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DISTRIBUTION CODE

INTRODUCTION

1. A Distribution Code is an essential part of the Regulatory Framework of the Pakistan Distribution Electric Supply System. In accordance with Section 20, of NEPRA “Regulation of Generation, Transmission and Distribution of Electric Power Act (XL of 1997)”, all distribution companies must obtain a Distribution Licence from the National Electric Power Regulatory Authority, NEPRA. As per Section 35 of NEPRA Act, Clause 15 of the NEPRA Licensing (Distribution) Rules - 1999, and the provisions of NEPRA Distribution Licence, all NEPRA Distribution Licensees must comply with an approved Distribution Code at all times.  Failure to do so can result in their Licence being suspended or revoked. 

2. The purpose of this Code is to ensure that the Licensee’s networks are planned developed, operated, and maintained in an efficient, safe, reliable, co-ordinated, and economical manner from the technical stand point. 

3. The Distribution Code, approved by NEPRA defines the technical and operational aspects of the relationship between Distribution Company and all those entities connected to the Distribution Company Distribution System.  All Generators, BPCs, Distribution Companies and Special Purpose Transmission Licensees shall be subject to the relevant provisions of the Distribution Code as applicable. 

4. This Distribution Code, approved by NEPRA, is designed to perform a similar function to that of the Grid Code in relation to Licensee’s networks; and is applicable to those which are connected to the Licensee’s 132/66/11/0.4 kV network within its Service Territory, and the NTDC. 

5. Most of the provisions of the Distribution Code are common to all Licensees except in those cases where an individual Licensee has received NEPRA approval for a specific change from the approved Distribution Code.  

6. However, the Distribution Code does not deal with commercial aspects of distribution supply system. It deals exclusively with technical and operational aspects concerning the distribution and supply of electricity, and the use of the Licensee’s networks for the transport of electricity. 

7. The relationship between the Grid Code and the Distribution Code is shown diagrammatically in Figure-1 on page ID-4. The Grid Code specifies all the technical and operational aspects of the interface requirements between NTDC and Licensees, and consequently the Distribution Code does not contain references to the rights and obligations of NTDC. 

8. The Distribution Code contains the following sections: - 

(a)        Code Management, which sets out procedures to be adopted by all parties for updating and amending the Distribution Code and contains provisions regarding enforcement, administration and compliance/ non-compliance of the Code, and the treatment under Force Majure conditions. 

(b)        Distribution Operating Code, which sets out procedures on operational matters relating to operational planning, including demand forecasts, co-ordination of the planning of Licensee’s network outages and generation plant outages, the reporting of operational changes and events, safety matters and dealing with the procedures under contingencies. Furthermore, it deals with the restoration of supply, load shedding, compliance of Performance Standards (Distribution). 

(c)         Distribution Planning Code, which sets out the procedures, planning methodology and criteria related to the distribution planning of the Licensee. It defines the standard of supply of the Licensee’s network, and the design principles to which it will be constructed, operated and maintained together with technical information and other requirements to be met by those requiring a connection to the Licensee’s network.  It also details the technical information exchange between parties relating to such connections. 

(d)        Distribution Design Code (DDC) sets out principles and standards to be applied in the design process of the Licensee Distribution System and any User connections to the Distribution System of the Licensee. 

(e)        Connection Code, which defines the standard of supply, offered by a Licensee to its connecting parties and the Connection and Use-of-system principles to which Licensee requires its connecting parties to adhere to together with technical information and other requirements to be met by those requiring a general connection to the Network.  It also details the technical information exchange between parties relating to such connections. (f) System Construction Code.  

(g)        System    Performance,    System             Reliability,        Consumer        Services Requirements.  

(h)        Metering Requirements. 

(i)          Protection Requirements. 

(j)          System Maintenance and Testing. 

(k)         Safety Requirements. 

(l)          Public Lighting. 

(m)       Emergency Plans and Load Shedding. 

(n)        Provisions of Informations. 

(o)        Distribution Data Registration Code. 

(p)        Competition in the Supply of Electric Power. 

          (q)      Schedules and appendices  

(r) Code Definitions, which provides an explanation of the terms used in this Distribution Code. 

1. The purpose of the Distribution Code is not just limited to the operational planning, daily routine operations and connection requirements relating to the Licensee’s networks. The Distribution Code should therefore, not be considered in isolation, but as part of a series of related Codes or Agreements, which may include, but not be limited to: 

(a)         Balancing Code (if appropriate); 

(b)         Use-of-System Code, (if appropriate)  and Bilateral Connection Agreements; 

(c)         Interconnection Agreements; and 

(d)         The Grid Code. 

1. Some of the Agreements listed above will relate to a Single Buyer Plus Market and others to a Bilateral Contracts Market. These supporting Codes or Agreements govern technical and commercial relationships between NTDC, Distribution Licensees and/or Users.  Such Codes or Agreements shall be developed by the Licensee, and approved by NEPRA. 

1. As with all documents, this Distribution Code may require modification from time to time as per the prevailing requirements of the system. The modus apprendie is covered in the “Code Management” sub-code of this Code. 

CODE MANAGEMENT 

CONTENTS 

CM 1             INTRODUCTION & SCOPE                                                      CM – 6 

CM 2             APPLICATION OF CODE                                                        CM – 6 

CM 3             COMPLIANCE                                                                       CM – 6 

CM 4             UNFORESEEN CIRCUMSTANCES                                           CM – 6 

CM 5             THE DISTRIBUTION CODE REVIEW PANEL                             CM – 6 

CM 6             COMMUNICATIONS BETWEEN  

                    DISTRIBUTION LICENCEES AND USERS                                 CM – 8 

CM 7             MISCELLANEOUS                                                                 CM – 8 

CM 8             JURISDICTION OF THE CODE                                                CM – 8 

CM 9             SYSTEM CO-ORDINATION WITH GRID CODE                          CM – 8 

CM 10           INDEMNITY TO THE DISCOs                                                  CM – 8 

CM 11           FORCE MAJEURE CONDITIONS                                             CM – 9  

CM 12           MATTERS TO BE AGREED                                                     CM – 9 

CM 13           INFORMATION DISSEMINATION                                             CM – 9 

CM 14           PRESERVATION OF CONTRACTS PRIOR TO  

                    ENACTMENT OF NEPRA ACT                                                 CM – 9 

CM 15           NON-COMPLIANCE                                                               CM – 9 

CM 16           CODE ADMINISTRATION                                                       CM – 9 

CODE MANAGEMENT 

CM 1                                           INTRODUCTION & SCOPE 

CM 1.1 The Code Management section contains provisions of general application to all the provisions of the Distribution Code with the objective to ensure cohesion among various sections of the Distribution Code to the benefit of all Users. Furthermore, this sub-code relates to the administration, enforcement, compliance of the Distribution Code along with treatment of various provisions of the Distribution Code under unusual and unforeseen circumstances. The mechanism for the revision and modifications of the Distribution Code is also contained herein/is also stated herein. 

CM 2             APPLICATION OF CODE 

The provisions of this Distribution Code shall apply to the Licensee and all the entities using distribution and sub-transmission network of the Licensee connected either directly or indirectly to the distribution and sub-transmission network of the Licensee. 

CM 3              COMPLIANCE 

CM 3.1 A User or an entity connected to Licensee’s network shall comply with this Code unless the consumer or the entity has been advised otherwise by the Licensee. The requisite level of compliance with the Code shall be made a part of the contract between a consumer and the Licensee and the Consumer Service Manual. 

CM 3.2 In case a Licensee is found to be in breach where a breach of the Code by a Licensee is found to be caused by a User or any entity connected to the Licensee’s distribution system not complying with the Code, the Licensee is deemed to have complied with the Code unless the Licensee does not act in accordance with the provisions of this Code and seeks the User’s compliance. 

CM 4             UNFORESEEN CIRCUMSTANCES 

CM 4.1 In case of emergence of unforeseen circumstances, not included in the Distribution Code, the Licensee shall promptly consult all affected Users in an effort to reach an agreement to take necessary mitigation of actions. If agreement cannot be reached in the 24 hours the Licensee shall determine the most appropriate course of action under intimation to Registrar NEPRA. While arriving at its determination, the Licensee shall take into account the views expressed by the Users and other circumstances peculiar to a particular event. Each User shall comply with such instructions as issued by the Licensee provided that the instructions do not contravene the technical parameters of a particular User’s System registered in the Distribution Code. The Licensee shall promptly refer all such unforeseen circumstances and any determination thereof to the Panel for consideration as per CM 5.4. 

CM 5             THE DISTRIBUTION CODE REVIEW PANEL 

CM 5.1 All the Licensees shall jointly establish and maintain the Panel within two month of the notification of the code, which shall be a standing body to undertake the functions detailed in CM 5.4 

CM 5.2 The panel shall function in accordance with the rules and procedures to conduct business duly approved by NEPRA. Subsequent to the establishment of the panel, it shall formulate its rules and procedures to conduct business and submit to NEPRA within three months of the establishment of the Panel. 

CM 5.3          The Panel shall consist of; 

1. a Chairman with one member appointed by each Licensee; 
2. a person appointed by the Authority; 
3. the following members; 

(i)  2 persons representing Generators with Embedded Generator. 

(ii)  1 persons representing SPPs.  

(iii)1 person representing Consumers Protection Group. 

(iv)1 representative from KESC. 

(v)  1 member from the Industry or Academic Institution or PEC. 

(vi)1 representative from BPC's (vii) 1 representative from NTDC 

(viii) 1 Representative of Generators connected to 132kV system of the Licensee 

The decision of the penal shall be enforceable upon the approval of two third majority of the total members of the panel which shall be recorded. 

Note:Representation within each category shall be based on rotation and mutual agreement.  

CM 5.4           The Panel shall: 

1. keep the Distribution Code and its workings under review; 
2. review all suggestions for amendments to the Distribution Code which any Consumer through the representative of Consumer Protection Group in the Panel may wish to submit to a Licensee for consideration by the Panel; 
3. publish recommendations as to amendments to the Distribution Code that a Licensee or the Panel believes to be desirable and the reasons for the recommendations; 
4. submit the agreed recommendations to NEPRA for approval 
5. issue guidance on the Distribution Code and its implementation, performance and interpretation, as and when requested by any User; f. resolve any matters of disputes between Licensee and its Users; and 

g. consider what changes are necessary to the Distribution Code arising out of any unforeseen circumstances as referred by the Licensee under CM 4.1. 

CM 5.5 The Distribution Licensee shall inform the proposed amendments to the Code to its Users through wide circulation in the press and if possible comment in writing with those who are liable to be affected by any proposed amendments to the Distribution Code and shall submit all such proposed amendments to the Panel for discussion prior to such consultation. 

CM 6             COMMUNICATIONS BETWEEN THE DISTRIBUTION LICENSEES AND USERS 

CM 6.1 Unless otherwise specified in the Distribution Code, the methods of operational communication and data transfer shall be agreed between the Licensee and Users from time to time. 

CM 6.2 All non-operational communications (data information and notices) between a Licensee and Users shall be in writing and issued to the appropriate officers of the Licensee and each User. 

CM 6.3 If for any reason a Licensee or a User re-locates its Control Centre, the Licensee or the User must inform the other party in writing of the move and advise the other party of any changes to their Control Telephony (dedicated telephone system). 

CM 6.4 All instructions and communications given by Control Telephony are to be recorded by whatever means and will be accepted by a Licensee and Users as evidence of those instructions or communications. 

CM 7             MISCELLANEOUS 

CM 7.1          Data and Notices

CM 7.1.1 References in the Distribution Code to ‘in writing’ shall include typewriting, printing, lithography and other modes of reproducing words in a legible and non-transitory form such as electronic communications. 

CM 7.1.2       Where applicable all data items shall refer to nominal Voltage and Frequency. 

CM 8             JURISDICTION OF THE CODE 

 The geographic Jurisdiction of the Code for each Distribution Company shall be the Service Territory of each Distribution Company (to be provided by each Distribution Company). The functional jurisdiction of this Code shall include all substations and lines rated 132kV and below.  

CM 9             SYSTEM CO-ORDINATION WITH GRID CODE 

The Licensee shall provide the NTDC metering data including peak demand, projected demand, voltage, frequency and embedded generation availability. This data will be available to NTDC to be used for operation and protection of specific 132kV lines and substations as described in the Grid Code. 

                     Illustration: - 

Figure ID-4 (page 4) shows the functional inter-relationships between Grid Code and Distribution Code and interfaces with the Network Users. 

CM 10           INDEMNITY TO THE DISTRIBUTION COMPANIES  

Each User shall indemnify the distribution company against any claim, action, damage, loss, liability, expenses or outstanding which the distribution company pays, suffers, incurs or is liable for in respect of any breach by that User or any officer, agent or employee of that User. 

CM 11           FORCE MAJEURE CONDITIONS  

Certain provision of the Distribution Code may be suspended in whole or in part pursuant to any directive given by the Authority under Force Majure conditions.  Licensee shall inform NEPRA within Seven days of its initiation about a Force Majure Condition. 

CM 12           MATTERS TO BE AGREED

Unresolved matters between Distribution Companies and Users are referred to Panel for resolution referred to as Review Panel. The review panel will need to refer to the Authority any matters requiring interpretation of the Distribution Code provisions. 

CM 13           INFORMATION DISSEMINATION 

The Licensee shall establish, operate and maintain web site providing necessary information about the sub-transmission and distribution system status, pricing, congestion, operating procedures, technical bulletins, technical committee meetings, and other relevant information and data. 

CM 14           PRESERVATION OF CONTRACTS PRIOR TO ENACTMENT OF NEPRA ACT 

 During the subsistence of the agreements entered into by the Licensee prior to the enactment of NEPRA Act, nothing contained in this Distribution Code shall be applied in a manner which is inconsistent with the agreements and materially increases the obligations or impairs the rights of the Users under their agreements. 

CM 15           NON-COMPLIANCE 

Any Act of non-compliance of any of the provision of this Distribution Code by any of the User or entity shall be subject to penalties as per Authority Fees & Fines Rules (2002). Provided however, no such penalties shall be imposed for non compliance with the provision of this Distribution Code upto to two years from the date of approval thereof by Authority. 

CM 16           CODE ADMINISTRATION 

                                 Distribution Companies shall be responsible for the enforcement and 

administration of the distribution code. 

ÑÑÑEnd of CMÒÒÒ

DISTRIBUTION OPERATION CODE NO. 1 

DEMAND FORECASTS

CONTENTS

DOC 1.1        INTRODUCTION, OBJECTIVE & SCOPE                        DOC 1-11 

DOC 1.2        DATA EXCHANGE AND INFORMATION FLOW               DOC 1-11 

DOC 1.3        DEMAND FORECAST DATA                                         DOC 1-12 

DOC 1.4        LICENSEE AND USER FORECASTS                             DOC 1-13 

DISTRIBUTION OPERATING CODE NO. 1 

DEMAND FORECASTS

DOC 1.2.1.1 The Licensee shall co-ordinate all Demand forecast information for each Connection Point to meet the requirements of the Grid Code. 

DOC 1.3        DEMAND FORECAST DATA 

DOC 1.3.1     Planning Periods 

DOC 1.3.1.1 Information for the following rolling timescales is required by each Licensee: 

(a)                 Operational Planning Phase (Medium term); 

(b)                 Programming Phase (Short term); and (c) Control Phase (Real time). 

DOC 1.3.1.2 In DOC1 Year 0 means the current Licensee Financial Year at any time, Year 1 means the next Licensee Financial Year, Year 2 means the Licensee Financial Year after year 1 and so on. 

DOC 1.3.2     Operational Planning Phase (8 weeks to 1 year ahead)

DOC 1.3.2.1 The information to be supplied to the Licensee during the Operational Planning Phase is specified in DOC 1 Appendix 1. 

DOC 1.3.3     Programming Phase (24 hours to 8 weeks ahead)

DOC 1.3.3.1 The information to be supplied to the Licensee during the Programming Phase is specified in DOC 1 Appendix 2. 

DOC 1.3.3.2 For the period 2 to 8 weeks ahead the information shall be supplied to the Licensee by 1600 hours each Thursday. 

DOC 1.3.3.3 For the period 2 to 12 days ahead the information shall be updated and supplied to the Licensee by 0900 hours each Wednesday. 

DOC 1.3.3.4 The Licensee may require the information specified in Appendices 1 and 2 of this sub-code to be updated if it reasonably considers it necessary and to be supplied to the Licensee by 0800 hours each day (or such other time as specified by the Licensee from time to time) for the next day.  On Thursdays and Saturdays the information should be supplied for the following two days. 

DOC 1.3.4     Control Phase (0 to 24 hours ahead)DOC 1 Appendix 3. 

DOC 1.3.4.1 The following information shall be supplied to the Licensee at reasonable times to be specified by the Licensee for the un-expired period covered by the Control Phase. 

(a)         Intimation by all the Embedded Generators to the Licensee in case the difference of their hourly output is more than 1 MW as compared to their schedule of generation already notified under DOC 1.3.3.3. 

(b)         Intimation by all the Bulk Power Consumer to the Licensee the detail of changes in the demand if such changes are more than 1 MW. 

DOC 1.3.4.2 On the basis of information provided by the Consumers as outlined in DOC 1.1.2 and DOC 1.3.4.1 above the Licensee shall work out its Demand Forecast for the real time.  

DOC 1.3.5     Post Control Phase 

DOC 1.3.5.1 The following data shall be supplied to the DISCO by 0300 hours each day:

Details of half hour Active Power and Reactive Power output sent out to the DISCO Distribution System by Embedded Generator not subject to 

Scheduling and Dispatch during the previous day on a half hourly basis. 

ÑÑÑEnd of DOC 1ÒÒÒ

DISTRIBUTION OPERATING CODE NO. 2 

OPERATIONAL PLANNING 

CONTENTS 

DOC 2.1        INTRODUCTION, OBJECTIVE & SCOPE                        DOC 2-15 

DOC 2.2        PROCEDURE                                                             DOC 2-15 

DOC 2.3        TIMESCALES AND DATA                                             DOC 2-16 

DOC 2.4        Operating Planning Phase                                            DOC 2-16 

DOC 2.5          Programming Phase                                                            DOC 2-17                 

                     Figure 1                                                                      DOC 2-18

  OPERATING CODE NO. 2 

OPERATIONAL PLANNING

DOC 2.2.1.1 Information relating to all facilities connected to the Distribution System of the Licensee, or that which may affect its Operation, shall be co-ordinated with the Licensee. 

DOC 2.2.2     Other Plant and Apparatus

DOC 2.2.2.1 Information relating to all facilities connected to the Distribution System of the Licensee, or that which may affect its Operation, shall be co-ordinated with the Licensee. 

DOC 2.4.1.1 Users and Embedded Generators (not subject to Central Despatch) shall provide the Licensee with information in accordance with DOC 2 Appendix 1. 

DOC 2.4.2                 Short Term Programme(Current Year down to 8 weeks ahead DOC2 

Appendix 2). 

DOC 2.4.2.1 The previous Medium Term Programme shall be updated to form the basis of the Short Term Programme. The Licensee shall continually review this programme as necessary and periodically discuss it with the relevant parties as appropriate. 

DOC 2.4.2.2 It shall take account of such review and discussions and any additional outages and the following further details of each outage proposed shall be notified at this stage by the appropriate party. 

1. return to service timing of circuits (if different from the programme); 
2. specific facilities to be worked upon; and 
3. any other information that may be reasonably specified by the Licensee from time to time. 

DOC 2.4.2.3 At any time and from time to time during the current Calendar year up to the Programming Phase (8 weeks ahead), all the relevant Users specified in DOC 2.1.6 may notify reasonable changes and additions to the outages previously notified during the Medium Term planning process.  The Licensee shall consider whether the changes shall adversely affect system security, stability, reliability and quality or other parties connected to the Licensee’s network, and shall discuss with the party in question.  Where the change is so discussed the Licensee shall inform the other affected Users. 

DOC 2.5.6.1 The Licensee shall obtain Scheduling information from Generators for other Embedded Generator not subject to Central Despatch where it considers it appropriate. 

DOC 2.5.6.2 The Scheduling information shall specify the following on an individual Generating Unit basis: 

1. the period the unit is required; 
2. the planned half hourly output; and 
3. any other information the Licensee reasonably considers necessary 

DISTRIBUTION OPERATING CODE No 2

Figure 1

DISTRIBUTION OPERATING CODE NO. 3 

SYSTEM RESTORATION

CONTENTS

DOC 3.1        INTRODUCTION, OBJECTIVE AND SCOPE                    DOC 3-20 

DOC 3.2.        PROCEDURE – BLACK START                                           DOC 3-20 

DISTRIBUTION OPERATING CODE NO. 3 

SYSTEM RESTORATION PLANNING 

DOC 3.1        INTRODUCTION, OBJECTIVE & SCOPE 

DOC 3.1.1      Black Start

DOC 3.1.1.1 Distribution Operating Code No. 3 covers the system recovery procedures following a Total or Partial Shutdown of the Total System as recognised by NTDC and that NTDC intends to implement Black Start procedures after having given notification to the Licensee. 

DOC 3.1.2     Force Majeure

DOC 3.1.2.1 DOC3 identifies the Licensee obligation to carry out certain actions according to certain pre-defined principles and procedures pursuant to any directive/instruction give by the NTDC concerning its Distribution System under Force Majeure Conditions.  

