CNCS Grid Code

Version December 2022

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DC 1 — PURPOSE AND SCOPE

The purpose of the Distribution Code is to establish the rules, procedures, requirements and standards governing the operation, maintenance and development of the Distribution System in order to ensure an efficient, coordinated and economic electricity distribution system. It also defines the procedures and requirements applicable to the Distribution Licensee and all Users of the Distribution System.

The Distribution Licensee as well as existing and potential Users connected to or seeking to connect to the Distribution System shall comply with the relevant sections of the Distribution Code, including Distributed Generators and Customers. Users connected to the Distribution System shall comply with the Distribution Code. The Interconnection Boundary between the Transmission and Distribution Systems shall be as defined in Section TC 1.1 of the Transmission Code.

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DC 2 — GENERAL REQUIREMENTS

This Distribution Code contains the procedures for providing an adequate, safe and efficient electricity distribution service to all regions of Mauritius, taking into account a wide range of Normal and Contingency Conditions. When unforeseen situations arise, the Distribution Licensee shall act as a reasonable and prudent operator in pursuit of one or more of the following general requirements:

• The need to preserve the integrity of the System
• Preventing damage to the System
• Compliance with the conditions of its Licence
• Compliance with the Electricity Act 2005 and its amendments
• Compliance with the Distribution Code

Users shall provide the reasonable cooperation and assistance that the System Operator reasonably requests in pursuit of the general requirements of this Section DC 2.

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DC 3 — DISTRIBUTION SYSTEM PLANNING

DC 3.1 — Purpose and Scope

The Distribution Licensee together with the Single Buyer shall be responsible for planning the development of the Distribution System. The Authority shall provide Ministerial policy guidelines for system development. The Single Buyer shall develop procedures for the elaboration of a long-term Integrated Resource Plan (IRP) (10-year horizon, updated annually), involving key stakeholders in a collaborative process. The Distribution Licensee and the Transmission Licensee shall be responsible for implementing the upgrading and expansion of the Transmission and Distribution Systems as defined in the IRP.

DC 3.2 — Distribution System Planning Criteria

DC 3.2.1 — Principles

The Distribution System planning criteria shall be based on Prudent Utility Practices and relevant international standards. The overriding principle is the responsibility of the Distribution Licensee to “maintain any installation, apparatus or premises related to its licence in such a state as to be able to provide a safe, adequate and efficient electrical service”.

DC 3.2.2 — Planning Criteria

• Back-up supply from the System for all branch lines with a load exceeding 100 A and 22 kV feeders
• Number of switching operations minimised to allow rapid restoration
• Feeder loading limited to 50 % of the conductor rated current under Normal Conditions
• Voltage regulation within the range ±6 % of the nominal value (230 V/400 V) at the Interconnection Boundary
• Closed 22 kV busbar configuration satisfying the N-1 Security Criterion where required

DC 3.2.3 — Voltage Criteria

• Between +6 % and −6 % of nominal voltage under Normal Conditions (MV and LV busbars)
• Between +10 % and −10 % of nominal voltage under Contingency Conditions (MV and LV busbars)

DC 3.2.4 — Load Power Factor

The Distribution System shall be planned for a demand with a Power Factor between 0.90 capacitive and 0.90 inductive under Normal Conditions.

DC 3.3 — Interconnection Studies

The Distribution Licensee, in collaboration with the Single Buyer and the System Operator, shall undertake interconnection studies whenever necessary, in particular to determine the interconnection requirements of any User System or Generation Plant. The studies include:

• DC 3.3.2 Demand Forecasts: The Distribution Licensee and the Single Buyer develop load forecasts from a Spatial Load Forecast supported by the network Geographic Information System, using an econometric regression methodology.
• DC 3.3.3 Load Flow Studies: Analysed at least for peak and minimum loads, based on metering or SCADA data (30-minute averages), and modelling planned contingency scenarios.
• DC 3.3.4 Voltage Regulation Studies: Taking into account 5-year demand forecasts and the use of tap changers, capacitors and Distributed Generator regulation.
• DC 3.3.5 Short-Circuit Studies: Determination of short-circuit current levels at switching points, ensuring that the breaking and closing capacity of all protection equipment is respected.
• DC 3.3.6 System Loss Studies: Quantification of Active Power losses and determination of optimal network open points.
• DC 3.3.7 Reliability Studies: Determination of theoretical levels of SAIDI (average interruption duration) and SAIFI (average number of interruptions) for the Distribution System. These indices shall be reported to the Authority.
• DC 3.3.8 System Earthing: Design in accordance with the Distribution System Construction Manual, aimed at protecting persons and property, limiting overvoltages and the effects of lightning.

DC 3.4 — Standard Planning Data

DC 3.4.1 Energy and Demand Forecasts: Users connected at MV shall provide their Energy and Demand forecasts for at least the following five years (monthly forecasts for the first year, annual for subsequent years).

DC 3.4.2 Distribution System Data: The Distribution Licensee shall make available to the Single Buyer and the System Operator all data relevant to the Distribution System, in particular transformers, power lines and Distributed Generation Units.

DC 3.4.3 User System Data: For LV connections: maximum power required and type of loads. For MV connections: Active/Reactive Power requirements, load type, maximum harmonic currents, details of cyclic load variations.

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DC 4 — DISTRIBUTED GENERATION

DC 4.1 — Introduction

Section DC 4 of the Distribution Code is applicable to all existing or potential Distributed Generators connected to the LV or MV Distribution System. The Distribution Licensee is responsible for all aspects related to the interconnections of Distributed Generators, including information exchange, the connection process, technical design specifications, safety requirements and compliance monitoring with standards. The Distribution Licensee may refuse the connection of a Distributed Generating Unit if this threatens the security or quality of supply.

