2018 to 2023

Generation System Adequacy for the Republic of South Africa SYSTEM OPERATOR | CORNER REFINERY ROAD AND POWER STREET, GERMISTON, 1401 0

IMPORTANT NOTICE While the System Operator has taken all reasonable care in the collection and analysis of data available, the System Operator is not responsible for any loss that may be attributed to the use of this information. The changing environment in the South African energy industry means continually changing data that might not have been included in the modelling of this study.

The study is not intended to be used as a plan, but rather to explore how possible different futures might test the adequacy of a generation system. Prior to taking business decisions, interested parties are advised to seek separate and independent opinion in relation to the matters covered by this report and should not rely solely on data and information contained here. Information in this document does not amount to a recommendation in respect of any possible investment.

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Table of contents 1 Introduction ...... 5 2 Methodology ...... 5 3 Assumptions ...... 6 3.1 Demand forecast ...... 7 3.2 Eskom existing and committed supply resources ...... 7 3.2.1 Eskom committed build schedule ...... 8 3.2.2 Shutdown of coal stations ...... 8 3.2.3 Eskom existing and committed sent-out capacity ...... 9 3.3 Non-Eskom existing installed capacity ...... 10 3.4 Renewable energy independent power producers contracted by Eskom ...... 10 3.5 Small- to medium-scale embedded generation (solar PV) ...... 11 3.6 Demand response ...... 11 3.7 Plant performance ...... 12 3.7.1 Modelling of plant performance ...... 12 3.7.1.1 Planned outages ...... 12 3.7.1.2 Forced outages ...... 12 3.7.1.3 Partial load losses ...... 13 3.8 Air quality retrofitting ...... 13 4 Study cases ...... 14 5 Results ...... 15 5.1 Results of adequacy study ...... 15 5.2 Plant required to restore adequacy ...... 15 6 Risks to system adequacy ...... 15 7 Conclusion ...... 16 8 Appendix: System Operator Statistics...... 17

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List of figures

Figure 1: MTSAO methodology ...... 6 Figure 2: Energy demand forecast ...... 7 Figure 4: Shutdown of Eskom coal station units ...... 9 Figure 3: Eskom installed sent-out capacity (MW) ...... 9 Figure 5: Non-Eskom installed capacity ...... 10 Figure 6: Estimated and forecasted small- to medium-scale embedded generation (solar PV) ...... 11 Figure 7: Eskom plant performance ...... 12 Figure 8: Capacity reduction due to air quality non-compliance ...... 13 Figure 9: MTSAO 2018 scenarios ...... 14 Figure 10: Year-to-date OCGT utilisation ...... 17 Figure 11: Number of frequency incidents ...... 18

List of tables

Table 1: MTSAO adequacy metrics ...... 5 Table 2: Eskom committed build capacity ...... 8 Table 3: REIPP cumulative installed capacity ...... 11 Table 4: MTSAO 2018 system adequacy levers required to close gaps in MW ...... 15

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Glossary of terms Term Definition The output parameters that are tracked in order to determine whether the Adequacy metrics power system is within acceptable thresholds Base-load The plant capable of generating all day, when available

The ratio of the actual generated energy against the nominal energy (sent- Capacity factor out energy capability), representing the extent to which the installed capacity is utilised

CSP Concentrated solar power

Unit output above its maximum continuous rating maximum that could be EL1 produced for a short period on specific request of the System Operator

Ratio of the available energy generation over a given time period to the Energy availability factor (EAF) maximum amount of energy that could be produced over the same time period, expressed as a percentage

The plant that usually generates before the morning and evening peak Mid-merit demand and has a typical capacity factor range of 10% to 40% National Energy Regulator of South The regulator of the electricity industry in terms of the Electricity Regulation Africa (NERSA) Act 4 of 2006 Generation capacity from a third party (external source) not necessarily Non-Eskom capacity connected to the utility’s grid The ratio of other unplanned energy losses (not under plant management’s control, including internal non-engineering constraints) to the maximum Other capability load factor amount of energy that could be produced over the same time period, expressed as a percentage Partial load losses Partial capacity reduction due to unplanned events

Peaking The plant generating only during the peak demand or emergency hours The ratio of planned energy losses during a given period of time to the Planned capability load factor maximum amount of energy that could be produced over the same time period, expressed as a percentage PV Solar photovoltaic SO The System Operator who is responsible for dispatch of power The ratio of unplanned energy losses during a given period of time to the Unplanned capability load factor maximum amount of energy that could be produced over the same time period, expressed as a percentage The amount of energy that cannot be supplied to consumers, resulting in Unserved energy involuntary loss of supply to customers due to insufficient generation capacity, demand-side participation, or network capability

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1 Introduction The South African Grid Code (SAGC, Version 9 July 2014) requires that the System Operator (SO) publish a review (called the Medium-Term System Adequacy Outlook) on or before 30 October of each year of the adequacy of the integrated power system to meet the medium-term (five-year future) requirements of electricity consumers.