DOC 3.1.2.2 The Licensee shall prepare plans to deal with emergencies under force majeure conditions.  These plans shall be in accordance with guidelines provided in the Distribution Code in consultation with the NTDC. The plans will need to take account of the directives/instructions given by the NTDC under force majeure conditions. This clause is not applicable to KESC who shall prepare its plans as per its requirements. 

DOC 3.2.2                   Partial Shutdown is a situation where all generation has ceased in a 

separated part of the Total System and there are no available interconnections to the other parts of the Total System. DOC 3.2.3   System Recovery

DOC 3.2.3.1 Certain Embedded Power Stations may be identified, as having an ability to start up from shut down without connections to external power supplies.  Such Power Stations are to be referred to as Black Start stations. 

DOC 3.2.3.2 The distribution company in conjunction with NTDC shall segregate the Licensee’s demand into suitably sized components to allow progressive reenergisation of the Licensee’s distribution system.  The size of the areas of demand will be determined by NTDC; and will be commensurate with the size of Generating Unit to be re-started. 

DOC 3.2.4     Re-synchronising Islands of Supply

DOC 3.2.4.1 The Licensee's regional load dispatch centres in the case of partial or full shut down shall follow the standard predefined instructions of NTDC to help recover the system from a black start condition. DOC 3.2.5 System Incident Procedures

 To co-ordinate activities, Users and the Licensee shall ensure that there are multiple and suitable communication paths available and that where appropriate senior members of staff are appointed to manage these abnormal situations. 

ÑÑÑEnd of DOC 3ÒÒÒ

DISTRIBUTION OPERATING CODE NO. 4 

OPERATIONAL LIAISON 

CONTENTS

DOC 4.1        INTRODUCTION, SCOPE AND OBJECTIVES                 DOC 4-23 

DOC 4.2        PROCEDURE                                                                      DOC 4-23 

DISTRIBUTION OPERATING CODE NO. 4 

OPERATIONAL LIAISON 

DOC 4.2.1.1 The Licensee and each User connected to its Distribution System shall nominate officers and agree on communications channels to make effective the exchange of information required under DOC4. 

DOC 4.2.1.2 The Licensee shall establish reliable and suitable communication facilities at its 132/66/33/11kV sub-stations. All operating instructions, messages and data received from or sent to the concerned Grid Sub-station and Distribution Load Dispatch Centres (LDC) shall be duly recorded at such sub-station.  

DOC 4.2.2     Requirement to notify Operations

DOC 4.2.2.1 In the case of an Operation on the System of a User connected to the Licensee’s Distribution System, which shall have or may have an Operational Effect on the Licensee Distribution System, the User shall notify the Licensee in accordance with DOC4. 

DOC 4.2.2.2 In the case of an Operation on the Licensee Distribution System or on receipt of notification of an Operation on the NTDC Transmission System, which shall have or may, in the opinion of the Licensee, have an Operational Effect on the System of a User connected to the Licensee Distribution System, the Licensee shall notify the User that such incident has occurred. 

DOC 4.2.2.3 An Operation may be caused by another Operation or an Event on another’s Licensee System and in that situation the information to be notified is different from that where the Operation arose independently of any other Operation or Event. 

DOC 4.2.2.4 Whilst in no way limiting the general requirement to notify in advance or post operation, the following are examples of situations where, inasmuch as they may have or have had an effect on the Operation of the Licensee Distribution System or another System, notification shall be required of: 

1. the implementation of a Scheduled Outage of facility which has been arranged pursuant to DOC2; 
2. the operation of any Circuit Breaker or Isolator or any sequence or combination of the two including any temporary over-stressing, System parallels, or Generating Unit synchronising;  
3. Operation of any circuit breaker and associated relays for planned or load shedding, unit tripping or reduction in output or forced tripping; 
4. Voltage control; 
5. Violation by Users of its obligations under the agreement or Consumer Service Manual and Performance Standards (Distribution);  
6. Potential for excessive loading on the facilities including inter-

connecting facilities; 

1. Unavailability of any control and protection facilities; 
2. Change in the exchange of power between Licensee and other 

systems/users; 

1. Unusual/abnormal event which may impact the functioning and 

performance of parties connected to the Licensee's system; and 

1. this section should include certain operational liaison in the form of notification procedures to the employees to caution and prepare them to take remedial steps in case of contingency event or emergency situation. 

DOC 4.2.3      Form

DOC 4.2.3.1 A notification under DOC2.4.1 shall be of sufficient detail to describe the Operation, stating the cause, to enable the recipient of the notification reasonably to consider and assess the implications and risks arising and shall include the name of the individual reporting the Operation.  The recipient may ask questions to clarify the notification. 

DOC 4.2.3.2 A notification by the Licensee of an Operation which has been caused by another Operation (the “First Operation”) or by an Event on a User’s System, shall describe the Operation and shall contain the information which the Licensee has been given in relation to the First Operation or that Event by the User. 

 The notification (other than in relation to the information which the Licensee is merely passing on from a User) shall be of sufficient detail to enable the recipient of the notification reasonably to consider and assess the implications and consequences arising from the Operation on the Licensee Distribution System and shall include the name of the individual reporting the operation on behalf of the Licensee. 

DOC 4.2.3.3 Where a User is reporting an Operation or an Event which itself has been caused by an incident or scheduled or planned action affecting (but not on) its System the notification to the Licensee shall contain the information which the User has been given by the person connected to its System in relation to that incident or scheduled or planned action (which the User must require, contractually or otherwise the person connected to its System to give it) and the Licensee may pass on the information contained in the notification. 

DOC 4.2.3.4 A notification by the Licensee of an operation under DOC4 which has been caused by an Operation or an Event on the NTDC Transmission System, may describe the Operation on the Licensee Distribution System and shall contain the information which the Licensee has been given in relation to the Operation or an Event on the NTDC Transmission System by NTDC.  The notification (other than in relation to the information which the Licensee is merely passing on from NTDC) shall be of sufficient detail to enable the recipient of the notification to consider and assess the implications and consequences arising from the Operation on the Licensee Distribution System and shall include the name of the individual reporting the Operation on behalf of the Licensee. The recipient may ask questions to clarify the notification. 

DOC 4.2.3.5 A User may pass on the information contained in a notification to it from the Licensee to a Generator with a Generating Unit connected to the System or to another Distribution Company connected to its System if it is required (by a contract pursuant to which that Generating Unit or that Distribution Company is connected to the System) to do so in connection with the equivalent of an Operation on its System (if the Operation on the Licensee Distribution System caused it). 

DOC 4.2.3.6 Other than as provided in DOC4.2.3.5, a User may not pass on any information contained in a notification to it from the Licensee or in a notification to another User from the Licensee to any other person connected to its System, but may only say that there has been an incident on the Total System and (if known and if power supplies have been affected) an estimated time of return to service.  Each User shall procure that any other Users receiving information, which was contained in the notification to a User from the Licensee, which is not bound by the Distribution Code, does not pass any information on other than as provided above. 

DOC 4.2.4     Timing

DOC 4.2.4.1 A notification under DOC 4.2.2 shall be given as far in advance as possible and in any event shall be given in sufficient time as shall reasonably allow the recipient to consider and assess then implications and risks arising. 

DOC 4.2.4.2 The notification shall be dictated to the recipient who shall record it and on completion shall repeat the notification in full to the sender and check that it has been accurately recorded. 

DOC 4.2.5     Requirement to Notify Events

DOC 4.2.5.1 In the case of an Event on the System of a User connected to the Licensee Distribution System, which has or has had an Operational Effect on the Licensee Distribution System or on the NTDC Transmission System, the User shall notify the Licensee in accordance with this DOC4. 

DOC 4.2.5.2 In the case of an Event on the Licensee Distribution System or on receipt of notification of an Event on the NTDC Transmission System, which shall have or may, in the opinion of the Licensee, have an Operational Effect on the System of a User connected to the Licensee Distribution System, the Licensee shall notify the User in accordance with this DOC4. 

DOC 4.2.5.3 An Event may be caused by (or exacerbated by) another Event or by an Operation on NTDC, another Distribution Company or user System and in that situation the information to be notified is different from that where the Event arose independently of any other Event or Operation. 

DOC 4.2.5.4 Whilst in no way limiting the general requirement to notify the following are examples of situations where notification shall be required if they have an Operational Effect: 

1. the actuation of any alarm or indication of any abnormal operating condition; 
2. adverse weather conditions being experienced; 
3. breakdown of, or faults on, or temporary changes in the capabilities of, facilities including Protection; and 
4. increased risk of inadvertent Protection operation. 

DOC 4.2.6     Form

DOC 4.2.6.1 A notification under DOC 4.2.5 of an Event which has arisen independently of any other Event or of an Operation, shall describe the Event (although it need not to state the cause of the Event) and subject to that it shall be of sufficient detail to enable the recipient of the notification to consider and assess the implications and risks arising.  The recipient may ask questions to clarify the notification. 

DOC 4.2.6.2 A notification by the Licensee of an Event which has been caused by (or exacerbated by) another Event (the “first Event”) or by an Operation on a User’s System shall describe the Event and shall contain the information which the Licensee has been given in relation to the first Event or that operation by the User.  The notification (other than in relation to the information which the Licensee is merely passing on from a User) shall be of sufficient detail to enable the recipient of the notification reasonably to consider and assess the implications and risks arising from the Event on the Licensee Distribution System and shall include the name of the individual reporting the Event on behalf of the Licensee.  The recipient may ask questions to clarify the notification. 

DOC 4.2.6.3 Where a User is reporting an Event or an Operation which itself has been caused by (or exacerbated by) an incident or scheduled or planned action affecting (but not on) its System the notification to the Licensee shall contain the information which the User has been given by the person connected to its System in relation to that incident or scheduled or planned action (which the User must require the person connected to its System to give it) and the Licensee may pass on the information contained in the notification. 

DOC 4.2.6.4 A notification by the Licensee of an Event under DOC 4.2.5.2 which has been caused by (or exacerbated by) an Event or an Operation on the NTDC Transmission System, shall describe the Event on the Licensee Distribution System and shall contain the information which the Licensee has been given in relation to the Operation on the NTDC Transmission System.  The notification (other than in relation to the information which the Licensee is merely passing on from NTDC) shall be of sufficient detail to enable the recipient of the notification reasonably to consider and assess the implications and risks from the Event on the Licensee Distribution System and shall include the name of the individual reporting the Event on behalf of the Licensee.  The recipient may ask questions to clarify the notification. 

DOC 4.2.6.5 A User may pass on the information contained in a notification to it from the Licensee to a Generator with a Generating Unit connected to its System or to another Distribution Company connected to its System if it is required (by a contract pursuant to which that Generating Unit or Distribution Company is connected to its System) to do so in connection with an Event on its System (if the Event on the Licensee Distribution System caused or exacerbated it). 

DOC 4.2.6.6 Other than as provided in DOC 4.2.6.5, a User may not pass on any information contained in a notification to it from the Licensee (and a User receiving information which was contained in a notification to another User from the Licensee may not pass on such information) to any person connected to its System, but may only say that there has been an incident on the Total System and (if known and if power supplies have been affected) an estimated time of return to service. Each User should ensure that any other User receiving information, which was, contained in a notification to such User from the Licensee, which is not bound by the Distribution Code, does not pass any information on other than as provided above. 

DOC 4.2.6.7 Except in an emergency situation the notification shall be dictated to the 

recipient who shall record it and on completion shall repeat the notification in full to the sender and check that it has been accurately recorded 

DOC 4.2.6.8 Where an Event has been reported to the Licensee by a Generator under DOC 4.2.5 relating to a Generating Unit and in order for the Generator to assess the implication of the Event on its System more accurately, it may ask the Licensee for details of the Fault Levels on infeeds from the Distribution System to that Generating Unit at the time of the Event, and the Licensee shall, as soon as reasonably practicable, give the Generator the information provided that the Licensee has that information. 

DOC 4.2.7      Timing

DOC 4.2.7.1 A notification under DOC 4.2.5 shall be given as soon as possible after the occurrence of the Event, or time that the Event is known of or anticipated by the giver of the notification under DOC4. 

DOC 4.2.8     System Control of NTDC

DOC 4.2.8.1 Where a part of a Licensee Distribution System is, by agreement, under the System Control of NTDC then the requirements and provisions of OC6 of the Grid Code shall apply to that situation as if the Licensee’s Distribution System is a part of NTDC System. 

DOC 4.2.9     System Control of the Licensee

DOC 4.2.9.1 Where a part of a System of a User is, by agreement, under the System Control of the Licensee then the requirements and provisions of this DOC4 shall apply to that situation as if the User’s System is a part of the Licensee Distribution System. DOC 4.2.10 Significant Incidents

DOC 4.2.10.1Where an Event on the Licensee Distribution System or the Dedicated System of a User has had or may have had a significant effect on the System of any of the others, the Event shall be reported in writing to the owner of the System affected in accordance with the provisions of DOC5.  Such an Event shall be termed a “Significant Incident”. 

DOC 4.2.10.2 Where a Licensee notifies a User of an Event under DOC4, which the User considers has had or may have a significant effect on that User’s dedicated System, that User shall require a Licensee to report that Event in writing and shall notify the Licensee accordingly.  Such an Event shall also be termed a “Significant Incident”. 

DOC 4.2.10.3 Without limiting the general descriptions set out in DOC 4.2.10.1 or DOC 4.2.10.2 a Significant Incident shall include Events which result in, or may result in, the following: 

1. operation of facilities controlled either manually or automatically; 
2. voltage outside the limits, prescribed in Performance Standards 

(Distribution); 

1. System frequency outside the limits, provided in the grid code; 
2. System Stability failure (transient and voltage both); 
3. Likelihood of system collapse or shut down; 
4. Thermal overloading of the facilities; and 
5. Tripping of large amounts of load or generation. 

ÑÑÑEnd of DOC 4ÒÒÒ

DISTRIBUTION OPERATING CODE NO. 5 

EVENT INFORMATION EXCHANGE 

CONTENTS

DOC 5.1         INTRODUCTION, SCOPE AND OBJECTION                       DOC 5-30 

DOC 5.2         PROCEDURE                                                                      DOC 5-30     

DSISTRIBUTION OPERATING CODE NO. 5 

EVENT INFORMATION EXCHANGE 

DOC 5.2.1.1The Licensee and each User specified in DOC 5.1.4 shall nominate officers and establish communication channels to ensure the effectiveness of this DOC5.  Such officers and communication channels may be the same as those established under DOC4. 

DOC 5.2.2       Written Reports of Events by Users to the Licensee

DOC 5.2.2.1 In the case of an Event, which has been reported verbally to the Licensee under DOC 4.2.2 and subsequently has been determined by the Licensee to be a Significant Incident, a written report shall be given to the Licensee by the User in accordance with DOC5. The Licensee shall not pass this report on to other affected Users but may use the information contained therein in preparing a report under DOC5 to a User in relation to a Significant Incident on the Licensee Distribution System, which has been caused, by (or exacerbated by) the Significant Incident on the User’s System. 

DOC 5.2.3       Written Reports of Events by the Licensee to Users

DOC 5.2.3.1 In the case of an Event, which has been reported verbally to the User under DOC 4.2.2 and subsequently has been determined by the User to be a Significant Incident, a written report shall be given to the User by the Licensee in accordance with DOC5.  The User shall not pass this report on to other affected Users but may use the information contained therein in preparing a report under DOC5 for another Distribution Company connected to its System in relation to a Significant Incident, which has been caused by (or exacerbated by) the Significant Incident on the Licensee Distribution System. 

DOC 5.2.5.1 A written report under DOC 5.2.2 shall be given as soon as reasonably practicable after the verbal notification under DOC4 and in any event a preliminary report shall normally be given within 24 hours of such time. 

DOC 5.2.7       Joint Investigation into Significant Incidents

DOC 5.2.7.1 Where a Significant Incident has been declared and a report submitted under DOC4 either party or parties may request in writing that a joint investigation be carried out. 

DOC 5.2.7.2 The composition of such an investigation panel shall be appropriate to the incident to be investigated, and agreed by all parties involved in a decision by the review panel. 

DOC 5.2.7.3 Where there has been a series of Significant Incidents (that is to say, where a Significant Incident has caused or exacerbated another Significant Incident) the parties involved may agree that the joint investigation should include some or all of those Significant Incidents. 

DOC 5.2.7.4 A joint investigation shall take place where two-thirds of the majority of the members of the Review Pannel agree to it.  The form and rules of, the procedure for, and all matters (including, if thought appropriate, provisions for costs and for party to withdraw from the joint investigation once it has begun) relating to the joint investigation shall be agreed at the time of a joint investigation. 

DOC 5.2.7.5 Any joint investigation under DOC4 is separate from any inquiry which may be carried out under the Grid Code disputes resolution procedures. 

ÑÑÑEnd of DOC 5ÒÒÒ

DISTRIBUTION OPERATING CODE NO. 6 

WORK SAFETY AT THE INTERFACE

CONTENTS

DOC 6.1         INTRODUCTION, OBJECTIVE & SCOPE                             DOC 6-33 

DOC 6.2         PROCEDURE                                                                      DOC 6-33 

DOC 6.3         ENVIRONMENTAL SAFETY                                                DOC 6-34 

DOC 6.4         SYSTEM CONTROL                                                           DOC 6-34 

DOC 6.5         SCHEDULES OF RESPONSIBILITY                                    DOC 6-35 

DISTRIBUTION OPERATING CODE NO. 6 WORK SAFETY AT THE INTERFACE

DOC 6.2.1.1 A Safety Management System (safety Code) specifying the principles and procedures, and where appropriate, the documentation to be applied so as to ensure the health and safety of all who are liable to be working or testing on the Licensee Distribution System, or on Plant and Apparatus connected to it, shall be developed by the Licensee and approved by NEPRA. 

DOC 6.2.2      Operational Boundaries and Principles

DOC 6.2.2.1 At sites or locations where an Operational Boundary exists, which Safety Management System (Safety Code) in terms of ownership, construction, commissioning, testing, operation, maintenance and replacement of the distribution facility are to be adopted and when, shall be jointly agreed by the Licensee and user.  This shall include provision for Control Persons to be nominated by the Licensee/user to operate to Safety Management Systems in use by field personnel where appropriate. 

DOC 6.2.2.2 A system of documentation shall be maintained by the Licensee and the User which records the inter-system safety precautions taken when: 

1. work or testing is to be carried out on High Voltage Plant and/or Apparatus across the Operational Boundary; and 
2. isolation and/or earthing of the other’s System is needed 

DOC 6.2.2.3 Where relevant, copies of the Safety Management System (safety code) and related documentation shall be exchanged between the Licensee and Users for each Operational Boundary at the time of their connection with the Licensee’s Distribution System. 

DOC 6.2.3      Authorised Personnel

DOC 6.2.3.1 Safety Management System must include the provision for written Authorisation of personnel concerned with the control, operation, work or testing of Plant and Apparatus forming part of, or connected to, the Licensee Distribution System. 

DOC 6.2.3.2 Each individual Authorisation shall indicate the class of operation and/or work permitted and the section of the System to which the Authorisation applies. 

DOC 6.3         ENVIRONMENTAL SAFETY 

DOC 6.3.1      Site Safety and Security

DOC 6.3.1.1 Arrangements shall be made to ensure site safety and security as required by statutory requirements. DOC 6.3.2 Site Specific Hazards

DOC 6.3.2.1 Arrangements shall be made by all parties to ensure that personnel are warned by an appropriate means of hazards specific to any site, before entering any area of the site. This shall include hazards that may be temporary or permanent.  Where these risks include contamination or similar, suitable decontamination facilities and procedures shall be provided. 

DOC 6.3.3       Inspections by Management / Safety Representatives

DOC 6.3.3.1 Arrangements shall be made to facilitate inspections by Licensee management and Safety Representatives to sites accommodating Licensee owned Plant and Apparatus. 

DOC 6.4         SYSTEM CONTROL 

DOC 6.4.1      Control Responsibilities

DOC 6.4.1.1 The Licensee and Users shall jointly agree and set down in writing schedules specifying the responsibilities for System Control of Equipment and facilities. These shall ensure that only one party is responsible for any particular item of Plant or Apparatus at any given time. 

DOC 6.4.1.2 The Licensee and each User shall at all times have nominated a person or persons responsible for the co-ordination of electrical safety from the System stand point pursuant to this DOC6. 

DOC 6.4.1.3 The principal of control responsibilities and their specifics such as 

outlined below but not limited to must be clearly spelled out and agreed to between parties. Some of these are: - a. Ease of control 

1. Least interruptible and most practical  
2. Safe, operationally effective and dependable 

DOC 6.4.2      Control Documentation

DOC 6.4.2.1 The Licensee and Users shall maintain a suitable system of documentation which records all relevant operational events that have taken place on the Licensee Distribution System or any other System connected to it and the co-ordination of relevant safety precautions for work. 

DOC 6.4.2.2 All documentation relevant to the Operation of the Distribution System, and safety precautions taken for work or tests, shall be held by the Licensee and the appropriate User for a period of not less than one year. 

DOC 6.4.3      System Diagrams

DOC 6.4.3.1 Diagrams illustrating sufficient information for control personnel to carry out their duties shall be exchanged by the Licensee and the appropriate User. 

