days of year)
Schedule of new build capacity for each generation technology
Energy generated per year for each generation technology
Cost-optimal retirement schedule for existing assets
Sasol
Medupi
Kusile
Majuba Wet
Majuba Dry
Kendal
Matimba
Lethabo
Tutuka
Duvha
Matla
Arnot
KrielKelvin
CamdenHendrinaKomati
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System Acceptability Metricse.g. System Adequacy
Scenario Constraintse.g. Carbon Budget, Annual
capacity build limits
System Planning for a Scenario
1Capacity refers to the maximum electrical power that can be generated from a source at different times of day.2Energy refers to the cumulative amount of electricity that can be generated from a source over a period of hours, days or years.3The same Plexos software is also used in the government process to develop the IRP
• Technology assumptions (cost and operating characteristics) must be common to the analysis of all future power system scenarios to allow like-for-like comparison
• Detailed technology assumptions can be found in the CSIR report1 covering the Plexos systems analysis
• Assumptions from the 2019 IRP were replaced with latest best public domain information if available (replacements indicated by bold italics)
• All costs are expressed in Jan 2019 Rands
• Summary of available technologies shown on this slide (for a full list of technologies made available to the optimiser see Appendix)
COMMON TO ALL POWER SYSTEM SCENARIOS INVESTIGATED
*Small Scale Embedded Generation
Sources: Integrated Resource Plan (2019); EPRI (2017); NREL Annual Technology Baseline (2019); 1CSIR, 2020 “Systems analysis to support increasingly ambitious CO2 emissions scenarios in the South African electricity system,” Technical Report, July 2020.
DISRUPTIVE REDUCTION IN THE COST OF WIND AND SOLAR PV EXPECTED TO CONTINUE FOR NEXT TWO DECADES
Sources: Integrated Resource Plan (2019); EPRI (2017); NREL Annual Technology Baseline (2019); for more information regarding these assumptions see CSIR (2020) technical report.
RE PROVIDES LOWEST COST ENERGY FOR NEW-BUILDHISTORICAL AND FUTURE COST LEARNING IN RE CRITICAL TO POWER SYSTEMS OF THE FUTURE
*LCOE costs for new-build wind and solar PV were developed using the REIPPPP Bid Window (BW) 4 (Expedited) costs as a starting point (aligned with IRP 2019), with declining cost trajectories thereafter based on the NREL Annual Technology Baseline (2019) learning assumptions. Although capacity factor and fixed operations and maintenance costs are anticipated to reduce, only capital expenditure costs was reduced in this assumption. This is highly conservative (particularly for wind).
South Africa has already witnessed rapid renewable energy price declines, as demonstrated through previous bid windows of the country’s Renewable Energy Independent Power
Producer Programme (REIPPPP). Based on interactions with South African industry experts in a separate study (Meridian Economics, 2020c), solar PV and wind energy cost declines
are expected to continue – the assumptions used in this modelling work* lie above or within industry expectations as reported in that study.
AFRAID OF THE DARK? SUFFERING FROM DUNKELFLAUTE?*FILLING THE GAP BETWEEN DEMAND AND RENEWABLE ENERGY GENERATION IN A TYPICAL WEEK
*In the German language, dunkelflaute is a word that refers to the fear of having inadequate sunshine or wind to maintain a viable supply of renewable energy.
• If early closure of coal power stations is not contemplated,
then fixed costs and future capital expenditure (capex) for
each station until retirement date is unavoidable
– In this case, new sources of energy would need to be lower
than the dispatch cost (coal fuel plus variable O&M) to
economically replace coal power
• As of 2020, New Build Wind and Solar PV LCOE¹ is still higher
than dispatch cost of all coal stations, as the chart shows
• BUT there is no rational reason not to close coal stations early
if it is economically efficient to do so. A more useful
comparison is thus the cost of new build alternatives to the
full cost of coal power including fixed costs and future capex.