DC 4.2 — Distributed Generation Interconnection

DC 4.2.1 — CEB SOLAR PHOTOVOLTAIC SCHEME (HOUSEHOLDS) and MSDG Grid Codes

The Distribution Licensee shall produce a document (DG Grid Code) for each category of Distributed Generation, covering procedural aspects (connection process up to the Connection Agreement) and technical aspects (safety requirements, design, construction, testing, commissioning and administrative aspects). The DG Grid Code shall be approved by the Authority.

DC 4.2.2 — Technical Aspects of the DG Grid Code

The technical aspects of the DG Grid Code shall contain at least:

• Safety, Isolation and Switching Rules (OSH Act 2005)
• Safety concerns and labelling of Electrical Installations
• Applicable standards, guidelines and component specifications
• Installation and compliance certification
• Construction specifications for MSDG 2 and MSDG 3 (switchgear arrangement, description of the interconnection installation, transformer specifications, protection guide, communication requirements)

DC 4.3 — Categories of Distributed Generators

• CEB SOLAR PHOTOVOLTAIC SCHEME (HOUSEHOLDS) — up to 50 kW, connected to the single-phase/three-phase 230/400 V network
• MSDG 1 — from 50 kW to 500 kW, connected to the 22 kV Distribution System via a dedicated 22/0.415 kV transformer where possible
• MSDG 2 — from 500 kW to 4 MW, connected to the 22 kV Distribution System via an MV switchgear panel (MV metering) and an interconnection step-up transformer
• MSDG 3 — from 4 MW to 10 MW, connected via a dedicated 22 kV line to the 22 kV section of the Transmission System

A Generation Plant with a Registered Capacity greater than 4 MW but not exceeding 10 MW connected via a dedicated line to the 22 kV section of the Transmission System shall comply with the requirements applicable to MSDG 3.

DC 4.4 — Connection Capacity

DC 4.4.1 Feasibility: The feasibility of connecting a Distributed Generation Plant shall be confirmed by a Network Interconnection Impact Study, conducted by the Distribution Licensee, on a case-by-case basis.

DC 4.4.2 Connection Studies: For CEB SOLAR PHOTOVOLTAIC SCHEME (HOUSEHOLDS), applications are allocated to the relevant feeder. For MSDG 1/2/3, the Distribution Licensee and the Single Buyer determine the required network modifications by conducting the appropriate studies.

DC 4.4.3 Capacity Allocation: The allocation of capacity to feeders for Distributed Generators shall be carried out in accordance with rules and procedures approved by the Authority.

DC 4.5 — Specific Rules for Distributed Generators

The integrity of the Distribution System and the security and quality of supply to existing Users shall not fall below the standard level due to the parallel (synchronised) operation of Distributed Generators. Parallel operation of the DGP is only permitted if authorised by the Distribution Licensee and the System Operator in accordance with applicable schemes and policies.

DC 4.6 — Provision of Information

Distributed Generators shall provide the Distribution Licensee and the Single Buyer with information on the Generation Plant and the proposed interface arrangements. Required information includes in particular:

• Terminal Voltage (kV), rated kVA/kW, P-Q Capability diagram
• Type of Generation Plant (synchronous, asynchronous, etc.) and primary energy resource
• Single-line diagram of the Distributed Generation Plant and Interconnection Site
• Specifications of the DGP interconnection transformer
• Interface arrangements: synchronisation means, earthing system, connection/disconnection means
• For MSDG 2 and MSDG 3: dynamic models, harmonic emissions (up to the 50th harmonic order), steady-state capacity

DC 4.7 — Technical Requirements

DC 4.7.1 — Design

DC 4.7.1.1 Connection Arrangements: CEB SOLAR PHOTOVOLTAIC SCHEME (HOUSEHOLDS) connected at 230/400 V; MSDG 1 connected at 22 kV via dedicated transformer; MSDG 2 or MSDG 3 connected via 22 kV switchgear panel and interconnection step-up transformer.

DC 4.7.1.2 Interconnection Transformer: The MSDG 1/2/3 interconnection transformer shall be of vector group Dyn11 (Delta on Network side, star on DGP side). The delta winding on the Distribution System side: (i) does not disturb the earth fault protection of the substation; (ii) prevents triple harmonics from reaching the Network; (iii) isolates the DGP from voltage dips due to single-phase earth faults. Alternative vector groups may be used subject to the Distribution Licensee's approval.

DC 4.7.1.3 Earthing:

• CEB SOLAR PHOTOVOLTAIC SCHEME (HOUSEHOLDS): in accordance with IEC 60364-5-55; TT system adopted in the distribution network
• MSDG 1: in accordance with IEC 60364-5-54; in parallel operation, the generator neutral point shall not be earthed. In isolated operation, the neutral-to-earth connection shall be closed via an interlocking system.
• MSDG 2 and MSDG 3: in accordance with BS 7354 and BS 7430; the 22 kV and LV earth electrodes shall be adequately separated.

DC 4.7.1.4 Electromagnetic Emission and Immunity: The Distributed Generation System shall comply with the requirements of IEC 61000.

DC 4.7.1.5 Surge Withstand Capability: The interconnection installation shall have a surge withstand capability (oscillatory and fast transient) in accordance with IEC 62305-3 (test levels of 1.5 kV). The design of control systems shall meet or exceed the requirements of IEEE C37.90.