In preparing the MTSAO, the SO considers the most recent information provided by Eskom generators, independent power producers, other non-Eskom generators, the national transmission company, transmission network service providers, and distributors such as:

 possible scenarios for growth in the demand of electricity consumers;  possible scenarios for growth in generation available to meet that demand;  committed projects for additional generation;  demand management programmes; and  reasonable assumptions on imports and exports and any other information that the SO may reasonably deem appropriate.

This Medium-term System Adequacy Outlook (MTSAO) provides a statement of generation adequacy to meet the expected electricity demand for the next five years (calendar years 2018 to 2023). The adequacy to transmit and distribute electricity does not form part of this MTSAO.

2 Methodology Generation adequacy studies are carried out to assess the balance between supply and demand, without taking into account any limitations imposed by the transmission or distribution systems. Based on South Africa’s load-shedding experience in year 2008, four metrics shown in Table 1 below were chosen to reflect risk associated with supply shortages to avoid the unreasonably high cost associated with reducing this risk to a negligible level. The adequacy metrics provide information on the operational, capacity, and energy adequacy of the generation system to meet expected demand. The system is deemed adequate if all four system adequacy metrics are satisfied.

Table 1: MTSAO adequacy metrics

Adequacy metric Threshold Details Unserved energy < 20 GWh per annum Energy not supplied OCCGT load factor < 6% per annum Gross load factor of all OCGT plant Energy supplied by generators operating above their continuous < 133 GWh per Emergency Level 1 rating. EL1 above the 133 GWh threshold is adjusted against the annum OCGT energy production. Expensive baseload < 50% per annum Gross load factor of the expensive coal-fired base-load stations stations

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The MTSAO assesses system risks using a Monte Carlo simulation technique, with the PLEXOS® Simulation Software, on an hourly unit commitment and economic dispatch problem that does an optimisation under uncertainties of the load, renewable generation production (particularly wind and solar), and plant outages. The simulation results are tested against the four adequacy metrics discussed above. Should any of the adequacy metrics not be met, additional capacity is then added as per the iterative process shown in Figure 1 until all the adequacy metrics have been met. The capacity options added to get to an adequate system are quantified per year and classified as base-load, mid-merit, or peaking capacity in MW, depending on the capacity factor required by the system for this resource.

Figure 1: MTSAO methodology

3 Assumptions The assumptions with the largest impact on system adequacy are the demand forecast, the available resources to meet demand, the performance of the plant, and the commercial operation dates of plant under construction. These assumptions are outlined in the following subsections. For the purposes of this assessment, it was assumed that the transient stability scheme (TSS) currently under construction would not affect the dispatch of units at Medupi or Matimba. The TSS would provide protection against the loss of rotor stability at Matimba and/or Medupi in the event of a fault close to or at Matimba or Medupi. Furthermore, the load-shedding events of June to July 2018 due to labour-related strike action and possible future events were not specifically included in the assessment.

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3.1 Demand forecast Stats SA reported that South Africa’s energy consumption increased from 244.8 TWh in the 2016 calendar year to 244.5 TWh in the 20171 calendar year, a decrease of 0.1%. The System Operator envisages energy demand growth to be conservative in the medium term and has derived two energy demand trajectories for the country based on the moderate- and low- growth scenarios as shown in Figure 2 below. The moderate energy forecast has an annual average growth rate (AAGR) of 1.9%, while the low energy forecast is based on a 0.64% AAGR.

