the south african grid code - nersa...the scheduling and dispatch rules rev 7.2- 2016 3 8.2...

The Scheduling and Dispatch Rules

Rev 7.2- 2016

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The South African Grid Code


Rev 7.2- 2016


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Table of Contents

1. GENERAL ................................................................................................................................... 4

1.1 DEFINITIONS ............................................................................................................................... 4 1.2 ACRONYMS AND ABBREVIATIONS .................................................................................................... 8 1.3 INTERPRETATION .......................................................................................................................... 8 1.4 OBJECTIVES ................................................................................................................................. 9 1.5 APPLICATION ............................................................................................................................... 9

2. ROLES AND RESPONSIBILITIES ................................................................................................... 9

2.1 NERSA ...................................................................................................................................... 9 2.2 THE SYSTEM OPERATOR .............................................................................................................. 10 2.3 GENERATORS ............................................................................................................................ 10

3. REGISTRATION OF RESOURCES AND STANDING DATA ............................................................. 10

3.1 SYSTEM OPERATOR REGISTRY ....................................................................................................... 10 3.2 NON-DISPATCHABLE RESOURCES ................................................................................................... 11 3.3 DISPATCHABLE THERMAL GENERATING UNITS ................................................................................. 11 3.4 DISPATCHABLE HYDRO GENERATING UNITS .................................................................................... 13 3.5 DISPATCHABLE PUMPED-STORAGE GENERATING UNITS ..................................................................... 14 3.6 DISPATCHABLE DEMAND-SIDE RESOURCES ...................................................................................... 16 3.7 INTERCONNECTIONS ................................................................................................................... 17

4. DAY-AHEAD SCHEDULING ........................................................................................................ 18

4.1 DEMAND FORECAST AND RESERVE REQUIREMENTS .......................................................................... 18 4.2 NON-DISPATCHABLE SCHEDULES .................................................................................................. 18 4.3 INTERCONNECTION SCHEDULES ..................................................................................................... 18 4.4 DISPATCHABLE THERMAL GENERATOR SUBMISSIONS ........................................................................ 19 4.5 DISPATCHABLE HYDRO GENERATOR SUBMISSIONS............................................................................ 21 4.6 DISPATCHABLE PUMPED-STORAGE GENERATOR SUBMISSIONS ............................................................ 22 4.7 DISPATCHABLE DEMAND-SIDE RESOURCE SUBMISSIONS .................................................................... 23 4.8 DISPATCH ALGORITHM ................................................................................................................ 23 4.9 PUBLISHING SCHEDULE REPORTS ................................................................................................... 24

5. REAL-TIME DISPATCH .............................................................................................................. 25

5.1 INPUTS TO THE REAL-TIME DISPATCH SCHEDULE .............................................................................. 25 5.2 DISPATCH ALGORITHM ................................................................................................................ 25 5.3 SCHEDULE REPORTS.................................................................................................................... 25

6. DISPATCH INSTRUCTIONS ........................................................................................................ 25

6.1 DISPATCH CONDITIONS ............................................................................................................... 26 6.2 DISPATCH INSTRUCTIONS ............................................................................................................. 26

7. BALANCING ............................................................................................................................. 27

7.1 BALANCING STACKS .................................................................................................................... 27 7.2 IMBALANCES ............................................................................................................................. 27 7.3 BALANCING PRICES ..................................................................................................................... 28 7.4 IMBALANCE CHARGES ................................................................................................................. 28

8. GENERATION MAINTENANCE OUTAGE COORDINATION .......................................................... 30

8.1 OBJECTIVES AND PRINCIPLES ........................................................................................................ 30


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8.2 RESPONSIBILITIES ....................................................................................................................... 31 8.3 MAINTENANCE OUTAGE PLANNING PROCESS .................................................................................. 32

9. REPORTING .............................................................................................................................. 35

9.1 SCHEDULE REPORTS.................................................................................................................... 35 9.2 DISPATCH REPORTS .................................................................................................................... 35 9.3 GENERATOR REPORTS TO NERSA ................................................................................................. 35 9.4 SO REPORTS TO NERSA ............................................................................................................. 36


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1. GENERAL

1.1 Definitions

(1) "Act" means the Electricity Regulation Act (Act 4 of 2006), as amended, and the regulations made thereunder;

(2) “Balancing” means ensuring that supply and demand on the NIPS are in balance in real-time;

(3) “Code” means the Distribution Code, the Grid Code or any other Code, published by NERSA, as applicable and as amended from time to time;

(4) "Control Area" means an electrical system with borders defined by points of Interconnection and capable of maintaining continuous balance between the generation under its control, the consumption of electricity within the electrical system and the scheduled interchanges with other Control Areas;

(5) “Controllability” means the direct means to vary or instruct the output of a device either via telephonic instruction or similar means in the case of a local operator controlled device or via a remote link to the device’s output controller.

(6) “Cold start-up”, means restarting of the generator after 36 hours following shutdown.

(7) “Curtailment” means that the amount of Active Power that the generating unit, the power station or the generating facility is permitted to generate is restricted by the SO, NSP or other Network Operator due to network or system constraints;

(8) "Demand-side resource" means an end-use customer that can respond to SO instructions (either in real-time, day-ahead or any other predetermined time as agreed with the SO) for load curtailment;

(9) “Dispatch” means the scheduling, coordination and management of the flow of electricity produced by generation facilities or consumed by the demand-side resource into and out of the national transmission power system, including the start-up and shut-down of those facilities.

(10) "Dispatch instruction" means the SO instruction to a generator or demand-side resource to effect a change in output (for the generator) or consumption (for the demand-side resource) or reserve capacity (for both generators and demand-side resources) either in real-time or in a predetermined time. These instructions may be:

(a) Automatic, in that the SO control system issues the instruction to the generator or demand-side resource without operator intervention; or

(b) Manual, in that the SO issues the instruction either telephonically, via electronic mail or other mechanism requiring operator intervention.


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(11) "Dispatchable" means the SO is authorised to influence the dispatch of the generator or demand-side resource and the generator or demand-side resource is able to respond to automatic or manual SO dispatch instructions.

(12) "Distribution Network" means the network owned and operated by a Distributor;

(13) "Distribution System" means the network infrastructure operating at nominal voltages of 132kV and below;

(14) "Distributor" means a legal entity licensed to construct, operate and maintain a Distribution network;

(15) "Effective available capacity" means the actual available capacity of a generator or demand-side resource at any instant taking into account actual events, in particular outages, constraints or load losses;

(16) "Embedded generator" means a legal entity controlling one or more generating units, connected specifically to the DS;

(17) “Emergency level 1 (EL1) generation” as defined in the RSA Grid Code.

(18) "Emergency operating condition" means a situation where generators, transmission or distribution service providers have an unplanned loss of facilities, or another situation beyond their control, that impairs or jeopardises the integrity of the NIPS and compromises safety of personnel, plant and equipment;

(19) “End-use customer” means users of electricity connected to the DS or the TS.

(20) "Energy" means the electricity produced, flowing or supplied by an electric circuit over a particular time interval, being the integral with respect to time of the instantaneous power, measured in units of watt-hours (Wh) or standard multiples thereof, i.e.:

(a) 1000 Wh = 1 kWh

(b) 1000 kWh = 1 MWh

(c) 1000 MWh = 1 GWh

(d) 1000 GWh = 1 TWh.