DOC 6.4.4      Communications

DOC 6.4.4.1 Where the Licensee reasonably specifies the need, suitable communication systems shall be established between the Licensee and other Users to ensure the control function is carried out in a safe and secure manner. 

DOC 6.4.4.2  Where the Licensee reasonably decides a back up or alternative routing of communication is necessary to provide for the safe and secure Operation of the Licensee Distribution System the means shall be agreed with the appropriate Users. 

DOC 6.4.4.3 Schedules of telephone numbers / call signs shall be exchanged by the Licensee and appropriate User to enable control activities to be efficiently co-ordinated. 

DOC 6.4.4.4 The Licensee and appropriate Users shall establish 24 hour availability of personnel with suitable Authorisation where the joint operational requirements demand it. 

DOC 6.5         SCHEDULES OF RESPONSIBILITY 

DOC 6.5.1      Ownership, Operation and Maintenance Schedules

DOC 6.5.1.1 Schedules specifying the responsibilities for ownership, Operation and maintenance shall be jointly agreed by the Licensee and appropriate Users for each location where an operational interface or joint responsibilities exist. 

DOC 6.5.2      Maintenance of Schedules and Diagrams

DOC 6.5.2.1 All schedules and diagrams shall be maintained by the Licensee and appropriate Users and exchanged as necessary to ensure they reflect the current agreements and network configuration. 

DOC 6.5.2.2 Submission to NEPRA of quarterly report on training activities regarding safety measures by the Licensee. 

ÑÑÑEnd of DOC 6ÒÒÒ

DISTRIBUTION OPERATING CODE NO. 7 

PLANT IDENTIFICATION 

CONTENTS

DOC 7.1         INTRODUCTION, OBJECTIVE & SCOPE                            DOC 7-37 

DOC 7.2         PROCEDURE                                                                       DOC 7-37 

DISTRIBUTION OPERATING CODE NO. 7 PLANT IDENTIFICATION 

DOC 7.2.1.1 When the Licensee or a User intends to install Apparatus on a site having an Ownership Boundary the proposed numbering and / or nomenclature to be adopted for the Apparatus must be notified to the other owners. 

DOC 7.2.1.2 The notification shall be made in writing to the relevant owners and shall consist of an Operation Diagram incorporating the proposed new Apparatus to be installed and its proposed numbering and / or nomenclature. 

DOC 7.2.1.3 The notification shall be made to the relevant owners at least six months prior to the proposed installation of the Apparatus. 

DOC 7.2.1.4 The relevant owners shall respond in writing within one month of the receipt of the notification confirming both receipt and whether the proposed numbering and / or nomenclature is acceptable or, if not, what would be acceptable. 

DOC 7.2.1.5 In the event that agreement cannot be reached between the Licensee and the other owners, the Licensee, acting reasonably, shall have the right to determine the numbering and nomenclature to be applied at that site. 

DOC 7.2.2      Existing Apparatus

DOC 7.2.2.1 The Licensee and / or every User shall supply the Licensee and / or every other User on request with details of the numbering and nomenclature of Apparatus on sites having an Ownership Boundary. 

DOC 7.2.2.2 The Licensee and every User shall be responsible for the provision and erection of clear and unambiguous labelling showing the numbering and nomenclature of its Apparatus on sites having an Ownership Boundary. 

DOC 7.2.3       Changes to Existing Apparatus

DOC 7.2.3.1 Where the Licensee or a User needs or wishes to change the existing numbering and / or nomenclature of any of its Apparatus on any site having an Ownership Boundary, the provisions of DOC 7.2.1 shall apply with any amendments necessary to reflect that only a change is being made. 

DOC 7.2.3.2 Where a User changes the numbering and / or nomenclature of its Apparatus, which is the subject of DOC7, the User shall be responsible for the provision and erection of clear and unambiguous labelling. 

DOC 7.2.3.3 Where a Licensee changes the numbering and / or nomenclature of its Apparatus, which is the subject of DOC7, the Licensee shall be responsible for the provision and erection of clear and unambiguous labelling. 

ÑÑÑEnd of DOC 7ÒÒÒ

DISTRIBUTION OPERATING CODE NO. 8 

SYSTEM TESTS 

CONTENTS

DOC 8.1        INTRODUCTION, OBJECTIVE & SCOPE                        DOC 8-40 

DOC 8.2.        PROCEDURE                                                                       DOC 8-40 

DISTRIBUTION OPERATING CODE NO. 8 

SYSTEM TESTS 

DOC 8.2.1.1 If the System Test proposed by the Licensee or the User connected to the Licensee Distribution System shall or may have an effect on the NTDC Transmission System then the provisions of DOC8 or the relevant provisions of the Grid Code shall apply. 

DOC 8.2.1.2 System Tests which have a minimal effect on the Distribution System or Systems of others shall 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 Distribution Planning and Connection Code. 

DOC 8.2.2      Proposal Notice

DOC 8.2.2.1 When the Licensee or a User intends to undertake a System Test which shall have or may have an effect on the System of others normally twelve months notice, or as otherwise agreed by the Licensee, of the proposed System Test shall be given by the person proposing the System Test (the ‘Test Proposer’) to the Licensee and to those Users who may be affected by such a System Test. 

DOC 8.2.2.2 The proposal shall be in writing and shall contain details of the nature and 

purpose of the proposed System Test and shall indicate the extent and situation of the facilities involved. 

DOC 8.2.2.3 If the information set out in the proposal notice is considered insufficient by the recipient they shall contact the party proposing the test with a written request for further information which shall be supplied as soon as reasonably practicable.  The Licensee shall not be required to do anything under DOC 8 until it satisfied with the details supplied in the proposal or pursuant to a request for further information. 

DOC 8.2.2.4 If the Licensee wishes to undertake a System Test the Licensee shall be deemed to have received a proposal of that System Test. 

DOC 8.2.3     Preliminary Notice and Establishment of Test Panel

DOC 8.2.3.1 The Licensee shall carryout the overall co-ordination of the System Test, using the information supplied to it under DOC 8 and shall identify in its reasonable estimation, which Users other than the party proposing the test, may be affected by the proposed System Test. 

DOC 8.2.3.2 A Test Co-ordinator, who shall be a suitably qualified person, shall be appointed by the Licensee with the agreement of the Users which the Licensee has identified may be affected and shall act as Chairman of the Test Panel referred to in DOC 8.2.4 (the Test Panel). 

DOC 8.2.3.3 All Users identified under DOC 8.2.3.1 shall be given in writing, by the Test Co-ordinator, a preliminary notice of the proposed System Test.  The preliminary notice shall contain: 

1. The Test Co-ordinator’s name and nominating company. 
2. The details of the nature and purpose of the proposed System Test, the extent and situation of Plant or Apparatus involved and the Users identified by the Licensee under DOC 8.2.3.1. 
3. An invitation to each User to nominate within one month a suitably qualified representative, or representatives where appropriate, to be a member of the Test Panel for the propose System Test. 

DOC 8.2.3.4 The preliminary notice shall be sent within one month of the receipt of the proposal notice or the receipt of any further information requested under DOC 8.2.2.3. 

DOC 8.2.3.5 As soon as possible after the expiry of that one month period all relevant Users and the Test Proposer shall be notified by the Test Co-ordinator of the composition of the Test Panel. 

DOC 8.2.4     Test Panel

DOC 8.2.4.1 A meeting of the Test Panel shall take place as soon as possible after the relevant Users and the Test Proposer have been notified of the composition of the Test Panel, and in any event within one month of the appointment of the Test Panel.  

DOC 8.2.4.2 The Test Panel shall consider 

1. the details of the nature and purpose of the proposed System Test and other matters set out in the proposal notice (together with any further information requested under DOC 8.2.2); 
2. the economic, operational and risk implications of the proposed System Test; 
3. the possibility of combining the proposed System Test with any other tests and with Plant and / or Apparatus outages which arise pursuant to the operational planning requirements of the Licensee, NTDC and Users; and 
4. implications of the proposed System Test on the Scheduling and Despatch of Generating Plant, insofar as it is able to do so. 

DOC 8.2.4.3 Users identified under DOC 8.2.3.1 and the Licensee (whether or not they are represented on the Test Panel) shall be obliged to supply that Test Panel upon written request with such details as the Test Panel reasonably requires in order to consider the proposed System Test. 

DOC 8.2.4.4 The Test Panel shall be convened by the Test Co-ordinator as often as he deems necessary to conduct its business. 

DOC 8.2.5     Proposal Report

DOC 8.2.5.1 Within two months of the first meeting the Test Panel shall submit a report, which in this DOC 8 shall be called a proposal report, which shall contain; 

1. proposals for carrying out the System Test (including the manner in which the System Test is to be monitored); 
2. an allocation of costs (including un-anticipated costs) between the affected parties, (the general principle being that the Test Proposer shall bear the costs); and 
3. such other matters as the Test Panel consider appropriate. 

The proposal report may include requirements for indemnities to be given in respect of claims and losses arising from the System Test.  All System Test procedures must comply with all applicable legislation. 

DOC 8.2.5.2 If the Test Panel is unable to agree unanimously on any decision in preparing its proposal report, the disputed matter regarding System Testing and inspection shall be referred to the Distribution Code Review Panel for resolution.  

DOC 8.2.5.3 The proposal report shall be submitted to all those who received a preliminary notice under DOC 8.2.2. 

DOC 8.2.5.4 Within fourteen days of receipt of the proposal report, each recipient shall respond to the Test Co-ordinator with its approval of the proposal report or its reason for non-approval. 

DOC 8.2.5.5 In the event of non-approval by one or more recipients, the Test Panel shall as soon as practicable meet in order to determine whether the proposed System Test can be modified to meet the objection or objections. 

DOC 8.2.5.6 If the proposed System Test cannot be so modified, the matter be referred to the Distribution Code Review Panel for resolution.  

DOC 8.2.5.7 If the proposed System Test can be so modified, the Test Panel shall as soon as practicable, and in any event within one month of meeting to discuss the responses to the proposal report, submit a revised proposal report and the provisions of DOC 8.2.5.3 and DOC 8.2.5.4 shall apply to that submission. 

DOC 8.2.5.8 In the event of non-approval of the revised proposal report by one or more recipients, the disputed matter shall be referred to the Distribution Code Review Panel for resolution. 

DOC 8.2.6     Final Test Programme

DOC 8.2.6.1 If the proposal report (or, as the case may be, the revised proposal report) is approved by all recipients, the proposed System Test can proceed and at least one month prior to the date of the proposed System Test, the Test Panel shall submit to the Licensee and all recipients of the proposal notice a programme which in this DOC 8 shall be called a final test programme stating the switching sequence and proposed timings, a list of those staff involved in the carrying out of the System Test (including those responsible for the site safety) and such other matters as the Test Panel deem appropriate.

DOC 8.2.6.2 The final test programme shall bind all recipients to act in accordance with the provisions contained within the programme in relation to the proposed System Test. 

DOC 8.2.6.3 Any problems with the proposed System Test which arise or are anticipated after the issue of the final test programme and prior to the day of the proposed System Test must be notified to the Test Co-ordinator as soon as possible in writing.  If the Test Co-ordinator decides that these anticipated problems merit an amendment to or postponement of the System Test, he shall notify any party involved in the proposed System Test accordingly. 

DOC 8.2.6.4 If on the day of the proposed System Test operating conditions on the System are such that any party involved in the proposed System Test wishes to delay or cancel the start or continuance of the System Test, they shall immediately inform the Test Co-ordinator of this decision and the reason for it.  The Test Co-ordinator shall then postpone or cancel, as the case may be, the System Test and shall, if possible, agree with all parties involved in the proposed System Test another suitable time and date or if he cannot reach such agreement, shall reconvene the Test Panel as soon as practicable which shall endeavour to arrange another suitable time and date and the relevant provisions of this DOC 8 shall apply. DOC 8.2.7 Final Report

DOC 8.2.7.1 At the conclusion of the System Test, the Test Proposer shall be responsible for preparing a written report (the ‘final report’) of the System Test for submission to other members of the Test Panel. 

DOC 8.2.7.2 The final report shall include a description of the facilities, tested and of the System Test carried out, together with the results, conclusions and recommendations. 

DOC 8.2.7.3 The final report shall not be distributed to any party which is not represented on the Test Panel unless the Test Panel, having considered the confidentiality issues, shall have unanimously approved such distribution. 

DOC 8.2.7.4 When the final report has been submitted under DOC 8.2.7 the Test Panel shall be dissolved. 

ÑÑÑEnd of DOC 8ÒÒÒ

DISTRIBUTION OPERATING CODE NO. 9 

TESTING AND MONITORING

CONTENTS

DOC 9.1        INTRODUCTION, OBJECTIVE AND SCOPE                           DOC 9-45 

DOC 9.2          PROCEDURE RELATED TO QUALITY OF SUPPLY              DOC 9-45 

DOC 9.3        PROCEDURE RELATED TO CONNECTION POINT  

                    PARAMETERS                                                                   DOC 9-46 

i

DISTRIBUTION OPERATING CODE NO. 9 

TESTING AND MONITORING 

ÑÑÑEnd of DOC 9ÒÒÒ

DISTRIBUTION PLANNING CODE 

Primary Planning Criteria (Voltage, Capacity, Reliability & Technical Losses) as applicable to all facilities at and below 132 kV, including grid stations, sub-transmission lines, 11 kV feeders, distribution transformers and LT feeders, is provided in this chapter. If the system is planned and designed to operate within the prescribed limits as specified in the Performance Standards (Distribution) and DDC and this Code, the technical losses will remain within acceptable values. 

The Licensee planner shall follow the following basic principles. 

1. During normal operating conditions and without a system component fault condition present, all equipment and facilities of the Licensee shall operate within normal ratings of the distribution facilities and the system voltages will be within the permissible limits as specified in the Performance Standards (Distribution), and this sub-code when the system is operating within the range of minimum load to the forecasted maximum peak load. 
2. During system emergency conditions and without and facilities of a Licensee system or equipment fault condition present, the equipment may be operated with overload or/and under voltage for a specified time limit and for specific number of hours as per manufacturer recommendations and IEC Standards. Planning criteria is based on normal and emergency equipment ratings.  Emergency ratings are those, which can safely exist for a specified number of hours as per IEC Standard/manufacturer instructions. 
3. 33kV and 66kV systems shall be retained with-in the existing Licensee service area only and shall not be extended further as far as possible and practicable. These systems should be gradually reduced and ultimately eliminated with load transferred to 132 kV systems. New development plans shall be based on 132 kV systems, which shall be developed in consultation with NTDC for an economic development of the entire system. 

1. System must deliver specified voltages as per this Code and NEPRA Performance Standards (Distribution)-Rules under all system conditions at all times. 
2. 11kV feeder shall not be loaded beyond its permissible limits as provided in this document or relevant IEC Standards. 
3. To provide a safe, reliable and secure supply of power in an economic and efficient manner as per the obligations placed under distribution licence and NEPRA Licensing Rules (Distribution)-1999. 
4. To propose and plan new 11kV feeders, bifurcation/ augmentation of existing feeders and new grid stations to take care of Clause (a), to Clause (c). 

1. To provide for an orderly, timely and least cost expansion of an adequate future distribution system. 
2. To forecast the load demand growth and propose new grid stations and/or 66kV/132kV lines after exploring all the possible options of reinforcement, augmentation or extension of existing sub-transmission system and 11kV distribution system. 
3. To develop five year distribution/sub-transmission investment/ development plans. 
4. To facilitate the Use of Licensee distribution system by BPCs and other Licensees for competition purposes. 
5. To exchange Planning Data with the NTDC. 
6. To provide Standards of Distribution Power Supply. 

Shunt capacitors un-switched/switched type, shall be installed on the Distribution System and sub-transmission system at suitable location for improvement of Power Factor, voltage profile and reduction of transmission and distribution losses. The size and location of capacitor installations shall be determined by the Licensee planning computer programs on the basis of reliable field data to avoid over voltages under light load periods. Useful formulae are given in the DPC Appendix-I, which may be applied for determining approximate size and location of capacitor installations or (the present procedures, which the distribution planning engineers, are following, whichever is more appropriate).

1. Loading profiles of 132/66kV lines and grid facilities. 
2. The critical modeling including analytical assessment of the corresponding effect of insertion/replacement of new equipment and its impact on the performance of the system and the point of connection. 
3. Switching complexity and co-ordination between 132 kV system and 11 kV and lower voltage level and NPCC and regional load dispatch center. 
4. Interfaced and security for communications facilities, remote monitoring, control and protection.
5. Ability to withstand levels of voltage. 
6. Short circuit study for circuit breakers and equipment. 
7. Equipment insulation co-ordination. 
8. Construction practices and additional requirements. 

Based on the NTDC/Licensee studies NTDC shall identify 66kV/132 kV transmission lines and grid stations projects that are critical to the reliability and performance of the 132 kV, 220 kV and 500 kV transmission system. NTDC and effected Licensees shall meet and work out details and costs associated for construction of the necessary 132 kV facilities. The expansion of 132/66kV Licensee system shall be carried out with a view of overall economics of developing the transmission network. 

Each year each Licensee shall submit to NTDC a relay coordination study. NTDC will prepare a system wide relay coordination study and advise each Licensee of any required changes to the relay settings. 

This information can be used for Load Demand forecasting to determine kVA/substation or substation served area and kVA feeder demand/feeder and kVA demand per feeder area served. 

Energy sales can be used to determine the required generation forecasts. Therefore the Licensee shall provide kWh meters at the substations. The 

SOFTWARE 

State-of-the-art Distribution Load flow software programs shall be used by each Licensee to analyze the 11 kV Distribution systems. The program Modules will satisfy the requirements for Distribution System Planning of the Licensee and the planning package will, at least, contain the following modules: 

1. Load Flow Analysis including single plan unbalanced load solution algorithm 
2. Capacitor Application and Optimization 
3. Short Circuit Analysis 
4. Voltage Regulation 
5. Motor Starting Dip Analysis 
6. Dynamic Feeder Optimization (area wise), including load transfer switching between feeders with a single and/or multiple sources. The function shall allow for system reconfiguration and is to perform operational and contingency analysis. 
7. Load Forecast 
8. Harmonic Analysis  

Transmission load flow software programs shall be used by each Licensee to analyze its 132 kV, 66kV, sub-transmission systems. The program modules will satisfy the requirements for Transmission System Planning. 

The Licensee shall make concerted efforts to make distribution system improvements through an effective and comprehensive planning process so as to operate more efficiently. The losses are the highest for the 11 kV and 400 V distribution systems. Periodic review of basic design parameters, construction techniques, and operating procedures for the distribution system can identify possible areas for improvement, which can increase the available energy accordingly. 

In addition to the items mentioned in the objectives the following items but not limited are candidates for loss reduction efforts.  

1. Use compression or bolted connector, eliminate wrapped wire connection on distribution lines. 
2. The selection of size of the conductor on the LT feeder should be on the basis which lends to a maximum of 5% voltage drop (regulation) along the entire length of the LT feeder on the basis of full load current of the LT feeder. 
3. Purchase new power transformers with 132/66/11 kV on-load tap changers. 
4. Ensizing the future distribution system, voltage levels, the provision of the Consumer Eligibility Criteria shall be followed while providing new service connection preferring to have diversity file mix in consumer on the feeders avoiding excessively long feeders and regular maintenance practices as included in this code. 
5. Require power factor correction capacitors be installed at consumers premises on LT side with a connected load of 50 kVA or greater and with a power factor of less than 0.9 as per the provisions of Consumer Service Manual. 
6. By proper installing the energy meters in vertical position and properly fixed. 
7. Implementation of equipment removal order in time. 
8. Regular monitoring and checking of disconnected consumers. 
9. Maintenance and monitoring of rise and fall consumption register. 
10. Attempts should be made to precisely estimate the break down ofthe losses along various sections of the distribution system by accurately modeling the distribution system in the state of art distribution software. 
11. Use insulated bus bars for making consumer connection to the secondary distribution system. 
12. Use of insulated cables for over head secondary system. 
13. Replacement of defective meters. 
14. Trimming of trees, which are touching the electric lines. 
15. Reducing the lengthy LT lines or eliminating the LT lines by installing low capacity distribution transformers for groups of consumers.  
16. Installation of sectionalizing switches/auto re-closer on branch lines and distribution transformers. 
17. Area planning, augmentation of conductor, transformer, additional transformers, conversion of lengthy sub-services by LT lines, bifurcation of feeders, aerial bundled cables etc.  

ÑÑÑEnd of Planning CodeÒÒÒ

DISTRIBUTION DESIGN CODE 

CONTENT

DDC 1           INTRODUCTION                                                                   DDC-58

DDC 2           DESIGN STANDARDS CRITERIA                                             DDC-58

DDC 3           DESIGN PRINCIPLES                                                            DDC-59 

DDC 4           EARTHING                                                                            DDC-60 

i

DISTRIBUTION DESIGN CODE 

These criteria shall apply to all distribution and sub-transmission lines and to be operated and maintained by the Licensee up to and including 132kV for both overhead lines and underground cables. 

The lines shall be designed and constructed in accordance with relevant provisions of IEC Standard or subsequent approved standards applicable to overhead lines and under-ground cables. 