Energy Demand Forecast & Growth Rate 275 3.00

270 2.50 2.00 265 1.50 260 1.00 255

0.50 GrowthRate[%] Energy Energy [TWh] 250 0.00

245 -0.50

240 -1.00 2017 2018 2019 2020 2021 2022 2023 Year Low Growth Rate Moderate Growth Rate Low Forecast Moderate Forecast Figure 2: Energy demand forecast

3.2 Eskom existing and committed supply resources Generation resources and demand-side initiatives are both used to meet the forecast demand. The South African power system is made up of Eskom plant, which currently forms the bulk of existing plant, non-Eskom generation resources licensed by NERSA, peaking and renewable independent power producers (IPPs) contracted by Eskom, imports, and demand-side management resources. Capacities of generation resources are grouped in terms of existing and committed Eskom plant, existing non-Eskom plant, existing and committed Eskom-contracted IPPs, and small- to medium-scale embedded generation.

1 Source: Statistics South Africa “Electricity generated and available for distribution”, March 2018

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Outlined below are details of the existing installed capacity, new capacity (in terms of quantity and timing) to be commissioned during the period of study, and capacity expected to be shut down during the period of study. 3.2.1 Eskom committed build schedule The commercial operation dates (CoDs) of Eskom committed new build used in the assessment are shown in Table 2 below for Medupi and Kusile Power Stations, respectively. The impact of the possible early commercial operation of Medupi Unit 2, which was synchronised to the national grid during October 2018 ahead of schedule, was not assessed in the study.

Table 2: Eskom committed build capacity

MEDUPI KUSILE Unit 6 Commercial Unit 1 Commercial Unit 5 Commercial Unit 2 31-Mar-2019 Unit 4 Commercial Unit 3 31-Dec-2019 Unit 3 31-Dec-2018 Unit 4 31-Dec-2020 Unit 2 31-May-2019 Unit 5 31-Aug-2021 Unit 1 30-Nov-2019 Unit 6 30-Jun-2022

Eskom new build programmes will add an additional 5 721 MW between 2019 and 2023. 3.2.2 Shutdown of coal stations Capacity from Duvha Unit 3 was assumed not to be available for the purposes of the study. The study further assumed that the units at Grootvlei, Hendrina, and Komati would be shut down when it was no longer economical to carry out maintenance required in terms of the Occupational Health and Safety Act (OHS Act) or turbine running hours. As at September 2018, 10 units had already been shut down at these stations, removing 1 389 MW from the Eskom generation installed base. It was assumed that the remaining units at these stations would be shut down when it is no longer economical to carry out this maintenance.

Shut down refers to a unit brought down to zero power, but may be restarted in the future if the necessary maintenance work is performed. However, for the purpose of this study, it was assumed that these units would not be returned to service during the study period. This should not be confused with decommissioning, which takes a unit out of service permanently or leaves it dismantled partly or wholly, or closure of a facility to the extent that it cannot be readily returned to service.

For the purposes of the assessment, other Eskom coal-fired units reaching their 50-year life were also shut down, similar to the draft IRP 2018. This resulted in the shutdown of a single unit at Arnot in 2021 and all the units of Camden between 2021 and 2023. The cumulative capacity shut down during the study period is depicted in Figure 3.

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Capacity Shutdown of Eskom Coal Stations 8 000 7 000 6 000 5 000 4 000 3 000

2 000 Capacity [MW] Capacity 1 000

-

Jul-18 Jul-19 Jul-20 Jul-21 Jul-22 Jul-23

Jan-20 Jan-18 Jan-19 Jan-21 Jan-22 Jan-23

Oct-18 Oct-19 Oct-20 Oct-21 Oct-22 Oct-23

Apr-18 Apr-19 Apr-20 Apr-21 Apr-22 Apr-23 Month Arnot Camden Hendrina Grootvlei Komati

Figure 3: Shutdown of Eskom coal station units

This study then effectively assumed that 3 880 MW would be shut down at Hendrina, Grootvlei, and Komati by the end of the study period. In addition, one unit at Arnot Power Station (372 MW) would be shut down in 2021 and all the units at Camden Power Station (1 481 MW), starting in 2021 and completed in 2023. A total of 5 731 MW would have been removed from the system by 2023. 3.2.3 Eskom existing and committed sent-out capacity The total Eskom installed capacity consists of coal, nuclear, pumped storage, diesel, hydro, and wind as shown in Figure 4. The assumed timing of commissioning of new build stations and shutting down of some units from older stations is as outlined in the following subsections.