A note on coal fuel costs: The data available for analysis remains
high-level, additional, more granular detail would allow:
• Understanding costs related to multiple supply sources per
station, including more expensive short-term contracts
• Understanding the proportion of coal that is subject to Take-
Or-Pay (TOP) contracts (some of this cost would remain
unavoidable even if stations were closed)
DISPATCH COST OF COAL IS CURRENTLY LOWER THAN RENEWABLES – IS THIS A USEFUL COMPARISON?
¹ LCOE includes all Capital, Operations and Maintenance Costs, Socio-Economic Development (SED), Enterprise Development (ED), and grid connection cost (see Appendix for further information on SED and ED). In general comparing the LCOE of variable and dispatchable plant does not adequately account for the different capacity and ancillary benefits each bring to the system.
Source: Eskom authored information in the public domain including Eskom (2019a), Dentons (2015), coal mining annual reports, interactions with coal supply and Eskom operations experts, EPRI.
– This cost component is based on EPRI (2017) information and is assumed to be the same R/kW for all units at all stations.
– We assume units can be closed one by one terminating the fixed cost per unit in the year of closure.
• Local air pollution abatement: Compliance with Minimum Emission Standards (MES)
– Coal-fired power plants emit harmful local air pollutants, including Particulate Matter (PM), Nitrogen Dioxide (NO2) and Sulphur Dioxide (SO2)
which are regulated under the Air Quality Act (2004).
– In order to be in compliance with Local Air Quality regulation, most of Eskom’s coal fleet require retrofitting, which implies additional capital and
fixed costs. Eskom has stated that these costs are prohibitive and has proposed a retrofitting schedule which leaves many of its plants out of
compliance. How this issue will be resolved is uncertain at present.
– This study requires assumptions to be made as to what technologies will be retrofitted at which stations when, and at what cost. For this, we
assume Eskom’s retrofit schedule (Eskom, 2019b) and Eskom’s associated costs (Naledzi, 2018) (critiqued as being inflated) for the following
reasons:
• Eskom’s cost dataset is internally consistent, context-specific and publicly available. The alternative would be to use data from different
sources and contexts for different technologies with differing degrees of credibility.
• Eskom’s schedule is consistent with that used in the IRP, promoting consistency and comparability.
• The assumption of partial compliance is conservative, as it reduces the coal fleet costs relative to other technologies.
• In our modelling both MES capital and MES operating expense (Opex) were treated as potentially avoidable costs.
FIXED OPERATIONS & MAINTENANCE (O&M) AND COST OF LOCAL AIR POLLUTION ABATEMENT
OUR ASSUMPTIONS CONSIDER LOWER DEMAND THAN IRP, BUT ALSO LOWER ENERGY AVAILABILITY FACTORS (EAF)
Source: Fabricius et al (Eskom) (2019)
For more information regarding these assumptions see CSIR & Meridian, 2020. “Systems analysis to support increasingly ambitious CO2 emissions scenarios in the South African electricity system.”
• In January 2020, the CSIR identified key interventions to mitigate the expected supply shortfall for this period, including emergency power procurement
by the Department of Mineral Resources and Energy (DMRE), customer response through unlocking small-scale embedded generation (SSEG), and
incorporating 200 MW of additional capacity from existing solar and wind projects (CSIR, 2020).
• In all scenarios, including the IRP, we assume that the CSIR’s identified interventions will close the energy supply gap identified.
• SSEG for all scenarios we considered is thus assumed to provide installed capacity of 3.4 GW (built from 2020 – 2022) followed by an additional 500MW
per year thereafter in line with the 2019 IRP assumptions
• The Integrated Resource Plan (2019) contains the best existing
expression of current government electricity policy. We
therefore use this as the basis of our reference scenario – the
plan against which mitigation scenarios can be compared.
