Electricity (Transmission) (Grid Code) Regulations, 2026

1. These Regulations may be cited as the Electricity Title (Transmission) (Grid Code) Regulations, 2026.

2. In these Regulations, unless the context otherwise requires — Interpretation “Energy Regulation Board” means the Energy Regulation Board established under the Energy Regulation Act; Cap. 436 “interconnected power system” has the meaning assigned to the words in the Act; “participant” means — (a) (b) (c) (d) (e) (f) (g) (h) a power producer; an end use customer; a distribution network service provider; intermediary power traders; a transmission network service provider; an embedded power producer; the system operator; and a regional operator; and Copies of this Statutory Instrument can be obtained from the Government Printer, P.O. Box 30136, 10101 Lusaka. Price K448.00 each. 86 Statutory Instruments 9th January, 2026 Application Guiding principles “transmission system” has the meaning assigned to the words in the Act.

3. These Regulations apply to participants in the operation of the interconnected power system and use of the transmission system as set out in the Schedule.

4. The following principles shall apply in achieving the purpose of these Regulations: (a) non discrimination; (b) (c) equal treatment; and transparency. Administration

5. These Regulations shall be administered by the Energy Regulation Board.

6. The Electricity (Grid Code) Regulations, 2013, are revoked. Revocation of Statutory Instrument No. 79 of 2013 9th January, 2026 Statutory Instruments 87 SCHEDULE (Regulation 3) THE TRANSMISSION GRID CODE ABBREVIATIONS The following abbreviations stand for the words used in this Code: AC ACE AGC ARC AVR BIL CT DC DEF DNSP DS E/F EHV ERB ERLF ESI F/L FACTS GCR GPS HV HVDC Hz IDMT IEC IPS kVA kVAr kW LV MCB Alternating Current Area Control Error Automatic Generation Control Auto Re-close Automatic Voltage Regulator Basic Insulation Level Current Transformer Direct Current Directional Earth Fault Distribution Network Service Provider Distribution System Earth Fault Extra High Voltage Energy Regulation Board External Reliability Loss Factor Electricity Supply Industry Fault Level Flexible AC Transmission Systems Grid Code Requirement Global Positioning System High Voltage High Voltage Direct Current Hertz Inverse Definite Minimum Time International Electro-Technical Commission InterConnected Power System Kilo-Volt-Ampere Kilo-Volt-Ampere reactive Kilo-Watt Low Voltage Miniature Circuit Breaker 88 Statutory Instruments 9th January, 2026 MCR ms MV MVA MVAr M W NCR NERC NPV O/C OEM OST PPA PSA PV QOS REA RMS RO RTU SAPP SCADA SCS SO SVC TCSC TNSP TX UPC VAr VT ZS Maximum Continous Rating Millisecond Medium Voltage Mega-Volt-Ampere Mega-Volt-Ampere reactive Mega-Watt Non-Compliance Report North American Electricity Reliability Council Net Present Value Over-Current Original Equipment Manufacturer Out-of-Step Tripping Power Purchase Agreement Power Supply Agreement Photovoltaic Quality of Supply Rural Electrification Authority Root Mean Square Regional Operator Remote Terminal Unit Southern African Power Pool Supervisory Control and Data Acquisition Substation Control System System Operator Static Var Compensator Thyristor Controlled Series Capacitor Transmission Network Service Provider Transformer Unified Power flow Controller Voltage Ampere Reactive Voltage Transformer Zambian Standard 9th January, 2026 Statutory Instruments 89 DEFINITIONS In this Code, unless the context otherwise requires — “active power” means the product of voltage and the in-phase component of alternating electric current (normally measured in Kw or MW); “agent” means an undertaking which acts in place of a user for the purpose of scheduling and dispatch; “ancillary services” means services supplied to the transmission system by power producers, DNSPs or end-use customers, which are necessary for the reliable and secure transport of power from power producers to DNSPs and customers, in order to maintain the short-term reliability of the IPS, and includes — (a) (b) (c) (d) (e) response; operating reserves; black start; reactive power supply; and regulation and load following; “apparent power” means the vector sum of active power and reactive power expressed in VA, kVA or MVA; “area control error” means the mismatch between the instantaneous demand and supply of a control area, which combines the frequency error and the tie line schedule error; “asynchronous” means a generating unit or electric drive that is not linked to the system frequency by a synchronising torque, and there is no natural contribution to the inertia of the IPS, although control mechanisms may be employed to synthesise a contribution which assists in stabilising the IPS after a disturbance, and “asynchronously” shall be construed accordingly; “automatic generation control” means the regulation of the power output of electric generators within a specified area in response to change in system frequency, tie-line loading, or the relation of these to each other, so as to maintain the scheduled system frequency or the established interchange with other areas within predetermined limits or both; “availability” means — (a) (b) (c) (d) for any period, the capability expressed in MW at the point of connection in respect of any centrally dispatched generating unit, or such embedded generating units (including energy storage devices) e” 2MW as the SO so notifies and any controllable demand e” 1MW; in respect of a generating unit, the maximum output which the generating unit can achieve sustainably during that period of which the value may be the physical limit due to the plant’s design or operational condition or it may be a limit set by a contractual agreement; in relation to an energy storage facility, the state of charge of the energy storage which shall be expressed as positive or negative MW; and in relation to controllable demands or other demand side facilities or aggregated response units, the change in output which may be achieved during the period and can be sustained for the period; “availability declaration” means a declaration of availability provided for under this Code; 90 Statutory Instruments 9th January, 2026 “battery storage” means a battery and its inverter or converter that are controlled together to modulate the flow of active power and reactive power at the point of connection both when importing energy into the battery and in the discharge of that energy; “black start” means the provision of generating equipment that following an IPS collapse is able to — (a) start without an outside electrical supply; and (b) energise a defined portion of the transmission system so that it can act as a start- up supply for other capacity to be synchronised as part of a process of re- energising the transmission system; “busbar” means an electrical conductor at a substation where lines, transformers and other equipment are connected; “central dispatch” means the regular dispatch of generating units by the SO, and “centrally dispatchable” shall be construed accordingly; “climate adaptation” means measures taken to adjust a transmission system to minimise the impact of climate change; “climate resilience” means the capacity of the electricity grid to anticipate, adapt, and recover from climate related disturbances, including extreme weather events and climate change; “Code” means the Electricity (Transmission) (Grid Code) Regulations, 2025; “commissioning” means the process of proving that a plant performs to specification; “committed project planning data” means data relating to a prospective user as explained in the Transmission System Chapter; “compressed air storage” means the use of electricity to compress the air, and the equipment driven by the compressed air to generate electricity; “connection to the transmission system” means the physical connection of customer equipment to the transmission system either directly or through a dedicated transformer provided by a TNSP; “connection agreement” means an agreement between a TNSP and a customer which sets out the terms relating to a connection to the transmission system, and where the customer is a power producer, it defines the registered capacity; “connection charge” means a charge recouped from a user for the cost of providing new or additional capacity; “connection information guide” means a document developed by a TNSP in accordance with this Code, which details the connection process which a user shall follow in order to be connected to the transmission system; “constrained generation” means the difference between the energy scheduled under normal operating conditions and the energy scheduled under constrained conditions at a point of connection; “control area” means an electrical system with borders defined by points of interconnection and capable of maintaining continuous balance within agreed frequency limits between the generation under its control, the consumption of electricity in the area and the scheduled interchanges with other control areas; “control centre” means an entity responsible for the operational control of the entire or specified electricity network assets; 9th January, 2026 Statutory Instruments 91 “controllable demand” means demand which can be modulated either automatically in response to non-emergency conditions on parts of the IPS or in response to signals from the SO or other licensed organisation to manage the electricity demand or flows; “customer” means an entity that contracts directly with a service provider for the provision of transmission services and these entities include a power producer, DNSP, end-use customers and an intermediary which receive dispatch instructions; “daily schedule” means a notice which contains information about the quantities of active power and reserve or other ancillary services, which is published daily by the SO to indicate the intention of the SO to dispatch certain generating units on the following day; “daily status form” means a form which shall be developed by the SO and used by a power producer to submit data to the SO; “demand” means the amount of electrical power consumed, comprising active power and reactive power; “demarcation point” means the point at which there is a change in asset ownership from a service provider to a user, and unless otherwise agreed on by a service provider and user, shall be- (a) in the case of a TNSP and power production facility, the bus bar connecting the two system (the protection circuits of the generating unit and step-up transformers shall belong to the power producer while all other protection circuits and equipment in the HV yard shall belong to the TNSP); (b) in the case of a TNSP and DNSP, international tie lines and end-use customers, at the point where ownership changes hands; and (c) in the case of two TNSPs, at the point where ownership changes hands; “dependability” means the probability of not failing to operate under given conditions for a given time interval as provided under IEC 50 - 448; “detailed data” means data additional to standard data which is needed to allow for detailed stability studies to be carried out; “direct agent” means an undertaking which has specific responsibilities devolved from the SO and therefore performs defined duties for the SO and is responsible to the SO under rules set by the SO; “directly connected” means a power producer and end-use customer whose equipment is connected to the transmission system rather than the distribution system; “dispatch” means the issue of instructions for generating units or controllable demand to carry out operational actions to achieve specific active power and reactive power outputs within registered data parameters or declared availability and by stated times; “dispatch instruction” means instructions issued by the SO to a user to — (a) (b) (c) alter the operational state or mode of operation of a plant; synchronise or de-synchronise a synchronous generating unit; connect or disconnect an asynchronous generating unit; (d) modify the amount of active power (MW) or reactive power (MVAr) generated or consumed at the user’s facility; or (e) provide or change any other contracted system service; 92 Statutory Instruments 9th January, 2026 “distribution network service provider” has the meaning assigned to the words in the Act; “distribution system” has the meaning assigned to the words in the Act; “earthing” means connection either temporarily or permanently to the general mass of earth in a manner that ensures at all times, an immediate discharge of electrical energy without danger, and “earth” shall be construed accordingly; “Electricity” has the meaning assigned to the word in the Act; “electricity supply industry” means the industry involved in generation, transmission, distribution and supply of electrical energy in the Republic; “embedded” means, in relation to a — (a) (b) (c) generating unit, connection to and operating in parallel with a distribution system; controllable load, connection to a distribution system; power producer, a power producer with embedded generating units; “emergency” has the meaning assigned to the word in the Act; “emergency level generation” means extra capacity, achieved without significant additional cost, from generating units over and above their MCRs that can be supplied up to one hour without risk of damage to the plant; “emergency outage” means an outage which occurs when a plant has to be taken out of service immediately so that repairs can immediately be effected to prevent further damage or loss; “end-use customer” means a load user whose equipment is connected to the transmission system; “energy storage” means the conversion of electrical energy into a form of energy which can be stored, the storing of that energy, and the subsequent reconversion of that energy back into electrical energy, but does not include – (a) storage of energy from regenerative braking, flywheel storage systems or any storage source where the delivery of active power is fundamentally not controllable or is short lived; or (b) synchronous compensation equipment; “event” means an unscheduled or unplanned occurrence on or relating to the transmission system including, faults, incidents and breakdowns; “extra high voltage” means a normal operating voltage falling within band 5 of IEC 60038 (.245kV); “final compliance certificate” means a document issued by the SO to a user indicating that the user’s installation is compliant with this Code; “firm quote” means a form of contract negotiated and signed between a TSNP and a customer stating the final connection conditions, which include financial terms; “flicker” means periodic fluctuations in voltage at frequencies below the fundamental frequency, which are generally expressed as percentage variations relative to the fundamental voltage, and the limits of disturbance likely to cause flicker are set out in ZS 387; “forced outage” means an outage that is not a planned outage; “frequency” means the number of oscillations per second on the AC waveform; 9th January, 2026 Statutory Instruments 93 “frequency sensitive mode” means the operation of a generating unit where the generation level is varied automatically to compensate for variations in the frequency of the IPS; “generating unit” means one or more devices converting one form of energy into electrical energy, including any rotating generation equipment, power electronic converters, prime movers and other sources of energy, together with all associated apparatus and any generator transformer which relate exclusively to the operation of that generator, and in the case of — (a) (b) (c) (d) a hydro-generator, includes the turbine, penstock and filter where related solely to that generator, water control valves, the electrical generator and all control equipment, including in the case of variable speed generators any convertors exclusive to that generator; a steam turbine, includes the boiler and heat exchanger and in the case of a solar concentrator the solar collectors; a gas turbine, includes the combustion turbine and ancillary equipment; a fuel engine, includes the engine and any gearbox; (e) wind generation, one or more wind turbine generators that are controlled together, including all apparatus and any step-up transformer and any reactive equipment which relates exclusively to the operation of those wind turbine generators; (f) solar generation, a group of devices which are controlled together to collect or concentrate the sun’s rays within a solar power production facility, together with all plant and apparatus and any step-up transformer which relates exclusively to the operation of that part of the solar power production facility; and (g) electricity storage, includes battery storage and compressed air storage; “governing” means a mode of operation where any change in system frequency beyond the allowable frequency dead band will have an immediate effect on the generating unit output according to the governor droop characteristic; “harmonics” means sinusoidal currents with a frequency equal to an integer multiple of the fundamental frequency; “high voltage (HV)” means nominal voltage levels greater than 33 kV up to and including 220kV; “incident report” means a formal communication of an occurrence of an incident between participants as provided under this Code; “information” means a type of knowledge represented by some data, which can be exchanged, stored or processed electronically or otherwise; “information owner” means a participant to whose system or installation the information pertains; “interruptible load” means a consumer’s load or a combination of consumer loads that can be contractually interrupted or reduced, without notice, on instruction by the SO; “islanding” means the separation of a part of the previously interconnected system from the IPS in a manner whereby the separated part is controlled within acceptable limits, and “island” and “islanded” shall be construed accordingly; “unit islanding” means the capability of generating units to settle down at nominal speed, supplying own auxiliary load after separation from the grid, at up to full load pre-trip conditions; 94 Statutory Instruments 9th January, 2026 “licence” has the meaning assigned to the word in the Act; “licensee” has the meaning assigned to the word in the Act; “limited performance certificate” means a document issued by the the SO to a user which indicats that the user’s installation is compliant with this Code; “load curtailment” means load reduction by a customer who is willing and able to reduce the customer’s use of power within one hour on instructions from the SO; “load following” means the provision of generation and load response capability, including capacity, energy, and maneuverability, that is dispatched by the SO to match power generation and load demand within a scheduling period; “load reduction” means the ability to reduce customer demand by load curtailment and load shedding; “losses” means the technical or resistive energy losses incurred on the transmission system; “metering” means equipment used in measuring supply parameters installed at supply points; “metering installation” means an installation that comprises an energy meter that is interrogated and has a communication link; “notice” means a complaint or request for further information, served on a user, or on a TNSP or the SO by a user in accordance with this Code; “operating parameters” means the technical capabilities, flexibilities and limitations of a generating unit, taking into account changes due to site rating as provided for under this Code; “operational effect” means the effect of any operation which causes the transmission system or the system of other users to operate differently from the way in which it would or may have operated in the absence of such operation; “outage” means an interruption of the flow of power to or from a point of supply; “outage request” means a written notice from a DNSP, power producer, end-use customer or TNSP for a plant to be taken out of service for planned maintenance, repairs, auditing, emergency repairs, construction, refurbishment, inspection, testing or to provide safety clearance for other activities such as servitude clearance, line crossings and underpasses; “output” means the active power delivered in MW, the reactive power delivered or absorbed in MVAr or the apparent power in MVA of a generating unit, measured by certified metering at the connection point or measured at some other point and adjusted by adjustment factors; “ownership boundary” means a boundary established between a TNSP and user and which is referenced in a connection agreement to determine the division of responsibility for assets and for their operation. “planned outage” means an outage as agreed on in the most recent version of the annual maintenance schedule; “plant” means any generation generating unit, switching or transformation equipment, or other HV or EHV equipment other than lines or cables connected to the transmission system; “point of connection” means the electrical node in a transmission substation where a customer’s assets are physically connected to the assets of a TNSP; 9th January, 2026 Statutory Instruments 95 “point of supply” means a transmission substation where energy can be supplied to a DNSP or end-use customer; “power” means the rate of generating, transferring or using energy; “power factor” means the ratio of active power to apparent power; “power producer” means a legal entity which generates electricity and whose generating plant is operated in parallel with the IPS, and includes any entity who owns or operates any llectricity storage device; “power production facility” means an installation comprising one or more generating units (even where sited separately) owned and controlled by the same power producer, which may reasonably be considered as being managed as one facility, and a power production facility may contain both synchronous and asynchronous generating units; “preliminary planning data” means the data relating to the proposed user development at the time when a user applies for a connection but before an offer is made by a TNSP and accepted by the applicant user; “primary substation equipment” means high voltage or EHV equipment installed at a substation; “proposal” is an offer of terms made by a TNSP to a user for connection to the transmission system; “protection” means the provisions for detecting abnormal conditions in a system and initiating fault clearance or actuating signals or indications; “prudent utility practice” means the standards, practices, methods and procedures that conform to safety and legal requirements which are attained by exercising a degree of skill, diligence and foresight which would reasonably and ordinarily be expected from skilled and experienced operatives engaged in the same type of undertaking under the same or similar circumstances; “quote” means an invoice stating connection conditions which includes financial terms; “reactive power” means the product of voltage and current and the sine of the phase angle between them, which is normally measured in kilovar (kVAr) or megavar (MVAr); “regional operator” means an entity, being a direct agent, subordinate to the SO and responsible to the SO for short-term reliability of part of the transmission system, by being in charge of controlling and operating that part of the transmission system in real time for the SO; “registered capacity” means the amount in MW, recorded in a connection agreement, which can be up to the maximum sustainable output of the generating unit measured at the point of connection when either delivering or absorbing the reactive power requirements under this Code; “regulating reserve” means generation capacity or controllable load available to respond within 10 minutes so as reserve category reserves capacity as part of the regulation ancillary service to allow for enough capacity to control frequency and control area tie- lines power within acceptable limits in real time; “regulation” means the provision of generation and load response capability, including capacity, energy and maneuverability, that responds to automatic control signals issued by the SO; “renewable resource” means energy sources deemed to cause no or low carbon emissions and includes solar, wind, hydro, geothermal and energy from waste, and hybrid technologies are assessed as renewable when operating solely on renewable resources; 96 Statutory Instruments 9th January, 2026 “safety coordinator” means a person nominated by a participant to be responsible for the coordination of safety precautions at a point of connection when work or testing is carried out on a system which necessitates the provision of safety precautions on MV, HV or EHV plant. “safety rules” means a document developmed by a TNSP mandating the basic procedures for work or testing on the transmission system by the staff of the TNSP when working on a user’s systems; “schedule day” means the period from 00:00 hours until 24:00 hours on the same day; “scheduling” means a process to determine which generating unit or equipment shall be in operation and at what loading; “security” means the probability of not having an unwanted operation; “service provider” means a TNSP or the SO; “site common drawings” means drawings that incorporate connection site layout drawings, electrical layout drawings, common protection or control drawings and common services drawings prepared for each connection site; “site responsibility schedule” means a schedule forming part of the connection agreement containing the information and prepared in accordance with this Code; “Standards” means the standards developed by the Zambia Bureau of Standards in accordance with the Standards Act; “stakeholder” means an entity that has an interest in the ESI; “standard data” means the general data required by a TNSP for planning a connection or the transmission system; “substation” means a site at which switching and or transformation equipment is installed; “supplier” has the meaning assigned to the word in the Act; “synchronise” means the condition where a generating unit or a transmission system is connected to the bus bars of another transmission system or the IPS, so that the voltages, frequencies and phase relationships of that generating unit or transmission system are within operational tolerances to those of the other transmission system or the IPS, and “desynchrononise”, “synchronisation”, “synchronising” or “synchronised” shall be construed accordingly; “synchronous” means a generating unit or drive that is linked to the system frequency by a synchronising torque in general, this means that there is a natural contribution to the inertia of the IPS, which assists in stabilising the IPS after a disturbance; “System” means the transmission system; “system Frequency” means the frequency of the fundamental AC voltage as measured at selected points by the SO; 9th January, 2026 Statutory Instruments 97 “system minutes” means a performance indicator for interruptions— (a) defined in the following equation: St = EIt * 60 PDt (b) where — (i) S = system minutes interrupted (ii) El = energy interrupted (MWh) (iii) PD = peak demand; and (iv) t = period under review; and “system operator” has the meaning assigned to the words in the Act; “system tests” means tests which involve simulating conditions or the controlled application of irregular, unusual or extreme conditions on the IPS or any part of the IPS, but does not include routine testing, commissioning tests or re-commissioning tests; “temporary compliance certificate” means a document issued by the SO to a user which indicates that the user’s installation is compliant with this Code; “testing and compliance manual” means a document developed by a TNSP, which defines the tests to be carried out to demonstrate compliance with this Code; “transmission equipment” means a cable, overhead line, transformer, switchgear and equipment for ancillary services used for transmission purposes; “transmission network service provider” has the meaning assigned to the words in the Act; “transmission” has the meaning assigned to the word in the Act; “undertaking” means an undertaking for the generation, transmission, distribution, aggregation or wholesale or retail supply of electricity, and includes such undertaking that generates, transmits, distributes or supplies electricity solely or mainly in the interest of a group of associated companies for the purpose of the business of those companies, whether or not any excess electricity is supplied to any other consumer who is not part of the group; “unplanned outage” means an outage that is not a planned outage; “user” means an end-use customer, a DNSP, power producer or other interconnected participant; “voltage control mode” means a mode of operation of a generating unit or reactive power control device whereby the reactive power generated or absorbed by the generating unit or other device is controlled so that the generating unit or other device attempts to maintain the voltage at a defined point to a set value; and “Zambia Bureau of Standards” has the meaning assigned to the words in the Standards Act. 98 Statutory Instruments 9th January, 2026 CHAPTER 1 TRANSMISSION SYSTEM

1.1 DEFINITIONS In this Chapter, unless the context otherwise requires — “user” means a DNSP, directly connected demand customer or directly connected power producer; and “power producer” means a user with synchronous or asynchronous generating units and energy storage facilities which can be operated in export or import mode.

1.2.1 Transmission System Connection Process and Procedure A.1 Pre-Connection Process (a) (b) (c) (d) (e) a TNSP is required by its licence to provide an annual statement for its transmission system indicating the present and future network topography, the projected load flows for the next 5 years, having regard to the range of expected or contracted flows across international interconnectors, and showing the fault levels at nodes on its transmission system. a TNSP shall provide, on request from a user, a statement of present and future circuit capacities, forecast power flows and loadings on the transmission system and shall include more details on fault levels at each node of interest to the user. a person seeking information may in addition make a request for a determination of what limits the capacity for import or export at a node and the difficulty and significance of removing that constraint. a TNSP shall be entitled to levy a charge for the work and statement reflecting the reasonable cost incurred by the TNSP or SO of producing the statement, according to a scale agreed with Energy Regulation Board. the statement shall be prepared within 60 days after the date of receipt of the information or the agreement of the person making the request to pay the cost of the statement, whichever is the later. In the case of power producers and end-use customers seeking connection, this period may be extended to 100 days depending on the nature and complexity of the request. (f) users seeking connection may request provisional quote information from A TNSP that shall be provided without commitment and without detailed studies. A.2 Connections Process (a) A TNSP shall develop a transmission connection information guide which shall be issued to a person who seeks connection to the transmission system. The transmission connection information guide shall be approved by Energy Regulation Board and shall be reviewed and re-approved at regular intervals not exceeding 5 years. (b) Transmission connection information guide shall include the following: (i) the obligation to offer a connection; (ii) state why a connection cannot be offered; (iii) the obligation and process for sharing information with, and obtaining feedback from, the SO; 9th January, 2026 Statutory Instruments 99 (iv) (v) the connection process to be followed including an application for connection and related timeframes governing the process and the exchange of information; that where a generation licence or exemption is required, evidence of either shall be provided to a TNSP prior to connection to the network; (vi) compliance with ZS 387; (vii) the obligation on the applicant to provide data to a TNSP or in the case of embedded generation to a DNSP and the method of provision of the data; (viii) the obligation to meet any approved charges; (ix) the obligation on a TNSP or the SO to assess system effects by conducting grid impact studies; (x) the time to respond to an applicant presenting a simple connection, or a complex connection; (xi) the information which an applicant must receive in the proposal; (xii) the time to accept a proposal and whether this can be varied by a TNSP; (xiii) the conditions when a proposal is considered accepted; (xiv) the process to be followed for staged development of Participant projects; (xv) the process to be to be followed for managing interactive proposals; (xvi) an annually reviewed charging statement including a process to be in place for managing stage payments; (xvii) the obligation for and minimum content of a connection agreement or use of system agreement prior to connection including the physical arrangements; (xviii) the obligation to pay for the initial and on-going costs of a connection prior to being connected or meet such arrangements as may otherwise be agreed; (xix) (xx) (xxi) the obligation to inform and seek approval or amendment for significant change to plant or the control of generating equipment; the condition under which a connection agreement may be amended or renewed including not allowing a user to unreasonably retain unused capacity; the technical conditions under which a connection agreement may be terminated or a connection suspended and when supply may be re-instated; (c) a user shall in the first instance approach a DNSP whose licensed area includes the location of the user’s facility. The DNSP will discuss arrangements with a TNSP in relevant cases and advise the user. (d) a TNSP shall develop and publish its own application form which shall be part of its approved connection information guide. A.3 Application for connection or modification of an existing Transmision System — connection to the (a) a user who intends to connect or modify an existing connection to the transmission system shall apply to a TNSP in accordance with the Act to connect or modify an existing connection to the transmission system; (b) an application referred to under paragraph (a) shall include the following information: (i) a description of the proposed connection or proposed modification to an existing connection, which shall comprise the user development of the user’s facility or point of connection; 100 Statutory Instruments 9th January, 2026 (ii) in case of a power producer, a copy of the generation licence or licence exemption; (iii) the relevant standard data and any further data requested by the TNSP; and (iv) the completion date of the proposed user development. (c) Despite paragraph (b), a power producer shall submit a proposal notice to the SO, where the proposed mofification of an existing connection proposes — (i) a replacement of, or a major modification to, an existing generating unit or the protection, voltage or frequency control arrangements of the generating unit; (ii) to change any of the generating units of the power producer in a manner that could reasonably be expected to either adversely affect the ability of that generating unit to comply with this Code or changes the performance or settings of the generating unit; (d) The proposal notice referred to under paragraph (c)shall — (i) contain detailed plans of the proposed change or modification; (ii) (iii) state when the power producer intends to make the proposed change or modification; and set out the proposed tests to confirm that the relevant generating unit as changed or modified operates in the manner contemplated in the proposal and in compliance wirh this Code. (e) The SO and a power producer shall where a disagreement arises on the proposal notice submitted in accordance with paragraph (c), refer the matter to the Energy Regulation Board for resolution. A.4 Processing of Application (a) (b) (c) a TNSP shall on receipt of the application refered to under paragraph A.3, evaluate the impact of the proposed development by a user on the transmission system. the TNSP shall inform the applicant whether the proposed development is acceptable or not. the TNSP shall, where the TNSP rejects the application, notify the applicant and state the reason for the rejection and in general terms, state what would make the application acceptable. (d) pargraph (c) shall not oblige the TNSP to enter into detailed design of the user’s installation. (e) he TNSP shall, where the TNSP accepts the application referred to under paragraph A.3 — (i) make a proposal to the applicant offering to connect the applicant or modity the applicant’s estisting connection to the transmission system; and (ii) subsequent to the signing of the relevant agreements, make available a point of connection to any requesting user. (f) The proposal referred to under paragraph (e) (i) shall state — (i) the technical details of the connection arrangements; (ii) the capacity offered, or in the case of a power producer, the registered capacity and any applicable restriction; (iii) network reliability; 9th January, 2026 Statutory Instruments 101 (iv) technical requirements from the user; and (v) any tariff applicable. (g) The TNSP shall, where the TNSP accepts the application referred to under paragraph A.3, provide the applicant with a budget quote or firm quote for a new connection or for modifying an existing connection within the following time frames: Budget Quote (business days) Firm Quote (Business days) Connection service Use of network service 30 15 60 30 (h) (i) the budget quote or firm quote for a new connection or for modifying an existing connection shall be in accordance with the tariff methodology and charging statement approved by the Energy Regulation Boad. a user shall on receipt of the TNSP’s proposal referred to under paragraph (e), accept the proposal within 30 days, or a longer period specified in the TNSP’s proposal, after which the proposal automatically lapses. (j) A user who intends to extend the period of validity of the proposal referred to under paragraph (i), shall engage the TNSP for an extension. (k) A proposal that is extended under paragraph (j), shall not retain the applicant’s position in any queue. (l) The time period for connecting or modifying an existing connection to the transmission system shall be negotiated and agreed upon between the TNSP and the user for each application. (m) The technical specifications for connecting or modifying an existing connection to the transmission system shall be — (i) in accordance with this Code; (ii) as agreed on between the TNSP and user; and (iii) based on the transmission system impact assessment studies. (n) The TNSP and applicant may, where the TNSP and applicant fail to reach an agreement on the proposed connection or modification to an existing connection, refer the matter to the Energy Regulation Board for resolution. (o) The TNSP and the applicant shall, where the applicant accepts the TNSP’s proposal enter into — (i) (ii) (ii) a connection agreement or in the case of an application to modify an existing connection, an amended connection agreement in advance of any ordering of any materials or physical construction work; in the case of an end-use customer, PSA or other form of agreement prior to construction work; and in the case of an end-use customer, use-of-system contract before the commencement of energy transactions over the transmission system. 102 Statutory Instruments 9th January, 2026 A.5 Connection Conditions Responsibility of a TNSP (a) A TNSP shall make capacity available on the TNSPs networks and provide open and non-discriminatory access for the use of this capacity to users of the transmission system including power producers and embedded power producers. (b) A TNSP shall — (i) make available to the users the TNSP’s transmission connection information guide approved by the Energy Regulation Board; (ii) (iii) (iv) perform the TNSP’s duties set out in the transmission connection information guide; charge users for connection to the TNSPs network in line with the TNSPs connection charging statement; respond to an applicant’s request to be connected on the TNSPs network within the period specified in ZS 397; (iv) provide the information that is required to be provided to a user under this Code; (v) (vi) (vi) (vi) (vii) enter into a connection agreement with a user before connecting the user to the TNSPs network; use reasonable means to obtain permission for the required extension to its network to facilitate for the connection of Users’ installations; deliver the contracted works within the timeframes provided under the connection agreement; apply processes in order to be reasonably satisfied that a user’s installation is safe to connect and complies with the requirements of this Code, including, where appropriate, making quality of supply assessments and witness testing; ensure that the testing set out in Appendix 1 is carried out following the procedures set out in the appropriate approved testing and compliance manual and issue, withhold or withdraw the appropriate notices and certificates; (viii) connect the user’s installation in accordance with the requirements of this Code and TNSP’s connection information guide; (ix) reject to connect any facility which the transmission impact assessment studies indicate shall have a deleterious effect by exceeding the parameters laid down in the ZS387 and power quality directive by the Energy Regulation Board, when connected to the transmission system; and (x) ensure that its employees or its agents entering the user premises shall comply with the requirements of ZS 418. A.6 Connection Responsibilities of Users (a) A user is required to fulfil the obligations of a user and requirements under this Code. (b) A user shall — (i) provide safe access to the TNSP employees to carry out investigation, installation, operation, inspection and maintenance of the TNSP’s electrical equipment on the customer’s premises; (ii) ensure that the arrangements for access under paragraph (i) are stated in a connection agreement; 9th January, 2026 Statutory Instruments 103 (iii) ensure that there is no unreasonable delay to access to the TNSP’s equipment; (iv) (v) be responsible for the removal and the reinstallation of any user asset for the TNSP to perform the installation work that the user has requested; and comply with the reasonable additional requirements specified by the TNSP in respect of the technical and design requirements of equipment proposed to be connected to the transmission system; (c) (d) (e) (f) despite paragraph (b)(iv), in the case of reinstallation work following damage due to negligence of either a user or DNSP, the user or the DNSP who has committed the act of negligence resulting in the damage shall be responsible for the entire works and the the user or the DNSP shall agree how the works shall be carried out; user assets shall meet the quality of supply standards ZS 387 as measured at the point of connection; a user shall, prior to commissioning, attempt to identify if new or altered user’s assets could have a deleterious effect at the point of connection and advise the TNSP should such deleterious effect be identified; and a user may, where the user believes the present, or proposed TNSP installation has the potential to adversely or materially affect the performance of the user assets, request the TNSP to submit design information, drawings or other relevant information. A.7 Connection Charging and Charging Statement (a) (b) (c) a user seeking to connect to the transmission system is required to meet the costs of that connection and any additional expenses incurred by the TNSP on behalf of the user; despite paragraph (a), all system-wide works required resulting from the connection of the generating units shall be borne by the TNSP; a TNSP shall prepare a statement showing the basis for calculating the charges for connection to its transmission system and shall review the cost base at least annually at times agreed with Energy Regulation Board, unless agreed with Energy Regulation Board that an annual update is not required in a particular instance. On acceptance of the methodology and following any review, the statement shall be published so that applicants can confirm that their connection charge has been calculated according to the method and cost base at present in force. (d) network augmentation may be required at the cost of the user when the connection of the user’s facility or modified facility causes any of the following to occur: (i) insufficient thermal capacity prospective; (ii) fault levels exceed the TNSP (or DNSP’s) network’s safe operating levels; (iii) network voltage limits are breached; (iv) network protection systems unable to detect all credible fault types; (v) quality of supply limits are breached; (vi) inadequate transient stability; or (vii) remote monitoring and control is required to be installed by the TNSP. (e) the TNSP is entitled to recover its costs from the applicant for undertaking investigations in response to generation or load connection enquiries and processing an application for a connection service; 104 Statutory Instruments 9th January, 2026 (f) (g) the TNSP connection charge to a user shall be based on a minimum cost-efficient solution designed in accordance with approved connection policy and the transmission system planning principles set out in this Code. This shall be described as the connection charge for a standard compliant connection; a user may request different or additional reinforcements to the transmission system over and above that which could be economically justified as described in the Transmission System Chapter on planning and development. The TNSP shall provide such reinforcements if the user agrees to bear the costs. The required solution shall be optimally designed by the TNSP, priced according to the connection pricing manual and set down in the negotiated contract; (i) a user who intends to construct their own connection to the existing system should approach the TNSP. The design and equipment specification and the final construction shall be approved by the TNSP. The process details shall be set down in the connection guidelines document approved by Energy Regulation Board; A.8 Connection Agreement (a) (b) (c) no material alteration to an existing installation shall be made without approval from the TNSP; a user seeking a new connection or a modification of an existing connection to the transmission system shall secure the required connection agreement or modified connection agreement with the TNSP prior to the actual connection or re-connection with modification, to the transmission system; a user requiring new connection or alteration to existing supply shall provide all relevant technical details required by these connection conditions, unless excused from any requirement by the TNSP, and shall provide further information requested by the TNSP to enable the TNSP to make a fair assessment of the user’s requirements; (d) a connection agreement shall include — (i) the capacity or in the case of a power producer the registered capacity applicable, and a statement that this may not be exceeded except as expressly agreed to by the SO who shall have regard to issues raised by the TNSP and the degree of firmness; (ii) any information or schedules required under this Code and any further information required by the TNSP; (iii) the work to be carried out by the TNSP; (iv) the connection charges and payment dates including any on-going charges; (v) the expected timescale; (vi) details of the interface arrangements and obligations; (vii) any special technical matters; (viii) submittals required prior to commissioning; (ix) any special performance requirements; (x) the agreement for the user to comply with this Code unless varied or excused, the capacity offered or in the case of a power producer, the registered capacity; and (xi) any tariff applicable. 9th January, 2026 Statutory Instruments 105 (e) a connection agreemt shall be drafted by the TNSP and signed by both TNSP and user in respect of each and every connection or point of supply; (f) a power producer shall be responsible for any dedicated connection costs incurred on the IPS as a result of connection of the generating facility to the transmission system and the TNSP may require surety that these costs will be paid. A.9 Method of Connection (a) (b) a new connection to the transmission system shall be by means of a three-phase overhead line with bare conductors, an underground cable or a combination of both in accordance with this Code. a TNSP shall use reasonable endeavours to connect the user on the date agreed with the user. A.10 Connection Information Exchange (a) (b) (c) information shall be exchanged between a user and the TNSP for the TNSP to perform power system load flow, dynamic and other studies or analyses, and to enable users to design their systems. a TNSP’s transmission connection information guide document shall stipulate the time frames for stages of the connection process and exchange of information. in addition to the other provisions of this Code, the Information Exachange Chapter under this Code explains the information to be exchanged for connection and on- going system planning and the rules under which information is exchanged. A.10.1 TNSPS Obligation to Supply Data (a) (b) a TNSP shall, on request by a user, provide information as may ber e a s o n a b l y required relating to the design and characteristics of the transmission system or generating units of other users, except such information as is held under data confidentiality arrangements. a TNSP shall, where a TNSP proposes to make certain modifications to s system or where it has received information from a user under paragraph (a), which may affect other user installations, notify the users of the proposal, subject to any constraint of confidentiality or timing. i t A.10.2 Data to be Supplied by TNSP

1. Connection Voltage The TNSP shall state the voltage at which a user may be connected following discussions and considering the following factors: (a) (b) (c) (d) the user’s capacity or projected requirement and nature of the load to be connected; the present loading of the network; quality and security of supply considerations; and the plans for IPS development;

2. Design Data-Specific Data to enable a User to Design the User’s System and Equipment Following an application for supply, or on request of a user, or following a material change in the transmission system, the TNSP will provide some or all of the following information to enable users to assess their systems: (a) design information; (b) drawings; and 106 Statutory Instruments 9th January, 2026 (c) other relevant information of the present or proposed distribution installation.

3. Fault Level at the Point of Connection (a) the source impedance under maximum capacity conditions for each point of connection; and (b) the source impedance under minimum capacity conditions for each point of connection.

4. Switchgear Safety Information Details of safety securing and interlocking.

5. Re-closure updated information on circuit re-closing, protection principles and settings needed to ensure co-ordination of protection between the transmission system and the user system(s).

6. Demand Transfer Information where the same demand can be supplied from alternate user points of supply, the TNSP shall provide sufficient information to enable the user to complete the appropriate clause under user demand in Appendix 2.

7. System Reliability the expected reliability of the transmission system and connection.

8. Earthing Information the method of earthing of the transmission system, for example, whether it is connected solidly to earth or through impedance. A.10.3 User Information to be supplied

1. User Network effects Users whose installation contains network elements are to supply a network model in approved form and additionally supply the network (and transformer) with the appropriate information detailed in Appendix 2.

2. Capacitive and Inductive Effects The user shall, when applying to make a connection, provide the TNSP with appropriate information as detailed in Appendix 2. Details are required of any capacitor banks and reactors connected at medium voltage and above, within the user’s facility, which could affect the transmission system and which it is proposed to connect, if agreed with the TNSP. When requested by the TNSP, details shall be provided of distributed circuit capacitance and inductance. Sufficient detail is required for the following: (a) (b) to verify that controlling equipment of the transmission system is suitably rated; and to show that the performance of the transmission system will not be impaired.

3. Data Tables (a) connection information set out in tables A to J of Appendix 2 is required, as determined by the TNSP. (b) (c) (d) information set out in tables A to J of Appendix 2 are relevant to users of each type. information set out in tables A of Appendix 2 is a summary of the data requested or supplied and may be required from any user. the TNSP required data from tables B to F of Appendix 2 are to be completed by users with demand and include data for users with controllable demand and demand transfer capability. 9th January, 2026 Statutory Instruments 107 (e) the TNSP required data from tables F to I of Appendix 2 are to be completed by power producers. (f) (g) (h) the TNSP required data from tables H to I of Appendix 2 are to be supplied by users with relevant facilities. Table H refers to power producers with synchronous generating units and schedule I to power producers with asynchronous generating units. the TNSP required data from table J of Appendix 2 are to be supplied by users with energy storage units. the Information Exchange Chapter explains how users, are to report their data for the purposes of connection and annually thereafter. In addition, the TNSP may request the user to submit additional design information, drawings or other relevant information, if the TNSP believes any proposed installation or modification has the potential to adversely or materially affect the performance of the transmission system.