Eskom Installed Capacity Tech 2018 2019 2020 2021 2022 2023 50000 Coal 36822 37839 39087 38690 38996 38074 Nuclear 1860 1860 1860 1860 1860 1860 40000 Pump 30000 Storage 2732 2732 2732 2732 2732 2732 Hydro 600 600 600 600 600 600 Capacity [MW] Capacity 20000 2018 2019 2020 2021 2022 2023 Gas 2405 2405 2405 2405 2405 2405 Year Wind 100 100 100 100 100 100 Coal Nuclear Pumped Storage Hydro Gas Wind Total 44519 45536 46784 46387 46693 45771

Figure 4: Eskom installed sent-out capacity (MW)

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3.3 Non-Eskom existing installed capacity Installed sent-out capacity of non-Eskom generation in South Africa is shown in Figure 5 below, excluding the Renewable Energy Independent Power Producer (REIPP) Programme. The capacity from Cahora Bassa (imported hydropower from Mozambique) is also reflected in the figure. For the purposes of the study, it was assumed that one generation unit of the five installed was on indefinite standby for contingencies, reducing the total capacity from Cahora Bassa available to the South African system to 1 100 MW.

The study, furthermore, assumed that, although short-term contracts between Eskom and some of the non-Eskom generators expired before or on 31 March 2017 (and had not been renewed), those generators would continue generating for own use. The energy produced by non-Eskom plant, excluding Cahora Bassa, was limited to 11 TWh2 per year throughout the study horizon. Any reduction in this production would negatively affect the system adequacy outlook.

Non Eskom Installed Capacity 140 140 Kelvin 12 Sasol Infrachem Coal 180 125 174 324 Sasol Synfuel Coal 144 Sasol Infrachem Gas 600 Sasol Synfuel Gas CahoraBassa DoE Gas 175 Mondi 1 005 250 SappiNgodwana Steenbras Other Gas Other CoGen 1 100 Other Hydro

Figure 5: Non-Eskom installed capacity, excluding REIPP

Due to unavailability of non-Eskom plant performance data, the MTSAO modelled typical plant performance based on plant of similar size and age. The actual generation profile of the above stations is not well understood; hence, there was a risk of overestimating their production, which would increase the demand required to be met by Eskom. 3.4 Renewable energy independent power producers contracted by Eskom The capacity available from the REIPP (contracted by Eskom under Bid Windows 1 to 4) is shown in Table 3 below.

2 Source: NERSA 2017 actuals net energy sent out

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Table 3: REIPP cumulative installed capacity, including commercially connected plants

Technology 2018 2019 2020 2021 2022 2023 Wind 1 980 2 012 2 616 3 343 3 343 3 343 PV 1 474 1 964 2 287 2 287 2 287 2 287 CSP 500 500 600 600 600 600 Hydro 14 14 19 19 19 19 Landfill 8 8 8 8 8 8 Other 25 25 25 25 Total 3 976 4 498 5 555 6 282 6 282 6 282

The timing of the commercial operation dates for Bid Window 3.5 and 4 projects signed in April 2018 was derived from the contractual dates and is different from those assumed in the October 2017 MTSAO due to delays in contracting. As at October 2018, REIPP capacity currently in commercial operation includes 1980 MW wind, 1474 MW solar PV, 300MW CSP, 14 MW landfill and 5 MW hydro. 3.5 Small- to medium-scale embedded generation (solar PV) The installed capacity of rooftop photovoltaic (PV) was assumed to be 285 MW (as at December 2017)3. Estimated and forecasted capacities are shown in Figure 6 below, showing a more aggressive growth pattern into the future.

2013 2014 2015 2016 2017

Total Installed 18 33 96 186 285 Capacity (MW)

Energy Generated 18.5 41.5 109.3 241.1 370.84 (GWh)

Figure 6: Estimated and forecasted small- to medium-scale embedded generation (solar PV)

The inclusion of these estimates did not materially change the outcome of the adequacy assessment, as the associated energy production was equivalent to less than 0.17% of the total system energy in 2017, and the technology had no impact on the peak requirements of the system. 3.6 Demand response Demand response refers to loads that can be reduced on instruction of the SO. The MTSAO assumed that the contracted interrupted loads due to expire from 2020 would not be renewed and would, therefore, not be available as emergency resources to be deployed by the SO when needed. An additional 350 MW of supplementary demand response is contracted up to March

3 Based on an April 2018 report by Eskom Research, Testing, and Development entitled “Trends and statistics of solar PV distributed generation in South Africa” 4 This amounts to 0.17% of Eskom’s 2017 energy sent out

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2018. There is no certainty regarding renewal of this option, and therefore, these options were not considered beyond this date. 3.7 Plant performance Four scenarios for Eskom generation fleet performance were considered in the MTSAO, specifically for energy availability factors (EAFs) of 80%, 75%, 73%, and 71% as reflected in Figure 7 below.