(21) "Flexible" means that the generating unit can be scheduled or dispatched in that hour according to the economic merit order determined in the dispatch algorithm;

(22) "Generating unit" means an independently controllable generating set, especially an alternator and all related equipment including the generation transformer that can be connected to the NIPS. In the case of wind generation the generating unit can refer to the generating facility rather than to the individual generating sets;


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(23) “Generating facility” means any apparatus which is licensed to produce electricity, including both synchronous and nonsynchronous apparatus (such as solar plant) in a single physical location.

(24) "Generator" has the same meaning as defined in the Code. For the purpose of these rules, reference to generators shall also include all qualifying generators;

(25) “Hot Start-up” means restarting of the generator within 8 hours after the shutdown.

(26) "Incremental cost of production" means the additional cost of production associated with each additional unit of output;

(27) "Inflexible" means that the generating unit cannot be scheduled or dispatched at any level other than the indicated available capacity for that hour;

(28) “Installed generation capacity” means total net maximum capacity (MW) of all qualifying generators;

(29) “Interconnection / Interconnector” means facilities that connect two adjacent systems or control areas;

(30) "International Trader" means a legal entity licensed to trade electricity across the borders of South Africa (either exports or imports);

(31) "Maximum Continuous Rating (MCR)" means the capacity that a generating unit or generating facility is rated to produce continuously under normal conditions;

(32) “Maximum Continuous Rating (MCR) Sentout” means the capacity that a generating unit or generating facility is rated to sentout continuously under normal conditions;

(33) “Minimum Stable Generation Point (Mingen)” means the minimum generation level of a generating unit or generating facility without experiencing stability problems (such as with the associated boiler);

(34) "National Integrated Power System" (NIPS) means the electrical network comprising components that have a measurable influence on each other as they are operating as one system. This includes:

(a) the TS;

(b) the DS;

(c) assets connected to the TS or DS;

(d) power stations connected to the TS or DS;

(e) international interconnectors;

(f) the control area for which the SO is responsible.


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(35) “NERSA” means the legal entity established in terms of the National Energy

Regulator Act, 2004 (Act 40 of 2004), as amended.

(36) “Normal operating condition” means an operating condition which is not an emergency operating condition.

(37) “Non-dispatchable” means that the generator makes the dispatch decision for the generating unit or facility or demand-side resource under normal operating conditions.

(38) "Power Station” means one or more generating units or generating facilities at the same location.

(39) “Pumped-storage cycle efficiency” means the ratio of the energy extracted from water in generating power to the energy put into the same quantity of water to pump the water back into the top reservoir in a pumped-storage system.

(40) "Qualifying generator" means a generator required to provide the information to the SO as per these rules and the Code. The rules governing when a generator becomes a qualifying generator shall be set by the SO and approved by NERSA from time to time.

Note: By default the following generator categories shall be regarded as qualifying generators:

(a) A generator operating a generating unit or facility connected directly to the TS.

(b) An embedded generator or a co-generator operating a generating unit or facility with an MCR greater than 10 MW.

(c) An embedded generator or a co-generator operating a generating unit or facility with an MCR greater than 1 MW but less than 10MW. These generator categories shall only comply with the requirements of section 8 of these rules.

(41) “Self-Dispatch” refers to an operating regime where a generating unit or facility output is determined by the generator under normal system conditions except where curtailment rules apply.

(42) “Sent-out” means the power or energy actually injected into the IPS by a generating unit or generating facility

(43) "System Operator" means the legal entity licensed to be responsible for short-term reliability of the IPS, which is in charge of controlling and operating the Transmission System and dispatching generation (or balancing the supply and demand) in real time.

(44) "Thermal generating unit" means a generating unit that uses heat (for instance the burning of fossil fuels) to generate electricity (either through steam or internal combustion processes). This shall include coal, concentrated solar power (CSP), nuclear and gas turbine units.


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(45) "Transmission System" means the network infrastructure operating at nominal voltages of above 132kV

(46) “Virtual Power Station (VPS)” means a load that can be dispatched by the SO.

(47) “Warm Start-up” means restarting of the generator between 8 and 36 hours after the shutdown.

1.2 Acronyms and Abbreviations

(1) DS = Distribution System

(2) IPS = Interconnected Power System (as defined in the Code);

(3) MCR = Maximum Continuous Rating;

(4) Mingen = Minimum Stable Generation;

(5) NIPS = National Integrated Power System

(6) SO = System Operator

(7) TS = Transmission System

(8) SCO = Synchronous Condensor Operation

(9) SDR = Scheduling and Dispatch Rules

(10) LFE = Load Forecast Error

(11) TNSP = Transmission Network Service Provider

(12) MCPR = Maximum Continuous Pump Rating

1.3 Interpretation

(1) In the Scheduling and Dispatch Rules (SDR), notwithstanding the definitions set out in the Act and the Code –

(a) a natural person includes a juristic person and vice versa;

(b) a word in the singular includes the plural, and visa versa;

(c) a generator refers to generators connecting to the Transmission System (TS) or the Distribution System (DS) (thus including embedded generators).

(2) unless the context indicates a contrary intention, words and expressions defined in the SDR shall bear the meanings assigned to them throughout the


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SDR and cognate expressions bear corresponding meanings;

(a) reference to "days" shall be construed as calendar days unless qualified by the word "business", in which instance a "business day" will be any day other than a Saturday, Sunday or public holiday as gazetted by the government of the Republic of South Africa from time to time. Any reference to "business hours" shall be construed as being the hours starting at 08h00 and ending at 17h00 on any business day;

(b) unless specifically otherwise provided, any number of days prescribed shall be determined by excluding the first and including the last day, or, where the last day falls on a day that is not a business day, the next succeeding business day; and

(c) the words "include" and "including" mean "include without limitation" and "including without limitation". The use of the words "include" and "including" followed by a specific example or examples shall not be construed as limiting the meaning of the general wording preceding it.

1.4 Objectives

The objectives of the Scheduling and Dispatch Rules (SDR) are:

(a) to set out roles, responsibilities and process for the scheduling and

dispatch of generation and demand-side resources in meeting the electricity demand.

(b) to enable the SO to coordinate maintenance outages as far as possible

in advance to allow the SO to maintain system integrity and reliability.

(c) to ensure fair and equitable treatment of all generator operators connected to the NIPS.

1.5 Application

(1) These SDR apply to all licensed qualifying generators and demand-side resources connected to the NIPS as well as International Traders.

(2) The SDR shall form part of both the South African Grid Code and the South African Distribution Code.

2. ROLES AND RESPONSIBILITIES

2.1 NERSA

NERSA shall be responsible for monitoring and enforcement of: (a) the application of the SDR by the SO; (b) compliance of generators to the SDR (via their licences); and


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(c) Handling of disputes between participants.

2.2 The System Operator

(1) The SO shall –

(a) apply the SDR;

(b) Schedule and Dispatch generation and demand-side resources to least cost whilst maintaining the prescribed system security;

(c) provide regular reports to NERSA prescribed in Section 9 regarding the scheduling and dispatch of the NIPS;

(d) maintain data for the auditing of the dispatch function;

(e) disclose to participants upon request the reasons for dispatch instructions;

(f) monitor and enforce compliance of demand-side resources to the SDR (via their customer agreements).