4. Data Categories (a) for the convenience of both users and TNSPs, data is divided into the following two categories: (i) standard data which is required to carry out initial assessment by load flow and fault level studies; and (b) (c) (ii) detailed data which is required to carry out later more detailed studies e.g. stability assessment. in most cases standard data elements are all that is required at the time of application, although for certain situations the TNSP might also require detailed data; applicants seeking connection shall ensure that the data provided is of good quality. Poor quality data can invalidate a proposal. Initial data (preliminary planning data) is often generic in nature. At the time when a project becomes agreed, the preliminary data is to be confirmed or replaced with committed project planning data, usually data provided by equipment manufacturers, and when constructed the committed project planning data is to be confirmed or preferably replaced with connected project planning data. There should be reasonable agreement between the data at all stages; (d) the rules for data confidentiality are set out in the Information Exchange Chapter; A.10.4 Submittals Prior to the Commissioning (a) the following shall be submitted to the SO by the user prior to the commissioning date, pursuant to the terms and conditions and schedules specified in the connection agreement: (i) (ii) the proposed name of the Participant site (which shall not be the same as, or confusingly similar to, the name of any of the TNSP’s sites or of any other Participant site); specifications of major customer assets not included in the standard data and detailed data and updated data with any estimated values assumed for planning purposes confirmed or, where practical, replaced by validated actual values and updated forecasts for items such as demand; (iii) a protection philosophy statement including the settings of protection; (iv) information to enable the TNSP to prepare the fixed asset boundary and the SO to prepare an operational Boundary, if different; 108 Statutory Instruments 9th January, 2026 (v) electrical diagrams of the customer assets at the point of connection; (vi) information that will enable the TNSP to prepare the point of connection drawings; (vii) a list of— (aa) (bb) officers who have been duly authorised to sign the site responsibility schedule on behalf of the user; the names and telephone numbers of authorised representatives, including the confirmation that they are fully authorised to make binding decisions on behalf of the user; and (cc) safety co-ordinators.; (viii) a statement that the user’s installation complies with the requirements of Code; (ix) copies of all safety rules and local safety instructions applicable at the users’ sites which shall be used at the TNSP or user interface; and (x) confirmation — (aa) of communication or SCADA interface arrangements for instruction; (bb) of instruction and information including the list of signals; and (cc) that the signals are formatted as required by the SO; (xi) proof of ownership of premises or lease agreement; and (xii) in the case of power producers, an estimate of the number of weeks of planned maintenance outage per annum for each generating unit proposed to be installed at the power production facility.

1.2.2 Commissioning of Equipment and Physical Connection to the Transmission System (a) (b) on completion of the user development and work at the point of connection, the customer assets at the point of connection and the user development shall be subjected to the test and commissioning procedure provided under this Code and further explained in each TNSP’s testing and compliance manual; the SO shall require certification and evidence to conclusively prove that the equipment installed, or to be installed, has been designed, tested and installed in a satisfactory manner and in conformance with the relevant standards and this Code. (c) the SO shall issue a certificate of electrical safety to the user for every installation established. (d) (e) (f) (g) the user shall, within 15 days of acceptance of the user’s written notice of readiness to connect, issue a certificate of approval to connect. the TNSP shall, before the user is physically connected, ensure that the TNSP is satisfied that the installation is safe to be connected. The safety requirements shall be approved and monitored by the Energy Regulation Board. the physical connection to the transmission system shall be made only after the SO has issued the certificate of approval to connect the user. a power producer shall ensure that an approved change or modification to a generating unit or to a subsystem of a generating unit is implemented in accordance with the relevant proposal approved by the SO; 9th January, 2026 Statutory Instruments 109 (h) (i) (j) (k) a power producer shall notify the SO promptly after an approved change or modification to a generating unit has been implemented and confirm that it conforms to the relevant proposal by conducting the relevant tests, in relation to the connection conditions; participants shall ensure that exciter, turbine governor and FACTS control system settings are implemented and are as finally recorded by the SO prior to commissioning; participants shall give the SO reasonable advance notice, of the time at which the commissioning tests will be carried out. The SO and the participant shall agree on the timely provision of operational data as provided under this Code; the TNSP’s testing and compliance manual applicable to transmission connections shall be prepared to clarify the tests to be carried out and the presentation of results, pursuant to this Code. Each TNSP’s testing and compliance manual shall show the following for each type of user: (i) which test is required; (ii) when the test is to be performed; (iii) whether the test is to be witnessed by the SO; (iv) under what conditions the test will be carried out; (v) acceptable ways to conduct the test; (vi) how the test results are to be recorded and presented; (vii) the pass or fail criteria; and (viii) what happens if the plant fails the test. (l) the SO has the right to witness certain tests. The SO should advise in a timely manner if the SO intends to do so; (m) the results of a compliance test shall be supplied to the SO in an agreed format; (n) certain aspects of the Code’s plant performance requirements may only be assessed when the plant has been energised. In this case, the approval to connect notice shall indicate that it is for the purpose of testing; (o) on successful completion of compliance testing the SO shall issue a final connection certificate; (p) where a test cannot be performed or a test fails to meet the requirements of this Code, the SO may refuse connection or may issue a temporary compliance certificate valid for a time to allow the matter to be rectified whilst the plant is permitted to be operational; (q) (r) the temporary compliance certificate will state the period of validity and any other conditions under which it is issued. Alternatively, the SO may issue a limited performance certificate restricting the performance of the plant in some way; if plant which originally complied later fails to meet Code requirements its final connection certificate may be withdrawn by the SO and, if appropriate, one of the other certificates issued or a final connection certificate may be issued for reduced capacity; and (s) in the case of disputes on compliance, the matter may be referred to the Energy Regulstion Board who may seek expert opinion. 110 Statutory Instruments 9th January, 2026

1.2.3 Failure to Comply (a) (b) in the event of non-compliance with the Code requirements, the SO may prevent the generating unit from being allowed to be operated commercially; and if a new user’s or an existing user’s equipment fails to comply with the standards set down in, or cannot comply (for technical or economic or other reasons) with the requirements of, the connection conditions, the user may seek an exemption from the provision from Energy Regulation Board in accordance with the provisions of this Code.

1.2.4 Conditions for Disconnection of Supply User’s equipment may be disconnected for the following reasons: (a) on a user’s written request; (b) in cases of emergency; (c) in the event of violation of Electricity Safety Code ZS 418 or other Safety Regulations from time to time in force; (d) in the event of violation of the commercial agreements such as — (i) where the user’s installation or use of electricity is such as to interfere with the satisfactory operation of the IPS or to cause disturbance to other users; (ii) where a TNSP or SO considers that the user’s or customer’s installation is in a dangerous condition; (iii) where alterations, repairs, renewal or maintenance of the transmission system or the TNSP’s assets or means of connection require the de-energization of the point of connection and subject to requisite notice period; or (iv) failure by user to comply to any provision of this Code; or (v) under conditions set out by any TNSP and agreed by Energy Regulation Board as necessary for revenue protection by the payment by any User of amounts due and for the prevention of fraud.

1.2.5 Conditions for Reconnection of Supply after Disconnection Subsequent to the disconnection under paragraph 1.2.4, a user’s assets may be reconnected for the following reasons: (a) on the user’s written request; (b) compliance with relevant Electricity Supply Code -Code of Practice ZS 418 or such other Code as shall be deemed applicable where a disconnection was effected; (c) compliance with relevant commercial terms and agreements and successful clearance of any matter causing disconnection under this Code; or (d) in compliance with the regulatory order, save for technical or safety reasons.

1.2.6 TNSP Planning Standards The transmission system is planned according to Zambian standard ZS 387 - Electricity Supply - Power Quality and Reliability which is approved by the Energy Regulation Board. 9th January, 2026 Statutory Instruments 111

1. Frequency (a) the nominal frequency of the transmission system is 50Hz and is normally controlled within the limits of ±0.15Hz unless exceptional circumstances prevail. The system frequency could rise or fall in exceptional circumstances. (b) in the case of non-interconnected networks (Island networks) the frequency can rise to 52.5Hz or fall to 47.5Hz.

1. Voltage The lower threshold of the transmission voltage is stated in the Electricity Act 2019 and the voltage ranges are set down in ZS 387.

2. System Earthing The Transmission System is in general effectively Earthed (IEC 60044-8). Earthing details will be provided in the connection agreement.

3. Power Quality (a) the System is planned to comply with ZS387 and the Energy Regulation Board Power Quality Directive regarding the parameters listed below — (i) voltage harmonics and interharmonics; (ii) voltage flicker; (iii) voltage unbalance ; (iv) voltage dips; (v) interruptions; (vi) voltage regulation; (vii) frequency; and (viii) voltage surges and switching disturbances. (b) it is not possible to always operate the system within the standards because certain contingencies have not been planned for. It is the responsibility of Participants to protect their plant and equipment from these abnormal situations.

1.2.7 Technical Requirements -All users A.1 Ownership boundaries (a) The user shall be responsible for the provision of the site required for the installation of the TNSP equipment required for connecting the user’s facility unless otherwise stated in the connection agreement. (b) The user shall be responsible for the circuit breaker to connect and disconnect the user’s installation and there shall also be visible isolation at the point of connection to provide the means of electrically isolating the transmission system from the user’s facility. The location of the circuit breaker and visible isolation shall be decided upon jointly by the TNSP and the user and shall be agreed in the connection agreement between the TNSP and the user (c) The ownership boundary shall be subject to specific agreement between the parties in each case which shall be guided by the rules set out in the definition of the demarcation point. Changes in the ownership boundary arrangements proposed by either Participant shall be agreed in advance and shall be recorded in the connection agreement. (d) All equipment at the ownership boundary shall meet the design principles contained in paragragh 1.2.7. 112 Statutory Instruments 9th January, 2026 (e) Connections to the transmission system shall incorporate a means of disconnection of the user’s installation by the TNSP. A.2 User Import and Export Limits All users shall ensure that their facility is so managed that neither import nor export quantities exceed the amounts agreed in their connection agreement except with the express permission of the SO. A.3 Tolerance All users shall ensure that their plant and equipment is so designed, installed and protected to withstand the system conditions in ZS 387 without damage. A.4 User Equipment Standards, Records and Maintenance (a) The user shall be responsible for the design, construction, maintenance and operation of the equipment on the user’s side of the point of connection. (b) All equipment on the user’s installation shall be suitable for use at the nominal operating frequency of 50 Hz and at the voltage and short-circuit rating stipulated in the proposal and confirmed in the connection agreement and shall normally be controlled within the approved limits. (c) All equipment in a user installation connected to the system shall be designed, manufactured, tested, and installed in accordance with all applicable statutory obligations and shall conform to the relevant Zambian standards (or equivalent IEC standards) applicable at the time of agreement to connect the installation to the transmission system. (d) If there is are no relevant Zambian standard or equivalent IEC standard available, and or if the TNSP considers it necessary, the TNSP may notify the users that supplemental specifications and standards shall be complied with, in which case the user’s plant and apparatus shall comply. (e) Where a user needs to install equipment that connects directly with TNSP equipment in transmission substations, such equipment shall adhere to the TNSP design requirements as set out in Transmision System Chapter. (f) The TNSP may require users to provide documentary proof that their connection equipment complies with all relevant design requirements, both by design and by testing. (g) Users shall ensure that all equipment at the point of connection and on the TNSPs’ sites is maintained at least in accordance with the manufacturers’ specifications or an alternate industry recognised methodology and shall monitor the performance of their plant and take appropriate action where deteriorating trends are detected. Users shall ensure that their equipment does not pose a threat to the safety of the TNSP’s plant or personnel. (h) Maintenance scheduling shall be done in accordance with the System Operation Chapter. (i) Users shall retain test results and maintenance records relating to the equipment at the point of connection and make this information available if requested. The SO or TNSP shall have the right to inspect the test results and maintenance records relating to such plant at any time. 9th January, 2026 Statutory Instruments 113 A.5 Equipment Ratings (a) Users’ equipment rating shall be adequate for the duties of carrying load current, making and breaking fault currents of 3-phase faults and single phase-to-earth faults and shall have regard to the X/R ratio at the location on the transmission system. (b) The SO shall provide information on the short-circuit levels having regard to known plans and the user shall ensure that equipment installed provides a reasonable safety margin. The information provided by the SO shall be made available as early as possible within the connection process. (c) Equipment design shall take account of TNSP’s requirements for its safety management systems. (d) Circuit breakers at the interface position shall be equipped with measurement and protection transformers and relays to the TNSP’s requirements. (e) The specification of associated apparatus and plant of the distribution System of a user shall meet the voltage that will be imposed as a result of the method of earthing. A.6 Transformers and tap changers, Reactors, User Networks and Plant (a) Users’ transformer insulation and the insulation of plant and other user network components is to be designed and operated, if necessary with ancillary devices, so as to withstand the asymmetrical voltages caused by faults and adequate for the BILs. (b) Users’ reactive power equipment, transformer tap changers and control shall be so managed to avoid disturbing the TNSP’s voltage management system. A.7 Earthing (a) The SO shall advise users about the earthing methods used in the transmission system. (b) The method of earthing used on those portions of user’s installations that are physically connected to the transmission system shall comply with the TNSP’s applicable earthing standards as provided in ZS 418 and ZS 691. (c) In cases where the calculated earth potential rise exceeds 5kV, the responsible Participant shall inform the affected Participants. (d) Users should be aware that approved designed lightning protection requirements shall be applied to the transmission system and switching yards and substation earthing requirement shall be in accordance with ZS418 and any other relevant standards. (e) Users shall take precautions to limit the occurrence and effects of circulating currents in respect of the neutral points connected with earth where there is more than one source of electricity. (f) In relation to earthing of the part of the user’s installation that is connected to the transmission system any earths associated with equipment within a prescribed zone shall be kept bonded. A.8 Fault Levels (a) The SO shall provide prospective users with information about the transmission system fault levels. Users shall ensure that their equipment is capable of operating at specified fault levels as published by the SO from time to time. (b) Users with large synchronous motors and users with generating units generally increase the transmission system fault levels. Before such plant is added to the trabsmission system, it shall be assessed whether existing equipment will be able to sustain the increased fault levels. 114 Statutory Instruments 9th January, 2026 (c) In the event that works are carried out that will result in fault level ratings exceeding that of user’s equipment, the TNSP shall seek overall lowest cost solution to address the problem. Corrective action shall be at the cost of the relevant asset owner that has caused the increase in fauIt levels. (d) Where mitigating actions have been put in place to reduce fault levels, the SO shall document the actions and the maximum fault levels, before and after such actions. (e) All users shall ensure that their contribution to single-phase to earth and three-phase fault level from their electric drives and generating units remains within levels agreed with the SO who shall have regard to the symmetrical and asymmetrical make and break ratings of system equipment and the nature of the user’s plant, and shall endeavour to ensure that the contractually agreed fault level in the network at the point of connection shall not be exceeded. A.9 Protection Design and settings (a) Protection requirements stated in this Code are to protect the transmission system. The user is responsible for protection of its personnel and equipment. All Participants shall take reasonable steps to protect their plant in accordance with prudent utility practice. (b) Required HV breaker tripping, fault clearance times, including breaker operating times depend on system conditions and shall be defined by the SO. All protection interfaces with the TNSP shall be co-ordinated amongst the Participants. (c) The asset owner in consultation with the other relevant Participants shall determine CT and VT ratios and cores. (d) A TNSP, and each user connected to the transmission system shall ensure that its measurement equipment complies with the accuracy classes specified in Electricity Metering - Code of Practice: ZS 647 for the purpose of operation and control of the IPS. (e) All users shall ensure correct and appropriate settings of protection to achieve effective isolation of faulty equipment within the specified clearance time. Protection settings at the point of connection shall not be altered, or protection bypassed and disconnected without consultation and agreement of the Participants on either side of the demarcation point. In the case where protection is bypassed and disconnected, by agreement, then the cause must be rectified, and the protection restored to normal condition as quickly as possible. If agreement has not been reached the electrical equipment will be removed from service forthwith. (f) The SO protection requirements, with which users (shall interface, are described in this section. (g) The primary objectives of the protection required under this Code are to — (i) ensure agreed power quality and security of supply to users; (ii) minimise damage to primary plant; (iii) prevent damage to healthy equipment that s fault current during faults; and (iv) limit safety hazards to the power utility personnel and the public. (h) The SO shall — (i) develop the protection requirement guide for connecting generating units to the transmission system to ensure safe and reliable operation of the transmission system; and 9th January, 2026 Statutory Instruments 115 (ii) be responsible for co-ordination of protection at the point of connection with all users and shall investigate any mal-function of protection or other unsatisfactory protection issues at the point of connection. (i) The TNSP shall— (a) ensure that periodic testing and the recording of test results for protection equipment and systems involving power producers installations and such other installations as the SO shall define is carried out to ensure these are performing to the designed specifications. Periodic tests must be performed by Participants which shall be at least every five years unless otherwise advised by manufacturers (j) The user shall — (i) install and maintain protection, which is compatible with the existing transmission system protection. The user’s protection settings shall ensure coordination with the TNSP’s protection. To achieve this — (aa) User’s plant shall be designed and operated with protective devices in accordance with the requirements set by the TNSP which shall have in mind the SO protection guide; and (bb) the fault clearance time shall be within the limits established by the TNSP’s in accordance with the protection philosophy; (ii) (iii) (iv) (v) (vi) ensure that faults in the user’s plant and apparatus do not unreasonably cause disturbances to the transmission system or to other users; ensure that their protection schemes and equipment comply with the SO’s protection requirement guide; provide the TNSP with test certificates, prior to commissioning of the protection system(s) that are installed at the point of connection with the TNSP; in the case of new users, or users specifically requested by the TNSP, provide a protection Philosophy Statement; and in the case users whose equipment is within the curtilage of a TNSP switching station or substation, have regard to the protection requirements applicable to the TNSP when designing and installing equipment and protection including CTs and VTs. (k) The protection schemes installed by a user shall incorporate adequate facilities for testing, monitoring and maintenance. (l) Users’ protection systems shall make provisions to safeguard their own equipment including their generating units from faults or conditions that may occur on the IPS or at the point of connection any single phase or three-phase tripping and auto- reclosing that may exist on the transmission system. (m) Joint responsibilities are: (i) insofar as the equipment of one Participant may have an impact on the other (including for TNSP’s whose networks are directly connected together), Participants shall agree to the detailed protection applications, in writing. DNSPs and end-use customers connected directly to the transmission substations shall ensure that they comply with the protection standards of the relevant TNSP; (ii) Participants shall cooperate with the TNSP to co-ordinate the settings of protection to ensure proper operation and selectivity; 116 Statutory Instruments 9th January, 2026 (iii) Where equipment or protection schemes are shared, the Participants shall provide the necessary equipment and interconnections to the equipment of the other Participant; and (iv) The TNSP and user shall be solely responsible for the Protection system of the electrical equipment and facilities at their respective sides of the point of connection and shall be responsible for the installation and maintenance of their respective protection relays at the point of connection. (n) New users or users specifically requested by the SO, shall prepare a protection Philosophy Statement according to a model format issued by the DNSP or SO content as follows: (i) a description of the protection philosophy; (ii) a description of plant capabilities and the relevant protection operations; (iii) (iv) (v) a description of any auto-reclose facilities installed or to be installed by any Participant; a list of relays and settings including for generating unit and associated equipment; the most probable fault clearance time (Fault inception to arc extinction) which must not threaten selectivity or equipment ratings; (vi) how the protection system allows for TNSP auto-reclose systems; (vii) how selectivity is achieved and compliance with Zambian standards and TNSP practice is observed (TNSP to inform in a standard protection policy paper with a local system information annex); and (viii) any other matter required by the TNSP or SO, to be determined in consultation with the user, and any resulting equipment to be provided and maintained by the relevant user at its own cost. (o) The protection philosophy statement shall be submitted by the user for approval by the TNSP which shall have in mind the SO protection guide. (p) The protection functions are considered adequate when the protection relays perform correctly in terms of: (i) reliability; (ii) speed of operation; (iii) selectivity; and (iv) sensitivity. (q) (r) protection dependability (IEC50-448) shall not be less than 99%. the Energy Regulation Board shall monitor compliance with all matters covered by this section of the Code and shall design and effect appropriate penalties for enforcing compliance. A.10 Work on and Testing of Protection Equipment (a) Any work on the protection circuits interfacing with transmission protection systems shall be sanctioned by the SO. (b) Prototype and routine testing shall be carried out as defined in Appendix 1. (c) Each user is responsible for tests on its own protection equipment, and a record of test results shall be kept for submission upon request by the TNSP or the Energy Regulation Board or both. Additionally, records of protection test results of the users own equipment must be submitted to the SO. Periodic tests must be performed once every two years. 9th January, 2026 Statutory Instruments 117 A.11 Backup Protection (a) In order to cover a circuit breaker or equipment having a similar function failing to operate correctly to interrupt fault current on the HV or EHV system, back-up Protection by operation of other circuit breakers or equipment having a similar function shall normally be provided by the user. (b) The TNSP will inform the user if it is not required. Users should note that if the circuit breaker is owned by the TNSP, it may be equipped with protection that is limited to that required to provide excess energy protection to the transmission system. A.12 Limitation of Fault Current For safety reasons, unless expressly permitted by the TNSP, fault-limiting devices are not permitted, if the failure to operate as designed could result in danger to personnel or damage to the transmission system. A.13 Inter-tripping For safety and equipment protection reasons, it is proposed to ensure that if protection of equipment is dependent on operation of both the user’s and the TNSP’s circuit breakers, appropriate inter-tripping is provided. The arrangements and settings are to be agreed between the user and the TNSP. A.14 Interface Protection Commissioning This shall be proven on site and the TNSP shall have a right to witness the commissioning. A.15 Users to comply with Power Quality and Reliability requirements (a) User’s developments shall meet the following power quality requirements assessed at the point of connection: (i) harmonic distortion shall be not more than permitted in the ZS 387 Electricity Supply Power Quality and Reliability standard or the relevant international standards; (ii) No direct current shall be injected into the transmission system. This applies both to power producers and demand users; (iii) Voltage fluctuations shall be within the limits defined in the ZS 387 or the relevant international standards. This applies to users with motor and disturbing loads; (iv) ZS387 - phase unbalance of currents shall not exceed 1% or 2% stated in the connection agreement for users connected at high voltage or extra high voltage ; and (v) Users with transformers which connect their installation to the transmission system shall ensure that the TNSP’s requirements for voltage stability of the transmission system are complied with. (b) Users of the transmission system must not generate voltage disturbances at a level that would affect other users. Users should select equipment that is capable of functioning satisfactorily in the presence of voltage ranges and disturbances at the levels that can be expected on the transmission system as stated in ZS 387. (c) The transmission system shall comply with the emission limits, which are set out in ZS 387. 118 Statutory Instruments 9th January, 2026 (d) (e) If a user’s network or equipment performance falls below the specifications of ZS387 or affects the power quality to other users, or causes damage, direct or indirect to the TNSP equipment, the process for dispute resolution uner this Code shall be followed. If users are aware that their network or equipment performance could be unacceptable as described above, they shall take reasonable steps at their own cost to overcome the shortcomings. These changes should be effected in consultation with the TNSP relating to both the technical scope and the time frame. A.16 Power Factor (a) DNSPs shall take all reasonable steps to ensure that the power factor at the point of supply is at all times 0.92 lagging or better. (b) End-use customers shall take all reasonable steps to ensure that the power factor at the point of supply is at all times 0.96 lagging or better unless otherwise agreed to in existing contracts between the Participants. (c) Power factor at the interface between TNSPs shall be specified by the SO acting reasonably. (d) The above requirement applies to each point of supply individually for DNSPs, and end-use customers with more than one point of supply. A leading power factor shall not be acceptable, unless specifically agreed to in writing. (e) A penalty and incentive scheme set or approved by Energy Regulation Board shall be agreed between the TNSP and the DNSP or end-use customer regarding the limits of the power factor. Should the power factor be out of the agreed limits, the penalty and incentive scheme shall apply. (f) The Participants shall co-operate in determining the plans of action to rectify the situation on a permanent basis. Overall lowest cost solutions shall be sought. A.17 Site related conditions (a) In the absence of agreement between the parties to the contrary, construction, commissioning, control, operation and maintenance responsibilities follow ownership. (b) The following applies to all sites with equipment operating at high voltage and above: A.17.1 Responsibilities for Safety (a) Any user entering and working on its plant on the TNSP’s site will work to the TNSP’s safety rules, unless otherwise agreed in writing. (b) A user may apply to the TNSP for permission to work according to that user’s own safety rules when working on its plant on the TNSP’s sites. If the TNSP is of the opinion that the user safety rules provide for a level of safety commensurate with that of the TNSP’s safety rules, it shall notify the user, in writing, that the user may use its own safety rules. (c) The TNSP entering and working on the TNSP’s plant on a user site may be requested by the user to work to the user’s safety rules. Until receipt of such notice, the TNSP’s safety rules will apply. The TNSP shall not be obliged to accede to this request where in the TNSP’s reasonable opinion the user’s safety rules do not provide a level of safety commensurate with the TNSP’s safety rules. (d) The TNSP may apply to a user for permission to work according to the TNSP’s safety rules when working on its plant on that user’s sites. If the user is of the opinion that the TNSP’s safety rules provide for a level of safety commensurate with that of that user’s safety rules, it shall notify the TNSP, in writing, that the TNSP may use its own safety rules. Until receipt of such notice, the TNSP’s safety rules will apply. 9th January, 2026 Statutory Instruments 119 A.17.2 Site Responsibility Schedule A set of connection site schedules shall be prepared identifying the equipment and ownership at the connection site, the points of connection and the responsibilities for safety, control and maintenance.to inform site staff the SO and TNSP(s) of agreed responsibilities for plant at the operational interface. A.17.3 operation and insulation zone diagrams (a) An operating diagram shall be prepared for each connection site at which a point of connection exists. the operation diagram shall include all HV and EHV plant and the connections to all external circuits and incorporate numbering, nomenclature and labelling as agreed with the TNSP. At those connection sites where work may be undertaken which could threaten the integrity of insulation in adjacent equipment the equipment layoutmust be depicted within a delineated area showing zonal insulation boundaries. the nomenclature used shall conform to that used on the relevant connection site and circuit. (b) The operating diagram (and the list of technical details) is intended to provide an accurate record of the layout and circuit interconnections, ratings and numbering and nomenclature of HV / EHV plant and related plant. A.17.4 Site Common Drawings (a) Site common drawings shall be prepared for each connection site and shall include connection site layout drawings and electrical layout drawings and they will identify the responsibilities for common services drawings. These items will form part of the connection agreement that will also require common protection or control drawings to be available to all relevant parties. (b) The following minimum set of drawings shall be made available by the respective asset owners for all points of supply, if required by the other Participant for the purposes of connection or later work: (i) key plan; (ii) bay layout table; (iii) foundation, earth-mat or earth-pit and trench layout; (iv) steelwork marking plan; (v) security fence layout; (vi) terrace, road and drainage layout; (vii) transformer plinth; (viii) general arrangement; (ix) drawings with sectional details; (x) slack span schedule; (xi) barrier fence layout; (xii) security lighting; (xiii) floodlighting parameter sketch; (xiv) protection details; (xv) contour plan; and (xvi) station electric diagram. 120 Statutory Instruments 9th January, 2026 (c) All drawings shall use the standard electrical symbol set as defined in IEC 60617 “graphical symbols for diagrams” or any other relevant Zambian Standard as a standard for electrical drawings, unless otherwise agreed between a service provider and customer. A.17.5 Disturbance and power quality reorders The SO shall determine the need for a user to fit a recorder(s) at a suitable location at a user’s point of connection. A.17.6 Access (a) The provisions relating to access to the TNSPs’ sites by users, and to users’ sites by the TNSPs, are set out in each connection agreement between the TNSP and each user. In addition to those provisions, where a TNSP, site contains exposed EHV, HV or MV conductors, unaccompanied access shall only be granted to individuals holding appropriate authorisation. (b) It is a requirement that all TNSPs’ plant on users’ sites is maintained adequately for the purposes for which it is intended and to ensure that it does not pose a threat to the safety of any user plant or personnel on the user site. Users shall have the right to inspect the test results and maintenance records relating to such plant, at any time. A.17.7 Site operational procedures The TNSP and users with an interface with a TNSP, must make available staff to take necessary safety precautions and carry out operation duties as may be required to enable work or testing to be carried out and for the operation of plant connected to the transmission system. A.18 Metering The responsibilities for metering are set out in the Metering Chapter of this Code.

1.2.8 Technical Requirements for Power Producers (a) (b) the SO is responsible for controlling frequency on the IPS. subject to the other provisions of this Code, the requirements set out in the table below applies to — (i) power producers connected to the transmission system; (ii) (ii) power producers having either synchronous or asynchronous generating units; and embedded power producers with a registered capacity 2MW. ≥ 9th January, 2026 Statutory Instruments 121 Technical Requirements ALL Generating Units TGCR1 Grid Protection Reverse Power – Switch to standstill protection User’s Generator transformer HV backup Earth fault and REF HV Breaker Fail HV Breaker Pole Discrepancy for circuit breakers with independent poles Yes Yes Yes <20MW 20-100MW >100MW Yes Yes Yes Yes Yes Yes System Depends on Requirements Grid Protection (achieved with Controls) Yes Yes Main Grid Protection only Depends on System Requirements TGCR2 Excitation System requirements PSS Yes TGCR3 Reactive Capabilities TGCR4 Active Power – Governing Yes Active Power - control functions — Ramp rate management — -Delta control if Yes based upon VRE AGC Yes Yes No Low Voltage Ride Through Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes 122 Statutory Instruments 9th January, 2026 A.1 Registered Capacity (a) (b) (c) power producers may not export more than the registered capacity in their connection agreement except with the express permission of the DNSP (in the case of embedded generating units) or the SO in the case of directly connected generating units. The SO shall have regard to information supplied by the TNSP when giving such permission; the registered capacity of synchronous generating units connected to the transmission system is the maximum permitted active power (MW) output of the generating unit measured at the generator terminals when generating 0.85 lagging (generating) - or0.95 leading (absorbing) power factor; the registered capacity of asynchronous generating units connected to the IPS and all embedded generating units is the maximum permitted active power (MW) output when generating or absorbing reactive power at 0.95 power factor (33% of active power) as measured at the point of connection; A.2 Tolerance of System and Environmental Conditions (a) (b) (c) power producers connected to the IPS must ensure that their plant remains connected for the specified system normal and abnormal conditions of frequency and voltage, including an ability to withstand sudden phase jumps of up to 20° at the point of connection without disconnecting or reducing output. The generating unit shall after a settling period resume normal production not later than 5 sec after the operating conditions in the point of connection have reverted to the normal operating conditions; generating plant connected to the IPS shall be designed and operated to include devices that will withstand and mitigate the effects of transient over voltages on the IPS whether as a result of switching or lightning; power producers whose plant is connected to the IPS must ensure that their equipment tolerates and remains operational throughout the temperature and other climatic conditions in Zambia. It is not acceptable for any plant, including inverters, to disconnect or significantly reduce output up to the maximum ambient temperature stated for the site in the connection agreement; A.3 Automatic Generation Control (a) (b) generating units ≥ 20MW approved for connection after the first revision of this Code and connected to the IPS shall be equipped with automatic generation control and appropriate communication; power producers with generating units 10MW but <20MW may fit AGC equipment and may elect to participate in AGC; ≥ A.4 Frequency Performance – Plant Capability The expected frequency performance of generating units connected to the IPS is as follows: A.4.1 Frequency Normal (a) he nominal frequency of the IPS is 50Hz and is normally controlled within the limits of ±0.15Hz (the normal frequency range) unless exceptional circumstances prevail; (b) generating units 2MW connected to the IPS shall be capable of continuous operation, at up to 100% of their registered capacity throughout the normal frequency range; ≥ (c) generating units connected to the IPS and selected to perform in AGC mode shall be directed to endeavour to maintain the frequency within the normal range; 9th January, 2026 Statutory Instruments 123 A.4.2 Frequency Abnormal (a) the transmission system frequency could rise or fall in exceptional circumstances and generating units must be capable of continuous normal operation for the high and low frequency conditions set out in this Code when the transmission system comes out of synchronism with the regional power pools. A.4.3 Frequency Low.-. < 49.85Hz (a) (b) (c) (d) (e) low frequency response for frequencies below 49.85HZ is defined as an ancillary service in the form of operating reserve. However generating units e” 2MW connected to the IPS shall be designed to be capable of operating in frequency response Mode with a time based response characteristic identified in the connection agreement or other agreement; below the normal frequency range, all generating units must remain connected to the transmission system. The output of any generating unit connected to the transmission system and all generating units approved for connection to the IPS after the first revision of this Code shall not be reduced by a greater percentage than the frequency; if the frequency drops to 47.5Hz the plant should remain connected but may trip to protect itself within a specified period. At this frequency, the IPS has been set to separate from the international interconnectors after a preset time delay. This value is meant to preserve transmission system integrity throughout the Regional power pool area; under-frequency control and protection shall be fitted and shall be coordinated with automatic load shedding; the behaviour of generating units connected to the transmission system or the IPS as determined by dynamic studies for turbo-alternators are as follows: (i) (ii) (iii) generating units connected to the IPS with rating of 5MVA or greater should be equipped with governors operating with a droop between 2% and 10% with an initial setting of 4%; any change from the initial 4% setting shall be reported to the SO with justification; the low and high frequency limits for turbo-alternators shall be 47Hz and

51.5Hz beyond which the generator may trip out in order to protect the unit; and (iv) within the low and high frequency limits, the generators are expected to remain connected to the grid for different range of frequencies for a period specified in the table below: Proposed Frequency Requirements for Turbo-alternators Frequency range Above 52Hz

49.0Hz – 51.0Hz Specified Operating Time Generator not allowed to run beyond this frequency Maximum time of 4 Seconds 1 Minute Continuous

49.85Hz – 50.15Hz Continuous (Dead-band Limit)

47.0Hz – 47.5Hz Below 47Hz 1 Minute 6 Seconds 200ms 124 Statutory Instruments 9th January, 2026 (f) all reasonable efforts shall be made by the power producer to avoid tripping large hydro-alternator based generating units for under frequency conditions provided that the system frequency is above 47.5Hz. A.4.4 Frequency High (a) when the frequency is above the normal range but less than a high frequency setting determined by the SO (normally 50.5Hz), generating units connected to the IPS shall reduce output according to the droop characteristic set in their governor device. This is a high frequency response mode; (b) generating units connected to the IPS and embedded generating units approved for connection after the first revision of the Code shall remain connected and shall respond by reducing active power for frequencies above 50.5Hz. Speed governors shall be set to a predetermined droop characteristic to achieve the output reduction in the following curve. The response shall be fully achieved within the time set in the dynamic study of the transmission system and must be sustained for the duration of the frequency excursion. The generating unit shall respond to the full designed minimum operational capability of the generating unit (which may in the case of hyrdo-alternators be the full load capability range) at the time of the occurrence; Above Table showing - High Frequency response for All Generation (c) generating units may connect or ramp up only when frequency is within or below the normal operating range except on the express requirement of the SO; (d) whilst responding to frequency excursions on the transmission system the change in output of the generating Unit shall be at the frequency response ramp rate (which is the fastest available ramp); (e) generating units shall be equipped with a lockout facility whereby after tripping due to high frequency they may only return to service either when the frequency falls below a set value (determined by the SO) for a time (set by the SO) or when the lockout is otherwise released by a signal sent by the SO. The arrangements and values will be set out in the connection agreement. A.4.5 Rate of Change of Frequency (a) generating units must be capable of withstanding a rate of change of frequency up to 1Hz/s without disconnection from the network other than when triggered by loss of mains protection. The rate of change of frequency shall be measured over a sliding 500ms time period. 9th January, 2026 Statutory Instruments 125 A.5 Active Power - Output Control (a) generating units e” 2MW, approved for connection to the IPS shall be capable of receiving a dispatch instruction to — (i) target an active power output or an absolute power limit; (ii) provide primary frequency control (with on or off instruction from SO); and (iii) in the case of renewable resource plant, to switch in or out frequency sensitive mode based upon active power delta regulation. (b) with respect to accuracy of the active power set point and the resulting control action, there shall not be any deviation of more than 2% of the set point value or by

