TRANSMISSION SYSTEM OPERATOR

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1 TRANSMISSION SYSTEM OPERATOR Ancillary Services Technical Requirements for 2013/ /18. 0 REF. NO.: LJvR/Draft-Comments /Signature /Published

2 PAGE 2 OF 37 TABLE OF CONTENTS 1. INTRODUCTION RESERVES INTRODUCTION INSTANTANEOUS RESERVE Description Methodology REGULATING RESERVE Description Methodology Technical Requirements MINUTE RESERVE Description Methodology Technical Requirements Calculation of 10-Minute Reserve for SUPPLEMENTAL AND EMERGENCY RESERVE Description Methodology Technical Requirements RESERVE REQUIREMENTS SUMMARY BLACK START AND ISLANDING BLACK START Description Technical Requirements UNIT ISLANDING Description Technical Requirements REACTIVE POWER AND VOLTAGE CONTROL DESCRIPTION TECHNICAL REQUIREMENTS CONCLUSIONS AND RECOMMENDATIONS CONSTRAINED GENERATION INTRODUCTION... 23

3 PAGE 3 OF NATIONAL SYSTEM CONSTRAINTS Cape Constraint Arnot Constrained Generation SUPPORTING CLAUSES Scope Abbreviations and Definitions Roles and Responsibilities Monitoring Process APPENDIX A CAPE CONSTRAINT S... 37

4 PAGE 4 OF 37 List of figures Figure 1: CPS1 & Regulating Up and Down Reserves vs. System Demand in April Figure 2: CPS1 & Regulating Up and Down Reserves vs. System Demand in June Figure 3: Peak within Peak Profiles Figure 4: Ten-Minute Reserve Calculation Figure 5: Projection of Intermittent Renewable Generation Penetration Figure 6: Differences between Evening and Morning Weekday Peaks Figure 7: Representation of North of Hydra Corridor showing Measurement Points Figure 8: Graphical representation of Western Grid Corridor showing Measurement Points Figure 9: Extract of Koeberg Production Plan (Rev 63) Figure 10: Expected 2012 OCGT Usage (Constrained & Unconstrained) Figure 11: Expected 2017 OCGT Usage (Constrained & Unconstrained) Figure 12: Expected 2013 OCGT Usage for Unplanned Reactor Trip Figure 13: Expected 2017 OCGTs Usage for Koeberg Trip during Refuel Period List of tables Table 1: Instantaneous Reserve Requirements... 6 Table 2: Regulating Up and Down Requirements Table 3: 10-Minute Reserve Requirements for 2012/13 to 2017/ Table 4: Summary of Reserve Requirements Table 5: Planned Unit Islanding Tests and Incidents per Year Table 6: Energy and Peak Demand Forecast... 30

5 PAGE 5 OF 37 ANCILLARY SERVICES TECHNICAL REQUIREMENTS FOR INTRODUCTION This document specifies the technical requirements for ancillary services for the period 2013/14 till 2017/18. Its purpose is to make the technical requirements of the System Operator for ancillary services known. The technical requirements as specified in this document will be used to develop a medium term view of requirements for ancillary services in the 5-year time horizon, and to contract for the forthcoming financial year, 2013/14. The following requirements are defined as ancillary services: Reserves Black Start Islanding Reactive Power Supply and Voltage Control Constrained Generation 2. RESERVES 2.1. INTRODUCTION The definitions of the five reserve categories included in ancillary services are given in the Eskom Short Term Energy Reserve Procedure SPC 46-2 and the South African Grid Code [3]. The minimum requirement for each reserve category needs to be revised annually. Each reserve category has its own required level and is exclusive, that is, capacity reserved for one category cannot be used for another category. National Control will dispatch reserves according to the scheduling rules as far as possible while adhering to Eskom procedure SOPC0008, Control of System Frequency under Normal and Abnormal Conditions.

6 PAGE 6 OF INSTANTANEOUS RESERVE Description The instantaneous reserve is the generating capacity or demand side managed load fully available within ten seconds to arrest the frequency outside the frequency deadband. 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. Generators are also expected to respond to high frequencies (above Hz). The requirements are given in the South African Network Grid Code Methodology The requirement is to keep frequency above 49.5 Hz following all credible single contingencies from a frequency within the deadband limit of 50±0.15 Hz. The credible single contingency is the loss of the largest unit. The credible multiple contingency is the loss of three typical coal fired units. The effect of rotating loads on system frequency was considered in the study Technical Requirements There is no current technical requirement for Instantaneous Down reserve capacity. However this service is mandatory for all generators according to the South African Network Grid Code, especially if the frequency exceeds 50.5 Hz. The Instantaneous Up reserve requirement was determined using DigSilent, establishing the effect of governing on system frequency [17]. The study tested various scenarios including various amounts of generation and demand side governing capacity. The study results indicated that more demand side capacity is needed to replace the equivalent generation capacity. The results are shown in Table 1. Table 1: Instantaneous Reserve Requirements