• The IRP is constructed on a system modelling basis but
– has ‘policy adjustment’ that forces in new coal, hydro and gas as
well as creates annual new-build constraints on solar PV of 1 GW
and wind of 1.6 GW
– assumes coal stations will all run to their design life end dates,
regardless of cost
– only presents a plan as far as 2030
• We needed to extend the IRP policy intent from 2031 to 2050
for comparison with other scenarios
• Retaining the IRP RE build constraints beyond 2030 results in
new-build coal in the late 2040s – an irrational policy outcome
considering cost of new-build coal relative to RE* in future
years (Merven et al (SA-TIED), 2018)
• Therefore our ‘current policy trajectory’ incorporates the same
new build profile as the IRP for all technologies to 2030, but
assumes that constraints on new build capacity for solar PV
and wind are lifted from 2030 onwards, and that capacity
expansion then proceeds on a least cost basis
CONSTRUCTING A CREDIBLE, POLICY REFERENCE SCENARIO BASED ON THE IRP 2019
Wind and solar PV new build limits retained. Installed capacity stagnates with new build merely replacing retiring plant
Wind and solar PV new build limits removed after 2030
IRP 2019 is used as a basis for constructing our ‘current policy trajectory’
*Merven et al (2018) have explored the impact of retaining RE build limits from a macro-economic perspective and conclude the impact of constraining RE could be as high as ZAR 0.16/kWh by 2050, using conservative assumptions on RE and ZAR 0.18/kWh, using more optimistic RE costs.
COAL-FIRED GENERATION AS PER CURRENT POLICYALL UNITS RUN TO SCHEDULED RETIREMENT. FORCED-IN NEW COAL CREATES PATH-DEPENDENCE
Current Policy Trajectory: Annual Energy Generation by Coal-fired Power Station With an excess of coal and hydro capacity (Inga) already forced in, their capital costs sunk by the early 2030s result in an increase in coal use to meet increasing demand. Forced build locks in coal and locks out cheaper RE options.
MAPPING THE TERRAIN OF EXISTING RSA CARBON BUDGETS
Suggesting a Paris-aligned carbon budget range for the RSA power sector
• The IRP 2010 & IRP 2019 Carbon constraint: A carbon constraint was included in
the 2010 IRP based on the power sector continuing to contribute its historical 45%
of SA emissions. This constraint, extended in the 2019 IRP to 2050 is related to the
Upper Trajectory and is therefore both outdated and unlikely to be aligned to the
Paris goals.
• Emissions associated with the Current Policy Trajectory scenario: Consistently
below the IRP carbon constraint, this represents a 3.97 Gt budget. But is it Paris-
aligned? The literature suggests that to enable RSA to achieve 2 degree alignment,
a power sector budget between 2.9 Gt to 3.4 Gt (Burton et al, 2018) would be
appropriate, and for ‘well below 2 degrees’, 2.3 Gt. (McCall et al, 2019).
• Noting the uncertainty around these budgets, the broad articulation of the Paris
goals, and the precautionary principle of the UNFCCC, we decided to explore the
range of 2.0 Gt – 3.4 Gt, with an emphasis on 2.3 Gt.
Total Emissions (Gt) 2020-2050
• The analysis presented here draws on the literature considering the allocation of global budgets to nations, and then on the role of the power sector in achieving South Africa's
contribution to this global effort. The intention is to identify a range of budgets for the power sector which are likely to support an emissions trajectory for RSA that is Paris-aligned.
• The National Benchmark Carbon Trajectory Range is South Africa’s current international and domestic climate policy position, which has an Upper Trajectory carbon budget of
17.5Gt and a Lower Trajectory carbon budget of 10.8Gt for economy-wide emissions. The Lower Trajectory has been assessed as being aligned to 66% probability levels of the
global 2˚C target being achieved, which is generally associated with ‘well below 2˚C’ (Peters, 2017). A Paris-aligned budget at the national, economy-wide level could therefore be
said to be 10,8Gt and below.