0.5% of the rated power, whichever provides the closer tolerance. In assessing compliance, due regard shall be taken of the available energy and the power curve as specified/set out in the connection agreement; (c) (d) power producers shall ensure that interface control and performance requirements are met in respect of each of their generating units through a capability to receive dispatch instructions delivered by an automatic remote control or SCADA system; additionally, generating units depending in total or in part on a variable energy source shall be equipped to receive a dispatch instruction to switch in or out and control ramp rate by setting an active power gradient; (e) there shall be three ramp rates as follows: (i) start-up or shutdown ramp rate; (ii) normal operating ramp rate; or (iii) emergency ramp rate which shall — (aa) be unconstrained for low frequency; and (bb) follow the curve in section 4.3 for high frequency. (f) ramp rates should be settable separately for — (i) output on start-up in the range 10% -100% of the registered capacity of the generating unit per minute; and (ii) for normal operation, in the same range. (g) ramp rates shall be effectively controlled over the entire output range of the generating unit; (h) emergency frequency management action shall be prioritised over any constraint imposed by any ramp rate limiter; (i) for all dispatch instructions, there should be automatic confirmation that — (i) the generating unit has commenced enactment of dispatch instruction; and (ii) the instructed action has been achieved. (b) an active power dispatch instruction to any generating unit connected to the IPS shall be fully enacted within 30 seconds except where constrained by energy resource or ramp rate limitations. A.6 Primary Frequency Control (a) generating units connected to the transmission system and all generating units 250kW approved to be connected to the IPS shall be fitted with a proportional frequency governor or a device emulating the function of a governor; and ≥ 126 Statutory Instruments 9th January, 2026 (b) this shall be active when the generating unit is in normal frequency control mode. The deadband and droop shall be settable. The droop shall be settable in the range 2% to 10% separately in steps of 1% for low and high frequency response and the deadband shall be settable between 49Hz and 51Hz in 0.05Hz intervals. The settings shall be advised by the SO. The governor setting controls are shown diagrammatically in Figure below. Figure showing – Governor droop control (c) the SO shall advise all power producers with directly connected generating units, all power producers not directly connected and all DNSPs regarding the dead band setting for generating units; (d) he SAPP Operating Sub-committee have approved relaxed frequency bands in the power pool from ±0.05Hz to ±0.15Hz during normal operations. The default dead band setting therefore shall be ±O.15Hz. That is, no response is required from the generating unit while the frequency is greater than 49.85Hz and less than 50.15 Hz; (e) routine and prototype response tests shall be carried out on the governing systems as indicated in Appendix 1; (f) generating units e” 2MW, connected to the IPS dependent on a variable energy source and approved for connection after shall be equipped with a delta power control mode where the actual power is a defined percentage below the maximum possible instantaneous power. (example in Figure below) Figure showing- delta control principle for variable energy generating unit active power control 9th January, 2026 Statutory Instruments 127 (g) any requirement to operate in normal frequency control mode is an ancillary service function and is therefore a contracted service. A.7 Active Power - Output Compliance (a) (b) the active power output of each generating unit shall be assessed in relation to its registered capacity and any dispatch instruction; and the active power output of a variable energy generating unit with registered capacity e”2MW shall be controllable as long as technically feasible based on the available energy. A.8 Fault Ride Through (a) (b) generating units connected to the IPS shall be able to withstand the effect of voltage deviations resulting from transmission system disturbances and generating units e”2MW should remain connected for the periods defined below in the fault ride through curve Figures (a) &(b) below; new generating units e” 2MW approved for connection after the first revision of the Code’should be able to stay connected as indicated in the following curves for all pre-fault operating positions within the operating range stated in their operating capability chart in the connection agreement in the case of synchronous generating units or shown in Figure (a) and (b) in the case of asynchronous generating units. Figure (a) -Low Voltage Ride Through Figure (b)- High Voltage Ride Through (c) note -because these incidents do not relate to the same type of event it is not intended that power producers plant will cope with both low voltage and high voltage ride through contemporaneously. 128 Statutory Instruments 9th January, 2026 A.9 Active and Reactive Power during a Low Voltage Fault - Generating Units Connected to the IPS (a) the priority for generating units connected to the IPS is to continue to supply active power. Active power during a low voltage ride through event should be delivered at least in proportion to retained voltage and delivery of reactive power is required up to the remaining emergency capacity of the device. The following refers to the remaining capacity of the generating unit; (b) during a voltage transient, a synchronous generating unit connected to the IPS should perform according to the capability chart contained within the connection agreement; (c) the provision of the additional reactive power shall continue until the voltage recovers stably to within the normal operational range; (d) (e) irrespective of the normal reactive power control mode selected, during the voltage transient, an asynchronous generating unit connected to the IPS should immediately be in voltage control mode and inject or absorb reactive power to attempt to restore the voltage at the point of connection. the reactive current response shall be supplied within the rating of the asynchronous generating unit with a rise time no greater than 100ms and a settling time no greater than 300ms. An asynchronous generating unit may provide this reactive current response directly from a generating unit, or other additionally installed dynamic reactive devices on the site, or a combination of both. 9th January, 2026 Statutory Instruments 129 A.10 Post Low Voltage Fault Recovery – Wind Powered Generating Units e”2MW connected to the IPS (a) (b) after fault clearance of a fault causing low voltage on the local system an asynchronous generating unit e” 2MW connected to the IPS, which has remained connected, for voltage dips longer than 250ms (transmission fault total clearance time) shall provide at least 90% of its maximum available active power within 1 second of the voltage at the point of connection recovering to the normal operating range; if the fault is cleared within 250ms an asynchronous generating unit shall provide at least 90% of its maximum available active power as quickly as the technology allows and in any event within 500ms of the voltage at the point of connection recovering to the normal operating range, as specified within the connection agreement for the particular site; (c) asynchronous generating units with a registered capacity of 2MW shall not consume on average more reactive power in the 10 seconds following a disturbance on the transmission system than they did on average in the 10 minutes before the occurrence of the disturbance. where an asynchronous generating unit is supporting the system voltage through reactive power export, it shall not draw reactive power during or immediately following the disturbance; and ≥ (d) the SO may require a reduction in the magnitude of the dynamic reactive response of the asynchronous generating unit if it is found to cause over-voltages on the transmission system. In such a case, the DNSP or SO will make a formal request to the power producer. The power producer and the DNSP or SO shall seek to agree on the required changes, and the power producer shall formally confirm that any requested changes have been implemented within 120 days of receiving the formal request from the SO. A.11 Voltage Performance The output of generating units connected to the transmission system shall not be affected by voltage changes at the point of connection within the normal range as stated in the connection agreement. Outside this range when voltage is falling, the output shall not fall at a greater rate than the voltage. At 0.9 per unit of nominal voltage the generating unit may trip to protect itself. A.12 Principles of Voltage Control (a) directly connected generating units approved for connection connected to the transmission system must be capable of supplying registered capacity in MW at any point between the limits of reactive power set down in the synchronous and asynchronous performance tables; (b) directly connected generating units shall additionally be equipped to vary their reactive power to assist in controlling voltage at the generator terminals or local to the power producer’s facility, but nothing shall compel a power producer to operate beyond the equipment rating or stability limits set down in the relevant connection agreement; (c) where the directly connected generating unit is to be operated on a fixed power factor or a reactive power order, this will be the subject of a dispatch instruction issued by the SO; (d) (e) further reactive power control requirements for asynchronous generating units of all sizes are set down in the performance table for asynchronous generating units; further reactive power control requirements for synchronous generating units having a registered capacity greater than 2MW are set down in a performance table for synchronous generating units; and 130 Statutory Instruments 9th January, 2026 (f) for directly connected generating units, dispatch instructions related to reactive power must be fully enacted within 30 secs except where the instruction requires tapping of a transformer or a matter requiring human action. A.13 Additional Protection Requirements for Generating Units (a) (b) (c) (d) (e) the TNSP will identify, at the time of forming the proposal, any generation or facility failure modes likely to threaten transmission system stability and the power producer shall demonstrate in the protection philosophy statement how the failures have been guarded against or the consequences mitigated. The size, type and location of plant on the transmission system are material factors in determining the effects of failure on transmission system stability; the settings of all the protection tripping functions on the generating unit protection system of a generating unit, deemed by the SO relevant to IPS performance shall be agreed with each power producer in writing, and shall be co-ordinated with the transmission protection settings. The settings shall be documented and maintained by the power producer, with the reference copy, which reflects the actual plant status and settings at all times, held by the TNSP; a generating unit, generating unit step-up transformer, generating unit auxiliary transformer, associated busbar ducts and switchgear shall be equipped with protection functions, maintained in line with international best practices, to rapidly disconnect appropriate plant sections should a fault occur within the relevant protection zones which fault may reflect into the transmission system; every power producer’s installation shall as a minimum be equipped with over- current and earth fault protection to trip the generating unit in the event of a fault; if the power production facility cannot withstand the acceleration that will occur following a reclose, it is required that the power production facility be equipped with a no-volts relay that trips the facility off during the reclose dead time; (f) the following protection systems shall as a minimum be applied by all power producers: (i) Main Protection This protection shall be installed in the HV substation yard or in the generating unit protection panels. If this protection is installed in the generating unit protection panels the DC supply for this protection and that used for control circuits shall be at least separately fused. (ii) unit switch to Standstill Grid Protection (achieved with Controls) Protection that guards against the inadvertent energization (by closing of a CB for example) of a unit at standstill, through the implementation of elaborate interlock arrangements in the control circuits and logics. (iii) Main Unit Protection This included protection such as differential schemes or stator earth fault schemes. For the avoidance of doubt, a main protection scheme with self- monitoring precludes the requirement for separate main and back-up protection schemes. (iv) Backup Impedance An impedance facility with a large reach shall be used. This shall operate for phase faults in the generating unit, in the HV substation yard or in the adjacent transmission lines, with a suitable delay, for cases when the corresponding main protection fails to operate. The impedance facility shall have fuse fail interlocking. 9th January, 2026 Statutory Instruments 131 (v) User’s generator transformer HV backup earth fault and REF This shall be an IDMT facility that shall monitor the current in the generating unit transformer neutral. (vi) HV Breaker Fail Protection The “breaker fail” protection shall monitor the HV circuit breaker’s operation for protection trip signals, fault conditions. (vii) HV Breaker Pole Discrepancy for circuit breakers with independent poles This protection detects the failure of delay in interrupting or closing one or two of the phases of a circuit and instructs a back-up interruption mechanism. (viii) Loss of mains Protection This is required unless the generating unit is of sufficient size and equipped not to require it. Loss of mains Protection settings will be specified for — (aa) over voltage; (bb) under voltage; (cc) over frequency; ZS387 – 51.25Hz; (dd) under frequency; ZS387 – 48.75Hz; and (ee) Rate of change of frequency (RoCoF), or other acceptable means, either within this Code or in connection agreements. (g) (h) (i) (j) (k) these protection elements may be applied to detect and trip the generating unit for other frequency and voltage events on the IPS; under and over voltage protection must monitor all three phases at the point of connection. This protection is set to ensure the generating system is disconnected from the transmission system when the voltage varies outside predetermined values; the under and over voltage protection shall be at least a two staged protection scheme, incorporating short term (less than 1 second) and long term (10 minute) voltage measurements; the difficult issue is to achieve selectivity for RoCoF to detect a network issue and disconnect the generating unit whilst ensuring that the generating unit remains connected for a sudden loss of infeed or load on the IPS. The power producer and the TNSP should agree the setting; as stated in the protection philosophy statement, any other matter required by the TNSP or SO, shall be determined in consultation with the user, and any resulting equipment is to be provided and maintained by the relevant user at its own cost. A.14 Additional Power Quality and Relioability Requirements the power producer must ensure that its generating unit’s contribution to the negative sequence voltage at the point of connection is less than 1% unless otherwise stated in the connection agreement or other form of agreement. 132 Statutory Instruments 9th January, 2026 A.15 Islanding (a) it is conceivable that a part of the transmission system, to which a generating unit is connected may, during emergency or planned outage conditions, become detached from the IPS. Unless, in the reasonable opinion of the SO (or DNSP in the case of embedded generating units) , a power producer’s plant shall remain connected and continuously control voltage and frequency within the limits set down in this Code , it must detect any condition whereby it is isolated from the IPS and cease to supply energy to customers (other than itself) within 500ms. for the avoidance of doubt, unless within an area stablished by adequate levels of synchronous generation, asynchronous generating units must trip within 500ms of becoming islanded; (b) (c) the generation facility shall be equipped with dead-line detection protection system to prevent the generator from being connected to a de-energized part of the transmission system; a procedure shall be set out and agreed between the TNSP and each power producer for return to service. In the case of automatic resynchronization, the procedure may include a standing dispatch instruction. in all other cases, a specific dispatch instruction shall be issued by the TNSP; (d) the SO shall be responsible in the resynchronization of the island grids after the black start procedure or after a significant incident has resulted in island grid operation; (e) during island grid operation, all synchronously connected generating units will be required to provide ancillary services as follows: (i) frequency regulating reserve for frequency control of the island grid; and (ii) voltage management in the absence of reactive power from the IPS. (f) asynchronously connected generating units adequately stabilised by sufficient synchronous generation may continue to operate and may be selected for modes which assist in the control of frequency and voltage local to the generating units. A.16 Facility for independent Power Producer action Frequency control under system islanding conditions shall revert to nominated synchronous power producers who shall liaise with other local (within the island) synchronous and asynchronous power producers to control the voltage and frequency within the island. The required frequency control range is 49.85Hz to 50.15Hz. Emergencies within the island will be subject to the same frequency limits as the IPS. A.17 Emergency Generating Unit Capabilities Power producers shall specify their generating units’ capabilities for providing emergency support under abnormal power system conditions, as detailed in the System Operation Chapter. A.18 Communication (a) a power producer shall ensure that it complies, in respect of each generating unit within its facility, with a list of signals as set down by the TNSP, and referred to in the connection agreement, which details the destination and format of signals required to enable information and normal and emergency control of the generating unit. All generating units with a registered capacity 2MW agreed for connection to the IPS shall provide real-time information to the SO regarding plant status, active power, reactive power or voltage at the point of connection and net energy produced over a defined period; ≥ 9th January, 2026 Statutory Instruments 133 (b) (c) the SO will have the right to test performance of these signals and the SO may withhold a temporary compliance certificate or final compliance certificate or replace a final compliance certificate with a limited performance certificate until such time as the problem has been rectified and the communication is proven to work; a Participant empowered to issue and receive signals from users is required to have proper regard for the security of the transmission system (including the SO control function) and the distribution system from cyber threats and all control centres, the SO, TNSPs and users of the transmission and distribution system are required to cooperate to the fullest extent in establishing and maintaining procedures and practices aimed at reducing such cyber-attack risks to any Participant; A.19 Generating Plant Commissioning Tests and Compliance Certification (a) where the generating unit requires connection to the transmission system in advance of the commissioning date, for the purposes of testing, the power producer shall comply with the requirements of the connection agreement; (b) (c) (d) (e) (f) (g) (h) a power producer shall submit to the SO a commissioning programme and prior to every test a detailed test procedure emphasizing system impact. The programme and procedures shall be approved by the SO; a power producer shall, as a minimum, confirm that at least interface protection (as described in the protection philosophy document) and preferably the main generating unit protection has been proven to function as designed; commissioning testing proves for the user that the plant supplied and installed is functioning as agreed, but in addition certain tests may be required by the SO to prove compliance with this Code; a TNSP has a right to witness these compliance tests and shall advise in a timely manner if it is the intention to do so. In any case, the results of compliance tests shall be supplied to the TNSP in an agreed format; a power producer shall keep records relating to the compliance by each of its generating units with each provision of this Code applicable to that generating unit, setting out such information that the SO reasonably requires for assessing power system performance (including actual generating unit performance during abnormal conditions); a power producer shall review, and confirm to the SO, compliance by each of that power producer’s generating units with every requiremrnt of this Code as specified in Appendix 1 and further explain in the TNSP’s connection information guide; a power producer shall conduct tests or studies to demonstrate that each power production facility and each generating unit complies with each of the requirements of this Code. Tests shall be carried out on new generating units, and after every outage where the integrity of any TGCR may have been compromised, to demonstrate the compliance of the generating unit with the relevant TGCR; (i) a power producer shall continuously monitor its compliance in all material respects with all the connection conditions of this Code; (j) if a power producer determines, from tests or otherwise, that one of its generating units or power production facilities is not complying with any material respect of one or more sections of this Code, then the power producer shall — (i) promptly notify the SO of that fact; 134 Statutory Instruments 9th January, 2026 (ii) promptly advise the SO of the remedial steps it proposes to take to ensure that the relevant generating unit or power production facility, as the case may be, can comply with this Code and the proposed timetable for implementing those steps; (iii) diligently take such remedial action as will ensure that the relevant generating unit or power production facility, as the case may be, can comply with this Code. The power producer shall regularly report in writing to the SO on its progress in implementing the remedial action; and (iv) after taking remedial action as described above, demonstrate to the reasonable satisfaction of the SO that the relevant generating unit or power production facility, as the case may be, is then complying with this Code; (k) where some functions cannot be proven until the generating unit is energised but the generating unit is considered safe to energise an energisation certificate is issued. This is the authority to energise the power producer’s facility or additional equipment as specified; (l) where a test fails to meet the requirements of this Code, the SO may refuse connection or may issue a temporary compliance certificate valid for a time to allow the matter to be rectified whilst the generating unit is permitted to be commercially operational. Alternatively, the SO may issue a limited performance certificate restricting the generating unit in some way; (m) (n) if all commissioning tests have been completed (and witnessed as required by DNSP or SO) and the results show that the plant complies, the SO will then issue a final compliance certificate; if there are tests which cannot be done (like fault-ride-through) because they require real system events, but the plant is otherwise compliant, the SO will issue a temporary compliance certificate; (o) when real events prove compliance, or if no appropriate transmission system conditions occur within 12 months, the SO will issue a final compliance certificate; (p) if during its lifetime the plant ceases to meet some compliance requirement, the final compliance certificate may be withdrawn and a limited compliance certificate issued until the matter is rectified. This applies to a main plant performance issue or a SCADA and communication issue. plant output may be restricted under a limited compliance certificate; (q) the SO may, if at any time, the SO believes that a generating unit or power production facility is not complying with this Code — (i) (ii) notify the relevant power producer of such non-compliance specifying the provision of this Code concerned and the basis for the SO’s belief; or issue an instruction requiring a power producer to carry out a test to demonstrate that the relevant power production facility complies with the requirements of this Code; 9th January, 2025 Statutory Instruments 135 (r) (s) a power producer shall not refuse the instruction issued in accotdance with paragraph (q) (ii), unless it is not issued timeously and there are no reasonable grounds for suspecting non-compliance; if the relevant power producer believes that the generating unit or power production facility, as the case may be, is complying with this Code, then the SO and the power producer shall promptly meet to resolve their difference. A.20 Return to service of mothballed Plant Once the customer has decided to return mothballed generating plant to service, the TNSP requires the information specified for new connections. A.21 Generating Plant Decommissioning (a) decommissioning of plant is the permanent withdrawal from service of generating plant. (b) the TNSP and SO require the following with a one-year notice period: Power Producer name Power Production Facility name Unit number or description Date to be removed from commercial service Details of any Auxiliary supplies required for dismantling and demolition kVA and the point at which supply is required and the duration Details of special safety precautions for TNSP personnel on the site

1.2.9 Synchronous Generating Units Performance Schedule for Generating Units Connecting to the IPS 136 Statutory Instruments 9th January, 2026 A.1 Generating Unit and Facility Data (a) (b) adequate data provided for in this Code shall be provided to the SO, to allow the SO to assess the behaviour of the plant and the transmission system with respect to load flows, fault levels and transient or dynamic stability and to assess compliance of generating units with the requirements of this Code; the following table summarises the performance requirements for all synchronous generating units additional to the technical requirements placed on all generating units. Code Requirement All Synchronous GU TGCR1 Grid Protection <20MW 20-100MW >100MW Main Grid Protection (with self-monitoring system) or main and backup ). This is main winding protection needed for all Generating Units. Depends on System Requirements Main and Backup-Protection (with self- monitoring system or monitoring system) This relates to certain elements further specified in

2.1.13.5 below. Some elements may not be required for smaller Generating Units. Yes Yes Reverse Power Generating Unit s witch to standby Yes Yes Yes Yes Generating Unit s witch to standstill protection Yes Yes Automatic Excitation Control System TGCR5 Black Start ing TGRC6 Emergency Generating Unit capabilities Yes Yes Yes Yes Yes Yes TGCR7 Independent action for control in System Island Yes Yes Yes Yes Yes Yes No Yes Yes (c) additionally, limiters (pressure, temperature and speed) under the TGCR2 requirement applies to all sizes of synchronous generating units except hydro generating units. A.2 Active Power Capability and Control (a) the frequency requirements and behaviour of turbo generators will be set out in the dynamic study and the basic requirements are as set out in this Code. A.2.1 Additional High Frequency > 50.15Hz Requirements for Turbo-alternator and Hydro- alternator Generating Units 50MW ≥ The generating units will be equipped with over frequency set at a value of 52.5Hz or above, which value shall be advised to the SO. 9th January, 2026 Statutory Instruments 137 A.2.2 Additional Low Frequency Requirements for Turbo- alternator and Hydro-alternator Generating Units 50MW ≥ If the transimission Frequency falls below 47.5Hz for more than I second, independent action may be taken by a power producer to protect the generating unit. Such action includes ability to island the generation with a suitably sized load block and and to independently manage voltage and frequency and provide sufficient fault level to ensure protection operation within the island position. A.3 Reactive Power Capability and Control for Synchronous Generating Units having a Registered Capacity greater than 2MW (a) (b) all new directly connected synchronous generating units shall be capable of supplying registered capacity in MW at any point between the limits 0.85 power factor lagging and 0.95 power factor leading at the generating unit terminals. reactive output shall be fully variable between these limits under AVR, manual or other control; a directly connected synchronous generating unit shall be equipped with a high-speed response excitation control system with an automatic, continuously and fast-acting AVR, targeted at controlling the synchronous generating unit terminal voltage. The objective of this control system shall be to provide selectable constant terminal voltage control of the generating unit, without instability, over the entire operating range of output up to registered capacity of the generating unit as indicated in the capability chart supplied as part of generator planning data in Appendix 3. Testing required is shown in Appendix 1. (Note that this does not include the possible influence of a power system stabilizer.) Testing processes and results presentation are further explained in each TNSP’s testing and compliance manual. Excitation systems shall comply with the requirements specified in IEC 60034; (c) routine and prototype response tests shall be carried out to demonstrate reactive capabilities as indicated in Appendix 1; (d) the excitation control system shall be equipped with an under-excitation limiter, load angle limiter and flux limiter as described in IEC60034-16-1; (e) the SO will advise on the requirement for over excitation limiters which shall, if required, form a connection agreement condition; (f) the excitation system shall have a minimum excitation ceiling limit of 1.6 per unit rotor current, where 1per unit is the rotor current required to operate the generating unit at rated load and at rated power factor; (g) The settings of the excitation system shall be agreed between the SO and each power producer, and shall be documented, with the master copy held by the SO. The power producer shall control all other copies. The procedure for this is set out in Appendix 1; (h) power system stabilizers as described in IEC 60034-16-J are a requirement for all new generating units connected to the transmission system, and for existing generating units retrofitting may be required depending on IPS requirements. The SO may require power system stabilizers for larger embedded generating units or facilities; (i) the requirements for other excitation control facilities and AVR refurbishment shall be determined in conjunction with the SO; (j) power producers shall not disable this automatic voltage control mode without prior approval of the SO; (k) routine and prototype response tests shall be carried out on excitation systems as indicated in Appendix 1, and in accordance with IEC60034-J6-3; 138 Statutory Instruments 9th January, 2026 A.4 Power System Stabiliser (a) (b) power system stabilizers as described in IEC60034-16-J are a requirement for new generating units installed on the transmission system after 30th August 2013 and all generating units e 20MW installed on the IPS approved for connection to the IPS; after the first revision of the Code, and for existing generating units retrofitting may be required depending on IPS requirements. The requirements for other excitation facilities and AVR refurbishment shall be determined in conjunction with the SO; A.5 Additional Protection Requirements for Synchronous Generating Units (a) (b) synchronous generating units shall have protection designed to trip the generating unit in the event of power flowing from the grid transmission system into the generator under any condition except when start-up supplies or for auxiliary supplies when the generating unit is not on line; protection supplies for main protection and other protection types shall be separately supplied either via fuses or MCBs. The IPS shall be protected with the following functions: (i) Stator Winding Protection All generating units shall have a suitable main protection scheme to afford instantaneous unit protection to the generator winding. This may be differential protection or stator earth fault (95% and 100%) or a combination of both. (ii) Voltage Protection Generating units shall have over-voltage and under-voltage backup-protection implemented, suitably coordinated with any such schemes implemented on the grid. (iii) Frequency Protection Generating units shall have over-frequency and under-frequency backup- protection implemented, suitably coordinated with any such schemes implemented on the grid to safe guard against operating the generating unit outside its determined limits but to not deprive the transmission system of generation during transmission system disturbances characterized by frequency excursions. (iv) Over Speed generating units shall have overspeed backup-protection implemented, to complement any such mechanical protection arrangements. (v) Negative Phase Sequence Generating units shall have negative-phase-sequence backup-protection implemented, to safe guard against the heating effects of unbalanced loading, suitably coordinated with any such schemes implemented on the grid. (vi) Over Current Generating units shall have a current based overcurrent backup-protection implemented (enhanced with voltage control for units >100MW), and suitably coordinated with grid back up protection schemes. 9th January, 2026 Statutory Instruments 139 (vii) Loss of Field Synchronous generating units shall be fitted with loss of field facility that matches the transmission system requirements. the power producer shall agree with the SO the type of facility to be implemented. (viii) Generating Unit Switch onto Standstill Protection This protection shall be installed in the HV yard substation or in the generating unit protection panels. If this protection is installed in the generating unit protection panels then the DC supply for this protection and that used for the circuit-breaker closing circuit shall be the same. (ix) Reverse Power This protection shall be installed in the HV yard substation or in the generating unit protection panels. If this protection is installed in the generating unit protection panels then the DC supply for this protection and that used for the circuit-breaker closing circuit shall be the same; (c) for larger generating units with solid connections between the prime mover and the generator, the SO may require pole-slipping protection to avoid damage or disturbance on the IPS; (d) the TNSP shall specify in the connection agreement any requirement for other protection designed to avoid damage or instability of the IPS. A.6 Synchronisation (a) (b) the power producer shall be responsible for synchronising the generating facility to the IPS within pre-agreed settings. a synchronous generating unit which may be operated in parallel with the IPS and approved to be installed after the first revision of the Code shall be equipped with an automatic synchronising facility. Only synchronous generating units with an automatic synchronising facility may have on-going permission to re-synchronise with the IPS after a system outage. (c) the automatic synchronising facility shall consist of a synchronising relay and a check relay. The settings on these relays shall be agreed with the DNSP or the SO as appropriate to ensure that they do not adversely affect the operation of the IPS. (d) existing synchronous generating units which do not comply need to have special procedures agreed with the DNSP or the SO as appropriate. A.7 Short-Circuit Contribution (a) (b) it is preferable that in the case of single-phase to earth faults, the short-circuit current contribution of a synchronous generating unit shall not exceed the short-circuit current in each phase occurring during a solid three-phase fault. This is to ensure that equipment ratings are not exceeded; in the event that calculation by a power producer shows that the single-phase to earth fault-current will be higher than the phase currents during a 3-phase fault, the power producer must draw the matter to the attention of the TNSP who will assess the situation on a case-by-case basis and advise the power producer. In the event that the TNSP’s assessment still shows that action is needed by the Power Producer, it will be the power producer’s responsibility to provide a technically sound solution in line with prudent utility practice; 140 Statutory Instruments 9th January, 2026 (c) for three-phase synchronous generating units, the single-phase short-circuit current shall not be below 60% of the 3-phase short-circuit current in order to facilitate protection selectivity; A.8 Black Start Capability (a) (b) (c) power producers with directly connected synchronous generating units shall notify the SO if their generating plant has a restart capability without connection to an external power supply; power production facilities that have declared that they have a station black start capability shall demonstrate this facility by test as described in Appendix 1; black start capable power production facilities may be called from time to time to carry out a black star as described in Appendix 1.

1.2.10 Asynchronous Generating Units Performance Table (a) paragraph 1.2.10 refers to asynchronous generating units e”2MW connected to the IPS and includes battery energy storage devices when exporting electrical energy to the IPS. (b) subject to the other provisions of this Code, the following table summarises the requirements placed on asynchronous generating units: Grid Code Requirement All Asynchronous GU <20MW 20-100MW >100MW TGCR3 Reactive Power Capability & Control Yes yes Yes TGCR4 Post Fault Output recovery Yes Yes Yes Fault level contribution Depends upon System Conditions A.1 Standards and Inverters (a) inverters shall be designed in accordance with the relevant national standards or IEC standards. Other standards may be acceptable but require the express agreement of the SO; (b) the DC content of the output current of the inverter at the AC terminals shall not exceed 0.5% of its rated output 50Hz nominal current; (c) each inverter must disconnect within 3 seconds when the average voltage for a 10- minute period exceeds the maximum nominal operating voltage; 9th January, 2026 Statutory Instruments 141 (d) where multiple single-phase inverters are connected to more than one phase, the inverters must be interlocked and configured to behave as an integrated multiphase inverter providing a reasonably balanced output to all connected phases at all times whilst connected to the transmission system. Alternatively, where inverters cannot be interlocked by internal controls, the installation must be protected by a phase balance relay which must immediately isolate the Inverter in the absence of reasonable balance; (e) the inverters must be physically prevented from operating independently and all installed inverters must simultaneously disconnect from, or connect to, the transmission system in response to protection or automatic controls (e.g. anti- islanding trip and subsequent reconnection). A.2 Additional Information Requirement (a) (b) (c) for asynchronous generating units (including energy storage generating units 2MW) connected to the IPS additional information is required to assess the dynamic response of the devices. Such information is to be in the form of a block diagram model with all parameters and also assembled and compiled into an RMS model in a format requested by the SO and specified in the TNSP’s connection information guide; ≥ the model shall be adequate to show the transient behaviour of devices including the device protection functions so as to determine whether the device will ride through faults and voltage transients and how the device will respond and comply with the requirements of this Code. The time step of the model shall be specified in the connection information guide; for asynchronous generating units (including energy storage generating units <2MW) seeking connection to the IPS, additional information may be required by the SO and if required it shall be a condition of forming a connection agreement that such information is provided. A.3 Active Power Capability and Control Asynchronous generating units shall, following a low voltage ride through event and after a settling period, resume normal production not later than 5 sec after the operating conditions at the point of connection have reverted to the normal operating conditions. A.4 Reactive Power capability for Asynchronous Generating Units having a Registered Capacity 2MW and Connected to the IPS ≥ (a) asynchronous generating units with registered capacity e” 2MW and approved for connection to the transmission system shall comply with the following requirements: (i) required reactive power at full output; (ii) each asynchronous generating unit with registered capacity e”2MW, shall be capable of absorbing or supplying reactive power output at the point of connection and within the range Q= -0.33per unit, +0.33per unit of registered capacity (0.95pf). This requirement applies when the level of output is above 20% of registered capacity, unless an alternative value of active power threshold is agreed upon by the SO in the connection agreement; and 142 Statutory Instruments 9th January, 2026 (iii) the required reactive power performance is control mode dependent as shown in Figure 2.1.14.4(a) which also shows the required performance when the level of active power output is below 20%. 9th January, 2026 Statutory Instruments 143 (b) the Figure belows shows - Minimum Reactive Power requirements for Asynchronous Generating Units 2MW depending on the selected control; ≥ (c) deviation from these ranges due to voltage deviation is accepted on the basis set down in the Figure below. This figure is hatched to show the not required area. (d) the above Figure shows -Per Generating Unit Reactive Power at the Point of Connection based upon 1per unit Active Power rating (shading shows where performance is required) A.5 Reactive Power Control Asynchronous generating units 2MW shall be equipped with a voltage regulator with the capability of operating continuously while targeting a voltage between 0.90 per unit and 1.10 per unit of the rated generator voltage at the point of connection from no-load to full-load. ≥ A.6 Modes of control (a) (b) different target objectives are needed to assist in achieving stable voltage control on the transmission system; each asynchronous generating unit with a registered capacity greater than 2MW shall be equipped to automatically control its reactive power during normal operation according to a control mode and settings advised from time to time by the SO. The initial control mode and settings will be provided in the connection agreement. each asynchronous generating unit shall be capable of the following control modes: (i) voltage control mode; (ii) reactive power control mode; and (iii) power factor control mode. 144 Statutory Instruments 9th January, 2026 (c) the control modes reactive power, power factor and voltage control are mutually exclusive, which means that only one of the three functions can be activated at a time. Unless excused by the SO the setting should be controlled remotely by SCADA. For directly connected asynchronous generating units, the target must always be settable remotely. A.6.1 Accuracy of control (a) (b) the voltage control mode shall be targeted to maintain the steady state voltage to a set- point value measured at the point of connection. If the set point voltage cannot be achieved, the control should target the maximum generation or absorption of reactive power as appropriate; the control tolerance to be achieved is ± 0.5% of the nominal voltage. The generating unit shall achieve the targeted quantity or in the case of being in voltage control mode the targeted quantity or maximum input or output of reactive power within 30 secs. A.6.2 Managing over Voltage (a) in the event that voltage exceeds the normal range and where reactive power or power factor control mode are employed, the generating unit must switch as an emergency to voltage control mode and target its reactive power capability to return the voltage to within the normal range. The control mode requirement is shown in the Figure below showing -Deployment of modes of Reactive Power control for Asynchronous Generating Units. The settings will be specified in the Connection Agreement. (b) in the event that the above emergency action by the generating unit cannot achieve a voltage within a specified limited time, the generating unit must trip as shown in Figure above. The over-voltage trip should conform to the requirements set out under this Code. It is possible to combine the reactive power control action with an active power control action to maximise the opportunity for the asynchronous generating unit to remain connected. Such complex control actions are to be agreed with the SO. A.6.3 Return to Service and Normal Control When the voltage has been stabilised to within the normal range for 10 minutes continuously, the generating unit shall revert to the normal control mode as previously instructed by the SO. 9th January, 2026 Statutory Instruments 145 A.7 Short-Circuit Contribution Asynchronousgenerating units (including inverters) above 2MW may be required to make a contribution to fault-level in order to ensure the proper operation of transmission systemprotection. The minimum contribution will be specified in the connection agreement as a current and phase-angle to the system voltage which maybe on a sliding scale with retained system voltage. A.8 Black Start Capability Asynchronousgenerating unitswill not be required to provide black start capability and will not be used as part of any black start plan until a stable synchronous system or part thereof has been established.

1.2 Transmission System Planning, Design And Development

1.3.1 Connecting Users And Connection Studies (a) The TNSP shall— (i) on payment of a fee approved by the Energy Regulation Board, provide information relating to the connection or modification of an existing connection to the transimission system to a person who requests for that information; (ii) carry out sufficient studies and investigations to ensure that a new or modified connection to the transmission systemshall not cause violation of the security of the transmission system and planning standards or create instability to the transmission system and distribution system under planned contingency conditions; (iii) determine the safe and efficient method to connect a user or modify a user’s existing connection to the transimission system, having regard to the Power Quality and Reliability Standards (ZS387), unless the connection or modification studies and investigations determine that the connection or mofification of the user’s facilitywould not be possible; (iv) use reasonable efforts to complete the assessment of an application to connect or modify an existing connection to the terms of a connection agreement, within the time period specified in the TNSP’s customer connection information guide including performing any studies and connection costing; (v) make a proposalto a user who intends to connect or modify an existing connection to the transmission system, showing — (aa) the work that shall be required to be carried out; (bb) the connection charge, which shall be in line with the connectionfee approved by Energy Regulation Board; and (cc) any other matters relevant to the connection set out in this Code; and (vi) provide a power producer with any information necessary for the power producer to properly design the connection or modification of an existing connection to the transmission system, and where an embedded generating unit is to be subject to central dispatch advise the embedded power producer of the provisions of this Code which that power producer should comply with. 146 Statutory Instruments 9th January, 2026 (a) The SO and TNSP shall perform the duties of the SO and TNSP set out under a connection agreement and — (i) make reasonable endeavours to perfom the duties within the time frames agreed upon with the user; and (ii)in the case of a TNSP, the duties includethe construction of extensions or upgrades to thetransmission system. Voltage level Compatibility level V  88000  88000 %  10  5 NOTE — In the absence of any agreement to the contrary, the supply voltage shall not deviate from the compatibility level for any period longer than 10 consecutive minutes.

1.3.2 Planning Standards -Criteria to be Applied when carrying out Connection and Modification Transmission System Studies (a) the SO and TNSP shall ensure that the transmission system meeting the n- 1 orn-2 contingency criterion,comply with all relevant limits set out in Figure below and the applicable electric current limits, under all credible transimission system conditions. Technical Voltage Limits A.1 Technical and voltage limitsandtargetsforplanningpurposes (a)The SO and TNSP shall ensure that the limits and targetsagainst which the existing transmission system performance and proposed options are checked include— (i) the technicallimits and voltage limitsset out in the Figure above; and (ii) any othertargetsforplanningpurposes. A.2 Generation connectionand modification loadflow studies (a) A power producer shall undertake generation connection and modification loadflow studies to assess whether the generation dispatch maximises the loading of generating units electrically close to the proposed generating unit, except that the generating units that shall be dispatchedand other parts of the transmission system shall be operated at or above the minimum generation levels to ensure that transimision system voltage and other stability factors are maintained. (b) A power producer shall maintain a transientstability aftera successfullyclearedsingle-phase to earth faultor a three-phase bolted fault. 9th January, 2026 Statutory Instruments 147 A.3 Designing Generation Connection Arrangements (a) the SO and TNSP shall when planning the integration of a power production facility of less than1000MW, assess the strategic importance of the power production facility before designing a connection or modification to an existing connection to the transmission system. (b) the SO and TNSP shall consider the following when assessing the strategic importance of a power production facility: (i) the reliability of the generated output based on the nature of the technology and the continuity of the energy source; (ii) the planned operating regime of the power production facility; (iii) the number and independence of generating units within the power production facility; (iv) the impact on reliability of the IPS of loss of all or part of the power production facility, havingregard to the amount of response available to cover outages with a normal loss risk; and (v) the dependence of the transmission system or local supply area on the power production facility’s contribution to voltage and other ancillary services. (c) The SO and TNSP shall ensure that— (i) all connecting circuits to thepower production facility that is connected to the transmission system are healthy; (ii) it is possible to transmit the total registered capacity output of the power production facility to the transimission system for any transimission system load condition; (iii) for powerproduction facilitiesof strategic importance, the outage of a transmission systemcircuit, orcomponent with a normal loss risk, should not result in the loss of generation output which would cause a violation of the security standard for end-usecustomers; and (iv) for power production facilitiesgreater or equal to 1000MW,there shallnot be loss of output resulting from contingencieson the IPS to apply to either the connection or transmission system. (d)The SO and TNSP shallin assessing the strategic importance of the power production facilityand designing a connection or modification to an existing connection to the transmission system— (i) have regard to prudent utilitypractice and historical records to determine the unplanned outage risk for— (aa) components of the transmission system; and (bb) incidentsaffecting theIPS; and (ii) classify component loss and incidents by risk category of a minimum “normal loss risk” and “infrequent loss risk”. (e) the SO and TNSP shall ensure that the transmission system design should be such that end-use customers do not experience outage as a result of secured normal loss risk incidents. 148 Statutory Instruments 9th January, 2026 (f) despite paragraph (e), some loss of end-use customer demand is acceptable for infrequent loss risk incidents. (g) the SO shall have regard to the impact of infrequent loss risk incidents on International Interconnector flows and SAPP agreements or any other regional agreements. (h) the SO and TNSP shall, where only asinglecircuit isused to connect a power production facilityof strategic importance to the transmission system, ensure that the circuit is able to be selected to alternative bus-bar sor is able to go onto by pass at each end of the circuit. (i) The SO and TNSP shall, where alocalarea depends on the power production facilityforvoltage support and provided the power production facilityis of strategic importance,ensure that the connectionwith the transmission system shall be secured by a minimum of two lines. (j) The cost of the additional lines and plant shall be a user cost and not a transimision system cost, where additional circuits or equipment is valuable in the case of a power production facility that is not of strategic importance. A.4 ForecastingtheDemand (a) The SO and TNSP shall — (i) be responsible for producing the transmission system demand forecast for every fifteen years; and (ii) update the actual transmission system demand against the transmission system demand forecast referred to under paragraph (i), annually. (b) subject to paragraph (a)(i), the SO and TNSP shall determine the transmission system demand forecast referred to under paragraph (a)(i)for each point of supply. (c) the SO shall forecast the maximum demand in MW for each transmission sub- station and there sult shall be reconciled with data from Participants. (d) a DNSP and end-use customer shal lannually,by endof October,supply the DNPS’s 15-year-ahead load forecast data to the SO in accordance with the Information Exchange Chapter and Form I set ot in Appendix 4. A.5 Reliabilitycriteria forplanningpurposes A TNSP shall formulate long-term plans for expanding or strengthening the transmission system on the basis of just if i ablere dundancy. A.6 Load growth studies (a) the SO shall, in collaboration with relevant Participants, when developing load growth studies take into accountcontingencies undervarious loading conditions. (b) the SO shall in undertaking the studies referred to under paragraph (a), take into consideration the appropriategenerating plant to meetthe load and provide spinning reserve. (c) the contingencies referred to under paragraph (a) shall— (i) in the case of more probable transmission system, n-1 (n is greater than 1 and is a natural number) contingency, assume the most unfavourable generation pattern within these limitations; and 9th January, 2026 Statutory Instruments 149 (ii) in the case of the less probable transmission system, n-2 contingency, use average figures. A.7 Transient stability studies (a) the SO shall, in collaboration with the relevant Participants, when undertaking transient stabilitystudies ensure that there is a reasonable margin to maintain stabilityfor a given initial operating condition so as to regain a state of operating equilibrium. (b) the SO shall retain transient stability for the following conditions: (i) a three-phase ,line or bus barfault,clearedinnormal protection times, with the transmission system healthy and the mostonerous power production facility loading condition; (ii)asingle-phase fault, clear edin”bustrip”times,with the transmission system healthy and the most on erouspower production facility loading condition;or (iii) a single-phase fault,clear edin normal protection times,with anyone line out of service and the power production facility loaded to average availability. A.8 Equipment Performance Assumptions A.8.1 TransmissionLines (a) a Participant shall ensure that thermal ratingsof standard transmission lines and cables are determined and updated from time totime. (b) the thermal ratings refered to under paragraph (a) shall be used as an initial check of line overloading. (c) a Participant shall, where thermal ratings limitsareclose to being exceeded, investigatethe situation as may be possoble to defer strengthening depending on the actual line design or assessed capacity andonlocalconditions. A.8.2 Transformers (a) a Participant shall ensure that standard transformer ratings are determined and updated fromtime totime using IEC specifications or any other equivalent or relevant standards. (b) a Participant shall, where the target loads areexceeded, assess the specific situation asmay be possible to defer adding extra transformers. A.8.3 SeriesCapacitors (a) the maximum steady-state current shall not exceed the rated current of the series capacitor for a healthy transmission system. (b) cyclic overload capabilities shall follow the provision so fIEC60143 or any other equivalent or relevant standards. (c) the particular rating to be used shall match the duration of the contingency with the required overload capability. (d) the durationofthe contingencyshall depend onability to pick up generation or shed-load, and the load profile. (e) aTNSPwho intends to installa new series capacitoror modify the size of anexisting series capacit or,shall arrange for sub-synchronous resonance,harmonic and protection coordination studies to be conducted to ensure that sub-synchronous resonance shall not be excited in anygene rating unit. 150 Statutory Instruments 9th January, 2026 A.8.4 Shunt ReactiveCompensation (a) shuntcapacitors shall be able to operate at3 0% above their nominal rated currentat nominal voltage to allow fo rharmonics and also for voltages upto the maximum level allowable; (b) a Participant who intends to install or modify shunt reactive compensation equipment shall at the Participant’s expense arrange fo rharmonic resonance studies to be conducted; (c) a Particpant shall, where harmonicresonance studiesindicate possible harmonicresonance conditions, which couldimpacton thetransmission system, that Participant, inform the SO before proceeding with the installation or modification. A.8.5 Circuit Breakers (a) aTNSP shall specify and install circuit breakers that meet transmission system fault levels and other conditions considered important for the safe and secure operation of the transmission system. (b) circuit breaker ratings shall be in accordance with international circuit breaker standards, IEC standards or any other equivalent or relevant standards. A.8.6 Bus-bararrangements (a) bus-bar layouts for the transmission system shall allow for selection to alternative bus-bars and the ability to go onto by-pass. (a) the minimum bus-bar layout shall— (i) for end-use customerand DNSPconnection, be adequate to ensure compliance with the relevant standards; and (ii) for generation connection, conform to the generation connection arrangements set out in this Code.