7 PAGE 7 OF 37 Period 2013/ / / / /18 Peak Off Peak This shows that a total instantaneous reserve of 600 during peak periods and 700 during off peak periods is required for the review period. These requirements are based on only generators providing all the instantaneous reserves REGULATING RESERVE Description Regulating Reserve is generating capacity or demand side managed load that is available to respond within 10 seconds and is fully activated within 10 minutes. The purpose of this reserve is to make enough capacity available to maintain the frequency close to scheduled frequency and keep tie line flows within schedule Methodology The regulating up and down requirement is based on meeting the following: i. Control Performance Standard (CPS1) performance criterion ii. Cater for a trip of an average unit on the IPS Technical Requirements The IPS needs sufficient regulating range up and down every hour of the day to keep the frequency and tie lines within acceptable limits, while meeting the peak load within the peak hour. A) CPS1 performance criterion A control area is required to carry enough regulating reserves so that AGC operates effectively and the control area satisfies the SAPP CPS requirements. CPS1 is a statistical measure of variability of the ACE of a control area, measuring the ACE in

8 PAGE 8 OF 37 combination with the frequency error of the interconnection for a control area. It measures whether a control area s control action helps or hurts the power system i.e. during low frequencies, does the control area act to increase generation and during high frequencies, does the control area act to decrease generation. To meet the CPS standard, a control area must meet CPS1 most of the time. Assuming the system frequency performance remained as observed in 2012, the optimal regulating up and down reserves to meet CPS1 were determined. Figure 1: CPS1 & Regulating Up and Down Reserves vs. System Demand in April 2012 Figure 1 shows that CPS1 exceeds 100% when regulating up and down reserves are each at least 500.

9 PAGE 9 OF 37 Figure 2: CPS1 & Regulating Up and Down Reserves vs. System Demand in June 2012 Figure 2 shows that regulating up and down reserves should be at least 550 to meet CPS1. Between 06:00 am and 09:00 am, and between 17:00 pm and 21:00 pm, the load changes fairly rapidly, requiring manual intervention from controllers. Thus, the analysis of AGC performance is considered from 09:00 am till 17:00 pm, outside of which, the system load changes more slowly. B) The Trip of an Average Unit on the IPS Although Koeberg is the largest generating unit on the Eskom IPS, there are only two units at Koeberg, making the probability of a unit trip small. Consequently, the average unit size of the coal fired units is used, around 600. Since the frequency is required to return to 50 Hz after a unit trip, and over peak there is little 10-minute reserve available (assuming all spinning and quick start units are running near MCR, at least 600 of the regulating up reserve and 600 of regulating down reserve are required.

10 PAGE 10 OF 37 Table 2: Regulating Up and Down Requirements Period 2013/ / / / /18 Peak Off Peak MINUTE RESERVE Description 10-Minute Reserve is generating capacity or demand side managed load that can respond within 10 minutes when called upon. It may consist of offline quick start generating plant (e.g. hydro or pumped storage) or demand side capacity that can be committed within 10 minutes. The purpose of this reserve is to restore Instantaneous and Regulating Reserve to the required levels after an incident. The 10-Minute Reserve is bid in day-ahead into the reserve market. 10-Minute Reserve may also be used for localised voltage stability and capacity constraints. Ancillary Services requires resources which may be used up to 600 hours per year (assuming a usage over 50 weeks, 4 days and 3 peak hours per day) for the 10-minute market. In addition, if the cost of any potential 10-minute reserve resource is close to or higher than gas turbines, it must be used in the emergency reserve market. Any new 10- Minute reserve resource must have no onerous energy restrictions since this reserve may be required to be used nearly every day Methodology The total requirement is based on carrying sufficient 10-Minute reserve to ensure that: i. The total operating reserve can replace a credible multiple unit trip ii. The total operating reserve meets SAPP operating reserve requirements iii. The total regulating (in one direction) plus 10-Minute reserves cater for typical peak within peak load variations The requirement is the greater of the three criteria.