*Noting that the allocation of the global carbon budget to nations has not been achievable in the UNFCCC process to date. In this study we are referring to the use of carbon budgets to assess Paris goal alignment. Further elaboration of this analysis is provided in ME, 2020b.
A SERIES OF COST-OPTIMISED SCENARIOS WERE DEVELOPED WITH DECREASING CARBON BUDGETS
• Power sector scenarios that emit far less than the current policy trajectory are also cheaper
• The Cost vs Emissions curve is almost flat for the likely Paris-aligned emissions range
• Substantial mitigation (+/- 1 Gt saving relative to the current policy trajectory) can be achieved with no increase in cost relative to the Current Policy Trajectory
• Even deeper mitigation comes at a fractional increase in cost
– Emissions can almost be halved (+/- 2 Gt saving relative to the current policy trajectory) for a 5% increase in electricity cost relative to the Current Policy Trajectory
• Given the 30-year future timeframe over which any cost difference will manifest, and inherent difficulty in forecasting over such a period, cost difference of this magnitude is likely in the error noise
– Relaxing any of our already conservative assumptions would only serve to reduce any mitigation cost further
NEW GENERATION CAPACITY: RE IS THE OPTIMAL CHOICENO NEW COAL, NUCLEAR OR HYDRO IS BUILT UNDER ANY COST-OPTIMAL SCENARIO
In all cost-optimal scenarios, the majority of new build capacity is wind and solar PV, with gas and storage providing flexibility and reserve capacity as coal retires.
Total new capacity built (GW) in each cost-optimal scenario from 2020 -2050
TRANSMISSION GRID CONSTRAINTSGRID EXPANSION LEAD TIMES MAY LIMIT CHOICE OF OPTIMAL RE LOCATION IN THE SHORT TERM
• The transmission (Tx) network needs to be strengthened toaccommodate the change in net flow of power (from North-Southto South-North) resulting from a more geographically distributednetwork of generation sources.
• Whilst CSIR (2016) shows excellent wind and solar resourcesacross most of RSA, project interest remains highest in regionswith less access to Tx infrastructure.
• Availability of grid infrastructure is a key consideration forintegrating renewable energy projects
• Eskom Transmission has expressed that currently, transmissionnetwork development has longer lead times than projectdevelopment from an EIA and servitude perspective
– Transmission network development takes 7-10 years
– Project development <5 years (roughly 1-4)
• Tx network expansion lead times are therefore a real-worldbottleneck which may constrain the RE build initially
• However, the optimised modelling analysis revealed theimportance of ramping up RE capacity significantly in the earlyyears in order to achieve ambitious mitigation.
• Another metric for Paris alignment other than carbon budgets addresses the date at which there should be no further coal in power generation systems.
• This has been argued as being around 2040 according to both international and domestic assessments (ME, 2020b).
• By imposing coal-off-by-2040 as an additional constraint on the Ambitious RE pathway, a final Realistic Mitigation Scenario is defined.
• This scenario generates emissions just greater than 2.5GT, nearly 500MT lower than imposing the ambitious RE pathway alone.
• The RE built in both scenarios is identical meaning that no decision regarding coal-off needs to be taken until the middle of the 2030s.
NEW GENERATION CAPACITY THE CAPACITY MIX FOR REALISTIC TRANSITION TO HIGH RE PENETRATION
In all realistic mitigation scenarios, the majority of new build capacity is wind and solar PV, with gas and battery storage acting as flexible reserve capacity as coal retires. No new coal, nuclear or Hydro is chosen by the optimiser.