1.3.3 Transmissionplanningandapproval Process A.1 Planningprocess (a) a TNSP shall follow a planning process divided into the following major activities: (i) identifying transmission system requirements; (ii) formulating alternative options to meet the needs of the transimission system; (iii)studying the options in paragraph (ii) to ensure compliance with a greed technical limits,justifiable reliability and quality of supply standards; (iv) costing the options referred to in paragraph (ii) on the basis of present day capital costs and using appropriate net discount rates,establish the net present cost of each option; (v) determiningthepreferredoption under paragraph (ii); (vi)building a business case for the preferred option under paragraph (v) using the approved justification criteria;and (vii) requesting approval of preferred option under paragraph (v) and initiating execution. 9th January, 2026 Statutory Instruments 151 (b) a TNSP, DNSP and relevant Participants shall develop transmission system plans in a manner which holistically treats the development of the IPS. A.2 Investment Appraisal (a) the relevant criteria shall be used for appraising investments made to achieve improved supply reliability or quality. (b) the criteria referred to under paragraph (a)shall also be used to determine orverify the desired level of transmission system or equipment redundancy. (c) the criteria referred to under paragraph (a) shall require that the cost of below standard transmission system services needs to be determined. (d) the factors to be considered in determing the cost referred to under paragraph (c)includethecostof: (i) interruptions; (ii) loadshedding; (iii) transmission systemconstraints; and (iv) poorquality ofsupply. (e) statistical analysis of transmission system outages is required for investment appraisal; (f) a TNSP shall in determing an investment under this Code, take into account the cost of unserved energy. (g) the cost of unserved energy shall be determined by considering the following factors— (i) type of load; (ii) duration and frequency of the interruptions; (iii) time of the day the interuptions under paragraph (ii)occur; (iv) whether notice is given of the impending interruptions under paragraph (ii); (v) indirect damage caused by interruptions under paragraph (ii); (vi) start-up costs incurred by the consumers; (vii) availability of end-use customer back-up generation; and (viii) any other relevant factors. (h) the concept of a load profile is set out in Form II of Appendix 4 dipicting load growing to maximum demand of 125MVA and the firm transformer ratingis100MVA. (i) aload duration curve needed to statistically calculate the annual energy not served is set out in Form III of Appendix 4. A.2.1 NPV for cost reduction investments (a) a TNSP who intends to invest in the transmission system shall evaluate the proposed expenditure which is intended to reduce the service providers’costs or the cost of lossesor other ancillary rervicesin accordance with this paragraph. (b) The NPV of the proposed investment shall be calculated using relevant methods. 152 Statutory Instruments 9th January, 2026 A.2.2 Development investigation reports (a) a TNSP shall, with the approval of the SO, develop a transmission system. (b) a TNSP shall, before any development of the transmission system is approved, compile a detailed development investigation report. (c) the development investigation report referred to under paragraph (a) shall— (i) be used as the basis for making an investment decision; and (ii) as a minimum contain the followingelements: (aa) a description of the problem orrequest; (bb) alternatives considered,including non-transmission orcapital and an e va lu at i o n of t h e l on g- t er mco st s o r b en efi ts o feach alternative;and (cc) detailed techno-economic justification of the selected alternative according to the approved investment criteria. A.3 Mitigation of transmission system constraints A TNSP shall— (i) be responsible for resolving constraints on the transmission system of the TNSP; (ii) regularly review the constraintson the transmission system; and (iii) put in place an economically optimised plan around each constraint on the transmission system,which plan may invoive investment,the purchase of the constrained generation ancillary service or other solutions. A.4 InterfacingbetweenParticipants andTNSPs A TNSP shall – (a) ensure regular interfacing with a DNSP and end-use customer regarding transmission system development; and (b) coordinate transmission system planning with the objective of achieving overall optimalplansso as to ensure economically efficient investment. A.5 Transmission investment plan (a) a TNSP shall annually ,publish a five-year-ahead transmission system investment plan, indicating the— (i) major capital investments planned; (ii) status of each project in the plan and stating whether the project is financially approved; and (iii) required approvals from the Energy Regulation Board for the plan or whether the plan has entered a construction phase. (b) thetransmission system investmentplan referred to under paragraph (a) shall be basedonproposalsaccepted before the last date for collecting information to carry out studies and prepare the plan,and initiatedprojects by the TNSP.

1.3.4 Transmision systemdevelopment A.1 Equipmentdesignstandards 9th January, 2026 Statutory Instruments 153 (a) a primary substation equipment shallcomplywith the relevantI EC specifications. (b)a TNSP shall agree with a relevant Particpant on the design standards at the user interface point. (c) aTNSP shall ensure that the agreed design standards at the user interface are documented. (d) the documentation referered to under paragraph (c) shall address— (i) the interface fortheprimary equipment; (ii) secondary circuits; (iv) common DC supplies; (v) AC supplies; (vi) compressed air systems; and (vii) fencing. (e) aTNSP shall ensure that switching devices atornear apower production facility are adequately rated and capable o fswitching loads and fault currents without generating undue switching surges. (f) the switching surge protection provided to the generating unit shall beasprovidedbyIEC60099 and any other equivalent or relevant standards. (g) a user may require a TNSP to provide documentary proof that the user’s connection equipment complies with all relevant standards set out in this Code,bothby design and by testing. A.2 Clearances A safety clearance from the transmission system equipment shall comply with ZS418 Electrical Safety Code - Code of Practice or any other equivalent or relevant standards or codes. A.3 Standardbusbararrangementsandsecuritycriteria The standard substation arrangement shall be in accordance with the provisions under the designing generation connection arrangements set out in this Code. A.4 MotorisedIsolators (a) a TNSP shall ensure that intheinterest ofsafety, all new substations with voltage levels of above 132kV are provided with motorised isolators. (b) a TNSP may ensure that a substation with voltages equal to or lower than 132kV are fitted with motorised isolators depending on the merits of cost and operations. A.5 Earthing and surge protection A TNSPshallensure adequacy of all earthing installations to providefor— (a) safety of personnel and the environment; (b) correct operation of all protection systems; and (c) agreed design and performance levels. A.6 Earthing isolators (a) a TNSP shall ensure that earthing switches are provide data new substation where the fault level is designed for 20kA and above. 154 Statutory Instruments 9th January, 2026 (b) a TNSP shall provide adequate protection to limit lightening surges at the point of connection as specified in IEC6007I and IEC60099. A.7 Tele-control (a) a TNSP may, on request, permit a Participant to have a tele-control equipment in the substation yard or buildings of another Participant ,to perform agreed monitoring of own equipment and other mutually agreed equipment. (b) the TNSP and other Participant refered to under paragraph (a) shall provide the Particpant who is granted permission under paragraph (a) with accesstothe tele- control equipment. A.8 Recorders (a) a user shal linstall quality of supply recorders as required by the SO as stipulated by ZS387 Electricity Supply- Power Quality and Reliability Standard at points of supply or points of connection. (b) aTNSPshall install disturbance recorders at locations in the transmission system that shall enable the SO to adequately analyze transmission system disturbances. (c) access to the recorders referred to under paragraphs (a) and (b) shall be as specified in the Information Exchange Chapter of this Code. A.9 FaultLevels (a) a TNSP shall maintain contracted minimum fault levels at each point of supply. (b) the TNSP will ensure that the maximum fault level stated in a user’s connection agreement is not exceeded. (c) despite paragraph (b), the TNSP may, re-state the maximum fault level as a result of developments by the TNSP or other users. (d) the TNSP shall advise the user on the minimum works needed to comply with the re- stated fault-level referred to under paragraph (c). (e) a Participant who causes the fault level referred to under paragraph (c) to be exceeded, shall pay for mitigation works. (f) the SO shall, where development or operational mitigating actions have been put inplace to reduce fault levels, document maximum fault levels, before and after such actions. (g) the TNSP and SO shall liaise with a user on howfault levels are planned to change and on the best over all solution when equipment ratings become inadequate. (h) a TNSP shall, when equipment ratings are exceeded,communicate to a Participant the potential impact of that falut level on the safety of people and nearby equipment. A.10 A TNSPdeliveredquality of supply (a) aTNSPshall where a user is connected to the transmission system,complywith ZS387 Electricity Supply- Power Quality and Reliability Standard at every point of connection. (b) despite paragraph (a), a TNSP shall where a single user is connected to the transmission system and has agreed otherwise in the connection agreement, comply with that connection agreement in respect of thatpoint of connection. 9th January, 2026 Statutory Instruments 155 (c) the Energy Regulation Board shall, where a user who is not part of the agreement under paragraph (b) seeks connection at the point of coonection referred to under paragraph (b), approve the basis of the cost of any remedy that may occur. (d)a TNSP shall, wheretheTNSP fails tomeet the standard parameters with ZS387 Electricity Supply- Power Quality and Reliability Standard at everypoint of connection,take reasonable steps at own cost to over come the short comings. (e) a TNSP shall before taking the reasonable steps referred to under paragraph (d), consult with the use rrefered to under parapraph (c) on both the technical scope and the time frame of implementing the reasonable steps.

1.3.5 service Provider Protection Requirements (a) a TNSPshall conduct periodicorcondition based maintenance testing of the equipment and transmission systemof the TNSP to ensure and demonstrate that equipment and transmission system are performing to the design specifications. (b) aTNSPshall make available to the SO and to users, the results of tests performedon the equipment and transmission system of the TNSP.

1.3.5.1 Equipment Protection Requirements A.1 Feeder Protection: above 132kV A.1.1 Protection Design Standards (a) a TNSP shall ensure that new feeders are protected by Main Iand Main 2 protection systems. (b) subject to design and capability of the protection scheme, the protection systems referred to under paragraph (a) shall be — (i) in the case of Main 1 protection system, line differential; and (ii) in the case of Main 2 protection system, distance protection. (c) the protection systems referred to under paragraph (b) shall be fully segregated in secondary circuits. (d) a TNSP shall — (i) incorporate an additional DEF in the main protection relays relating to Main 1 protection system and Main 2 protection system; or (ii) instal a separate protection relay to the main protection scheme to all eviate possible deficiencies of distance relays in detection of high resistance faults. (e) a TNSP shall install non-directional O/C and E/F protection functions either separately oras integral parts of the main protection relay to provide optional backup which may use definite time and IDMT over-current. A.1.2 ProtectionSettings (a) a TNSP shall ensure that the protection relays s pecified under the Protection Design Standards provision, provide reliable protection against all possible short circuits and remote or local back-up for busbar faults that are not cleared and those that are not set to provide overloadt ripping. (b) a TNSP may ensure, where specifically required, that the feeder protection is set to provide remote back-up for other faultsas agreed upon with other Participants. 156 Statutory Instruments 9th January, 2026 A.1.3 AutomaticRe-closing (a) a TNSP shall provide ARC facilities onall feeders. (b) the SO shall decideon ARC selection based on real time transmission system, environmental constraints and consultation with users likely to be affected with regard to equipment capabilities, and inaccordance with the ARC philosophy contained in the SO’s Protection Philosophy Statement or other document. (c) a TNSP shall— (i) implement allARC settings and methodology; and (ii) on request, make available the ARC setting and methody to a DNSP and end- usecustomers. A.1.4 Power SwingBlocking (a) a TNSP shall — (i) equip new distance relays on the transmission system with a power swing blocking facility; (ii) block unwanted operations of distance relays during power swing conditions onthe transmission system; and (iii) ensure that the philosophy implemented under SAPP rules or any other regional rules oncontrol are at ie lines, prevail. A.2 FeederProtection:132kV andbelow,atTNSPSubstations A.2.1 Design Standard (a) the feeder protection for voltages from 132KV and below shall be protected by a single protection system, incorporating either distance or differental protection relays, unless otherwise agreed to by the Participants. (b) where the protection system referred to under paragraph (a) fails, definite time and IDMT over-current shall provide backup protection. (c) the protection system shall be equipped with automatic re-closing. Synchronising relays shall be provided on feeders that operatein “ringsupplies” and are equipped with line voltage transformers. A.2.2 ProtectionSettings Protection relays shall provide reliable protection against all possible short circuits within the protected zone as well as remote or local back-upfor uncleared bus-bar faults and should not be set to provide time delayed overload tripping where measurements and alarms are provided on the SCADA system. A.2.3 AutomaticRe-closing (a) ausershall determine ARCrequirements. (b) the SO may specify additional ARC requrements for transmission system security reasons, which could extend beyond the TNSP’s substation. A.3 Tele-Protection requirement: New distanceprotectionsystems shall beequipped with tele-protection facilities to enhancethespeed ofoperation. 9th January, 2026 Statutory Instruments 157 A.4 Transformerand Reactor protecion (a) the standard schemes for transformer protection shall be designed to providethe requisite degree of protection for the following fault conditions: (i) (ii) faults within the tank and the tap changer; faultsontransformerconnections; (iii) overheating; and (iv) faults externaltothetransformer. (b) the TNSP shall consider the applicaticn of the following schemes in the design of the protection system: (i) Transformer –IDMT-LagE/F; (ii) Transformer HVorMV- IDMTL O/C; (iii) Transformer HV/MV- lnstantanousO/C; (iv) Transformer LV(Tertiary) -IDMorInstantaneous O/C; (v) Transforme rCurrent Differential Protection; (vi) Transformer High Impedance Restricted E/F; (vii) Transformer Therma lOverload; and (viii) Buchholtz alarm and trip Protection. A.5 Transmission Bus-bar Protection Bus-bars shall be protected by bus zone current differentil protection set to be as sensitive as possible for the” in-zone faults”and maintain stability for any faults outside the protected zone,even with fully saturated CTs. A.6 Transmissionbuscouplerandbussectionprotection Bus coupler and bus section panels shall be equipped withO/C and E/Fprotection. A.7 Transmissionshuntcapacitorprotection (a) all the new high voltage capacitor banks shall be equipped with sequence switching relays to limit in rush current during capacitor bank energisation. In rush reactors and damping resistors shall also be employed to limit in rush current. (b) the following protection functions shall be provided for all types of protection schemes: (i) unbalanced protection with alarm and tripmages; (ii) O/C protection with instant aneous and definite time elements; (iii) E/F protection with instant aneous and definite time sensitive function; (iv) overload protection with IDMT characteristic; (v) over voltage with definite time; (vi) circuit breaker close in hibit for 300 seconds after de-energisation;and (vii) ancillary protection functions as indicated in paragraph A.9. 158 Statutory Instruments 9th January, 2026 A.8. Over-voltage Protection (a) primary Protection against high transient over-voltages of magnitudes above 140%, such as those induced by lightning,shall be provided by means of surge arrestors. To curtail dangerous,fast developing over-voltage conditions that may arise as a result of disturbance, additional over-voltage protection shall be installed on shunt capacitors and feeders. (b) over-voltage protection on shunt capacitors is set to disconnect the capacitor (s) at 110% voltage level with a typical delay as advised from time to time by the SO or the ROs. (c) over-voltage protection on end-use customer’s feeders is set to trip the local breaker at a voltage level of 120% with a delay of 1 to 2 seconds. A.9 AncillaryProtectionFunctions protection systems shall be equipped with ancillary protection functions and relays that enable adequate co-ordination between protection devices and with bay equipment.TheTNSP shall consider the following functions for new protection system designs: (a) breaker fail and bus trip; (b) breakerpolediscrepancy; (c) breaker anti-pumping; (d) pantograph isolator discrepancy (pole discrepancy applied to isolators); and (e) master trip and lockout.

1.3.5.2 SystemProtectionrequirements A.1 Under-Frequencyloadshedding (a) the actions taken on the power system during a nunder-frequency condition is defined in the System Operation Chapter. (b) under-frequency loadshedding relays shall be installed in the IPS as determined by the SO inconsultation with DNSPs and end-use customers.There spective as set owners shall pay for the installation and maintenance of under-frequency loadshedding relays. (b) under-frequency relays shall be tested periodically.The users shall submit to the SO a written report of each such test,within a Month of the test being done, in the format specified in the Information Exchange Chapter. (c) the provisions of the SAPP operating guidelinesor other regional guidelines shall prevail over the provisions of this paragraph in the event of conflict. A.2 Out-of-step tripping (OST) (a) the purpose of the OST protection is to separate power system in a situation where a loss of Synchronous operation takes place between a generating unit o rgenerating units and the main powers ystem.In such a situation system separation is desirable to remedy the situatio n. Once the Is l and edSystem is stabilized it can be reconnected to the IPS. (b) the SO shall determine and specify the OST functionality to be installed at selected locations by theTNSP. 9th January, 2026 Statutory Instruments 159 A.3 Under-voltageloadshedding (a) under-voltage loadshedding Protection schemes shall be used to prevent loss of steady- state stability under conditions of large local shortages of reactive power or voltage collapse. Automatic loadshedding and tripping of suitable loads is carried out to arrest the slide. (b) the SO shall determine and specify the under-voltage loadshedding functionality to be installed at selected locations by DNSPs and end-use customers. A.4 Protection System performancemonitoring (a) the TNSP shall monitor the performance of the protection system. (b) the TNSP shall investigate each Protection operation for its correctness based on available information. (c) the TNSP shall provide a report to users affected by a protection operation when requested to do so.

1.3.6 Nomenclature (a) all safety terminology shall comply with ZS418 Electrical Safety-Code of Practice. (b) engineering drawings relating to connecting equipment shall use t he symbol set and layout conventions as stipulated in IEC 60617 “graphical symbols for diagrams” or any other relevant Zambian Standard as a Standard for electrical drawings, unless otherwise agreed between a service provider and customer.

1.3.7 Network Maintenance (a) participants shall monitor the performance of Participant’s plant and take appropriate action where deteriorating trends are detected, including those that may be influenced by extreme weather conditions or climate change. (b) the TNSP shall consider the environmental conditions and potential for extreme weather events when prioritizing upgrades to the transmission system to ensure long-term reliability of the transmission system (c) maintenance scheduling shall be donein accordance with the System Operation Chapter. (d) the TNSP shall agree, inwriting,withits users, details ofany special maintenance requirements as well as maintenance coordination requirementsfor each transmission Substation. (e) the TNSP shall provide distributors and users with details of its maintenance plans and practice sup on request.

1.3.8 Climate Resilience Standards And Guidelines The Energy Regulation Board shall, in consultation with Participants and other relevant stakeholders, develop and issue Climate Resilience Standards and Guidelines addressing: (a) integration of climate resilience considerations into power sector planning processes, including generation, transmission and distribution development plans; (b) assessment methodologies for evaluating climate vulnerabilities of Transmission System assets; (c) technical specifications for climate-resilient equipment and infrastructure that shall be included in grid connection agreements; 160 Statutory Instruments 9th January, 2026 (d) design adjustments for varying environmental conditions across Zambia; (e) operational protocols for extreme weather events; and (f)maintenance considerations for climate-exposed assets.

1.3.8.1 Reporting on Climate Resilience (a) the SO shall submit Reports on compliance with Climate Resilience Standards and Guidelines to the Energy Regulation Board in accordance with the reporting procedures established in this Code. (b) the Energy Regulation Board shall compile an annual summary of climate resilience implementation across the electricity sector and submit this to the Ministry responsible for energy to inform national climate adaptation planning. 9th January, 2026 Statutory Instruments 161 CHAPTER 2 METERING (a) Where the provisions inrelation tometering installations under SAPP and any other regional power pools and this Code are similar,the document with strigent provisions shall apply. (b) Where there are different requirements on the provision of meter data under the SAPP and any other regional power pools than under this Code both sets of data provision shall be applied.

2.1 General Provisions (a) the metering point shall be located at commercial boundary between the Participants. (b) Participants may request an independent audit of metering installations.There questing Participant shall be responsible for any costs relating to the audit unless the metering installation is proved to be outside the defined standard. (c) participants shall provide all the necessary information reasonably required to perform their respective metering duties. (d) the type, installation,operation and testing of metering installation at each metering point shall comply with ZS640 - 647 metering standards or any other relevant Standards.

2.2 Responsibility for metering Installations (a) a service provider shall ensure that all points identified as metering points in accordance with paragraph 2.1 have metering installations in accordance with the provisions of this Code. (b) the Participants shall be responsible for managing and collecting metering information. (c) participants connected to orintending to connect to the transmission system shall provide the relevant service provider with all information necessary to enable the service provider to perform metering duties. (d) the Participants shall ensure that commissioning, maintenance, auditing and testing of metering installations are carried out in accordance with ZS640 – 647 metering standards or any other relevant Standards.

2.3 Metering Installation requirements (a) A Participant shall take into account the following requirements when installing meters: (i) each metering point shall be installed with main and check meter; (ii) both active and reactive energy shall be measurable without compromising any requirements of this Code; (iii) full four quadrant metering shall be installed where active and reactive energy flow is in both directions; (iv) the meters shall be configured to store or record metering datain half hourly integration periods, which shall be in non-volatile memory that is able to be maintained without externa lpower; (v) the metering system shall be able to stored at a in memory for a minimum of 40 days; and 162 Statutory Instruments 9th January, 2026 (vi)historical metering data shall be retained for a minimum period of five years or as stipulated in ZS 647. (b) a customer shall bear the cost of a metering installation. (c) a customermay, with the consent of a service provider, install own metering in a service provider’s installation. (d) customer metering referred to under paragraph (b) is secondary metering only and not for billing purposes.This provision is subject to there being no impact on the settlement metering. (e) the service provider shallprovide historical metering data to the customers on request. (f) the service provider shall provide real time metering data when requested to do so by the customer.

2.4 Data valldation (a) The Participants shall carry out data validation in accordance with ZS640 -647 metering standards or any other relevant Standards in the event of— (i) electronic access to the meters not being possible; (ii) an emergency bypass or other scheme having no metering system;or (iii) metering data not being available. (b) a Participant may, in carrying out data validation, resort to any of the following: (i) manual meter data downloading; (ii) estimationor substitution subject to mutual agreement between th eaffected parties; (iii) profiling;or (iv) reading of the meter at scheduled intervals. (c) when the need for metering estimations arises,the estimates shall be done in accordance with ZS647 or any other relevant Standards.

2.5 Meter verification In addition to the ZS647 verification requirements, meter readings shall be compared with the metering data base atleast once ayear.

2.6 Metering data base (a) a service provider shall, in addition to meter measurement data, create, maintain and administer a metering data base containing,the following information: (i) (ii) name and unique identifier of the metering installation; the date on which the metering installation was commissioned; (iii) the connecting parties at the metering installation; (iv) maintenancehistoryschedulesforeachmetering installation; (v) telephone numbers used to retrieve information from the metering installation; (vi) type and form of the meter at the metering installation; and 9th January, 2026 Statutory Instruments 163 (vii) fault history of a metering installation. (b) the service provider shall retain metering information for atleast five years for audit trail purposes and commissioning documents forall metering installations.

2.7 Metering data base inaccuracies In the event of test results revealing that data in the metering data base is inaccurate, the service provider shall inform all affected Participants and corrections shall be made to the official metering data and the associated billing by mutual agreement.

2.8 Access to metering data (a) the service provider shall make metering data available to affected participants in the format agreed on. (b) service providers shall publish all data in the formats agreed upon by participants. New formats shall be negotiated between the service provider and the affected Participants.The service provider shall store all customer information in a data base and shall ensure that the data base is maintained and updated continuously. (c) the service provider shall at the expense of the requesting Participant, providenon- standard data provision methods. (d) security requirements for metering data shall be as specified in ZS647 or any other relevant Standards.

2.9 Confidentiality Metering data for use in energy trading and billing are confidential information and shall be treated in accordance with the Information Exchange Chapter. 164 Statutory Instruments 9th January, 2026 CHAPTER 3 SYSTEMOPERATION

3.1 Interpretation In this Chapter, unless the context otherwise requires- “user” means a demand customer, DNSP or power producer; and “power producer” means a user withsynchronous or asynchronous generating unitsandenergy storage facilities which can be operated in export or import mode.

3.2 Operating Requirements And Arrangements Involving Users

3.2.1 Operational Responsibilities of All Participants (a) all Participants shall set up operational procedures for their respective facilities to ensure safe and efficient operation of the IPS. (b) except where otherwise stated, a Participant shall not operate theequipment of another Participant without the permission of the asset owner. (c)where aParticipantintends to operateanother Participant’s equipment, the other Participant has the right to testandauthorisetherelevant operating staff of the Participantwho intends tooperatethe other Participant’s equipmentin accordance with such other Participant’sstandards before granting such permission. (d) despite the provisions of this Chapter, Participantsshall be responsible for safeguarding the health oftheir equipment and for protecting their personnel and the public from dangers arising from their EHV, HV and MV systems. (e) a user shall — (i) (i) comply with ZS418 Electrical Safety Code of Practice and other relevant safety legislation; and develop in-house safety regulations in accordance with Electricity Suply Industry Safety Rules.

3.2.2 Operational Responsibilities of Users and Embedded Power Producers (a) a user shall immediately disconnect from theIPS, when conditions on the IPS, undernormalorabnormal conditions, are likely to jeopardise users’ plant or personnel. (b)directly connected users and embedded power producers shall at all times operate their equipment in such a manner to ensure that they comply with the conditions specified in their connection agreement or other form of agreement with the SO. (c) all directly connectedend-use customers shall declare any embeded generating plant and specify any interlocking mechanism to prevent inadvertent parallel operation with the transmission system. (d) customers having embeded generation are deemed to be demand users and power producersif the generating equipment may be operated in parallel with the IPS. (e) a directly connectedpower producer shall— (i) ensure that its generating units are operated within the capabilities defined in the connection agreement entered into with the TNSP; 9th January, 2026 Statutory Instruments 165 (ii) (iii) reasonably cooperate with the SO in executing all the operational activities during an emergency generation condition; assist the SO in correcting quality of supply problems caused by the users equipment connected to the transmission system; (iv) maintain in service at all times any required protection to trip in the event of supply loss causing an Island condition to prevent non-transient conditions arising outside ZS387 when operating in Islanded mode; (v)provide the SO with monthly performance indicators in relation to each generating unit at each power production facility in respect of availability and reliability; and (vi) report significant events,such as catastrophic failures to th eEnergy Regulation Board and SO within 24 hours of occurrence of such event. (b) apower producer with centrally dispatched generating units shall submit to Energy Regulation Board the performance indicators set out in Appendix 5 ondates advised by Energy Regulation Board.

3.2.3 Demand Forecasting (a) a Demand forecasting shall specify the informationthat the Participants shall provide to the SO so that the demand forcasting requirements can be met. (b) a user shall provide loading and generation output information tothe SO to enable the SO to efficiently operate the IPS and to ensure maximum system security and system stability of the IPS. (c) a power producerwithelectricitystoragefacilityshall be deemed as- (i) generator, when exporting energy; and (ii) demand, when importing energy. (d) a power producer referred to under paragraph (c) shall provide loading and generation outputinformation as required by the SO from other users with demand or generating units. (e) a userwithcontrollable loads shall identify the part of the user’s load that is controllable. A.1 Information flow and coordination (a) DNSPs shall co-ordinate demand forecast information for each bulk supply point. (b) DNSPs shalla ggregate and provide demand forecast information to the SO and TNSP where- (i) change in demand is greater or equal to 10MW at any bulk supply point; and (ii) there is a change in the range of net demand profile as specified by the SO and TNSP. (c) the SO and TNSP may request that an end-use customer or DNSP forecast also contains some historic and validated values to judge the trend and additionally require that any step changes are validated. (d) demand forecast information from power producers for directly connectedgenerating units greater or equal to 2MWand embedded generating unitssubject tocentral dispatchshall be provided to the SO. 166 Statutory Instruments 9th January, 2026 (e) power producersshall submit to the SO any projected increase or decrease in installed capacity or long-term capacity available. A.2 Demand forecast data Directly connectedend-use customersand other relevant Participants shall provide to the SOinformation regarding demand and planned shutdowns for specified future periods as set out in the Transmission System Chapter. This shall be provided on an annual basis.The data is required to be submitted to the SO by the last working day of September in each calendar year. A.3 OutputInformation

3.2.4 All Generating Units (a) power producers with generating units subject to central dispatch and normally with registered capacitygreater or equal to 10MWshall provide the SO with information regarding outputavailable for specified future periods. (b) DNSPsshall provide summary information in relation to generating units connected to the distribution system. This shall be provided on an annual basis according to a timetable set by the SO. The data is required to be submitted to the SO by the last working day of October in each calendar year. (c) information from generating unitsshall beas set out in the table for generating unit output available and controllable demand outputs in the Transmission System Chapter. A.1 Operational planning and Return to Service (a) users shall provide the SO with a procedure and timetable for the co-ordination of outage requirements for plant and apparatus to enable the SO to operate the IPS effectively. (b) users with directly connected controllable demand under the control of the SO shall provide Outage Information to the SO for purposes of operational planning and return to service.The data is required to be submitted to the SO by the last working day of October in each calendar year. A.2 Provision of Information (a) directly connected end-use customersand DNSPs shall furnish the SO with information on planned outages inorder for the SO to properly plan,and coordinate its control, maintenance and operation activities. (b) centrally dispatched embedded generating units shall provide outage information directly to the SOwhich shall share this information with theDNSP. (c) information supplied to the SO from power producers, shall include details of planned outagesfor maintenance or other purposes as well as the expected time of return of service. (d)the SO may require additional information from users regarding major plant and associated equipment which may affect the performance of the IPS. A.3 SO Information to Users The SO shall advise users who may be significantly affected by particular outages of IPSplantand apparatus, of the likely dates and duration of the outages. If there are objections from users, these shall be considered by the SO and alternative arrangements proposed if possible. 9th January, 2026 Statutory Instruments 167

3.2.5 Outage Management - Time scales and data Detailed implementation of data gathering and timescales shall be determined by the SO. Form IV set out in Appendix 4sets the timetable for the annual process. A.1 Yearly Planned Maintenance Schedule (a) by a date set by the SO, eachcentrally dispatchable power producer, controllable load provider, energy storage provider and TNSP shall submit its preferred annual maintenance schedule to the SO who will prioritise work based on information provided by the Participants and taking account of safety and security of the IPS and connected parties. (b) the SO may require Participants to reconsider their schedules and re-submit a revised outage plan for their plant and equipment. (c) once all the submissions have been approved, they shall be consolidated into a yearly maintenance schedule. Copies of the yearly maintenance schedule shall be circulated to all users. A.2 Yearly Unplanned Outages (a) if a previously unplanned outage allowstimetogive noticetotheSO,thisshallbedone atleast2weeksbefore the outage. (b) when the need for an unplanned outage is first identified it shall be communicated to the service providers as an unplanned outage indicating outage dates, times, reason, type of maintenance and urgency assigned to it. (c) at this point the service providers shall confirm the outage if it satisfies all the necessary requirements. A.3 EffectingofOutages (a) theSOshallmake availabletocustomers anoutage schedule ofall planned outages on the IPS.The outageschedule shall cover a period of one calendar year and shall indicate the status of the (b) outage,that is to say, whether the outage is confirmed or not. The schedule shall be updated and republished monthly. (c) when an outage is cancelled or refused it is the responsibility of the person cancelling or refusing the outage to furnish reasons for cancellation or refusal, in writing. The person receiving the cancellation or refusal shall thenenter this information into the system when changingthe status to cancelled. This shallalso apply to outagesthat arepostponed. A.4 Emergency Outage (a) in the case of emergency outages of customer equipment, customers shall inform service providers verbally ofthe need for the outage. However, within 24hours after the outage has been effected,theoutage request will need to be formalised in writing. (b) service providers shall alsoinform customers inthe case of emergency outages on their installations. A.5 Long Term Maintenance Planning for Power Producers (a) power producersshall compile anindicative 5-year-ahead maintenance plan in consultation with the SO and TNSP. The power producer shallthen provide the SOwith the following documents inthe pro-forma format specified in the Information Exchange Chapter: 168 Statutory Instruments 9th January, 2026 (i) a 52-week-ahead outage plan per power production facility,showing planned outageandreturn dates and other known generation constraints, updated weekly by15:00hours everyThursday; (ii) an annual maintenance or outage plan per power production facility, looking 5- years ahead, showing the same information as above and issued by: 31 December of each year; and (iii) a monthly variance report, explaining the differences between the 52 weekly ahead planned and the actual outages during the month. (b) a power producer shall ensure the absolute minimum deviation from its annual outage plan. Each deviation shall be negotiated with the SO and shall be accommodated as far as reasonably practical. (c) the SO shall coordinate network outages affecting generating unit output with related generating unit outages to the maximum possible extent. (d) The objectives to be used by tbe SO in this maintenance coordination are— (i) firstly maintaining adequate reserve levels at all times; (ii) secondly ensuring reliability where IPS constraints exist; and (iii) thirdly maintaining acceptable and consistent real-time technical risk levels. (e) the SO shall provide forecasting of demand for the next day, the daily demand for the next seven days and the weekly demand for the next twelve months to the power producers. A.6 Refusal or cancellation of Outages A Participant shall not unreasonably refuse or cancel a confirmed outage. The direct costs related to the cancellation or postponement of an outage shall be borne by the Participant cancelling or postponing the outage.

3.2.6 Emergency and Contingency Planning including Demand Control A.1 Duties of SO and Users (a) the SO inconjunction with all Participants shall develop, implement, maintain and ensure compliance with all contingency and emergency plans that are relevant to the performance of the IPS.These plansshall be consistent with prudent utility practices. (b) the SO shall beresponsible for keeping all Participants informed of the status and expected status of the IPS and of the SAPP. (c) the SO shall be responsible for determining all operational limits on the IPS, updating them periodically and making them available tothe Participants. (d) the SO, inconjunction with all Participants, shall conduct network studies which may include but not be limited to loadflow,fault level, stability and resonance studies to determine the effect that various component failures would have on the reliability of the IPS. (e) scenario loadflow studies shall be performed at least annually. (f) emergency plans shall allow for quick and orderly recovery from a partial or complete system collapse, with minimum impact on customers. (g) all emergency plans shall be periodically verified by audits ,on-site inspections , actual tests and simulations to the greatest practical extent. In the event of such tests causing undue risk or undue cost to aParticipant, the SO shall take such risks or 9th January, 2026 Statutory Instruments 169 costs into consideration when deciding whether to conduct the tests. The cost of the se tests shall be borne by the respective asset owners. The SO shall co- ordinate these tests with all affected Participants.Users are required to support such testing as required by the SO. Anytests shall be carried out at a time that is least disruptive to the Participants. The SO shall ensure the co-ordination of the tests in consultation with all affected Participants. (h) emergency plans shall be developed in consultation with all affected Participants,and shall be consistent with internationally acceptable practices, and shall include but not be limited to— (i) under-frequency load-shedding; (ii) prevention of voltage slide and collapse; (iii) meeting any national disaster management requirements including the necessary minimum load requirements; (iv) forced outages at any point of connection; (v) ensuring continuation of supply to every Power Production facility during normal and abnormal conditions; (vi) supplyrestoration; (vii) partial or total loss of operational communications; (viii) loss of the ability to operate the SO’s Control Centre; and (ix) blackstart process. (i) all contingency and emergency plans shall be reviewed every two years or in accordance with changes in network conditions or where there has been significant change in staff who are required to carry out emergency functions. (j) the SO shall, in consultation with the users, set the requirements and procedures to implement demand control. (k) participantson the IPS shall make available loads and schemes with appropriate signals including under-frequency,under-voltage, breaker statu setc to comply with demand control requirements. A.2 Basis of Demand Control (a) demand control is concerned with procedures to be controlled by the SO to permit reductions in demand. (b) the demand control procedures ensure that hardship to users and customers is minimized and, that in so far as is practicable, all parties affected are treated equitably. (c) demand control deals with the following means of reducing demand: (i) automatic low or high frequency or voltage demand disconnection or connection; (ii) user demand reduction instructed by the SO;or (iii) emergency manual demand disconnection. (d) the SO shall implement demand control measures when— (i) abnormal conditions exist on the IPS; (ii) a multiple outage contingency exists resulting in island grid operation; and 170 Statutory Instruments 9th January, 2026 (iii) there is any other operational event which the SO deems to warrant implementation of demand contro l measures for the safe operation of the IPS. A.3 Methods of Demand Control (a) the methods applied to achieve demand control shall include but not be limited to— (i) customer demand management; (ii) automatic under-frequency loadshedding; (iii) automatic under-voltage loadshedding; (iv) emergency manual loadshedding; (v) voluntary load curtailment. (b) the SO shall develop load reduction procedures in conjunction with directly connected end-use customers, ROs, TNSPs and DNSPs,which shall be regularly updated, to reduce load in a controlled manner taking cognisance of the type of load and other factors. (c) where demand control is exercised by the SO or DNSPs it shall be done in a manner that, in so far as reasonably practicable, does not discriminate against any customer. The SO and DNSPs shall use reasonable endeavours to ensure that the burden is shared fairly among customers. Exemptions may apply to vital and priority customers. (d) in addition to disconnecting load, a deliberate reduction of voltage, or frequency (when disconnected from the SAPP system), may be used to achieve a temporary reduction in demand. (e) the SO may carry out emergency manual load shedding on the transmission system or instruct it to be carried out on the distribution system for reasons of shortfall in supply or other reasons. (f) in the event of a sustained period of short fall then planned rota load shedding may be used to share the available power among affected customers. A.4 Implementation of Demand Control (a) where demand control is planned in advance, notice shall be given to users to the extent possible. (b) where demand control is exercised by a DNSP on instruction from the SO, in order to safeguard the IPS, then the DNSP is required to respond to the SO instructi A.5 Demand Control studies and audits and reporting of defects (a) the transmission and distribution licenseesand ROs shall co-operate with the SO to ensure equitable and effective demand control by providing information, carrying out studies and auditing performance. (b) any Participant aware that any load shedding equipment is defective or inoperable shall immediately inform the SO.

3.2.7 Operational communications and liaison A.1 Purpose 9th January, 2026 Statutory Instruments 171 Operationalcommunications and liaison sets down the operational information exchange process and assistance between Participants to facilitate the safe and secure normal and abnormal operation of the IPS. A.2 Proced (a) the Participants shall appoint competent personnel to operate their network and where needed shall establish direct communication channels amongst themselves to ensure the flow of operational information between the Participants. (b) all Participants shall submitnames of authorized personnel to the SO or its direct agent and such direct agent shall so inform the SO who shall maintain a current comprehensive listing. (c) where a Participant experiences an emergency, theother Participants shall assist that Participant tothe extent possible and as may be necessary, to ensure that it does not jeopardise the operation of the IPS or health of plant. (d) the SO and users shall agree on the bus-bar configuration or configurations at each point of supply during normal and emergency conditions. Details of such configuration or configurations shall be included in the operating agreement between the Participants. (e) the SO, inconsultation with aspecific user, shall compile acomprehensive maintenance, testandinspectionplan forallequipment, systemsandschemesinstalled inthespecificHV yards. (f) the TNSPshallprovidenotification tousers ofany work to be carried out on anyprotection, control and instrumentation circuits in adjacent HV yards. The TNSP shall compile re-commissioning programs for such work in consultation with the user. (g) whenever possible, DNSPs and end-use Customers maybe required to transfer loadfrom one point of supply to another by performing switching operations on the network. The SO and user shall agree adequate procedures to minimise disruption, circulating currents and voltage step changes. Where load transfer is possible, the operating agreement shall cover atleast the operational communication , notice period requirements and switching proceduresfor such operations.

