Grid code 2014

Grid Code -Version 02
The Grid Code -Version 02 1 of 199
THE GRID CODE
FOR THE
NIGERIA ELECTRICITY TRANSMISSION
SYSTEM

GRID CODE
INDEX
CHAPTER 1: GENERAL CONDITIONS 7
1. SECTION: BACKGROUND 7
1.1. Title 7
1.2. New Arrangement for the Nigerian Electricity Sector 7
1.3. The Grid Code 7
1.4. Application of the Grid Code 7
1.5. Role of the TCN 8
2. SECTION: ORGANISATION AND OBJECTIVES 9
2.1. Objective 9
2.2. Unforeseen circumstances 9
2.3. Enforcement 10
2.4. Definitions 10
2.5. Interpretation 10
2.6. Derogations 11
2.7. Hierarchy 13
2.8. Data and Notices 14
2.9. Effectiveness 14
3. SECTION: REVIEW PROCESS AND CODE DISPUTES 15
3.1. Review Panel 15
3.2. Amendments to grid code 15
3.3. Disputes on the grid code 15
4. SECTION: MONITORING, TESTING AND INVESTIGATIONS 17
4.1. General 17
4.2. Monitoring 17
4.3. Testing 18
4.4. Investigations 19
4.5. Consequences of Monitoring, Testing and Investigations 19
CHAPTER 2: PLANNING 20
5. SECTION: PURPOSE AND SCOPE 20
5.1. Objectives 20
5.2. Purpose 20
5.3. SCOPE 21
6. SECTION: LOAD FORECAST 21
6.1. Objective 21
6.2. Long term Demand Forecast 22
7. SECTION: EXPANSION PLANNING 22
7.1. Planning standards 22

7.2. Long Term Expansion Plan 22
7.3. User involvement 24
8. SECTION: DATA REQUIREMENTS FOR LONG TERM PLANNING 26
8.1. Information Required 26
8.2. Standard Planning Data 27
8.3. Generating Unit Data 32
8.4. Demand and Active Energy Data 35
8.5. Detailed Planning Data 36
8.6. Transient Over-voltage Assessment Data 40
8.7. User’s Protection Data 41
8.8. Network Data 43
CHAPTER 3: CONNECTION CONDITIONS 45
9.1. Objective 45
9.2. Purpose 45
9.3. Scope 46
10. SECTION: TRANSMISSION SYSTEM PERFORMANCE CHARACTERISTICS 47
10.1. Frequency and Voltage 47
10.2. Voltage Perturbations 48
11. SECTION: CONNECTION PROCESS 50
11.1. Application for connection 50
11.2. Process of the application 52
11.3. GRID Connection Agreement 54
12. SECTION: TECHNICAL CRITERIA FOR PLANT AND APPARATUS AT THE CONNECTION POINT 56
12.1. General 56
12.2. SCADA, Measurement and Data Exchange 56
12.3. Telecommunication Installations 57
12.4. Power System control 58
12.5. Protection Criteria and Metering 58
12.6. ADDITIONAL REQUIREMENTS for Power Stations 59
CHAPTER 4: OPERATION 63
13.1. Objective 63
13.2. Scope 63
14. SECTION: POWER SYSTEM CONTROL 65
14.1. Objective 65
14.2. General 65
14.3. Power System Control Actions 66
14.4. Notification to all Users 66
14.5. Control under fault or emergency conditions 66

14.6. De-energisation of plant 67
14.7. Operating procedures including Fault Reporting 68
15. SECTION: FREQUENCY CONTROL AND OPERATING RESERVE 70
15.1. Objective 70
15.2. General 70
15.3. Frequency limits 70
15.4. Frequency Control 71
15.5. Components of Operating Reserve 71
15.6. Operating Reserve policy 72
15.7. Amount of Operating Reserve 74
15.8. Operating Reserve Procurement 74
16. SECTION: VOLTAGE CONTROL 77
16.1. Objective 77
16.2. General 77
16.3. Voltage Control 77
16.4. Voltage Control policy 77
16.5. Voltage Control methods 78
16.6. Voltage Control during emergencies 78
16.7. Provision of voltage control 79
17. SECTION: BLACK START 81
17.1. Objective 81
17.2. General 81
17.3. Ancillary Service 81
17.4. Requirements 81
18. SECTION: EMERGENCY OPERATION AND RESTORATION 83
18.1. Objective 83
18.2. General 83
18.3. Emergency operation 84
18.4. Restoration of supply 85
18.5. Back-up Control Centre 86
18.6. Emergency co-ordination facility 86
18.7. Under-Frequency Load shedding 87
19. SECTION: OPERATIONAL PLANNING 89
19.1. Objective 89
19.2. General 89
19.3. Functions of the Operational Planning staff 90
19.4. Data required for Medium Term and operational Planning 91
19.5. Actual Demand Control data 93
19.6. Connections 93
19.7. Changes to Information Already Supplied 94

19.8. Timing and publication 94
20. SECTION: INFORMATION EXCHANGE 95
20.1. Objective 95
20.2. General 95
20.3. Requirement to notify 95
20.4. Notification of an ABNORMAL operation 95
20.5. Form of notification of an ABNORMAL operation 96
20.6. Recording of an ABNORMAL operation 96
20.7. Timing in respect of an ABNORMAL operation 96
20.8. Notification of events 97
20.9. Form of notification of an event 97
20.10. Provision of further information 97
20.11. Recording of an event 97
20.12. Timing in respect of an event 97
20.13. Operational communication and data retention 97
20.14. Contact locations 98
20.15. Communication facilities 100
20.16. Supervisory control and data acquisition (SCADA) 100
20.17. Computer equipment 101
20.18. Telephone/Facsimile 101
20.19. Access and security 101
20.20. Time standards 101
20.21. Communication between the Users 102
20.22. Data and notices 102
20.23. Data retention 102
21. SECTION: SCHEDULING AND DISPATCH 104
21.1. Objective 104
21.2. General 104
21.3. Data and Process 104
21.4. Dispatch Scheduling 105
21.5. Generation Dispatch 107
22. SECTION: OUTAGE CO-ORDINATION 113
22.1. Objective 113
22.2. General 113
22.3. Outage scheduling 113
22.4. Changes to the committed Outage scheduling programME 115
22.5. Other information to be notified 116
23. SECTION: RELIABILITY MEASURES 117
23.1. Objective 117
23.2. General 117

23.3. Applicable Reliability Criteria 117
23.4. Reliability Indicators 117
23.5. Reporting 118
24. SECTION: SYSTEM TESTING ON THE NETWORK 119
24.1. Objective 119
24.2. General 119
24.3. Tests Required by TSP or System Operator 119
24.4. Tests required by User(s) 120
24.5. Evaluation of Proposed System Tests 121
24.6. Approval for System TestS 121
24.7. Scheduling of System Tests 122
24.8. Dispatching of System Tests 123
24.9. Test Reporting 123
24.10. Disputes 124
25. SECTION: SAFETY AND CO-ORDINATION 125
25.1. Objective 125
25.2. GEneral 125
25.3. Interpretation 125
25.4. Procedure 126
25.5. Record of Network Safety Precautions (RNSP) 127
25.6. Safety Precautions on High Voltage Equipment 128
26. SIGNIFICANT INCIDENT AND ACCIDENT REPORTING 132
1. APPENDIX 1: DEFINITIONS 134
2. APPENDIX 2: CONDITIONS PRECEDENT 154
3. APPENDIX 3: RELIABILITY CONCEPTS AND DEFINITIONS 155
4. APPENDIX 4A – RECORD OF NETWORK SAFETY PRECAUTIONS (RNSP) 167
4. APPENDIX 4B – RECORD OF NETWORK SAFETY PRECAUTIONS 169
4. APPENDIX 4C – RNSP ISSUE PROCESS 171
4. APPENDIX 4D – RNSP CANCELLATION PROCESS 172
4. APPENDIX 4E – RNSP TESTING PROCESS 173
5. APPENDIX 5 – DATA REGISTRATION REQUIREMENTS 174
6. APPENDIX 6 - DISTRIBUTION NETWORK DATA 188
7. APPENDIX 7 – NETWORK EXPANSION PLANNING DATA 192
8. APPENDIX 8: CIVIL EMERGENCIES 197
9. APPENDIX 9: GRID CODE REVIEW PANEL 198