Total new capacity built (GW) in each realistic mitigation scenario from 2020 - 2050
*includes hydro** includes hydro and nuclearNote that, although China’s policy target is 20% by 2030, China’s least cost power system includes 39% wind and solar share by 2030 (see Nature Communications study by He et al, 2020)
INVESTMENT IMPLICATIONS OF AN AMBITIOUS RE PATHWAY
• Over the next 10 years alone, ambitious RE pathways could attract in the region of R200 Bn more capital investments over and
above the IRP2019, whilst not relying on the fiscus
• This scale of investment presents an enormous opportunity for a much-needed economic stimulus, particularly post Covid
• It creates the opportunity for value chain localisation, reindustrialisation, and large-scale job creation in manufacturing,
associated services, construction, operations and maintenance
• Policy commitment to an ambitious RE pathway translates into positioning RSA as a major green investment location
• Such a positioning will likely increase access to green financing across the economy as the international decarbonisation agenda
accelerates
AN OPPORTUNITY TO TRIGGER A SUSTAINED ENERGY SECTOR CAPITAL INVESTMENT PLAN FOR SOUTH AFRICA
R244 Bn R345 Bn R455 Bn
*The figures above assume that solar PV and wind projects come online in 2022, with capital investments in the two years prior to commercial operation for wind, and one year prior for solar
• Gas accounts for less than 3% of energy generation in all scenarios investigated –mostly in the range from 1.5% - 2.5%
• Peaking requirements can be provided by liquid fuels for at least the next 10 years in all scenarios
• In all realistic mitigation scenarios, liquid fuels can provide the necessary fuel capacity for at last a further 5 years into the late 2030s.
• Even the coal-off-by-2040 scenario, which relies on mid-merit capacity to replace coal, has annual fuel consumption until late 2030s in the historic range of existing OCGT liquid fuel usage
• RSA does not need to expand gas infrastructure to support the power sector for the foreseeable future
• Such a decision can wait for 10 – 15 years
• The option to delay this decision has immense value for the country – we do not need to lock into long term gas commitments for the power sector now
THE QUESTION IS ABOUT HOW TO OPTIMALLY SPECIFY RSA'S RE BUILD PROGRAMME• In order to stress test the study’s main finding (that cost is no longer a barrier to an accelerated energy transition) we considered three examples
of ‘realistic’ scenarios: ‘Modest RE pathway’, ‘Ambitious RE pathway’ and ‘coal-off by 2040’
– Even with these ‘reality-adjustments’ the scenarios support the study’s main finding – cost is not a material barrier
• What then does the optimal ‘realistic’ build programme look like? This is the real question RSA should be concerned with now:
– It should be as close to the theoretically optimal scenarios as possible whilst accommodating realistic constraints and policy objectives
• Speeding up Tx infrastructure upgrade processes to enable an optimal mix should be prioritised in order to lower the system cost
• Targeting development in declining mining regions and addressing the need for localisation and sector transformation
• The major constraints on the RE industry are policy uncertainty and regulatory restrictions – these can be addressed through political
commitment and sector reforms
• We know that the RE build must be immediate and ambitious
- A slow start means we are highly unlikely to achieve Paris-alignment and economic competitiveness in the low carbon global future. Emissions
over the long-term are most easily and cost-effectively achieved by initiating coal phase down immediately, and allowing it to proceed steadily
- For a similar level of costs, a more ambitious RE build pathway delivers valuable options for more rapid future decarbonisation if required, and
- scaling up of the associated economic stimulus and socio-economic benefits (especially in areas which will be most impacted by reduced coal-
Paris Agreement The Paris Agreement provides a global framework for avoiding dangerous climate change by limiting global warming to well below 2°C above pre-
industrial levels and pursuing efforts to limit it to 1.5°C
PLEXOS Model Plexos is an integrated optimisation model used for long-, medium-, and short-term energy market analysis to inform power system planning
PM Particulate Matter
PPD Peak-Plateau-Decline
Precautionary Principle The UNFCCC specify in Article 3 (3) of the Paris Agreement that signatory Member States should take precautionary measures to
anticipate, prevent or minimise the causes of climate change and mitigate its adverse effects
PV Photovoltaic
REDZ Renewable Energy Development Zones (see Additional Information)
REIPPPP Renewable Energy Independent Power Producer Procurement Programme; South Africa’s renewable energy auction process launched in 2010 as
part of a set of interventions to enhance South Africa’s electrical power generation capacity (see Additional Information)
RSA Republic of South Africa
SEA Strategic Environmental Assessment
SO2 Sulphur Dioxide
SSEG Small-Scale Embedded Generation
UNFCCC United Nations Framework Convention for Climate Change
VOM Variable Operations and Maintenance
GLOSSARY OF TERMS, ACRONYMS AND ABBREVIATIONS
Glossary Reference List Additional Information Assumption Detail
REFERENCE LIST (1)• Burton, J. et al., 2018 “Coal transition in South Africa - Understanding the implications of a 2°C-compatible coal phase-out for South Africa.” IDDRI & Climate Strategies
• BP Global Energy Outlook, 2019. Available: http://www.bp.com/statisticalreview
• Council of Scientific and Industrial Research [CSIR], 2020. “Setting up for the 2020s: Addressing South Africa’s electricity crisis and getting ready for the next decade.”