Eskom Plant Energy Availability Factor Eskom Plant Forced Outage Rate 85 20

80 15

75 10 EAF EAF [%] 70 FOR [%] 5

65 0 2018 2019 2020 2021 2022 2023 2018 2019 2020 2021 2022 2023 Year Year 80% EAF 75% EAF 73% EAF 71% EAF 80% EAF 75% EAF 73% EAF 71% EAF Figure 7: Eskom plant performance

These numbers are averages over the study period and may vary from year to year. Different combinations of planned and forced outage rates5 resulted in different annual average system EAFs, ranging from 71% to 80%. On 8 October 2018, current financial year EAF was 74.86%, while calendar year EAF was 73.6%.

For the purposes of the assessment, it was assumed that there would be sufficient coal of the correct quality available. 3.7.1 Modelling of plant performance 3.7.1.1 Planned outages Planned outages were optimised by the Projected Assessment of System Adequacy (PASA) model of PLEXOS®, which is an algorithm used to shape required maintenance events into periods of time with high capacity reserve margin. PLEXOS® enables the same pattern to be applied across scenarios with the same planned outage rate, thereby enabling a balanced comparison.

3.7.1.2 Forced outages Forced outages were modelled as independent events; that is, one generator failing does not influence the failure of another. Also, there was no certainty of forced outage at any particular time; that is, several units may fail simultaneously, or there may be no failures at all. Reasons for forced outage of a generator, such as system voltage disturbance that, in turn, causes another

5 Forced outage rate is a combination of Unplanned Capability Load Factor (UCLF) and Other Capability Load Factor (OCLF)

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3.7.1.3 Partial load losses The System Operator observed a trend of partial load losses typically increasing during peaking hours and decreasing during periods of low demand.

Since load losses are categorised as capacity on forced outage in plant performance reporting, an explicit modelling of the pattern of partial load losses improved the assessment of system adequacy during the peak period. Historical data from 2015 to 2018 year-to-date was used to predict the pattern of partial load losses used in the study. 3.8 Air quality retrofitting Eskom is legally bound to comply with the minimum emission standards (MES)6 at all power stations. The MES were promulgated in 2010 and required Eskom to comply with existing plant standards by 2015 and for existing plant to comply with new plant standards by 2020. Most of the power stations do not comply with one or more of the standards. A postponement application to delay compliance by five years was granted to Eskom in 2015. Eskom is in the process of applying for further postponements for the full implementation of the MES. For the purposes of the assessment, it was assumed that the MES would not have an impact on the availability of generation plant and that sufficient provision was made for planned outages to complete the required retrofits. If additional planned outages were to be required to do the retrofits, EAF might be negatively impacted. Should all emission projects not be concluded and the DEA not allow additional postponements, a number of units would be impacted and might be de-rated or shut down. That scenario would lead to a reduction of the total Eskom system capacity as shown in Figure 8 below.

, Figure 8: Capacity reduction due to air quality non-compliance

6 Air quality refers to sulphur oxides (SOx), nitrogen oxides (NOx) and particulate matter (PM)

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4 Study cases The scenarios considered in this assessment are shown in

Figure 9 below. Common parameters for all scenarios were the 50-year life of plant for coal power stations, shutdown dates for Grootvlei, Hendrina, and Komati, forecasted commercial operation dates for Eskom new build plants, and contracted REIPP capacity and timing. A total of six scenarios as shown in Figure 9 were tested in the study. Two demand forecasts were used, where the low demand forecast was tested against two plant performance scenarios and the moderate forecast tested against four Eskom plant performance scenarios.

Figure 9: MTSAO 2018 scenarios

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5 Results 5.1 Results of adequacy study Based on the assumptions used, the results of the MTSAO 2018 can be summarised as follows:

 At an EAF of 71%, the system is inadequate, regardless of demand growth.  At an EAF of 73%, the system is inadequate for moderate demand growth.  At an EAF of 75%, the system is adequate for all demand forecast scenarios considered.  At an EAF of 80%, the system is adequate for all demand forecast scenarios considered. 5.2 Plant required to restore adequacy Simulations were carried out on all the scenarios that violated the adequacy metrics to estimate the additional supply needed to restore system adequacy. The supply required to close the gaps was characterised as baseload, mid-merit, or peaking plant, depending on the capacity factor required by the system for this supply.