(2) In the event that generation capacity and demand-side resources are insufficient to meet the demand, the SO may take mitigating actions that may not be in line with the SDR but in accordance with its functions in terms of the System Operation Code. .

(3) Under normal operating conditions any contractual requirements that restrict dispatch instructions from the SO shall apply. Under emergency operating conditions the SO may override these contractual requirements and enforce dispatch instructions on all generators, provided that the generator is able to comply with SO instruction within statutory limits.

2.3 Generators

(1) A Generator shall take into consideration all prevailing constraints, technical

and/or economical, prior to submitting information required under the SDR.

3. REGISTRATION OF RESOURCES AND STANDING DATA

3.1 System Operator Registry

(1) The data required in sections 3.2 to 3.7 below shall be provided by the qualifying generator or demand-side resource at registration. This data shall be maintained by the SO and changed from time to time at the request of the qualifying generator or demand-side resource, and with concurrence of the SO.

(2) The data shall be maintained by the SO in a Registry.

(3) This Registry shall be available for inspection by NERSA.

(4) Each qualifying generator or demand-side resource shall be able to review and


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shall be responsible to update the data held in the Registry relevant to that resource.

(5) A qualifying generator or demand-side resource must submit in writing to the SO modifications to the Registry data by 08h00 on the day preceding the date at which the modification becomes effective, unless mutually agreed between the SO and the qualifying generator or demand-side resource.

3.2 Non-dispatchable resources

(1) A qualifying generator that is non-dispatchable shall be registered with the SO for collecting information regarding maintenance outage scheduling, production planning, day-ahead scheduling and balancing purposes.

(2) Non-dispatchable generators shall be considered as self-dispatchable in terms of their license conditions or power purchase contract and under normal operating condition will have a priority over dispatchable generators to dispatch power over the NIPS

(3) Specific data relevant to a non-dispatchable generating unit or generating facility shall be submitted by the generator and maintained by the SO. This data shall include:

(a) Official power station name;

(b) Official generating unit or facility names;

(c) Location of the power station;

(d) Metering arrangement , including the device identification number and telephone number for remote interrogation;

(e) If embedded within a network other than the TS, the name of the Distributor responsible for the network;

(f) The type of generating unit(s) or generating facility (for example, coal-fired thermal, pumped-storage, hydro, wind, solar PV etc.);

(g) The MCR generated and MCR sent-out of the generator and the expected load factors.

3.3 Dispatchable Thermal Generating Units

(1) At the power station level, the following data shall be submitted by the generator and maintained by the SO:

(a) Official power station name

(b) Number of generating units

(c) Location of the power station



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(e) If embedded within a network other than the TS, the name of the Distributor responsible for the network.

(2) At the generating unit level, the following data shall be submitted by the generator and maintained by the SO:

(a) The official generating unit name;

(b) The unique SO identifier for the generating unit, determined by the SO at registration;

(c) The MCR and corresponding sent-out power of the generating unit;

(d) The minimum stable generating point (“Mingen”) and corresponding sent-out power of the generating unit;

(e) The start-up ramp rates and costs of the generating unit, expressed as:

(i) The time since operation (in hours) until which the generating unit is assumed hot; the associated start-up ramp rate (in MW/hr) from a hot condition; the start-up cost (in R) for starting up from a hot condition; and the associated lead time to synchronisation from a hot condition after an instruction;

(ii) The time since operation (in hours) until which the generating unit is assumed warm (assumed as any period in excess of the hot condition); the associated start-up ramp rate (in MW/hr) from a warm condition; the start-up cost (in R) for starting up from a warm condition; and the associated lead time to synchronisation from a warm condition after an instruction;

(iii) The associated start-up ramp rate (in MW/hr) from a cold condition (assumed as any period in excess of the warm condition); the start-up cost (in R) for starting up from a cold condition; and the associated lead time to synchronisation from a cold condition after an instruction.

(iv) The minimum run time of the generating unit (in hours), being the minimum time that the unit is prepared to generate. A generating unit, if committed by the SO, will be scheduled to generate for a time at least equal to this period under normal circumstances.

(v) The minimum down time of the generating unit (in hours), being the minimum time that the generating unit is prepared to stay off before being synchronised again. A generating unit, if de-committed by the SO, will be scheduled off for a time at least equal to this period under normal circumstances.

(vi) Start-up ramp rate, being the rate (in MW/hr) at which the generating unit may be loaded between synchronisation and Mingen.

(vii) The loading ramp rate, being the rate (in MW/hr) at which the generating unit may be loaded between Mingen and MCR;

(viii) The de-loading ramp rate, being the rate (in MW/hr) at which the


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generating unit may be de-loaded between MCR and Mingen;

(ix) The shut-down ramp rate, being the rate (in MW/hr) at which the generating unit may be de-loaded between Mingen and off load;

(x) The certified capacity for Regulating Reserve (in MW) agreed by the SO;

(xi) The certified capacity for Instantaneous Reserve (in MW) agreed by the SO;

(xii) The certified capacity for 10 Minute Reserve (in MW) agreed by the SO;

(xiii) The certified capacity for Supplemental Reserve (in MW) agreed by the SO;

(xiv) The certified capacity for Emergency Reserve (in MW) agreed by the SO; and

(xv) The commercial operation indicator, being a flag (either Y or N) to indicate whether the generating unit is in commercial operation.

3.4 Dispatchable Hydro Generating Units


(a) Official power station name;

(b) The unique SO identifier for the power station, determined by the SO at registration;

(c) Number of generating units;

(d) Location of the power station;

(e) The water resource supplying the power station and its capacity;

(f) The names and contact details of any authority responsible for management of the water resource

(g) Metering arrangement , including the device identification number and telephone number for remote interrogation;

(h) If embedded within a network other than the TS, the name of the Distributor responsible for the network.



(b) The unique SO identifier for the generating unit, determined by the SO at


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registration;

(c) The MCR and corresponding sent-out power of each generating unit;

(d) Cavitation (hydraulic instability) zones,

(e) The minimum stable generating point (Mingen) and corresponding sent-out power of each generating unit;

(f) The variable Operating and Maintenance Costs of the power station (in R/MWh);

(g) The (energy equivalent) maximum outflow from the water resource per day (in MWh/day);

(h) The (energy equivalent) maximum outflow from the water resource per week (in MWh/week);

(i) The (energy equivalent) minimum outflow from the water resource per day (in MWh/day);

(j) The (energy equivalent) minimum outflow from the water resource per week (in MWh/week);

(k) The certification for Regulating Reserve (in MW) agreed by the SO;

(l) The certification for Instantaneous Reserve (in MW) agreed by the SO;

(m) The certification for 10 Minute Reserve (in MW) agreed by the SO;

(n) The certification for Supplemental Reserve (in MW) agreed by the SO;

(o) The certification for Emergency Reserve (in MW) agreed by the SO;

(p) The certification for Synchronous Condenser Operation (in MVAr) agreed by the SO;

(q) The time taken for mode changes between stand-still, SCO and generating mode in all directions (in minutes);

(r) The commercial operation indicator, being a flag (either Y or N) to indicate whether the power station is in commercial operation.

3.5 Dispatchable Pumped-storage Generating Units


(a) Official power station name

(b) The unique SO identifier for the power station, determined by the SO at registration;


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(c) Number of generating units;

(d) Location of the power station;

(e) The water resources connected to the power station;

(f) The names and contact details of any authority responsible for management of the water resources;

(g) Metering arrangement , including the device identification number and telephone number for remote interrogation;

(h) If embedded within a network other than the TS, the name of the Distributor responsible for the network.



