SYSTEM OPERATOR TRANSMISSION

Transcription

1 SYSTEM OPERATOR TRANSMISSION Ancillary Services Technical Requirements for 2014/ /19. 0 REF. NO.: LJvR/Published

2 PAGE 2 OF 45 TABLE OF CONTENTS 1. INTRODUCTION RESERVES INTRODUCTION INSTANTANEOUS RESERVE Description Methodology Technical Requirements REGULATING RESERVE Description Methodology Technical Requirements TEN MINUTE RESERVE Description Methodology Technical Requirements Calculation of Ten minute reserve for SUPPLEMENTAL RESERVE Description Methodology Technical requirements EMERGENCY RESERVE Description Methodology Technical requirements RESERVE REQUIREMENTS SUMMARY BLACK START AND ISLANDING BLACK START Description Technical Requirements Conclusions... 19

3 PAGE 3 OF UNIT ISLANDING Description Technical Requirements Conclusions REACTIVE POWER AND VOLTAGE CONTROL DESCRIPTION TECHNICAL REQUIREMENTS CONCLUSIONS CONSTRAINED GENERATION INTRODUCTION NATIONAL SYSTEM CONSTRAINTS Cape Constraint SUPPORTING CLAUSES Scope Abbreviations and Definitions Roles and Responsibilities Monitoring Process APPENDIX A SUPPLEMENTAL RESERVE DETERMINATION INTRODUCTION METHODOLOGY FOR DERIVING EXPECTED USAGE OF DMP AND GAS SIMULATION STUDY Economic Level of Supplmental DMP CONCLUSIONS APPENDIX B CONSTRAINED GENERATION CAPE CONSTRAINT S... 45

4 PAGE 4 OF 45 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: cost saving versus DMP capacity 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 2014 OCGT Usage (Constrained & Unconstrained) Figure 11: Expected 2019 OCGT Usage (Constrained & Unconstrained) Figure 12: Expected 2018 OCGT Usage for Unplanned Reactor Trip Figure 13: Expected 2014 OCGTs Usage for Koeberg Trip during Refuel Period Figure 14: Expected 2019 OCGTs Usage for Koeberg Trip during Refuel Period List of tables Table 1: Instantaneous reserve requirements... 7 Table 2: Regulating up and down reserves requirements Table 3: Ten minute reserve requirements Table 4: Supplemental reserve requirements Table 5: Emergency reserve requirements Table 6: Summary of Reserve Requirements Table 7: Energy and Peak Demand Forecast... 37

5 PAGE 5 OF 45 ANCILLARY SERVICES TECHNICAL REQUIREMENTS FOR 2014/ /19 1. INTRODUCTION This document specifies the technical requirements for ancillary services for the period 2014/15 till 2018/19. 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, 2014/15. 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 is 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

6 PAGE 6 OF 45 possible while adhering to Eskom procedure , Control of System Frequency under Normal and Abnormal Conditions 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, by establishing the effect of governing on system frequency [15]. 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

7 PAGE 7 OF 45 needed to replace the equivalent generation capacity. The results are shown in Table 1. Table 1: Instantaneous reserve requirements Period 2014/ / / / /19 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 reserve 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 and SAPP requirement (i.e. keep frequency within dead band for 95% of the time) ii. Cater for a trip of an average unit size on the IPS of stations with capacity >3000

8 PAGE 8 OF 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 and SAPP requirement A control area is required to carry enough regulating reserve 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 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, it checks whether a control area increases generation to restore system frequency. During high frequencies, it checks whether a control area decreases generation to restore system frequency. 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

9 PAGE 9 OF 45 Figure 1 shows that CPS1 exceeds 100% when regulating up and down reserves are each at least 500. 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. AGC performance analysis is considered between 09:00 and 17:00 when system load changes slowly. The system load during hours outside 09:00 and 17:00 changes rapidly, requiring manual intervention from controllers. B) Trip of an average unit size for stations with capacity greater than 3000 The average unit size of the coal fired units for stations with a total capacity of more than 3000 is 600. The higher of the requirements in A) and B) is 600. Therefore 600 regulating up and 600 regulating down capacity is required.