11 PAGE 11 OF Technical Requirements A) Multiple unit trip requirement A credible multiple unit trip is defined in the grid code as a typical trip of three coal fired units. To ensure reliability it was assumed that the total operating reserve should be sufficient to replace the loss of three biggest coal fired units. Thus, up to 2014 Majuba has the biggest three units at 3 x 669 = 2007 and from 2015 Medupi will have the biggest three coal fired units at 3 x 722 = The 10- Minute reserve requirement = Total operating instantaneous regulating B) SAPP Requirement The proposed SAPP Operating Guidelines state that a minimum of 1070 of operating reserve is currently required from the Eskom control area and half of this must be spinning reserve. The 10-Minute reserve requirement = Total operating instantaneous - regulating C) Peak within peak study The peak within peak is defined as the difference between the absolute peak and the average demand for the hour. Peak within peak values were calculated for typical weeks in summer and winter. Figure 3: Peak within Peak Profiles

12 PAGE 12 OF 37 Figure 3 is based on typical weeks for August 2011 to July 2012 months. Thus, peak within peak value = Average value was chosen to have a representative value. The difference between the absolute peak and the average is minimal Calculation of 10-Minute Reserve for The 10-Minute requirement was evaluated using the following equation: 10-Minute requirement = maximum(mut capacity - IR - RR, SAPP requirement - IR - RR, Pk_in_Pk RR), where MUT is a multiple unit trip, IR is the instantaneous reserve, RR is the regulating reserve and Pk_in_Pk is the peak within the peak. The results are summarised as follows: Figure 4: Ten-Minute Reserve Calculation The 10-Minute reserve requirements are shown in Table 3 below. Table 3: 10-Minute Reserve Requirements for 2012/13 to 2017/18 Period 2013/ / / / /18 Peak Off Peak Literature shows that impact of intermittent generation is significant on frequency control above 15% penetration levels. Since intermittent generation penetration is less than 10% by 2017, no significant impact is expected on operating reserve. Thus, the above stated operating reserves requirements should be sufficient to counter the effect of renewables on frequency control. See Figure 5 below:

13 PAGE 13 OF 37 Figure 5: Projection of Intermittent Renewable Generation Penetration 2.5. SUPPLEMENTAL AND EMERGENCY RESERVE Description Supplemental Reserve is generating capacity that can respond within 6 hours or demand side managed load that can respond normally within 2 hours to restore the other reserves. This reserve must be available for at least 2 hours (See SPC 46-2). Emergency Reserves are reserves that are required less often than 10-minute reserves. Emergency Reserves can also be used for other emergency operation such as local network energy constraints and voltage control. This includes interruptible loads, generator emergency capacity (EL1), and gas turbines. The call up time depends on the technology but a maximum call up of 10 minutes is preferred. Each of these reserves needs to be certified and contracted year-ahead. Emergency Reserve is utilised in accordance with SOPC0008. The reserve must also be under the direct control of the control room at National Control. These requirements arise from the need to take quick action when any abnormality arises on the system Methodology The total requirement is based on the replacement of the largest power station capacity assuming that there is no operating reserves.

14 PAGE 14 OF Technical Requirements A) Supplemental Reserve Rationale is to shave off week day peaks to cater for Generation maintenance. The potential capacity for Generation maintenance is the difference between eveninghours peak and day hours-peak based on instantaneous four seconds load data. Typical summer and winter week day load profiles were studied to identify the peak magnitudes and durations. The plot below shows a summary of the evening peak to morning peak differences. The plot shows the maximum available to generation for maintenance provided the equivalent supplemental capacity is available for at least two hours. Thus, up to 3000 of supplemental reserve is required. Figure 6: Differences between Evening and Morning Weekday Peaks B) Emergency Reserve The worst contingency catered for in deriving the technical requirements is the loss of the largest power station, which should be replaced by supplemental and emergency capacity. Majuba is the largest power station from 2013/14 till 2016/17 with a total capacity of From 2017/18 Medupi will be the new largest power station with a total capacity of 4332 according to the 2010 integrated

15 PAGE 15 OF 37 resource plan. If system operating reserve is zero over peak load and the largest station is lost, we need about 3900 till 2016/17 and 4400 in 2017/18 of emergency plus supplemental reserve to replace the lost generation. The emergency requirement is the total requirement (largest station capacity) minus the supplemental requirement RESERVE REQUIREMENTS SUMMARY Table 4 shows the expected requirements for each reserve category during each time of use period (peak and off peak) for 2013/14 till 2017/18. Table 4: Summary of Reserve Requirements Reserve Time of Use Period 2013/ / / / /18 Instantaneous Peak Off Peak Regulating Peak Off Peak Minute Peak Off Peak Total Operating Pk/ Off_Pk Supplemental Pk/ Off_Pk Emergency Pk/ Off_Pk BLACK START AND ISLANDING Black start and unit islanding services are required for restoring the network in the event of a blackout or an incident on the system.