3.2.8 Fault reporting, analysis and incident investigation A.1 Purpose Fault reporting, analysis and incident investigationsets out the requirements for the exchange of information in relation to operations and events on the IPS or the installation of any user connected to the IPS, which have had, or have the potential for an operational effect on the IPS or the installation of any other user. A.2 Procedure (a) a Participant shall— (i) report all incidents that materially affect the quality of supply on the IPS to the other Participants affected or likely to have been affected; (ii) ensure that emergency notification includes the name of the individual reporting the incident; and 172 Statutory Instruments 9th January, 2026 (iii) provide sufficient details in describing the event including the cause, timing and recording of the event to assist the SO in assessing the risk and implications to the IPS and all the affected users’equipment. (b) for planned events,which significant incidents have an identified operational effectonthe IPS, oronusers’ equipment connected to the IPS, the relevant Participant shall notify the SO. A notification under this part of the Code shall be given as far in advance as possible, to allow the recipient to consider and assess the implications and risks arising. Where a planned event is so notified to a DNSP the DNSP shall ensure that the information is passed to the SO in a timely manner. A.3 Power Producers,TNSPs, DNSPs and end-use Customers (a) Power Producers, TNSPs, DNSPs and end-use customers shall report the following eventsverbally to the SO: (i) anyloss of output, tripping of generating units; (ii) change of status of agc and governing; (iii) loss of transmission capacity; or (iv) loss ofmajor load to the so. (b) within seven days of averballyreportedevent, the Participant that reported the eventshall submit to the SO or RO a detailed written reportin Form V set out in Appendix

4. (c) where a Participant determines that afault thathad occurred on another Participant’s system requires further investigation, the Participant shall issue an incident report. A.4 System Operator investigation (a) the SO shall investigate all incidents that materially affect or could materially affect the quality of supply onthe IPS. Such an investigation shall commence immediately after receipt of a preliminary reportand all affected Participants shall provide required information and participate in the investigation. (b) participants shall, within mutually agreed time frames, implement recommended actions. A.5 Significant Incidents Significant incidents shall include eventswhich result in, or may result in, the following: (a) voltage outside statutory limits; (b) system frequency outside statutory limits; or (c) system stability failure. A.5.1 Reports (a) the following are the matters to be included in a written report of a significant incident: (i) date and time of significant incident; (ii) duration of incident; (iii) location; (iv) equipment involved; 9th January, 2026 Statutory Instruments 173 (v) description of significant incident; (vi) effect on users and where appropriate details of any demand control undertaken; (vii) conclusions and recommendations, if applicable; and (viii) in the case of incidents resulting in damage, estimated date and time of return to normal service.

3.2.9 Testing and Commissioning A.1 System Tests System tests are those which involve simulated or the controlled application of irregular, unusual or extreme conditions on the IPS or any part of the IPS, but do not includecommissioning or re-commissioning tests orany other tests of a minor nature. A.1.1 Procedures for System Tests If a system test is proposed by the SO or the user connected to the IPS then the provisions of this section shall apply and all transmission system test procedures shall comply with all applicable legislation. A.1.2 Tests defined as System Tests System tests which have a minimal effect on the IPS or the systemsof others will not be subject to this procedure. Minimal effect shall be taken to mean variations in voltage frequency and waveform distortion of a value not greater than those figures which are defined in the ZS387 and further stated in the Transmission System Chapter. A.1.3 Arrangements for a systemTest (a) when the SO or a user intends to undertake a systemtest which may have significant effect on the system of other users, normally twelve months’ notice, or as otherwise agreed by the SO, shall be given by the person proposing the systemtest (test proposer) to the SO and to those users who may be affected by such a systemtest. (b) the proposal shall be in writing and shall contain details of the nature and purpose of the proposed systemtest and shall indicate the extent and situation of the plant or apparatus involved. The SO shall not be required to do anything until it is satisfied with the details supplied in the proposal. A.1.4 Duties of SO (a) theSO shall have responsibility for overall co-ordination of the systemtest, and shall identify in its reasonable estimation, which users other than the test proposer, may be affected by the proposed systemtest. (b) following receipt of the systemtest proposal, the SO shall evaluate the impact of the system test and discuss the proposals with users identified as being affected. (c) within one month of receiving the systemtest proposal the SO shall submit a report to the test proposer which shall contain proposals for carrying out the system test (including the manner in which it is to be monitored). (d) an allocation of costs between the affected parties, (the general principle being that the test proposer will bear the costs). 174 Statutory Instruments 9th January, 2026 (e) such other matters that the SO considers appropriate. An outline of the procedure to be followed and the proposed test schedule and advice regarding any costs. (f) if theproposal report is approved by all recipients, the systemtest can proceed. A.1.5 System Test Programme (a) at least one month prior to the date of the proposed systemtest, the SO shall submit the following to all recipients of the proposal notice: (i) a programme called a final test programme stating the switching sequence and proposed timings; (ii) a list of those staff involved in carrying out the system test (including those responsible for site safety); and (iii) such other matters as the SO deems appropriate. (b) the final test programme shall bind all recipients to act in accordance with the provisions contained within the programme in relation to the proposed systemtest. A.1.6 System Test Final report (a) at the conclusion of the systemtest, the test proposer shall be responsible for preparing a written report (the “final report”) of the systemtest for submission to the SO. (b) the final report shall include a description of the plant and apparatus tested and of the systemtest carried out, together with the results, conclusions and recommendations. (c) results of tests shall be reported to relevant parties, taking into account confidentiality issues. A.2 Commissioning andConnection (a) users and TNSPs shall provide commissioning programmes to the SO in a timely manner. The SO shall verify commissioning programmes of the IPS to ensure co- ordination of activities. (b) commissioning of new equipment associated with a transmission connection, or re- commissioning of such existing equipment, shall be agreed with the SO in writing. The said aspects shall include, but not be limited to, the following: (i) cornmissioning procedures and programmes; (ii) documents and drawings required; (iii) proof of compliance with standards; (iv) documentary proof of the completion of all required tests; (v)SCADA information to be available and tested before commissioning where such facilities are available; and (vi) site responsibilities and authorities. (c) participants shall give a minimum notice period of one month, unless otherwise agreed, from the date of receipt of the request for all commissioning or re- commissioning. Where commissioning is likely to involve a requirementfor dispatch or operating for test purposes, the Participant concerned shall notify the SO of this requirement, including reasonable details as to the duration and type of the testing required. 9th January, 2026 Statutory Instruments 175 (d) when commissioning equipment at the point of connection, the TNSP shall liaise with the affected customers on all aspects that could potentially affect the customers’operation. (c) the TNSP and users shall perform commissioning tests in order to confirm that TNS Pand the users’ plant and equipment meet the requirements of this Code.Tests as set out in Appendix 1 shall be performed and the results reported according to the requirement and format indicated in the TNSP’s testing and compliance manual. (d) the SO or TNSP has the right to witness certain tests performed to ensure Code compliance.Where the TNSP plans to exercise its right to witness any test it shall respond promptly, after receipt of the test programme and indicate its intention and how joint arrangements for the test are to be made. (e) on considering the test results, the SO shall issue or withhold a temporary compliance certificate, final compliance certificate or a limited compliance certificate. (f) before being put into operational service, TNSP and user equipment shall have the operational settings including protection settings most recently agreed with the SO applied, and where these differ from any settings in the connectionagreement or other form of agreement an amendment to the agreement shall be issued.

3.2.10 Safety at the transmission system or user interface (a) the following procedures set down the basic safety requirements at all the user and transmission system interfaces. These procedures are necessary to ensure the safety of all who may have to work at either side of the interface or on the interface (boundary). (b) when work on HV equipment or HV isolation is required,the TNSP and the user shall adopt a common form of record of- (i) the isolation for work; (ii) safety earthing (being connections to earth, temporarily fitted, or closed (to protect persons working from electrical danger); and (iii) the authority to carry our work or testing. (c) Appendix 6 sets out the form of record to be used. (d) Written rules for safety working and communicating procedures shall be available and used by all persons who may have to work at or use the facilities provided at the Interface. (e) Electrical equipment connected to either side of the interface and interface equipment shall be under the control of a named person at either side. (f) each item of equipment shall be controlled by only one identifiable person at any one time. (g) adequate means of isolation shall be provided at the interface to allow work to be carried out safely at either side of the interface. (h) where necessary to prevent danger adequate facilities for safety earthing shall be provided at either side of the interface to allow work to be carried out safely at the interface or at either side of the interface. (i) adequate working space, adequate means of access and egress and, where necessary, adequate lighting shall be provided at all electrical equipment, on or near which work is being done in circumstances which may cause danger. 176 Statutory Instruments 9th January, 2026 (j) all electrical equipment shall be suitably identified where necessary to prevent danger. (k) electrical installations and equipment shall comply with the relevant statutory requirements. (l) operation and maintenance of the user’s equipment shall only be carried out by authorized personnel. Before first commissioning the plant, operating procedures shall be agreed with the SO. (m) Instructions for operating and earthing the user’s electrical equipment shall be clearly displayed in the user’s switching location. (n) safety procedures for personnel working on or in close proximity to the transmission systemplant and apparatus shall be governed by the TNSP.

3.2.11 Communication of system conditions, operational information and IPS performance (a) the SO shall, to the extent practicable, communicate system conditions to all Participants periodically as necessary to inform them of altered status or risk which might affect their operations. (b) the SO shall be responsible for providing Participants with operational information as may be agreed from time-to-time and as specified in the Information Exchange Chapter.This shall include information regarding planned and forced outages on the IPS. (c) the SO shall annually publish expected fault levels , including the rupturing of relevant IPS equipment, foreach point of supply.

3.2.12 Tele-control Where tele-control facilities are shared between the SO and other Participants, the SO shall ensure that operating procedures are established in consultation with the Participants.3.3 Scheduling and Dispatch Of Generation and ancillary Services In this Paragraph reference to power producers, controllable demand users and energy storage users include agents acting for those users for the purpose of managing dispatch for those users.

3.3.1 Objective of Scheduling and Dispatch (a) The following shall be observed in order to meet demand: (i) at minimum cost; (ii) operating within Government Energy policy guidelines; and (iii) with an appropriate margin of reserve, whilst maintaining: (iv) safety on the system; (v) the security and quality of electricity supply; and (vi) taking account of operational constraints. (b) In meeting the demad in paragraph (a), the SO needs to— (i) issue instructions to centrally dispatched generating unitsto managefrequency security andvoltage on theIPS; 9th January, 2026 Statutory Instruments 177 (ii) issue frequency management instructions to embedded generating unitse”250KVA; (iii) issue instructions to centrally dispatched controllable demands; (iv) issue instructions to agents in respect of either of the duties of 1 to 3 above for non-centrally dispatched generating units; (v) manage power flows with international interconnected parties; and (vi) issue instructions to direct agents, users or agents with respect to ancillary services. (c) the SO may need to consider Government Energy policy as directed by Energy Regulation Board, commercial agreements and market prices to achieve economic dispatch. (d) The SO may dispatch embeddedgeneration e”250KVA to assist in controlling IPS frequency. However, the SO must co-ordinate Dispatch of such generation to have regard to the present condition and loading of the distribution system.

3.3.2 Scheduling (a) The SO may use direct agentsincluding but not limited to aRO or a DNSP to assist in the scheduling and dispatch of non-centrally dispatched generating units. in the case of direct agents or agents, the SO mayschedule or dispatch to the direct agent or agent an aggregated requirement for active power, reactive power or any other service for the zone or zone(s) concerned so that the direct agent or agent becomes part of the daily schedule. (b) TheSO remains responsible for ensuring that each direct agent or agent so employed performs these functions in accordance with theActand any other relevant requirements placed on the SO by law or by Energy Regulation Boardand shall be entitled to audit and report on such compliance and to copy such report to Energy Regulation Board. (c) Generating units connected to the transmission system and embedded generating units over 10mw and such other embedded generating units e” 2MW as are required and notified by the SO will be centrally dispatched by the SO or adirect agent. (d) the schedule will identify generating units or aggregated generating units to be dispatched, the expected level of dispatch of active power the mode and target of reactive powerand the required contribution to AGC and response in each category. A.1 Data provided to the SO by Power Producers All declarations made to the SO should be at site reference conditions. A.1.1 Availability Declaration (a) by a time,each day set by the SO, each power producer shall notify the so by agreed means regarding the plant availability of each of its centrally dispatched generating units using an availability declaration in the daily status form. the availability declaration shall state the plant availability of the each centrally dispatched generating unit to be applied for the next schedule day and explain any variance from agreed maintenance plans. (b) such availability declaration will replace any previously submitted availability declaration for the same period. (c) embedded generating units e” 2MW not centrally dispatched connected to the IPS will notify by exception, meaning that their last availability declaration will be assumed unless a change of availability is notified. 178 Statutory Instruments 9th January, 2026 (d) embedded generating units < 2MW connected to the IPS are not required to notify availability to the SO. (e) where an agent seeks to combine generating units of registered capacity< 2MW each, the agent shall make the availability declarationto the SO and it is for the agent to form information and control arrangements with the individual power producers. A.1.2 Operating Parameters (a) by a time each day set by the SO, each power producer, controllable load provider, energy storage provider or agent shall notify the SO of any revisions to the operating parameters of each of its centrally dispatched generating units to those parameters submitted under a previous availability declaration. Direct agents shall be entitled to set a separate timetable with power producers, controllable load providers, energy storage providers or agents acting for any of these categories of user. (b) the operating parameters shall reasonably reflect the operating characteristics expected on the schedule day. If not revised, the previously submitted operating parameters shall apply. (c) embedded generating units not centrally dispatched shall notify changes in operating parametersby exception. (d) by a time each day setby the SO, each power producer, in respect of each of its centrally dispatched generating units e”2MW declared available, shall notify the SO or its direct agent by agreed means of the following other relevant scheduling and dispatchdata: (i) details of any special factors which may have a material effect on the likely output of active power or reactive power of such centrally dispatched generating unit; and (ii) any temporary changes and their possible duration, to the operating parameters. (e) if the SO or its direct agent fails to issue a new dispatch instruction within 15 minutes of being notified of a temporary change to that day’s operating parameter then the relevant power producer shall be entitled to change the operation of such generating to bring its operation within the applicable availability and operating parameters until the SO or its direct agent issues a new dispatch instruction within the applicable availability and operating parameters. Prior to making such a change in operation, the power producer will use reasonable endeavors to advise the SO or its direct agentimmediately of its intended action and timing. A.2 Distribution and UserSystem data provided to the SO (a) by a time each day set by the SO, each user with centrally dispatched generating units or an agent representing embedded power producers, will submit to the SOor its direct agent, in agreed form, confirmation of the following in respect of the next schedule day: (i) constraints on its system, which the SO may need to take into account for derivation of the daily scheduleor operation of the IPS.In this context, constraints include any restrictions on the operationof embedded centrally dispatched generating units, as a result of the user’ssystem; and 9th January, 2026 Statutory Instruments 179 (ii) the requirements for maintaining voltage within prescribed limits and reactive power reserves, which the SO may take into account for IPSsecurity reasons. (b) the form of the submission shall be— (i) centrally dispatched generating unit output - active power and reactive power, in each case a fixed value or an operating range, at the low voltage side of the generator transformer for identified centrally dispatched generating units for each hour of the schedule day; and (ii) adjusted in each case for active power by the correction factors applicable for those centrally dispatched generating units to provide output at the points of connection; (iii) in the case of agents making submission in respect of embedded generation; the preferred method is to declare demand and generation separately rather than net demand, however the SOmay form individual arrangements with agents and in all cases the basis of the submission must be clearly stated. A.3 Directly ConnectedConsumer data provided to the SO by a time each day set by the SOeach directly connected end-use customer with a maximum demand greater than 1 MW will submit to the SO or its direct agentin agreed form the end-use consumer’s best estimate of its hourly demand profile by point of connection for the following schedule day.The declaration may be by exception, based upon normal daily and weekly profiles, except that > 1MW end-use customers must provide information for holidays and other exceptional times as requested by the SOor its direct agent. A.4 Redeclarations If at any time between the time each day set by the SOand the expiry of the next schedule day, the user becomes aware of any change to the information submitted it shall promptly notify the SO. A.5 Proving Availability The SO,or on instruction its direct agent,may at any time (but not more frequently than 6 times in a calendar year except as provided for below) require the user to prove that its plant is available to produce output to the extent declared by the user, by instructing the plant to meet the most recently declared availability levels. Whether the plant meets or fails to meet the declared availability levels must be recorded by the SO and advised to theuser. The SO will then record the level achieved by the plant as the maximum availability until the user provides evidence that any problem has been rectified. A.6 Variable Renewable Resource Forecast by a time each day set by the SO, all previous forecasts for the output of all generating units depending on variable renewable resource shall be updated for the next schedule day and shall further be updated so that no forecast is more than 4 hours ahead of the operating time (real time).In addition, the SO shall receive real-time output or a summary of output related to each variable renewable energy plant e”2MW and such local environmental information as enables improved forecasting of the immediate period ahead. A.7 Method of preparing the Daily Schedule (a) The SO shall, when preparing thedaily schedule for centrally dispatched generating units, review: (i) the expected hourly maximum and average demand profiles on the IPS; 180 Statutory Instruments 9th January, 2026 (ii) the declared availability and operating parameters (daily status form) of each centrally dispatched generating unit or summarized declared availability of embedded generating units connected to parts of the IPS; (iii) The declared active power and reactive power capability of generating units; (iv) the expected output profile of embedded generating units and variable renewable resource generating units; (v) other relevant data in respect of each generating unit, as determined by the SO; (vi) SAPP requirements, AGC and operating margin; (vii) system losses and constraints. (viii) ancillary service requirements; (ix) operating standards; (x) Power procurement or contractual data and prices; and (xi) Other factors deemed by the SO to be relevant. (b) In the event that two or more centrally dispatched generating units which are not constrained-on have equivalent costs, the SO will first schedule the centrally dispatched generating unit that will give the highest reduction in overall IPScosts.

3.3.3 Dispatch Instructions to Power Producers (a) each Participant shall have the right to reduce or disconnect a point of connection under emergency conditions if such action is necessary for the protection of life or equipment. Advance notice of such action shall be given where possible and no financial penalties shall apply for such action. (b) the operating parameters used in the dispatch phase shall be those used by the SO to compile the day-ahead generation schedule. (c) dispatch instructions relating to the schedule day shall be issued at any time during the period beginning immediately after the issue of the daily schedule in respect of that schedule day. (d) a dispatch instruction given by the SO or its direct agent may require: (i) synchronisation or desynchronisation of a synchronous generating unit or the operational connection or disconnection of an asynchronous generating unit; (ii) a change in the active power output of a synchronous centrally dispatched generating unit or a constraint in the active power output of a variable renewable resource generating unit; (iii) an instruction to switch on or off AGC on any generating unit equipped with AGC; (iv)a change in the reactive power output of a synchronous centrally dispatched generating unitor constraint in or change in the reactive power setting or mode of operation of a variable renewable resource generating unit; (v) a change to the mode of operation or an instruction to provide an ancillary service by a specific centrally dispatched generating unit; or 9th January, 2026 Statutory Instruments 181 (vi) in certain circumstances (i.e when it is technically not prudent within the operating standards to maintain output or maintain output at the present level), an instructed limit on, reduction, or cessation of output from an embedded generating unit or a variable renewable resource generating unit. (e) in addition, the SO or its direct agent may instruct, directly or by the use of agents, any embedded generating unit e” 250kVA to support the system frequency by: (i) being connected and synchronised to theIPS; (ii) operating according to a dispatched active power output level; or (iii) remaining disconnected from theIPS. (f) All generating units e” 2MW agreed for connection after the first revision of the Codeshall be equipped that the SO or an agent may issue dispatch instructions electronically directly to the plant. (g) A dispatch instruction given by the SO or its direct agentto a power producer may be given by telephone or electronic means. The SO will maintain a list of the type of dispatch instructions which are to be confirmed in writing within 5 minutes and users shall so confirm. Each Participant shall enter all dispatch instructions into their respective logs. (h) in the case of generating units controlled by AGC, the dispatch instructions may also be given by direct signal from the control centre and are then electronically acknowledged by the plant. (i) adispatch instruction must be either formally acknowledged immediately by the power producer in respect of that centrally dispatched generating unit, or a reason given immediately for non-acceptance.The reason for non-acceptance may only be on safety grounds (relating to persons or plant) or because the dispatch instruction is not in accordance with the daily status form relevant to the time and period to which the dispatch instruction relates. (j) adispatch instruction given by SCADA direct signaling to the plant must be acknowledged as received by a signal from the plant and a confirmation signal returned indicating that the action is being taken and a further signal when the action is completed. (k) for a dispatch instruction to be valid, it must observe the limits of availability, ancillary service capability and operational parameters as properly declared to the SO. (l) in the event that an unforeseen problem arises in carrying out the dispatch instruction, the SO must be notified without delay by telephone. (m) the SO shall keep a record power scheduled and dispatched. A.1 Generation Synchronising and De-synchronising times (a) power producers will only synchronise or desynchronise synchronous centrally dispatched generating units in response to a dispatch instruction from the SO. Desynchronisation may take place without the SO’s prior agreement if it occurs automatically as a result of centrally dispatched generating unit or transmission protection operations or it is done purely on safety grounds. (b) the SO shall determine the required timing of synchronising and desynchronising of each synchronous centrally dispatched generating unit. 182 Statutory Instruments 9th January, 2026 (c) if the power producer is unable to meet the synchronising time, it must inform the SO immediately. (d) if the actual synchronising time is later than the instructed time by more than 10 minutes, this will constitute a redeclaration of availability by the centrally dispatched generating unit. Additionally, the SO shall keep a record and inform Energy Regulation Boardand thepower procurer. (e) if the actual synchronising time is early by more than one minute, the SO shall keep a record and inform Energy Regulation Boardand thepower procurer. (f) if the SO issues a dispatch instruction to a power producer, for a centrally dispatched generating unit, which is not in accordance with the data submitted on daily status form, the power producer must immediately contact the SO to indicate the error. The SO will take immediate steps to amend the dispatch instruction. A.2 Additional instructions to Centrally Dispatched Generating Units (a) additional instructions to centrally dispatched generating units may include the provision of reserve as an ancillary service. (b) following the daily schedule and to ensure that an adequate operating margin is maintained, dispatch instructions may include details of reserve to be carried on each centrally dispatched synchronous generating unit or variable renewable resource generating unit, including notification of the timescale in which that reserve may be transferable into increased generating unit output.

3.3.4 Frequency Response (a) All generating units e”250kVA fitted with frequency sensitive mode and connected to the IPSshall respond to an instruction from the SO, or its direct agent, to move into frequency sensitive mode and shall respond according to agreed droop and frequencyramping settings. (b) generating units shall not under normal operating conditions deviate from instructed active power by more than limits set down in their connection agreement. (c) in the case of low frequency response this will be a contracted ancillary service provision. Power producers so contracted shall ensure that their generating units respond in line with the amounts and times in their connection agreement. Frequency response is classified as primary response, secondary response and tertiary response. (d) in the case of variable renewable resource generating units e”2MW connected to the IPS, power producers shall ensure that their generating units accurately respond to an instruction from the SO or its direct agentto move to frequency sensitive mode and follow a Delta control algorithm at settings instructed by the SO or its direct agent Response Category Starts - Hz End - Hz 9th January, 2026 Statutory Instruments 183 (e) generating units with AGC fitted shall respond to a SO request to operate in this mode.AGC mode is subject to contractual or ancilliary service payments(f) in the case of high frequency (above 50.5Hz) response this will be an automatic action for all generating units connected to the IPS, according to a ramp rate reduction of active power. All generating units must have reduced to minimum stable generation by 52Hzand if possible to 0MWoutput but shall not trip until 52.5Hz. (g) allgenerating units may trip at frequencies below 47.5Hz or above 52.5Hz to protect themselves.

3.3.2 Reactive Power To ensure that a satisfactory system voltage profile and sufficient reactive power reserves are maintained, dispatch instructions may include, in relation to reactive power— (a) Reactive PowerOutput- Large SynchronousGenerating Units (i) in the case of large synchronous generating units the SO shall indicate to the power producer whether the power producer is to maintain the required level of reactive power import or export at the generator terminals or the point of connection with the system. (ii) if to achieve the reactive power order the power producer must on-load tap change the generator transformer this shall be agreed. Once tapchanged, the generator transformer may not be tap changed again without the consent of the SO. (iii) the power producer shall not seek to adjust the terminal voltage of the generator without prior permission from the SO except in the case of imminent danger to personnel or plant. This means that the reactive power output once set will vary with transmission system conditions. (b) Reactive PowerOutputfrom Directly Connected A synchronous Generating Unitsand Directly Connected Synchronous Generating Units Connected after the first revision of the Code In the case of directly connected asynchronous generating units and directly connected synchronous generating units approved for connectionafter the first revision of the Code, theSO shall specify the required level of reactive power import or export at the point of connection with the transmission system, and the power producer shall ensure that the targets are met. (c) target voltage levels (i) target voltage levels are to be set for directly connected generating units at the point of connection. The target may be achieved by a combination of— (aa)on load tap changing on the generator transformer; or (bb) adjusting the directly connected generating unit stator terminal voltage or by automatic adjustments made to power electronic convertor in the case of asynchronous generating units. (d) in relation to each directly connected asynchronous generating unit,where there is no HV indication, the arrangements will be set down in the connection agreement— (i) under normal operating conditions, the power producer will not tap the transformer again or adjust terminal voltage settingswithout the agreement ofthe SO. 184 Statutory Instruments 9th January, 2026 (ii) under certain circumstances the power producer may be instructed to maintain a target voltage until otherwise instructed and this will be achieved by on-load tap changing on the generator transformer or adjusting directly connected generating unit stator terminal voltage without reference to the SO or by automatic adjustments made to power electronic convertor in the case of asynchronous generating units. (e) maximum reactive power output (“maximum excitation”) under certain conditions, such as low system voltage, an instruction to maximum reactive power output at instructed active power output (“maximum excitation”) may be given, and a power producer should take appropriate actions to maximise reactive power generation unless constrained by plant operational limits or safety grounds (relating to persons or plant). (a) maximum reactive power absorption (“minimum excitation”) under certain conditions, such as high system voltage, an instruction to maximum reactive power absorption at instructed active power output (“minimum excitation”) may be given, and a power producer should take appropriate actions to maximise reactive power absorption unless constrained by operating parameter limits or safety grounds (relating to persons or plant). (b) in addition— (i) irrespective of the daily schedule, the SO may issue dispatch instructions for active power (from synchronous generating units) and reactive power at any point on or within boundaries of the generator performance chart as modified by any temporary changes submitted in the daily status form; (ii) the issue of dispatch instructions for active power at the connection point of any centrally dispatched generating unit, will be made with due regard to any resulting change in reactive power capability and may in the case of a synchronous generating unit include instruction for reduction in active power generation to enable an increase in reactive power capability; (iii) the excitation system, unless otherwise agreed with the SO, must be operated only in its constant terminal voltage mode of operation with (in the case of synchronous generators) VAr limiters in service. Any constant reactive power output control mode or constant power factor output control mode must always be disabled unless agreed otherwise with the SO. In the event of any change in the system voltage, a power producer must not take any action to override automatic reactive power response that is produced as a result of constant terminal voltage mode of operation unless instructed otherwise by the SO or unless immediate action is necessary to comply with stability limits or unless constrained by operating parameter limits or safety grounds (relating to persons or plant); (iv) a dispatch instruction relating to reactive power will be implemented without delay and shall be achieved not later than 2 minutes after the instruction time, or such longer period as the SO may instruct; (v) on receiving a new dispatch instruction for active power, no tap changing, or directly connected generating unit terminal voltage adjustment shall be carried out to change the reactive power output unless there is a new dispatch instruction for reactive power. In the event of an incompatibility 9th January, 2026 Statutory Instruments 185 between an active powerinstruction and a reactive power instruction, the most recent instruction applies; (vi) where a dispatch instruction to synchronise is given, or where a centrally dispatched synchronous generating unit is synchronised and a dispatch instruction for active power is given, a dispatch instruction for reactive power consistent with the centrally dispatched synchronous generating unit operating parameters may be given. In the case of embedded generating units, the SO shall take due regard of distribution system voltage considerations. In the absence of a dispatch instruction for reactive power with a dispatch instruction to synchronise, the reactive power output shall be 0 MVAr; (vii) where a dispatch instruction to desynchronise is given, a dispatch instruction for reactive power, compatible with shutdown, may be given prior to desynchronisation being achieved. in the absence of a separate dispatch instruction for reactive power, it is implicit in the instruction to desynchronise that reactive power output shall be reduced to 0 mvar by the time of desynchronization; and (viii) in the case of directly connectedasynchronous generating units e” 2MW the SO may issue a dispatch instruction to alter the reactive power control mode and to set the target value and the power producer shall monitor compliance with the dispatch instruction.

3.3.3 Dispatch Instructions to Users with Demand (a) dispatch instructions to users with demand relating to the schedule day shall be issued as a list of special actions in respect of that schedule day at any time during the period beginning immediately after the issue of the generation schedule. the so will issue instructions directly to the users with demand in relation to special actions and demand control. dispatch instructions may include— (i) a requirement for demand reduction, de-energisation or restoration; and (ii) an instruction to affect a load transfer between connection points. (b) the so shall communicate with users with demand in an agreedmanner. (c) each demand user must comply without delay with all dispatch instructions received by it. The SO or its direct agent may not instruct emergency generation unless the subject of a separate agreement. In the event of an unforeseen problem arising that prevents the carrying out of a dispatch instruction, the SO must be notified by telephone without delay and not later than 5 minutes after receipt of the dispatch instruction. The SO shall confirm the notification in writing within 5 minutes of receipt. (d) each Participant shall enter all dispatch instructions sent and received and all events into the respective logs.

3.4.1 Integrated Power System (a) participants shall setup operational procedures fortheir respective networks toensuresafe and efficient operation of the IPS. (b) international tie-line operations shall begoverned by SAPP and other agreements. 186 Statutory Instruments 9th January, 2026 (c) each power producer shall comply with all dispatch instructions correctly given by the SO unless the power producer has given notice to the SO under the provisions of the scheduling and dispatch code regarding non-acceptance of dispatch instructions. (d) each power producer with synchronous generating units must utilise the relevant run-up or run-down rate and loading or de-loading rate in accordance with the operating parameters. (e) to preserve transmission system integrity under emergency conditions the SO may issue emergency instructions. Such emergency instructions issued directly to the power producer and may require an action or response that is outside operating parameters. The power producer will use reasonable endeavours to achieve these emergency instructions without prejudice to the safety of the plant or persons.

3.4.2 SOResponsibilities (a) the SOshall beresponsible forthesafe and efficient operationoftheIPS. (b) the SOshall beresponsible forthe following: A.1 System Reliability, Safety and Security (a) the SOshall operate the IPS under both normal and abnormal conditions to achieve the highest degree of reliability practicable.Where there is afault, remedialaction shall be taken promptly to address any abnormal condition that may jeopardise the reliability and safety of the system. (b) the SOshall dispatch generation on the IPS subject to constraints of security, reliability and the environment and shall— (i) develop daily a generation scheduletwenty-four hours (24) day-ahead energy and ancillary services schedule before14:00 each day; and (ii) be responsible for executing and rescheduling of the energy and ancillary services schedule. (c) the SO shall endeavour to retaininternational interconnections unless itbecomes evident thatcontinued parallel operation would jeopardise theintegrity oftheIPS. (d) where itisunsafe tooperate generating units inparallel with the system when critical levels of frequency and voltage result on the IPS from adisturbance, the SO shall ensure that separation or safe shut down of generating units shall be accomplished insuch away as to minimize the time required to resynchronise and restore the system to normal. (e) during or after a systemdisturbance, high priority shall begiven to keeping all synchronised generating units running and connected to the IPS, or islanded on their own auxiliaries, inorder tofacilitatesystem restoration. (a) where thereislossofallgeneration andinterconnections with neighbouring countries, blackstart services shall be contracted with atleast two suitable facilities. (b) in the event of severe contingency, the SO shall ensure that instability,uncontrolled separation or cascading outages do not occur. (c) the SO shall be responsible for restoration of the IPS after supply interruptions,in accordance with the restoration procedures for the IPS. 9th January, 2026 Statutory Instruments 187 (d) in the event of system disturbances, the SO shall endeavour to minimise adverse effects on customers. (e)the SO shall operate and maintain primary and backup control centers and associated facilities toensure continuous operation ofthe IPS. A.2 RegionalOperator (a) the RO shall be responsible in relation to a part of the systemfor the following- (i) retaining interconnections to the transimission system; (ii) restoration of the transmission system after supply interruptions; (iii) maintaining its primary control centre; (iv) determining transmission systemoperational limits; (v) coordinate maintenance schedules; (vi) ensure reliable communication between its primary control centre and the SO; (vii) ensure reliable communication between its control centres; (viii) ensure establishment of transmission system protection philosophy: (ix) maintaining transmission system protection data base; (x) (xi) development ,implementation and maintenance of operating procedures for its transmission system; and ensuring compliance with emergency and contingency plans in harmony with the SO. (b) theROshall— (i) (ii) operate the transmission system during normal and abnormal conditions; schedule supply on the transmission system; (iii) operate primary control centre; (iv) manage transmission system constraints; (v) issue operations instructions on the transmission system; (vi) verify commissioning programmes of equipment on transmission system; (vii) authorize personnel towork on its transmission system; and (viii) maintain record of bulk supplies.

3.4.3 OperationalAuthority (a) the SO or its direct agents shall have the authority to issue operational instructions over the transmission system and its inter-connectors with other networks in order to guarantee the security of supply of electricity IPS or (in the case of direct agents specified parts of the IPS). Operational authority for the distribution system shall lie withthe respective DNSPs. (b) network control at the interface between the TNSP and a customer shall be in accordance with the operating agreements between the Participants. 188 Statutory Instruments 9th January, 2026

3.4.4 Operating Procedures (a) the SOinliaison withrelevant Participantsshall develop and maintain operating procedures forthesafe,secure andreliable operation oftheIPS andforassets connected totheIPS. (b) Theseoperatingprocedures shall beissued toall Participants.TheSAPP operating agreements shall apply inthecaseofoperationalliaison with all international powersystems connected totheIPS.

3.4.5 OperationalMeasures The SOshall establish and implement operating instructions, procedures and guidelines to cover the operation of the IPS under all system conditions. The SOshall maintain a database with version control of all such documents, and shall— (a) operate the IPS within itsnormalrating and definedtechnical standards. (b) manage constraints on the IPS through the determination of operational limits and the purchase of the constrained generation ancillary services where applicable. (c) co-ordinate maintenance schedules ofplant and equipment on the IPS and ensure that subsequent planned outages do not violate the reliability criteria of the IPS. (d) ensure adequate and reliable communication between all control centres,power production facilitys and substations. communications facilities to be provided and maintained by the customers are specified in the Information Exchange Chapter. (e) ensure the establishment of a common protection philosophy for the IPS as required by the Transmission System Chapter. (f) review protection settings on the IPS, after system alterations, and shall maintain an updated data base of these settings.

3.4.6 Ancillary Services The SO shall— (a) beresponsible forthe provision ofallshort-term reliability services forthe IPS; (b) determine reliability targets for the purpose of acquiring ancillary servicesin consultation with affected Participants. Thereliability targets shall beselected so astominimise the sum of the cost of providing the reliability plusthecost tothe customer of limited reliability. The cost of providing suitable ancillary service levels shall be calculated annually for budgetary purposes; and (c) be responsible for procuring the required ancillary services needed to provide the required reliability. (d) The SO shall develop for approval by Energy Regulation Boarda procedure for reimbursement of costs incurred for the provision of cost

3.4.7 Voltage control (a) theSOshallberesponsible forthe voltage control oftheIPS, attransmission level voltages aswell asatthe interface between theTNSPs themselves andbetweenthe TNSPs and their customers. (b) IPSvoltages shall becontrolled during normal operationtobewithinstatutory limits atthepoints of supply and otherwise asagreedwith customers. 9th January, 2026 Statutory Instruments 189 (c) thebilateral agreement for voltage and power factor control at the TNSP- TNSPboundary shall be submitted to the Energy Regulation Board for approval.

3.4.8 Conditions IPSSystem FrequencyandACEControlUnder Abnormal Frequency orImbalance The SO shall be responsible forthe balancing ofsupply and demand inreal timethrough theimplementation ofthe energyschedules,dispatch instructions andutilisationofancillary services. A.1 Description of Normal Frequency or Balancing Conditions TheIPSisconsideredtobe under normal frequency conditions when— (a) the immediate demand can be met with the available scheduled resources, including any contingency resources; (b) the frequency is within the range 49.85 to50.15Hz; and (c) there are no security or safety contraventions. A.2 operation during abnormal conditions (a) when abnormalconditions occur, therelevant Participants shalltakecorrective actions asstipulated inForm VI set out inAppendix 4 whichgives guidelines onoperation duringabnormal conditions. (b) the corrective action includes both supply-side and demand-side options. Where possible, warnings shallbeissued bytheSOonexpected utilisation ofanycontingency resources. (c)the order in which emergency resources are to be used may change from time to time based on contractual arrangement and equity considerations. The SO shall issue an updated list of emergency resources available annually. (d)termination oftheuseofemergency resources shall occur as the plant shortage situation improves and after frequency has returned to normal in the order that the most essential end-use customers shall be restored first unless other arrangements are implemented by agreement with Energy Regulation Board as part of rota load shedding. (e) during emergencies that require load shedding,the request to shedload shall be initiated in accordance with agreed procedures prepared and published by the SO and agreed by Energy Regulation Board. (f) automatic under-Frequency systems shall be kept armed atall times, apart from gas turbines,which shall be armed by the SO when a shortage isexpected. (g) following such emergency operations as may be necessary to protect the integrity of the IPS or the safety of equipment and human life,the Participants shall work diligently towards removing the cause of the emergency and the supply shall be reconnected immediately after the emergency conditions have passed. 190 Statutory Instruments 9th January, 2026 CHAPTER4 INFORMATION EXCHANGE

4.1 InformationExchangeInterface (a) for each type of information exchange, parties shall provide at the least the following information: (i) (ii) (iii) thename and contact details oftheperson(s) designated bythe information owner to beresponsible forprovision ofthe information; thenames andcontact details ofandtheparties represented bypersons requestingthe information; and the purpose for which the informationisrequired. This does not applytopost- dispatch information. (b) the parties shall agree on appropriate confirmation procedures for the transfer of information. (c) the means of exchange of information may involve any non-transitory or written form including facsimile and electronic communications. Immediate operational information forming operational instructions which is given verbally shall be repeated and written down by the Participants and the record retained for the periods stated under this Code.

4.2.1 Objective (a) the objectives of system planning information are provided in the Transmission System Chapter and these include,to- (i) provide interaction ofDNSP’s or end-use customers’planned system with the IPS; (ii)provide information for the IPS tosupply DNSPs and end-use customers for system planning and development; (iii) facilitate existing and planned connections; and (iv) to provide faultcondition information. (b) system planning information is divided into standard data and detailed data as explained in the Transmission System Chapter.

4.2.2 Information required by Customers (a) the TNSP shall provide customers orpotential customers,on request, with any relevant information that they require to properly plan and design their own networks or installationsorcomply with their obligations in terms of this Code. (b) theTNSPshall make available all the relevant information related to network planning as described in the Transmission System Chapter.

4.2.3 Information required by Power Producers (a) theTNSP shallprovide power producers with information about equipment andsystems installed in the HVyards defined inForm VII set out in Appendix 4. 9th January, 2026 Statutory Instruments 191 (b) the TNSPshall provide the power producers with monthly rolling maintenance schedules forallplanned work in HV yards for a period of one year in advance. (c) log books on all vessels under pressure for receivers installed in HV yards shall be made available on request from the power producer.

4.2.4 Information required byTNSPs (a) customers may be required by aTNSP to provide information for reasons that include, but are not limited to— (i) planning and developingtheIPS; (ii) monitoring current and future powersystem adequacyand performance; or (iii) fulfil its statutory or regulatory obligations. (b) customers shall providethe information required, without unreasonable delay and as theTNSP may request onaregular basis. (c) customers shall submitthe information in the following Schedules totheTNSP: (i) Appendix 2, DNSP and end-use customer data; and (ii) Appendix 3, generator planning data; and (iii) Appendix 7, generator maintenance data. (d) customers shall, on request to upgrade anexisting connection or when applying for a new connection, provide theTNSP with information as outlined in Form VIII set out in Appendix 4. (e) theTNSP mayestimate anysystem and connection planning information or any maintenance planning information not provided byacustomer.The TNSP shall take reasonable steps to reach agreement with the customer on estimated data items. TheTNSPshall indicate tothe customer all such estimated data items. The obligation toensure the accuracy of the data remains with the customer. (f) power producers shall submit weekly updates tothe relevant TNSP and SO all the maintenance planning informationset out inAppendix 7 with regard toeach generating unit ateachpower production facility.