10 PAGE 10 OF 45 Table 2: Regulating up and down reserves requirements Reserve Period 2014/ / / / /19 Regulating Peak up Off Peak Regulating Peak down Off Peak TEN MINUTE RESERVE Description Ten 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 Ten minute reserve is bid in day-ahead into the reserve market. Ten 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 Ten minute market. In addition, if the cost of any potential Ten minute reserve resource is close to or higher than gas turbines, it must be used in the emergency reserve market. Any new Ten 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 Ten 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

11 PAGE 11 OF 45 iii. The total regulating (in one direction) plus Ten minute reserve cater for typical peak within peak load variations The requirement is the greater of the three criteria 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 Ten 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 Ten 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.

12 PAGE 12 OF 45 Figure 3: Peak within Peak Profiles Figure 3 is based on typical weeks for May 2012 to April 2013 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 Ten minute reserve for The Ten minute requirement was evaluated using the following equation: Ten 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

13 PAGE 13 OF 45 The Ten minute reserve requirements are shown in Table 3 below. Table 3: Ten minute reserve requirements Period 2014/ / / / /19 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 2018, 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: Figure 5: Projection of intermittent renewable generation penetration

14 PAGE 14 OF SUPPLEMENTAL RESERVE Description Supplemental reserve is generating or demand side capacity that can respond in 6 hours to restore the other reserves. This reserve must be available for at least 2 hours (See SPC 46-2) Methodology The total requirement is based on carrying sufficient supplemental capacity to avoid running gas turbines Technical requirements It costs money to provide DMP supplemental reserve. Given the current expected amount of various emergency reserves that are (or should be) dispatched before DMP based on cost such as EL1 and Interruptible load, the economic amount of DMP capacity may be calculated. This will depend on the relative energy costs of DMP compared to gas turbines, as well as the capacity charge paid to customers for making their capacity available to be reduced when the need arises. If gas is cheaper than DMP at any time then no DMP should be utilised before using gas turbines (including OCGT). The details of the study are given in Appendix A Supplemental Reserve Determination. The result of the study is that 1100 of supplemental DMP is required. The supplemental reserve requirements are as follows: Table 4: Supplemental reserve requirements Period 2014/ / / / /19 Peak/ Off peak

15 PAGE 15 OF EMERGENCY RESERVE Description Emergency reserve is capacity that is required less often than Ten minute reserve. This includes interruptible loads, generator emergency capacity (EL1), and gas turbine capacity. The call up time depends on the technology but a maximum call up of 10 minutes is preferred. Emergency reserve are 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 (operating plus supplemental plus emergency) reserves capacity equal to largest power station capacity. Therefore emergency reserve = largest power station capacity operating reserve - supplemental reserve Technical requirements The worst contingency catered for in deriving the technical requirements is the loss of the largest power station, which should be replaced by operating, supplemental and emergency reserve capacity. Majuba is the largest power station from 2014/15 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 integrated resource plan The emergency reserve requirements are as follows: Table 5: Emergency reserve requirements Period 2014/ / / / /19 Peak/ Off peak

16 PAGE 16 OF RESERVE REQUIREMENTS SUMMARY Table 6 shows the expected requirements for each reserve category from 2014/15 till 2018/19. Table 6: Summary of Reserve Requirements Reserve Time of Use Period 2014/ / / / /19 Instantaneous Peak Off Peak Regulating Peak Off Peak Ten Minute Peak Off Peak Operating All periods Supplemental All periods Emergency All periods Total All periods 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 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

17 PAGE 17 OF 45 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 technical requirements for Black-start involve those stated in the South African Grid Code (SAGC) and also the minimum System Operator requirements. A) South African Grid Code (SAGC) Requirements 1) The SAGC requires that there be at least two suitable Black-start facilities at different locations in the system. 2) The System Operator shall determine the mimimum requirements for each of the Black-start facility mentioned above before contracting. 3) To prove the capability of the system, the System Operator shall perform partial and full black start tests periodically (every 3 & 6 years) as required by the SAGC. This shall be done in accordance with the latest version of the operating standard EST A partial test done every three years shall involve: Isolation of the unit Starting up of the unit from an independent source and Energising a defined portion of the transmission / distribution system. A full test done every six years shall involve: Isolation of the unit Starting up of the unit from an independent source Energising a defined portion of the transmission / distribution system and The subsequent loading of the unit to prove blackstart capability.