DC 4.7.2 — Performance Requirements

• Continuous operation at rated power for system frequencies between 49.25 Hz and 50.75 Hz (50 Hz ± 1.5 %)
• Maintaining synchronisation during a Rate of Change of Frequency up to ± 2.5 Hz per second (measured over 500 ms)
• MSDG 1/2/3 shall be capable of operating within the voltage range specified for Contingency Conditions (DC 3.2.3)
• Reactive Power capacity specified in Table 2, available from 20 % of Registered Capacity

DC 4.8 — Protection Requirements

DC 4.8.2 — General Requirements

The coordination and selectivity of the Protection system shall be safeguarded. The Protection system shall provide protection against faults occurring on the Distribution System and the DGP's electrical installations (short-circuit, earth faults, overload) and prevent Islanding.

DC 4.8.3 — Protection Availability

The Distributed Generator shall ensure that all its electrical installations are protected at all times. The DGP shall be protected against: overload, short-circuit, earth faults, overcurrent, abnormal voltages, abnormal frequencies, lightning and loss of mains (ROCOF and vector shift).

DC 4.8.6 — Trip Settings

Distributed Generating Units shall not supply the Distribution System after the formation of a Power Island. The DGP shall be disconnected from the Distribution System within 0.5 seconds of the formation of a Power Island (loss of mains protection, Table 3).

DC 4.8.7 — Reconnection

Following a Protection-initiated disconnection, the DGP shall remain disconnected from the Network until the voltage and frequency at the Interconnection Boundary have remained within Normal Condition limits for at least 3 minutes. Automatic reconnection is only permitted when the disconnection was due to operating parameters being outside normal ranges.

DC 4.8.8 — Synchronisation of AC Generators

The Distributed Generator shall provide and install automatic synchronisation equipment. A Synchronism Check Relay shall be provided on all generator circuit breakers and all other circuit breakers capable of connecting the DGP's installations to the Distribution System.

DC 4.9 — Additional Protection Requirements for MSDG 2 and MSDG 3

DC 4.9.1 — Inter-Tripping Protection (≥1 MW)

The inter-tripping scheme shall be designed and pre-wired so that the tripping of the interconnection feeder circuit breaker at the 22 kV Distribution System Substation causes the tripping of CB1. This scheme is wired but initially disabled for Registered Capacities up to 4 MW only.

Solar PV Power Plants: (1) During daylight hours, upon tripping of the 22 kV circuit breaker on fault, the System Control Engineer remotely opens CB1, which inter-trips CB2 and all other outgoing circuit breakers. After supply restoration, CB1 is remotely reclosed and the MSDG site contact reclosed. (2) At night, circuit breaker CB1 is not opened as there is no PV generation.

DC 4.9.2 — Protection against Relay Malfunction

The "watchdog" function of the protection relay shall issue an alarm in the event of malfunction. For DGPs with a Registered Capacity greater than 1,000 kW, this alarm signal shall (if required) be transmitted to the Distribution System Substation via optical fibre or wireless communication.

DC 4.9.3 — Protection Settings: Grading and Discrimination

For DGPs with a Registered Capacity greater than 500 kW, the Distributed Generator shall submit to the Distribution Licensee the appropriate settings for the grading and discrimination of the interconnection protection (22 kV circuit breaker on the Distribution System side) with upstream protection. The Distributed Generator shall also submit the DGP fault current contribution (three-phase and single-phase-to-earth).

DC 4.9.4 — Additional Protection and Safety Requirements

In addition to the mandatory interlocking systems (IEC 62271-200), an appropriate interlocking mechanism shall prevent the mechanical closing of CB1 onto an energised busbar on the client side. For synchronous/asynchronous machines: (a) a "Dead Bus Live Line" synchronism check relay shall prevent the electrical/remote closing of CB1 if the 22 kV busbar is energised; (b) a synchronism check relay on all generator circuit breakers capable of connecting the DGP to the Network.

DC 4.10 — Black Start Capability

Distributed Generators shall notify the System Operator and the Distribution Licensee if their Generation Plant has a Black Start Capability (ability to restart the Generating Unit in the absence of Network supply).

DC 4.11 — Power Quality

DG electrical installations shall not cause excessive voltage excursions nor deviate from the range maintained by the System Operator. A DGP shall not produce excessive distortion of the sinusoidal voltage or current waveforms, and shall comply with DC 6.

DC 4.12 — Testing and Commissioning

DC 4.12.1 — General Requirements

The Distributed Generator shall carry out tests and pre-commissioning in accordance with relevant standards and keep written records of results. The Distribution Licensee has the right to require ad hoc tests (harmonic distortion levels, voltage rise, protection operation, fault investigations).

DC 4.12.2 — CEB SOLAR PHOTOVOLTAIC SCHEME (HOUSEHOLDS) and MSDG 1

Testing and pre-commissioning of CEB SOLAR PHOTOVOLTAIC SCHEME (HOUSEHOLDS) and MSDG 1 installations shall be carried out by an Installer.

DC 4.12.3 — MSDG 2 and MSDG 3

For Greenfield projects, the Distributed Generator shall submit the test procedures to the Distribution Licensee for approval at least 3 months before the planned Commercial Operation Date. Tests shall be carried out by a Registered Professional Engineer (MSDG 2) or Independent Engineer (MSDG 3).