4.2.5 InformationrequiredbytheSO (a) participants shall provide the SO with updated technicaldata required for studying thebehaviour oftheIPS. (b) the SO shall be entitled to request any of the planning information in tables A to K set out in Appendix 2. (c) tables A to J set out inAppendix 2 are relevant to the users of each type. (d) table A set out in Appendix 2is a summary of the data Schedules requested or supplied and may be required from any user. (e) the TNSP required data from tables B to F set out in Appendix 2 are to be completed by users with demand and includes data for users with controllable demand and demand transfer capability. 192 Statutory Instruments 9th January, 2026 (f) the TNSP required data from tables F to I set out in Appendix 2 are to be completed by power producers. (g) the TNSP required data from tables H and I set out in Appendix 2are to be supplied by users with relevant facilities. Table H set out in Appendix 2 refers to power producers with synchronous generating units and table I set out in Appendix 2to power producers with asynchronous generating units. (h) the TNSP required data from table J set out in Appendix 2are to be supplied by users with energy storage units. (i) all users must complete details of their location, interface equipment and interface protection. Additionally, users with HVor EHV equipment must on request provide sufficient information to enable the SO to assess transient overvoltage analysis. This information is in tables A and Bset out in Appendix 2. (j) users with HVor EHVconnection arrangements must provide details of their interface equipment and ownership and control diagrams and additionally record the drawing references on table Bset out in Appendix 2. (k) users must provide and maintain as current, a list of senior managers, safety co- ordinators, competent persons and a nominated person in case of emergency and must provide a means of contact with those persons. (l) on request from the SO, a user shall supply sufficient details with respect to the user or transmission system ownership boundary to enable an assessment to be made of transient overvoltage effects. (m) prior to connection, a user must supply an itemised statement of compliance with the connection conditions and such other Code matters as apply to that user. The statement of compliance must be provided in a format approved by the SO (n) the SO has the right to require any or all of the following data from users.Where the SOrequires the data the user must provide it as below. A.1 User’s with Demand (a) users with demand must also provide the information in table Cset out in Appendix 2 of the connection conditions. (b) users with demand are required to provide demand patterns and forecast demand for each of the five succeeding calendar years as set down in table D and Eset out in Appendix 2 of the connection conditions and to update these tables annually. Users must complete and submit these tables whether or not they reasonably believe there will be a change in the present data. (c) users with large motors, which contribute, to fault levelon thetransmission systemshould complete table Fset out in Appendix 2. A.2 Users with Controllable Demand and Demand Transfer capability (a) users with controllable demand are required to complete the appropriate clause of table Eset out in Appendix 2, which indicates how much of their demand is controllable and any special features or limitation of the demand or control arrangement. Users must also state the period of any contracted arrangement to control the demand and any contractual limitations. 9th January, 2026 Statutory Instruments 193 (b)users withdemand transfer capability(where the samedemand can be supplied from alternateuserpoints of supply) shall provide, and keep updated, information relating to that demand including the proportion ofdemandnormally fed from each point of supply and the arrangements (manual or automatic) for transfer under planned or fault outage conditions as in table Eset out in the Second Schedule. A.3Users with Disturbing Loads Users with disturbing loads including DC drives should first seek information about the fault level at theirpointof connection to the transmission system must then provide the information in tableC set out in the Second Schedule together with evidence of the assessment. A.4 Power Producers (a)users with generating units must advise which of their generating units are traditional generating units synchronous and which are asynchronous. (b) power producers must complete table F set out in Appendix 2 indicating their fault level contribution. Power producers must complete table G, H or I set out in Appendix 2 for each generating unit showing the characteristics of that generating unit and must additionally complete a schedule indicating the maximum capability of the entire site (which could in certain circumstances be less than the sum of the generating units located on the site). (c) table H set out in Appendix 2 requiresusers to define the fuel or renewable source and, if fossil fuel is used, any intended pattern of use of the generating units. (d) the tables also require users to provide sufficient information to allow the SO to conduct fault level, transient and dynamic studies. (e) the SO will use the information provided to model the generating unit to determine a technically acceptable method of connection. If the SOreasonably concludes that the nature of the proposed connection or change to an existing connection requires analysis that is more detailed then further information than that specified in the schedules may be required. (f) power producers are also required to indicate whether they intend to add or retire generating units within the following five-year period. unless changed from previously submitted data, power producers need not re-submit, on an annual basis, the standard data and detailed- data for their generating units. A.5 Users with both Demand and Generating Units Users with demand and generating units shall complete the appropriate schedules for each. The SOmay seek further information regarding the pattern by which users intend to offset their demand or deliver energy to the network. A.6 Users with Energy StorageGenerating Units An electricity storage generating unit is at times a generating unit and at times demand or controllable demand. The appropriate tables are therefore to be completed by such users taking account of any expected deterioration in performance over the subsequent five-year period. A.7 Users with electric vehicle charging This type of connection is treated as one of demand, controllable demand, or controllable demand with a generating unit, depending on whether it is possible to use the stored energy in the 194 Statutory Instruments 9th January, 2026 vehicle batteries to re-supply the distribution system. The user should complete the appropriate tables for demand, controllable demand and the relevant power producer set out in Appendix 2.

4.3.1 Pre-Commissioning studies (a) participants shallmeetall systemplanning informationrequirements beforethe commissioning testdate,suchasconfirming anyestimated values assumed forplanning purposesor,where practicable,replacing them with validated actual values andwith updated estimatesfor the future. (b) the SO shall perform pre-commissioning studies prior to sanctioning the final connection of new or modified plant. Such studies shall utilise data supplied by customers inaccordance withthis Code, toverifythatallcontrol systems are correctly tuned and planningcriteria have been satisfied. (c) the SO may request adjustments prior tocommissioning shouldtuning adjustments be found to be necessary. The asset owner shall ensure that all system planning informationrecords aremaintained forreference fortheoperational lifeoftheplant. Information shall bemade available within reasonable time onrequest fromthe SO.

4.3.2 General Information requirements (a) measurements and indications to be suppliedby Participants tothe SO shall bepresented insuch form asmaybe prescribed bythe SO.These shall include, butnot belimitedto, the standards set out in Appendix 8. (b)where required signals become unavailable ordonotcomply withapplicable standards forreasons within the control ofthe provider oftheinformation, such aParticipant shall report tothe SO and restore or correct the signalsorindicationsas soon as practical. (c)following amodification totheIPS,additional measurements orindicationsinrelation to aParticipant’splant and equipment maybe needed tomeettransmission systemrequirements. In such an instance the SOshall notify the affected Participants. The costsrelated to suchmodificationsshall beonaccount oftheParticipant effecting themodification. (d) On receipt ofsuch notificationfromtheSOtheParticipant shall promptly ensure that suchmeasurements orindications aremade available atthe RTU. (e)the data formats tobeused andthefields ofinformationtobesupplied totheSOby thevarious Participants shall beasset out in Appendix 8ofthis Code. (f) theTNSP shall provide feedback tocustomers regarding thestatus ofequipment and systems installedinthesubstations where they areconnected tothetransmission system onrequest. AgreementsbetweenPartiesshalldetermine thedetails andfrequency ofsuchfeedback. (g) plant status reportsprovided bytheTNSP willalso includecontingency plans where applicable. (h)in the network where out-of- step relays are installed,the SO shall inform customers how the relays are expected to operate. The characteristics of such an islanded network shall be provided,based onthemost probable local network configuration at such a time. 9th January, 2026 Statutory Instruments 195

4.3.3 Commissioningandnotification (a) participantsshall jointly notify the SO aboutthe results of the verification of all measurements orindications forfunctionality and accuracy onceevery fiveyears,so astoachieve overallaccuracy ofoperational measurements with in the limits agreed. (b) commission ingrecordsshallbemaintainedforreference by the SO for the operational life of the plant and shall be made available, within are as on able time, to anyParticipant onrequest. (c) the assetowner shall communicate changes made to commissioned equipment, during an outage,to the SO and the relevant TNSP, before the equipment is returned to service.The TNSP shall keep commissioning records of operational data as set out in the Eighth Schedule,for the operational life ofthe plant connected to theIPS.

4.3.4 InterControl Centrecommunication This is communication betweentheSOandcustomercontrol centres. Fornormal and abnormalconditions, the following shall apply: A.1 Normal Conditions (a) control centres shall, upon request,provide each other with network information required for the security,safety, reliability and integrity oftheIPS. Suchinformation exchangeshall be electronic or paper-based withinthe time frameagreedupon by Participants. (b) participants shall optimiseredundant control centre facilities where required inorder toensure thesecurity oftheIPS anditssafe operation. A.2 Abnormal Conditions in abnormal conditions, communication shall be limited to the level necessaryto enabletheSOreturntheIPStoitsnormal condition. Allcontrol centres willtherefore berequiredtoawait operational instructions from the SO, except insituationswhere aParticipantisislanded, inwhich casethe Participant would assume control ofthe Participant’sfrequency and voltage, and await synchronising instructions from the SO. Inexceptional situations, when acustomer’snetwork needs support from the IPS,theyshallcommunicatethenetwork status, andthekind ofsupport needed. A.3 Communication facilities requirements The communication facilities for voice and data that aretobeinstalled and maintained between the applicable IEC standards the SO and Participants shall comply with forSCADAandcommunications equipment- (a) Tele-control (i) theinformation exchange shall support dataacquisitionfromRTUs, SCSs and PCSs.The SO shall monitor the state of the IPSvia telemetry from the RTUconnectedtotheParticipants’ plant. (ii) the signals and indicationsrequired by the SO are definedin Appendix 8,togetherwith suchother information asthe SO may, bynotice tothe Participant reasonably require fromtimetotime. (iii) participants shallinterface viathestandard digital interfaces, as specified bytheSO. Interface cabinets shallbe installed inthe Participants’ plant and equipment room if required. The provision and maintenanceofthewiring and signalling 196 Statutory Instruments 9th January, 2026 from theParticipants’ plant andequipment totheinterface cable shall betheresponsibility ofthe Participant. (iv) the capability for the SOtodeactivate and reactivatethe scanning of agivenRTU shall beprovided bytheParticipants, as shall the capability ofmonitoring theavailability ofall RTUcentrally. (v)participants shallcomply withsuchtele-controlrequirements asmay be applicabletotheprimary control centre and, as reasonably required, totheemergencycontrol centre ofthe SO. (b) telephone orfacsimile (i) eachcustomer shallberesponsible fortheprovision andmaintenance ofatleast one telephone and one facsimile machine and these shall be reserved for operational purposes only.These facilities shall be continuously attended and answered without undue delay. (ii) the SO shall use avoice recorder for historical recording of all operational voice communication with Participants. These records shall beavailablefor at least threemonths after which they may be disposed of.The SO shall make the voice recordsof anidentified incident available within areasonabletimeperiod after such arequest from aParticipant orthe Energy Regulatio Board. (c) Electronic mail The Participants shall provide each other with electronic mailing addresses ofcontact persons asdefined inthis Code. A.4 SCADA and Communication Infrastructure at Points of Supply (a) Accessand Security (i)theSOshallagree with Participants the procedures governing Security and access to the Participants’SCADA, computer and other communication equipment.The procedures shall allow for adequate access to the equipment and information by the SO or its nominated representative for purposes of maintenance, repair, testing and the taking of readings. (ii) each Participant shall designate a person with delegated authority to perform the duties of information owner in respect of the granting of access to information covered in this Code t othird parties , and shall disclose that person’s name and contact details to the Energy Regulation Board. Each Participant may, at its sole discretion, designate more than one person to perform these duties. (b)Time Standards all information exchange shallbeGPS satellitetimesignal referenced.The SO shall ensure broadcasting of the standard time to relevant telecommunication devices in ordertomaintaintime coherence. (c)IntegrityofInstallation The Participant shall be responsible for optimising th ereliability and Security of the facilities to comply with the SO equipment and OEM minimum requirements.This includes the provision, at no charge to the SO,of an uninterruptible power supply with an eight-hour standby capacity. A.5 DataStorageandArchiving 9th January, 2026 Statutory Instruments 197 (a) the obligation for data storage and archiving shall lie with the information owner. (b) the systems must provide for clear and accessible audit trailsonall relevant operational transactions. All requests that require an auditon a system shall be undertaken with reasonable notice to the parties. (c) the information owner shall keep all information for a period of atleast five years, unless otherwise specified in this Code,commencing from the date the information was created. (d) the parties shall ensure security against unauthorised access,use and loss of information. (e) parties shall store planning information that is kept electronically for at least five years or for the life of the Plant or equipment concerned, which ever is longer. (f) the SO shall store operational informationina historical repository sized for 3 years data.The data includes: (i) transmission systemtime-tagged status information, change of status alarms and event messages; (ii) hourly scheduling and accounting information; and (iii) operatorlogsandoperations. (g) An audittrail of all changes madeto archive data should be maintained. This audit trail shall identify all changesmade, and thetime anddate ofthe change.The audit trail shall include both before and after values of all content and structure changes.

4.4.1 SystemInformation The SO shall provide Participants,with at least the following system informationon request: (a) hourly systemtotalMW loading; (b) hourly individual power production facility MWsent out; (c) hourly system constraints and constrained generation; (d) hourlyinternationaltie-linepowerflow;and (e) systemload flowdata.

4.4.2 GenerationInformationsettlement participants shall meet atleast every three months to reconciIe generation information. Should this information be classified as confidential, both parties shall treat it accordingly.

4.4.3 AdditionalPost-Dispatch Information The SOshall provide operationalinformationto the power producersregarding station dispatch and overall dispatch performance asspecifiedinForm IX set out in Appendix 4.

4.4.4 Half-hourlydemandMeteringdata 198 Statutory Instruments 9th January, 2026 TheTNSP shall provideParticipants with half-hourly metered datapertaining totheir installations.

4.5 File Transfers (a) the format of the files used for data transfer shall be agreed and defined by the supplier and receiver of the Information. (b) the parties shallkeeptheagreednumber offiles forbackup purposessoastoenable therecovery ofinformation inthecaseofcommunication failuresasshowninForm X set out in Appendix 4.

4.6.1 Generating Unit performance data (a) generators shallprovide theSOwithmonthly-agreed performance indicatorsinrelation toeach generating unit ateach power production facility asset out in Appendix 5. (b) power producers shall report significant events, such ascatastrophicfailures, totheSOwithin seven (7) days ofoccurrence ofsuch anevent. The SO shall report to the Energy Regulation Board within 24 hours of receiving such information.

4.6.2 DNSP and End-use Customers Performance (a) the performancemeasurement ofallDNSPs and end-use customers shall be in accordance with Zambian Standard ZS387, Electricity SupplyPowerQuality and Reliability. (b) DNSPs shallreport periodic testing ofunder-frequency load shedding relays in the format giveninForm XI Set out in Appendix 4.

4.6.3 TNSP and SO Performance (a) the TNSP and SO shall make available performance indicators listed inForm XII set out in Appendix 4,monthly to the Energy Regulation Board and customers. (b) the TNSP shall provide to customers all performance indicators at each point of supply inaccordance withTransmission System Chapter.

4.6.4 System operation Performance Information (a) the SO shall make the following IPS operational information available to all participants in the following manner: (i) daily as follows: (aa) the hourly actual demands of the previous day(MW); and (bb) the reserve a mounts over the morning, midday and evening peaks of the previousday ( MW); (ii) monthly as follows: (aa) MWgenerated, imports, exports, available for distribution/sale and transmission losses; (bb) generaticn plan; availability; (cc) regulating reserve hours deficit over total hours; (dd) number offrequency excursions; 9th January, 2026 Statutory Instruments 199 (ee) report for each abnormal network condition and the action taken by the SO to restore normal operations; and (ff) network constraints as reported by the TNSP; and (iii) annually as follows: (aa) annualpeakMW,dateandhour; (bb) annualminimumMW,dateandhour;and (cc) externalreliabilityloss factor (ERLF). (b) Following a transmission system disturbance , the TNSP shall make available all information collected via recorders installed at substations, to the SO for analysis within seven days of the date of the occurrence. Thereafter the SO shall compile a report that shall be available to affected customers on request.

4.7 Confidentiality ofInformation (a) information exchanged between parties governed by this Code shall be confidential, unless otherwise stated but nothing in this clause shall prevent a licensee performing its licence duties. (b) information received as part of a connection application is confidential up to the time when the applicant accepts a proposal from the TNSP to be connected.Thereafter the information becomes the background against which the system is planned and other connections are assessed. A user may define certain information (usually detailed data) as confidential and that information shall be so treated, as required under this section of the Code. (c) confidentialinformation shall not betransferred toathird party without the written consent ofthe information owner.Partiesshallobservetheproprietaryrightsofthird parties for the purposes of this Code. Access to confidential information within the organisations of parties shall be provided as reasonably required. (d) parties receiving information shall use the information only for the purpose fo rwhich it was supplied. (e) theinformation owner may request the receiver of information to enter intoa confidentiality agreement before confidential information is provided.Aproforma agreement is included inForm XIV set out in Appendix 4 ofthisCode. (f) theParties shall take all reasonable measures to control unauthorised access to information and toensure secure information exchange.Parties shall report any leak of the Information that is governed by a confidentiality agreement, assoonaspracticable after it be comes aware to the leak, and shall provide the information owner with all reasonable assistance toensure itsrecovery ordestruction, asdeemed appropriateby the information owner.

4.8 Security of Information Systems It is a duty of the SO to ensure that the control andoperational arrangements are secure and a duty of the TNSP to ensure all non-public information is secure. All Participants shall be required to co-operate in any reasonable precaution, test or audit to ensure that information is secured against unauthorised access or cyber threats.The Parties shall agree how costs are to be met for tests and for information system security measures. The matter shall be decided by Energy Regulation Board if there is a failure to agree. 200 Statutory Instruments 9th January, 2026 CHAPTER 5 GENRAL PROVISIONS

5.1 Compliance Audits (a) aParticipantmay, where another Participant fails to comply with any provision of this Code, requesttheEnergy Regulation Boardtoconductanauditofthat Participant. (b) despite paragraph (a), a Participant shall not make arequest for an audit relating to the same failure within six months of a previous audit request. (c) a request made under this paragraph shall include the following information: (i) the provision of the Code which has not been complied with; (ii) the name of the representative appointed by the requesting participant to conduct the audit; and (iii) the date and time at which the informationis required. (d) a Participant against whom a request is made under this paragraph may, where the Participant believes that the request is frivolous or vexatious,declare a dispute and refer the dispute to the Energy Regulation Board in accordance with this Code. (e) a Participant shall not unreasonably withhold any relevant information requested for by the Energy Regulation Board during a compliance audit. (f) aParticipant shall, when requested by theEnergy Regulation Board, provide the Energy Regulation Board with access to all relevant documentation, data and records that is required for purposes of conducting a compliance audit. (g) the cost of the audit referred to under paragraph (a) shall be borne by the Participant— (i) who requested for the audit, if the findings of the audit are that the other Participant is compliant with the Code; or (ii) against whom an audit request is made, if the findings of the audit are that the Participant is not compliant with the code.

5.2 Exemption (a) a Participant may apply to the Energy Regulation Board for exemption from any provision of this Code using Form XV set out in Appendix 4. (b) an application for exemption under paragraph (a) shall be made on the following grounds: (i) facilitate transition through interim arrangements; (ii) tofacilitate temporary conditions necessitating exemption; (iii) contractual obligations such asPPAs entered into prior tothe coming into effect of this Code; or (iv) where the system security benefits derived from compliance are small and the cost of compliance is large. (c) the Energy Regulation Board may exempt a Participant referred to under paragraph (a) from any provisionof this Code on terms and conditions that the Energy Regulation Board determine. 9th January, 2026 Statutory Instruments 201 (d) The Energy Regulation Board shall, where the Energy Regulation Board rejects an application under paragraph (a), inform the applicant of the decision in writing.

5.3 Complaint Reporting and Dispute Resolution The procedure for handling disputes arising fromthe implementation of the Code shall be asfollows.

5.3.1 Complaint Reporting (a) acustomer may, where an incident in relation to the provisions of this Code occurs notify, in writing, theservice provider of the incident. (b) the service provider shall, on receipt of the notice referred to under paragraph (a)— (i) give reasons for the occurrence of the incident; (ii) state what has been done to address the incident; and (iii) indicate what action the service provider shall take toavoid such anincident inthe future. (c) aservice provider may, where a customer fails to comply with the requirements of this Code, notify the customer of the failure, in writing. (d) the customer shall, on receipt of the notice referred to under paragraph (c), provide theservice providerwithreasons forthefailure and,where appropriate, indicate themeasures thatwillbetaken toaddress theproblem that caused the failure to comply with the provision of this Code. (e) a service provider shall keep alogofallnotices received and all notices served oncustomers. (f) notices areoperational innature and generally require action only bytechnical and customer-relations staff.

5.3.2 Non-Conformance Report (a) a customer or service provider may, after issuance of the notice referred to under this paragraph 5.3.1, issue a non-conformance report to the Energy Regulation Board, where the - (i) customer or service provider fails toprovide the appropriate feedback tothe notice; (ii) customer or service provider willfully misrepresents the facts concerning the occurrence of the incident; (iii) (iv) customer or service provider fails to implement the agreed preventative actions within the time frameagreed bythe parties; thenumber ofnotices becomes excessive inrelation tohistorical performance; or (v) the recommendation of a mediation by the Energy Regulation Board are notadhered to. (b) a customer or service provider shall, where a non-conformance report is issued to the Energy Regulation Board in accordance with paragraph (a), serve the non- conformance report on the other party. 202 Statutory Instruments 9th January, 2026 (c) the Energy Regulation Board shall, on receipt of the non-conformance report referred to under paragraph (a)— (i) advise the parties to resolve the issue through negotiation; (ii) take action interms oftheprocedures forhandling licensing contraventions; or (iii) advise theparties toconsider any other action that the Energy Regulation Board may determine. (d) the parties shall, where the parties, following the negotiation under paragraph (c)(i) agree to address the responsibilities that are subject of the non-conformance report, implement remedial action within an agreed time frame. (e) the parties shall, where the parties fail to resolve the issues in a non-conformance report within time frame agreed on by the parties, declare a dispute.

5.3.3 Disputes (a) a customer or service provider may only refer a dispute to the Energy Regulation Board after complying with the requirements under paragraphs 5.3.1 and 5.3.2. (b) a Participant shall, where adispute isreferred to the Energy Regulation Board, provide the Energy Regulation Board with the following information: (i) thefull history ofrelevant incident reports; (ii) thedetailed non-conformance report andaccompanying information that gave rise tothedispute; and (iii) awritten report fromeach Participant detailing thereason fornot being ableto resolve the issues raised under the non-conformance report. (c) The Energy Regulation Board shall record the disputes received under this paragraph inaccordance Form XVI set out in Appendix 4. (d) The Energy Regulation Board shall take into account the following when considering a dispute under this Code: (i) the manner inwhich the problem was addressed at each stage before a dispute was referred to the Energy Regulation Board; (ii) how thoroughly theproblem hasbeen studied byboth parties; (iii) what action has been taken by the parties; (iv) the actual cost, environmental impact orother impact, ontheparties; (v) whether the complaint isreasonable; (vi) whether atimeframe cannot beagreed forresolving the non-conformance report; (vii) existingandhistoricalperformancetrends of the parties; (viii) reference to relevant standards; (ix) the appropriate network design or operation standards; (x) adevelopingdatabaseofprecedentswithsimilarevents; and (xi) historicalagreementsbetweentheparties. 9th January, 2026 Statutory Instruments 203 (e) the Parties may, where mediation under this Code fails, explore other dispute resolution mechanisms. (f) the Energy Regulation Board shall, wherethe Energy Regulation determines that the subject of a dispute can only be addressed by amending theCodeor any rules or processes developed to implement the Code, advise the parties accordingly.

5.4 Register (a) The Energy Regulation Board shall keep and maintain a register of- (i) participants registered under the Code; (ii) participants who have been exempted under the Code; (iii) disputes resolved under the Code; and (iv) any other register under this Code that the Energy Regulations Board may determine. (b) A register referred to under paragraph () shall contain – (i) information as may be determined by the Energy Regulation Board; and (ii) in the case of a register of Participants exempted under the Code, the nature oftheexemption and itsduration. (c) aregister referred to under paragraph (a) shall be in Form XVII set out in Appendix 4. 204 Statutory Instruments 9th January, 2026 APPENDIX 1 (Chapter 1- Transmission System) Surveying Monitoring and Testing of Users Installations A.7.1 Introduction This section specifies the procedures to be followed in carrying out surveying, monitoring or testing to confirm: • • A.7.2 Scope compliance by Users with the Grid Code provision by Power Producers of ancillary services that they are required or have agreed to provide. This Appendix 7 applies to Users (including Power Producers with Synchronous and Asynchronous Generating Units) to prove performance requirements as required in the Grid Code. Power Producers includes Centrally Dispatched Embedded Power Producers and other Embedded Power Producers so advised by the SO in their Connection Agreement or other form of agreement. A.7.3 Request for surveying, monitoring or testing for all Users The SO may issue an instruction requiring: • any Directly Connected User or DNSP to facilitate TNSP’s monitoring and testing, or to carry out monitoring or testing of its interface protection and power quality emissions at any time. The SO shall provide reasonable notice of its intention to have the facility monitored, reasonableness having regard to the time needed to make arrangements for the monitoring and testing and whether the SO suspects that there are serious issues for the Total System or other Users. A.7.4 Request for performance surveying, monitoring or testing for all Centrally Dispatched Power Producers The SO may issue an instruction requiring: • a Centrally Dispatched Power Producer to carry out a test, at any time. The SO may not request the test sooner than 48 hours from the time of instruction. The purpose of the test is to demonstrate that the relevant Power production Facility and any Generating Unit therein complies with the Grid Code technical performance requirements. A.7.5 Ongoing monitoring of each Centrally Dispatched Generating Unit’s performance Power Producers shall monitor each of their Generating Units during normal service to confirm ongoing compliance with the applicable parts of the Grid Code. Any material deviations detected must be reported to the System Operator within five working days. Power Producers shall keep records relating to the compliance by each of their Generating Units with each section of the Grid Code applicable to that Generating Unit, as proven by tests stated in this Appendix 7. These tests set out such information as the System Operator or TNSP reasonably requires for assessing Power System performance under normal and abnormal conditions. 9th January, 2026 Statutory Instruments 205 A Power Producer shall provide to the SO a report, in January of each year, detailing during the past 12 month period the compliance or non-compliance in any material respect for each of its Generating Units with every section of the Code. A.7.6 Information Exchange Information supplied to the TNSP will be shared with the SO. Users shall inform the SO and TNSP when User planned routine testing will be carried out. This is to allow the SO to assess System risks and to inform the User if any change is to be made to the time when the test may be varied out and to advise of any change to interface settings following the testing. A.7.7 Procedures A7.7.1 Interface Protection systems Applicable to All Users Parameter Protection function Reference Section 2.1.11.9 APPLICABILITY AND FREQUENCY OF TEST Prototype study: For all new Directly Connected, Users or following major refurbishment or upgrade of Circuit Breaker arrangement or Protection systems. ROUTINE REVIEW PERIOD: All Directly Connected Users to confirm compliance every five years. PURPOSE To ensure that the relevant Protection functions at the interface position with the Total System are co-ordinated and aligned with the System requirements. PROCEDURE Prototype:

1. Establish the System Protection function and associated trip level requirements as agreed with the TNSP in the Protection Philosophy Statement and further confirmed in the Connection Agreement or latest amendment to the Connection Agreement

2. List that all equipment is present and connected.

3. Confirm that all primary protection is functioning as intended, e.g. by primary current injection testing and secondary injection tests and record performance of unit, and non-unit protection schemes for main and back-up protection functions.

4. Ensure that any directional protection is functioning and that voltage signals are present and correctly configured.

5. Ensure that protection of inductive or capacitive devices at the interface position is performing as intended.

6. Ensure that any overall facility, or Plant, Loss of Mains protection is operating as intended.

7. Test that circuit breakers trip (and reclose where appropriate) on receipt of appropriate signals and manually from operational trip locations.

8. Ensure that any indication fitted to circuit breaker bays to measure voltage, current and the number of circuit breaker operations or resettable number of operations is functioning as intended.

9. On completion of testing, confirm record and initial or sign that the agreed settings have been applied or re-applied and that all links removed for testing have been restored. 206 Statutory Instruments 9th January, 2026 REVIEW PROCESS:

1. Review Items 1-9 above. The review of item 2 is to ensure that no intermediate action has taken place to remove and repair a protective device, whereby the device has not been restored or properly restored. ACCEPTANCE CRITERIA All Protection functions are set to meet the necessary Protection requirements as set down in the latest schedule to the Connection Agreement. All secondary protective devices and current and voltage measuring Protection Devices are functioning as intended and are within specified tolerances. All circuit breakers are operating as intended. The test engineer has confirmed that all protection has been properly returned to service. REPORTING Submit a report to the TNSP and System Operator as part of commissioning programme for a prototype study or within 1 month of completion for 5-yearly for routine tests. Submittals to the TNSP and System Operator are for acceptance and updated record and should contain one original master copy and one working copy. ACCEPTANCE TNSP A7.7.2 - Power quality -All Directly Connected Users (including DNSPs) Parameter

1. Power Quality monitoring Reference Section

2.1.11.15 Description APPLICABILITY AND FREQUENCY OF TESTING New Directly Connected Users with disturbing equipment (including Power producers with Asynchronous Generating Units) and existing Users of the TS when so notified by the TNSP. ROUTINE TESTING / REVIEW PERIOD: Confirm compliance every 6 years. PURPOSE To confirm that the limits for all power quality parameters specified in ZS 387 are met at the Point of Connection or other location as agreed with the TNSP and specified in the Connection Agreement. PROCEDURE The following tests shall be calculated within a minimum active power level range from 0.2pu to 1.0pu Using a suitable power quality recorder, as defined in ZS387, power quality shall be measured at the Connection site to cover rapid voltage changes, flicker, voltage phase unbalance, voltage fluctuation and harmonic content. Prior to energisation suitable modelling and calculations shall be undertaken to demonstrate that the installation will not have a significant impact on the power quality of the System both at the point of compliance and at other points in the System as determined by the TNSP. ACCEPTANCE CRITERIA The measurements shall demonstrate that the levels for power quality (rapid voltage changes, flicker, voltage phase unbalance, voltage fluctuation and harmonic content) are within the limits specified in ZS387 over the full operational range. 9th January, 2026 Statutory Instruments 207 Due account will be taken of any conditions on the System which may affect the results of the test. The relevant User must, if requested, demonstrate, to TNSP's reasonable satisfaction, the reliability of the suitable recorders, disclosing calibration records to the extent appropriate. Reporting Submit a report to the System Operator one month after the test. ACCEPTANCE TNSP A7.7.3 Generating Protection system A7.7.3 Generating Protection system For All Generating Units ≥ 2MW Parameter Generating Unit Protection Confirming functionality and integrity and confirming final settings Reference Section 2.1.11 APPLICABILITY AND FREQUENCY OF TESTING Prototype study: For all new Power Production Facilities or any Power Production Facility following major refurbishment or upgrade of Plant, switchgear or Protection systems. ROUTINE REVIEW PERIOD: All Power Producers to confirm compliance every five years. PURPOSE To ensure that the relevant Protection functions in the Power Production Facility are co-ordinated and aligned with the System requirements and function as instructed in the Protection philosophy Statement (as amended by Schedules to the Connection Agreement). PROCEDURE Prototype:

1. Agree the System Protection functions and associated trip level requirements as set down in the Protection Philosophy Statement as required in Section 2.1.5.8.4. (c) and as required in GCR1 in Section

2. Carry out tests to prove the integrity and functionality of each protection element as detailed in 2.1.13.5 {a-i).as follows: (a) Apply final Protection functions and settings to all protection functions as agreed in the Protection Philosophy statement and updated in the latest issue of any schedule to the Connection Agreement (b) With the Generating Unit off load and de-energised, inject appropriate signals into every Protection function and confirm correct operation and correct calibration. Document all Protection function operations. (c) Carry out trip testing of all Protection functions, from origin (e.g. Buchholz relay) to all tripping output devices (e.g. HV or EHV breaker). Document all trip test responses. (d) Apply short-circuits at all relevant Protection zones and  with a Synchronous Generating Unit operating at nominal speed, excite the generator slowly, recording currents at all relevant Protection functions and confirm correct operation of all relevant Protection functions; With the Generating Unit at nominal speed, excite the Generating Unit slowly, recording voltages on all relevant Protection functions. Confirm correct operation and correct calibration of all Protection functions. Document all readings and responses; or  with an Asynchronous Generating Unit Connected and operating above 20% of Registered Capacity Output measure currents in all protective devices and compare with expected currents from the capability curve; confirm the operation of over-voltage, under-voltage and over frequency, Under frequency and Rate of Change of Frequency protection. 208 Statutory Instruments 9th January, 2026 Document all readings and responses. Remove all short-circuits fitted.

3. Record protection performance results in agreed format.

4. Confirm that the protection trips the required interrupting device or otherwise blocks the flow of electric current (e.g. in a power electronic controlled device). REVIEW PROCESS:

1. Review Items 2 to 5 above. ACCEPTANCE CRITERIA All Protection functions are fully operational and operate to required levels within the relay Original Equipment Manufacturer (OEM) allowable tolerances, or in the case of Asynchronous Generating Units, functions are operating within OEM Generating Unit design tolerances. [Measuring instrumentation used shall be sufficiently accurate and calibrated to a traceable standard.] REPORTING Submit a report to the TNSP and System Operator during the commissioning process or within 1 month of 5-yearly for routine tests. ACCEPTANCE SO A7.7.4 Excitation system for Directly Connected Synchronous Generating Units Parameter Excitation and setting integrity study APPLICABILITY Reference Section

2.1.13.4 Prototype study: All new Directly Connected Synchronous Power Production Facilities or Power Production Facilities at which major refurbishment or upgrades of excitation systems have taken place. Where localised changes or modifications are done, only affected part or parts shall be covered. ROUTINE REVIEW PERIOD: All Power Production Facilities to confirm compliance every six years. PURPOSE To ensure that the excitation systems in the Power Production Facilities is co- ordinated and aligned with the System requirements. PROCEDURE Prototype:

1. Establish the excitation system performance requirements from the TNSP and System Operator.

2. Derive a suitable model for the excitation system according to IEEE

421.5 or IEC 60034.16.2. Where necessary, non-standard models (non- IEC or IEEE) shall be created. This may require Frequency response and bode plot tests on the excitation system as described in IEEE 421.2.1990.

3. Submit the model to the TNSP and System Operator for their acceptance.

4. Derive excitation system settings that match the Power Production Facility Plant, Transmission Plant and System requirements. This includes the settings of all parts of the excitation system such as the chop- over limits and levels, limiters, Protection devices and alarms.

5. Confirm the stability of the excitation system for relevant excitation system operating conditions.

6. Document the details of the trip levels, stability calculations for each setting and function.

7. Convert the settings for each function into a per unit base and produce a high-level dynamic performance model with actual settings in p.u. values. 9th January, 2026 Statutory Instruments 209

8. Derive actual card setting details and document the relay setting sheet for all setting functions.

9. Produce a single line diagram/block diagram of all the functions in the excitation system and indicate the signal source.

10. Document the tripping functions for each tripping on one tripping logic diagram.

11. Consolidate the detailed setting calculations, model, per unit setting sheets, relay setting sheets, Plant base information on which the settings are based, tripping logic diagram, Protection function single line diagram and relevant Protection relay manufacturers’ information into one document.

12. Submit to the TNSP and System Operator for their acceptance and update by providing them with one original master copy and one working copy update as applicable. REVIEW: Review items 1 to 10 above. Submit to the TNSP and System Operator for their acceptance and update. Provide the TNSP and System Operator with one original master copy and one working copy update if applicable. ACCEPTANCE CRITERIA The excitation system is set to meet the necessary control requirements in an optimised manner for the performance of the Transmission and Power production Facility Plant. The excitation system operates stable both internally and on the network. REPORTING Submit a report to the System Operator prior to commissioning for a prototype study or six yearly for routine tests, within one month after expiry of the due date. Parameter Excitation response tests Reference Section 2.1.13.3 and

2.1.13.4 ACCEPTANCE SO APPLICABILITY Prototype test: All new Synchronous Power Production Facilities coming on line and all other Power Production Facilities after major modifications or refurbishment of Protection or related Plant. Also, after localised modifications or works have been carried out to the plant that will affect this performance. Routine test: All Power Producers to perform tests on each Generating Unit 6-yearly or after a major overhaul of Plant. PURPOSE To confirm that the excitation system performs as per the specifications. PROCEDURE • With the Generating Unit off line, carry out Frequency scan/bode plot tests on all circuits in the excitation system critical to the performance of the excitation system. • With the Generating Unit in the open circuit mode, carry out the large signal performance testing as described in IEEE 421.2 of 1990. Determine time response, ceiling voltage and voltage response. • With the Generating Unit Synchronised and loaded, carry out the small signal performance tests according to IEE 421.2 of 1990. Also carry out power system stabiliser tests and determine damping with and without power system stabiliser. • Document all responses. 210 Statutory Instruments 9th January, 2026 ACCEPTANCE CRITERIA The excitation system meets the necessary control requirements in an optimised manner for the performance of the Transmission and Power Production Facility Plant as specified. The excitation system operates stably both internally and on the network. The power system stabilisers are set for optimised damping for modes agreed with the TNSP and SO. REPORTING Submit a report to the SO prior to commissioning and within one month of tests carried out at 6 yearly intervals thereafter. ACCEPTANCE SO A7.7.5 Generating Unit Reactive Power capability for Directly Connected Synchronous Generating Units Parameter Reactive power capability APPLICABILITY Prototype test: All new Directly Connected Synchronous Power Production Facilities and all other Power Production Facilities after major modifications or refurbishment of Protection or related Plant. Reference Section

2.1.13.4 ROUTINE REVIEW / TESTING PERIOD: Confirm compliance every 6 years. PURPOSE To confirm that the Reactive Power capability specified is met. PROCEDURE The Generating Unit will be required to regulate the Voltage on the HV Busbar to a set level. The Generating Unit will also be required to demonstrate its Reactive Power capability and functioning of Reactive Power control mode for 1 hour and to prove the specified accuracy of control over the entire Active Power Output range of the Plant up to Registered Capacity from a lagging Power Factor of 0.85 to a leading Power Factor of 0.95 (as measured at the generator terminals) or such other value as shall be specified in the Connection Agreement and measured at the Point of Connection. If network considerations restrict the Generating Unit Output, then the maximum leading and lagging capability will be demonstrated without breaching the network operators limits. Note that although this is a commissioning test it may be deemed by the SO to be a System Test, having regard to the size and location of Plant. The SO may also require a test to prove over and under excitation limiters either separately or as part of this test. ACCEPTANCE CRITERIA The Generating Unit shall maintain the set voltage within ±5% of the capability registered with the TNSP and System Operator for at least one hour. REPORTING Submit a report to the TNSP and System Operator one month after the test. ACCEPTANCE SO A7.7.6. - Reactive power control capability verification for Directly Connected Asynchronous Generating Units Parameter Reactive power control function and operational range For all new Asynchronous Generating Units and after major modifications or refurbishment of related Plant components or functionality. Reference Section

2.1.14.4 Description APPLICABILITY ROUTINE REVIEW / TESTING PERIOD: Confirm compliance every 6 years. PURPOSE To confirm that the Reactive Power capability specified is met and that control functions are functioning as specified. 9th January, 2026 Statutory Instruments 211 PROCEDURE The range of Reactive Power capability when generating full Registered Capacity Active Power shall be confirmed to be at least as required in Section 2.1.14.4 of the Grid Code. These tests should be scheduled at a time when at least 95% of Registered Capacity of the Generating Unit is in service. There should be sufficient MW resource forecasted to generate at least 65% of Registered Capacity of the Generating Unit. The following tests shall be performed within a minimum active power level range of at least 0.2 pu.