18 PAGE 18 OF 45 4) Due diligence and as part of preparations, planning and studies are done prior to the partial or full Black start facility test. 5) 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. 6) The first unit shall be capable of energising a portion of the power system within four hours of shutdown. B) Technical Requirements For Black Start Facilities 1) 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. 2) Geographical location of a unit capable of black starting has to allow for restoration without technical constraints. 3) The station shall conduct periodic diesel generator compliance monitoring tests as required by the System Operator. These tests include testing the selfstart facility and monitoring fuel and water levels. Periodic self-start tests involve; 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 o The tests are done to heat soak the machines, so reducing the risk of rotor and stator misalignment of the diesel generator. 4) There shall have sufficient water/fuel for three black start attempts on the unit at all times. 5) 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. 6) The unit shall be capable of picking up load blocks of 30 to 50.

19 PAGE 19 OF 45 7) The Black-start facility shall be capable of maintaining the frequency within 49 to 51 Hz during energisation and load pick up. 8) 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. 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 Conclusions The SAGC requires that Eskom shall at least have two Black-start facilities at different locations and furthermore instructs the System Operator to determine the minimum requirements for those facilities before contracting. To improve reliability and speed up the restoration plan during a blackout, the System Operator opted for a third Black-start facility with the first unit, June 2014 set as the commissioning date. The system restoration plan review involving further system studies to determine the impact of a third Black-start facility, identification and testing of synchronising points to support the technical requirements and improve the system reliability 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 auxiliaries to maintain stability of the turbo generator, and to supply its auxiliary load

20 PAGE 20 OF 45 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) South African Grid Code (SAGC) Requirements 1) Units that do not have a black start facility or self start capability shall island when required except if construction occurred before the implementation of the Grid Code and without an HP bypass facility designed for islanding. Thus all the units commissioned after the SAGC should have Islanding capabilities. 2) Return to service units are currently exempted from this requirement as they do not have an HP bypass facility required for islanding. 3) The SAGC specifies that only units rating greater than 200 MVA will be certified. 4) The units are expected to disconnect from the power system at full load and sustain the islanding for two hours. 5) The prototype test is only done on a representative unit for the station with routine testing being required for all remaining units. a) 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. b) 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. 6) The tests shall be carried out in accordance with the latest version of procedure EPC , Certification/ Decertification Procedure for Turbo-

21 PAGE 21 OF 45 Generator Unit Islanding and Standard for Steam Turbine Unit Islanding, Load Rejection and Speed Control Verification (GGS 0500) Conclusions Studies under the restoration plan review will be conducted to determine the optimum placement of islanding including determining exactly how many units are expected to island during a system Blackout. The requirements derived from the study results are expected to speed up the restoration plan and thereby improve system reliability. 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.

22 PAGE 22 OF TECHNICAL REQUIREMENTS The technical requirements for reactive power and voltage control involve requirements from the System Operator, South African Grid Code (SAGC) and Renewables Grid Code.

23 PAGE 23 OF 45 A) System Operator (SO) Requirements 1) SO shall use peaking stations (pump storage and OCGTs) in SCO for voltage control. 2) All installed thermal and peaking stations will be used for voltage control at the discretion of the SO. 3) All generators shall have automatic voltage regulators (AVR)/converters in an automatic voltage control mode. 4) All generators shall inform/update SO of any restriction that might affect the reactive power support. 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. B) SAGC Requirements for Renewables Including IPPs 1) 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. 2) Reactive power output shall be fully variable between these limits under AVR, manual or other controls. 3) SO shall control power station export/import of reactive power through TEMSE or telephone. 4) When a unit is in pumping or generating, reactive power supply is mandatory in full operating range 5) Voltages shall not deviate by more than ±5% from declared voltages under normal operating conditions. 6) Gas Turbines units build after the implementation of a Grid Code shall be capable of operating in SCO.