The testing phase includes at least:

• Functional test, insulation resistance, performance checks
• 6-hour operating test with the Generating Unit connected to the network
• Verification of settings of all Protection relays/systems
• Verification of voltage phasing between the DGP and the Network
• Test of all inter-tripping circuits
• Earthing test at the switching substation

For solar PV Power Plants only: module string polarity, Voc and Isc, PV array insulation resistance. For wind power plants: vibration level, overspeed trip, yaw drive tests. The pre-commissioning phase (in the presence of the Distribution Licensee and the System Operator) includes: active power measurement tests, relay functional tests, 22 kV energisation, reactive power capacity, power quality (IEC 61400-21), anti-islanding test.

DC 4.12.4 — Certification

The Distributed Generator shall submit a Certificate of Installation signed by the Installer / RPE / IE. Upon compliance, the Distribution Licensee issues a Certificate of Compliance confirming that the installation complies with the Distribution Code and is fit for connection to the Distribution System.

DC 4.13 — Standby Generators

Parallel operation with the Distribution System is not permitted for Standby Generators unless expressly agreed by the System Operator. Customers with Standby Generators shall ensure that any part of the installation supplied by the generator is first disconnected from the Distribution System. Warning signs shall be placed on LV and MV poles and transformers where a Standby Generator is connected.

DC 4.14 — Compliance with the Distribution Code

In the event of non-compliance, the Distribution Licensee informs the Distributed Generator in writing of the discrepancies. The Distributed Generator has:

• 60 days for CEB SOLAR PHOTOVOLTAIC SCHEME (HOUSEHOLDS)
• 90 days for MSDG 1, MSDG 2 and MSDG 3

After this period, the Distribution Licensee is entitled to disconnect the Distributed Generator. Reconnection requires the Distribution Licensee to certify that the installation complies with the Distribution Code.

DC 4.15 — Additional Requirements for MSDG 2 and MSDG 3

DC 4.15.1 — Uninterruptible Power Supply (UPS)

An online UPS is required to ensure that the protection, measurement, control and communication systems operate without interruption for at least 3 hours after loss of network supply. In the event of loss of the secure auxiliary supply, all 22 kV circuit breakers of the Distributed Generator shall be tripped. For DGPs with a Registered Capacity ≥ 1 MW, all communication equipment shall be supplied by a separate UPS.

DC 4.15.2 — Indications, Alarms and Instrumentation

Alarms and trips shall have local indication and, for DGPs with a Registered Capacity ≥ 1 MW, a set of potential-free contacts for downstream transmission to the Distribution System Substation. External indicator lamps shall be installed for DGPs with a Registered Capacity > 200 kW: red lamp = parallel operation; green lamp = isolated operation.

DC 4.15.3 — Generation Programme

DGPs connected to the MV network with a Registered Capacity greater than 2 MW shall submit a Distributed Generation forecast to the Distribution Licensee and the System Operator in accordance with the requirements of SOC 4.2.4.

DC 4.15.4 — Preventive and Corrective Maintenance

A DGP with a Registered Capacity > 1 MW shall submit its preventive maintenance plan to the System Operator each year. The Distribution Licensee shall communicate its maintenance plans to DGPs connected to the MV network at least one week before the planned action. No compensation applies for any loss of generation due to preventive and corrective maintenance on the Distribution System network.

DC 4.15.5 — Performance Requirements

DC 4.15.5.1 Fault Ride-Through (LVRT): The DGP shall remain connected to the Distribution System for phase voltage dips where the voltage measured at the Delivery Point remains above the voltage-duration profile curve (Figure 1 for synchronous/asynchronous machines, Figure 2 for Power Plants). In addition, the DGP shall provide Active Power in proportion to the retained voltage and maximise the reactive current injected into the Distribution System.

DC 4.15.5.2 Frequency Response: A DGP with a Registered Capacity ≥ 1 MW shall provide a power-frequency response in accordance with Figure 3 (power reduction above 50.5 Hz at 40 %/Hz; reconnection only when frequency returns to ≤ 50.5 Hz). Disconnection < 0.5 s if frequency > 52 Hz or < 47 Hz.

DC 4.15.5.3 Reactive Power Control: A DGP with a Registered Capacity ≥ 1 MW shall be equipped with mutually exclusive Reactive Power control functions: (a) Power Factor Control; or (b) Reactive Power Control. A voltage control mode may also be required on a case-by-case basis.

DC 4.15.5.4 Ramp Rate Limits: A DGP with a Registered Capacity ≥ 1 MW shall have a maximum ramp rate (up and down) equal to the Registered Capacity (MW) divided by 5 for 1-minute ramps. Ramp rate settings shall be approved by the System Operator before commissioning. For any subsequent changes, a minimum two-week notice is required.

DC 4.16 — Installer

A DGP shall be installed in accordance with the manufacturer's instructions. The Installer shall take into account: maximum demand, type of earthing system, nature of supply, external influences, compatibility/maintainability/accessibility, protection against electric shock and thermal effects, protection against overcurrents, isolation and switching. The Installer shall affix a label clearly indicating the next planned maintenance. The Installer shall be qualified in the field of DGP electrical installations and hold an approved certificate.

DC 4.17 — Communication Requirements for MSDG 2 and MSDG 3

DC 4.17.1 — Communication System Configuration

An MSDG 2 with a Registered Capacity ≥ 1 MW or MSDG 3 shall install communication equipment for the secure transfer of operational data and protection and control signals via: (a) optical fibre cables (DGPs with Registered Capacity ≥ 1 MW); (b) 4G/LTE (via VPN) or Microwave link as a backup communication channel. The Distributed Generator bears the cost of installing the communication from the DGP to the corresponding Substation.