(b) The unique SO identifier for the generating unit, determined by the SO at registration;

(c) The MCR and corresponding sent-out power of each generating unit;

(d) Cavitation (hydraulic instability) zones,

(e) The minimum stable generating point (Mingen) and corresponding sent-out power of each generating unit;

(f) The maximum continuous pump rating (MW) (“MCPR”) of each generating unit;

(g) The minimum stable pumping point (MW) (“minpump”) of each generating unit;

(h) The (generation energy equivalent) maximum level of the upper reservoir (in MWh);

(i) The (generation energy equivalent) minimum level of the upper reservoir (in MWh);

(j) The (generation energy equivalent) maximum level of the lower reservoir (in MWh);

(k) The (generation energy equivalent) minimum level of the lower reservoir (in MWh);

(l) The (generation energy equivalent) expected inflow into the upper reservoir (in MWh/hr);

(m) The (generation energy equivalent) expected inflow into the lower reservoir (in MWh/hr);


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(n) The (generation energy equivalent) allowed outflow from the upper reservoir (in MWh/hr);

(o) The (generation energy equivalent) allowed outflow from the lower reservoir (in MWh/hr);

(p) The (generation energy equivalent) required outflow from the upper reservoir (in MWh/hr);

(q) The (generation energy equivalent) required outflow from the lower reservoir (in MWh/hr);

(r) The pumped- storage cycle efficiency of the power station (in percentage);

(s) The certification for Regulating Reserve (in MW) agreed by the SO;

(t) The certification for Instantaneous Reserve (in MW) agreed by the SO;

(u) The certification for 10 Minute Reserve (in MW) agreed by the SO;

(v) The certification for Supplemental Reserve (in MW) agreed by the SO;

(w) The certification for Emergency Reserve (in MW) agreed by the SO;

(x) The certification for SCO (in Mvar) agreed by the SO;

(y) The time taken for mode changes between stand-still, SCO, pumping and generating in all directions (in minutes);

(z) The commercial operation indicator, being a flag (either Y or N) to indicate whether the power station is in commercial operation.

3.6 Dispatchable Demand-side Resources

(1) The following data shall be submitted by the demand-side resource and maintained by the SO:

(a) Official demand-side resource name;

(b) The unique SO identifier for the demand-side resource, determined by the SO at registration;

(c) Location of the demand-side resource;


(e) If embedded within a network other than the TS, the name of the Distributor responsible for the network.

(f) The maximum dispatch level of the resource (in MW);

(g) The dispatch costs of the resource (in R/MWh);


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(h) The (energy equivalent) maximum utilisation of the resource per day (in MWh/day);

(i) Number of occasions that the demand resource may be utilized in a given period (i.e. day, week or year);

(j) The (energy equivalent) maximum utilisation of the resource per week (in MWh/week);

(k) The certification for Regulating Reserve (in MW) agreed by the SO;

(l) The certification for Instantaneous Reserve (in MW) agreed by the SO;

(m) The certification for 10 Minute Reserve (in MW) agreed by the SO; and

(n) The certification for Supplemental Reserve (in MW) agreed by the SO;

(o) The certification for Emergency Reserve (in MW) agreed by the SO.

3.7 Interconnections

(1) The International Trader(s) shall be responsible for contractual aspects of the trade over the interconnectors to neighbouring countries.

(2) All expected export and import volumes shall be included in the Energy Forecast produced by the SO as per Section 4.1. The International Trader(s) shall be responsible for providing this information to the SO by 09h00 on the day preceding the dispatch day.

(3) The expected import volumes shall be included in the interconnection schedules provided by the International Trader(s) as per Section 4.3.

(4) The following data shall be submitted by the International Trader(s) and maintained by the SO for each interconnection with neighbouring countries:

(a) Official interconnection name;

(b) The unique SO or identifier for the interconnection, determined by the SO at registration;

(c) Location of the interconnection;

(d) The names and contact details of the neighbouring network authority and control area authority;

(e) Metering arrangement , including the device identification number and telephone number for remote interrogation;

(f) If embedded within a network other than the TS, the name of the Distributor responsible for the network.


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4. DAY-AHEAD SCHEDULING

4.1 Demand Forecast and Reserve Requirements

(1) The SO shall produce a forecast of system energy demand for each hour of the dispatch day (as well as indicative forecasts of system energy demand for each hour for the six days following the dispatch day). This demand shall include network technical losses for each hour of the dispatch day (as well as expected exports to, or expected imports from, neighbouring networks), indicating the required total net sent-out from all generators (except non dispatchable they will indicate their estimated output). The demand forecast shall be produced by 10h00 on the day preceding the dispatch day and shall be made available to all participants.

(2) The SO shall determine the required reserves for each hour of the dispatch day (as well as for each hour of the six days following the dispatch day). These requirements shall determine the minimum reserve requirements for each of the following categories:

(a) Regulating Reserve (Up)

(b) Regulating Reserve (Down)

(c) Instantaneous Reserve (Up)

(d) 10 Minute Reserve

(e) Supplemental Reserve

(3) The SO shall establish agreements with generators and demand side for the provision of the required reserves in line with Systems Operations Code.

4.2 Non-Dispatchable Schedules

(1) A non-dispatchable generator shall provide a schedule of the expected sent-out for each hour of the dispatch day (as well as indicative schedules for each hour of the six days following the dispatch day). This schedule shall be provided to the SO by 10h00 on the day preceding the dispatch day. The information provided shall include:

(a) The official power station name (as in the SO Registry);

(b) The hour (00h00 to 23h00 – the hour start time);

(c) The expected sent-out in the hour (in MWh); and

(d) The expected available capacity of the power station in the hour (in MW).

4.3 Interconnection Schedules

(1) The International Trader(s) shall provide a schedule of the expected imports or exports (firm and unfirm) for each hour of the dispatch day (as well as indicative schedules for each hour of the six days following the dispatch day). This


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schedule shall be provided by 10h00 on the day preceding the dispatch day. The information provided shall include:

(a) The official interconnection name (as in the SO Registry);

(b) The hour (0h00 to 23h00 – the hour start time); and

(c) The expected import in the hour (in MWh).

(d) The expected export in the hour (in MWh).