CHAPTER 1: GENERAL CONDITIONS
1. SECTION: BACKGROUND
1.1. TITLE
1.1.1. The Grid Code and guidelines shall be called the Grid Code for the Electricity
Industry of Nigeria (the “Code”)
1.2. NEW ARRANGEMENT FOR THE NIGERIAN ELECTRICITY
SUPPLY INDUSTRY
1.2.1. The Electric Power Sector Reform Act, 2005 (henceforth referred to as the Act) gave
legal backing to the unbundling of the Nigeria Power Sector. The Act stipulates the
functional unbundling of the Generation, Transmission and Distribution Sectors.
1.2.2. Pursuant to Sections 8, 65 and 66 of the Act, a Transmission and System Operating
Company (TCN) shall be established and licenced to perform the functions of transmission
and system operations of the High Voltage network of the Nigerian Electricity Supply
Industry.
1.3. THE GRID CODE
1.3.1. The Grid Code contains the day-to-day operating procedures and principles
governing the development, maintenance and operation of an effective, well-coordinated and
economic Transmission System for the electricity sector in Nigeria.
1.3.2. The code is designed to:
(a) Facilitate an efficient production and supply of electricity for all Users of the
Transmission System and TCN itself, without any act of discrimination between
Users or class of Users.
(b) Facilitate competition in the generation and supply of electricity in the country.
1.3.3. For complete understanding of the operation of the Nigeria Electricity industry post -
deregulation, this document has to be read in conjunction with the Market Rules, Metering
Code, Distribution Code and other documents relating to other operational aspects of the
industry.
1.4. APPLICATION OF THE GRID CODE
1.4.1. The Grid Code shall apply to TCN and Users of the Transmission System. TCN shall
be responsible for implementation of the Grid Code. All Users the System Operator and the
Transmission Service Provider shall comply with the Grid Code and assist TCN in this
regard. Users must provide all the required information and reasonable rights of access,
service and facilities necessary for implementation of the Grid Code.

(a) If any User has any difficulty in complying with any of the provisions of the
Grid Code, the User shall immediately, without delay, inform the same to the
Nigerian Electricity Regulatory Commission and TCN, and shall remedy his
non-compliance promptly.
(b) Consistent failure in compliance with the Grid Code may lead to disconnection
of the User’s plant, Equipment or Apparatus.
(c) Consistent failure by the System Operator or the Transmission Service Provider
to comply with the Grid Code shall be dealt with under Section 4.5.
(d) The operation of the Grid Code shall be reviewed regularly by the Grid Code
Review Panel in accordance with the provisions of the relevant Sections of the
Code.
1.5. ROLE OF THE TCN
1.5.1. TCN shall perform two different groups of functions in relation to network and
system operation activities:
(a) As Transmission Service Provider (TSP):
(i) admit Users in accordance with the this Grid Code who satisfy the
requirements for connection;
(ii) evaluate and accept grid connections;
(iii) ensure proper metering at all Connection Points;
(iv) obtain necessary information from Users of the Transmission Network to
enable it perform adequate planning operations and development of the
Transmission Network.
(b) As System Operator:
(i) dispatch Generating Units in accordance with this Code at least cost, on the
basis of Nominations by Generators;
(ii) procure Ancillary Services and recover the costs of procuring Ancillary
Services
b.ii.1) such procurement may be directly from a Generator or may be via
NBET in which case NBET would recover the costs directly from Off-
takers;
(iii) handle Power System emergencies and restore the Power System;
(iv) perform Demand forecasting;
(v) coordinate Generation and Transmission Outages;
(vi) supervise compliance with, and enforce, the Grid Code;
(vii) test and monitor Users’ Equipment to ensure their compliance with the Grid
Code;

(viii) report scheduled and planned actions and unexpected occurrences such as
faults to Users and the Regulator; and
(ix) produce procedures for conducting system tests pertaining to the network.
2. SECTION: ORGANISATION AND OBJECTIVES
2.1. OBJECTIVE
2.1.1. The objectives of these General Conditions are:
(a) To establish the conditions applicable to all the provisions of the Grid Code and
to the extent possible, ensure that the provisions of the Grid Code apply for the
benefit of the TSP, System Operator and all Users, and for it to apply
consistently to all Users.
(b) To provide the principles and procedures for the development and application
of the Grid Code.
(c) To establish requirements for monitoring, testing and investigation on whether
Users are operating within their design, operating and connection requirements,
as specified in the Grid Code, Grid Connection Agreements, Ancillary Services
Agreements or any other relevant Agreements between Users and the TCN.
2.2. UNFORESEEN CIRCUMSTANCES
2.2.1. The Grid Code contains procedures for the management of day to day technical
situations on the Transmission Network, taking into account a wide range of operational
conditions likely to be encountered under both normal and abnormal conditions.
2.2.2. The Grid Code cannot predict and address all the possible operating conditions.
Users must therefore understand and accept that the TCN, in such unforeseen circumstances,
may be required to act decisively to discharge its obligations under its License conditions
within the following general principles and priorities:
(a) Preserve the safety of Equipment, to prevent damage to Plant and/or
Apparatus, and public safety to prevent personal injury.
(b) Preserve or restore the integrity of the Transmission System, including the
avoidance of breakdown, separation or collapse (total or partial).
(c) Compliance by the System Operator with the Electric Power Sector Reform
Act, conditions in its System Operator Licence, and the Grid Code.
2.2.3. In case of an unforeseen circumstance that cannot be resolved with the general
principles as defined in the previous condition, the System Operator shall act according to the
following:
(a) The application of a policy aimed at equitable sharing amongst Users of any
temporary restriction that might be necessary in exceptional circumstances, and
(b) The application of Good Utility Practice.

2.2.4. If circumstances not envisaged by the provisions of the Grid Code should arise, the
System Operator shall, to the extent reasonably practicable in the circumstances, consult
promptly and in good faith with the Grid Code Review Panel (the Panel) or all affected Users
in an effort to reach agreement as to what should be done. If agreement between the System
Operator and the Panel or affected Users cannot be reached in the time available, the System
Operator shall determine what shall be done in accordance with Good Utility Practice.
2.2.5. The System Operator shall promptly refer any unforeseen circumstance identified,
together with the determinations and interpretations made, to the Panel for consideration.
2.2.6. Each User shall comply with all instructions given to it by the System Operator,
following a determination of actions regarding an unforeseen circumstance even if there is a
difference in interpretation, provided that such instructions are consistent with the technical
characteristics of the User's System and the principles established in the Grid Code, and do
not endanger the safety of its Equipment or staff.
2.2.7. Users should note that the provisions of the Grid Code may be suspended in whole
or in part during a Security Period or in accordance with a Civil Emergency Direction issued
under a Civil Emergency directive by an appropriate authority.
2.2.8. Users shall provide such reasonable cooperation and assistance as TCN may require
in any such unforeseen circumstances.
2.3. ENFORCEMENT
2.3.1. The Act assigns to NERC the authority to establish the appropriate technical codes
and manuals that may be required for the safe, reliable and efficient operation of the System.
Within such powers, the NERC has the authority to establish the initial Grid Code and to
approve amendments from time to time, as proposed by the TCN and affected Users.
2.3.2. The provisions of this Code shall be enforced by the System Operator in accordance
with the Rule 45 of the Market Rules, guidelines from NERC, and Grid Connection
Agreements.
2.4. DEFINITIONS
2.4.1. Capitalised words and expressions used in this Code, unless the context otherwise
requires, shall have the meaning assigned to them in Appendix1.
2.4.2. Where a term is not defined in this document it takes the meaning assigned in the Act
or the Market Rules with the Act definition taking precedence.
2.5. INTERPRETATION
2.5.1. In this Code, unless the context otherwise requires:
(a) a reference to a particular Section, Subsection, or Appendix is to a Section or
Subsection of, or Appendix to, this Code;