4. The Asynchronous Generating Units will be required to regulate the voltage at the PCC to a set level within the design margins or it shall be required to achieve maximum import or export of Reactive Power in an attempt to achieve the set point Voltage. The Asynchronous Generating Units will be required to provide a fixed Q to a set level within the design margins. The Asynchronous Generating Units will be required to obtain a fixed PF within the design margins. The operation of instructed functions of change of control mode and settings shall be proven to work and the instructions shall be confirmed as received and achieved. ACCEPTANCE CRITERIA

3. The Asynchronous Generating Units shall maintain the set Voltage within ±5% throughout the Active Power range unless operating at maximum input or export of Reactive Power, and shall demonstrate the capability for at least one hour having regard to environmental conditions. For a range of Active Power Outputs up to Registered Capacity the Asynchronous Generating Units shall maintain the Reactive Power (Q) within ±2% of the set point for a range of values of Q up to the maximum import and export capability detailed in the Connection Agreement and shall demonstrate the capability for at least one hour having regard to environmental conditions. For a range of Active Power Outputs up to Registered Capacity the Asynchronous Generating Units shall maintain the set PF within ±2% of the set point for a range of Power Factors within the Capability Curve in the Connection Agreement. and shall demonstrate the capability for at least one hour. at least one hour having regard to environmental conditions. conditions. REPORTING Submit a report to the SO, one month after the test. ACCEPTANCE SO A7.7.7 Governing system for Synchronous Generating Units Parameter Reference Governing response tests Section

2.1.12.5 and 2.1.13.2 APPLICABILITY Prototype test: All new Synchronous Power Production Facilities and all other Power Production Facilities after major modifications or refurbishment of Protection or related plant. ROUTINE TEST All Generating Units to be monitored continuously. Additional tests may be requested by the System Operator, acting reasonably but not more than 2-yearly. PURPOSE To prove that the Generating Unit is capable of the minimum requirements for governing. PROCEDURE 212 Statutory Instruments 9th January, 2026 A7.7.8 - Active Power control capability verification A7.7.8 - Active Power control capability verification Parameter Active Power control function and operational range Reference Section 2.1.12.4 PROCEDURE

1. Frequency or speed deviation to be injected on the Generating Unit for ten minutes.

2. Active Power Output of the Generating Unit to be measured and recorded. ACCEPTANCE CRITERIA Minimum requirements of the Grid Code are met. Any lockout function for high-frequency is proven to work as intended. ACCEPTANCE SO Description APPLICABILITY For all new Generating Units ≥2MW and after major modifications or refurbishment of related Plant components or functionality. ROUTINE REVIEW / TESTING PERIOD: Confirm compliance every 6 years. PURPOSE To confirm that the Active Power curve and the control capability specified is met. PROCEDURE By measuring incident solar energy or wind speed and direction confirm the Generating Unit Output and range of Output is an described in the Connection Agreement by tables or graphs e.g. a wind rose. In the case of Generating Units depending on Variable Renewable Energy (VRE), the performance of the Generating Unit will be judged according to the measured wind speed or solar irradiance. The following tests shall be performed within an Active Power level range of at least 0.2p.u.or higher

1. The Generating Unit will be required to regulate the Active Power to a set of specific setpoints within the design margins.

2. The Generating Unit will be required to obtain a set of Active Power setpoints within the design margins with minimum two different gradients for ramping up and two different gradients for ramping down.

3. The Generating Unit will be required to maintain as a minimum two different set levels of response within the design margins. In the case of VRE Plant this will be achieved by a Delta control function and due regard will be taken to the settings of that controller.

4. The Generating Unit will be required to operate as a minimum to limit Active Power Output according to two different absolute power constraint set levels within the design margins.

5. The Generating Unit will be required to verify operation according to as a minimum two different parameter sets for a frequency response curve within the design margins. 9th January, 2026 Statutory Instruments 213 ACCEPTANCE CRITERIA

1. The Generating Unit shall maintain the set Output for a range of Outputs up to full Registered Capacity within ±2% of the Registered Capacity for at least one hour.

2. The Generating Unit shall demonstrate ramp rates for a range of Outputs with precision within ±2% of Registered Capacity for ramping up and down within environmental conditions.

3. The Generating Unit shall maintain a response set level within ±2% of the Registered Capacity for at least one hour.

4. The Generating Unit shall maintain a series of absolute power constraint set levels within ±2% of Registered Capacity for at least one hour.

5. The Generating Unit shall demonstrate that the requested Frequency response curves can be obtained.

6. Any lockout functions required for high frequency are proven to work. REPORTING Submit a report to the TNSP and SO one month after the test. ACCEPTANCE SO A7.7.9 - Fault ride through simulations for all Generating Units ≥ 2MW Reference Description Parameter Section To demonstrate

2.1.12.7. fault ride though voltage droops and peaks. APPLICABILITY All new Generating Units and after major modifications or refurbishment of related plant components or functionality. ROUTINE TESTING / REVIEW: Continuous performance monitoring PURPOSE To confirm that new Generating Units connecting to the Total System perform according to the Grid Code during and after faults on the System which create Voltage Events outside the normal Voltage range. [Whist the requirement applies to all Generating Units, unless specifically required by the SO the test applies to Asynchronous Generating Units because the physics dictates that it is unlikely that Synchronous Generating Units would be non-compliant.] PROCEDURE In order to prove compliance, the System voltage at the Point of Connection of the Generating Unit needs to become abnormal to an extent and for a period for which the Grid Code requires that the Generating Unit remains Connected. An approved disturbance recorder is to be installed and System Voltage transients and actual Plant performance recorded. The quantities to be measured, estimated or recorded are as follows: Phase voltages Positive phase sequence and negative phase sequence voltages Phase currents Positive phase sequence and negative phase sequence currents Estimate of the Generating Unit’s negative phase sequence impedance (i) (ii) (iii) (iv) (v) (vi) MW- Active Power at the Generating Unit (vii) MVAr – Reactive Power at the Generating Unit (viii) Real / Reactive, current / power reference as appropriate (ix) Any fault ride through protection which has operated (e.g. crowbar in the case of DFIG) (x) Any other signals related to fault ride through which demonstrate that the model supplied as Detailed Planning Data is accurate. It is not intended to require Power Producers to retain a disturbance recorder at each 214 Statutory Instruments 9th January, 2026 It is not intended to require Power Producers to retain a disturbance recorder at each site after a Generating Unit or Power Production Facility has demonstrated compliance, however if later System Events indicate that the Generating Unit or Power production Facility is not maintaining compliance, the Final Compliance Certificate may be withdrawn and the Plant will be treated as a new Plant from a compliance point of view. ACCEPTANCE CRITERIA

1. From recording of actual Events, the Plant performance can be judged against the System Voltage during and after the Event. It is necessary to prove that the Plant remained connected, delivered the expected Active Power and Reactive Power during and after the Event including the prescribed recovery performance.

2. In the case that no suitable System Events occur within a period of 9 months from the issue of a Temporary Compliance Certificate, a User may apply to the SO for relief of the physical proof of compliance, and compliance shall then be judged as if the Plant performed as per the dynamic model supplied as Detailed Data and having regard to performance of Plant of the same manufactured type. In the case that the Generating Unit under test has previously failed to ride through a fault for which it should have been compliant, a Final Compliance Certificate will not be issued until a disturbance recorder report shows that the issue has been rectified. REPORTING Submit a report to the TNSP as soon as practicable after a suitable Event and in any case within 1 month, showing the performance of the Generating Unit. In the case that the Generating Unit fails to ride through a fault for which it should have been compliant indicate what steps are being taken to rectify the situation. ACCEPTANCE SO A7.7.10 Black Start capability for Generating Units so identified Parameter Black Starting Reference Section2.1.13.8 and 2.1.14.7 APPLICABILITY Routine test: Power Production Facilities that have been contracted under Ancillary Services to supply Black Start services. REVIEW / TESTING PERIOD Once every three years for a partial test and once every six years for a full test. PURPOSE To demonstrate that a Black Start Power Production Facility has such capability. PROCEDURE • The relevant Generating Unit of the Power Production Facility shall be disconnected from the System and shut down. • All external auxiliary supplies to the relevant Generating Unit shall be • disconnected. In the case of a station Black Start, the designated Generating Unit, shall be started with the relevant unit-board being energised from an independent auxiliary supply within the Power Production Facility. This auxiliary supply has to be in shutdown mode until the alternator is at a standstill. • The Generating Unit shall be re-Synchronised to the IPS. ACCEPTANCE CRITERIA The Generating Unit shall be able to re-Synchronise to the IPS within 4 hours from the start of the test. A partial test shall involve: Isolation of the Generating Unit • • Starting up of the Generating Unit from an independent source and • Energizing a defined portion of the Total System. A full test shall involve: • Isolation of the Generating Unit • Starting up of the Generating Unit from an independent source • Energizing a defined portion of the Total System and • The subsequent loading of the unit Generating Unit to prove Black Start capability. 9th January, 2026 Statutory Instruments 215 REPORTING Submit a report to the TNSP and System Operator one month after the test. The System Operator may request a full re-test in the event of a failed test or to re-test functions that did not meet test requirements. ACCEPTANCE SO A7.7.10 Black Start capability for Generating Units so identified Parameter Reference Black Starting Section2.1.13.8 and 2.1.14.7 APPLICABILITY Routine test: Power Production Facilities that have been contracted under Ancillary Services to supply Black Start services. REVIEW / TESTING PERIOD Once every three years for a partial test and once every six years for a full test. PURPOSE To demonstrate that a Black Start Power Production Facility has such capability. PROCEDURE • The relevant Generating Unit of the Power Production Facility shall be disconnected from the System and shut down. • All external auxiliary supplies to the relevant Generating Unit shall be disconnected. • In the case of a station Black Start, the designated Generating Unit, shall be started with the relevant unit-board being energised from an independent auxiliary supply within the Power Production Facility. This auxiliary supply has to be in shutdown mode until the alternator is at a standstill. • The Generating Unit shall be re-Synchronised to the IPS. ACCEPTANCE CRITERIA The Generating Unit shall be able to re-Synchronise to the IPS within 4 hours from the start of the test. A partial test shall involve: • Isolation of the Generating Unit • Starting up of the Generating Unit from an independent source and • Energizing a defined portion of the Total System. A full test shall involve: • Isolation of the Generating Unit • Starting up of the Generating Unit from an independent source • Energizing a defined portion of the Total System and The subsequent loading of the unit Generating Unit to prove Black Start capability. REPORTING Submit a report to the TNSP and System Operator one month after the test. The System Operator may request a full re-test in the event of a failed test or to re-test functions that did not meet test requirements. ACCEPTANCE SO 216 Statutory Instruments 9th January, 2026 T a b l e A : - U s e r S y s t e m d a t a – A l l U s e r s C o n n e c t i o n C o n d i t i o n s ( C h a p t e r 1 - T r a n s m i s s i o n S y s t e m ) A P P E N D I X 2 9th January, 2026 Statutory Instruments 217 T a b l e B : - U s e r S y s t e m d a t a – D e m a n d – S t a n d a r d D a t a 218 Statutory Instruments 9th January, 2026 9th January, 2026 Statutory Instruments 219 220 Statutory Instruments 9th January, 2026 9th January, 2026 Statutory Instruments 221 222 Statutory Instruments 9th January, 2026 9th January, 2026 Statutory Instruments 223 224 Statutory Instruments 9th January, 2026 T A B L E C : L O A D C H A R A C T E R I S T I C S D A T A - D E M A N D 9th January, 2026 Statutory Instruments 225 3 226 Statutory Instruments 9th January, 2026 9th January, 2026 Statutory Instruments 227 Note on reactive equipment and Harmonic distortion assessment – data requirements For each shunt capacitor or reactor or Power Factor correction equipment or harmonic filters with a rating in excess of 10MVAr connected to or capable of being connected to a User network, the User shall inform and provide the TNSP with the specific shunt capacitor or reactor data as well as network details necessary to perform primarily harmonic resonance studies. The User shall inform the TNSP of its intention to extend or modify this equipment. If any Participant finds that a capacitor bank of 10MVAr or less is likely to cause harmonic resonance problems on the TS, it shall inform the TNSP. The 1OMVAr minimum size limit shall be reconsidered in respect of the affected network (for information reporting purposes in respect of this code), and tbe TNSP shall inform the affected Participants of this fact and request the additional data. If the affected network is modified or reinforced to the extent that capacitor banks of IOMVAr or less no longer cause harmonic resonance problems on the TS, the TNSP shall inform the affected participants that information reporting requirements have returned to normal. Any Party to this code investigating a complaint about Harmonic distortion, shall have the right to request such additional information (including, but not restricted to, data from Harmonic distortion measuring devices) from parties in the vicinity of the source of the complaint as may reasonably be required to complete the investigation. The following information is required from Parties as stated above: Shunt capacitor or reactor rating MVAr Equipment type – Reactor / Capacitor / harmonic filter Location (station name) Voltage Rating kV Resistance / reactance / susceptance of all components of the capacitor / reactor bank. Fixed or switched If switched - how controlled If automatic Control Control details (manual, time, Voltage load etc) Details of control algorithm and settings. If under FACTs device control which device and details of the control algorithm SERIES CAPACITOR OR REACTOR DATA REQUIREMENTS Series capacitors are installed in long transmission lines to increase load transfer capability. Series reactors are installed to limit fault levels, or to balance load sharing between circuits operated in parallel that would otherwise not share load equitably, or to balance load sharing on an interconnected network. 228 Statutory Instruments 9th January, 2026 The following data is required Reactor / capacitor Location (specifically substation bay where applicable) Voltage Rating Impedance rating Current rating (continuous or emergency, maximum times for emergency ratings). kV Ohms or MVAr Continuous A Hours A Hours A Hours A Note: if a series capacitor or reactor is located in a dedicated reactor or capacitor station (i.e. a substation built to hold only the series reactor or capacitor), the lines or cables linking it to each remote end substation must be specified as separate circuits under line or cable data. FACTS DEVICES FACTS devices enable system parameters (voltage, current, power flow) to be accurately controlled in real time. Because of their cost, they are generally used only if cheaper, more conventional, solutions cannot deliver the required functionality. Applications requiring rapid control capability include the following: (a) Voltage regulation following loss of a system component, generation, large bad; (b) voltage flicker mitigation; (c) Negative phase sequence voltage compensation; (d) SSR damping; (e) Machine transient stability enhancement; (f) System load transfer capability enhancement; (g) Load sharing control in interconnected, deregulated, networks. The most commonly used FACTS device is the SVC. Other FACTS devices made possible by advances in power electronics and control systems include STATCON, TCSC, thyristor- controlled tap changer, thyristor-controlled phase shifter, BES (Battery Energy Storage), and UPC. The common factor is rapid control capability. Because FACTS devices are purpose-designed for their specific applications, the following data is required 9th January, 2026 Statutory Instruments 229 Name Station, HV Voltage, Device number Type (SVC, STATCON, TCSC etc) Configuration. Provide a single line diagram showing all HV components and their MVA / MVAr and voltage ratings, with all controlled components so identified Provide a block diagram of the control system suitable for dynamics modelling Primary control mode Voltage control, arc furnace flicker mitigation, negative phase sequence Voltage control. Customers are required to perform, or cause to be performed, Harmonic studies to ensure that their installation does not excite Harmonic resonance, and that harmonic distortion levels at the PCC with the TS do not exceed the limits specified in ZS 387 Electricity Supply - Quality and Reliability standard. HVDC HVDC is a form of FACTS device because of its rapid control capabilities. However, HVDC is treated separately because its primary function is the transmission of Active Power. HVDC is used to connect two systems that are not necessarily interconnected via the AC network (and thus in synchronism), or even at the same nominal Frequency. Users wishing to connect HVDC systems to the TS shall supply a single line diagram showing all HV Plant (including valve bridges) forming part of the HVDC system, plus additional HV Plant required for its proper operation, e.g. Harmonic filters, synchronous condensers, FACTS devices, etc. Users and the TNSP shall cooperate in performing, or causing to be performed, studies to determine network strengthening requirements needed to accommodate the HVDC system without violating the planning criteria specified in the Network Chapter. In addition, customers shall thereafter perform, or cause to be performed, studies to demonstrate that the proposed HVDC system does not exceed QOS parameters specified in ZS387 Electricity Supply - Power Quality and Reliability standard, and where applicable shall specify what additional HV plant will be required to ensure compliance with this standard. 230 Statutory Instruments 9th January, 2026 Table D1: User Demand profiles Daily Load User Profile for (day) Week No All Users with Demand This Demand profile should be completed for each year of the 5-year period. Where there is no change expected, a User may complete the following declaration. [Year 0 refers to the year just past.] TNSP(s) may request D1 and D2 as part of Connection Data Declaration - [User name] is unaware of any expected change to this/ these Demand profile(s) over the 5-year forecast period. Data description Y0 Y1 Y2 Y3 Y4 Y5 Update time Comments Forecast daily Demand profiles in respect of each User system.

1. Day of User maximum Demand (MW) at annual maximum Demand conditions; 2 Two days notified by DNSP End of Jan 00:00 – 01:00 01:00 – 02:00 02:00 – 03:00 03:00 – 04:00 04:00 – 05:00 05:00 – 06:00 06:00 – 07:00 07:00 – 08:00 08:00 – 09:00 09:00 – 10:00 10:00 – 11:00 11:00 – 12:00 12:00 – 13:00 13:00 – 14:00 14:00 – 15:00 9th January, 2026 Statutory Instruments 231 14:00 – 15:00 15:00 – 16:00 16:00 – 17:00 17:00 – 18:00 18:00 – 19:00 19:00 – 20:00 20:00 – 21:00 21:00 – 22:00 22:00 – 23:00 23:00 – 24:00 In addition the TNSP may periodically require a 15 year forecast of Demand and a statement setting out the basis for the forecast. For each Point of Connection the TNSP should receive the forecast for Demand as gross of Embedded Generation and shall separately receive a net Demand forecast. A negative net Demand forecast indicates that Embedded Generation exceeds Demand at that Point of Connection for that time period. For the avoidance of doubt, these forecasts are for Transmission planning and are not related to Commercial Policy. Table D2: User Demand profiles Weekly and Seasonal Load Year User All Users with Demand This Demand profile should be completed for each year of the 5-year period. Where there is no change expected, a User may complete the following declaration. [Year 0 refers to the year just past.] WEEKLY If there is a significant difference in daily load profile for certain days of the week Users must supply representative profiles for e.g. work days and non-work days. SEASONAL Users who expect significant variation in Demand throughout the year should indicate their expected Maximum Demand and Minimum Demand for each Month and if certain periods have different daily profiles these should be supplied. 232 different daily profiles these should be supplied. Statutory Instruments 9th January, 2026 Maximum Demand MVA Minimum Demand MVA January February March April May June July August September October November December Schedule D3: Generating Unit Output usable and Controllable Demand Profiles User Site Daily Output usable and/or Controllable Demand Profile for (day) Week No Generating Unit / Controllable Demand identifier All Users with Generating Units and all Users with Controllable Demand This Output usable/Controllable Demand profile should be completed for each year of the 5-year period. Where there is no change expected, a User may complete the following declaration. [Year 0 refers to the year just past.] TNSP(s) may request D3 and D4 as part of Connection Data Declaration - [User name] is unaware of any expected change to this/ these Output usable/Controllable Demand profile(s) over the 5-year forecast period. Data description Y0 Y1 Y2 Y3 Y4 Y5 Update time Comments Forecast daily Output usable/Controllable Demand profiles in respect of each Generating Unit and/or Controllable Demand.

1. Day of Generating Unit maximum Output usable (MW) at End of Jan annual maximum Demand conditions; 2 Two days notified by TNSP And/Or:

1. Day of User maximum Demand (MW) at annual maximum End of Jan Demand conditions; 2 Two days notified by DNSP 9th January, 2026 Statutory Instruments 233 (a) 00:00 – 01:00 01:00 – 02:00 02:00 – 03:00 03:00 – 04:00 04:00 – 05:00 05:00 – 06:00 06:00 – 07:00 07:00 – 08:00 08:00 – 09:00 09:00 – 10:00 10:00 – 11:00 11:00 – 12:00 12:00 – 13:00 13:00 – 14:00 14:00 – 15:00 Schedule D4: Generating Unit Output Available and Controllable Demand Profiles Weekly and Seasonal Load User Year All Users with Generating Units This Output usable profile should be completed for each year of the 5-year period. Where there is no change expected, a User may complete the following declaration. [Year 0 refers to the year just past.] WEEKLY If there is a significant difference in daily profile for certain days of the week Users must supply representative profiles for e.g. work days and non-work days. SEASONAL Users who expect significant variation in Output usable throughout the year should indicate their expected Maximum Output and Minimum Output for each Month and if certain periods have different daily profiles these should be supplied. All Users with Controllable Demand This Controllable Demand profile should be completed for each year of the 5-year period. Where there is no change expected, a User may complete the following declaration. [Year 0 refers to the year just past.] WEEKLY If there is a significant difference in daily profile for certain days of the week Users must supply representative profiles for e.g. work days and non-work days. 234 WEEKLY Statutory Instruments 9th January, 2026 If there is a significant difference in daily profile for certain days of the week Users must supply representative profiles for e.g. work days and non-work days. SEASONAL Users who expect significant variation in Controllable Demand throughout the year should indicate their expected Maximum Demand and Minimum Demand for each Month and if certain periods have different daily profiles these should be supplied. Maximum Output usable or Maximum Controllable Demand MVA Minimum Output usable or Minimum Controllable Demand MVA January February March April May June July August September October November December 9th January, 2026 Statutory Instruments 235 T A B L E E : C O N N E C T I O N P O N T I 236 Statutory Instruments 9th January, 2026 9th January, 2026 Statutory Instruments 237 NOTE ON INFORMATION ON TRANSFERRABLE DEMAND ON CUSTOMER NETWORKS If a User will have two or more points of supply from the Transmission System (or the Transmission System and the Distribution System) which may be interconnected, including the one applied for, the User shall specify the amount of load to be between Points of Supply under normal conditions as well as under contingencies. The same requirement applies to any Embedded Power Producers within the User’s network, since they affect fault levels as well as net load on the System. The User shall also specify whether it intends to interconnect two or more transmission points of supply via its network. In such circumstances the User shall provide detailed information on the lines and cables used. Where a circuit consists of two or more segments of different characteristics (different overhead line tower andlor conductor bundle types and/or underground cable types), each section shall be specified separately. In addition, ALL Users connecting to the TS must supply a Protection Philosophy Statement New Users, or Users specifically requested by the SO, shall prepare a Protection Philosophy Statement according to a model format issued by the TNSP with content as follows: • • • • • a description of the Protection philosophy; a description of Plant capabilities and the relevant Protection operations. a description of any auto-reclose facilities installed or to be installed by any Participant; a list of relays and settings including for Generating Unit and associated equipment; the most probable fault clearance time (Fault inception to arc extinction) which must not threaten selectivity or equipment ratings; • how the Protection system allows for TNSP auto-reclose systems; • how selectivity is achieved and compliance with Zambian standards and TNSP practice is observed (TNSP to inform in a standard Protection policy paper with a local system information annex); and • any other matter required by the TNSP or SO, to be determined in consultation with the User, and any resulting equipment to be provided and maintained by the relevant User at its own cost. • The Protection Philosophy Statement shall be submitted by the User for approval by the TNSP. 238 Statutory Instruments 9th January, 2026 The Protection functions are considered adequate when the Protection relays perform correctly in terms of: (a) reliability; (b) speed of operation; (c) selectivity; and (d) sensitivity. The Statement shall be agreed and signed by the User and the TNSP Protection Settings Chapter shall contain the following: (i) a section defining the base values and per unit values to be used; (ii) a single line diagram showing all the protection functions and sources of current and voltage signals; (iii) a protection tripping diagram(s) showing all the protection functions and associated tripping logic and tripping functions; (iv) a detailed description of setting calculation for each protection setting, discussion on protection function stability calculations, and detailed dial settings on the protection relay in order to achieve the required setting; (v) a section containing a summary of all protection settings on a per unit basis; (vi) a section containing a summary for each of the protection relay dial settings/programming details; (vii) an annex containing plant information data (e.g. OEM data) on which the settings are based; (viii) an annex containing OEM information sheets or documents describing how the protection relays function. 9th January, 2026 Statutory Instruments 239 a t a d d e e f n i t l u a F : F e l b a T 240 Statutory Instruments 9th January, 2026 9th January, 2026 Statutory Instruments 241 242 Statutory Instruments 9th January, 2026 9th January, 2026 Statutory Instruments 243 s r o t a r e n e g s u o n o r h c n y S - H e l b a T 244 Statutory Instruments 9th January, 2026 9th January, 2026 Statutory Instruments 245 246 Statutory Instruments 9th January, 2026 9th January, 2026 Statutory Instruments 247 248 Statutory Instruments 9th January, 2026 9th January, 2026 Statutory Instruments 249 250 Statutory Instruments 9th January, 2026 9th January, 2026 Statutory Instruments 251 252 Statutory Instruments 9th January, 2026 9th January, 2026 Statutory Instruments 253 254 Statutory Instruments 9th January, 2026 9th January, 2026 Statutory Instruments 255 Additional Information Requirements In addition, the following Detailed Data shall be supplied by Power Producers with Centrally Dispatched Synchronous Generators and such other Power Producers as the SO shall require. Excitation Settings Document A document agreed and signed by the SO containing the following: (i) a section defining the base values and per unit values to be used; (ii) a single line diagram showing all the excitation system functions and all the related protection tripping functions; (iii) an excitation system transfer function block diagram in accordance with IEC standard models; (iv) a detailed description of setting calculation for each of the excitation system functions, discussion on function stability calculations, and detailed dial settings on the excitation system in order to achieve the required setting; (v) a section containing a summary of all settings on a per unit basis; (vi) a section containing a summary for each of the excitation system dial settings/programming details; (vii) an annex containing plant information data (e.g. OEM data) on which the settings are based; (viii) an annex containing OEM information sheets or documents describing the performance of the overall excitation system and each excitation function for which a setting is derived. Governor Setting document A document agreed and signed by tile SO containing the following: (i) a section defining the base values and per unit values to be used; (ii) a single line diagram showing all the excitation system functions and all the related protection tripping functions; (iii) all excitation system transfer function block diagram in accordance with IEC standard models; (iv) A detailed description of setting calculation for each of the governor system functions, discussion on function stability calculations, and detailed dial settings on the governor system in order to achieve the required setting; (v) a section containing a summary of all settings on a per unit basis (vi) a section containing a summary for each of the governor system dial settings/programming details; (vii) an annex containing plant information data (e.g. OEM data) on which the settings are based; (viii) an annex containing OEM information sheets or documents describing the performance of the overall governor system and each governor function for which a setting is derived. Modelling Information Excitation System The generator shall fill in the following parameters or supply a Laplace-domain control block diagram in accordance with IEEE or lEC standard excitation models (or as otherwise agreed with the SO) completely specifying all time constants and gains to fully explain the transfer function from the compensator or unit terminal voltage and field current to unit field voltage. Customers shall perform, or cause to be performed, small signal dynamic studies to ensure that the proposed 256 Statutory Instruments 9th January, 2026 excitation system and turbine governor do not cause dynamic instability. Where applicable, a PSS (power system stabiliser) shall be included in the excitation system to ensure proper tuning of the excitation system for stability purposes Excitation system type (AC or DC) Excitation feeding arrangement (solid or shunt) Excitation system filter time constant Excitation system lead time constant Excitation system lag time constant Excitation system controller gain Excitation system controller lag time constant Excitation System maximum controller output Excitation System minimum controller output Excitation System regulation factor Excitation System rate feedback gain Excitation System feedback time constant Text Text Sec Sec Sec Sec pu pu sec Speed governor system, turbine and boiler models The Power Producer shall supply a Laplace domain control block diagram in accordance with lEC standard prime mover models for thermal and hydro units (or as otherwise agreed with the TNSP), fully specifying all time’ constants and gains to fully explain the transfer function for the governor, turbine, penstocks and control systems in relation to frequency deviations and set point operation. Control devices and protection relays The Power Producer should supply any additional Laplace domain control diagrams for any outstanding control devices (including power system stabilisers) or special protection relays in the unit that automatically impinge on its operating characteristics within 30 seconds following a system disturbance and that have a minimum time constant of at least 0.02 seconds. 9th January, 2026 Statutory Instruments 257 s r o t a r e n e G s u o n o r h c n y s A - I e l b a T 258 Statutory Instruments 9th January, 2026 9th January, 2026 Statutory Instruments 259 260 Statutory Instruments 9th January, 2026 9th January, 2026 Statutory Instruments 261 262 Statutory Instruments 9th January, 2026 9th January, 2026 Statutory Instruments 263 264 Statutory Instruments 9th January, 2026 9th January, 2026 Statutory Instruments 265 266 Statutory Instruments 9th January, 2026 s t i n U g n i t a r e n e G e g a r o t S y g r e n E – J e l b a T 9th January, 2026 Statutory Instruments 267 268 Statutory Instruments 9th January, 2026 3 I X D N E P P A ) m e t s y S n o i s s i m s n a r T - 1 r e t p a h C ( a t a D g n i n n a l P r o t a r e n e G n e h w d n a s a d e t a d p u n e h t d n a n o i t c e n n o c o t r o i r p , O S d n a P S N T e h t o t d e d i v o r p e b l l a h s n o i t a m r o f n i g n i w o l l o f e h t , d e t a c i d n i e s i w r e h t o s s e l n U a t a d n o i t a t s r e w o P ) a ( . r u c c o s e g n a h c 9th January, 2026 Statutory Instruments 269 (b) Unit data Unit number Capacity Unit capacity (MW) Normal maximum continuous generation capacity: Normal maximum continuous sent out capacity Unit auxiliary active load Unit auxiliary reactive load Maximum (EL1) generating capacity Maximum (EL2) sent out capacity Normal minimum continuous generating capacity Normal minimum continuous sent out capacity Generator rating (Mbase) Normal maximum lagging power factor Normal maximum leading power factor Governor droop Forbidden loading zones Terminal voltage adjustment range Short circuit ratio Rated stator current Time to synchronise with penstock charged (warm) Time to synchronise with penstock empty from (cold) Normal loading rate Normal de-loading rate Partial load rejection capability MW MW MW MVAr MW MW MW MW MVA MVAr MVAr MW KV Amp Hour Hour MW/min MW/min % MW name plate rating Description Capability chart showing full range of operating capability of the generator, including thermal and excitation limits Data Diagram Open circuit magnetisation curves Short circuit characteristic Zero power factor curve V curves Graph Graph Graph Diagram 270 Statutory Instruments 9th January, 2026 Documents Protection setting document Description A document agreed and signed by the SO containing the following: (i) (ii) (iii) (iv) (v) (vi) (vii) (viii) a section defining the base values and per unit values to be used a single line diagram showing all the protection functions and sources of current and voltage signals a protection tripping diagram(s) showing all the protection functions and associated tripping logic and tripping functions a detailed description of setting calculation for each protection setting, discussion on protection function stability calculations, and detailed dial settings on the protection relay in order to achieve the required setting a section containing a summary of all protection settings on a per unit basis a section containing a summary for each of the protect settings/programming details an annex containing plant information data (e.g. OEM data) on which the settings are based an annex containing OEM information sheets or documents describing how the protection relays function ion relay dial Excitation setting document A document agreed and signed by the SO containing the following: (i) (ii) (iii) (iv) (v) (vi) (vii) (viii) a section defining the base values and per unit values to be used a single line diagram showing all the excitation system functions and all the related protection tripping functions an excitation system transfer function block diagram in accordance with IEC standard models a detailed description of setting calculation for each of the excitation system functions, discussion on function stability calculations, and detailed dial settin gs on the excitation system in order to achieve the required setting a section containing a summery of all settings on a per unit basis a section containing a summary for each of the excitation system dial settings/programming details. an annex containing plant information data (e.g. OEM data) on which the settings are based an annex containing OEM information sheets or documents describing the performance of the overall excitation system and each excitation function for which a setting is derived Governor setting document A document agreed and signed by the SO containing the following: (i) (ii) (iii) (iv) (v) (vi) (vii) (viii) a section defining the base values and per unit values to be used a single line diagram showing all the excitation system functions and all the related protection tripping functions an excitation system transfer function block diagram in accordance with IEC standard models a detailed description of setting calculation for each of the governor system functions, discussion on function stability calculations, and detailed dial settings on the governor system in order to achieve the required setting a section containing a summery of all settings on a per unit basis a section containing a summary for each of the governor system dial settings/programming details an annex containing plant information data (e.g. OEM data) on which the settings are based an annex containing OEM information sheets or documents describing the performance of the overall governor system and each governor function for which a setting is derived 9th January, 2026 Statutory Instruments 271 (c) Reserve capability The generator shall provide the SO with the reserve capability of each power station. The reserve capability shall be indicated as defined in the SAPP Operating Guidelines (1996) (d) Unit parameters Direct axis synchronous reactance Direct axis transient reactance saturated Direct axis transient reactance unsaturated Sub-transient reactance unsaturated Quad axis synchronous reactance Quad axis transient reactance unsaturated Negative phase sequence synchronous reactance Zero phase sequence reactance Turbine generator inertia constant for entire rotating mass Stator resistance Stator leakage reactance Poiter reactance Generator time constants: i. Direct axis open-circuit transient ii. Direct axis open-circuit sub-transient iii. Quad axis open-circuit transient iv. Quad axis open-circuit sub-transient v. Direct axis short-circuit transient vi. Direct axis short-circuit sub-transient vii. Quad axis short-circuit transient viii. Quad axis short-circuit sub-transient Speed damping Saturation ratio at 1 pu terminal voltage Saturation ratio at 1.2 pu terminal voltage " q Units % on rating % on rating % on rating % on rating % on rating % on rating % on rating % on rating MW s/MVA % on rating % on rating % on rating sec sec sec sec sec sec sec sec ' ' d d Symbol X d X satd X unsat "  XX X q X unsat X 2 X q0 H Ra q ' X L X P Tdo’ Tdo’’ Tqo’ Tqo’’ Td’ Td’’ Tq’ Tq’’ D S(1.0) S(1.2) 272 Statutory Instruments 9th January, 2026 (e) Excitation system The generator shall fill in the following parameters or supply a Laplace-domain control block diagram in accordance with IEEE or IEC standard excitation models (or as otherwise agreed with the SO) completely specifying all time constants and gains to fully explain the transfer function from the compensator or unit terminal voltage and field current to unit field voltage. Customers shall perform, or cause to be performed, small signal dynamic studies to ensure that the proposed excitation system and turbine governor do not cause dynamic instability. Where applicable, a PSS (power system stabiliser) shall be included in the excitation system to ensure proper tuning of the excitation system for stability purposes. Excitation system type (AC or DC) Excitation feeding arrangement (solid or shunt) Excitation system filter time constant Excitation system lead time constant Excitation system lag time constant Excitation system controller gain Excitation system controller lag time constant Excitation system maximum controller output Excitation system minimum controller output Excitation system regulation factor Excitation system rate feedback gain Excitation system rate feedback time constant Symbol Tr Tc Tb Ka Ta Vmax Vmin Kc Kf Tf Units Text Text Sec Sec Sec Sec p.u. p.u. Sec (f) Speed governor system, turbine and boiler models The generator shall supply a Laplace domain control block diagram in accordance with IEC standard prime mover models for thermal and hydro units (or as otherwise agreed with the TNSP), fully specifying all time constants and gains to fully explain the transfer function for the governor, turbine, penstocks and control systems in relation to frequency deviations and set point operation. (g) Control devices and protection relays The generator should supply any additional Laplace domain control diagrams for any outstanding control devices (including power system stabilisers) or special protection relays in the unit that automatically impinge on its operating characteristics within 30 seconds following a system disturbance and that have a minimum time constant of at least 0,02 seconds. 9th January, 2026 Statutory Instruments 273 (i) Unit step-up transformer Symbol Units Number of windings Vector group Rated current of each winding Transformer rating Transformer nominal LV voltage Transformer nominal HV voltage Tapped winding Transformer ratio at all transformer taps Transformer impedance at all taps (For three winding transformers the HV/LV1, HV/LV2 and LV1/LV2 impedances together with associated bases shall be provided) Transformer zero sequence impedance at nominal tap Z 0 Earthing arrangement, including neutral earthing resistance and reactance Core construction (number of limbs, shell or core type) Open circuit characteristic Amps MVATrans kV kV % on rating MVATrans Ohm Graph (j) Unit forecast data The generator shall provide the TNSP and SO with expected maintenance requirements, in weeks per annum, for each unit at a power station. (k) Return to service of mothballed generating plant: Once the customer has decided to return mothballed generating plant to service, the TNSP requires the information specified for new connections. (l) Decommissioning of generating plant: Decommissioning of plant is the permanent withdrawal from service of generating plant. The TNSP requires the following with a one-year notice period: Generator name Power station name Unit number Date to be removed from commercial service Auxiliary supplies required for dismantling and demolition kVA, point at which supply is require, duration 274 Statutory Instruments 9th January, 2026 APPENDIX 4 (Chapter 1- Transmission System) FORM I Planning Schedules Table 1: Five and Fifteen-year demand forecast Demand = Total Demand + Distribution Losses – Embedded Generation Energy Maximum demand Expected minimum demand Year GWh MW MVAr MW MVAr Measured Year 0 Year 1 Year 2 Year 3 Year 4 Year 5 Year 6 Year 7 Year 8 Year 9 Year 10 Year 11 Year 12 Year 13 Year 14 Year 15 Table 2: Embedded generation > 50MVA 9th January, 2026 Statutory Instruments 275 A V M 0 5 > n o i t a r e n e g d e d d e b m E : 2 e l b a T 276 Statutory Instruments 9th January, 2026 APPENDIX 4 (Transmission System Chapter) Typical Load Profile FORM II 9th January, 2026 Statutory Instruments 277 APPENDIX 4 (Transmission System Chapter) Load Duration Curve FORM III 278 Statutory Instruments 9th January, 2026 APPENDIX 4 (Chapter 3- System Operation) Outage Planning timetable To be set out by SO Activity Responsible Output FORM IV Target Date By 1 st October preceding the year of execution of the plan By 1 5th October preceding the year of execution of the plan By 30 th October preceding the year of execution of the plan SO requests for submission of annual maintenance plans from participants Submission of annual maintenance plans to the SO by participants Consolidation of the Maintenance Plans in consultations with the participants and produce a draft equipment outage program Meeting the participants to review the draft equipment outage program Consolidate the reviewed equipment outage program and issue an approved final copy Circulation and Publication of the annual equipment outage program First Review of the equipment outage program Second Review of the equipment outage program Third Review of the equipment outage program Fourth Review of the equipment outage program System Operator Request for maintenance plans Grid Code Participants Participants’ maintenance plans annual System Operator Draft consolidated equipment outage program System Operator and the Participants Inputs for finalizing the consolidated equipment outage program System Operator Final approved equipment outage program System Operator Issues final equipment outage program By 15th November preceding the year of execution of the plan By 15th December preceding the year of execution of the plan By 31st December preceding the year of execution of the plan System Operator and the Participants System Operator and the Participants System Operator and the Participants System Operator and the Participants Revised and updated equipment outage program March in the year of execution of the plan Revised and updated equipment outage program June in the year of execution of the plan Revised and updated equipment outage program September in the year of execution of the plan Revised and updated equipment outage program December in the year of execution of the plan 9th January, 2026 Statutory Instruments 279 APPENDIX 4 (Chapter 3- System Operation) Format for Preliminary Incident Report FORM V a. Time of the incident b. Location c. Plant and/or apparatus directly involved (and not merely affected by the incident) d. Description of the incident e. Demand (MW) and/or generation (MW) interrupted and duration of interruption f. Generating unit – frequency response (MW and Hz correction achieved subsequent to the incident) g. Generating Unit – MVAr performance (change in output subsequent to the incident) h. Change in tie-line flow, where applicable i. Estimated time and date of return to service j. Measures taken to prevent/ mitigate recurrence 280 Statutory Instruments 9th January, 2026 APPENDIX 4 (Chapter 3- System Operation) Operation During Abnormal Conditions Condition for Usage Resources in Default Order of Usage FORM VI Warnings WHEN A SHORTFALL IN CAPACITY IS EXPECTED TO OCCUR, ISSUE WARNINGS UNTIL SUFFICIENT CAPACITY IS OBTAINED TO COVER THE SHORTFALL. When there is an appreciable loss of load leading to increased frequency, issue warnings until load has been restored. Gradual frequency decline IF THE FREQUENCY FALL BE- LOW 50HZ AND ABNORMAL VOLTAGE CONDITION EXISTS Rapid Frequency Decline ENSURE OPERATION OF UNDER-FREQUENCY PROTECTION SCHEMES a. Emergency level generation warning b. load shedding warning c. Emergency generation reduction d. Generation plant shut down e. Run unscheduled generation units f. g. Declare emergency to other SAPP Control Areas Interruptible load shedding h. Under-frequency relay protection schemes 9th January, 2026 Statutory Instruments 281 APPENDIX 4 (Chapter 4 – Information Exchange) Power Producer HV Yard Information FORM VII Commissioning Projected or target commissioning test date Operating Target operational or on-line date Reliability of connection requested Number of connecting circuits e.g. one or two feeders, or firm/non-firm supply required (subject to Network chapter requirements) Location map. Upgrades: Name of existing point of supply to be upgraded and supply voltage. New connections: Provide a 1:50 000 or other agreed scale location map, with the location of the facility clearly marked. In addition, specify the co- ordinates of the point of connection. Site plan Provide a plan of the site (with at least 1:200 or 1:500) of the proposed facility, with the proposed point of supply, and where applicable, the transmission line route from the facility boundary to the point of supply, clearly marked. Electrical diagram single-line Provide an electrical single-line diagram, drawn to the relevant IEC standard, of the customer intake substation. 282 Statutory Instruments 9th January, 2026 APPENDIX 4 (Chapter 4 – Information Exchange) Post-Dispatch Information FORM IX The SO shall provide the following minimum operational information in near real-time and as historic data in relation to each power station: No 1 2 3 4 5 6 7 8 9 10 11 Data description High limit Low limit AGC mode CER/BLO AGC status AUT/OFF/MAN Set point AGC pulse Sent-out Auxiliary Contracted Power Station spinning 32-bit flag on AGC settings Format Real Real Character Character Real Real Real Real Integer Integer Integer Size 999,99 999,99 3 3 99,99 9,9 999,99 999,99 999 999 Unit MW MW MW MW MW MW 32 bits The SO shall provide the following minimum operational information in near real-time in relation to the overall dispatch performance: No 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Data description Area control error (ACE) Average ACE previous hour System frequency (Hz) Frequency distribution current hour Frequency distribution previous hour System total generation Control area total actual interchange Control area total scheduled interchange System operating reserve System sent-out System spinning reserve AGC regulating up AGC regulating down AGC regulating up assist AGC regulating down assist AGC regulating up emergency AGC regulating down emergency AGC mode AGC status Area control error output System transmission losses ZESA tie-lines DRC tie-lines BPC radial-line AGC performance indicators Format Real Real Real Real Real Integer Integer Integer Integer Integer Integer Integer Integer Integer Integer Integer Integer Char Char Real Real Integer Integer Integer Size 999,99 999,99 99,999 999,99 999,99 99999 99999 99999 99999 99999 99999 99999 99999 99999 99999 99999 99999 TLBC /CFC ON/ OFF

999.99 99999 99999 99999 Unit MW MW MW MW MW MW MW MW MW MW MW MW MW MW MW MW MW MW MW MW MW MW 9th January, 2026 Statutory Instruments 283 APPENDIX 4 (Chapter 4 – Information Exchange) FORM X File AGC pulses NERC System near real-time data Back Up Files Description The total pulses sent to a unit by the AGC system to move the set-point up or down list of the total NERC "A1" and "A2" criteria violations in the system over an hour Historic near real -time system data files on readings as required for post-dispatch Trigger Event Ongoing, file created at end of hour Ongoing, file appended at end of hour Frequency Hourly Daily Communication failure To be agreed Unit near real-time data Historic near real -time unit data files on readings as required for post dispatch Communication failure To be agreed 284 Statutory Instruments 9th January, 2026 APPENDIX 4 (Chapter 4 – Information Exchange) Reporting Format for Periodic Testing of Under-Frequency Load Shedding Relays FORM XI Distributor: Date: Substation: Fed from transmission substation (directly or indirectly): Activating frequency Timer setting Required As tested Required As tested

0.8Hz/s Instantaneous Instantaneous Instantaneous 20 seconds Instantaneous Feeders selected (Required) Feeders selected (As tested) Stage 1 Stage 2 Stage 3 Stage 4 Stage 5 Stage 1 Stage 2 Stage 3 Stage 4 (Current SAPP Guidelines) 9th January, 2026 Statutory Instruments 285 APPENDIX 4 (Chapter 4 – Information Exchange) Performance Indicators for TNSPs and SO FORM XII Indicator Month Year to date 12 MMI Unit System minutes lost Minutes No. of Interruptions No. of statutory voltage transgressions Mandatory under-frequency load shedding Customer voluntary load shedding TS losses % 286 Statutory Instruments 9th January, 2026 APPENDIX 4 (Chapter 4 – Information Exchange) FORM XIV Information Confidentiality CONFIDENTIALITY AGREEMENT FOR INFORMATION TRANSFER TO THIRD PARTIES CONFIDENTIALITY AGREEMENT BETWEEN …………………………………. (HEREINAFTER REFERRED TO AS THE INFORMATION OWNER) AND …………………………………………………………………………………………. (HEREINAFTER REFERRED TO AS THE RECIPIENT) IN RESPECT OF INFORMATION SUPPLIED TO PERFORM THE FOLLOWING WORK: …………………………………………………………………………………………………………………………………………………………………………………… (HEREINAFTER REFERRED TO AS THE WORK) ON BEHALF OF ………………………………………………………………………………………… (HEREINAFTER REFERRED TO AS THE CLIENT).