4.4 Dispatchable Thermal Generator Submissions

(1) Dispatchable thermal generators shall provide a daily submission of the expected hourly availability of each generating unit and the incremental cost curve associated with the dispatch of these units. The schedule should include indicative hourly availability for each hour of the six days following the dispatch day. This schedule shall be provided by 10h00 on the day preceding the dispatch day. The information provided shall include: (a) The official generating unit name (as in the SO Registry);

(b) Availability indicators in the form of:

(i) The hour (0h00 to 23h00 – the hour start time);

(ii) The hourly declared available capacity (in MW), being the maximum sent-out to which the generating unit may be scheduled in the hour;

(iii) The flexible indicator (either F or I), indicating whether the generating unit is flexible (or able to be dispatched by the SO) in that hour (F), or inflexible to central dispatch (I);

(iv) The Instantaneous Reserve Availability Indicator (either A or U), indicating whether the generating unit is available to provide Instantaneous Reserve in the hour (A) or not (U);

(v) The Regulating Reserve Availability Indicator (either A or U), indicating whether the generating unit is available to provide Regulating Reserve in the hour (A) or not (U);

(vi) The 10 Minute Reserve Availability Indicator (either A or U), indicating whether the generating unit is available to provide 10 Minute Reserve in the hour (A) or not (U);

(c) The incremental cost of production, in the form of a piecewise-linear cost curve, with parameters set as follows (see also Figure 01 below):

(i) The minimum generation point of the generating unit (MW), which must be the same as the mingen value for the generating unit from the standing data;


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(ii) The first elbow point (MW) which must be greater than or equal to the minimum generation point;

(iii) The second elbow point (MW) which must be greater than or equal to the first elbow point;

(iv) The third elbow point (MW) which (a) must be equal to the MCR for the generating unit from the standing data, and (b) must be greater than or equal to the second elbow point;

(v) The Emergency Level 1 (EL1) point (MW) which must be greater than or equal to the third elbow point;

(vi) The Cost Increment 0, for the block of capacity between 0MW and the minimum generation point. The Cost Increment 0 must be non-negative;

(vii) The Cost Increment 1, for the block of capacity between the minimum generation point and the first elbow point. The Cost Increment 1 must be non-negative;

(viii) The Cost Increment 2, for the block of capacity between the first elbow point and the second elbow point. The Cost Increment 2 must be greater than or equal to the Cost Increment 1;

(ix) The Cost Increment 3, for the block of capacity between the second elbow point and the third elbow point. The Cost Increment 3 must be greater than or equal to the Cost Increment 2;

(x) The EL1 Cost, for the block of capacity between the third elbow point and the EL1 point. The EL1 Cost must be greater than or equal to the Cost Increment 3.

(xi) The determination of incremental cost of production shall be conducted in accordance with the rules and processes approved by NERSA.

(xii) Generators shall reflect internal constraints of generating units to preferably not produce above, or below, certain output levels via adjusted incremental cost submissions, and not via adjusted declared availability or mingen value submissions. Generators shall maintain records in supporting of adjusting the incremental cost of production for a minimum period of five years.


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Figure 01: Typical bid curve (550 MW MCR generator)

4.5 Dispatchable Hydro Generator Submissions

(1) A dispatchable hydro generator shall provide a daily submission of the expected hourly availability of each generating unit. The schedule should include indicative hourly availability for the six days following the dispatch day. This schedule shall be provided by 10h00 on the day preceding the dispatch day. The information provided shall include:

(a) The official generating unit name (as in the SO Registry);



(ii) The hourly declared available capacity (in MW), being the maximum sent-out to which the generating unit may be scheduled in the hour;

(iii) The flexible indicator (either F or I), indicating whether the generating unit is flexible (or able to be dispatched by the SO) in that hour (F), or inflexible to central dispatch (I); and

(iv) The Instantaneous Reserve Availability Indicator (either A or U), indicating whether the generating unit is available to provide Instantaneous Reserve in the hour (A) or not (U);


(vi) The 10 Minute Reserve Availability Indicator (either A or U), indicating whether the generating unit is available to provide 10 Minute Reserve in the hour (A) or not (U);

0

20

40

60

80

100

120

0 100 200 300 400 500 600s

R/ MWh

INC0

INC2

INC3

MW

INC4

MINGEN ELBOW1

ELBOW2

MCR

EL1

INC1


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(vii) The preferred run flag (either Y or N), indicating whether the generator prefers to run this generating unit in that hour (Y), or not (N). This allows the generator to set the preferred regime to meet the water commitments imposed by the water authorities.

(2) A dispatchable hydro generator shall also provide an indication of the energy limit applicable to the dispatch day (in MWh) above which the SO may not schedule additional energy from the power station, as well as the energy limit applicable to each of the six days following the dispatch day. An indication of the total energy limit for the full seven days (in MWh) shall also be provided above which the SO may not schedule additional energy from the power station.

(3) A hydro generator may declare itself to be must-run if river or dam conditions require it or there are contractual issues requiring them to release water downstream. They must fully declare to SO all the issues around such a declaration.

4.6 Dispatchable Pumped-Storage Generator Submissions

(1) A dispatchable pumped-storage generator shall provide a daily submission of the expected hourly availability of each generating unit. The schedule should include indicative hourly availability for the six days following the dispatch day. This schedule shall be provided by 10h00 on the day preceding the dispatch day. The information provided shall include:

(a) The official generating unit name (as in the SO Registry);



(ii) The hourly declared available capacity (in MW), being the maximum sent-out to which the generating unit may be scheduled in the hour.

(iii) The Instantaneous Reserve Availability Indicator (either A or U), indicating whether the generating unit is available to provide Instantaneous Reserve in the hour (A) or not (U);

(iv) The Regulating Reserve Availability Indicator (either A or U), indicating whether the generating unit is available to provide Regulating Reserve in the hour (A) or not (U);

(v) The 10 Minute Reserve Availability Indicator (either A or U), indicating whether the generating unit is available to provide 10 Minute Reserve in the hour (A) or not (U);

(vi) The hourly declared available pumping capacity (in MW), being the maximum capacity to which the generating unit may be scheduled to pump in the hour.


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4.7 Dispatchable Demand-side Resource Submissions

(1) A dispatchable demand-side resource shall provide a daily submission of the expected hourly available capacity of each resource. The schedule should include indicative hourly availability for the six days following the dispatch day. This schedule shall be provided by 10h00 on the day preceding the dispatch day. The information provided shall include:

(a) The official demand-side resource name (as in the SO Registry);



(ii) The hourly declared available capacity (in MW), being the maximum response to which the resource may be scheduled in the hour; and

(iii) the flexible indicator (either F or I), indicating whether the demand-side resource is flexible (or able to be dispatched by the SO) in that hour (F), or inflexible to central dispatch (I).

(iv) The Instantaneous Reserve Availability Indicator (either A or U), indicating whether the demand-side resource is available to provide Instantaneous Reserve in the hour (A) or not (U);


(vi) The 10 Minute Reserve Availability Indicator (either A or U), indicating whether the generating unit is available to provide 10 Minute Reserve in the hour (A) or not (U)

(2) A dispatchable demand-side resource shall also provide an indication of the energy limit applicable to the dispatch day (in MWh or hours) above which the SO may not schedule additional response from the demand-side resource, as well as the energy limit applicable to each hour of the six days following the dispatch day. An indication of the total energy limit for the full seven days (in MWh) shall also be provided if appropriate above which the SO may not schedule additional energy from the demand-side resource.

4.8 Dispatch Algorithm

(1) The SO shall determine an Unconstrained Schedule which will determine the optimal dispatch for all qualifying generators and demand-side resources for each hour of the dispatch day, taking into consideration the hourly expected demand, reserve requirements, non-dispatchable generator schedules and interconnection schedules, and the costs and availabilities of dispatchable generators and demand-side resources, but without consideration of network constraints.

(2) The dispatch algorithm objective shall be to minimise the total cost of generation required to meet the expected demand, constrained by the reserve requirements


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and technical capabilities of dispatchable generators.

(a) The total cost of generation will include the incremental cost of generation for each scheduled generator, the start-up costs for generators synchronised during the period and the costs of dispatching demand-side resources.

(b) Regulating, instantaneous and 10 minute reserve will be co-optimized with the energy dispatch schedule, taking into account the individual reserve requirements. Supplemental reserve will be optimized independently based on availability, certification and supplemental requirements as determined by the SO.