(b) a reference in a particular Section or Appendix to a paragraph is to a paragraph
of that Section or Appendix;
(c) the table of contents and Section and Subsection headings are for convenience
only and shall be ignored in construing this Code;
(d) references to the masculine include the feminine and references in the singular
include references in the plural;
(e) “N” means Naira;
(f) the word “include” shall be construed without limitation;
(g) a reference to a “person” includes any individual, partnership, firm, company,
corporation (statutory or otherwise), joint venture, trust, association,
organisation or other entity, in each case whether or not having separate legal
personality;
(h) a reference to applicable law shall be construed, at the particular time, as
including a reference to any modification, extension, re-enactment or
replacement thereof then in force;
(i) a derivative term of any defined or interpreted term or expression shall be
construed in accordance with the relevant definition or interpretation;
(j) a reference to another agreement or any deed or other instrument shall be
construed as a reference to that other agreement, deed or other instrument, as
the same may have been, or may from time to time be, modified; and
(k) “in writing” means typewriting, printing, lithography, electronic mail, facsimile
and other modes of reproducing words in a legible and non-transitory form.
2.6. DEROGATIONS
2.6.1. If a User finds that it is, or will be, unable to comply with any provision of this Code,
then the User shall, without delay, report such non-compliance to the System Operator and
shall make such reasonable efforts as are required to remedy such non-compliance as soon as
is reasonably practicable.
2.6.2. When the non-compliance described in the Subsection 2.6.1 arises upon the issuance
of this Grid Code relating to Equipment already connected to the Transmission System or
Equipment approved to be connected to the Transmission System where the User has
commenced the procurement or works prior to the issuance of this Grid Code and the User
believes either that it would be unreasonable (including on the grounds of cost and technical
considerations) to remedy such non-compliance or that it should be granted an extended
period to remedy such non-compliance, the User shall promptly submit to the System
Operator a request for derogation from such provision in accordance with this Section. The
burden of proof shall rest with the User to show good reason why it cannot comply.

2.6.3. If TCN finds that it is, or will be, unable to comply with any provision of this Grid
Code, then it shall, without delay, report such non-compliance to the NERC and shall make
such reasonable efforts as are required to remedy such non-compliance as soon as is
reasonably practicable.
2.6.4. When the non-compliance described in the previous Subsection arises upon the
issuance of this Grid Code, relating to Equipment already connected to the Transmission
System or Equipment approved to be connected to the Transmission System where TCN has
commenced the procurement or works prior to the issuance of this Grid Code, and TCN
believes either that it would be unreasonable (including on the grounds of cost and technical
considerations) to remedy such non-compliance or that it should be granted an extended
period to remedy such non-compliance, TCN shall promptly submit to the NERC a request
for derogation from such provision in accordance with this Section. The burden of proof
shall rest with TCN, to show good reason why it cannot comply.
2.6.5. A request for derogation from any provision of this Grid Code shall contain:
(a) the detail of the Equipment and if relevant Connection Point in respect of
which derogation is sought and the nature and extent of non-compliance;
(b) the provision of this Grid Code with which the TCN or User that requests the
derogation, is or will be unable to comply;
(c) the reason for the non-compliance; and
(d) the remedial actions and the date by which compliance could be achieved (if
remedy of the non-compliance is possible).
2.6.6. Every six months, the System Operator shall report to the NERC:
(a) the list of derogations requested during the previous six (6) months, including
requests by the TCN, and the status of each request;
(b) the list of approved derogations during the previous six (6) months indicating
type of derogation and party; and
(c) for each approved derogation, the progress of remedial actions in achieving
compliance.
2.6.7. On receipt of any request for derogation, the System Operator or the NERC, as
applicable, shall promptly consider such a request provided that the System Operator or the
NERC considers that the grounds for the derogation are reasonable. In its consideration of a
derogation request, the System Operator or the NERC, as applicable, may contact the User
or System Operator, to obtain clarifications of the request or request additional information
or to discuss changes to the request, and review possible remedial actions to achieve
compliance as soon as reasonably practicable.
2.6.8. The System Operator shall:
(a) keep a register of all derogations which have been granted, identifying the name
of the User in respect of whom the derogation has been granted, the relevant
provision of this Grid Code and the period of the derogation; and

(b) on request from the NERC or any User, provide a copy of such register of
derogations.
2.6.9. The NERC shall:
(a) keep a register of all derogations that have been granted to the TCN, identifying
the relevant provision of this Grid Code and the period of the derogation; and
(b) on request from any User provide a copy of such register of derogations.
2.6.10. The NERC may initiate on its own initiative or at the request of the System Operator,
or in view of a User complaint, a review of any existing derogations, and any derogations
under consideration where a relevant and material change in circumstance has occurred.
2.7. HIERARCHY
2.7.1. In the event of any inconsistency between this Grid Code and the Act or the Market
Rules, or the license of the TSP or the System Operator or a Licensee that is a User, the Act
shall prevail to the extent of such inconsistency.
2.7.2. Nothing in this Grid Code is intended to or shall derogate from any license obligation
of a Licensee.
2.7.3. If any provision of this Grid Code should be found to be unlawful or wholly or
partially invalid for any reason, the validity of all remaining provisions of this Grid Code shall
not be affected.
2.7.4. If part of a provision of this Grid Code is found to be unlawful or invalid but the rest
of such provision would remain valid if part of the wording were deleted, the provision shall
apply with such minimum modification as may be:
(a) necessary to make it valid and effective; and
(b) most closely achieves the result of the original wording but without affecting the
meaning or validity of any other provision of this Grid Code.
2.7.5. In the event of any conflict between the provisions of this Grid Code and any
contract, agreement or arrangement between TCN and a User, the provisions of this Grid
Code shall prevail unless this Grid Code expressly provides otherwise, provided that in the
case of Grid Connection Agreements with Users signed prior to the approval of this Grid
Code, the conditions in such agreement shall prevail unless:
(a) the parties agree on amendments to such an agreement: or
(b) the User registers a non-compliance situation that negatively affects the security
of the Transmission System, in which case the User must accept the necessary
amendments to ensure full compliance with this Grid Code, except for any
derogation.
2.7.6. This Grid Code shall be interpreted so as to avoid, to the extent reasonably possible,
findings of inconsistency between this Grid Code and the Market Rules; but where there is
such an inconsistency and it relates to financial issues the Market Rules shall prevail and
where it relates to engineering issues and/or technical issues this Grid Code shall prevail.

2.8. DATA AND NOTICES
2.8.1. For the purposes of this Code, “Business Day” means a day other than:
(a) a Saturday or a Sunday; or
(b) a public holiday in Nigeria;
2.8.2. References to times of the day in these Rules are to official time in Nigeria.
2.8.3. Any notice required to be given by this Grid Code shall be deemed to have been
given or received:
(a) if sent by hand, at the time of delivery;
(b) if sent by post, from and to any address within Nigeria, four (4) Business Days
after posting unless otherwise proven; or
(c) if sent by facsimile, subject to confirmation of uninterrupted transmission
report, or by e-mail, one hour after being sent, provided that any transmission
sent after 17:00 hours on any day shall be deemed to have been received at
08:00 hours on the following Business Day unless the contrary is shown to be
the case.
2.9. EFFECTIVENESS
2.9.1. The provisions of this Code shall come into effect upon the satisfaction or fulfilment
of the events and matters set out or referred to in Appendix 2 (the “Conditions Precedent”),
as declared by the Commission.