4. The Recipient agrees to treat all information (hereinafter referred to as the Information) received from the Information Owner, whether in hard copy or electronic format or in any format whatsoever, as strictly confidential. The Recipient agrees to disclose the Information only to authorized persons who are in his permanent employ, and who require access to the Information to perform their duties in respect of the Work on behalf of the Client. Persons other than those described in Clause 2 above, including but not restricted to temporary employees, subcontractors, and sub-consultants, shall enter into separate Confidentiality Agreements with the Information Owner prior to receiving the Information. The Recipient undertakes to use the Information only to perform the Work on behalf of the Client, and for no other purpose whatsoever.

5. On completion of the Work, the Recipient shall at his expense return to the Information Owner all hard copy material and electronic media containing the Information supplied to him by the Information Owner. The Recipient shall furthermore ensure that all duplicate copies of the Information in his or his employees’ possession (electronic as well as hard copy format) are destroyed.

8. 9th January, 2026 Statutory Instruments 287 The Recipient shall take all reasonable measures to protect the security and integrity of the Information. If requested to do so by the Information Owner, the Recipient shall forthwith at his expense return to the Information Owner all hard copy material and electronic media containing the Information supplied to him by the Information Owner. The Recipient shall furthermore ensure that all duplicate copies of the Information in his or his employees’ possession (electronic as well as hard copy format) are destroyed. The Recipient shall report any leak of the Information, howsoever caused, to the Information Owner as soon as practicable after he becomes aware of the leak, and shall provide to the Information Owner with all reasonable assistance to ensure its recovery or destruction (as deemed appropriate by the Information Owner). Signed at ………………………………………………… on this the ……..............…… day of ……………………………. by (full name) …………………………………......…….in his/her capacity as …………………………………….......................................…........…. on behalf of ……………………………………......……, the Information Owner…………..……………… Signed at ………………………………………………… on this the …….............…… day of ……………………………. by (full name) ……………………………......………….in his/her capacity as …………………………………………. on behalf of …………………………………………, the Recipient 288 Statutory Instruments 9th January, 2026 APPENDIX 4 (Chapter 5 – General Provisions) Exemption Request Form FORM XV GC E No:………………………… Text to be exempted from: Section(s)…………………. Page(s)………………... Reason for exemption (if additional space is required, please use attachments) ..…………………………………………………………………..........................................…… ……………………………………………………………………………..................................... ……………………………………………………………………………...........………………… ………………………………………………………………………….....................…………… Additional Information (if additional space is required, please use attachments) ……………………………………………………….………………………………………....… ………………………………………………………………………………………………………… ……………………………………………………………………………………………………… Duration: From:……………………To:………………………………………………………. Exemption Applicant’s Name:…………. Date ……………………………….. Checked by: (Secretariat) ……………………. ………………….Date ………………………………… Recommended by: (GCTC Chairperson) ……………………. ………..Date ………………………………… Approved/Not approved: (ERB BOARD CHAIRPERSON)………………… Date ………………………………… 9th January, 2026 Statutory Instruments 289 APPENDIX 4 (Chapter 5 – General Provisions) Log of Disputes between Participants Dispute No. Complainant Defendant Complaint Resolution DESCRIPTION DATE DESCRIPTION DATE FORM XVI 290 Statutory Instruments 9th January, 2026 APPENDIX 4 (Chapter 5 – General Provisions) FORM XVII Register of Participants and Exemptions CODE: REFERENCE NO. PARTICIPANTS EXEMPTIONS (REASON FOR EXEMPTION) REQUESTED BY EXPIRY DATE 9th January, 2026 Statutory Instruments 291 APPENDIX 5 (Chapter 3- System Operation and Chapter 4 -Information Exchange) Generator Performance Data Generator performance data is a means of providing a measurement of generating station processes. A combination of different metrics yields indicators that provide an objective assessment of critical parameters on the performance of key processes. They are used to identify non-performing areas in order to facilitate improvements. This is also used to provide industry with statistical data on how well the industry is performing. The indicators will provide generating stations in Zambia an opportunity to benchmark their performance against other best run hydro power stations in the world. It also offers these station’s management data for strategic management. The Key Performance Indicators report on each station’s efficiency and effectiveness is at a tactical level. The assumption here is that, even when a generating station is embedded in a vertically integrated utility, it is very possible to measure these statistics against a common benchmark. For the purpose of these indicators, all generation equipment outages will be considered planned and scheduled at every beginning of the year. All other outages procured during the progression of the year will be considered unplanned. (a) Reliability This indicator will be expressed in terms of Unit Capability Factor (UCF). The purpose of this indicator is to monitor progress in attaining high unit and plant energy production availability. It reflects the effectiveness of plant programmes and practices in maximizing available electrical generation and provides an overall indication of how well the plant was operated and maintained. It comprises Planned Capability Loss Factor (PCLF) and Unplanned Capability Loss Factor (UCLF) and it is expressed as a difference between 100% and the percentage attributed to PCLF and UCLF. UCF  100  PCLF  UCLF (i) Unplanned capability loss factor (UCLF) The purpose of this indicator is to monitor industry progress in minimising outage time and power reductions that result from unplanned equipment failures or other conditions. This indicator reflects the effectiveness of plant programmes and practices in maintaining systems available for safe electrical generation. It is therefore an expression of energy lost due to unplanned outages, against the total available energy, calculated as a percentage. UCLF  UnplannedM Whlost %100 TotalMWhde * signed (ii) Planned capability loss factor (PCLF) Planned capability loss factor is defined as the ratio of the planned energy losses during a given period of time to the reference energy generation expressed as a percentage. 292 Statutory Instruments 9th January, 2026 Planned energy loss is energy that was not produced during the period because of planned shutdowns or load reductions due to causes under plant management control. Energy losses are considered to be planned if they are scheduled and appear on the System Yearly Maintenance Program. It will stimulate detailed scrutiny and predictability of generating plant so that outages are focused and scheduled one (1) year in advance. PCLF  PlannedMWh lost TotalMWhde %100 * signed (b) Internal Reliability Loss Factor This factor is expressed to measure the number of internal factors leading to reduction in Reliability of generating plant against the total reduction in Reliability. It is therefore expressed as a percentage of energy lost due to internal faults leading to lost generation against available energy during the period. UnplannedM IRLF  Whlostduet o TotalMWhav int ailable ernalfault s * %100 (c) External Reliability Loss Factor This factor measures the influence that external factors leading to forced outages has on the generating plant. Such factors could include transmission line trippings/ outages, deferred maintenance activities due to system load changes, cascade trippings and many others. It is expressed as a percentage of energy losses due to faults external to the generating plant, leading to loss of generation against total available energy during the given period. UnplannedM ERLF  Whlostduet TotalMWhAv oexternalf ailable aults * %100 (d) Mean-Time-To-Repair (MTTR) This factor measures the average time used to carry out repairs due to faults in any given period. It is expressed as the sum of all durations generating units were disconnected from the grid due to internal faults against the total number of breakdowns due to internal faults. n n t n 1  T * %100 Where; t = time duration for each internal fault n = outage number T is the total number of outages in the period. (e) Mean-Time-Between-Failures (MTBF) This is expressed as the total time in a given period divided by the number of internal faults plus

1. It is meant to express on an average the time between any two failures following each other. 9th January, 2026 Statutory Instruments 293 Mean-Time-To-Repair and Mean-Time-Between-Failures are two factors that are used to measure the quality of maintenance being carried out on generating plant. (f) Start-up Failure Rate (SFR) This is expressed as the number of times a generating unit or plant fails to connect to the grid at the required time against the total number of requested synchronizations. This measure is used to gauge under-frequency recovery time. SFR  NumberOffa NumberOfCo iledStartU ps ntractedSt %100 artUps Start-up comprises the set of operations that enable the unit to be connected to the off-site power grid for the production of electrical energy according to requirements issued by the SO. It includes all the necessary “de-isolations” and rendering to “normal” all equipment required for generation. The contracted start-up refers to the number of start-up instructions issued and received from the System Operation by the Generation Control Room. (g) Total Unplanned Station Shutdowns (TUSS) This is the total number of times that a generating station separates with the grid. It could either be as a result of an internal or external unplanned factor, but leading to a total station outage. It measures the protection requirements defined in the Network chapter, section 4.1, or it could be declared as an Ancillary Service as declared in the System Operations chapter section 7. 294 Statutory Instruments 9th January, 2026 APPENDIX 6 (Chapter 3- System Operation) Safety Across Boundaries - RISSP Recording of Safety Precautions RISSP 1 Agreement of Safety Precautions When a User or the SO wishes to carry out work and/or testing on or near its system and it is of the opinion that, for this to be done safely, Safety Precautions are required on the other’s System the following process shall be undertaken:

2. in the case of work on the SO’s HV or EHV apparatus, the SO’s Requesting Safety Co-ordinator will contact the User’s Implementing Safety Co-ordinator; or in the case of work on the User’s HV apparatus the User’s Requesting Safety Co-ordinator will contact the SO’s Implementing Safety Co-ordinator; in either case this contact is made in order to agree, the location at which the Safety Precautions will be implemented or applied. When a SO wishes to carry out work and/or testing on or near the Transmission System and it is of the opinion that, for this to be done safely, Safety Precautions are required on (or relating to) more than one User system the provisions of this Appendix shall be followed with regard to each User separately. RISSP 2 Agreement of Isolation The Requesting Safety Co-ordinator shall inform the Implementing Safety Co- ordinator of the HV or EHV apparatus on which Safety from the system is to be achieved and they will need to reach agreement on the location(s) at which Isolation is to be established on (or relating to) the Implementing Safety Co-ordinator’s system. The Implementing Safety Co-ordinator shall then promptly inform the Requesting Safety Co-ordinator of the following: 3 4 5 for each location, the identity (by means of name and numbering or position, as applicable) of each point of Isolation; whether Isolation is to be achieved by an Isolating Device in the isolating position or by an adequate physical separation or sufficient gap or by disablement (by means of switching or dismantling) of Plant and/or apparatus so that electrical energy cannot pass from the apparatus (or, in the case of Plant, from the associated apparatus) to the HV or EHV apparatus, other than by an Isolating Device; and the procedures to be taken under Safety Rules being applied to clearly identify the isolated equipment and points of Isolation and to ensure that no inadvertent re-energization can take place. The Implementing Safety Co-ordinator shall maintain each point of Isolation in accordance with the relevant Local Safety Instructions until the Requesting Safety Co-ordinator confirms that Isolation is no longer required and that it is safe (including any arrangements for Earthing implemented by the Requesting Safety Co-ordinator) to re-energise the previously Isolated part of the system. 9th January, 2026 Statutory Instruments 295 RISSP 3 Agreement of Earthing If, in addition to the Isolation requested when the Requesting Safety Co-ordinator requires Earthing, the Requesting Safety Co-ordinator shall notify this requirement to the Implementing Safety Co-ordinator and they must reach agreement on the location(s) at which Earthing is to be established on the Implementing Safety Co- ordinator’s system until the Requesting Safety Co-ordinator confirms that the arrangements for Earthing are no longer required. The Implementing Safety Co-ordinator shall then promptly inform the Requesting Safety Co-ordinator for each location, the identity (by means of apparatus name and numbering or position, as is applicable) of each point of Earthing. The Implementing Safety Co-ordinator shall maintain each point of Earthing in accordance with the relevant Local Safety Instructions. RISSP 4 In the event of Disagreement In any case where the Requesting Safety Co-ordinator and the Implementing Safety Co-ordinator are unable to agree the location of the Isolation and (if requested) Earthing, it shall be at the closest available points on the in-feeds to the apparatus on which safety from the system is to be achieved. The closest point will be as indicated on the Ownership Boundary Diagram or, in the case where, by reason of the design of any HV or EHV apparatus on which Safety Precautions are to be applied, it is not practicable to apply Safety Precautions on that apparatus, it shall be at the most appropriate point(s) on the User’s Plant and/or apparatus to achieve safety from the system, as determined by the DSP. RISSP 5 Implementation of Isolation and Earthing Once the location of Isolation and (if requested) Earthing are agreed, the following procedure will apply: 6 7 the Implementing Safety Co-ordinator will ensure the implementation of the Isolation; the Implementing Safety Co-ordinator will confirm to the Requesting Safety Co-ordinator that the Isolation has been established on their system; RISSP 6 Work Following confirmation by the Implementing Safety Co-ordinator to the Requesting Safety Co-ordinator that all of the agreed Safety Precautions have been established on or relating to the system of the Implementing Safety Co-ordinator, the Implementing Safety Co-ordinator will record in Section 1.1. of his RISSP-B the details of the HV apparatus on which the Implementing Safety Co-ordinator has been told that safety from the system is required. The Implementing Safety Co- ordinator will also record the Safety Precautions established on or relating to the system of the Implementing Safety Co-ordinator onto parts 1.1 and 1.2 of his RISSP-B. Where Earthing was not requested (either because Earthing was possible but was not required or because Earthing was not possible), part 1.2(b) of the RISSP-B will be completed with the words “not Earthed”. The Implementing Safety Co-ordinator shall then contact the Requesting Safety Co- ordinator and confirm, by reading out the details entered on parts 1.1 and 1.2 of RISSP-B, to the Requesting Safety Co-ordinator, that the Safety Precautions have been established. 296 Statutory Instruments 9th January, 2026 The Requesting Safety Co-ordinator will then complete parts 1.1 and1.2 of RISSP- A with the precise details received from the Implementing Safety Co-ordinator and then read back all those details to the Implementing Safety Co-ordinator. If both confirm that the details entered are the same, the Requesting Safety Co-ordinator shall issue the RISSP identifying number, as stated on the RISSP-A, to the Implementing Safety Co-ordinator who shall ensure that the number, including its prefix and suffix, is correctly entered on the RISSP-B. The Requesting Safety Co-ordinator and the Implementing Safety Co-ordinator shall then respectively complete part 1.3 of RISSP-A and RISSP-B (which relates to the identity and location of the Implementing Safety Co-ordinator and the Requesting Safety Co-ordinator respectively). Each Safety Co-ordinator shall then complete the issue of the RISSP by signing part 1.3 of their respective RISSPs and then enter the time and date. Once signed, no alteration to the RISSP is permitted; the RISSP may only be cancelled. If a change is required then the original RISSP shall be cancelled and a new RISSP shall be issued following the above RISSP procedure so that the new RISSP incorporates the required alterations. For the avoidance of doubt, if the need for an alteration to a RISSP is discovered after the commencement of work or testing, procedures in Safety Rules shall immediately be implemented to remove all persons from danger and secure the zone until the procedure under a new RISSP has been completed. The signed copy of the RISSP shall be transmitted in facimile form by an agreed method by both the Requesting Safety Co-ordinator and the Implementing Safety Co-ordinator for confirmation. The Requesting Safety Co-ordinator is then free to authorise work, but not testing. Where testing is to be carried out, the testing procedure set out below shall be implemented. The procedure for carrying out the work is entirely an internal matter for the Party which the Requesting Safety Co-ordinator is representing. RISSP 7 Testing Where the Requesting Safety Co-ordinator wishes to authorise the carrying out of a test to which the procedures in this procedure apply the Requesting Co-ordinator may not do so and the test will not take place unless and until the following procedures have been followed: 8 9 confirmation is obtained from the Implementing Safety Co-ordinator that no person is working on, or testing, or has been authorized to work on, or test, any parts of the systems within the points of Isolation identified on the RISSP form relating to the test which is proposed to be undertaken (the “original RISSP”), and the points of Isolation on the Requesting Safety Co- ordinator’s system, and will not be so authorized until the proposed test has been completed (or cancelled) and the Requesting Safety Co-ordinator has notified the Implementing Safety Co-ordinator of its completion (or cancellation) and thereby the cancellation of the requirements; all current RISSPs (except for the original RISSP under which Testing is to be carried out) between the Requesting Safety Co-ordinator and the Implementing Safety Co-ordinator which relate to those parts of the system s between the points of Isolation identified on the original RISSP (under which Testing is to be carried out) and the points of Isolation under these RISSPs on the Requesting Safety Co-ordinator’s system), have been cancelled. ; and 10 the Implementing Safety Co-ordinator agrees with the Requesting Safety Co- ordinator to permit the testing on those parts of the system s between the points of Isolation identified in the original RISSP and the points of Isolation on the Requesting Safety Co-ordinator’s system. 9th January, 2026 Statutory Instruments 297 The Requesting Safety Co-ordinator will inform the Implementing Safety Co- ordinator as soon as the test has been completed or cancelled. Where Earthing has been removed during a test and has not been restored at the original position upon completion or cancellation of the test, the original RISSP shall be cancelled.. RISSP 8 Cancellation When the Requesting Safety Co-ordinator decides (having followed all relevant internal procedures) that Safety Precautions are no longer required, the Requesting Safety Co-ordinator will contact the Implementing Safety Co-ordinator and provide the identifying number of the RISSP. The Requesting Safety Co-ordinator shall read out to the Implementing Safety Co-ordinator the details entered on parts 1.1 and 1.2 of his RISSP-A, and the Implementing Safety Co-ordinator shall confirm that the details entered on parts 1.1 and 1.2 of the RISSP-B are the same. The Requesting Safety Co-ordinator shall then confirm to the Implementing Safety Co-ordinator that the Safety Precautions are no longer required. The Requesting Safety Co-ordinator and the Implementing Safety Co-ordinator shall then respectively complete part 2.1 of RISSP-A and RISSP-B (which relates to the identity and location of the Implementing Safety Co-ordinator and the Requesting Safety Co-ordinator respectively). Each Safety Co-ordinator shall then complete the cancellation of the RISSP procedure by signing part 2.1 of their respective RISSPs and then entering the time and date. The Implementing Safety Co-ordinator is then free to arrange the removal of the Safety Precautions, the procedure to achieve that being entirely an internal matter for the Party which the Implementing Safety Co-ordinator is representing. The only situation in which any Safety Precautions may be removed without first cancelling the RISSP is when Earthing is removed for the purpose of testing. The RISSP having been cancelled, all the co-ordination and Information exchange is required during the removal of Earths and switching processes shall be carried out using a telecommunication system preferably having voice recording facility. Where Earthing has been requested neither Safety Co-ordinator shall instruct the removal of any Isolation forming part of the Safety Precautions until it is confirmed to each by the other that all Earthing has been removed. This must be confirmed using a telecommunication system preferably having voice recording facility. RISSP 9 Loss of Integrity of Safety Precautions In any instance when any Safety Precautions may be ineffective for any reason the relevant Safety Co-ordinator shall without delay inform the other Safety Co- ordinator(s) of that being the case and, if requested, of the reasons why. The work must be stopped and procedures in the Safety Rules shall immediately be implemented to remove all persons from danger and secure the zone until the conditions have been re-accessed and restored to the original level. RISSP 10 Safety Log The SO and each User shall maintain a safety log which shall be a chronological record of all messages relating to Safety Coordination sent and received by the Safety Co-ordinator(s). The safety log must be retained for a period of not less than 3 years. 298 Statutory Instruments 9th January, 2026 [CONTROL CENTRE/SITE] RECORD OF INTER-SYSTEM SAFETY PRECAUTIONS RISSP - A (RISSP-A)] (To be completed by the Requesting Safety Co-ordinator) RISSP Number

1.1 HV APPARATUS IDENTIFICATION Safety Precautions have been established by the Implementing Safety Co-ordinator to achieve (in so far as it is possible from that side of the Point of Connection) safety from the system on the following HV apparatus on the Requesting Safety Co-ordinator’s system: [state identity - name(s) and, where applicable, identification of the HV circuit(s) up to the Point of Connection]:

1.2 SAFETY PRECAUTIONS ESTABLISHED ISOLATION [State the location(s) at which Isolation has been established. For each location, identify each point of Isolation. For each point of Isolation, state the means by which the Isolation has been achieved and whether immobilised and locked, safety notice affixed or other safety procedures applied, as appropriate.] [State the location(s) at which Earthing has been established. For each location, identify each point of Earthing. For each point of Earthing, state the means by which the Earthing has been achieved and whether immobilised and locked or other safety procedures applied, as appropriate]. EARTHING

1.3 ISSUE I have received confirmation from ________________ (name of Implementing Safety Co-ordinator) at __________________(location) that the Safety Precautions identified in paragraph 1.2 have been established and that instructions will not be issued at his location for their removal until this RISSP is cancelled. Signed __________________(Requesting Safety Co-ordinator) at ____________________ (time) on ___________________(date) 9th January, 2026 Statutory Instruments 299 PART 2

2.1 CANCELLATION I have confirmed to _______________________(name of the Requesting Safety Co-ordinator) at _____________________ (location) that the Safety Precautions set out in paragraph 1.2 are no longer required and accordingly the RISSP is cancelled. Signed _____________________ (Requesting Safety Co-ordinator) at ________________________(time) on ___________________________(Date) 300 Statutory Instruments 9th January, 2026 [CONTROL CENTRE/SITE] RECORD OF INTER-SYSTEM SAFETY PRECAUTIONS RISSP - B (To be completed by the Implementing Safety Co-ordinator) (RISSP-B)] RISSP Number PART 1

2.1 CANCELLATION I have confirmed to _______________________(name of the Implementing Safety Co-ordinator) at _____________________ (location) that the Safety Precautions set out in paragraph 1.2 are no longer required and accordingly the RISSP is cancelled. Signed _____________________ (Requesting Safety Co-ordinator) at ________________________(time) on ____________________(Date) 302 Statutory Instruments 9th January, 2026 APPENDIX 7 (Chapter 4 – Information Exchange) Generator Maintenance Data (a) The 52-weeks-ahead outage plan per week per generator shall be updated weekly to the SO in the format shown below: Annual Maintenance Schedule Station Name:_______________________________ Unit No. Activity MW lost 1 2 3 4 5 … … n+51 Week 1 Annual Maintenance 2 Annual Maintenance 2 Governor modernization 3 Transformer oil 100 100 100 150 ETC. (b) The annual maintenance/outage plan per generator, looking 15 years ahead, shall also be supplied to the SO. The format shall be quarterly based as follows: Five Year Ahead Maintenance Schedule Station Name:__________________ Unit No. Activity MW lost 1 Annual Maintenance 2 Annual Maintenance 2 Governor modernization 3 Transformer oil etc Years 1 2 3 4 5 15 15+1 15+n 9th January, 2026 Statutory Instruments 303 (c) A weekly variance report, explaining the differences between the planned and actual outages, shall be supplied to the SO as shown below: Outage Start Date End Date Reason for difference Unit No Description Plan Actual Plan ACTUAL 304 Statutory Instruments 9th January, 2026 APPENDIX 8 (Chapter 4 – Information Exchange) Operational Data This appendix specifies the data format to be used by the SCADA system for the mapping of RTU data into the SCADA database. The database has a definition for each electrical configuration (ELC) or electrical object in the station. Each ELC definition specifies a different ELC type, e.g. transformers, units, feeders, etc, and is accompanied by a picture showing the ELC and all its associated devices as they would be indicated on the SO operational one-line displays. In each instance, the picture defines the primary devices and is followed by the points belonging to each device. Description of table column headings used in this section The headings in the tables of this section are described as follows: (a) Device Gives the name of the device and acts as a collector of all point information belonging to the device. Each binary status point can be mapped to one or two binary bits. In the case of a breaker or SOlator, the state is reported via two bits. In the case of single-bit alarm points, only one bit is used to report the state of the indication. 01_state This is the alarm state of the point. 10_state This is the normal state of the point. In the table above the TYPE column indicates the number of bits used to report the state of the point in question. For single-bit points please ignore the left-hand 0 or 1 value in the headings “01-State” and “10-State”. Where an indication uses two bits to report the state, the right-hand bit is used report that the state is OPEN and the left-hand bit to report the state when it is CLOSED. Thus an open condition will be “01” and a closed state will be “10”. It is thus illogical for a device to have a permanent value of either “00” or “11”. However, if the device is in transit between “01” and “10” then a temporary value of “00” is possible. The SCADA system reports a state of “00” as “In transit”, which will normally only be seen on slow-moving devices such as Isolators. (b) Category defines the category the point belongs to: Health, Main Protection, Back-up Protection or Information. Classical alarm systems attempt to set priorities on alarm points. However, the priority of a point changes as the system changes, which means having a fixed priority is not useful. As an alternative, the approach used here is to assign the point to the area that is affected by the indication. In this case we have four areas, namely: Health Main Protection Backup Protection Information All alarm indications that refer to the health of the primary or secondary plant are assigned to this category. All protection activity that is triggered by the Main 1 protection circuits is assigned to this category. Where back-up protection is installed, such as on transformers, or where Main 2 protection is used, these alarms are assigned to this category. Pure state change data such the state of a breaker or Isolator are assigned to this category. As such, no alarming is associated with these points – the data presented is pure information. 9th January, 2026 Statutory Instruments 305 (c) Type Indicates the type of point – single-bit, double-bit, analogue or binary change detection. (d) Control Indicates if there is a supervisory control associated with the point A5.1 Generator The generator shall install operational measurements to specification from the SO so as to provide continuous operational information for both real time and recording purposes in relation to each unit at each power station in respect of the following: (a) Gas turbines Unit isolator Pole Unit isolator state Unit HV Breaker Breaker failed to trip Bus zone trip Earth applied Pole Protection abnormal Protection operated Protection unhealthy Breaker gas critical Breaker non-urgent Unit breaker state CT SF6 gas critical (CT) SF6 non-critical (CT) Unit Step Up Transformer Reactive power Active power Unit LV Breaker Breaker failed to trip Earth applied Pole Breaker gas critical Breaker non-urgent Unit breaker state Unit 01_State Disagree Open 01_State Alarm Alarm Alarm Disagree Alarm Alarm Alarm Alarm Alarm Closed 01_State Alarm Alarm 01_State 01_State Alarm Alarm Disagree Alarm Alarm Closed 01_State 10_State Normal Closed 10_State Normal Normal Normal Normal Normal Normal Normal Normal Normal Tripped 10_State Normal Normal 10_State 10_State Normal Normal Normal Normal Normal Tripped 10_State Category Health Info Category Main Info Health Health Health Main Health Health Info Info Category Health Health Category Info Info Category Main Health Health Health Info Info Category Type Single Double Type Single Single Single Single Single Single Single Single Single Double Type Single Single Type Analogue Analogue Type Single Single Single Single Single Double Type Control False False Control False False False False False False False False False False Control False False Control False False Control False False False False False False Control 306 Statutory Instruments 9th January, 2026 01_State Ready Ready Alarm On Alarm Auto Unit Engine A Engine B Frequency Unit start not ready Remote control SCO start not ready Sequence starting Stator voltage Supervisory Under-frequency start Unit at standstill Unit auto load to base Unit auto load to minimum Unit auto load to peak Unit failed to start Unit voltage Unit in generation mode Unit in SCO mode Unit load rate Unit loading mode Unit generated Unit reactive power sent out Unit active power generated Unit active power sent out Unit tripped and locked out Alarm Initiate Unit under frequency start Isolated Armed Yes Yes Yes Yes Alarm Yes Yes Fast Auto reactive power (b) Hydro units 10_State Not ready Not ready Normal Off Normal Manual Off Off Normal No No No Normal No No Slow Manual Normal No Category Health Health Info Health Info Health Info Info Info Health Info Info Info Info Health Info Info Info Info Info Info Info Info Info Info Info Type Single Single Analogue Single Single Single Single Analogue Single Single Single Single Single Single Single Analogue Single Single Single Single Analogue Analogue Analogue Analogue Single Single Control False False False False True False False False False False True True True True False False True True True False False False False False False False 9th January, 2026 Statutory Instruments 307 Unit Isolator 1 Pole Unit Isolator state Unit Isolator 2 Pole Unit Isolator state Unit HV Breaker Breaker failed to trip Bus zone trip Earth applied Pole Protection abnormal Protection operated Protection unhealthy Breaker gas critical Breaker non-urgent Unit breaker state CT SF6 gas critical (CT) SF6 non-critical (CT) Unit LV Breaker Breaker failed to trip Earth applied Pole Breaker gas critical Breaker non-urgent Unit breaker state Unit Step Up Transformer Reactive power Active power Isolator 3 Pole Unit Isolator state Isolator 4 Pole Unit Isolator state Unit Frequency Auto load Automatic power regulator Emergency trip Unit start not ready Unit to pump mode Unit to SCO mode Pump start not ready Pump to generation mode Pump to SCO mode SCO start not ready SCO to generation mode SCO to pump mode Sequence starting Stator voltage Under-frequency start Unit AGC – high limit Unit AGC – high regulating limit Unit AGC – low limit factor 01_State Disagree Open 01_State Disagree Open 01_State Alarm Alarm Alarm Disagree Alarm Alarm Alarm Alarm Alarm Closed 01_State Alarm Alarm 01_State Alarm Alarm Disagree Alarm Alarm Closed 01_State 01_State Disagree Open 01_State Disagree Open 01_State 10_State Normal Closed 10_State Normal Closed 10_State Normal Normal Normal Normal Normal Normal Normal Normal Normal Tripped 10_State Normal Normal 10_State Normal Normal Normal Normal Normal Tripped 10_State 10_State Normal Closed 10_State Normal Closed 10_State Active Operated Normal Normal Operated Alarm Active Active Alarm Active Active Alarm Active Active Auto Info Armed High Health Normal Normal Off Off Normal Off Off Normal Off Normal Manual Analogue Off Normal Analogue Category Health Info Category Health Info Category Main Info Health Health Health Main Health Health Info Info Category Health Health Category Main Health Health Health Info Info Category Info Info Category Health Info Category Health Info Category Info Info Health Main Health Info Info Health Info Info Health Info Info Info Log_only Health Health Panel Type Single Double Type Single Double Type Single Single Single Single Single Single Single Single Single Double Type Single Single Type Single Single Single Single Single Double Type Analogue Analogue Type Single Double Type Single Double Type Analogue Single Single Single Single Single Single Single Single Single Single Single Single Single No Single Single No Control False False Control False False Control False False False False False False False False False False Control False False Control False False False False False False Control False False Control False False Control False False Control False True True True False True True False True True False True True False False False Low Normal Health Single False 308 Statutory Instruments 9th January, 2026 limit Unit AGC – raise/lower blocking Unit AGC – ramp rate Unit AGC – set-point active power Unit AGC – status Unit at standstill Unit voltage Unit guide vane Unit in generation mode Unit in pump mode Unit in SCO mode Unit load limiter reactive Unit generated Unit reactive power sent out Unit active power generated Unit active power sent out Unit synchronising Unit turning in generation direction Unit direction in motor turning power Off Normal On Yes Yes Yes Yes Yes Yes Yes Off Normal No No No No No No Info Info Info Info Info Info Info Info Info Info Info Info Info Info Info Info Info Info Single False Analogue Analogue Single Single Analogue Analogue Single Single Single Analogue Analogue Analogue Analogue Analogue Single Single False True False True False True True True True True False False False False False False Single False (c) Steam units Unit Isolator 1 Pole Unit Isolator state Unit Isolator 2 Pole Unit Isolator state Unit HV Breaker Breaker failed to trip Bus zone trip Earth applied Pole Protection abnormal Protection operated Protection unhealthy Breaker gas critical Breaker non-urgent Unit breaker state 01_State Disagree Open 01_State Disagree Open 01_State Alarm Alarm Alarm Disagree Alarm Alarm Alarm Alarm Alarm Closed 10_State Normal Closed 10_State Normal Closed 10_State Normal Normal Normal Normal Normal Normal Normal Normal Normal Tripped Category Health Info Category Health Info Category Main Info Health Health Health Main Health Health Info Info Type Single Double Type Single Double Type Single Single Single Single Single Single Single Single Single Double Control False False Control False False Control False False False False False False False False False False Tripped 10_State Normal Normal 10_State Closed 01_State Alarm Alarm 01_State 10_State Normal Normal Normal Normal Normal Tripped 10_State Normal 01_State Alarm Alarm Disagree Alarm Alarm Closed 01_State High Info Category Health Health Category Info Info Category Main Health Health Health Info Info Category Health Health 9th January, 2026 Statutory Instruments Unit breaker state CT SF6 gas critical (CT) SF6 non-critical (CT) Unit Step Up Transformer Reactive power Active power Unit LV Breaker Breaker failed to trip Earth applied Pole Breaker gas critical Breaker non-urgent Unit breaker state Steam Unit Unit AGC – high limit Unit AGC – high regulating limit Unit AGC – low limit Unit AGC – low regulating limit Unit AGC – raise/lower blocking Unit AGC – ramp rate Unit AGC – set-point active power Unit AGC – status Unit voltage Unit islanded Unit generated Unit reactive power sent out Unit active power generated Unit active power sent out Info Info Health Info Health Health Info Info Info Info Info reactive Normal Normal power Alarm Low Info Off Off On No Double Type Single Single Type Analogue Analogue Type Single Single Single Single Single Double Type Single Analogue 309 False Control False False Control False False Control False False False False False False Control False False Single Analogue False False Single False Analogue Analogue Single Analogue Single Analogue Analogue Analogue Analogue False True False False False False False False False Generators contributing to regulating reserve shall provide indications for emergency generation and maximum generation for rescheduling. A5.2 Distributor and end-use customer (a) Transmission equipment The Customer shall provide operational information for both real time and recording purposes in relation to each feeder, transformer and compensation device at each substation required for the full functionality of a SVC, as well as full control by the SO. Interruptible Load (b) All interruptible loads shall meet the minimum requirements. The SO shall negotiate and integrate the conditions as presented in bilateral agreements and additional contracts without reducing the requirements as defined in this Grid Code. The interruptible load shall install operational measurements to specification so as to provide operational information for both real time and recording purposes in relation to each controllable energy block in respect of the following minimum requirements for operation and control of a interruptible load: 310 Statutory Instruments 9th January, 2026 01_State Disagree Closed 01_State Closed 01_State Alarm Alarm 01_State No Isolator Pole Isolator state Breaker Unit breaker state CT SF6 gas critical (CT) SF6 non-critical (CT) Load Load acknowledged Load interrupt acknowledged No No Block load acknowledged Return acknowledged Load active power reduction reduction service No to LUSAKA 9th January, 2025 [MOE/DPI.64/9/2] 10_State Normal Open 10_State Tripped 10_State Normal Normal 10_State Yes Yes Yes Yes Category Health Info Category Info Category Health Health Category Info Info Info Info Info Type Single Double Type Double Type Single Single Type Single Single Single Single Control False False Control True Control False False Control True True True True Analogue False M. CHIKOTE, Minister of Energy

1.1 HV APPARATUS IDENTIFICATION Safety Precautions have been established by the Implementing Safety Co-ordinator to achieve (in so far as it is possible from that side of the Point of Connection) safety from the system on the following HV apparatus on the Requesting Safety Co-ordinator’s system: [state identity - name(s) and, where applicable, identification of the HV circuit(s) up to the Point of Connection]:

1.2 SAFETY PRECAUTIONS ESTABLISHED ISOLATION [State the location(s) at which Isolation has been established. For each location, identify each point of Isolation. For each point of Isolation, state the means by which the Isolation has been achieved and whether immobilised and locked, safety notice affixed or other safety procedures pplied, as appropriate.] EARTHING [State the location(s) at which Earthing has been established. For each location, identify each point of Earthing. For each point of Earthing, state the means by which the Earthing has been achieved and whether immobilised and Locked or other safety procedures applied, as appropriate].

1.3 ISSUE to have I confirmed (name of Requesting Safety Co- ________________________ (location) that the Safety Precautions identified ordinator) at in paragraph 1.2 have been established and that instructions will not be issued at my location for their removal until this RISSP is cancelled. Signed ______________________ (Implementing Safety Co-ordinator) at ______________________ (time) on _____________________ (date) 9th January, 2026 Statutory Instruments 301 PART 2