24 PAGE 24 OF 45 7) Generators shall conduct prototype and routine tests to demonstrate reactive capability. 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. C) SAGC Requirements for Renewables/IPPs 1) During start up / energising, the Renewables/IPPs are only allowed to consume or export reactive power from the transmission system by not more that 5% of rated reactive power. 2) Different power factor gategories are specified as follows; Category 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. 3) The Renewables/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) as well as a voltage control function capable of controlling the voltage at the POC via orders using set points. 4) The Renewables/IPPs shall ensure that they can function/operate under any of the three different modes mentioned below. Furthermore the reactive power

25 PAGE 25 OF 45 and voltage control functions are mutually exclusive, which means that only one of the three functions mentioned below can be activated at a time: a) Q-control b) Power Factor control c) Voltage-control 5) The applied parameter settings for reactive power and voltage control functions shall be determined before commissioning by the NSP in collaboration with the SO CONCLUSIONS The technical requirements for reactive power and voltage control were enhanced to accommodate all the new Suppliers (Renewables/IPPs) connected to the transmission system taking into consideration that the service is mandatory for all the role players. Although Eskom has different generator power factor requirements for conventional plants and Renewables/IPPs it is expected that this will not affect the desired voltage profile during operations as long as all the generators adhere to the System Operator instructions. The reactive power contribution of conventional plants and Renewables/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 Renewables/IPPs further increases complexity and challenges to the existing protection and automation at all voltage levels within the Eskom network system.

26 PAGE 26 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. To support the MYPD, this requires the System Operator to identify national system constraints over a 5 year horizon, 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 with a duration beyond a few hours that have a significant impact and have a high probability. 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. The power corridor down to the Cape represents the only transmission network where there is a risk of running expensive gas generation out of the economic merit order, constituting constrained generation for the system. Only with commissioning of the second unit at Medupi Power Station is the station expected to have to be constrained down under light loading in the region. This will represent uneconomic dispatch of generation for the system and will be counted as part of constrained generation. Once the Operations Planning Department has

27 PAGE 27 OF 45 established how much spinning is needed, the extent of the problem for constrained generation can be established. [4] Cape Constraint The 765 kv strengthening is now expected to be commissioned up to Kappa substation by July 2014, delayed by a further 10 months over that previously assumed [6]. Based on the assumed regional and national demand, generation performance and cost, 14.2 GWh is required from the OCGT for constrained generation to cater for the N-2 refuel contingency at the start of the 2014/15 financial year. 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 that it 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 July 2014, increasing the Western Grid transfer limits. Once the 765 kv Cape transmission strengthening 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 given in Appendix B Constrained Generation SUPPORTING CLAUSES Scope This document specifies the technical requirements for ancillary services for financial years 2014/15 to 2018/19. 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

28 PAGE 28 OF 45 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, 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.

29 PAGE 29 OF Monitoring Process The provision of these requirements is monitored regularly via the monthly performance reports.

30 PAGE 30 OF APPENDIX A SUPPLEMENTAL RESERVE DETERMINATION 6.1. INTRODUCTION The method used for this study is to simulate the hourly commitment and dispatch for calendar year 2014 using the PLEXOS production simulation program. This gives the expected usage of emergency resources and supplemental DMP. The reason the two reserve categories are handled together is because supplemental DMP is part of the emergency resource merit order followed by National Control during plant shortages METHODOLOGY FOR DERIVING EXPECTED USAGE OF DMP AND GAS The method used for this study is to simulate the hourly commitment and dispatch for calendar year 2014 using the PLEXOS production simulation program. This gives the expected usage of emergency resources and supplemental DMP. The reason the two reserve categories are handled together is because supplemental DMP is part of the emergency resource merit order followed by National Control during plant shortages SIMULATION STUDY Economic Level of Supplmental DMP The breakeven level of supplemental DMP capacity was determined by comparing the total cost of each extra of capacity of DMP with the saving due to running one less of gas. The cost drivers for DMP are fixed and variable costs. The fixed cost is incurred over the year and consists of: (i) Administration costs paid to the DMP customer data aggregator. These are assumed to scale linearly with the capacity certified for DMP, as each resource needs metering, monitoring and payment administration. (ii) Capacity payment to the customers. The customers are paid for every hour that they are scheduled by National control. Thus, the payment is proportional to the capacity bid available each day, since currently all the capacity is scheduled by National Control whenever the day-ahead with the user to ensure it is in line with the authorised version on the database.