DC 4.17.2 — Communication Equipment

Data to be transmitted includes:

• Unidirectional communication from Substation to DGP: 22 kV circuit breaker status (open/closed)
• Unidirectional communication from DGP to Substation: status of interconnection, transformer and generator circuit breakers; alarms (protection operated, relay faulty, SF6 alarm, UPS, door, inter-trip, remote/local control, other alarms); MW and MVAr at Delivery Point; 22 kV busbar voltage; current at Delivery Point
• Remote control for DGPs with Registered Capacity ≥ 1 MW only: OPEN/CLOSE commands for LBS and CB1

Wireless communications (if used) shall use 3G/4G/LTE or newer technology, a Microwave link as the primary channel and 3G/4G/LTE as backup, dual-SIM capability, VPN tunnels, two routers in primary/hot-standby configuration, data rate ≥ 85 kbps downstream / 42 kbps upstream.

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DC 5 — DISTRIBUTION SYSTEM INTERCONNECTION

DC 5.1 — Introduction

This section specifies the normal method of interconnection to the Distribution System and the minimum technical, design and operational criteria with which every User shall comply. All interconnection costs and responsibility are normally borne by the User connected to the Distribution System.

DC 5.4 — Method of Interconnection

DC 5.4.1 Low Voltage Interconnections: Supply provided as single-phase 230 V or three-phase 400 V. Information required for LV interconnections includes at minimum: Customer name/address, location, type of interconnection, required capacity, identification of large motors or welding equipment.

DC 5.4.2 Medium Voltage Interconnection: Prior to the first energisation of a User System, the following data shall be provided to the Distribution Licensee: updated data, protection diagrams, Operating Diagram, list of Safety Coordinators, Common Site Plans.

DC 5.5 — Interconnection of Distributed Generators

Generator Interconnections shall comply with the relevant requirements of the Generation Code and Section DC 4. The operator of a Distributed Generation Plant shall operate and maintain Generating Units in a manner that does not adversely affect the Distribution System and other Users.

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DC 6 — POWER QUALITY STANDARDS

DC 6.1 — General Provisions

All Users connected to the Distribution System shall maintain the quality of the voltage waveform at the Interconnection Boundary within the limits specified in this section.

DC 6.2 — Voltage and Current Harmonic Distortion

DC 6.2.1 Voltage: The Distribution Licensee shall limit line-to-neutral voltage harmonics below the values recommended in IEEE 519 for the Interconnection Boundaries of all Users (Table 4).

DC 6.2.2 Current:

• The Total Harmonic Distortion (THD) or Total Demand Distortion (TDD) shall be less than 5 % of the fundamental current at rated power
• Each individual harmonic shall be limited in accordance with the percentages listed in IEEE 519 (Table 5)
• Even harmonics in these ranges shall be < 25 % of the limits for the listed odd harmonics

DC 6.3 — Voltage Fluctuations

DC 6.3.1 Voltage Flicker: In accordance with the maximum values at the Interconnection Boundary specified in IEC TR 61000-3-7 (MV) and IEC TR 61000-3 parts 3 and 11 (LV).

DC 6.3.2 Voltage Variations:

• Limited for repetitive step changes: ≤ ±1 % of nominal voltage under Normal Conditions
• For occasional non-repetitive fluctuations: ≤ ±3 % of nominal voltage
• Step changes due to connection/disconnection of a DGP or Customer: ≤ ±6 % for fortuitous outages such as faults
• Induction generators shall be fitted with soft starters limiting inrush currents to a maximum of 110 % of rated current

DC 6.4 — Phase Imbalance

The weekly 95th percentile of Phase Imbalance (Voltage), calculated in accordance with IEC 61000-4-30 and IEC 61000-3-13, shall be ≤ 1.3 % on the Distribution System, except under abnormal conditions.

DC 6.5 — Exceptional Conditions

DC 6.5.1 Limitation of DC Injection: A Customer or Distributed Generator shall not inject a direct current greater than 0.25 % of the rated AC output current per phase. A Generator/Customer connected to the LV network shall not inject a DC current greater than the larger value between 20 mA and 0.25 % of the rated AC output current per phase.

DC 6.5.2 Voltage and Current Imbalance: The total voltage imbalance in the Network shall be less than 2 %. The contribution to the voltage imbalance level at the Interconnection Boundary of a Distributed Generation Plant shall be ≤ 1.3 %.

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DC 7 — ELECTRICAL INSTALLATIONS — INTERCONNECTION SITES

DC 7.1 — General Requirements

All electrical installations related to Users/Licensee at the Interconnection Boundary shall comply with the requirements of DC 7 and its sub-sections.

DC 7.2 — Substation Electrical Installations

All circuit breakers, disconnectors, earthing devices, power transformers, voltage transformers, current transformers, surge arresters and other equipment at the Interconnection Site shall be constructed, installed and tested in accordance with the technical standards specified by the Distribution Licensee and Prudent Utility Practices. Installations and switchgear shall be designed, manufactured and tested in ISO 9001-certified or equivalent premises.

DC 7.3 — Interconnection Boundaries

• LV and MV: The Distribution Licensee's responsibility extends to the User's Interconnection Boundary (main fuses/circuit breakers for large installations, meter output terminals for residential installations).
• Distributed Generators: The design requirements for Interconnection Boundaries for Distributed Generators are defined in Section DC 4.
• Boundary with the Transmission Network: The interconnection of the Distribution System to the Transmission System shall comply with the relevant provisions of the Transmission Code.