16 PAGE 16 OF BLACK START Description System black start capability is the provision of generating equipment that, following a system black out, is able: To start itself without an outside electrical supply (self-start), and To energise a defined portion of the transmission system so that it can act as a start-up supply for other base load generators to be synchronised as part of a process of power system restoration Technical Requirements The South African Grid Code (System Operations Code v8) requires that there be at least two suitable black start facilities in the system. Further, the System Operator must coordinate maintenance between the black start facilities to ensure that at least one facility is always available. A) General Requirements Each black start facility shall be available at least 90% of the year as long as maintenance and repairs are coordinated such that there is at least one facility available all the time. Periodic compliance monitoring tests as required by the System Operator. These tests may include testing the self-start facility and monitoring fuel and water levels. To prove the capability of the system, the System Operator shall perform black start tests periodically as required by the South African Grid Code, Network Code Appendix A2.3.8 GCR8 version 8. This shall be done in accordance with the latest version of the operating standard SOST Units contracted for black start shall be capable of providing sufficient reactive power support to control the declared transmission voltages between ±5% of nominal voltage. The black start facility shall be capable of maintaining the frequency within 49 to 51 Hz during energisation and load pick up

17 PAGE 17 OF 37 Due to the fact that system failures can occur during restoration, the power station shall be capable of sequentially black starting a unit up to 3 times. B) Technical Requirements For Black Start Facilities A thermal power station shall be capable of self-starting at least one unit after a forced shut down without support from the external grid The first unit shall be capable of energising a portion of the power system within four hours of shutdown The unit shall be capable of picking up load blocks of 30 to 50 There shall have sufficient fuel for three black start attempts on the unit at all times Geographical location of a unit capable of Black starting has to allow for restoration without technical constraints. Sufficient reactive power required for voltage control during energising. C) Additional Requirements For Pump Storage or Hydro Black Start Facility A pumped storage/ hydro station shall be capable of self-starting one or more units, energising a part of the grid (line to a thermal station) and so providing auxiliary power to enable a thermal unit to start within four hours of shutdown of the thermal unit D) Required Black Start Diesel Generator Tests per Year Weekly and monthly tests requirements are conducted as follows: Full Speed No Load [FSNL] run machine once a week for 2 hours Full Speed Base Load [FSBL] run machine once a month for 3 hours The tests are done to heat soak the machines, so reducing the risk of rotor and stator misalignment UNIT ISLANDING Description Unit islanding refers to the capability of a generating unit to disconnect from the transmission system by opening the HV breaker, and to automatically control its

18 PAGE 18 OF 37 auxiliaries to maintain stability of the turbo generator, and to supply its auxiliary load without external supply. The unit shall be capable of islanding from full load and remaining in an islanded state for at least two hours Technical Requirements Unit islanding is a mandatory ancillary service for generating units certified for islanding. To prove the capability of the station to be certified, the South African Grid Code (Network Code, Appendix A2.3.8) (SAGC) requires a once off test to be performed. A) Grid Code Requirements Units that do not have a black start facility or self start capability shall island when required. Thus all the units commissioned after the SAGC should have Islanding capabilities. Return to service units are currently exempted from this requirement as they do not have an HP bypass facility required for islanding. The SAGC specifies that only units rating greater than 200 MVA will be certified. B) Prototype and Routine Tests The prototype test is only done on a representative unit for the station with routine testing being required for all remaining units. The once off prototype test requires the unit be islanded from full output and remain in an islanded state for a minimum of two hours. Routine tests shall be performed on each unit after each general overhaul or six years. Routine tests require a unit to island from 60% of MCR and remain there for 20 minutes, under normal operating conditions. The tests shall be carried out in accordance with the latest version of procedure EPC , Certification/ Decertification Procedure for Turbo-Generator Unit Islanding and Standard for Steam Turbine Unit Islanding, Load Rejection and Speed Control Verification (GGS 0500).