Table 4 approximates capacity needed to restore the system to adequacy. The optimal investment (in terms of quantity and timing) in capacity should be informed by a long-term planning study, such as the Integrated Resource Plan.

Table 4: MTSAO 2018 system adequacy levers required to close gaps in MW

Scenario Lever 2018 2019 2020 2021 2022 2023 Moderate demand + 71% EAF Baseload 1 000 2 100 1 000 1 500 1 500 2 100 Mid-merit - - 800 - 700 700 Peaking - - 1 500 1 500 900 600 Low demand + 71% EAF Baseload 200 400 400 400 400 400 Moderate demand + 73% EAF Baseload - 300 - - 600 1 500 Peaking - - - 300 - 900

Increasing the capacity available to the system by either increasing EAF or delaying the shutdown of units as well as demand side initiatives would increase the adequacy of the system.

6 Risks to system adequacy The MTSAO identified the following risks that could result in the deterioration of system adequacy:

 Insufficient plant maintenance due to either funding constraints or unavailability of space to do maintenance would cause deterioration of plant performance.  Earlier shutdown for economic or other reasons of Eskom and non-Eskom units. Such events would further reduce capacity available to meet the demand.

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 Insufficient coal at power stations due to the low coal stockpile levels currently experienced at some power stations. This could be exacerbated by unavailability of suitable coal and/or excessive rain in the Mpumalanga area.  Failure to comply with air quality standards might lead to load losses or shutdown of generation units or stations. Currently, some of the Eskom power stations do not comply with one or more of the minimum emission standards required by the National Environmental Management: Air Quality Act 39 of 2004. Projects to ensure compliance might be hindered by funding constraints or other logistical impediments such as compatibility of new technologies with aging Eskom plant.  Retrofitting of plant to comply with environmental legislation might require additional PCLF; this might increase the system’s planned outage days to affect retrofits and, consequently, reduce EAF, thus having an impact on the availability of generators.  The switching back to using Eskom supply by non-Eskom generators would increase demand on the system.  A further risk is a delay in the assumed Eskom and IPP commissioning dates.

7 Conclusion

The assessment indicated that the system would be adequate for the two demand scenarios studied with an EAF at 75% and above. A deteriorating EAF or increase in demand would have an impact on adequacy and could be further exacerbated if one or more of the identified risks were to materialise.

Increasing the capacity available to the system by either increasing EAF or delaying the shutdown of units as well as demand side initiatives would increase the adequacy of the system.

Care must be taken to mitigate the risks of a shortage of coal and potential impacts of the MES on the available capacity on the systems. Should these risks materialise, it would have severe negative implications for the adequacy of the system.

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8 Appendix: System Operator Statistics

Some of the monitored system reliability indices deemed relevant are reported this section based on actual System Operator year-to-date data, as at end September 2018: a. Usage of open cycle gas turbine (OCGT) load factor includes Ankerlig (1 327 MW), Gourikwa (740 MW) and Department of Energy (DoE) OCGTs at Dedisa (335 MW) and Avon (670 MW). The contractual load factor for the DoE OCGTs is 1% every half year. Figure 10 shows a weighted total OCGT utilisation of 2.15% year to date, well below the adequacy metric of 6%.

OCGT Load Factor 2018 YTD 8.00 7.00 6.00 5.00 4.00 3.00

Load Factor [%] Factor Load 2.00 1.00 0.00 Jan Feb Mar Apr May Jun Jul Aug Sep Month Ankerlig Gourikwa Avon Dedisa System

Figure 10: Year-to-date OCGT utilisation b. Frequency incidents reveal cases where reserves were deployed. Paragraph 9 of the South African Grid Code: Version 9 stipulates the type (instantaneous, regulating) and capacity in MW required to restore the system depending on the level of frequency drop. The actual incidents in Figure 11 below show that the system had sufficient reserves to recover from the disturbances. There were no incidences of frequency dropping less than 49.2Hz; such an incident would automatically activate under-frequency load shedding.

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Frequency Incidents Count 2018 YTD 60

50

40

30

No of incidemts ofNo 20

10

0 Jan Feb Mar Apr May Jun Jul Aug Sep Month

49.5 < f < 49.7 f < 49.5 f > 50.4 f > 50.5

Figure 11: Number of frequency incidents

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