DC 7.4 — Protection Requirements

All protection systems and settings shall comply with the Distribution Licensee's Protection Policy. The protection of the Distribution System and Customers shall be designed, coordinated and tested to isolate affected parts of the System at the required speed and sensitivity, while maintaining supplies to the rest of the System. The Distribution Licensee alone is responsible for the protection of the Distribution System; Users alone are responsible for the protection of their Systems on their side of the Interconnection Boundary.

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DC 8 — SITE CONDITIONS

DC 8.1 — General

Responsibility for the construction, commissioning, control, operation and maintenance of Electrical Installations is determined according to the ownership of each installation, unless an agreement between the Parties provides otherwise.

DC 8.2 — Safety Responsibilities

The Distribution Licensee and all Users of the Distribution System shall comply with relevant electrical regulations. Prior to MV interconnection, the Distribution Licensee and the User shall conclude a written agreement on the Safety Rules to be used for works at Installations at the Interconnection Boundary (SOC 15).

DC 8.3 — Site Responsibilities Tables

A Site Responsibilities Table shall be produced for the System Operator and the Users with which it interfaces (format as per DC 21.1). These documents shall be included in the IA, ESPA, CA or PPA.

DC 8.4 — Diagrams and Plans

DC 8.4.1 Project Plans: The User shall prepare and submit 3 copies of all drawings to the Distribution Licensee and the System Operator for review (review within 15 days). Within 90 days of the Commercial Operation Date, the User shall provide a complete set of as-built drawings (2 paper copies and PDF electronic version).

DC 8.4.2 Operating Diagrams: An Operating Diagram shall be prepared by the User for each Interconnection Site in accordance with DC 21.2.

DC 8.4.3 Common Site Plans: The User prepares and submits the Common Site Plans for its side of the Interconnection Boundary. The Distribution Licensee then produces and distributes the complete Common Site Plans for the entire Interconnection Site.

DC 8.5 — Access

Arrangements for access to Distribution Licensee sites by Users, and vice versa, shall be defined in each IA, ESPA, CA or PPA. The request shall be detailed and submitted 3 working days in advance.

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DC 9 — COMMUNICATIONS AND CONTROL

For the purposes of this section, the term User refers to Distributed Generators and Customers connected to the MV Distribution System. Telecommunications between User(s) and the System Operator shall be established if required by the System Operator. Control telephony is the means by which Operations Engineers communicate for the control of the Distribution System, in both normal and emergency situations. The User shall install appropriate telephony equipment if its installation is not compatible with the Operator's system.

The System Operator shall provide a SCADA outstation interface. The User shall provide 4–20 mA measurement signals for voltage, current, frequency, Active Power and Reactive Power, as well as Equipment positions and alarms to the System Operator's SCADA outstation equipment (in accordance with DC 21.3).

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DC 10 — TESTING AND MONITORING

DC 10.1 — Introduction

In order to ensure that the Distribution System is operated efficiently and in accordance with Licence conditions, the Distribution Licensee with the support of the System Operator shall organise and carry out tests and/or monitoring of the effect of Users' Installations on the Distribution System.

DC 10.2 — Purpose

The purpose of DC 10 is to specify the requirement for testing and/or monitoring in order to ensure that Users are not operating outside the technical parameters required by the Distribution Code.

DC 10.3 — Power Quality Procedure

The System Operator periodically determines the need to test and/or monitor power quality. These tests are carried out at the System Operator's expense. If a counter-test is requested by the User, it is carried out at the User's expense. A User operating outside the limits shall rectify the situation or disconnect the Equipment causing the problem immediately or within a timeframe agreed with the System Operator.

DC 10.4 — Interconnection Boundary Parameter Procedure

The System Operator periodically monitors the Active and Reactive Power flows at the Interconnection Boundary. All costs related to increasing the physical capacity of the Boundary are borne by the User.

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DC 11 — DEMAND CONTROL

DC 11.1 — Introduction

The System Operator establishes requirements for Distribution System Users and Customers to enable reductions in total demand in the event of insufficient generation to meet total demand, or to avoid disconnecting Customers and Users, or in the event of a failure and/or overload on any part of the Transmission and/or Distribution Systems. Demand Control procedures aim to minimise difficulties for Users and to treat all affected parties equitably. The System Operator and Users shall comply with the requirements established in section SOC 9 of the System Operations Code.

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DC 12 — OPERATIONAL COMMUNICATION

DC 12.1 — Purpose

The System Operator and Users shall exchange information so that the implications of an Operation and/or an Incident can be considered, potential risks assessed and appropriate actions taken to maintain the integrity of the Total System and Users' Installations. The System Operator and Users shall comply with the requirements established in section SOC 11 of the System Operations Code.

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DC 13 — MAINTENANCE STANDARDS

All System Installations and Equipment shall be operated and maintained in accordance with Prudent Utility Practices and in a manner that does not constitute a threat to the safety of employees or the public. The System Operator shall establish a Distribution System Maintenance Policy which shall be reviewed and approved by the Authority. The Distribution Licensee shall coordinate with the System Operator the planned maintenance of MV installations in the Distribution System. The System Operator, the Distribution Licensee and any connected User shall comply with the requirements established in section SOC 12 of the System Operations Code.

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DC 14 — SWITCHING INSTRUCTIONS FOR MEDIUM VOLTAGE EQUIPMENT

Medium Voltage switching shall only be carried out with the permission of the System Control Engineer or their designated representatives, except in the event of a System Emergency. Persons required to carry out Medium Voltage switching shall be specifically certified and authorised by the System Operator to perform such switching. The System Operator shall comply with the requirements and procedures of section SOC 7 of the System Operations Code.