The distribution network fed from 132/11 kV, 66/11 kV, 33/11 kV 11/0.4kV transformers shall be initially planned as independent networks within their respective service area. A service area of any particular substation shall mean for this purpose, an area where load shall normally be supplied by that sub-station through one or more number of feeders, as required, without exceeding the specified KVA-Km Loading limit of any feeder within the area and provisions of DPC 10. 

The Licensee shall take suitable measures, sufficiently in advance, to augment the capacity of its 11 kV feeders if in the event of the specified KVAKM loading of any particular feeder is being exceeded. 

The design of the distribution lines shall incorporate features to enable their augmentation, in future, with minimum interruption to power supply to other consumers. The existing Rights of Ways shall be fully exploited by the Licensee. 

KVA-Km loading limits for conductors may be calculated in accordance with a sample calculation shown at DDC Appendix 1. 

The designing of the distribution system should be on the basis of optimum economic loading criteria. 

1. The principles of design, manufacturing, testing and installation of Distribution Equipment, overhead lines and underground cables, including quality requirements, shall conform to applicable standards such as IEC, IEEE, Pakistan Standards or approved current practices of the Licensee. 
2. The specifications of Equipment, overhead lines and cables shall be such as to permit the Operation of the Licensee Distribution System in the following manner; 

i. within the safety limits as included in the approved Safety Code of the Licensee or the relevant provisions of the Performance Standards (Distribution); ii. within operating frequency and voltage ranges as provided in this code or Performance Standards (Distribution); and 

iii. within the thermal ratings as provided by the manufacturer or relevant IEC specifications. 

1. Equipment shall be suitable for use at the operating frequency, within specified operating voltage range and at the design short-circuit rating of the Licensee Distribution System to which it is connected having due regard to fault carrying capabilities and making and breaking duties of the circuit breakers. In appropriate circumstances, details of the System to which connection is to be made shall be provided by the Licensee. 

1. The standards, publications and specifications referred to in paragraphs (a) to (c) above are such standards, publications and specifications current at the time that the facility was manufactured (and not commissioned) in the case of facility on the Total System, or awaiting use or re-use.  If any such facility is subsequently moved to a new location or used in a different way, or for a different purpose, or is otherwise modified then such standards, publications and specifications current at the time that the facility was manufactured (and not commissioned) shall apply provided that in applying such standards, publications and specifications the facility is reasonably fit for its intended purpose and use having due regard to the obligations of the Licensee under their respective licenses and the User under the Consumer Service Manual. 

DDC 4            EARTHING

A Licensee must ensure that the neutrals and body of the power transformer at a grid station shall be connected to earth mesh provided in the yard of the grid stations through independent leads. The neutral wire should additionally be connected to earth rod and mesh through a separate lead. All other installations in the yard be connected to earth mesh. The earth resistance shall be up to or less than 2 ohms for Grid Station equipment. 

The earthing of a distribution transformer, the neutral and body of the transformer should be connected to ground rods as per IEC and PSI Standards Design Specifications. 

Earthing of Consumer Service and its meter shall be as per design standards adopted by the Licensees; and consistent with IEC, and IEEE Standards.  

The earth resistance of the distribution transformers and HT/LT structures/poles shall not be more than 2.5Ωand 5Ωrespectively. 

ÑÑÑEnd of DDCÒÒÒ

CONNECTION CODE 

CONTENTS 

CC 1    INTRODUCTION                                                                                             CC-62 CC 2     SCOPE                                                                                                             CC-62

CC 3 PURPOSE AND AIM       CC-62 CC 4 PRINCIPALS         CC-63 

CC 5            SUPERVISORY CONTROL AND DATA ACQUISITION  

                    (SCADA) SYSTEM                                                                          CC-63 

CC 6            ESTABLISHING OR MODIFYING CONNECTION                                  CC-64

CC 7             CONNECTION ARRANGEMENTS FOR GENERATORS                       CC-71 

CC 8             INSPECTION AND TESTING                                                              CC-77

CC 9             RIGHT OF ENTRY AND INSPECTION                                                 CC-77

CC 10           ENFORCING COMPLIANCE with NTDC NETWORK                              CC-77

CC 11           REQUIREMENTS FOR EMBEDDED GENERATORS                             CC-77

                    FIGURE-1 

                    Connection Procedure                                                                       CC-79

                    DIAGRAM-1 

           INTERCONNECTION CONFIGURATIONS FOR GENERATORS     Connections at 11kV; Scheme 1 and Scheme 1A                                       CC-80

                    DIAGRAM-2 

INTERCONNECTION CONFIGURATIONS FOR GENERATORS 

                    Connections at 66kV; Scheme 2                                                         CC-81

                    DIAGRAM-3 

INTERCONNECTION CONFIGURATIONS FOR GENERATORS 

                    Connections at 66kV; Scheme 2A                                                       CC-82

                    DIAGRAM-4 

INTERCONNECTION CONFIGURATIONS FOR GENERATORS 

                    Connections at 132kV; Scheme 3                                                        CC-83

                    DIAGRAM-5 

INTERCONNECTION CONFIGURATIONS FOR GENERATORS 

                    Connections at 132kV; Scheme 3A                                                      CC-84

i

CONNECTION CODE 

CC 1              INTRODUCTION 

  This section deals with the connection principles, requirements, guidelines, and procedures for the entities other than NTDC seeking either new connection with Licensee's network or modifying existing connection. 

  In this sub-code of the Distribution Code, the network connection requirements have been outlined which specify both the minimum technical/functional, design and operating criteria that must be complied with by any User connected to or seeking connection with the Licensee's network. It also prescribes the application procedures to be adopted by the prospective Users, and the obligation that needs to be fulfilled by the Licensee related to providing connection and operating its system after the connection has been provided. Furthermore, it specifies the information requirements on the part of prospective and existing Users of the Licensee's system. The procedures contained in this chapter are applicable to the following. a. All Generators 

1. Embedded Generators 
2. Independent Generators 
3. Other Distribution Companies 
4. Externally Connected Consumers  
5. Externally-connected Parties  
6. BPCswith supply of 1MW and above. 

CC 2              SCOPE 

This chapter deals with connection to the Licensee’s network at 11kV and above upto 132 kV in respect of the entities listed in CC1. The time limits related to provide new connection to Applicants provided in this sub-code shall not be inconsistent with the time limits as provided in NEPRA Performance Standards (Distribution)-Rules clause 4(c). These time limits have also been detailed in the Consumer Service Manual approved by NEPRA. 

CC 3              PURPOSE AND AIMS

 The Connection Code provides the framework for connection to the Licensee's network. It has the following aims: 

1. to enumerate the principles and guidelines for establishing a connection and use of the network; 
2. to establish and streamline the process to be followed by a prospective and existing User to establish or modify a connection to Licensee’s network; 
3. to manage and prepare the distribution network of the Licensee, and the connection point for applicant seeking the connection;  
4. to establish process to ensure ongoing compliance with technical and operating requirements indicated in this sub-code;  
5. to achieve long term economic benefits in terms of costs and system reliability towards an orderly development of the distribution system; and 
6. to establish a uniform, consistent and fair policy of Connection to the Licensee’s distribution system.  

CC 4              PRINCIPLES 

The conditionalities and the procedures covered under this Connection Code are based on, among others, the following principles and assumptions: 

1. All Users shall have an opportunity to form a connection to the network; and have access to the services provided by the Licensee. 
2. To provide a uniform treatment in identifying terms and conditions for each applicant. 

CC 5             OWNERSHIP BOUNDARIES 

CC 5.1 The point or points at which supply is given or taken between the Licensee’s System and Users shall be agreed upon between the Licensee and the User as required.  For supplies at Low Voltage (LV) the general rule is that the point of supply will be at the Users terminals of the Licensee’s owned metering equipment but not inconsistent with Consumer Service Manual and Consumer Eligibility Criteria. For High Voltage (HV) supplies, including connections between Distribution Licensees and Users, and where necessary busbar connected supplies at Low Voltage, the points of supply shall be subject to specific agreement between the parties in each case. 

CC 5.2           The respective ownership of Plant and Apparatus shall be recorded in a written agreement between the Licensee and the User as required.  In the absence of a separate agreement between the parties to the contrary, construction,       commissioning, control, operation           and      maintenance responsibilities shall follow ownership. 

CC 5.3  For supplies at High Voltage, the Licensee shall with the User’s agreement prepare a responsibility schedule and, an Operation Diagram determined by the Licensee during the application process for connection showing the agreed Ownership Boundary. Copies of these documents shall be retained by the Licensee and User. Changes in the boundary arrangements proposed by either party must be agreed in advance and shall be re-coded on the Licensee Operation Diagram. 

CC 5.4           Network Boundaries

The Licensee shall own and operate the assets of 132kV and 66kV substations and distribution network of 11kV and lower voltage level in its ownership and control.  

NTDC shall operate 132 kV lines leading to the Combined Delivery Points of distribution Licensees, 132 kV transmission lines connecting to generating stations, and lines connecting more than one distribution Licensee.  

Bifurcation of Network between NTDC and Licensee  

The Network Bifurcation Point between NTDC and Licensee shall be the dropper from the terminal structure of 220 kV grid station to the Licensee’s 132kV or 66kV line, which shall also be the Connection Point for that Licensee. The NTDC’s maintenance jurisdiction shall be up to the tension strings of the same terminal structure towards gantry side.  

           Bifurcation of Network between Distribution Companies and Azad Jammu andKashmir (AJK) Network

AJK Electricity Department is taking power from PESCO, IESCO and GEPCO at 11kV voltage. The Network Bifurcation Point shall be the jumpers of 11kV Power cable connected to the panel.  

CC 5.5           Combined Delivery Points

These are 220/132/66 kV substations where 132/66 kV lines originate into the Licensee’s network. 

CC 6              ESTABLISHING OR MODIFYING CONNECTION 

CC 6.1  Process and Procedures

 The entities listed in CC 1 seeking a new connection or modification of an existing connection shall adopt the following process and the procedures. 

  The Licensee shall submit the connection application to NTDC (the detailed process of the Procedure is indicated in Figure-1 attached at the end of this sub-code), whereas Independent Generators, BPCs and Special Purpose Transmission Licensee (SPTL), Housing Colonies, Defence Establishment, and Embedded Generators shall submit their applications to the respective Licensee and NTDC simultaneously. The Distribution Companies shall evaluate their application for providing the connection and shall forward to NTDC (wherever applicable) what Licensee considers it necessary.  

CC 6.2           Intention Application

The entity wishing to modify its existing connection or connect to the network of the Licensee at 11kV and above upto 132kV for the first time shall prepare an intention proposal. The proposal must indicate: 

1. The type of facilities he intends to establish (distribution and/or subtransmission system). 
2. Size of the facility and range including load factor. 
3. Proposed Connection Point. 
4. Tentative Schedule for connection. 
5. Protection and metering requirements. 
6. Voltage level at which the connection is required/modified. 
7. Maximum and minimum active and reactive power requirements. 
8. Type and characteristics of the proposed load to be connected. 
9. The possible material effects of this proposed connection on the network power transfer capability including that of other networks, 
10. Any additional risk posed by this proposed connection to other Users. 
11. Adequacy of the inter-connection facility for at least next 5 years timeframe, and effectiveness of the protection/metering facilities installed. 
12. Short circuit and stability consideration. 

In addition intention proposal shall be made available at the offices of the Licensees or on-line. 

Provision of on-line intention application should also be made by Licensee. 

The respective Licensee, must evaluate the intention application within 30 business days (Preliminary evaluation time) based on the following considerations and make communication with the applicant. 

1. Evaluate the application and accompanied information. 
2. Check feasibility of the proposed connection. 
3. Study transmission and/or distribution congestion or reinforcements required due to connection. 
4. List out design functional requirements and performance standards and specification and communicate to the applicant in the next communication. 
5. Prepare preliminary cost estimate for connection. 
6. Indicate if additional information is required from the applicant. 
7. If the applicant has made connection agreements with other Code participants. 
8. Prepare load flow studies for the year, the facility shall go into service. 

 If distribution company requires additional information from the applicant, the applicant must be requested within 30 business days (preliminary evaluation time) to provide such information. If Licensee does not require such information the applicant must be made on “offer to Connect” within the 30 day time period to apply for connection to their network.  

 In case the applicant has been requested to provide additional information, he must provide such information within 10 business days after receipt of request from Licensee. The Licensee shall consult NTDC and other Licensees regarding the proposed connection if necessary. 

 The Licensee must provide the information/data related to its network to applicant, which shall help the applicant to prepare its application. The technical data, which may vary depending on the connection requirements and the type, rating and location of the facility to be connected is to be attached with the application. 

CC 6.3                    Service and Network Design Conditions

                    a.        Substation Drawings and Data

1. Switchyard equipment connection lay out of all the substations under their control. 
2. Equipment foundation layout. 
3. Foundation structural (civil) drawings iv. Earthing Layout 

v. Construction and Maintenance Standards vi.          Procedures related to safety and switching vii.        One line Diagrams 

  Connection diagrams 1 to 5 as referred in Table-1 and connection flow chart are provided at end of this sub-code. 

Any other information relevant to the submission of an application for connection.  

 The Licensee must use its reasonable endeavours to advise the Applicant of technical risks, rights, obligations, and responsibilities in respect of the proposed connection.   

CC 6.4           Application for Connection or Modification

On receipt of offer for connection from the Licensee the applicant must submit its application within 30 business days from the Date of Offer for connection. The application must provide the following information for further evaluation by Licensee. 

1. Technical and commercial Feasibility Report. 
2. Detailed Design of the facility the applicant intends to install. 
3. A final committed Implementation Schedule showing proposed milestone dates for construction and commissioning of the applicant’s connection facilities. 
4. Details of the Protection arrangements and settings keeping in view the protection schemes adopted by the Grid Code and concerned Licensee. 
5. Copies of all Safety Rules and Local Safety Instructions applicable at Applicant’s Sites. 
6. Proposed usage of the facilities. 

Licensee shall carryout preliminary evaluation of the application and if the application meets requirements of this Code and the technical criteria for connection/ modification, it shall send its concurrence to the Applicant and NTDC to allow connection with its network. The NTDC shall evaluate the application with reference to the Grid Code and its obligations as System Operator, as per its obligations in the Grid Code wherever required. 

 If the Applicant wants to have connection at multiple connection points of the network of Licensee then, he shall include all the connection points in the same application, however, the term and conditions for each connection point may vary in accordance with the conditions prevailing at each connection point. If the connection points are within the network of different distribution Licensees, the Applicant must prepare and submit separate applications to NTDC and concerned distribution Licensee.  

The Licensee shall evaluate the application and its contents within 30 (thirty) days and invite the applicant to have negotiations for Connection Agreement. 

CC 6.5          Connection Agreements

   If the Applicant wishes to accept the Offer to Connect, the Connection Applicant must: 

1. Agree and apply for licence from NEPRA to operate as an independent generator, embedded generator or a Special Purpose Transmission Licensee. 
2. Agree to be bound by relevant provisions of the Grid Code (if applicable) and Distribution Code. 
3. Must follow all relevant rules and regulations already issued or to be issued in future by the Licensee, GoP, NEPRA, or the relevant Authorities including Safety Code of the concerned Licensee. 
4. The detailed environmental framework is not being provided in the Grid Code and Distribution Code, however, the applicant must agree to abide by all such requirements, which are set out by the environmental agencies or NEPRA Licences, Rules and Regulations. 
5. Enter into a connection agreement with each relevant distribution Licensee and, in doing so, must use its reasonable endeavors to negotiate in good faith with all parties with which the Applicant must enter into such a connection agreement. 

  The Licensee responsible for the connection must inform NTDC and other distribution Licensees, if needed, that a Connection Agreement has been entered into between them; and forward to NTDC all relevant technical functional, and operational details of the proposed connection, including the proposed protection and metering installation, and the terms upon which a User is to supply any ancillary services or disconnection/reconnection under the connection agreement. 

 NTDC and the Licensee must, within 10 business days of receipt of communication regarding Connection Agreement shall convey its comments on the metering, and protection arrangements.  

 The Applicant must agree to make provisions for rectification of causes for deteriorated quality and reliability of supply at the connection points of other Users caused by the Applicant’s connection to the network and subsequent operation. In the event of disagreement between the parties, Review Panel shall be the arbitrator whereas the final decision shall be made by NEPRA only, if requested by the Review Panel. 

CC 6.6  The design of connection between Licensee’s distribution system or subtransmission network and Users shall be in accordance with the principles setout in the Grid Code, Distribution Code, Performance Standards (Distribution), Consumer Eligibility Criteria and Consumer Service Manual, as applicable. 

Before entering into the connection agreement, it shall be necessary for the Licensee to be reasonably satisfied that the User's system and installation/equipment at the boundary with the Licensee’s distribution system or network shall comply with all appropriate requirements of the Distribution Code/Grid Code and applicable design specifications of the Licensee. 

CC 6.7  In terms of overall time limits for providing connection as provided in Performance Standards (Distribution) for 11kV and above the time shall start from the date of submission of formal application by the Applicant on receipt of offer from the Licensee till such time the consumer is provided with the connection. The time stated in this section shall not include any time required that is beyond the control of the Licensee. 

                    The time schedules for 11kV and above connection is summarized as under.                         Preliminary evaluation time of Intention Application                    = 30 days                      Additional information required if any from the Applicant                  = 10 days                      Offer for Connection to the Applicant                                                 = 15 days 

                    Submission of formal application for Connection by the Applicant = 30 days              Final evaluation of Application by the Licensee                           = 30 days 

                     Negotiation and Connection Agreement                                             = 07 days 106  

Days 

                     Comments of NTDC on Connection Agreement                          = 10 days 

                     Providing Connection on 11kV                                                  = 59 days 

496  

                     Providing Connection above 11kV                                             = 449 days 

Days

CC 6.8           Communication

Where for operational reasons, Licensee determines that a means of routine and emergency operation, communication between the Licensee and the User is required, then the same shall be provided and maintained by the Licensee. 

CC 6.9          Supervisory Control and Data Acquisition (SCADA) System 

 Licensee shall have a communication system and supervisory control and data acquisition (SCADA) system to monitor and control its network including 132/66 kV sub-stations and generators connected to its network. At the generating station, a RTU shall be provided for monitoring and control of each the generating units. In addition, RTU provided by the Generator shall have facility of dispatching and loading the generating unit by the Licensee from Licensee’s Load Dispatch Center.  

CC 6.10        Technical Requirements

CC 6.10.1      Generating Plant Performance Requirements

 For Embedded Generating Plant subject to Central Dispatch the electrical parameters required shall be those detailed in the Grid Code. For generation 

not subject to Central Dispatch the electrical parameters shall be specified by the Licensee at the time of Offer for Connection. A Generating Unit must be capable of supplying its Registered Capacity within the System frequency range of 49.5 to 50.5 Hz.  The output power should not be affected by voltage changes within the permitted operating range as provided in this Code, Grid Code or Transmission Performance Standards. The Generating Unit shall comply with the voltage and frequency requirements as set by the Licensee in the Connection Agreement not inconsistent with the Codes and Performance Standards at all times. 

CC 6.10.2      Control Arrangements

 The Licensee shall specify in writing at the time of offer for connection if a continuously acting fast response automatic generator excitation control system (AGC) is required to control the Generating Unit or Power Station.  This shall be dependent upon the size and type of Generating Unit and the network of the Licensee’s system to which the Generating Unit shall be connected and the provisions of the Grid Code, if applicable. 

CC 6.10.3      Co-ordination with Existing Protection

                    It shall be necessary for the Protection associated with Embedded Generating Plant to co-ordinate with the Protection associated with the Licensee’s system as follows: 

1. For Generating Unit directly connected to the Licensee’s system, the Generating Unit must meet the target clearance times for fault current interchange with the Licensee’s system in order to reduce to a minimum the impact on the Licensee’s system due to faults on circuits owned by Generators. The Licensee shall ensure that the Licensee Protection settings meet its own target clearance times. Protection systems of both parties must be well-coordinated and periodically tested for their functioning as expected. 

The target clearance times are measured from fault current inception to arc extinction of the circuit breaker and shall be specified by the Licensee to the requirements of the connecting network of the Licensee’s system. 

1. The settings of any Protection controlling a Circuit Breaker or the operating values of any automatic switching device at any point of connection with the Licensee’s system shall be agreed upon between the Licensee and the User including Generators in writing during the initial connection consultation process. 

 The Protection settings or operating values shall not be changed without the express agreement of the Licensee and/or NTDC, if applicable. 

1. It shall be necessary for the Generating Plant Protection to co-ordinate with any auto-reclose policy specified by the Licensee. 
2. Any Generating Unit connected to the Licensee’s system shall be required to withstand, without tripping, the Negative Phase Sequence loading incurred during the clearance of a close-up phase-to-phase 

fault by System Back-up Protection which shall be within the Generating Unit short time rating in the Licensee’s system.  The Licensee shall advise the Generator of the expected Negative Phase Sequence loadings during the Connection Agreement process. 

CC 6.10.4      Islanding

 It is conceivable that a part of the Licensee’s system, to which Embedded Generators are connected can, during emergency conditions, become detached from the rest of the distribution and transmission System.  It shall be necessary for the Licensee to decide, dependent on local network conditions, if it is desirable for the Embedded Generators to continue to generate onto the islanded Licensee’s system. 