• CSIR, 2016 “Wind and solar PV resource aggregation study for South Africa,” Report: November 2016. Available:
• CSIR, 2019 “Additional renewable energy development zones proposed for wind and solar PV”, Available: https://www.csir.co.za/renewable-energy-development-zones
• CSIR, 2020 “Systems analysis to support increasingly ambitious CO2 emissions scenarios in the South African electricity system”, Available: http://hdl.handle.net/10204/11483
• Department of Environmental Affairs, 2016. Strategic Environmental Assessment for Electricity Grid Infrastructure in South Africa. CSIR Report Number:
CSIR/02100/EMS/ER/2016/0006/B. Stellenbosch.
• Department of Environment Forestry and Fisheries, 2019. Phase 2 Strategic Environmental Assessment for wind and solar PV energy in South Africa. CSIR Report Number:
CSIR/SPLA/SECO/ER/2019/0085 Stellenbosch, Western Cape.
• Dentons, 2015 “Report in respect of the investigation into the status of the business and challenges experienced by Eskom.”
• Eberhard, A. and Naude, R. 2017. The South African Renewable Energy IPP Procurement Programme: Review, Lessons Learned and Proposals to Reduce Transaction Costs. Report:
University of Cape Town, Graduate School of Business.
• Energy Intelligence, 2016. REIPPPP: All you need to know. Available: https://www.energyintelligence.co.za/reippp-all-you-need-to-know/
• EPRI, 2017 “Power Generation Technology Data for Integrated Resource Plan of South Africa,” Tech. Rep., no. August, pp. 10-3-10–5.
• Eskom, 2019a “Shutdown of Grootvlei, Komati & Hendrina Power Stations – GGF,” 25 April 2019.
• Eskom, 2019b “Applications for suspension, alternative limits and/or postponement of the MES compliance timeframes for Eskom’s coal and liquid fuel fired power stations”,
March 2019.
• Eskom, 2019c, Eskom Transmission Development Plan (TDP) 2020-2019 Public Forum “Impacts of the IRP 2019”, Presented 31 October 2019.
• Eskom, 2019d, Eskom Transmission Development Plan (TDP) 2020-2019 Public Forum “Planning for the South African Integrated Power System: Generation
Assumptions”, Presented 31 October 2019.
Glossary Reference List Additional Information Assumption Detail
REFERENCE LIST (2) • He, G., Lin, J., Sifuentes, F. et al., 2020. Rapid cost decrease of renewables and storage accelerates the decarbonization of China’s power system. Nat Commun 11, 2486.
policy : Alternatives for the South African electricity system.”
• Meridian Economics, 2020a “Accelerating renewable energy industrialisation in South Africa: What’s stopping us?”
• Meridian Economics 2020b (Carbon Policy Brief)
• Meridian Economics 2020c “Meridian’s renewable energy levelised cost tool,” Explanatory Note: June 2020
• Meridian Economics, 2017 “Eskom’s financial crisis and the viability of coal-fired power in South Africa: Implications for Kusile and the older coal-fired power stations.”