3. SECTION: REVIEW PROCESS AND CODE DISPUTES
3.1. REVIEW PANEL
3.1.1. A Grid Code Review Panel (GCRP) shall be formed pursuant to Rule 42 of the
Market Rules. This Panel shall be in charge of the Grid Code review and amendment.
3.2. AMENDMENTS TO GRID CODE
3.2.1. This Code may be amended in accordance with the provisions of Rule 44 of the
Market Rules.
3.3. DISPUTES ON THE GRID CODE
3.3.1. Any Dispute relating to, arising out of or in connection with this Code between:
(a) a User and the TSP;
(b) a User and the System Operator;
(c) a person who applies to be a User and the TSP; and
(d) between Users,
shall be referred to an Expert as defined in Subsection 3.3.3 below.
3.3.2. In the event that the Dispute cannot be resolved by an Expert it shall be resolved in
accordance with the provisions contained in Rule 43 of the Market Rules.
3.3.3. Expert Determination:
(a) Where this Code provides that any Dispute or other matter shall be referred to
an Expert or the parties otherwise so agree the following provisions shall apply:
(i) Expert shall be a suitably qualified person with requisite experience jointly
appointed by the parties and willing to act. If the parties are unable to agree
on the choice of an Expert within 30 days, the Expert shall upon a request in
writing by either party, be appointed by NERC.
(ii) For a period of 30 days after the appointment of the Expert or such other
period as the parties may agree, each party may make such written
submissions as it wishes to the Expert and shall simultaneously provide a
copy to the other party.
(iii) At the end of such 30 day period each party shall have a period of 15 days to
make counter-submissions to the Expert (with a copy to the other party) in
reply to the other party’s written submissions made during the
aforementioned 15 day period provided that neither party shall during such
15 day period make any written counter-submission which purports to reply
to, raise or refer to, any new matters not raised or referred to in any
submission made during the aforementioned 15 day period.

(iv) At the end of the 15 day period referred to in Subsection (iii) above, and no
later than 15 days thereafter, either party may, with the consent of the Expert
and at a time and place decided by the Expert, make an oral presentation to
the Expert in the presence of the other party commenting on or explaining
matters previously submitted to the Expert in writing.
(v) The Expert shall render his determination in writing within 30 days of the
completion of the oral presentations made in accordance with Subsection (iv)
and give reasonable details of the reasons for his determination.
(vi) The decision of the Expert shall be final and binding on the parties save in
the event of fraud or manifest error or mistake.
(vii) The Expert shall act as an expert and not as an arbitrator.
(viii) The costs of the Expert shall be borne equally by the parties.
(ix) Neither party shall have any right to commence or maintain any legal
proceedings pertaining to a Dispute until the Dispute has been resolved in
accordance with Subsections (i), (ii) or (v) above, and then only to enforce or
execute the award under such procedure.
(x) The parties shall each secure that all Experts and arbitrators shall agree to be
bound by the provisions on confidentiality of this Code as a condition of
appointment.

4. SECTION: MONITORING, TESTING AND INVESTIGATIONS
4.1. GENERAL
4.1.1. The System Operator or the TSP, as applicable, will need to carry out certain
monitoring, testing and investigations in respect of the performance and characteristics of
Generation and Load plant in order to discharge its responsibilities in respect of the safe,
secure and economic operation of the Transmission System and in respect of Generation
Dispatch.
4.1.2. In order to achieve the primary objectives, procedures need to be established for the
monitoring, testing and investigation for each of the following:
(a) Whether centrally Dispatched Generating Units comply with Dispatch
Instructions;
(b) Whether Generators are in compliance with registered Availability, Ancillary
Services capabilities, operating characteristics and any other data required to be
registered by those Generators;
(c) Whether power quality of Users conforms to the standards and limits agreed
upon between the affected parties, with respect to the minimum and maximum
fault levels, harmonic current injected limits, harmonic voltage contributions,
short-term and long-term voltage Flicker, voltage unbalance, the number and
the duration and severity of voltage depressions; and
(d) Whether Users are in compliance with protection requirements and protection
settings, Grid Connection Agreements, Ancillary Services Agreements and other
relevant support agreements between Users and the System Operator or the
TSP, as applicable.
(e) Whether Service Providers are in compliance with protection requirements and
protection settings, Grid Connection Agreements, Ancillary Services
Agreements and other relevant support agreements between Users and the
System Operator or the TSP, as reasonably applicable.
4.2. MONITORING
4.2.1. Time
Monitoring may be carried out at any time by the System Operator or TSP, as applicable,
and may result, without the application of further testing, in the evaluation by the System
Operator or TSP of User non-compliance.
4.2.2. Period

Monitoring may be continuous for a specified or unspecified period and shall be carried
out by monitoring, data recording and analysis. It shall not require advance notice from
the System Operator or TSP to User.
4.2.3. Recording and analysis system
Where a data recording and analysis system is used, the System Operator shall inform the
User that this is so and describe any instrument being used. On request from the User,
shall make available to the User information in respect of the data recording and analysis
system.
4.2.4. Disputes
Disputes shall be handled according to Subsection 3.3 above.
4.2.5. Performance parameters
Performance parameters shall be defined according to Rule 12 of the Market Rules.
4.2.6. Monitoring systems and procedures
The systems and procedures shall be laid out as defined in this Code.
4.3. TESTING
4.3.1. System Operator’s or TSP’s right to testing
System Operator or TSP may, from time to time, carry out tests to verify that a User is
complying with its connection conditions and registered operating characteristics in the
Registered Information. Such testing by the System Operator and/or TSP should be
done in such way as to minimize risk to personnel, Generating Unit and grid integrity.
The System Operator may:
(a) Induce controlled Power System Frequency or voltage conditions or variations
for the purpose of determining that the Generating Unit’s response is in
accordance with its registered Availability, Ancillary Service capabilities and
operating characteristics, and
(b) Having given three (3) Business Days notice, or less where agreed, send a
representative to the User’s site to verify by testing in accordance with the test
procedures specified, that the User is in compliance with its registered values.
4.3.2. Dispatch Instruction
Tests shall be carried out to a Dispatch Instruction from the System Operator.
A test may require the User to carry out specific actions in response to a Dispatch
Instruction.
In particular in order to test the Generating Units Availability the System Operator may
instruct it to operate at full load and if it is shut down instruct it to start and then operate
at full load.
4.3.3. Site attendance

A System Operator or TSP representative shall be allowed at User sites in order to carry
out tests in accordance with agreed or generic testing procedures.
4.3.4. Results
The results of a test may be derived from the monitoring of performance during the test.
4.3.5. Subcontracting of testing work
If the System Operator or TSP subcontracts testing work on a User’s site, then the User
and the System Operator or TSP shall be in agreement on the selection of a suitable
subcontractor.
4.3.6. Confidentiality
Confidentiality shall be adhered to in accordance with the Market Rules or the Grid
Connection Agreement as applicable.
4.4. INVESTIGATIONS
4.4.1. Refer to Market Rules 45 for details on investigations.
4.5. CONSEQUENCES OF MONITORING, TESTING AND
INVESTIGATIONS
4.5.1. Enforcement
Refer to Market Rules 45 for issues surrounding enforcement of these Subsections.
4.5.2. Payment
Payment for any costs associated with testing will be in accordance with the Market Rules.

CHAPTER 2: PLANNING
5. SECTION: PURPOSE AND SCOPE
5.1. OBJECTIVES
5.1.1. The objectives of this Planning Chapter are:
(a) To provide guidelines and address the requirements for the System Operator to
perform long-term expansion planning of the Nigeria Transmission System.
(b) To specify the conditions and guidelines for the Users to provide information to
the TSP or the System Operator in order that planning and development of the
Nigeria Transmission Network can be undertaken in accordance with relevant
standards.
(c) To specify standards which will be used in the planning and development of the
Nigeria Transmission Network.
(d) To specify the information required by the System Operator from Users in
respect of:
(i) capability of gas-fired generating units to run using alternative fuels; and
(ii) mothballed generating plants.
(e) To promote interaction between TSP and Users in respect of any proposed
development on the network or on a User’s system that might impact on the
performance of the Nigeria Transmission Network or interconnection to the
network.
5.2. PURPOSE
5.2.1. The Transmission System expansion planning will cater for the connection of new
Load/Generation to the Transmission System. It will ensure that the impact of these
connections can be handled by the existing Transmission System or, if not, it will identify the
need for required expansion. The planning and development of the Transmission System
shall be in accordance with the Transmission Planning Criteria and relevant standards
applicable in Nigeria.
5.2.2. Reasons for development: The development of the Transmission System, involving
its reinforcement or extension, will occur for a number of reasons including, but not limited
to:
(a) A development on a User’s System (e.g. a Distribution Company) already
connected to the Transmission System;
(b) The introduction of a new substation or the modification of an existing
substation between a User’s System and the Transmission System;