31 PAGE 31 OF 45 reserve falls below the target limit. Historical data shows that the number of days scheduled are nearly 50% of all days in a year. (iii) The variable payment for usage is the energy price for DMP times the energy reduced. with the user to ensure it is in line with the authorised version on the database.

32 PAGE 32 OF 45 Figure 6: cost saving versus DMP capacity with the user to ensure it is in line with the authorised version on the database.

33 PAGE 33 OF 45 FINAL RUN - 20 STEPS OF 100 UNIT CAPACITY CUM ENERGY CAP GWH HOURS/ YR CUM FIXED COST(Rmil) (DF) CUM DMP ENERGY COST (Rmil) TOTAL DMP COST (Rmil) CUM ENERGY COST SAVING (GC-DE) Rmil NET SAVING (GC-DE-DF) Rmil Figure 6 and the table above shows that the maximum cost saving occurs if 1100 of DMP is dispatched (i.e. made available and used) before we dispatch OCGT at its expected price of 2700 R/h. Note that more DMP capacity may be certified provided that only 1100 is dispatched before OCGT CONCLUSIONS System operator needs at least 1100 of Supplemental DMP in This quantity depends heavily on the price of fuel at the OCGT stations, and may vary with time. A higher DMP capacity than stated above may be procured but only the economic quantity should be contracted each day. The rest could be offered after gas turbines. with the user to ensure it is in line with the authorised version on the database.

34 PAGE 34 OF APPENDIX B CONSTRAINED GENERATION 7.1. CAPE CONSTRAINT Transmission strengthening to the Cape is still in progess 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 by July The North of Hydra Corridor limits the amount of power that can safely 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) Figure 7: Representation of North of Hydra Corridor showing Measurement Points 1 1 Source: [11] with the user to ensure it is in line with the authorised version on the database.

35 PAGE 35 OF 45 The healthy transfer capacity will increase from 4360 to 5150 [7] once the 765 kv transmission strengthening reaches Kappa, expected by July 2014 [6]. 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, 9, 13]: 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 July 2014 is given as 2700 after which it increases to 3390 [7]. To remain within equipment safe thermal 2 Source: [11] with the user to ensure it is in line with the authorised version on the database.

36 PAGE 36 OF 45 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.) Load Forecast An hourly load forecast for the Cape and national demand was obtained from Short Term Load Forecasting in the System Operator and the Medium Term Load Forecasting respectively [10]. The Western Grid demand 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). Compared to the previous report issued for 2013 to 2017, the peak demand for the Western Cape and Cape support of the Namibian demand is projected to be marginally down with energy marginally up. National demand is forecast to be marginally down both on peak demand and energy. The national forecast assumed is consistent with the load forecast assumed by Energy Planning, reduced from the previous forecast until The demand forecast for the system and the region is as shown in Table 7. with the user to ensure it is in line with the authorised version on the database.

37 PAGE 37 OF 45 Table 7: 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 () Generation Performance The targets for generation plant performance was set to the current performance [12]. This is 3% lower than the previous performance targets. Western Grid Constraint Maintaining continuity of the electrical supply is essential for 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 a dedicated direct 132 kv offsite supply and control system from a gas-fired power station in the Cape Peninsula [13]. 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 load includes generation from Palmiet, Acacia, Ankerlig, Gourikwa, Gas1, and the available transmission capacity. with the user to ensure it is in line with the authorised version on the database.