19 PAGE 19 OF 37 C) Planned Unit Islanding Tests and Expected Incidents Table 5 shows the planned routine Islanding tests and the expected Islanding Incidents per year from 2013/14 till 2017/18. The plan includes expected tests to be done on the new coal and pump storage units. Table 5: Planned Unit Islanding Tests and Incidents per Year Usage 2013/ / / / /18 2 Hour Tests Min Tests Incidents Min Minutes 4. REACTIVE POWER AND VOLTAGE CONTROL 4.1. DESCRIPTION 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 electrical power while maintaining the required levels of supply quality and security. Voltage control involves control of reactive power to maintain acceptable voltages under normal and contingency conditions. Voltage is maintained within fairly tight range to protect the Customer and Utility equipment and prevent voltage collapse. Shunt caps, reactors and transformer tap changers are used on the Transmission system but they are slow to respond. FACTS devices do not produce voltage but can control reactive power. Synchronous generators can provide dynamic reactive power support to voltage control as quickly as possible. During start up / energising, the IPPs are only allowed to consume or export reactive power from the Transmission system by not more that 5% of rated reactive power TECHNICAL REQUIREMENTS National Control will use the installed pump storage and the open cycle gas turbines (OCGTs) in synchronous condenser operation for voltage control. The OCGTs will

20 PAGE 20 OF 37 be used for reactive power and voltage control at the discretion of National Control. All power stations capable of providing reactive power and voltage control, shall do so in consultation with the System Operator. All generators capable of voltage control shall be required to do reactive capability tests as stipulated in Eskom procedure , Generating unit reactive power and voltage control certification procedure. Additionally generators shall have automatic voltage regulators or converters in automatic voltage control mode. All units built after the implementation of the South African Grid Code shall be equipped with power system stabilisers as defined in IEC 60034, IEEE42. Reactive output shall be fully variable so as to achieve acceptable levels of voltage (± 5%) under automatic or manual control. A) SAGC Requirement for Existing Eskom Conventional Plants As required by the South African Grid Code, Network Code, all units greater than 100 shall be capable of supplying rated power output () at any point between the limits of 0.85 power factor lagging and 0.95 power factor leading at the HV side of the generator transformer. B) SAGC Requirements for Renewables Including IPPs Categry A: The IPP shall comply with a power factor range of 0.95 lagging < PF < 1.0 when generating more than 20% of rated power. Category B: The IPP shall be designed so that the operating point can lie anywhere within lagging and leading. Category C: The IPP shall be designed so that the operating point can lie anywhere within the 0.95 leading and 0.95 lagging. The IPP shall be equipped with reactive power control functions capable of controlling the reactive power supplied by the IPP at the point of connection (POC)

21 PAGE 21 OF 37 as well as a voltage control function capable of controlling the voltage at the POC via orders using set points. The reactive power and voltage control functions are mutually exclusive, which means that only one of the three functions mentioned below can be activated at a time: 1. Q-control 2. Power Factor control 3. Voltage-control The applied parameter settings for reactive power and voltage control functions shall be determined before commissioning by the NSP in collaboration with the SO. C) Voltage Control Requirement The declared transmission voltages are controlled between ± 5% and all units certified for reactive power control shall: o Run in a voltage control mode (AVR/Converter) o Be under the operational control of National Control o Respond to V-control signals from National Control and mitigate voltage variations o Successfully perform reactive power capability tests according to Eskom procedures o Be able to export/import within its reactive power capability o Notify and update NC of any problem that might affect the reactive power support D) SCO Requirement All units certified for SCO capability shall: o Be tested for SCO capability and documented in the capability report form. o Be certified for SCO operation o AS section shall witness the test. o AS shall inform NC about the certified SCO operation. o SCO operation will be used only under NC instructions.

22 PAGE 22 OF 37 o The active power () consumed during SCO operation and the duration will be recorded and used for payments. o Gas turbines built after GC implementation shall be capable of SCO 4.3. CONCLUSIONS The SAGC specifies the power factor range for the existing Eskom conventional generation plants and the Renewables code specifies this for renewable generation. The SAGC further emphasises that the voltage requirement is mandatory to all the generation suppliers and also that all generators shall have automatic voltage regulators or converters in automatic voltage control mode as opposed to Q- control mode or power factor control mode. The reactive power contribution of existing Eskom conventional plants and new IPP plants is very dependent on the technology used, the connection point and voltage level as well as additional reactive power support (SVC, STATCOM). Furthermore, the integration of IPPs such as wind farms further increases complexity and challenges to the existing protection and automation at all voltage levels within the Eskom network system.