(c) Changing requirements for electricity transmission facilities due to changes in
factors such as Demand, Generation, technology, Reliability requirements,
and/or environmental requirements; and
(d) A combination of more than one of the above-mentioned developments.
5.2.3. Work involved: The reinforcement or extension of the Transmission System may
involve works:
(a) At a new or existing substation where the User’s Plant and/or Apparatus is
connected to the Transmission System;
(b) On new or existing Transmission lines or other facilities which join that
substation to the remainder of the Transmission System; and
(c) On new or existing Transmission lines or other facilities at or between points
remote from that substation.
5.2.4. Timing: The time required for the planning and development of the Transmission
System will depend on the type and extent of the necessary reinforcement and/or extension
work. The time required for obtaining planning permission and wayleaves, including any
associated hearings, and the degree of complexity in undertaking the new work while
maintaining satisfactory security and Quality of Supply on the existing Transmission System.
Actual implementation should be scheduled in advance and coordinated with Users in
accordance with Section 19 (Operational Planning) to minimize the impact and risk to the
Transmission System and User's Plant.
5.3. SCOPE
5.3.1. This Planning Chapter applies to the System Operator, TSP and to Users of the
Transmission System which in this Part of the Code are:
(a) Generators;
(b) Distributors;
(c) Interconnected parties; and
(d) Directly Connected Customers.
6. SECTION: LOAD FORECAST
6.1. OBJECTIVE
6.1.1. The objective of this Section is to specify the Generation and Demand Forecasts that
the System Operator has to generate for short, medium and long term planning expansion
purposes.

6.2. LONG TERM DEMAND FORECAST
6.2.1. Timing and publication: System Operator shall create a new long term (20 years)
Demand Forecast for the Transmission Network, at least once every 3 years.
This long term Demand Forecast, shall be updated yearly given the actual Demand in the
previous year, and shall form part of the report on long term expansion planning to be
supplied to the Commission pursuant to Subsection 7.2.7
6.2.2. Demand Forecasts factors: The System Operator shall take the following factors
into account when conducting long term Demand Forecasting:
(a) Historical Demand data;
(b) Current and anticipated future land use;
(c) Population and demographic forecasts;
(d) Economic growth rates;
(e) Technological development as it potentially effects Demand; and
(f) Other information supplied by Users.
6.2.3. Demand Forecast methodology: System Operator shall use a geographical based
Demand Forecast methodology based on the factors in Subsection 6.2.2 to produce unbiased
forecasts of the Transmission Network Demand into the future.
The methodology shall allow System Operator to perform sensitivity analysis to
determine an optimistic, realistic or pessimistic long term Demand Forecast.
7. SECTION: EXPANSION PLANNING
7.1. PLANNING STANDARDS
7.1.1. Transmission Planning Criteria: The System Operator, in consultation with the TSP
shall develop comprehensive Transmission Planning Criteria to guide the expansion planning
of the Transmission System. The Transmission Planning Criteria shall be approved by the
Commission.
7.1.2. The System Operator shall apply the Transmission Planning Criteria and relevant
standards in the planning and development of the Transmission System.
7.2. LONG TERM EXPANSION PLAN
7.2.1. Long term Demand Forecast
The System Operator shall use the long term (20 years) Demand Forecast for the
Transmission System, pursuant to Subsection 6.2, as input for long term expansion
planning.
7.2.2. Refurbishment

The TSP in consultation with System Operator shall perform refurbishment audits on
the existing Transmission System in order to determine the remaining useful life of the
Transmission System components.
The TSP shall produce a refurbishment plan to replace ageing and damaged Equipment.
Such plan shall take into consideration security of the Transmission System and the
impact of such activities on Users.
7.2.3. Analyse current network
The System Operator shall analyse and document the current Transmission System
adequacy.
7.2.4. Expansion alternatives
The System Operator in collaboration with the TSP shall hold workshops with
stakeholders to determine possible alternatives to address the combination of the
following inputs:
(a) Long term Demand Forecast;
(b) Refurbishment needs; and
(c) Current Transmission System performance.
7.2.5. Analyse alternatives
The System Operator in collaboration with the TSP shall evaluate the alternatives
determined pursuant to Subsection 7.2.4 for at least five, ten, fifteen and twenty years
into the future. At least the following analysis shall be performed:
(a) Load flow analysis;
(b) Fault level calculations;
(c) Stability studies;
(d) Reliability studies; and
(e) Financial analysis.
7.2.6. Based on the analysis performed pursuant to Subsection 7.2.5 the System Operator
shall develop a financially feasible least cost expansion plan, which meets the approved
Transmission Planning Criteria.
7.2.7. Long-term expansion plan report
The System Operator shall document the long-term twenty year expansion plan in a
report every year. This report shall include at least the following sections:
(a) Long-term Demand Forecast;
(b) Long-term Generation Adequacy Forecast (as required under the Market Rules);
(c) Long-term Transmission Network Adequacy Forecast;
(d) Long-term zonal Supply and Demand Margin;

(e) Long-term Statutory outage plan for transmission infrastructure;
(f) Long-term Refurbishment plan;
(g) Alternatives (Identification and Analysis);
(h) Capital investment programme; and
(i) Financial motivation.
The Commission shall circulate this report to all Users for comments. The Commission
will approve the long-term expansion plan once it is satisfied that the System Operator
has taken all relevant comments into account.
7.2.8. Approval
The TSP shall be committed to implement the projects listed in the long-term expansion
plan (and only these projects) after the Commission has approved the report.
7.3. USER INVOLVEMENT
7.3.1. User’s data
The System Operator shall require Users to provide data and information as detailed in
Appendixes 6 and 7 on a regular basis, in order for the System Operator in conjunction
with the TSP to undertake the planning and development of the Transmission System in
accordance with international standards. Information received for this purpose shall be
treated as Transmission System planning data.
7.3.2. Additional data
The System Operator or the TSP shall require additional data or information from a
User when the System Operator considers it necessary. The User shall submit the
information to the System Operator without delay. Such information may be required so
that the System Operator and/or TSP can:
(a) Plan and develop the Transmission System in accordance with the relevant
standards
(b) Monitor Power System performance and predict Power System performance
(c) Fulfil its statutory or regulatory obligations.
7.3.3. Plant modification
In planning for the development of the Transmission System, the System Operator or
the TSP may require an individual User or group of Users, to modify or install new Plant
or Apparatus, where the System Operator can reasonably show that it is prudent or
necessary to do so. If the work is to be a significant benefit to the User(s), the expenses
shall be borne by the User(s) otherwise by the TSP.
7.3.4. Objection
The User(s) may object on grounds that to modify or install new Plant or Apparatus as
required, in accordance with Good Utility Practice, would be technically or financially

infeasible. This may include, but shall not be limited to, for example, the installation of
Power System Stabilisers. Such objection shall be dealt with under the terms of the
User’s Grid Connection Agreement.
7.3.5. Closing down
The User shall give the System Operator at least a 24-calendar-month notice if the User
plans for any Generating Units with registered capacity greater than 10 MW:
(a) to close down, retire or withdraw it from service; or
(b) to cease to maintain and keep it available.
The TSP shall give the System Operator at least a 24-calendar-month notice if the TSP intends
to remove any transmission circuit or transformer.