 If no facilities exist for the subsequent resynchronization with the rest of the Licensee’s system then the Embedded Generator shall under Licensee’s instruction, ensure that the Generating Unit is disconnected for resynchronization. 

 Under emergency conditions there is an expectation that some generation shall continue to operate outside the frequency limits specified in the Grid Code. However, for Embedded Generators connected to the Licensee’s system at a voltage level less than 132kV it is likely that this could mean connection within an automatic low frequency load disconnection zone.  Consequently, Embedded Generators should ensure that all Protection on Generating Unit should have settings to co-ordinate with those on the automatic low frequency load disconnection equipment, which shall be detailed by the Licensee. 

CC 6.10.5      Black Start Capability

 It shall be necessary for each Embedded Generator to notify the Licensee if its Generating Unit has a restart capability without connection to an external power supply. 

CC 6.10.6      Generating Unit Commissioning Tests

 Where a Generator requires connection to the Licensee’s system in advance of the commissioning date, for the purposes of testing, the Generator must comply with the requirements of the Connection Agreement.  The Generator shall provide the Licensee with a commissioning programme, approved by the Licensee if reasonable in the circumstances, to allow commissioning tests to be co-ordinated. 

                 Under certain circumstances either more or less detailed information than that specified above might need to be provided and shall be made available by the Generator at the request of the Licensee. 

CC 6.10.7 Any relevant information regarding technical design and operational criteria as mentioned in CC 5.4 of the Grid Code may also be supplied along with the following information. 

1. Earthing requirements/negative sequence current injection 
2. AGC (frequency and speed governing characteristics) 
3. Emergency generator disconnection conditionalities. 
4. Power quality requirements 

i. Harmonics ii. Resonance 

iii.   Voltage flicker / dips iv.    Voltage unbalance 

1. Adequate and accurate metering equipment. 

CC 7              CONNECTION ARRANGEMENTS FOR GENERATORS  

 The Licensees are required under this sub-code to process a connection application or to submit an Offer to Connect for the provision of distribution network services to the Generator’s generating unit or group of generating units 

 If a Generator or an Embedded Generator requests for connection to the network of Licensee, the Licensee shall negotiate in good faith with the Generator to reach an agreement in respect of the open access arrangements as per the provisions of its licence. In the event of disagreement between the parties, NEPRA shall be the final arbitrator. 

 The Generator shall follow the same procedure for seeking connection to the network as mentioned in CC 6 of this code. However, as a basis for negotiation for the connection agreement, the Generators: 

1. must provide to the Licensee with such information as is reasonably requested relating to the expected operation of its generating units; and 
2. the Licensee must provide to the Generator such information as is reasonably requested to allow the Generator to fully assess the commercial impact of the connection arrangements sought by the Generator. 

A Generator may seek open access arrangements at any level of power transfer capability between zero and the maximum power out put of the Generator’s generating unit or group of generating units as per the provisions of the Grid Code and Distribution Code. 

CC 7.1           Connection Arrangement for Bilateral Transactions

  If the Users intend to make bilateral transactions, for such connections both the User and Generator within the service territory of Licensee shall make mutual Connection Agreements, however they shall convey the details of these agreements to Licensee and NTDC both. 

CC 7.2           Disconnection and Reconnection

 The following procedures need to be adopted for disconnection of any facility from the network. 

CC 7.2.1        Voluntary Disconnection

  For the voluntary disconnection of any equipment or the facility, the User must give atleast two months advance notice that it intends to disconnect its 

facility from the Licensee’s network or subject to the procedure set out in the Connection Agreement. 

   However, it shall be ensured that disconnection and reconnection procedures are made an integral part of the Connection Agreement. 

Before taking decision for disconnection of the equipment or the facility, it must be ensured that by such disconnection there is no impact on the quality or reliability of supply to other Users. If an impact is found, it shall be handled as per the provision of the contract between Licensee and the User to resolve the issue.    

Prior to disconnection, the Licensee must inform NTDC about the disconnection proposal and its expected impact on the network. 

   The voluntary disconnection and subsequent re-connection shall be subject to fulfillment of all the requirements placed under the provision of Distribution Licence, NEPRA Act and Rules, and Consumer Service Manual. CC 7.2.2 Involuntary Disconnection

                     The Licensee may disconnect equipment or the facility of User or entity if: 

1. The User is not operating its facility in accordance with the Connection Agreement or the provisions of Grid/Distribution Codes, in accordance with the law of the land, Consumer Service Manual or Connection Agreement by giving advance notice depending upon the situation. 
2. In case of operational emergencies due to which electrical system of the Licensee is incapable of providing the required services. 
3. In the event of emergencies, the User’s facility must be disconnected in an orderly manner or as indicated in the Connection Agreement, so that the security of the system is not affected. 
4. A defaulted User must not bring proceedings against the Licensee to seek to recover any amount for any loss or damage incurred due to the disconnection. 

CC 7.2.3        Reconnection of the Equipment or the Facility

The Licensee, following an outage or emergency, must reconnect the User’s Facility after confirming that: 

1. The User has rectified all such circumstances, which were the cause of disconnection. 
2. The Licensee must charge a reasonable cost as indicated in the Connection Agreement for reconnection of the facility which was disconnection due to default. 
3. The facilities, which were disconnected due to emergencies, must be reconnected as soon as the causes of the emergency have been eliminated, and the network has returned to steady state operating conditions.   

CC 7.2.4        Connection Related Obligations of Generators

 Generators proposing to connect to the Licensee’s system shall submit a detailed design report that covers, as a minimum, the following subjects: a) Suitability requirements 

b)           Adequate fault levels at the Site 

c)           Maintenance outage co-ordination 

d)           Stability requirements. 

e)           Insulation level requirements (switching insulation levels and high voltage protection) 

f)            Lightning protection for average isokeraunic levels for the site. 

g)           Efficient and simple operational co-ordination procedures 

h)           Plant Dispatch obligations 

i)            Isolation Equipment. 

                    Frequency and Voltage Control

Each Generator’s generating unit must be capable of contributing to frequency and voltage control of the NTDC’s Transmission System by continuous modulation of Active Power and Reactive Power output. Therefore, to achieve this requirement it shall require that: (a) Each Generating Unit must be fitted with a fast acting, proportional speed governor, and a unit load controller or equivalent control device to provide frequency regulation under normal operating conditions; and (b) The generating unit must ensure that a continuously acting automatic excitation control system is provided to manage constant terminal voltage control of the Generating Unit without instability over the entire operating range of the Generating Unit. The requirements for excitation control facilities shall be included in the connection agreement. 

                    Reactive Power Supply and Voltage Regulation

The Generators shall maintain a network voltage or reactive power output as required by the System Operator of NTDC within the reactive capability of the Generators.  

CC 7.2.5        Data Requirements

The Applicant shall provide the following data with the Intention Application.  The Applicant shall also provide a Single Line Diagram of the proposed facility which must indicate all the current carrying parts/equipment connected at all the voltage levels of the proposed substation.    

1. Names of the substation and its operating voltage 
2. Connection of the Operators Network  and Generators 
3. Metering arrangement 
4. Protection arrangement 
5. Make of the equipment 
6. If double busbar is being operated by splitting, it  shall be indicated accordingly 
7. Any other useful information not listed above. 

                    Equipment Data

                    Circuit Parameters:

1. Rated voltage (kV) 
2. Operating voltage (kV) 
3. Positive phase sequence reactance 
4. Positive phase sequence resistance 
5. Positive phase sequence susceptance 
6. Zero phase sequence reactance (both self and mutual) 
7. Zero phase sequence resistance (both self and mutual) 
8. Zero phase sequence susceptance (both self and mutual) 

                    Transformers

1. Rated MVA 
2. Voltage Ratio 
3. Winding arrangement 
4. Positive sequence reactance 
5. Max, min and nominal tap positions  
6. Positive sequence resistance 
7. (max, min and nominal tap) 
8. Zero sequence reactance 
9. Tap changer range 
10. Tap change step size 
11. Tap changer type: on load or off circuit 
12. Earthing method: Direct, resistance or reactance
13. Impedance (if not directly earthed) 
14. Phase connection. 

                    Switchgear

1. Switchgear. For all circuit breakers:-Rated voltage (kV) 
2. Operating voltage (kV) 

i.      Rated 3-phase rms short-circuit breaking current, (kA) ii.     Rated 1-phase rms short-circuit breaking current, (kA) iii.     Rated 3-phase peak short-circuit making current, (kA) iv.         Rated 1-phase peak short-circuit making current, (kA) 

v. Rated rms continuous current (A)DC time constant applied at testing of asymmetrical breaking abilities (secs.) 

                    Generating Unit Data

1. Rated terminal volts (kV) 
2. Rated MVA 
3. Rated MW 
4. Dependable Capacity MW 
5. Minimum Generation MW 
6. Short circuit ratio 
7. Direct axis synchronous reactance 
8. Direct axis transient reactance 
9. Direct axis sub-transient reactance 
10. Direct axis short-circuit transient time constant. 
11. Direct axis short-circuit sub-transient time constant. 
12. Quadrature axis synchronous reactance. 
13. Quadrature axis sub-transient reactance. 
14. Quadrature axis short-circuit sub-transient time constant. 
15. Stator time constant. 
16. Stator leakage reactance. 
17. Armature winding direct-current resistance. 
18. Maximum Emergency Capability. 
19. Installed Capacity. 
20. Maximum action and reaction power out put. 
21. Type of generating plant (synchronous,  asynclimuous etc). 
22. Type of prime movers 
23. Operating regime of generator in continuous intermittent, peak lopping. 
24. Fault level contribution. 
25. Method of voltage control. 
26. Zero sequence aa.    Negative sequence bb.    Automatic voltage regulation.  cc. Speed governor and prima mover data. dd.            Capacity and stand by requirements. ee.     Auxiliary demand of individual unit and power house. 

Interface Arrangements

1. The means of synchronization between the Licensee and the User; 
2. Details of arrangements for connecting with earth that part of the Generator’s System directly connected to the Licensee Distribution System; 
3. The means of connection and disconnection which are to be employed; and 
4. Precautions to be taken to ensure the continuation of safe conditions should any earthed neutral point of the Generator’s System operated at HV become disconnected from earth. 

 More or less detailed information than that contained above might need to be provided, subject to the type and size of generation or the point at which connection is to be made to the Licensee Distribution System. This information shall need to be provided by the Generator at the reasonable request of the Licensee. 

                    Preferred Connection Arrangement

The three schemes have been described in Table 1 for interconnection of the generators. The existing generators are using these schemes, however, the new generators may design new configurations, which shall be acceptable by Licensee after evaluation of the prevailing system conditions. These schemes of connection diagrams are provided at the end of this sub-code. 

Table-1 

CC 8              INSPECTION AND TESTING 

  Regarding inspection and testing of equipment and the facilities of the Users, the following procedures are to be followed: 

CC 9              RIGHT OF ENTRY AND INSPECTION 

  The Licensee, who is also party to the Connection Agreement, believes that another User is not operating its network in accordance with the technical limits setout for the Connection in the Grid/Distribution Code, and the connection agreement, and due to which negative impact is reflected to the Licensee’s or another User network, can enter into the premises of the connection of the User and inspect the operating conditions of that Connection. 

  The Licensee who intends to inspect premises of the Connection of a User under normal operating conditions shall give a three-business day’s notice for the same indicating the name of the representative who would conduct the inspection, and time and date of the inspection. 

"However, detailed provision regarding Licensee's right of entry to consumer's premises to inspect connection and metering facilities are included in the Consumer Service Manual". 

CC 10            ENFORCING COMPLIANCE with NTDC NETWORK 

  The procedures to ensure enforcement of network connection requirements as well as compliance of connection provisions of the Distribution Code should be in accordance with relevant provisions of the Code Management sub-code of this code. 

CC 11            REQUIREMENTS FOR EMBEDDED GENERATORS 

CC 11.1         EMBEDDED GENERATORS

CC 11.1.1 Distribution Connection Code is applicable to all existing and prospective Generators, including Consumers with Own Generation, having Plant operating or capable of operating in parallel with the Licensee Distribution System.  

CC 11.1.2 In addition to meeting the requirements of this code, Embedded Generators shall need to meet the requirements of other relevant sections of the Distribution Code and relevant provisions of the Grid Code. 

CC 11.2         Information Required from All Embedded Generators

It shall be necessary for each Generator to provide the Licensee information on (a) the Generating Plant and (b) the proposed interface arrangements between the Generating Plant and the Licensee Distribution System. Any other relevant information provided in CC 7 of this sub-code may be required by the Licensee before entering into an agreement to connect any Generating Plant onto the Licensee Distribution System: 

CC 11.3         Obligations of Embedded Generators

        The Obligations of Embedded Generators shall be as follows but not limited to: 

1. Must Obtain License from NEPRA to operate as Generator unless it is a self generator. 
2. Must comply with the requirements and conditions of connections for Generators set out in the Connection Agreements made with the Licensee and Grid/Distribution Code accordingly.  
3. The Generators must submit an application for change for approval by the distribution company of the existing or the installation of a new equipment at its facilities. Prior to installation of the proposed equipment, its specifications including any change in the layouts must be approved by the Licensee 
4. Must comply with the technical, functional and operational requirements setout for the connection by the Licensee as per this subcode or connection agreement. 
5. Must provide generation availability forecast information including the amounts of output, partial shutdowns, any de-ratings and outages (MW & MVAR both), to the relevant Distribution Company or NTDC for Dispatch function, if applicable. 
6. The Generators must provide their development programs to the relevant Distribution Company so that the transmission or distribution facilities can be upgraded in a timely manner, if required for, evacuation of power from the Generator’s facilities. 
7. Permit and participate in inspection and testing of facilities and equipment prior to commissioning. 
8. Must participate in frequency and voltage control, stability requirements and short circuit requirements as specified in the Grid Code or Distribution Code. 
9. Must maintain requisite functional protection facilities accurate metering facilities, testing, inspection and repairs at all times.  

                                         CONNECTION PROCEDURE                             Figure-1

for new connection or amendment of existing connection 

Connections at 11kV 

Scheme 1

The generators may adopt any of the configurations depending on its location with reference to the substation and existing feeders and loading and operating condition of the feeders. 

Connections at 66kV 

Scheme 2

For connection of generators at 66kV two configurations have been indicated which may be adopted according to the system conditions. The new generators may opt for new configurations, which System Operator may except after carrying out necessary system studies. 

DIAGRAM-2 

Connections at 66kV 

Scheme 2A

DIAGRAM-3 

Connections at 132kV 

Scheme 3

For interconnection of generators to 132kV network two configurations schemes 3&3A have been provided. Both the schemes are in use by existing generators. However, the new generators may opt for new configurations, which the System Operator may accept according to prevailing and expected future conditions of the system. 

DIAGRAM-4 

Connections at 132kV 

Scheme 3A

DIAGRAM-5 

SYSTEM CONSTRUCTION  CODE 

CONTENT 

SC 1              CONSTRUCTION MANUAL                                                                  SC-86

SC 2              CONSTRUCTION GUIDELINES                                                            SC-86

SC 3              CONSTRUCTIONAL IMPROVEMENTS                                                  SC-87

SYSTEM CONSTRUCTION CODE 

Following instructions are provided on construction practices as guidelines to form contents and level of details required for the operating / construction manual to be prepared by the Licensee's. 

SC 2.1           Overhead Distribution Lines

The overhead distribution lines shall be designed in accordance with applicable international standards.  

SC 2.2Wiring on Consumer’s Premises

The service Wires to consumers shall be installed in accordance with relevant Construction Standards for 230V/400V supply and in accordance with the Consumer Service Manual. 

SC 2.3Underground Installations

Direct buried cable or conduit or other raceways installed shall meet the minimum cover requirements of International standards. All underground installations shall be grounded and bonded in accordance with the DISCOs/KESC approved standards based on relevant international standards like IEC, IEEE, and ASI. Underground cable installed under a building shall be in a raceway that is extended beyond the outside walls of the building. 

The system can be improved by providing the following construction criteria by the Licensee. 

SC 3.1Foundation of the Poles/Structure

Foundations shall be designed considering the nature of soil/salinity in the area. Presently the PCC Poles, Steel Tubular Polesare being erected without any foundation. This practice alarmingly decrease the life in the salinity zones. Here the salt is absorbed by the poles in the ground and after some time the pole cracks/crumbles. This can be avoided by providing concrete foundations of sulphate resistive cement wherever necessary and required. 

SC 3.2Insulators

In areas where air borne dust/salts are deposited on insulators during fog and forms contamination which is conductive and weakens the dielectric strength of the insulators which causes flashovers and insulator failure continuating flashovers shall be avoided by providing double disc insulators in the construction design in such areas.  

SC 3.3Line Connectors

Line connectors must be installed properly so as not to result in loose joints or cause flashovers, broken conductors and severe line losses. The Licensee must use parallel grove type connectors (PG) and follow installation instructions to assure proper installation. The instructions shall indicate wire brushing of the conductors, adding an oxide compound to conductor surface, and proper tightening of the bolts.  

Use of compression type connectors shall be promoted. Hand Compression Tools shall be used to affix these connectors. 

SC 3.4Transformer Connections

1. Licensee shall develop construction standards that provide for the best connections to primary and secondary conductors. 
2. The Licensee shall incorporate the following in its construction design standards: 
   1. Use of Wasp conductor/copper conductor Jumpers for transformers up to capacity of 100 kVA. 
   2. Use of double WASP Conductor jumpers for 200 kVA

Transformer. 

1. Use of P.G. connectors for joining the jumpers to line. 
2. Use of special compression lugs/Thimbles to join the jumpers to transformer bushings. 

The Licensee shall specify that distribution transformers are provided with lugs on transformers bushings.  

SC 3.5Proper Construction Techniques

The construction quality shall be improved by adopting proper construction techniques; including. 

The use of shovel for structure pit digging and auger for PCC poles. 

The use of Rollers on every pole for Stringing of Conductors. The use of Sag Charts and Tension Meters for proper sags. 

Stay wire shall be affixed to the pole at a 45-degree angle to provide the maximum strength to the pole or at appropriate angle depending upon the site location, and condition. 

SC 3.6Affixing of Hardware

The pole framing to install Hardware, Cross arms, Insulators shall be affixed to the pole while it is still lying on ground and then erect it, so that labour time can be saved. 

The Licensee Engineer shall prepare a site plan before starting a job, stating the requirement of shut downs, transport, Tools and Plant, work force and the material needed for the job, and shall arrange them before starting work at site. 

ÑÑÑEnd of SCÒÒÒ

SYSTEM PERFORMANCE, RELIABILITY 

AND CONSUMER SERVICE REQUIREMENTS

CONTENTS 

SPR 1           SYSTEM OPERATION                                                                      SPR-90

SPR 2           POWER-FREQUENCY VOLTAGE VARIATIONS                                   SPR-91

SPR 3           OPERATIONAL CONSTRAINTS                                                         SPR-92

SPR 4            HOTLINE WORKING TOOLS, TRAINING AND TESTING                       SPR-92

SPR 5           MANAGEMENT OF OUTAGE PLANS                                                   SPR-92

SPR 6           LOAD DISPATCH CENTRE                                                                SPR-93

SPR 7           UNPLANNED INTERRUPTIONS                                                        SPR-94

 SYSTEM PERFORMANCE, RELIABILITY  AND CONSUMER SERVICE REQUIREMENTS

Licensee shall monitor the distribution system loads and assure that the following system capacity and loading guidelines are followed:  

SPR 1.1.2.1   Equipment Loading Criteria

1. Conductor Loading

The capacity of a feeder is a function of the feeder length and the distribution of the loads along the feeder. The purpose of establishing current carrying capacity criteria for planning is to initiate the planner to review a feeder that may be in violation based on existing as well as forecasted load. 

1. The loading limits of all the distribution facilities of the lines and grid station should be in accordance with IEC Standard, manufacturer recommendation with due regard to ambient temperature conditions.  

SPR 1.1.5      Voltage Monitoring and Control and Load Balancing

Voltage monitoring at each 132/66/33/11 kV Sub-station shall be carried out by data logging. 

Voltage monitoring on the secondary side of 33/0.4kV and 11/0.4kV distribution transformers shall be carried out at least once in one year during Peak Load hours to cover at least two nos. of transformers on each 11KV feeder as follows: 

1. One transformer towards the beginning of the feeder 
2. One transformer towards the end of the feeder 

The load on each phase shall be kept equal to the maximum possible extent. 

Improvement to voltage conditions can be achieved by but not limited to the following action: - 

1. Providing proper earthing of the transformer. Proper earth connection may result in proper voltage at consumer premises. 
2. The load on the LT feeders must be kept balanced as far as possible. 
3. Unbalance load cause heavy voltage drops in the overloaded phases. 
4. Adjusting/shifting consumers on adjacent transformers to reduce the length of LT radial line from the transformer as for as possible. 
5. To bring in circuit all fixed disconnected 11kV capacitors installed on the feeders. 
6. Bybifurcating the existing 11kV feeders. 
7. By augmenting the existing 11kV conductor. 
8. By providing 11kV voltage regulators on the feeders. 