23 PAGE 23 OF CONSTRAINED GENERATION 5.1. INTRODUCTION The Grid Code [3] requires that the System Operator manage real-time system constraints within safe operating limits, using constrained generation as one of the ancillary services as required. In particularly, 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, wherever practical. This requires the System Operator to identify national system constraints in the short term and Grid Planning outline those in the long term, define relevant system problems by establishing those constraints affecting the capacity to meet demand, and draw conclusions on the need for this service. An input in establishing the need for this service includes determining the constraints of a high probability, duration beyond a few hours having a significant impact be identified. This requirement excludes the long duration planned transmission outages that are coincident with full generation at Matimba from the list of national constraints requiring constrained generation, for example, as such planned outage can be coordinated with Matimba generation outages NATIONAL SYSTEM CONSTRAINTS The Grid Code requires that those power stations which run out of schedule as part of constrained generation must be financially compensated. There are two corridors along which generation is affected by system constraints: Cape constraint Arnot 400/275kV transformer overload constraint Medupi Power Station is not expected to be constrained down as a system protection scheme is being developed to eliminate any stability requirement that calls for Medupi to initially operate at reduced output due to initial limited network

24 PAGE 24 OF 37 capacity. [4] This sheme will be required to be operational before the second unit is commissioned Cape Constraint Consistent with Ancillary Service Technical Requirements for , [14], there is no need for constrained dispatchable generation for the period 2013/14 to 2017/18. To limit the need for use of expensive local generation, Koeberg is restricted to refuel outside of winter (01 May to 31 August). This restriction on Koeberg, requires Koeberg replace some of its partially spent fuel with new fuel, incurring a financial loss due to the Cape network constraint. Koeberg is compensated financially for this. The 765 kv Cape transmission is expected to reach Kappa substation by September 2013, increasing the Western Grid transfer limits. Once the line is integrated at 400 kv, there is no constrained generation requirement for the Cape based on the projected regional demand. The motivation for this requirement is shown in Appendix. Closing Observations The risk associated with the Beta 765/400 kv transformer identified in [13] is expected to be eliminated with the commissioning of the new 765 kv link between Beta and Perseus and the addition of the new 765 kv strengthening into Perseus from the north by December 2012 [6, 7]. This represents a huge improvement to security of supply for the region south from Bloemfontein Arnot Constrained Generation Arnot Power Station has 4 of its units connected to the 400 kv bus and 2 of its units connected to the 275 kv bus at the station. There are 3 x 400/275 kv coupling transformers (1 x 800 MVA and 2 x 400 MVA) at the station.

25 PAGE 25 OF 37 Arnot Power Station is constrained during the loss of the 800MVA 400/275KV coupling transformer. Operations Planning has calculated the minimum number of units required online at Arnot 275kV bus to avoid overloading the remaining 400MVA transformers [15, 16]: The requirement is: Peak: 2 x 275kV units online Off-Peak: 1 x 275kV unit online There are several short term and longer term measures to deload Arnot 275 kv. These include commissioning Duvha-Leseding 400 kv, Maputo 100 and further 100 Agrekko gas-fired generation by September, and Hendrina-Prairie 400 kv in There is also a plan to commission a 400 kv line from Kendal to Gumeni (Prairie B) linked to Marathon by SUPPORTING CLAUSES Scope This document specifies the technical requirements for ancillary services for financial year 2013/14 to 2017/18. The purpose of the document is to make the System Operator s requirements known to ensure a reliable network and provide optimal usage of ancillary services for the next five financial years. It applies to all Eskom line divisions, Transmission, Distribution, Customer Services and Generation. All participants of ancillary services need to meet all aspects of the South African Grid Code relating to these services Abbreviations and Definitions GX: Generation division IPS: Interconnected Power System Peak and Off-peak: Peak periods are considered only during weekdays. There are two peak periods in the daily system load profile, morning peak and evening peak,

26 PAGE 26 OF 37 occuring at different times of the day during winter and summer months. Public holidays are treated the same as weekends with no peak periods. In winter, identified as May to August, the morning peak occurs from 06:00 to 09:00 and the evening peak occurs from 17:00 to 20:00. In summer, covering the remainder of the year outside winter, the morning peak occurs from 09:00 to 12:00 and the evening peak from 18:00 to 21:00. Thus the peak periods occur for six hours of the day every weekday. OP: Operating Procedure OS: Operating Standard SO: System Operator SOG: System Operator Guideline Roles and Responsibilities The personnel from Ancillary Services in the System Operator business area, in consultation with the relevant service providers of Ancillary Services, are responsible for providing the detailed technical requirements. The General Manager, System Operator signs approval of these requirements Monitoring Process The provision of these requirements is monitored regularly via the monthly performance reports.