8. SECTION: DATA REQUIREMENTS FOR LONG TERM
PLANNING
8.1. INFORMATION REQUIRED
8.1.1. In order to develop the Long Term Expansion Plan, the System Operator shall use
the guidelines and data requirements indicated in Appendices 5, 6, 7 to specify the technical,
design criteria and procedures to be applied in the planning and development of the Nigeria
Transmission Network. This information shall be taken into account by Users, when
planning and developing their own Plant and Equipment connected to the network.
8.1.2. For Network Planning, User information required as stipulated in Appendices 5, 6, 7
includes data on:
(a) Standard Planning Data
(b) Detailed Planning Data
(c) Network Planning data (Forecast and Registered)
(d) Connection Planning Data
8.1.3. Standard Planning Data:
This is the data a User, whether already connected or seeking such connection to the
Transmission Network, shall provide the TSP of its Plant or Equipment at the
Connection Site, which may have impact on the performance of the Nigeria Electricity
Network. In addition each Embedded Generating Unit with capacity greater than
1.0MW connected to the Distribution Network shall provide the TSP with fault infeed
data as specified in this Code.
User shall provide the TSP a Single Line Diagram, depicting both its existing and
proposed arrangement(s) of load current carrying Equipment relating to both existing
and proposed Connection Points that can impact on the Network performance.
8.1.4. Detailed Planning Data:
These are additional detailed data, where it may apply, of the Users Plant and Equipment
required by the TSP to conduct further studies if the Users Plant and Equipment might
have serious impact on the Transmission Network or existing Users already connected to
the Network before allowing the User to connect to the Network. This data must be
provided within 30 Business Days after request.
8.1.5. Network Planning Data:
The data required in this category is in Appendix 7.
8.1.6. Connection Planning Data:
The Grid Code requires that at the time the TSP signs a Grid Connection Agreement
with the User, estimated values assumed in the Standard Planning Data for planning
purposes are confirmed or where practicable replaced by validated actual values. This

data is then termed Connection Planning Data. Connection Planning Data is divided
into:
(a) Forecast Data – items in the Standard Planning and Detailed Planning Data that
will always be forecast data.
(b) Registered Data – items in the Standard Planning and Detailed Planning Data
which upon connection to the network become fixed (subject to any subsequent
changes).
Connection Planning Data and other relevant Data held by the TSP when a new
application is made shall form the background against which such application shall be
considered and against which planning for the entire network will be based. With the
exception of other data, Users Registered Data shall be treated as non-confidential.
8.2. STANDARD PLANNING DATA
8.2.1. User’s System Layout
Users connected or seeking connection to the Transmission Network shall provide
Single Line Diagram, depicting both its existing and proposed arrangement(s) of load
current carrying Equipment relating to both existing and proposed Connection Points.
The Single Line Diagram to be supplied is in addition to the operational diagram.
The Single Line Diagram must include all parts of the User System operating at
Transmission and sub Transmission Voltages at the Connection Site. Such diagram must
include all parts of the User’s sub-Transmission System operating at voltages greater than
20kV which under either intact Network or Planned Outage conditions:
(a) normally interconnects separate Connection Points, or busbars at a Connection
Point which normally run in separate sections; or
(b) connects Embedded Generating Units connected to the User’s Sub-
transmission System to a Connection Point.
The Single Line Diagram should also contain additional details of the User’s sub-
Transmission System not already included above and also details of the bulk power
transformers connecting the User’s sub-Transmission System to a lower voltage, plus
points at which demand Data and fault infeed data are supplied.
8.2.2. The Single Line Diagram shall include:
Electrical circuitry (i.e. overhead lines, identifying which circuits are on the same towers,
underground cables, power transformers, reactive compensation Equipment and similar
Equipment); and
(a) Substation names (in full or abbreviated form) with Operating Voltages
(b) Circuit breakers
(c) Phasing arrangements

For each circuit shown on the Single Line Diagram, each User shall provide the
following details relating to that part of its Users System:
Circuit Parameters:
 Rated voltage (kV)
 Operating voltage (kV)
 Positive phase sequence reactance
 Positive phase sequence resistance
 Positive phase sequence susceptance
 Zero phase sequence reactance (both self and mutual)
 Zero phase sequence resistance (both self and mutual)
 Zero phase sequence susceptance (both self and mutual)
For each transformer shown in the Single Line Diagram, User shall provide the
following:
 Rated MVA
 Voltage Ratio
 Winding arrangement
 Positive sequence reactance (max, min, nominal tap)
 Positive sequence resistance (max, min, nominal tap)
 Zero sequence reactance
In addition for all interconnecting bulk transformers between the User’s Transmission
Voltage System and the User’s sub-Transmission System, the User shall supply the
following
 Tap changer range
 Tap changer step size
 Tap changer type: on load or off circuit
 Earthing method: direct, resistance or reactance
 Impedance (if not directly earthed)
User shall supply the following about the User’s Equipment installed at a Transmission
Site:
 Switchgear: For all circuit breakers:-
o Rated voltage (kV)

o Operating voltage (kV)
o Rated 3-phase rms short-circuit breaking current (kA)
o Rated 1-phase rms short-circuit breaking current (kA)
o Rated 3-phase peak short-circuit making current (kA)
o Rated 1-phase peak short-circuit making current (kA)
o Rated rms continuous current (A)
o DC time constant applied at testing of asymmetrical breaking abilities (rms)
 Substation Infrastructure
(This includes but not limited to load switches, isolators, current transformers, line
traps, busbars, through bushings etc.)
o Rated 3-phase rms short-circuit withstand current (kA)
o Rated 1-phase rms short-circuit withstand current (kA)
o Rated 3-phase peak short-circuit withstand current (kA)
o Rated 1-phase peak short-circuit withstand current (kA)
o Rated rms continuous current (A)
 Lumped System Susceptance
For all parts of the User’s Subtransmission System which are not included in the
Single Line Diagram, each User shall provide the equivalent lumped shunt
susceptance at nominal Frequency. This should include shunt reactors connected to
cables which are not normally in or out of service independent of the cable (i.e. they
are regarded as part of the cable), but not including independently switched reactive
compensation Equipment connected to the User’s System, or any susceptance of the
User’s system inherent in the Demand (Reactive Power) data specified under this
Code.
 Reactive Compensation Equipment
For all independently switched reactive compensation Equipment including that
shown in the Single Line Diagram, not operated by TCN and connected to the User’s
System at 33kV and above, the following information is required:
o Type of Equipment (fixed or variable)
o Capacitive and/or inductive rating or its operating range in MVAr
o Details of any automatic control logic to enable operating characteristics to
be determined
o The point of connection to the User’s System in terms of electrical location
and network voltage.
8.2.3. Short Circuit Contribution to the TSP Transmission Network

(a) General
To allow the TSP and System Operator to calculate fault currents, each User is
required to provide data, calculated in accordance with best international practice as
set out in this Code.
The data should be provided from the User’s System with all Generating Units
Synchronised to that User’s System. The User must ensure that the pre-fault
network conditions reflect a credible System operating arrangement.
The list of data items required, in whole or part under the following provisions is set
out in Section 8.2.4. The fault currents in sub-paragraphs (a) and (b) of the data list
in Section 8.2.4 should be based on a.c. load flow that takes into account any pre-
fault current flow across the point of connection being considered.
Where prospective short-circuit currents on Equipment owned, operated or
managed by the TSP are close to the Equipment rating, and in TSP or System
Operator’s reasonable opinion more accurate calculations of the prospective short
circuit currents are required, then the TSP may request additional short circuit data.
(b) Data from Directly Connected Customers
Directly Connected Customers at each Node on the Single Line Diagram provided
to the TSP shall provide motor loads and/or Embedded Generating Units and other
installations of direct current converters which do not form a DC converter Station
assuming a fault at that location, as follows:-
The data items listed under the following parts of 8.2.4
(a) (i), (ii), (iii), (iv), (v) and (vi)
And the data items shall be provided in accordance to detailed provisions of
8.2.4(c)–(f).
(c) Data from User’s Generating Unit in a Power Station
For each Generating Unit in a User’s Power Station, with one or more associated
Unit Transformer(s), the User is required to provide values for the contribution of
the Power Station Auxiliaries (including Auxiliary Gas Turbine or Auxiliary Diesel
Engines) to the fault current flowing through the Unit Transformer(s). The data
items listed under the following parts of 8.2.4(a) should be provided:-
(i), (ii) and (v)
(iii) if the associated Generating Unit step-up transformer can supply zero phase
sequence current from the Generating Unit side to the Transmission Network
(iv) if the value is not 1.0 p.u.
The data item shall be provided in accordance with the provisions of 8.2.4(c)–(f).
Auxiliary motor short circuit contribution and any Auxiliary Gas Turbine Unit
contribution through the Unit Transformers must be represented as a combined