1. Pre-arrangedshut down for maintenance of lines and grid stations should be avoided during the months of May to August as far as possible and to co-ordinate with other utility (telephone, cable, gas) officials. 
2. Pre-arranged shut down must not be allowed during the peak load hours. 
3. Communication between the system operator and grid station staff (especially carrier system) must be maintained and kept in working order all the times. 
4. Availability of transport in working order all the time with adequate maintenance and operation staff alongwith necessary tools and service equipment. 
5. Availability of material and proper T & P with the maintenance and operation staff to attend emergency. 
6. To properly schedule preventive maintenance of the lines and grid stations. 
7. Availability of telephone attendant in complaint offices with the telephone in working order all the times. 
8. To provide mobile telephones or wireless set to the complaints attendant and maintenance staff. 
9. Establishing the training centers in the field to train the line staff in operation, maintenance and construction of distribution system. 

ÑÑÑEnd of SPRÒÒÒ

METERING REQUIREMENTS 

CONTENT 

MR 1             INTRODUCTION                                                                   MR-95

MR 2             PURPOSE                                                                             MR-95

MR 3             LOCATION OF METERING POINT                                            MR-95

MR 4             TEMPER AND REVENUE PROTECTION                                  MR-95 

MR 5             APPLICATION                                                                      MR-96

MR 6             SUBSTATION METERING REQUIREMENTS                             MR-96 

MR 7             STANDARDS                                                                         MR-96

MR 8             PERFORMANCE REQUIREMENTS                                         MR-97

MR 9             TESTING AND CALIBRATION                                                MR-100 

i

METERING REQUIREMENTS 

Metering shall provide accurate measurement of electrical quantities delivered to or received from the electric transmission, sub-transmission, and distribution network. Metering devices including all instrument transformers shall be revenue class with facilities for measuring, active and reactive energies, peak demand, power factor, etc. that are required for billing, planning and engineering purposes. Metered quantities shall be remotely transmitted via SCADA system (whenever available) and recorded in the metering database at Licensee computer center.  

Metering facility shall be provided at the connection points between Users and Licensee to record energy and active power (KW) delivered or consumed for the purpose of billing, engineering studies and planning. Metering shall provide measurements of energy and power delivered at the point of connections between the Generators and other Users. Metering data shall be made available to all Users. 

Metering devices and instrument transformers for revenue metering must comply with the latest applicable international and local standards, including but are not limited to the following. 

• IEC 60145 Var-hour (reactive energy) meters 
• IEC 60521 Class           0.5,       1          and      2          alternating-current         watt-hour                                   meters
• IEC 60687 Alternating   current static     watt-hour          meters for                                 active energy (classes 0.2 S and 0.5 S). 
• IEC 61036 Alternating   current static     watt-hour          meters for                                 active energy (classes 1 & 2). 
• IEC 61107 Data            exchange          for        meter   reading,             tariff      and       load                             control - direct local data exchange. 
• IEC 61354 Electricity     meters –          marking            of         auxiliary            terminals                                   for tariff devices 
• IEC 61361 Electricity     metering            –          local     and       remotedata 

• IEC 60186 Voltage transformers 

MR 8             PERFORMANCE REQUIREMENTS 

Revenue metering and ancillary equipment shall read energy and power delivered to or received from the electric transmission with an appropriate degree of accuracy, but not less than +/- 0.2* %. Revenue class metering shall have the following characteristics; 

*        As per PEPCO’s comments on Grid Code vide No. 3935-48 / Technical Director/86 dated 16.02.2005. 

• Threephase four-wire and three phase three wire configuration, electronic, digital, with accuracy class of 0.2 from 0% to 100% of full scale is standard. 
• Meters shall be capable of measuring and recording active and reactive power, phase currents and phase voltages at 30minute intervals for a period of 70 days, with intervals programmable from 1 minute to 2 hours. 
• The meter shall have the capability of recording active and reactive energy and maximum demand for the entire billing period. The meter billing period shall be programmable and can be programmed to automatically store the accumulated value and reset the counter for the next billing period. 
• Multiplier corresponding to the combination of CT and PT ratios shall be programmable in the meter. Accuracy class of CT and PT shall be in accordance with applicable DISCOs technical specifications.  
• Meters shall be capable of time of use and seasonal applications. Meters shall have internal time clock for time and date stamping of data. Time clock shall  have high accuracy and shall synchronize to GPS time signals. 
• Meters shall have provisions for remote meter reading by telemetering or by SCADA. Communication portsshall be provided for optical and serial data communication with industry standard protocol support. 
• Meter shall have self-diagnostic capability and includes an alarm to indicate failure and/or tampering. 

‘ 

                     a)       Installation

Installation of revenue meter and ancillary equipment at the substation for the point of connection shall be the Generator and other Users’ responsibility. The Generators and other User connecting to the Licensee's network shall submit to the Licensee for approval the engineering design for revenue metering, proposed location of metering equipment and ancillaries complete with wiring and installation drawings and bill of materials. The proposed metering location shall be adjacent to any telemetring, communication and data logging equipment. 

Revenue metering and ancillary devices shall be provided in secured metal enclosure. Enclosure shall have doors with locks for easy access. Glass window shall be provided on the door to allow visual reading of the meter inside the enclosure. Instrument transformers shall be installed in secured location and shall be dedicated and not be shared with protection or other metering devices, to prevent tampering. All wiring between the instrument transformer outside the metering compartment shall be installed in rigid galvanized steel conduits. Meter shall be located where it is accessible for reading the registers and for testing and maintenance.  

                     b)       Access 

Each User shall grant the Licensee right to enter upon and pass through and remain upon any part of such User’s property to the extent necessary for the purpose of performance of obligation under this Code. 

The right of access provided for under this code includes the right to bring on to such User property such vehicles, plant machinery and maintenance or other materials as shall be necessary for the purpose of performance of obligation under this Code. 

Each User shall procure that all reasonable arrangements and provisions are made and/or revised from time to time as when necessary or desirable to facilitate the safe exercise of his right of access. 

                     c)       Telemetering (Data Collection System) 

Facilities are to be provided by the User for remote transmission of metering information to the Licensee to be recorded in the metering database. Transmission of telemetered data information must be secure and reliable and not prone to tempering. All metered quantities including times and date of acquisition must be telemetered. Quantities that are to be metered shall include: 

• Apparent energy 
• Real energy  
• Energy (KWh or MWh) delivered to load 
• Energy (KWh or MWh) received from supply 
• Reactive energy (KVArh or MVArh) 
• Peak demand MW or kW •          Peak MVAr or kVAR demand  
• Power Factor. 

Metering database is to be provided at the DISCO Headquarters or Distribution Control Center location. Database will have metered quantities, meter information, metering constants, instrument transformer ratios, etc. Information in the data base computer will be accessible to for billing, engineering studies and planning. 

The communication protocol for transmitting metering information shall be in accordance with IEC 61107. 

ÑÑÑEnd of Metering RequirementsÒÒÒ

PROTECTION REQUIREMENTS 

CONTENT 

                    PR 1             PROTECTION SYSTEM PRACTICES AND  

                                        SYSTEM CO-ORDINATION                                                     PR-102     

                    PR 2              SYSTEM PROTECTION OPERATION                                       PR-102

                    PR 3              POWER-FREQUENCY VOLTAGE VARIATIONS                        PR-103

                    PR 4              PROTECTION COORDINATION WITH NTDC AT 132 kV            PR-103

                    PR 5              STANDARDS AND PRACTICES                                               PR-104

                    PR 6              SUBSTATION PROTECTION                                                   PR-104

                    PR 7              TESTING, CALIBRATION AND MAINTENANCE                         PR-105

                    PR 8              CONTROL AND SWITCHING COORDINATION                         PR-105

                    PR 9              INSULATION CO-ORDINATION REQUIREMENTS                     PR-106

PROTECTION REQUIREMENTS 

                    PR 1             PROTECTION SYSTEM PRACTICES AND SYSTEM CO-ORDINATION 

  The Licensee shall follow suitable and necessary provisions regarding protection system practices and co-ordination such as the following but not limited to achieve the aims of proper functioning of the distribution system of the Licensee at all times: 

1. Protection co-ordination of distribution system, sub-transmission system and system upto the metering point of the User (wherever applicable).  
2. Intentions to protect the Licensees lines, sub-station facility and equipment against the effects of faults. 
3. Achievement of co-ordination with protection systems at the NTDC Transmission level and other Distribution Companies. 
4. Provision for the disconnection of all faulted items from the power system in a timely manner as specified in PMC 2.2 of the Grid Code. 
5. Protection schemes designed to cope with single element, double element failure or stuck breaker condition and to maintain proper equipment protection. 
6. Minimization of loss of power supply of distribution system following protection operation and chances of inadvertent operation. 
7. Supply the distribution system protection scheme data of Licensee to the User and NTDC upon request 
8. Provide protective earthing devices. 
9. Replace the mechanical relays with digital equipment over a period of time, co-ordinated with NTDC. 

The protection relays shall be in accordance with the IEC Standard No. 255, and IEC 60255 (Protective Relays) 

                    PR 2             SYSTEM PROTECTION OPERATION 

 The Licensee shall plan, design, co-ordinate with NTDC, procure, install, operate and maintain its requisite protection systems and submit the pertinent information to NTDC in the form and manner as determined by the Grid Code at least once a year. 

A Licensee shall use the protection systems for its network, in coordination with NTDC, which shall cover the following types of protection at 132kV and 66kV sub-station. 

(i)           Bus bar protection (differential relay) 

(ii)          Transformer protection (differential relay, Buchholz relay, low oil relay, winding temperature rise relays, over-current relay, earth fault, and pressure relief on HV/LV sides. 

1. For faults on the User’s substation equipment directly connected to the sub-transmission network of the Licensee and for faults on the sub-transmission network of the Licensee directly connected to the User’s substation equipment, fault clearance period from fault inception to circuit breaker arc extinction duly co-ordinated with NTDC shall be set out in the Transmission Service or Connection Agreement duly coordinated with NTDC.  
2. All fault clearing times shall be specified by the Licensee and approved by the NTDC except for the connection point where NTDC is required to specify. 
3. In the event the primary or main protection system fails to meet the fault clearance times listed above, a back up or secondary protection system shall be provided. Back-up protection shall be coordinated with the primary protection so as to provide discrimination. 
4. Circuit breakers provided at the point of connection between the User's substation and the transmission network shall be provided with breaker failure protection. In the event the breaker fails to operate, the breaker failure protection will initiate tripping of all the electrically adjacent circuit breakers within the time limit approved by NTDC. 

Additional protection may be required by NTDC as per the provisions of the Grid Code. 

 For the purpose of connecting and disconnecting a generating unit and/or User’s substation from the 132 kV sub-transmission network it is essential that the necessary equipment be provided. This equipment shall include, but not limited to the following: 

1. In conjunction with the protection system, circuit breakers shall be provided at the connection point between the User and the transmission network. The circuit breaker shall have the proper voltage ratings, short circuit current rating and continuous current rating. Rating shall be submitted to NTDC for approval. 
2. Control panels for circuit breakers, disconnecting switches and protection system shall be provided at the connection point. SCADA connections for monitoring and control of circuit breakers, disconnecting switches, metering and protection devices.  
3. Disconnecting switches shall be provided for isolating circuit breaker for maintenance. Disconnecting switches shall be no-load break type and have the same voltage, continuous current and fault closing current capability as the circuit breaker. 
4. Disconnecting switches shall be provided for isolating transformers in the substation for maintenance. Disconnecting switches shall have wiper to prevent arcing when energizing the transformer. Disconnecting switches shall be no-load break type and have the 

same voltage, continuous current and fault closing current capability as the circuit breaker. 

1. Grounding switches shall be furnished to ground the bus bars and transmission line for maintenance. 

Disconnecting and grounding switches shall be motor-operated and shall permit remote operation and interlocking with other switching devices. Control and electrical interlock for disconnecting and grounding switches shall be provided in the control panel. Control shall have interface with SCADA for remote control and monitoring of the disconnecting and grounding switches. 

1. Switching Procedures

All switching activities performed at the connection point between the Licensee and User system shall be performed under the direction of the Licensee (system operator). All other switching activities in the Users system shall be coordinated with the Licensee. Proper communication and tagging procedure shall be observed to prevent accidents and damage to equipment involved in the switching operation.  

1. Testing and Maintenance of Control Facilities  

Control and switching shall be scheduled once a year or as per manufacturer's recommendations for testing and maintenance. Adjustments in protection system and control will be made at this time if necessary. Equipment found to be defective shall be repaired or replaced, accordingly. Testing and maintenance will be coordinated with Licensee and NTDC. Tests, calibration, repair and replacement of equipment shall be recorded and distributed to all concerned parties. 

1. Monitoring

The Licensee shall provide RTUs for remote monitoring of its 132kV facilities. 

                    PR 9              INSULATION CO-ORDINATION REQUIREMENTS 

  The protection system shall be developed with the co-ordination of NTDC and in accordance with relevant design and equipment standards.  

ÑÑÑEnd of PRÒÒÒ

SYSTEM MAINTENANCE AND TESTING 

CONTENT 

                    SMT 1           MAINTENANCE REQUIREMENTS                                                           SMT-108

                    SMT 2           MAINTENANCE STRATEGIE                                                                   SMT-110

                    SMT 3           ON-LINE TESTING AND PREVENTATIVE MAINTENANCE                         SMT-110

                    SMT 4           OFF LINE PREVENTIVE MAINTENANCE AND TESTING                           SMT-110

SYSTEM MAINTENANCE AND TESTING 

The Licensee shall assure that proper tools and spares are available at all work places for carrying out maintenance and testing. 

Licensee shall provide a training center for imparting training to Licensee’s workmen corresponding to the following categories/aspects. a.            Maintenance Strategies 

1. On-line testing and preventive maintenancewhere applicable. 
2. Off-line testing and preventive maintenance where applicable. 
3. Testing and Maintenance of Grid Station equipment, and use of T&P. 
4. Construction of 33kV/11kV/0.4kV lines and installation of distribution transformers 
5. Safety 

The training shall incorporate but not limited to the following procedures and techniques.  

1. Lines  

• 132kV line feeding the DISCOs should be looked after by the DISCO to the fed by the line. 

1. Grid Stations

• Operating mechanism of different types of circuit breakers i.e. (ACB, VCB and OCB) 
• Testing of circuit breakers with respect to contact resistance, opening/closing timings, oil testing, insulation testing of vacuum interrupter in case of VCB. 
• Testing of the power transformers current transformers with respect to capacitance and dissipation factor (C & DF), oil testing. 
• Grid station battery operation and maintenance with respect to specific gravity, voltage, float charge volt/cell, boost charge volt/cell, end of discharge voltage cell at 10 Hrs. rate. 
• Procedure and use of different types of protective relays, used on transmission lines and grid stations. 

1. Construction

• Distribution transformer installation. 
• Consumer's overhead and underground service connection. 
• Installation and connection of different types of energy meters. 
• Grounding of electrical equipment. 
• Construction techniques including; 

(i)           Use of shovel and auger for pit digging 

(ii)          Use of rollers on every pole for stringing of conductor 

(iii)        Use of sag charts for proper sag 

(iv)        Fixing of stay wire to the pole 

(v)         Erection and foundation of pole/structure 

(vi)        Fixing of hardware to the pole/structure 

1. Use of Testing Equipment and Tools

Procedure and use of different types of testing equipment and tools used in the maintenance of the system. 

1. Safety

Awareness and implementation of safety code management. 

The Licensee shall arrange off-line preventative maintenance and testing of its system. An annual plan of maintenance and testing including lines and sub-stations shall be prepared by the Licensee which should further be broken down into monthly schedules. The chapter should layout the procedures and schedules for lines, and sub-stations which must cover the following points: - 

1. the procedure and schedule of patrolling the transmission and 

distribution lines; 

1. preparation and submission of patrolling reportsby the field staff; 
2. the points which need to be noted during patrolling;  
3. scheduling shut-down to attend the major problems, if any 

encountered during the patrolling report; 

1. in case of sub-station the schedule of maintenance and testing should be prepared on the basis of manufacturer's recommendation for different equipments which may be on daily basis, monthly basis, half yearly basis, yearly basis and five yearly basis; 
2. the detail of maintenance and testing which is required to be carried out on each equipment should be prescribed with schedule; 
3. oil dielectric tests for transformers, breakers and other oil filled distribution apparatus; 
4. test equipment to perform insulation resistance tests, C & DF test, voltage withstand tests opening/closing timings of the breakers, contact resistance of the breakers etc. should be arranged and provided;  
5. earthing test equipment and meggers shall be provided for field testing of earthing systems at substations, structures, poles, distribution transformers, and at consumer connections; and    j. cleaning/washing of insulators on the lines and sub-stations, specially in polluted area. 

                    SMT 4.1         Listing T & P

The chapter should also prescribe the list of required standard, testing equipment and tools which are to be used by the Licensee during maintenance, and breakdowns. 

ÑÑÑEnd of SMTÒÒÒ

SAFETY REQUIREMENTS 

CONTENTS 

                    SR 1              INTRODUCTION                                                                   SR-113

                    SR 2              OBJECTIVES                                                                         SR-113

                    SR 3              SCOPE                                                                                 SR-113

                    SR 4              SAFETY MANAGEMENT CRITERIA                                          SR-113

                    SR 5             PROCEDURES                                                                       SR-114

                    SR 6              SAFETY AT THE LICENSEE / USER INTERFACE                     SR-115 

                    SR 7             PUBLIC AND PROPERTY SAFEGUARD                                   SR-115

 i

i

 SAFETY REQUIREMENTS 

                    SR 1              INTRODUCTION 

  The Licensee shall abide by the Safety Requirements of its "Power Safety Code" as published by distribution company and approved by NEPRA. This code presents safety instructions for the electrical works concerning construction, installation, operation and maintenance of electric supply lines and grid station facilities. The Licensee shall also abide by the Safety requirements as per NEPRA Regulation of Generation, Transmission and Distribution of Electric Power Act (XL of 1997), and safety standards established in the Consumer Service Manual, Consumer Eligibility Criteria and Distribution Performance Standards Rules.  

                    SR 2              OBJECTIVES 

  To lay down the safety management criteria to be applied to ensure safety of persons working on the Distribution System and at or across operational and Ownership Boundaries, general public and animals. 

                    SR 3              SCOPE 

  Each Licensee shall develop its Safety Manual in accordance with the requirements of the established instructions presented in the ”Power Safety Code” as published by Distribution Company and approved by NEPRA, and implement the same.  

  Similar Criteria and Standards of Safety Management Systems shall be provided by other Users of the Distribution System and approved by the Licensee when carrying out work or tests at the operational interface with the Licensee.  

                    SR 4              SAFETY MANAGEMENT CRITERIA  

1. All distribution facilities of a distribution company shall be constructed, operated, controlled and maintained in a manner consistent with the Distribution Code, Power Safety Code, Consumer Service Manual, Performance Standards (Distribution) and other applicable documents.  
2. A distribution company shall ensure that its distribution facilities do not cause any leakage of Electrical Current or Step Potential beyond a level that can cause harm to human life, as laid down in the relevant IEEE/IEC Standards; prevent accessibility of live conductors or equipment; and prevent development of a situation due to breakdown of equipment which results in voltage or leakage current that can cause harm to human life, property and general public including without limitation, employees and property of the distribution company. 
3. A distribution company shall implement suitable, necessary, and appropriate rules, regulations and working practices, as outlined in its Distribution Code or applicable documents, to ensure the safety of its staff and members of the public. This shall also include suitable training for familiarity and understanding of the rules, regulations, practices, and training to use any special equipment that may be required for such purposes including without limitation basic first aid training. 

                    The Safety Management criteria that applies to the Licensee and the following Users of the Distribution System: a.        Embedded Generators. 

1. Bulk Power Customers 
2. Other Distribution Companies 
3. Independent Generators 
4. SHYDO, KESC 
5. Any other party reasonably specified by the Licensee including Users connected at 132 kV/ 11 kV/ 0.4 kV for appropriate sections when necessary. 
6. Agents of the Licensee or Users working on the Distribution System or at or across operational boundaries. 

                    SR 5              PROCEDURES 

  The Safety Manual will present the principles, guidelines, and procedures (Safety Management System) for ensuring safety of all relevant personnel of the Licensee and Users for work on their respective Systems or Plant or Apparatus connected to them. 

  There shall be joint agreement by the Licensee and Users on which Safety Management System is to be used for sites or locations where an operational boundary exists and proper documentation of the safety precautions to be taken shall be maintained.  

  There shall be written authorization of personnel who do the work of control, operation, work or testing of Plant or Apparatus forming part of or connected to the Distribution System of the Licensee. 

  There shall be joint agreement between the Licensee and Users which specifies responsibility for system or control equipment which shall ensure that only one party is responsible for any item of plant or apparatus at any one time. 

  The Licensee and each User shall at all times have nominated a person or persons responsible for the co-ordination of safety on the respective systems. 

  The Licensee and each User shall maintain a suitable system of documentation which records all relevant operational events that have taken place on the Distribution System or other System connected to it and the coordination of relevant safety precautions for work. 

  System diagrams which show sufficient information for control personnel to carry out their duties shall be exchanged between the Licensee and User as required. 