27 6. APPENDIX A 6.1. CAPE CONSTRAINT Transmission strengthening to the Cape is currently underway as outlined in TDP [5]. Due to the commissioning schedule, the 765 kv transmission strengthening to the Cape is only expected to reach Kappa substation September The North of Hydra Corridor limits the amount of power that can be imported into the Cape and is defined as the sum of power flow on the following lines: North of Hydra corridor = (Perseus Hydra kv) + (Perseus Hydra kv) + (Beta Hydra kv) + (Beta Delphi 400 kv) + (Perseus Hydra 765 kv) + (Perseus Gamma Hydra 765 kv) x x x x x x Figure 7: Representation of North of Hydra Corridor showing Measurement Points 1 1 Source: [11] LJvR/Draft-Comments /Signature /Published

28 PAGE 28 OF 37 The 765 kv strengthening between Zeus, Perseus, Beta, Hydra and Gamma, together with the series compensation of the Alpha-Beta 765 kv lines will increase the healthy transfer capacity by December 2012 to 4360 [7] and 5150 [8] once Kappa is reached, expected by September 2013 [7]. The actual North of Hydra Corridor import depends on the generation and load in the region south of Beta and Perseus. National Control limits South of Hydra Corridor to that amount of power that may be safely transferred on the transmission corridor into the Western Grid [7, 8, 12]: South of Hydra Corridor = (Hydra Kronos 400 kv) + (Hydra Droerivier kv) + (Hydra Droerivier kv) + (Hydra Droerivier kv) + (Gamma-Kappa 765 kv) Figure 8: Graphical representation of Western Grid Corridor showing Measurement Points 2 Hence, the minimum healthy transfer capacity for this corridor until September 2013 is given as 2700 in after which is increases 3390 [7]. To remain within equipment 2 Source: [12] with the user to ensure it is in line with the authorised version on the database.

29 PAGE 29 OF 37 safe thermal limits with the system healthy limit at 2700, the System Operator must ensure that the Western Grid import not exceed 2800 during zero Koeberg unit operation [7]. Once the 765 kv strengthening reaches Kappa susbstation, the healthy transfer increases to 3390, with zero Koeberg unit operation increasing to 3850 [7]. (The zero Koeberg unit operation limit applies when the in-service unit has tripped during a refuelling outage at Koeberg.) Cape Load The Western Grid load in this study is defined as the sum of the load at the main transmission substations (MTS) in the Western Grid plus the exports to Namibia (NamPower and Skorpion). An hourly load forecast for the national demand and Cape load was obtained from the Medium Term and Short Term Load Forecasting Section in the System Operator respectively [10]. The Western Cape and Cape support of the Namibian demand is projected to be marginally down on energy and peak demand over the next two financial year, 2013 and 2014, compared to the report for the previous report issued for 2012 to Both the energy and demand is expected to exceed the previous figures from 2015 onwards. The demand forecast for the system and the region is as shown in Table 6. with the user to ensure it is in line with the authorised version on the database.

30 PAGE 30 OF 37 Table 6: Energy and Peak Demand Forecast Financial Year National Forecast Western Cape and Namibia Forecast Eastern Cape and Karoo Forecast Energy (TWh) Peak () Energy (TWh) Peak () Energy (TWh) Peak () Western Grid Constraint Maintaining continuity of the electrical supply is essential to ensuring acceptable operating risk for nuclear power stations. As required by the operating licence, Koeberg has two independent offsite electrical supplies, the 400 kv transmission grid and an offsite supply direct dedicated line and control system from a gas-fired power station in the Cape Peninsula [12]. According to the Koeberg agreement with the System Operator [9], the transmission system to the Cape needs to be operated to cater for the next single worst contingency. This is the loss of a Koeberg unit when one unit is above 800, and the loss of the Hydra-Kronos 400 kv line when the individual maximum output from operating Koeberg units is below 800. In addition to Koeberg, the capacity available in the Western Cape to supply the load includes generation from Palmiet, Acacia, Ankerlig, Gourikwa, Gas1, and the available transmission capacity. Western Grid Constrained Generation Resources Network constraints may be met using the following local generation resources. with the user to ensure it is in line with the authorised version on the database.

31 PAGE 31 OF 37 I) Koeberg The System Operator prefers units to be online during winter (01 May to 31 August) as the alternative increases the likelihood of using local gas generation. The two refuels (120 and 220) at Koeberg during the review period as per the Rev 63 production plan [8] meet this preference in the 2013/14 financial year. Figure 9: Extract of Koeberg Production Plan (Rev 63) II) Palmiet Constraints The operation of Palmiet is covered by the document Operation of Palmiet Pump Storage Scheme (SOPPC0029). By imposing constraints on the planned outages of Palmiet so that they do not coincide with the refuel outages of Koeberg, the System Operator ensures that maximum capacity is available during the Koeberg refuel outages in case of an unplanned Koeberg outage during this period. with the user to ensure it is in line with the authorised version on the database.