(3) The dispatch algorithm will optimise the pumped-storage cycle to minimise the cost of generation over a week, considering pump storage cycle efficiency and the limits imposed on the reservoir levels (including targets instituted by the SO for reservoir levels at specific times).

(4) Emergency resources, including interruptible load resources and emergency generators such as designated open-cycle gas turbines and the EL1 increments of thermal generators, are not included in the dispatch optimisation unless the SO indicates an emergency operating condition in particular hours, in which case these resources may be included and pre-dispatch reserve restrictions are removed.

(5) Once the Unconstrained Schedule is determined, the SO shall determine a Constrained Schedule which incorporates transmission network constraints.

(6) The Constrained Schedule dispatch algorithm objective shall also be to minimise the total cost of generation within the additional security constraints imposed by the SO to cater for transmission network and other constraints required to meet security of supply objectives.

4.9 Publishing Schedule Reports

(1) The SO shall provide to the generators or demand-side resources daily Unconstrained Schedule and Constrained Schedule reports by 14h00 of the day preceding the dispatch day.

(2) Each generator or demand-side resource shall be informed of the expected sent-out (or response in the case of the demand-side resource) for each hour of the dispatch day as well as capacity allocated to reserves.

(3) The SO shall also provide a daily general adequacy report indicating the expected demand, reserve requirements, the capacity available to meet the demand, capacity allocated to reserves and the total expected sent-out determined by the dispatch algorithm. This report shall be published by 14h00 on the day preceding the dispatch day.

(4) The SO shall maintain a daily report on the constraints experienced in scheduling and the deviation between the Unconstrained Schedule and the Constrained Schedule. This report shall be produced and submitted to NERSA on request.


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5. REAL-TIME DISPATCH

5.1 Inputs to the Real-time Dispatch Schedule

(1) The SO shall have the ability to determine a real-time dispatch schedule. This real time dispatch schedule shall be authorized for use by AGC at the SO’s discretion. In addition, the SO may determine a revised Constrained Schedule for each hour of the dispatch day based on revised input data during the day.

(2) Revisions to the interconnector schedules may be submitted by the International Trader(s) at any time for the remainder of the dispatch day, indicating the revised hourly expected imports or exports.

(3) Revisions to the availability of dispatchable generators or demand-side resources may be made to the SO at any time for the remainder of the dispatch day, indicating the revised hourly availability for the generating units.

(4) When dispatchable generators become aware that there is a constraint limiting their output they must declare that constraint with the reason and the expected time for the constraint to be lifted.

5.2 Dispatch Algorithm

(1) The real-time dispatch algorithm shall adjust the Day-Ahead Constrained Schedule (or a revised Constrained Schedule determined on the day, following the same methodology as the day-ahead schedule) based on the revised input data and the real-time network model.

(2) This dispatch algorithm shall take into account the transmission and distribution network and generator constraints (including ramping and energy constraints).

5.3 Schedule Reports

(1) Each generator or demand-side resource shall be informed of the expected sent-out (or response in the case of the demand-side resource) and capacity allocated to reserves for each hour of the remainder of the dispatch day as determined in the revised Constrained Schedule determined on the day.

(2) The SO shall also provide a revised general adequacy report indicating the expected demand, reserve requirements, the capacity available to meet the demand, capacity allocated to reserves and the total expected sent-out determined by the revised Constrained Schedule.

(3) The SO shall maintain a daily report on the revised Constrained Schedule (where applicable) and the real-time dispatch schedule. This report shall be produced and submitted to NERSA on request.

6. DISPATCH INSTRUCTIONS


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6.1 Dispatch Conditions

(1) The SO shall maintain an electronic log of system conditions at regular intervals of four seconds as well as the hourly integrated system information. This log shall include the conditions relating to frequency, generation, interconnector flows, corridor flows and voltages.

(2) The four-second interval data shall be held by the SO for three years at which time the four-second data may be deleted. The hourly integrated data shall be maintained for five calendar years from the day of dispatch.

(3) The system condition log shall be utilised for audit purposes to support the reasons for dispatch instructions.

6.2 Dispatch Instructions

(1) The SO shall issue dispatch instructions to qualifying generators to indicate the required sent-out or to demand-side resources to indicate the required response.

(2) Non-dispatchable generators may be expected to follow specific dispatch

instructions in the case of an emergency operating condition in the NIPS or the

existence of a need for curtailment. These instructions must be duplicated into

a separate electronic log for commercial reconciliation purposes.

(3) Should curtailment be necessary the SO shall, in issuing such instruction,

consider the total economic cost.

(4) These dispatch instructions shall be logged by the SO, taking the form of:

(a) The official generating unit name or demand-side resource name (as in the SO Registry);

(b) The date and time of the dispatch instruction;

(c) The expected sent-out (in the case of a generator) or response (in the case of a demand-side resource).

(5) An audit mechanism must be maintained to allow for verification of the logged details.

(6) The day-ahead Constrained Schedule (or revised Constrained Schedule determined on the day, where applicable) shall constitute a dispatch instruction unless replaced by a manual or automatic dispatch instruction from the SO.

(7) The real-time dispatch schedule shall constitute a dispatch instruction (replacing the day-ahead instruction) unless itself replaced by a manual or automatic dispatch instruction from the SO.

(8) If the SO has issued a dispatch instruction to a generator or demand-side resource that replaced the day-ahead schedule the SO must continue to issue dispatch instructions before the start of each hour (or 5-minute interval) to indicate the level of sent-out the generator is expected to produce or response


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the demand-side resource is expected to provide.

7. BALANCING

7.1 Balancing Stacks

(1) Within seven days of the end of the dispatch day, all dispatch instructions shall be logged and verified, and all metering data for every generator and demand-side resource shall be collated and verified. On the eighth day following the dispatch day, two balancing stacks shall be determined for each hour of the dispatch day, one for Balancing Energy Sold to the SO and another for Balancing Energy Bought from the SO.

(2) The Balancing Energy Sold stack is derived from the incremental cost curves of generators and the costs of the demand-side resources. Only generators and demand-side resources that are declared available and flexible for the hour are included in the Balancing Energy Sold stack. The capacity available is limited at the minimum point by the sum of the day-ahead scheduled generation or demand-side resource response and the day-ahead scheduled instantaneous reserve, and on the maximum point by the least of the declared availability and the effective available capacity of the generator or demand-side resource. Energy increments meeting these requirements and constraints are stacked in increasing order of energy cost.

(3) The Balancing Energy Bought stack is derived from the incremental cost curves of generators and the costs of the demand-side resources. Only generators and demand-side resources that are declared available and flexible for the hour are included in the Balancing Energy Bought stack. The capacity available is limited at the maximum point by the day-ahead scheduled generation or demand-side resource response, and on the minimum point by the minimum stable generation point (or zero for a demand-side resource). Energy increments meeting these requirements and constraints are stacked in decreasing order of energy cost.

7.2 Imbalances

(1) For each hour of the dispatch day the following shall be determined:

(a) The instructed energy output for each generator or instructed response for each demand-side resource for the hour, based on the dispatch instructions given by the SO (adjusted for ramping constraints);

(b) The actual metered energy output for each generator;

(c) The actual metered response for each demand-side resource, based on the deviation of the actual metered consumption from the baseline consumption, being either of:

(i) the average actual metered consumption of the preceding two hours; or

(ii) the profile determined by the demand-side resource and approved by the SO before the dispatch day.