38 PAGE 38 OF 45 Western Grid Constrained Generation Resources Network constraints may be met with support from the following local generation resources. 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 (220 and 121) at Koeberg during the review period as per the Rev 63 production plan [8] meet this preference in the 2014/15 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). with the user to ensure it is in line with the authorised version on the database.

39 PAGE 39 OF 45 By ensuring that planned outages at Palmiet are outside the refuel outage window for Koeberg, the System Operator ensures that maximum capacity is available during the Koeberg refuel outages. This strategy reduces the likelihood of running gas should the inservice unit trip at Koeberg during this time. 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 a Koeberg unit during a non-refuel period Unplanned loss of a Koeberg unit 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 2014 during system healthy conditions was determined for the load forecast described in Table 7. with the user to ensure it is in line with the authorised version on the database.

40 PAGE 40 OF 45 Figure 10: Expected 2014 OCGT Usage (Constrained & Unconstrained) Figure 10 shows that there is no difference in monthly OCGT usage for the Western Grid due to the constraint. This figure is consistent with that observed in the previous report [14]. The expected monthly OCGTs usage for the Western Grid for 2019 during system healthy conditions was determined for the load forecast given in Table 7. Figure 11 shows a monthly difference of 0 GWh. with the user to ensure it is in line with the authorised version on the database.

41 PAGE 41 OF 45 Figure 11: Expected 2019 OCGT Usage (Constrained & Unconstrained) Loss of a Koeberg unit during a non-refuel period Figure 12 below shows the monthly OCGT usage for 2018 for an unplanned unit trip. There is no increase in OCGT usage for the Western Grid due to the Cape constraint. with the user to ensure it is in line with the authorised version on the database.

42 PAGE 42 OF 45 Figure 12: Expected 2018 OCGT Usage for Unplanned Reactor Trip Loss of a Koeberg unit during a refuel period Two refuel outages during which the in-service unit was tripped were considered. The worst Western Gid energy period was again identified to establish the need for constrained generation. During outage RO220, Koeberg unit 1 was tripped on the Friday before the worst energy week GWh of OCGT energy for the Western Grid was found to be needed due to the Cape network constraint. The expected usage of the Cape OCGT generation for the contingency is shown in Figure 13. with the user to ensure it is in line with the authorised version on the database.

43 PAGE 43 OF 45 Figure 13: Expected 2014 OCGTs Usage for Koeberg Trip during Refuel Period To increase the chance of running OCGTs for constrained generation, the outage in 2018 of Koeberg unit 2 starting 28 August 2018 was delayed until 21 June The OCGTs may be expected to run during a Koeberg contingency during this refuel period. The week commencing Monday, 29 June 2019 was identified as the period of interest. An estimate for expected energy needed from the OCGTs was determined from a PLEXOS production simulation assuming the unplanned loss of Koeberg unit 1 starting at 19:00 on Friday 26 July 2019 and finishing 18:00 on Tuesday 06 August GWh of OCGT energy for the Western Grid was found to be needed due to the Cape network constraint. The expected usage of the Cape OCGT generation for the contingency is shown in Figure 14. Hence, 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.

44 PAGE 44 OF 45 Figure 14: Expected 2019 OCGTs Usage for Koeberg Trip during Refuel Period with the user to ensure it is in line with the authorised version on the database.

45 PAGE 45 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 Spinning Specification with Commissioning of 2nd Unit, 27 June Transmission Development Plan , GP Report 11/ B Herbst, of Cape Strengthening Progress Outlook, 22 April M Rampokanyo, of Cape Transfer Limits for 765 kv Strengthening, 30 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 Load Forecast for Cape covering 2014/15 to 2019/20, 30 April Michael Barry, of National Forecasts Forecasts, 27 March 203, 11 April D Matshidza, Eskom Grid Planning, Zeus-Omega 765 kv Integration, May Nomakhosi Sekane, of 2014_REPORT_F2014 Unipede F2014 Apr13_1.1.xlsx, 08 May TA Carolin, Managing a network for optimisation and safety, Energize, March Ancillary Services Technical Requirements for 2013/14-17/18, Document Number 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.