32 PAGE 32 OF 37 III) Western Grid Dispatchable Generation By imposing a minimum requirement on constrained generation, the System Operator ensures sufficient generating capacity during supply shortages and contingencies. The requirement on OCGTs to meet demand in the Western Cape is based on meeting local demand for the following three scenarios: System healthy Unplanned loss of Koeberg during a non-refuel period Unplanned loss of Koeberg during a refuel period The unplanned loss of a Koeberg unit will be defined as a 7 day loss of a Koeberg unit plus 4 days to ramp to full load (264 hours in total) System Healthy The expected OCGTs usage for 2013 during system healthy conditions was determined for the load forecast described in with the user to ensure it is in line with the authorised version on the database.

33 PAGE 33 OF 37 Table 6. Figure 10: Expected 2012 OCGT Usage (Constrained & Unconstrained) Figure 10 shows a monthly OCGT usage difference of 0 GWh for the financial year due to the network and Palmiet capacity constraints. This figure is consistent with that observed in the previous report [14]. The expected OCGTs usage for 2017 during system healthy conditions was determined for the load forecast shown in with the user to ensure it is in line with the authorised version on the database.

34 PAGE 34 OF 37 Table 6. Figure 11 shows a monthly difference of 0 GWh. Figure 11: Expected 2017 OCGT Usage (Constrained & Unconstrained) Loss of a Koeberg unit during a non-refuel period Figure 12 below shows the monthly OCGT usage for 2013 for an unplanned unit trip. The plot shows a slight increase in OCGT usage due to the unplanned unit trip over that observed without this trip in Figure 10. There is no increase in OCGT usage due to the Cape constraint. with the user to ensure it is in line with the authorised version on the database.

35 PAGE 35 OF 37 Figure 12: Expected 2013 OCGT Usage for Unplanned Reactor Trip Loss of a Koeberg unit during a refuel period To increase the need for OCGT constrained generation usage, the outage in 2017 of Koeberg unit 2 starting March 2017 was delayed until 21 July The OCGTs may be expected to run during a Koeberg contingency during a refuel period in the 2017/18 financial year. The analysis is done for the periods of maximum Western Grid energy demand during the delayed refuel period for the financial year. The week commencing Monday, 24 July 2017 was identified as such. An estimate for expected energy needed from the OCGTs was determined from a Plexos simulation catering for an unplanned loss of Koeberg unit 1 for 7 days followed by a 4-day ramp up to full load during the identified period starting at 19:00 on Friday 21 July 2017 and finishing 18:00 on Tuesday 01 August GWh of OCGT energy was found to be needed due to the network constraint. The expected usage of the Cape peaking generation for the contingency is included in Figure 13. Hence, at no OCGT units are required to to meet the energy requirements during such a contingency. with the user to ensure it is in line with the authorised version on the database.

36 PAGE 36 OF 37 Figure 13: Expected 2017 OCGTs Usage for Koeberg Trip during Refuel Period with the user to ensure it is in line with the authorised version on the database.

37 PAGE 37 OF S 1. Integrated Resource Plan for Electricity , Government Gazette, no , 06 May LE Jones, Strategies and Decision Support Systems for Integrating Variable Energy Resources in control Centres for Reliable Grid Operations, post April The South African Grid Code: The System Operator Code, Rev 8.0 July LNF de Villiers, of Medupi initial integration and need for spinning, 14 February Transmission Development Plan , GP Report 11/ A Marais, of Latest Cape Strengthening Execution Projection covering 2013/14 to 2018/19, 25 April E Bezuidenhout, of Expected Commissioning Date for Gamma-Hydra 765kV Line, 22 June M Rampokanyo, of Cape Transfer Limits for 765 kv Strengthening, 25 April JB van Wyk, Koeberg 10 Year Production Plan Rev 63, 01 December L. Nieuwoudt, Provision of Requirements for Secure Off-site Power Supplies as Required by the South African Grid Code: Koeberg Agreement with the System Operator, Document Number R, January J Janse Van Rensburg, of Western Cape Forecast, 27 April MTEP, National IRP 2010 Demand Forecast, 30 April D Matshidza, Eskom Grid Planning, Zeus-Omega 765 kv Integration, May TA Carolin, Managing a network for optimisation and safety, Energize, March Ancillary Services Technical Requirements for , Document Number SOPRP Ancillary Service Technical Requirements for , Document Number, , 09 May C Gertzen, Power Transfer Limits (2010), Document Number SOPRP0234, 12 November M de Haan, Power Transfer Violation Report for June 2011, Document Number SOPRP , 13 June Dumi Mtolo, Instantaneous reserves studies for 2012, Document Number with the user to ensure it is in line with the authorised version on the database.