short circuit current contribution at the Generating Unit’s terminals, assuming a
fault at that location.
If the User’s Power Station has separate Station Transformers, data should be
provided for the fault current contribution from each transformer at its high voltage
terminals, assuming a fault at that location as follows:-
The data items listed under the following parts of 8.2.4
(a) (i) to (vi)
And the data items shall be provided in accordance with the detailed provisions
of 8.2.4(b)-(f)
Data for the fault infeeds through both Unit and Station Transformers shall be
provided for the normal running arrangement when the maximum number of
Generating Units are Synchronised to the Network. Where there is an alternative
running arrangement which can give higher fault infeed through the Station
Transformers, then a separate data submission representing this condition shall be
made.
No account should be taken of the interconnection between the Station and Unit
Board, unless the normal operating arrangement within the Power Station is to have
the Station and Unit Boards interconnected within the Power Stations.
Auxiliary motor short circuit current contribution through the Station Transformers
must be represented as a combined short circuit contribution through the Station
Transformers.
8.2.4. Data Items
(a) Below is the list of data utilised in this part of the Planning Chapter. It also
contains rules on the data which generally apply:-
(i) Root mean square of the symmetrical three-phase short circuit current infeed
at the instant of fault (I1”).
(ii) Root mean square of the symmetrical three-phase short circuit current after
the subtransient fault current contribution has substantially decayed (I1’).
(iii) The zero sequence source resistance and reactance values of the User’s
Equipment as seen from Node on the Single Line Diagram provided under
8.2.1 (or Station Transformer high voltage terminals or Generating Unit
terminals as appropriate) consistent with the infeed described in 8.2.1
(iv) Root mean square of the pre-fault voltage at which the maximum fault
currents were calculated;
(v) The positive sequence X/R ratio at the instant of fault
(vi) The negative sequence resistance and reactance values of the User’s
Generating unit seen from Node on the Single Line Diagram provided under
8.2.1 (or Station Transformer high voltage terminals or Generating Unit
terminals, if appropriate) if substantially different from the values of positive

sequence resistance and reactance which would be derived from the data
provided above.
(b) In considering this data, unless the User notifies TCN accordingly at the time of
data submission, TCN will assume that the time constant of decay of the
subtransient fault current corresponding to the change from I1” to I1’ (T”) is
not significantly different from 40ms. The User must inform TCN if the
assumption is not correct in relation to an item of data.
(c) The value for X/R ratio must reflect the rate of decay of the d.c. component
that may be present in the fault current and hence that of the sources of the
initial fault current. All shunt elements and loads must therefore be deleted from
any system model before the X/R ratio is calculated.
(d) In producing the data, the User may use “time step analysis” or “fixed-point-in-
time analysis” with different impedances.
(e) If a fixed-in-time analysis with different impedances method is used, then in
relation to the data submitted under (a) (i) above, the data will be required for
“time zero” to give I1”. The figure of 120ms is consistent with a decay time
constant T” of 40ms, and if that figure is different, then the figure of 120ms
must be changed accordingly.
(f) Where a “time step analysis” is carried out, the X/R ratio may be calculated
directly from the rate of the d.c. component. The X/R ratio is not that given by
the phase angle of the fault current if this is based on a system calculation with
shunt loads, but from the Thevenin equivalent of the System impedance at the
instant of fault with all non-source shunts removed.
8.3. GENERATING UNIT DATA
8.3.1. Directly Connected Generating Unit
Each Generator with an existing, or proposed Power Station directly connected, or to be
directly connected, to the Nigeria Transmission System, shall provide the TSP with data
relating to that Power Station both current and forecast as specified in 8.3.2 to 8.3.3.
On receipt of this data, the Generator may be further required by the TSP or System
Operator to provide details of Embedded Generating Unit data.
Where Generating Units which term includes CCGT Units are connected to the
Transmission Network via a busbar arrangement which is or is expected to be operated
in separate sections, the section of busbar to which each Generating Unit is connected is
to be identified in the submission.
8.3.2. Output Data
Items (a) to (i) listed below shall be supplied by each User for its Generating Units, in
accordance with the type of Generating Unit involved:
 Power Stations and Generating Units:

Data items 8.3.2(a) to (h) are required with respect to each Power Station and each
Generating Unit of each Power Station.
 Embedded Generating Units
Data item 8.3.2 (a) is required with respect to each Embedded Generating Unit and
Generating Unit.
 CCGT Units/Modules
Data item 8.3.2(g) is required with respect to each CCGT unit.
Data item 8.3.2(a) is required with respect to each CCGT Module
Data item 8.3.2(b), (c), (d) and (e) are required with respect to each CCGT Module
unless TCN informs relevant User in advance of the submission that it needs the
data item with respect to each CCGT Unit. Where any definition utilised or referred
to in relation to any of the data items does not reflect CCGT Units, such definition
shall be deemed to relate to CCGT Units for the purpose of these data items.
 Hydro Schemes
Data item Appendix 5 is required with respect to each Hydro Scheme.
(a) Data Items: Registered Capacity (MW)
(b) Output Usable (MW) on a monthly basis
(c) Network Constrained Capacity (MW) which may be placed on the capacity of
an Embedded Generating Unit due to Distribution Network Operator’s System
in which it is embedded. Where the Embedded Generating Unit connected to a
Distribution Network via a busbar arrangement which is or is expected to be
operated in separate sections, details of the busbar arrangements and connected
circuits at the substation to which the Embedded Generating Unit is connected
must be provided to TCN to determine where the power generated by the
Embedded Generating Unit would appear on the Transmission Network.
(d) Minimum Generation (MW)
(e) MW obtainable from User’s Generating Units in excess of Registered Capacity.
(f) Generating Unit Capability Chart:
(i) at the synchronous Generating Unit stator terminals
(ii) at the electrical points of connection to the Transmission Network (or User
System if Embedded) for a non-synchronous Generating Unit
(g) A list of CCGT Units within a CCGT Module, identifying each CCGT Unit and
the CCGT Module of which it forms part, this must be unambiguous in the case
of a Range CCGT Module:
(i) details of the possible other CCGT Module configurations should also be
submitted,

(ii) for each case details of the single Grid Connection Point at which power is
provided from the Range CCGT Module shall be submitted,
(iii) these requirements apply to Embedded Range CCGT Modules.
(Nothing shall prevent the busbar at the relevant point being operated in separate
sections)
(h) Expected running regime(s) at each Power Station and type of Generating Unit
(e.g. Steam Unit, Gas Turbine Unit, Combined Cycle Gas Turbine Unit, etc.)
(i) A list of Power Stations and Generating Units within a cascade Hydro Scheme,
identifying each Generating Unit and Power Station and the cascade Hydro
Scheme of which each form part unambiguously. In addition:
(i) details of the Transmission Network Entry Point at which Active Power is
provided, or if Embedded the Transmission Network Supply points within
which the Generating Unit is Connected.
(ii) where the Active Power output of a User Generating Unit is split between
more than one Transmission Network Supply Point the percentage that
would appear under normal and Outage conditions at each Transmission
Network Supply point.
Without prejudice to paragraph (g) above, identification of CCGT Units within a CCGT
Module can only be amended in accordance with the following provision:
If the CCGT Module is a Normal or Range CCGT Module, the CCGT Units
within that Module can only be amended if TCN gives its prior consent in
writing. At least 6 months notice of desire to amend the CCGT Units within such
CCGT Module must be given before the amendment can take effect.
8.3.3. Rated Parameter Data
The following information is required to facilitate an early assessment of the need for
more detailed studies:
(a) For all User’s Generating Units – Rated MVA, Rated MW
(b) For each synchronous Generating Unit:
(i) Short circuit ratio
(ii) Direct axis transient reactance
(iii) Inertia constant for whole machine, MWsecs/MVA
(c) For each synchronous Generating Unit step-up transformer:
(i) Rated MVA
(ii) Positive sequence reactance (at max, min and nominal tap)