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DC 15 — NUMBERING AND NOMENCLATURE

DC 15.1 — Introduction

This section defines the responsibilities and procedures for notifying the relevant owners of the numbering and nomenclature of Equipment at Interconnection Boundaries.

DC 15.2 — Objectives

The main objective is to ensure that at any Site where there is an ownership boundary, each item of Equipment has a mutually agreed numbering and/or nomenclature, in order to ensure the safe and efficient Operation of the Systems involved and to reduce the risk of error.

DC 15.3 — Procedure

New Equipment: The proposed numbering/nomenclature shall be notified in writing at least 3 months before the planned installation. The recipient shall respond in writing within one month of receipt.

Existing Equipment: The System Operator and each User are responsible for the provision and placement of clear labels indicating the numbering and nomenclature of their Equipment at sites having an Interconnection Boundary.

Modifications: When numbering/nomenclature needs to be changed, the same procedures apply. The party making the change is responsible for updating the labels.

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DC 16 — SPECIAL SYSTEM TESTS

DC 16.1 — Introduction

This section defines the responsibilities and procedures for organising and conducting Special System Tests which have or may have an effect on the Distribution System or Users' Systems. Special Tests are those involving the simulated or controlled application of irregular, unusual or extreme conditions on the System, excluding commissioning or re-commissioning tests.

DC 16.2 — Purpose

The objectives are: (a) to ensure that the procedures for organising Special Tests do not threaten the safety of personnel or the general public and cause minimum threat to the security of supplies and the integrity of Installations; and (b) to define the procedures to be followed for the establishment and reporting of Special System Tests.

DC 16.3 — Procedure

When a User plans to undertake a Special System Test, notice shall be provided 1 month in advance to the Distribution Licensee and affected Users. The System Operator has overall coordination and convenes a Test Committee. The latter produces a proposal report within 2 months of its first meeting. If the report is unanimously approved by all recipients, a final test programme is submitted at least 1 month before the planned date. A final report is produced at the conclusion of the Test and the Committee is dissolved.

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DC 17 — DISTRIBUTION METERING

DC 17.1 — Purpose and Introduction

This section defines the manner in which power and energy flows shall be measured at an operational Interface. The Distribution Licensee is responsible for the acquisition, installation, maintenance, calibration and testing of meters and metering systems, as well as meter reading, billing and management of Customer complaints.

DC 17.3 — Distributed Generator Metering Requirements

Required overall accuracy (maximum permissible values):

• CEB SOLAR PHOTOVOLTAIC SCHEME (HOUSEHOLDS) and MSDG 1: ± 2.0 %
• MSDG 2: ± 1.5 %
• MSDG 3: ± 0.5 %

Parameters to be measured include: Active Energy (Wh) import/export, Reactive Energy (VARh) 1st and 4th quadrant, Active and Reactive Power demand and THD. The demand interval is 30 minutes. Measuring transformers shall comply with IEC 61869.

DC 17.4 — Metering Requirements — Users

Required overall accuracy of billing metering systems: ± 1 % in laboratory and ± 2 % in the field. For CT meters: ± 1.5 % (LV) and ± 1 % (MV). All meters shall comply with the latest revisions of IEC 62053 or equivalent international standards.

DC 17.6 — Delivery Point (metering points)

For CT meters, the Delivery Point is at the position of the Current Transformers used for the metering system, designed as close as possible to the Interconnection Boundary. Current transformers shall be installed in a separate compartment, upstream of the main switch.

DC 17.8 — Calibration and Sealing

All meters shall be factory-calibrated. Calibration of electronic meters is carried out in the factory only. Any laboratory calibration shall be performed in laboratories accredited by the Mauritius Accreditation Service (MAURITAS). All meters shall be sealed to prevent unauthorised access, with an indication of the re-calibration date and serial number. The kilowatt-hour standard used for calibration shall be traceable to a recognised national or international standard. Only meters that have received type approval from the Mauritius Standards Bureau (MSB) may be used.

DC 17.9 — Metering Disputes

If the Metering System proves to be inaccurate by more than the permitted error and the Single Buyer and the Distributed Generator/User are unable to reach agreement within a reasonable time, the matter may be submitted to arbitration. A User/Distributed Generator has the right to request a verification of meter accuracy. If more than one verification is requested in the same calendar year, the Single Buyer may charge for the additional verifications if accuracy is within ± 2 %.

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DC 18 — REQUIREMENTS FOR THE RODRIGUES DISTRIBUTION SYSTEM

In general, the electrical system of the peripheral island of Rodrigues (a small isolated system comprising a few generators and 22 kV feeders) shall comply with the requirements of the Distribution Code, with the following exceptions.

DC 18.1 — Exemptions

• DC 3.2.2 (Planning Criteria)
• SOC 9.4a (Demand Control methods – System Operations Code)

DC 18.2 — Planning Criteria for Rodrigues

• Feeder and transformer loading limited to 100 % of rated under Normal Conditions
• Margin of at least 10 % of System demand for Spinning Reserve
• In the event of a Generating Unit failure, the remaining Units shall be able to meet demand
• System frequency maintained within the limit of 50 Hz ± 0.75 Hz under Normal Conditions

DC 18.4 — Demand Control

The System Operator shall use Automatic Load Shedding by Under-Frequency Relays to handle short-term imbalances between Total System Power and Demand. The demand subject to automatic disconnection shall be divided into discrete MW blocks. After 2 activations, feeders at levels 1 and 2 shall where possible be exchanged with those at lower levels so as not to penalise the same Customers.