1. When work is conducted along public streets or highways, pedestrian and vehicular traffic shall be warned in compliance with applicable standards. 
2. Where necessary, open manholes, ditches and excavations shall be barricaded or be substantially covered to prevent pedestrians, animals or vehicles from falling into them. 
3. During the night and in all dark locations, lights or torches should be in place at any obstruction, excavation or opening which is likely to cause injury to workers or public. 
4. When working on customers’ premises or public property, every effort shall be made by Licensee staff to avoid hazards to customers or public and their property. Tools, excess material, and scrap shall be removed when the job is completed. 
5. No Licensee's employee shall smoke or use matches or open flames on customers’ premises unless it is positively known ‘that such action does not conflict with the customers’ rules, wishes and safety. 
6. Walks, aisles, stairways, fire escapes and all other passageways shall be kept clear of all obstructions. 
7. Any floor or wall opening shall be guarded with standard railings and toe boards. Other means of temporary protection may be used only with an observer present. 
8. Tools and plant shall not be placed where they may cause tripping or stumbling hazards, or where they may fall and strike anyone below. 
9. Adequate measures shall be taken to overcome slipping hazards, which may exist. 
10. Nails in boards, such as those removed from scaffolds, forms and packing boxes shall be removed. The boards shall be carefully stacked or stored. 
11. Nails that have been driven into barrels or tins to secure the head shall be removed when the head is removed. 
12. Work areas and vehicles shall be neat and orderly at all times. 
13. Scrap bins (dust bins) shall be provided and used for broken glass, insulators, sheet metal scraps, used pressurized containers and other waste material. 

ÑÑÑEnd of Safety RequirementsÒÒÒ

PUBLIC LIGHTING

CONTENT 

                                         PUBLIC LIGHTING                                                                     PL 118 

 PUBLIC LIGHTING 

PL 1.1           The licensee shall provide distribution facilities for public lighting within its distribution        territory.                    Maintenance/operation   and       replacement      of lamps/fixtures shall be carried out by the licensee at mutually agreed terms and conditions with the relevant local body desirous of establishing a public lighting system.   

PL 1.2           construction of the public lighting in the territory of the licensee shall also be governed under a mutual agreement between the licensee and the relevant local body. 

EMERGENCY PLANS AND LOAD SHEDDING 

CONTENTS 

                    EPL1           BREAKDOWNS AND EMERGENCY PROCEDURES                  EPL-120

                    EPL2            LOAD SHEDDING                                                                  EPL-120

                    EPL3            LICENSEE'S OBLIGATION                                                       EPL-121

 EMERGENCY PLANS AND LOAD SHEDDING 

A Licensee shall have plans and schedules available to shed up to a maximum of 30% of its connected load at any time upon instruction from NTDC. However, the amount of load that may be shed by the Licensee under particular emergency system conditions shall be equal to its allocation, as determined by NTDC, based on the Licensee’s peak load demand in relation to the Total System Peak Demand of NTDC. This 30% load must be made up from separate blocks of switchable load, which can be immediately either automatically or manually disconnected in turn at the instruction from NTDC. A Licensee shall provide copies of these plans to NTDC as per the requirements of Performance Standards (Distribution).  

Wherever possible NTDC shall give Licensee advance warning of impending need for load shedding to maintain system voltage and/or frequency in accordance with the Grid Code. 

As per the provisions of the Grid Code, and Performance Standards (Distribution) NTDC shall maintain an overview and as required instruct each Licensee the quantum of load to be disconnected and the time of such disconnection. This instruction shall be given in clear, unambiguous terms and related to prepared plans. 

When instructed by NTDC, the distribution companies shall shed the load in the following order: 

1. Supply to consumers in rural areas; and residential consumers in urban areas where separate feeders exists. 
2. Supply to consumers, other than industrial, in urban areas. 
3. Supply to agriculture consumers where there is a dedicated power supply. 
4. Supply to industrial consumers. 
5. Supply to schools and hospitals. 
6. Supply to defense/strategic installations. 

A Licensee shall prepare schedules of load disconnection, which demonstrate this priority order and which rotate load disconnection within the above groups in a non-discriminatory manner. The principle of proportionality shall be kept in mind so as not to excessively burden a particular consumer class. 

                    EPL 3            LICENSEE'S OBLIGATIONS 

  The Licensee shall establish procedures for restoring the supply after emergency breakdowns consistent with Grid and Distribution Code.  

 Licensee shall interact with NTDC, in case of black start and shall follow NTDC instructions for restoration of supply.  

  Each Licensee shall abide by the requirements of the system restoration plan prepared by NTDC and shall ensure that its personnel are familiar with, and are trained and experienced in their standing instructions and obligations to implement the required emergency restorations procedure. 

  The power supply in a post emergency state is to be restored under the instructions of NTDC in reverse sequence that outlined in the clause 7 of the Performance Standards (Distribution) approved by NEPRA. 

Note: KESC shall plan its own emergency plan and load shedding consistent with the order of priority provided in the Performance Standards (Distribution) and Distribution Code. 

ÑÑÑEnd of EPLÒÒÒ

PROVISION OF INFORMATION 

CONTENTS 

                    PI 1               REQUIREMENTS                                                                   PI-123

                    PI 2               LICENSEE'S OBLIGATIONS                                                     PI-123

                    PI 3               ANNUAL SYSTEM PERFORMANCE REPORT                           PI-123

                    PI 4               CONFIDENTIALITY                                                                  PI-123

PROVISION OF INFORMATION 

ÑÑÑEnd of PIÒÒÒ

DISTRIBUTION DATA REGISTRATION CODE 

CONTENTS 

                    DDRC 1        INTRODUCTION, OBJECTIVE & SCOPE                                   DDRC-125

DDRC 2          DATA CATEGORIES                                                                       DDRC-125 

                    DDRC 3        PROCEDURES AND RESPONSIBILITIES                                  DDRC-126

                    DDRC 4        DATA TO BE REGISTERED                                                      DDRC-127

i

i

 DISTRIBUTION DATA REGISTRATION CODE 

DDRC 3.6.1 Licensee shall advise a User in writing of any estimated data it intends to use pursuant to DDRC 3.6 relating directly to that User's facility in the event of data not being supplied. 

DDRC 3.6.2 A User shall advise Licensee in writing of any estimated data it intends to use pursuant to DDRC 3.6 in the event of data not being supplied. 

DDRC 3.6.3 In the event the required data is not supplied or is incomplete or in-accurate by the User, the Licensee shall refer the matter to the "Review Pannel" which shall issue necessary instructions to the defaulted party in writing. 

 Failure to obtain/supply the required data within the specified timeframe from/by the defaulted party, the Licensee shall consider the matter as a violation of the Distribution Code provision. Suitable measures regarding 

Distribution code non-compliance are covered in CM 16 of this Distribution Code. 

ÑÑÑEnd of DDRCÒÒÒ

i

i i COMPETITION IN THE SUPPLY OF ELECTRIC POWER 

CONTENTS 

                                         COMPETITION IN THE SUPPLY OF ELECTRIC POWER           CSE-129 

COMPETITION IN THE SUPPLY OF ELECTRIC POWER 

The following provisions need to be included in this Sub-Code. a.            Use-of-system charges 

1. Provision of Services to Bulk Power Consumers notreceiving power from the distribution company. 
2. Supply to consumers within the Concessional Territory 
3. Supply to consumers to the Housing Colonies. 
4. Supply to consumers to Defence Establishments. 

Supply to Non-native Bulk Power Consumers

The Licensee shall offer power supply connection services to all the BPCs within its Service Territory regardless of their choice of power supplier as per its obligations under NEPRA distribution licence and Section 22 of NEPRA Act. 

This obligation includes offering access to its distribution system to the Bulk Power Consumer either connected with the Licensee's/receiving power from the Licensee but wishing to switch its supplier other than the host distribution company OR a new Bulk Power Consumer already having a power contract with a supplier (other than the Licensee) and wishing to connect to the Licensee's network for power wheeling purposes. 

This obligation entails the following:- 

1. Providing service connection as per the provisions of Performance Standards (Distribution) – Rules 2005. 
2. Offering Metering, Billing, Consumer Services such as complaint handling. 
3. Offer of reasonable and approved use-of-system charges. 
4. Offer to enter into a connection contract on reasonable fair, consistent and approved terms and conditions regarding connection services, consumers services and rate and charges. 
5. Offer to comply with the relevant provisions of Consumer Eligibility Criteria, Distribution Code, Performance Standards (Distribution) Consumer Service Manual, Grid Code, approved Complaint Handling Procedures, Safety Code, if applicable, any other special conditions forming part of the Power Purchase Agreement of the Non-native Bulk Power Consumer. 

ÑÑÑEnd of CSEÒÒÒ

SCHEDULE AND APPENDIX 

CONTENTS

DOC 1  Appendix 1 DEMAND FORECASTS – OPERATIONAL PLANNING PHASE (8 weeks to 1 year ahead inclusive)          S&A          131 

 DOC 1 Appendix 2 ------------------------------------------------------------------------------------------------------------------------- 

DEMAND FORECASTS – PROGRAMMING PHASE (24 hours to 8 weeks ahead inclusive)          S&A132 

 DOC 1 Appendix 3 ------------------------------------------------------------------------------------------------------------------------- 

DEMAND FORECASTS – CONTROL PHASE (0 to 24 hours ahead)               S&A---------------------------- 133 

                    DOC 2          Appendix 1 

OUTAGE PLANNING  

OPERATIONAL PLANNING PHASE 

                                        MEDIUM TERM PROGRAMME                                                   S&A-134

                    DOC 2          Appendix 2 

OUTAGE PLANNING  

OPERATIONAL PLANNING PHASE 

                                        SHORT TERM PROGRAMME                                                     S&A-135 

                    DOC-5        Appendix-I 

Matters, if Applicable to the Significant Incident,  

to be included in a Written Report Given in  

                                        Accordance with DOC 5.2.2                                                         S&A-136 

                    DPC            Appendix-I 

SHUNT CAPACITOR INSTALLATION 

                                         (Useful Formula)                                                                        S&A-137

                    DDC            Appendix-I 

KVA-KM LOADING 

                                         (Sample Calculations)                                                                 S&A-138

                    PR                Appendix-I

                                        Publications found with ICS code.                                                 S&A-139

                    DDRC         Schedule No. 1

                                        GENERATING UNIT DATA                                                         S&A-156

                    DDRC          Schedule No. 2

                                         USERS SYSTEM DATA                                                              S&A-157

                    DDRC          Schedule No. 3 

DOC-1 

APPENDIX-1 

DEMAND FORECASTS – OPERATIONAL PLANNING PHASE 

(8 weeks to 1 year ahead inclusive) 

Forecast information for each of the next 1 year of: 

(a)         Date and Time of Annual NTDC System Maximum and 

Minimum Power Demand as notified by the NTDC. 

(b)         Hourly Maximum and Minimum Annual Power usage of distribution company with reference to Maximum and Minimum NTDC System demand at a specified date and time at each transmission connection point. 

(c)         Annual energy Forecast demand at annual average conditions of all the different categories of consumers connected to the distribution company's system. 

(d)         Maximum generation output in MW by all the embedded generating plants at a specified date and time of annual Peak Hours on NTDC's system. 

Where reference is made to ‘specified’ or ‘NTDC Demand’, the information shall be provided by the Licensee following the receipt of information provided by NTDC in accordance with OC2 of the Grid Code. 

DOC-1 

APPENDIX-2 

DEMAND FORECASTS – PROGRAMMING PHASE 

(24 hours to 8 weeks ahead inclusive) 

The following information shall be provided to the Licensee in the time scales specified in DOC1: 

(a)         Hourly operational schedule of each embedded generating unit whose output is more than 1 MW and is not subject to central dispatch. 

(b)         All the Bulk Power Consumers and other distribution companies connected to the licensee's system shall intimate to the licencee the specific date and time where the aggregate change in their load due to their operation is expected to be more than 1 MW. 

(c)         Any other relevant Demand forecast information reasonably required by the Licensee. 

DOC-1APPENDIX-3

DEMAND FORECASTS – CONTROL PHASE 

(0 to 24 hours ahead) 

The following information shall be supplied to the Licensee at reasonable times to be specified by the Licensee for the un-expired period covered by the Control Phase. 

(a) Intimation by all the embedded generating plants to the licencee in case the difference of their hourly output is more than 1 MW as compared to their schedule of generation already notified under DOC 1.3.3.3. 

(a) Intimation by all the Bulk Power Consumer to the licencee the detail of changes in the demand if such changes are more than 1 MW. 

DOC-2 

APPENDIX-1 

OUTAGE PLANNING 

OPERATIONAL PLANNING PHASE 

MEDIUM TERM PROGRAMME – Calendar Year – 1 – 2 Year ahead  

This appendix should be completed by Licensee in consultation with Users and 

Embedded Generators (not subject to central dispatch)  

DOC-2 

APPENDIX-2 

OUTAGE PLANNING 

OPERATIONAL PLANNING PHASE 

SHORT TERM PROGRAMME – Current Calendar year down to Programming 

Phase (8 Weeks) 

This appendix should be completed by Licensee in consultation with Users and 

Embedded Generators (not subject to central dispatch) 

DOC-5  

APPENDIX-I

MATTERS, IF APPLICABLE TO THE SIGNIFICANT INCIDENT, TO BE INCLUDED IN A WRITTEN REPORT GIVEN IN ACCORDANCE WITH DOC 5.2.2 

Applicable to Licensee and Embedded Generator 

1              Time and date of Significant Incident; 

2              Location; 

3              Facility involved; 

4              Brief description of the Significant Incident; and 

5              Details of any Demand Control undertaken. 

Applicable to Licensee: 

(a)       duration of incident and corrective actions taken; 

(b)       estimated date and time of return to normal service. 

Applicable to Embedded Generator: 

6              Effect on generation including, where appropriate: 

(a)       MW of generation interrupted; 

(b)       frequency response achieved; 

(c)       MVAr performance achieved; and 

(d)       estimated date and time of return to normal service. 

DPC 

APPENDIX-I 

SHUNT CAPACITOR INSTALLATION 

(Useful Formulae) 

                    1.        CAPACITOR REQUIRED 

                             KVAR = KVA1 (Sin ∅1 – [Cos ∅1 / Cos ∅2] Sin ∅2) 

Where KVAR is: Amount of capacitance to be added to improve the Power Factor from Cos ∅1 to Cos ∅2. 

KVA1 is: Original kVA. 

                    2.        OPTIMUM LOCATION OF CAPACITORS 

                                         L                   =        [1– (KVARC / 2 KVARL) x (2n–1)] 

                              Where,

                                         L                  =        distance in per unit along the line from sub-station 

      KVARC=          Size of capacitor bank     KVARL =           KVAR loading of line 

 n                    = relative position of capacitor bank along the feeder from sub-station if the total capacitance is to be divided into more than one Bank along the line. If all capacitance is put in one Bank then values of n=1. 

                              3.        VOLTAGE RISE DUE TO CAPACITOR INSTALLATION 

% Rise = (KVARC.X) / 10V2 

Where, 

                               X        = Reactance per phase 

                               V        = Phase to phase voltage in kilovolts 

DDC 

APPENDIX-1 

* Appropriate values may be taken for any other temperature and equivalent spacing. 

                    2.        ASSUMPTIONS 

    Length of Line ……………………………………       1 KM    kVA Loading ……………………………………..       1000 kVA     3 Phase Voltage …………………………………       11,000 V 

                    3.        REGULATION 

                             Percent Regulation (approx.) = {I (R Cos ∅+ X sine ∅)/E}x100 

                              Where

                              I        = Current per phase in amp 

                              R       = Resistance per phase in ohms 

                              X       = Reactance per phase in ohms 

                              Cos∅= Power Factor 

                              E       = Phase-Neutral voltage in volts 

                              Percent Regulation =           416.2 x (0.5449x0.8+0.421x0.60          x100 = 4.44%

                                                                                                6451                            

For 1% Voltage Regulation the KVA-KM loading for the selected conductor size at 0.8PF will be 1912 KVA-KM. For any other Power Factor, voltage and conductor temperature the Voltage Regulation may be calculated by substituting appropriate values of current, Resistance Cos ∅and Sine ∅in the formula. 

PR 

APPENDIX-I

Publications found with ICS code: 

29.060.01 Electrical wires and cables in general 

                    29.060.01          IEC 60344 (1980-01)  

Guide to the calculation of resistance of plain and coated copper conductors of lowfrequency cables and wires 

                    29.060.01          IEC 60364-5-52 (1998-11) Ed. 1.1Consolidated Edition

Electrical installations of buildings - Part 5: Selection and erection of electrical equipment - 

Chapter 52: Wiring systems 

                    29.060.01          IEC 60364-5-523 (1999-02)

Electrical installations of buildings - Part 5: Selection and erection of electrical equipment - Section 523: Current-carrying capacities in wiring systems  

                    29.060.01          IEC 61084-1 (1991-07)  

Cable trunking and ducting systems for electrical installations - Part 1: General requirements 

29.060.01              IEC 61084-1-am1 (1993-10)Amendment No. 1 

                    29.060.01          IEC/TR2 61200-52 (1993-03)

Electrical installation guide - Part 52: Selection and erection of electrical equipment - Wiring systems 

Publications found with ICS code: 

29.120.50 Fuses and other overcurrent protection devices 

                    29.120.50          IEC 60050-441 (1984-01)  

International Electrotechnical Vocabulary. Switchgear, controlgear and fuses 

29.120.50  IEC 60050-441-am1 (2000-07)Amendment 1 

                    29.120.50          IEC 60050-448 (1995-12)  

International Electrotechnical Vocabulary - Chapter 448: Power system protection 

                    29.120.50          IEC 60099-1 (1999-12) Ed. 3.1Consolidated Edition

Surge arresters - Part 1: Non-linear resistor type gapped surge arresters for a.c. systems 

                    29.120.50          IEC 60099-4 (1998-08) Ed. 1.1Consolidated Edition

Surge arresters - Part 4: Metal-oxide surge arresters without gaps for a.c. systems 

                    29.120.50          IEC 60099-5 (2000-03) Ed. 1.1Consolidated Edition

Surge arresters - Part 5: Selection and application recommendations 

                    29.120.50          IEC 60127-4 (1996-08)  

Miniatures fuses - Part 4: Universal Modular Fuse-Links (UMF) 

                    29.120.50          IEC 60255-6 (1988-12)  

Electrical relays - Part 6: Measuring relays and protection equipment 

                    29.120.50          IEC/TR 60255-20 (1984-01)

Electrical relays. Part 20: Protection (protective) systems 

                    29.120.50          IEC 60269-2 (1986-09)  

Low-voltage fuses. Part 2: Supplementary requirements for fuses for use by authorized persons (fuses mainly for industrial application) 

                    29.120.50          IEC 60269-2-1 (2000-03) Ed. 3.1Consolidated Edition

Low-voltage fuses - Part 2-1: Supplementary requirements for fuses for use by authorized persons (fuses mainly for industrial application) - Sections I to V: Examples of types of standardized fuses 

                    29.120.50          IEC 60269-3 (1987-06)  

Low-voltage fuses. Part 3: Supplementary requirements for fuses for use by unskilled persons (fuses mainly for household and similar applications) 

                    29.120.50          IEC 60282-1 (1994-12)  

High-voltage fuses - Part 1: Current-limiting fuses 

29.120.50              IEC 60282-1 (1998-01) Ed. 4.2Consolidated EditionHigh-voltage fuses - Part 1: Current-limiting fuses 

29.120.50              IEC 60282-2 (1997-12) Ed. 2.1Consolidated EditionHigh-voltage fuses - Part 2: Expulsion fuses 

                    29.120.50          IEC 60282-3 (1976-01)  

High-voltage fuses. Part 3: Determination of short-circuit power factor for testing currentlimiting fuses and expulsion and similar fuses 

                    29.120.50          IEC 60291 (1969-01)  

Fuse definitions 

                    29.120.50          IEC 60364-4-42 (1980-01)  

Electrical installations of buildings. Part 4: Protection for safety. Chapter 42: Protection against thermal effects 

                    29.120.50          IEC 60364-4-43 (1977-01)  

Electrical installations of buildings. Part 4: Protection for safety. Chapter 43: Protection against overcurrent 

                    29.120.50          IEC 60364-4-45 (1984-12)  

Electrical installations of buildings. Part 4: Protection for safety. Chapter 45: Protection against undervoltage 

                    29.120.50          IEC 60364-4-46 (1981-01)  

Electrical installations of buildings. Part 4: Protection for safety. Chapter 46: Isolation and switching 

                    29.120.50          IEC 60364-4-473 (1999-03) Ed. 1.1Consolidated Edition

Electrical installations of buildings - Part 4: Protection for safety - Chapter 47: Application of protective measures for safety - Section 473: Measures of protection against overcurrent 

                    29.120.50          IEC 60549 (1976-01)  

High-voltage fuses for the external protection of shunt power capacitors 

                    29.120.50          IEC 60644 (1979-01)  

Specification for high-voltage fuse-links for motor circuit applications 

                    29.120.50          IEC/TR 60755 (1983-01)  

General requirements for residual current operated protective devices 

                    29.120.50          IEC 60787 (1983-01)  

Application guide for the selection of fuse-links of high-voltage fuses for transformer circuit application 

                    29.120.50          IEC 60931-3 (1996-08)  

Shunt capacitors of the non-self-healing type for AC power systems having a rated voltage up to and including 1000 V - Part 3: Internal fuses 