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(2) The total Imbalance Energy Bought for the hour is determined as the sum of all deviations of the actual metered output or response from the instructed output or response where the instructed exceeds the actual output or response.

(3) The total Imbalance Energy Sold for the hour is determined as the sum of all deviations of the actual metered output or response from the instructed output or response where the actual exceeds the instructed output or response.

(4) The Load Forecast Error (LFE) for the hour shall be determined as the net system demand for the hour (measured as the total metered sent-out by all generators net of pumping energy and actual demand-side responses) less the expected demand for the hour.

(5) The LFE shall be added to the total Imbalance Energy Sold if the LFE is negative (i.e. the expected demand exceeds the net system demand). The LFE shall be added to the total Imbalance Energy Bought if the LFE is positive (i.e. the net system demand exceeds the expected demand).

7.3 Balancing Prices

(1) The SO shall determine the total energy costs incurred in maintaining the NIPS balance in real-time, either through

(a) Utilising generation or demand-side resources where the SO is responsible to compensate these resources for energy provided; or

(b) Utilising own resources and incurring the costs involved.

(2) These actual costs shall be determined separately and summated for costs incurred in meeting Imbalance Energy Bought requirements and those incurred in meeting Imbalance Energy Sold requirements.

(3) The Imbalance Energy Bought Price shall be determined as the minimum of:

(a) The weighted average incremental costs of resources included on the Balancing Energy Sold stack and providing capacity to meet the Imbalance Energy Bought;

(b) The actual costs incurred in meeting Imbalance Energy Bought requirements divided by the total Imbalance Energy Bought.

(4) The Imbalance Energy Sold Price shall be determined as the minimum of:

(i) The weighted average incremental costs of resources included on the Balancing Energy Bought stack and providing capacity to meet the Imbalance Energy Sold;

(ii) The actual costs incurred in meeting Imbalance Energy Sold requirements divided by the total Imbalance Energy Sold.

7.4 Imbalance Charges

(1) For each hour, imbalance charges shall be determined for generators and


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demand-side resources causing imbalances on the system, applying the Imbalance Prices to the actual imbalance calculated.

(2) Once the imbalance calculations are made for the last day of a calendar month the invoices for the imbalance charges for that month shall be submitted to the applicable generators and demand-side resources.


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8. GENERATION MAINTENANCE OUTAGE COORDINATION

8.1 Objectives and Principles

8.1.1 Objectives

(1) The objective of this chapter is to set out the procedure and responsibilities in the generation maintenance outage scheduling process. The rules provided have the objective of providing a common understanding so the process can proceed in an orderly fashion and be transparent, fair and equitable.

8.1.2 Principles

(2) The following principles should apply in the maintenance outage scheduling process.

(a) The short-term system integrity must be safeguarded.

(b) The long-term plant health and hence sustainability of the system must be safeguarded by allowing for adequate maintenance.

(c) Under constrained conditions, priority rules must be applied which take legal, commercial and safety considerations into account.

(d) Load shedding and load curtailment shall only be resorted to when there is insufficient generation capacity to meet demand and maintenance outage requirements.

(e) Generators that own multiple Power Stations are allowed to do fleet optimisation taking into consideration all prevailing constraints, technical and/or economical, prior to submitting information as required.

8.1.3 Summary

(1) In general terms the SO shall be responsible for coordinating the scheduling of maintenance outages of generating facilities connected to the NIPS. This is a logical extension of its responsibility to maintain system integrity and the dynamic supply demand balance requisite to the provision of a secure and consistent supply of quality electrical energy to South Africa.

(2) Generators shall be responsible for all the applicable outage and resource planning for the maintenance outage itself.

(3) The coordination process begins with a three-year load forecast of weekly peak demands. This is compared with the forecast of available installed generation capacity. From the difference between the load forecast and the generation forecast is subtracted an allowance for unplanned events and normal operating reserve. What is left is the excess generation capacity available for planned maintenance outages.

(4) Three maintenance outage schedules will exist; the three-year plan, a rolling 52-


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week plan and a 28-day hourly schedules.

(5) In dealing with the non-dispatchable generators there is still an obligation on their part to notify the SO of their planned and actual unavailability. They can in times of system shortage or for any other reasons (for example, network constraints) be requested to delay or change their maintenance outage or production plans. Such delay or change shall be negotiated in good faith.

8.2 Responsibilities

(1) The SO shall be responsible for coordinating the maintenance outage schedule between generating units and generating facilities (including embedded generators) connected to the NIPS. This shall apply to all licensed generating units as required by the SO.

(2) Generators shall be responsible for all the resource and work planning and execution for the maintenance outage itself.

(3) The SO shall determine the excess capacity available for generation maintenance outages and determine and document a fair and transparent mechanism agreed with generators prior approval to allocate this capacity to generators. This document shall be approved by NERSA.

(4) The SO shall inform potentially affected TNSPs, Distributors and generators of these maintenance outages to allow for alignment of maintenance outages to take place.

(5) TNSPs and Distributors shall inform the SO of any maintenance that may affect the availability of generating units or generating facilities within their networks.

(6) The coordination between SO, Distributors and TNSPs may be done partially through an aggregator or agent appointed by the SO.

(7) The generating unit and generating facility maintenance outage scheduling shall be structured as a three-year (updated annually) maintenance outage schedule, a rolling 52-week maintenance outage plan and a 28-day maintenance outage plan. Maintenance outages that are included in the three-year maintenance outage schedule shall be given priority in the 52-week maintenance outage plan.

(8) Generating units or generating facilities with total licensed capacity smaller than 50 MW do not need to fulfil the requirements for the three-year maintenance outage schedule, but are required to fulfil those of the 52-week maintenance outage plan and 28 day outage plan.

(9) The generators should engage with their NSP prior to submitting the outage request.

(10) Non-dispatchable generators may develop their own maintenance outage schedules and shall inform the SO accordingly. The SO may request them to delay or change their maintenance outage schedule to maintain system integrity. Such delay or change shall be negotiated in good faith.


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8.3 Maintenance Outage Planning Process

(1) The three-year maintenance outage schedule period shall run from 01st April of the following year. This maintenance outage schedule shall be determined as follows:

(a) The SO shall determine a weekly peak demand forecast for the schedule period by 31 August of the year preceding the schedule period. This will be done on an annual basis.

(b) The SO shall determine the operating reserve requirement for the scheduling period by 31 August and indicate what is required from generating facilities.

(c) The SO shall determine the provision of all unplanned or forced outages or restrictions on generating facilities output. This will be done considering the current and historic plant performance and expected future plant performance.

(d) The SO shall determine the excess capacity to be used in the maintenance scheduling process. This shall include generation capacity coming on line in the scheduling period. A portion of emergency generation will be included according to SO discretion and as provided for by NERSA. The allowance for self-dispatching generators will be determined by the SO based on historical experience and performance of such plant. For intermittent generation facilities, the capacity credit of the relevant resource will be included in the installed capacity, and in the maintenance outage request.

(e) Considering the factors listed above, the SO shall determine the excess capacity available for maintenance outages.