• Merven et al, 2018 “Quantifying the macro- and socio-economic benefits of a transition to renewable energy in South Africa,” SA-TIEDS working paper June 2018, Available:
• Marquard, A., 2019 “The development of South Africa’s energy emissions path and the implications for our Nationally Determined Contribution,” Presented SA-TIED Workshop
2019.
• Naledzi, 2018 “Component 4 Health impact focused CBA”, November 2018.
• NREL (National Renewable Energy Laboratory), “2019 Annual Technology Baseline,” Golden, CO Natl. Renew. Energy Lab., 2019.
• Our World In Data, 2020. Available: www.ourworldindata.org
• Peters, G., 2017 “What does ‘well below 2°C’ mean?” CICERO blog post, Available: https://cicero.oslo.no/no/posts/klima/well-below-2c
• Rahmstorf and Levermann, 2017 “Why global emissions must peak by 2020”, Available: http://www.realclimate.org/index.php/archives/2017/06/why-global-emissions-must-
peak-by-2020/
• SAREM, 2020. SA Renewable Energy Roadmap, methodological approach, draft for workshopping. Greencape.
• UNFCCC, 2015. Paris Agreement to the United Nations Framework Convention on Climate Change
Glossary Reference List Additional Information Assumption Detail
1. Abatement technology and timeframe : What can we assume will be retrofit when?
• Here, a distinction is recognised between regulatory compliance and Eskom’s planned retrofit schedule - which is not fully compliant with the Air
Quality Regulations (Eskom, 2019b). In the study we opt for the latter, to be consistent with the 2019 IRP* and therefore to ensure consistency across
baseline and scenarios. It is worth noting that this is a conservative assumption in the context of the study, as full compliance assumes greater coal
fleet cost, increasing the cost of the baseline versus the mitigation scenarios.
• The technologies retrofit at each plant, including retrofit dates are taken from Eskom’s committed retrofit schedule (Eskom, 2019b). It was assumed
that no downtime outside the ordinary maintenance schedule was required for retrofits**.
2. Costs : How much will these retrofits cost?
• Capital and operating costs associated with each abatement technology are Eskom’s (Naledzi, 2018). The Flue Gas Desulphurisation (FGD) costs in
particular have been critiqued as being inflated*** & ****
• MES shown includes MES Opex as well as CAPEX annualised from the date spent to the closing date of the station in the reference scenario (IRP)
ESTABLISHING A BASELINE LOCAL AIR POLLUTANT MITIGATION PROFILE FOR THE COAL FLEET
Assumption DetailGlossary Reference List Additional Information
Note: Eskom’s public documents underpinning the local air pollutant profile are difficult to navigate. The assumptions upon which each document builds are not always clearly spelled out. Whilst
we only rely on information in the public domain, our interpretation of this frequently required clarification with Eskom’s Environmental Management Unit.
*The 2019 IRP assumes the ‘MES 1’ scenario developed by Eskom and used in the Medium Term System Adequacy Outlook, Eskom, 30 October 2019. The MES 1 scenario is that contained in the
2019 Applications for suspension, alternative limits and/or postponement of the MES compliance timeframes for Eskom’s coal and liquid fuel fired power stations’ dated March 2019 (Eskom
ENV18-245 rev 2.1). (Confirmed by Deidre Herbst, personal communication, 2019).
**Personal communication CSIR 2019; Sahu email 09-11-2019. We note that this is different to Eskom’s assumption in the MTSAO 2019, where MES 1 increases planned outages.
***Personal communication with various international experts (Myllyvirta, Rosenberg)
****FGDs increase CO2 emissions slightly due to the addition of limestone into the boiler. The technology also reduces energy output, in the region of a percent. Neither of these aspects were
included in the modelling, as neither was held to be materially significant.