29.120.50              IEC 60934 (2000-10)  Circuit-breakers for equipment (CBE)  

                    29.120.50          IEC/TR3 61459 (1996-08)  

Coordination between fuses and contactors/motor-starters - Application guide 

Publications found with ICS code: 

29.120.70 Relays 

                    29.120.70          IEC 60050-446 (1983-01)  

International Electrotechnical Vocabulary. Electrical relays 

                    29.120.70          IEC 60255-3 (1989-06)  

Electrical relays - Part 3: Single input energizing quantity measuring relays with dependent or independent time 

                    29.120.70          IEC 60255-5 (2000-12)  

Electrical Relays - Part 5: Insulation coordination for measuring relays and protection equipment - Requirements and tests  

                    29.120.70          IEC 60255-6 (1988-12)  

Electrical relays - Part 6: Measuring relays and protection equipment 

                    29.120.70          IEC 60255-8 (1990-10)  

Electrical relays - Part 8: Thermal electrical relays 

                    29.120.70          IEC 60255-9 (1979-01)  

Electrical relays. Part 9: Dry reed make contact units 

                    29.120.70          IEC 60255-11 (1979-01)  

Electrical relays - Part 11: Interruptions to and alternating component (ripple) in d.c. auxiliary energizing quantity of measuring relays 

                    29.120.70          IEC 60255-12 (1980-01)  

Electrical relays - Part 12: Directional relays and power relays with two input energizing quantities 

                    29.120.70          IEC 60255-13 (1980-01)  

Electrical relays - Part 13: Biased (percentage) differential relays 

                    29.120.70          IEC 60255-14 (1981-01)  

Electrical relays. Part 14: Endurance tests for electrical relay contacts - Preferred values for contact loads 

                    29.120.70          IEC 60255-15 (1981-01)  

Electrical relays. Part 15: Endurance tests for electrical relay contacts - Specification for the characteristics of test equipment 

                    29.120.70          IEC 60255-16 (1982-01)  

Electrical relays - Part 16: Impedance measuring relays 

                    29.120.70          IEC 60255-19 (1983-01)  

Electrical relays. Part 19: Sectional specification: Electromechanical all-or-nothing relays of assessed quality 

                    29.120.70          IEC 60255-19-1 (1983-01)  

Electrical relays. Part 19: Blank detail specification: Electromechanical all-or-nothing relays of assessed quality - Test schedules 1, 2 and 3 

                    29.120.70          IEC/TR 60255-20 (1984-01)

Electrical relays. Part 20: Protection (protective) systems 

                    29.120.70          IEC 60255-21-1 (1988-09)  

Electrical relays - Part 21: Vibration, shock, bump and seismic tests on measuring relays and protection equipment - Section One: Vibration tests (sinusoidal) 

                    29.120.70          IEC 60255-21-2 (1988-10)  

Electrical relays - Part 21: Vibration, shock, bump and seismic tests on measuring relays and protection equipment - Section Two: Shock and bump tests 

                    29.120.70          IEC 60255-21-3 (1993-09)  

Electrical relays - Part 21: Vibration, shock, bump and seismic tests on measuring relays and protection equipment - Section 3: Seismic tests 

                    29.120.70          IEC 60255-22-1 (1988-05)  

Electrical relays - Part 22: Electrical disturbance tests for measuring relays and protection equipment - Part 1: 1 MHz burst disturbance tests 

                    29.120.70          IEC 60255-22-2 (1996-09)  

Electrical relays - Part 22: Electrical disturbance tests for measuring relays and protection equipment - Section 2: Electrostatic discharge tests 

                    29.120.70          IEC 60255-22-3 (2000-07)  

Electrical relays - Part 22-3: Electrical disturbance tests for measuring relays and protection equipment - Radiated electromagnetic field disturbance tests  

                    29.120.70          IEC 60255-22-4 (1992-03)  

Electrical relays - Part 22: Electrical disturbance tests for measuring relays and protection equipment - Section 4: Fast transient disturbance test 

                    29.120.70          IEC 60255-23 (1994-10)  

Electrical relays - Part 23: Contact performance 

                    29.120.70          IEC 60255-25 (2000-03)  

Electrical relays - Part 25: Electromagnetic emission tests for measuring relays and protection equipment 

                    29.120.70          IEC 61733-1 (1995-12)  

Measuring relays and protection equipment - Protection communication interfacing - Part 1: General 

                    29.120.70          IEC 61811-1 (1999-03)  

Electromechanical non-specified time all-or-nothing relays of assessed quality - Part 1: Generic specification  

                    29.120.70          IEC 61811-50 (1997-09)  

Electromechanical all-or-nothing relays - Part 50: Sectional specification: Electromechanical all-or-nothing telecom relays of assessed quality  

                    29.120.70          IEC 61811-51 (1997-10)  

Electromechanical all-or-nothing     relays    -           Part      51:        Blank   detail     specification      - Electromechanical all-or-nothing telecom relays of assessed quality - Non-standardized types and construction  

                    29.120.70          IEC 61811-52 (1997-10)  

Electromechanical all-or-nothing     relays    -           Part      52:        Blank   detail     specification      - Electromechanical all-or-nothing telecom relays of assessed quality - Two change-over contacts, 20 mm x 10 mm base  

                    29.120.70          IEC 61811-53 (1997-10)  

Electromechanical all-or-nothing     relays    -           Part      53:        Blank   detail     specification      - Electromechanical all-or-nothing telecom relays of assessed quality - Two change-over contacts, 14 mm x 9 mm base  

                    29.120.70          IEC 61811-54 (1997-10)  

Electromechanical all-or-nothing     relays    -           Part      54:        Blank   detail     specification      - Electromechanical all-or-nothing telecom relays of assessed quality - Two change-over contacts, 15 mm x 7,5 mm base  

                    29.120.70          IEC 61812-1 (1996-10)  

Specified time relays for industrial use - Part 1: Requirements and tests  

Publications found with ICS code: 

29.130.10 High voltage switchgear and control gear  

                    29.130.10          IEC 60056 (1987-03)  

High-voltage alternating-current circuit-breakers 

                    29.130.10          IEC 60129 (1984-01)  

Alternating current disconnectors and earthing switches 

                    29.130.10          IEC 60265-1 (1998-01)  

High-voltage switches - Part 1: Switches for rated voltages above 1 kV and less than 52 kV  

                    29.130.10          IEC 60265-2 (1988-03)  

High-voltage switches. Part 2: High-voltage switches for rated voltages of 52 kV and above 

                    29.130.10          IEC 60298 (1990-12)  

A.C. metal-enclosed switchgear and controlgear for rated voltages above 1 kV and up to and including 52 kV 

                    29.130.10          IEC 60420 (1990-10)  

High-voltage alternating current switch-fuse combinations 

                    29.130.10          IEC 60466 (1987-01)  

A.C. insulation-enclosed switchgear and controlgear for rated voltages above 1 kV and up to and including 38 kV 

                    29.130.10          IEC 60470 (2000-05)  

High-voltage alternating current contactors and contactor-based motor-starters 

                    29.130.10          IEC 60517 (1990-10)  

Gas-insulated metal-enclosed switchgear for rated voltages of 72.5 kV and above 

                    29.130.10          IEC/TR 60518 (1975-01)  

Dimensional standardization of terminals for high-voltage switchgear and controlgear 

                    29.130.10          IEC 60694 (1996-05)  

Common specifications for high-voltage switchgear and controlgear standards 

                    29.130.10          IEC/TS 60859 (1999-07)  

Cable connections for gas-insulated metal-enclosed switchgear for rated voltages of 72,5 kV and above - Fluid-filled and extruded insulation cables - Fluid-filled and dry type cableterminations  

                    29.130.10          IEC/TR 60932 (1988-01)  

Additional requirements for enclosed switchgear and controlgear from 1 kV to 72.5 kV to be used in severe climatic conditions 

                    29.130.10          IEC 61128 (1992-02)  

Alternating current disconnectors - Bus-transfer current switching by disconnectors 

                    29.130.10          IEC 61129 (1992-02)  

Alternating current earthing switches - Induced current switching 

                    29.130.10          IEC 61166 (1993-04)  

High-voltage alternating current circuit-breakers - Guide for seismic qualification of highvoltage alternating current circuit-breakers 

                    29.130.10          IEC/TR2 61233 (1994-07)  

High-voltage alternating current circuit-breakers - Inductive load switching 

                    29.130.10          IEC 61259 (1994-04)  

Gas-insulated metal-enclosed switchgear for rated voltages 72,5 kV and above - Requirements for switching of bus-charging currents by disconnectors 

                    29.130.10          IEC 61330 (1995-12)  

High-voltage/low voltage prefabricated substations 

                    29.130.10          IEC/TR2 61633 (1995-04)  

High-voltage alternating current circuit-breakers - Guide for short-circuit and switching test procedures for metal-enclosed and dead tank circuit-breakers 

                    29.130.10          IEC/TR2 61634 (1995-05)  

High-voltage switchgear and controlgear - Use and handling of sulphur hexafluoride (SF6) in high-voltage switchgear and controlgear 

                    29.130.10          IEC/TR2 61639 (1996-12)  

Direct connection between power transformers and gas-insulated metal-enclosed switchgear for rated voltages of 72,5 kV and above  

                    29.130.10          IEC/TR2 61640 (1998-07)  

Rigid high-voltage, gas-insulated transmission lines for rated voltage of 72,5 kV and above 

                    29.130.10          IEC 61958 (2000-11)  

High-voltage prefabricated switchgear and controlgear assemblies - Voltage presence indicating systems  

                    29.130.10          IEC/TR 62063 (1999-08)  

High-voltage switchgear and controlgear - The use of electronic and associated technologies in auxiliary equipment of switchgear and controlgear 

Publications found with ICS code: 

29.130.20 Low voltage switchgear and controlgear  

                    29.130.20          IEC 60439-1 (1999-09)  

Low-voltage switchgear and controlgear assemblies - Part 1: Type-tested and partially typetested assemblies 

                    29.130.20          IEC 60439-2 (2000-03)  

Low-voltage switchgear and controlgear assemblies - Part 2: Particular requirements for busbar trunking systems (busways) 

                    29.130.20          IEC 60439-3 (1990-12)  

Low-voltage switchgear and controlgear assemblies. Part 3: Particular requirements for lowvoltage switchgear and controlgear assemblies intended to be installed in places where unskilled persons have access for their use - Distribution boards 

                    29.130.20          IEC 60439-4 (1990-12)  

Low-voltage switchgear and controlgear assemblies. Part 4: Particular requirements for assemblies for construction sites (ACS) 

                    29.130.20          IEC 60439-4 (1999-07) Ed. 1.2Consolidated Edition

Low-voltage switchgear and controlgear assemblies - Part 4: Particular requirements for assemblies for construction sites (ACS) 

                    29.130.20          IEC 60439-5 (1998-10) Ed. 1.1Consolidated Edition

Low-voltage switchgear and controlgear assemblies - Part 5: Particular requirements for assemblies intended to be installed outdoors in public places - Cable distribution cabinets (CDCs) for power distribution in networks 

                    29.130.20          IEC 60715 (1981-01)  

Dimensions of low-voltage switchgear and controlgear. Standardized mounting on rails for mechanical support of electrical devices in switchgear and controlgear installations 

29.130.20              IEC 60947-1 (2000-10) Ed. 3.1Consolidated EditionLow-voltage switchgear and controlgear - Part 1: General rules 

29.130.20              IEC 60947-2 (1998-03) Ed. 2.1Consolidated EditionLow-voltage switchgear and controlgear - Part 2: Circuit-breakers 

                    29.130.20          IEC 60947-3 (1999-01)  

Low-voltage switchgear and controlgear - Part 3: Switches, disconnectors, switchdisconnectors and fuse-combination units 

                    29.130.20          IEC 60947-4-1 (2000-11)  

Low-voltage switchgear and controlgear - Part 4-1: Contactors and motor-starters - Electromechanical contactors and motor-starters  

                    29.130.20          IEC 60947-4-2 (1999-12)  

Low-voltage switchgear and controlgear - Part 4-2: Contactors and motor-starters - AC semiconductor motor controllers and starters  

                    29.130.20          IEC 60947-4-3 (1999-09)  

Low-voltage switchgear and controlgear - Part 4-3: Contactors and motor-starters - AC semiconductor controllers and contactors for non-motor loads 

                    29.130.20          IEC 60947-5-1 (1997-10)  

Low-voltage switchgear and controlgear. Part 5: Control circuit devices and switching elements - Section One: Electromechanical control circuit devices  

                    29.130.20          IEC 60947-5-1 (2000-03) Ed. 2.2Consolidated Edition

Low-voltage switchgear and controlgear - Part 5-1: Control circuit devices and switching elements - Electromechanical control circuit devices 

                    29.130.20          IEC 60947-6-1 (1989-07)  

Low-voltage switchgear and controlgear. Part 6: Multiple function equipment - Section One: Automatic transfer switching equipment 

                    29.130.20          IEC 60947-6-1 (1998-01) Ed. 1.2Consolidated Edition

Low-voltage switchgear and controlgear - Part 6-1: Multiple function equipment - Automatic transfer switching equipment  

                    29.130.20          IEC 60947-6-2 (1992-09)  

Low-voltage switchgear and controlgear - Part 6: Multiple function equipment - Section 2: Control and protective switching devices (or equipment) (CPS) 

                    29.130.20          IEC 60947-6-2 (1999-03) Ed. 1.2Consolidated Edition

Low-voltage switchgear and controlgear - Part 6-2: Multiple function equipment - Control and protective switching devices (or equipment) (CPS) 

                    29.130.20          IEC 60947-7-1 (1999-08) Ed. 1.1Consolidated Edition

Low-voltage switchgear and controlgear - Part 7: Ancillary equipment - Section 1: Terminal blocks for copper conductors 

                    29.130.20          IEC/TR3 61117 (1992-02)  

A method for assessing the short-circuit withstand strength of partially type-tested assemblies (PTTA) 

                    29.130.20          IEC/TR3 61641 (1996-01)  

Enclosed low-voltage switchgear and controlgear assemblies - Guide for testing under conditions of arcing due to an internal fault 

                    29.130.20          IEC 62026-1 (2000-07)  

Low-voltage switchgear and controlgear - Controller-device interfaces (CDIs) - Part 1: General rules 

                    29.130.20          IEC 62026-2 (2000-07)  

Low-voltage switchgear and controlgear - Controller-device interfaces (CDIs) - Part 2: Actuator sensor interface (AS-i) 

                    29.130.20          IEC 62026-3 (2000-07)  

Low-voltage switchgear and controlgear - Controller-device interfaces (CDIs) - Part 3: DeviceNet 

                    29.130.20          IEC 62026-5 (2000-07)  

Low-voltage switchgear and controlgear - Controller-device interfaces (CDIs) - Part 5: Smart distributed system (SDS) 

Publications found with ICS code: 

29.180 Transformers. Reactors  

29.180      IEC 60044-2 (2000-11) Ed. 1.1Consolidated EditionInstrument transformers - Part 2 : Inductive voltage transformers 

                    29.180               IEC 60050-421 (1990-10)  

International Electrotechnical Vocabulary. Chapter 421: Power transformers and reactors 

29.180       IEC 60076-1 (2000-04) Ed. 2.1Consolidated EditionPower transformers - Part 1: General 

                    29.180               IEC 60076-2 (1993-04)  

Power transformers - Part 2: Temperature rise 

                    29.180               IEC 60076-3 (2000-03)  

Power transformers - Part 3: Insulation levels, dielectric tests and external clearances in air  

                    29.180               IEC 60076-5 (2000-07)  

Power transformers - Part 5: Ability to withstand short circuit  

                    29.180               IEC 60076-8 (1997-11)  

Power transformers - Part 8: Application guide  

                    29.180               IEC 60296 (1982-01)  

Specification for unused mineral insulating oils for transformers and switchgear 

                    29.180               IEC 60354 (1991-10)  

Loading guide for oil-immersed power transformers 

                    29.180               IEC 60542 (1976-01)  

Application guide for on-load tap-changers 

                    29.180               IEC 60551 (1987-12)  

Determination of transformer and reactor sound levels 

                    29.180               IEC 60599 (1999-03)  

Mineral oil-impregnated electrical equipment in service - Guide to the interpretation of dissolved and free gases analysis 

                    29.180               IEC/TR 60616 (1978-01)  

Terminal and tapping markings for power transformers 

                    29.180               IEC 60722 (1982-01)  

Guide to the lightning impulse and switching impulse testing of power transformers and reactors 

                    29.180               IEC 60726 (1982-01)  

Dry-type power transformers 

                    29.180               IEC 60905 (1987-12)  

Loading guide for dry-type power transformers 

                    29.180               IEC 61181 (1993-06)  

Impregnated insulating materials - Application of dissolved gas analysis (DGA) to factory tests on electrical equipment 

                    29.180               IEC 61203 (1992-12)  

Synthetic organic esters for electrical purposes - Guide for maintenance of transformer esters in equipment  

                    29.180               IEC 61378-1 (1997-09)  

Convertor transformers - Part 1: Transformers for industrial applications  

                    29.180               IEC 61378-2 (2001-02)  

Converter transformers - Part 2: Transformers for HVDC applications  

                    29.180               IEC 61558-1 (1998-07) Ed. 1.1Consolidated Edition

Safety of power transformers, power supply units and similar - Part 1: General requirements and tests 

                    29.180               IEC 61558-2-1 (1997-03)  

Safety of power transformers, power suply units and similar - Part 2: Particular requirements for separating transformers for general use  

                    29.180               IEC 61558-2-2 (1997-10)  

Safety of power transformers, power supply units and similar - Part 2-2: Particular requirements for control transformers  

                    29.180               IEC 61558-2-3 (1999-10)  

Safety of power transformers, power supply units and similar devices - Part 2-3: Particular requirements for ignition transformers for gas and oil burners 

                    29.180               IEC 61558-2-4 (1997-03)  

Safety of power transformers, power supply units and similar - Part 2: Particular requirements for isolating transformers for general use  

                    29.180               IEC 61558-2-5 (1997-12)  

Safety of power transformers, power supply units and similar - Part 2-5: Particular requirements for shaver transformers and shaver supply units  

                    29.180               IEC 61558-2-6 (1997-03)  

Safety of power transformers, power supply units and similar - Part 2: Particular requirements for safety isolating transformers for general use   

                    29.180               IEC 61558-2-23 (2000-05)  

Safety of power transformers, power supply units and similar devices - Part 2-23: Particular requirements for transformers for construction sites 

                    29.180               IEC 61596 (1995-05)  

Magnetic oxide EP-cores and associated parts for use in inductors and transformers. 

Publications found with ICS code: 

29.240 Power transmission and distribution networks  

                    29.240               IEC 60050-601 (1985-10)  

International Electrotechnical Vocabulary. Chapter 601: Generation, transmission and distribution of electricity - General 

                    29.240               IEC 60050-602 (1983-01)  

International Electrotechnical Vocabulary. Chapter 602: Generation, transmission and distribution of electricity - Generation 

                    29.240               IEC 60050-603 (1986-08)  

International Electrotechnical Vocabulary. Chapter 603: Generation, transmission and distribution of electricity - Power systems planning and management 

                    29.240               IEC 60050-604 (1987-03)  

International Electrotechnical Vocabulary. Chapter 604: Generation, transmission and distribution of electricity - Operation 

                    29.240               IEC 60050-605 (1983-01)  

International Electrotechnical Vocabulary. Chapter 605: Generation, transmission and distribution of electricity - Substations 

                    29.240.10          IEC 61643-1 (1998-02)  

Surge protective devices connected to low-voltage power distribution systems - Part 1: Performance requirements and testing methods  

Publications found with ICS code: 

29.240.10 Substations. Surge arresters 

                    29.240.10          IEC 60099-1 (1999-12) Ed. 3.1Consolidated Edition

Surge arresters - Part 1: Non-linear resistor type gapped surge arresters for a.c. systems 

                    29.240.10          IEC 60099-4 (1998-08) Ed. 1.1Consolidated Edition

Surge arresters - Part 4: Metal-oxide surge arresters without gaps for a.c. systems 

29.240.10              IEC 60099-5 (2000-03) Ed. 1.1Consolidated EditionSurge arresters - Part 5: Selection and application recommendations 

                    29.240.10          IEC 61330 (1995-12)  

High-voltage/low voltage prefabricated substations 

                    29.240.10          IEC 61643-1 (1998-02)  

Surge protective devices connected to low-voltage power distribution systems - Part 1: Performance requirements and testing methods  

                    29.240.10          IEC 61643-21 (2000-09)  

Low voltage surge protective devices - Part 21: Surge protective devices connected to telecommunications and signalling networks - Performance requirements and testing methods 

Publications found with ICS code: 

29.240.20 Power transmission and distribution lines 

                    29.240.20          IEC 60050-466 (1990-10)  

International Electrotechnical Vocabulary. Chapter 466: Overhead lines 

                    29.240.20          IEC 60055-1 (1997-05)  

Paper-insulated metal-sheathed cables for rated voltages up to 18/30 kV (with copper or aluminium conductors and excluding gas-pressure and oil-filled cables) - Part 1: Tests on cables and their accessories 

                    29.240.20          IEC 60105 (1958-01)