DC 18.5 — Frequency Response for MSDG 2 and MSDG 3

Each Generating Unit or Power Plant in Rodrigues shall be equipped with a fast-acting frequency control device (Governor Control System) with:

• Adjustable governor droop between 4 % and 8 % (for other units)
• Dead band not exceeding 0.05 Hz (± 0.025 Hz)
• Capable of controlling System frequency below 52 Hz when islanded
• Operating only within the System frequency range of 47–52 Hz

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DC 19 — DISTRIBUTION DATA RECORDING

DC 19.1 — Purpose

The purpose of DC 19 is to: (a) list all data to be provided by Users to the System Operator and the Single Buyer; (b) list all data to be provided by the System Operator to Users; and (c) list all data to be exchanged with Distributed Generators under the Distribution Code.

DC 19.3 — Data Categories

Each data item is classified into three categories:

• System Planning Data — as required by the Planning and Interconnection section
• Generation Planning Data — as required by the Generation Code
• Operational Data — as required by the System Operator, including Scheduling and Dispatching data from the Generation Code

DC 19.4 — Procedures and Responsibilities

Each User shall submit the data summarised in DC 20 to the Distribution Licensee, who then shares it with the Single Buyer and the System Operator. Data may be submitted via computer link, USB key, CD ROM or cloud technology, following prior written consent. The User shall notify the Distribution Licensee of any change to already submitted data. If a User does not provide the required data, the Distribution Licensee may estimate it in collaboration with the System Operator and/or the Single Buyer.

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DC 20 — DATA TABLES

DC 20.1 — User System Data Table

The following information is required from each User connected to the Distribution System via an Interconnection Boundary:

• User's name, address and contact details
• Location of the proposed interconnection
• Type of interconnection (residential, commercial, industrial)
• Maximum power required (kVA or kW)
• Type and number of significant load items (cookers, showers, motors, welding equipment, electric vehicles, etc.)
• Type of load and control arrangements (e.g. motor starting type, controlled rectifiers)
• Maximum current on each phase
• Details of cyclic load variations and fluctuating loads

DC 20.2 — Fault Supply Data Table

The following information is required from each User connected via an Interconnection Boundary where the User System contains one or more Distributed Generating Units and/or motor loads:

• Terminal Voltage (kV), rated kVA/kW, P-Q Capability diagram
• Type of Generation Plant (synchronous, asynchronous, etc.) and intended operating mode (continuous, intermittent, peak-lopping)
• For synchronous and asynchronous machines: inertia constant, direct-axis reactances (sub-transient, transient, synchronous), time constants, zero and negative sequence resistances and reactances
• Maximum and minimum fault injection levels (three-phase and single-phase-to-earth)
• X/R ratio under short-circuit conditions

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DC 21 — ANNEXES

DC 21.1 — Annex A: Site Responsibilities Tables

Each Site Responsibilities Table shall: clearly indicate the ownership and responsibility of each item of Equipment at the Interconnection Site; be signed on behalf of the System Operator and the User with date; be included in the IA, ESPA, CA or PPA. The standard form includes the fields: Company, Interconnection Site, signatures and dates of both parties.

DC 21.2 — Annex B: Operating Diagram Procedures

Where possible, all MV Equipment at any Interconnection Site shall be represented on a single Operating Diagram. The layout shall represent as accurately as possible the geographical arrangement at the Interconnection Site. Operating Diagrams shall accurately show the current status of Equipment (in service/out of service). Items to be represented include in particular: busbars, circuit breakers, disconnectors and switches, earthing devices, power transformers, measuring transformers (current and voltage), surge arresters, black start generators. All graphical symbols used shall be approved by the System Operator.

DC 21.3 — Annex C: SCADA Interfacing

General requirements for SCADA signals shall comply with IEC 60870-2-1 and IEC 60870-3 (electromagnetic compatibility). In particular:

• Digital inputs: potential-free contacts; single points for alarms (contact open = normal state, contact closed = alarm); double points to indicate primary states (only states "10" and "01" valid)
• Energy meter inputs: pulses active for a minimum of 100 ms, reopening of at least 100 ms, normal state = open
• Analogue inputs: 4–20 mA signals (or other agreed range), electrically isolated, two-wire connection
• Control outputs: switching between 0 V and 48 V for a maximum of 2.5 seconds at 1 amp, electrically isolated outputs, two-wire connection

DC 21.4 — Annex E: Typical Interconnection Diagrams

DC 21.4.1 Typical MSDG 1 Interconnection Arrangement: The typical interconnection for MSDG 1 is described in this annex.

DC 21.4.2 Typical MV Switchgear Panel and Protection Guide for MSDG 2 and MSDG 3: Important notes include:

• The above diagrams refer to typical installations; the actual protection and inter-tripping requirements may vary depending on the particular configuration of the Generation Plant.
• The Distributed Generator is responsible for the appropriate protection of its transformer and internal loads.
• Inter-tripping between the Distribution System Substation and the Generation Plant is required for Registered Capacities greater than 1 MW.
• For synchronous/asynchronous machines: (a) a Dead Bus Live Line (DBLL) relay is required to prevent the electrical/remote closing of CB1 onto an energised busbar; (b) a key interlock shall be provided between CB1 and all 22 kV outgoing circuit breakers of the Generation Plant; (c) the Distributed Generator shall provide the required Synchronism Check Relay on circuit breakers capable of connecting the DGP to the Distribution System.