(f) All generators shall provide the SO with indicative generation capacity unavailability plans for each generating unit or facility for the scheduling period starting 1st April the following year. This will be provided for the three-year period by 30 September of the year preceding the first year of the schedule. This information shall be submitted in accordance with the SO requirement. For the year ahead, this information will be updated through the 52-week plan.

(2) The above plans shall include the following:

(a) capacity required for maintenance outages (MW),

(b) proposed maintenance outage dates (start and end)

(c) scope of maintenance work to be done

(d) an indication of the category of maintenance in terms the following table:

Table 1. Categorisation of maintenance outage work

Heading Description


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S Statutory Outage required to perform actions that are required by local legislation.

W Warrantee Outage required in terms of honouring the warrantee requirements of capital investment made at the facility.

R Risk Outage required to address significant risk existing at the facility.

M Maintenance Outage required to perform normal maintenance of assets of the facility in order to sustain performance, integrity or assurance.

Q Quantification Outage required to quantify the scope of future outages or to quantify the risk posed by a threat within the facility.

H Safety / Health Outage required to address risk threatening human safety or health.

E Environmental Outage required to address risk to the environment.

(e) Priority of maintenance outages

(f) The SO shall publish the provisional plan and coordinate the work done to optimise the maintenance outages as far as possible within the constraints of, and concessions for, the capacity available for maintenance outages. The maintenance plan will be agreed between the SO and other parties by negotiation. Failing such agreement the dispute resolution process in the Governance Code shall be followed, pending which the SO decision shall prevail.

(g) The SO shall publish the refined three-year maintenance outage schedule by 30 November to be effective from 1st April the following year.

(h) Generators shall notify the SO of any changes to the three-year maintenance outage schedule as soon as they become aware of such changes.

(i) All changes to the three-year maintenance outage schedule will be dealt with in the 52-week planning process unless if it is outside the 52-week plan in which case it will be dealt with during the following three-year maintenance outage scheduling process.

(3) The rolling 52-week maintenance outage plan shall be processed as follows:

(a) Within three weeks of a maintenance outage that is in the three-year maintenance outage schedule coming into the rolling 52-week maintenance outage plan window the generator shall submit in writing confirmation that the maintenance outage will take place and list its requirements, the work to be done and the reasons for doing the work. In addition the generator shall provide the potential impact to the generator of delaying the maintenance outage. As part of the maintenance outage request, generators shall provide the SO with information relating to the requirements for the maintenance outage and the risk of not performing the maintenance outage when requested.

(b) The SO shall publish the weekly peak demand forecast and the existing maintenance outage schedule for the schedule period to all generators by the Tuesday of every week of the schedule. This publication shall also indicate the changes required to the existing maintenance outage schedule.


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(c) The SO shall confirm the operating reserve requirement and indicate what is required from generating facilities.

(d) The SO shall determine the provision of all unplanned or forced outages or restrictions on generating facilities output. This will be done considering the current and historic plant performance, and expected future plant performance.

(e) The SO shall publish the 52-week rolling maintenance outage plan by the Thursday preceding the first week of the plan. The first 28 days of the plan will be shown as a daily plan. The remaining 48 weeks will be weekly plans.

(f) Generators shall notify the SO of any changes to the three-year maintenance outage schedule as soon as they become aware of such changes.

(g) A generator may deviate from the maintenance outage schedule only after receiving the approval of the SO. Such approval may only be given once the SO has undertaken a risk assessment of the impact of the requested deviation. Such a request should be put in at least 28 days prior to the expected maintenance outage date. If the requested deviation cannot be accommodated the generator will have the opportunity to maintain the existing schedule or request an alternative date.

(4) Short-term maintenance outage requests may be made by a generator if additional short-term maintenance is required. These requests should be made 28 days prior to the maintenance outage. The SO will determine if the maintenance outage can be accommodated considering all other requests and system conditions. A priority list will be drawn up and maintained of all maintenance outage requests based on, amongst others, duration since request, duration of maintenance outage, impact of not doing the maintenance outage etc.

(5) If the SO determines that continuing with the maintenance outage will result in serious capacity constraint, all the generators will be informed of that risk so that any generator able to assist by moving a maintenance outage will be able to make that decision.

(6) The SO, if it identifies an opportunity for maintenance, may offer a generator to advance any planned maintenance outage as may be reasonably possible without jeopardising reliability of the NIPS.

(7) The SO may request any generator to reschedule any planned maintenance outage as may be necessary to ensure the adequacy of the generation supply.

(8) The SO may request a generator to change the start date of a maintenance outage within a period of not less than seven days. The same request can be made to generators that are already on maintenance outage that are able to return to service earlier.

(9) The SO, if it identifies any imminent risk to the NIPS, or any part thereof, may instruct a generator at any time to delay or defer any planned maintenance outage as may be reasonably necessary to maintain the reliability of the NIPS and the generator shall comply with any such instruction; provided that the


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generator shall be entitled not to comply with any such instruction if it will cause the generator to be in breach of any statutory and regulatory obligations or lose the benefit of any warranty conditions that have been taken into account in determining its planned maintenance requirements or will reasonably constitute a threat to health, safety or the environment.

(10) Should a condition arise and after an agreement between the relevant parties whereby a generation unit outage is withheld with reference to these rules, the resultant cost (if any) shall form part of the incremental cost of the generating unit until released for the required outage.

(11) If generators are not able to reschedule their maintenance outages on the SO instruction, and as a result there is insufficient generation, the SO shall declare a system constraint and notify all generators of the situation and notify NERSA of the possibility of load-shedding.

(12) Under conditions where there is insufficient capacity to meet demand and no opportunity to delay or defer maintenance outages or alternatively to bring back plant already on maintenance outages, load reduction shall be required.

9. REPORTING

9.1 Schedule Reports

(1) The SO shall provide the day-ahead and revised scheduling reports to generators and demand-side resources as required under Sections 4.9 and 5.3.

(2) These reports shall be kept for a minimum of three full calendar years from the day of operation.

9.2 Dispatch Reports

(1) The SO shall provide a report to NERSA when requested on the dispatch instructions issued to all generators and demand-side resources. This report shall cover the day-ahead and revised schedules along with the real-time dispatch schedule and dispatch instructions for each generator and demand-side resource for each hour at five minute intervals including the AGC settings and the hourly tie-line actuals and contracts.

(2) The actual metered sent-out from each generator and response from a demand-side resource for each hour (or 5 minute interval where metered) shall also be included in the above report.

9.3 Generator Reports to NERSA

(1) Generating facilities shall on a monthly basis provide NERSA with the following generating unit data in a format approved by NERSA:

(a) Auxiliary energy consumed by each generating unit


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9.4 SO Reports to NERSA

(1) The SO shall on a monthly basis provide NERSA with the following system data in a format approved by NERSA:

(a) The hourly sent-out for each generating unit for which the SO has Telemetry. For pumped-storage units, pump energy is to be reported separately

(b) The hourly use (sent-out energy) of emergency generation

(c) The hourly use of Virtual PS and Interruptible customers

(d) The hourly tie-line actual and contracted MW

(e) The hourly system demand

(f) The hourly generation load losses

(g) The hourly load shed

(h) The hourly imports and exports

(2) The SO shall on a monthly basis provide NERSA with a curtailment report detailing the curtailment instructions issued to non dispatchable generation with the reasons and cost.

the south african grid code - nersa...the scheduling and dispatch rules rev 7.2- 2016 3 8.2...

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