8.4. DEMAND AND ACTIVE ENERGY DATA
8.4.1. Introduction
Each User directly connected to the Transmission Network with Demand shall provide
TCN with Demand data – historic, current and forecast, as specified in this Code, which
applies equally to Active Energy requirements and to Demand unless the context
otherwise requires.
Data will need to be supplied by
(a) Users, in relation to Demand and Active Energy requirements on the User’s
System
(b) Directly Connected Customer in relation to its Demand and Active Energy
requirements
8.4.2. Active Power and Energy Data
Forecast daily Demand (Active Power) profiles as specified in (a), (b) and (c) below, in
respect of each of the User’s Systems (each summed over the Transmission Network
Supply Points in each User System) are required for:
Peak day on each of the User’s Systems giving the numerical value of the maximum
Demand (Active Power) that in the Users’ opinion could reasonably be imposed on the
(a) Day of peak Demand on the Transmission Network (Active Power) as notified
by System Operator.
(b) Day of minimum Demand on the Transmission Network (Active Power) as
notified by System Operator.
(c) In addition, the total Demand (Active Power) in respect of the time of peak of
the Transmission Network Demand in the preceding year for each of the User’s
Systems summed over the Transmission Network Supply points, for actual and
weather corrected values shall be supplied.
8.4.3. In order that Users can provide the above data the SO shall by calendar week 20,
inform Users of the Transmission Network in writing of the following, for the current year
and each of the subsequent 5 years, which will apply until replaced by the following year’s
notification:
(a) The date and time of the annual peak of the Transmission Network Demand.
(b) The date and time of the annual minimum of the Transmission Network
Demand.
(c) Total Active Demand used on each of the grid Supply Points in the preceding
year, together with a prediction of the current financial year, is required.
8.4.4. Each Active Energy submission required in Subsection 8.4.2 shall be subdivided into
the following categories of Customer tariff:

(i) Domestic customers
(ii) Commercial customers
(iii) Industrial customers
(iv) Customers connected at 33kV and above
(v) Traction
(vi) Street lighting and special customers
In addition, the total User losses and Active Energy provided by Distributed
Generating Units shall be supplied.
8.5. DETAILED PLANNING DATA
8.5.1. Introduction
(a) Directly Connected
Each User with existing Power Station(s) directly connected or to be directly
connected to TCN network shall provide TCN with data relating to the Plant and
Equipment, both current and forecast as in 8.5.2 as applicable.
(b) Embedded
Users with existing or proposed Embedded Generating Unit(s) shall provide TSP
with data relating to the Embedded Generating Unit(s) both current and forecast.
(c) Demand
For each User’s Generating Unit which has an associated Unit Transformer, the
value of the Demand supplied through this Unit Transformer when the Generating
Unit is at Rated MW output is to be provided.
Where the Power Station has associated Demand additional to the unit supplied
Demand which is supplied from either the Transmission Network or the
Generator’s User’s Equipment the Generator User shall supply forecasts for each
Power Station of:
The maximum Demand that in the User’s opinion could reasonably be imported
from grid network or the Generator’s User Equipment as appropriate;
(i) The Demand at the time of peak TCN Network Demand;
(ii) The Demand at the time of minimum TCN Network Demand.
In order that Users can provide the above data, the SO shall by calendar week 20,
inform Users of the Transmission Network in writing of the following, for the
current year and each of the subsequent 5 years, which will apply until replaced by
the following year’s notification:
(iii) The date and time of the annual peak of the Transmission Network Demand

(iv) The date and time of the annual minimum of the Transmission Network
Demand
8.5.2. Synchronous Generating Unit and associated control system data
The following synchronous Generating Unit and Power Station data should be supplied
(a) synchronous Generating Unit Parameters
(i) Rated terminal volts (kV)
(ii) Rated MVA
(iii) Rated MW
(iv) Minimum generation MW
(v) Short circuit ratio
(vi) Direct axis synchronous reactance
(vii) Direct axis transient reactance
(viii) Direct axis sub-transient reactance
(ix) Direct axis short-circuit transient time constant
(x) Quadrature axis synchronous reactance
(xi) Quadrature axis sub-transient reactance
(xii) Quadrature axis short-circuit sub-transient time constant
(xiii) Stator time constant
(xiv) Stator leakage reactance
(xv) Armature winding direct-current resistance
(xvi) Turbogenerator inertia constant (MWsec/MVA)
(xvii) Rated field current (amps) at rated MW, rated MVAr export and at rated
terminal voltage
(xviii) Field current (amps) open circuit saturation curve for Generating Unit
terminal voltages ranging from 50% to 120% of rated value in 10% steps as
derived from appropriate manufacturer’s test certificates.
(b) Parameters for Generating Unit Step-up Transformer(s)
(i) Rated MVA
(ii) Voltage ratio
(iii) Positive sequence reactance (at max, min & nominal tap)
(iv) Positive sequence resistance (at max, min & nominal tap)
(v) Zero phase sequence reactance
(vi) Tap changer range

(vii) Tap changer step size
(viii) Tap changer type-on load or off load
(c) Excitation control system parameters
(i) Excitation Equipment nominal response
(ii) Rated field voltage
(iii) No-load field voltage
(iv) Excitation Equipment on-load positive ceiling voltage
(v) Excitation Equipment no-load positive ceiling voltage
(vi) Excitation Equipment no-load negative ceiling voltage
(vii) Details of excitation Equipment described in block diagram form showing
transfer functions of individual elements
(viii) Details of over-excitation limiter described in block diagram form showing
(ix) Details of under-excitation limiter described in block diagram form showing
(d) Governor parameters
(i) Incremental droop values (in %) are required for each Generating Unit at six
MW loading points (MLP1 to MLP6).
(ii) Governor and associated prime mover parameters – All Generating Units
o Governor Block diagram showing transfer function of individual elements
including acceleration sensitive elements
o Governor time constant (in seconds)
o Speeder motor setting range (%)
o Average gain (MW/Hz)
o Governor deadband – maximum setting (+/- Hz), normal setting (+/-
Hz), minimum setting (+/- Hz)
(where the Generating Unit governor does not have a selectable deadband
facility, then the actual value of the deadband need only be provided)
(iii) Governor and associated prime mover parameters (Steam Units):
o HP valve time constant (in seconds)
o HP valve opening limits (%)
o HP valve opening rate limits (% /second)
o HP valve closing rate limits (%/second)
o HP turbine time constant (in seconds)

o IP valve time constant (in seconds)
o IP valve opening limits (%)
o IP valve opening rate limits (% /second)
o IP valve closing rate limits (%/second)
o IP turbine time constant (in seconds)
o LP valve time constant (in seconds)
o LP valve opening limits (%)
o LP valve opening rate limits (% /second)
o LP valve closing rate limits (%/second)
o LP turbine time constant (in seconds)
(iv) Governor and associated prime mover parameters (Gas Turbine Units):
o Inlet guide vane time constant (in seconds)
o Inlet guide vane opening limits (%)
o Inlet guide vane opening rate limits (%/second)
o Inlet guide vane closing rate limits.(% /second)
o Fuel valve constant (in seconds)
o Fuel valve opening limits (%)
o Fuel valve opening rates limits (%/second)
o Fuel valve closing rate limits (%/second)
(v) Governor and associated prime mover parameters – hydro Generating Units
o Guide vane actuator time constant (is seconds)
o Guide vane opening limits (%)
o Guide vane opening rate limits (%/second)
o Guide vane closing rate limits (%/second)
o Water time constant (in seconds)
(vi) Unit control options
o Maximum droop %
o Normal droop %
o Minimum droop %
o Maximum Frequency deadband +/- Hz
o Normal Frequency deadband +/- Hz
o Minimum Frequency deadband +/- Hz

o Maximum output deadband +/-MW
o Normal output deadband +/-MW
o Minimum output deadband +/-MW
(vii) Frequency settings between which Unit load controller droop applies:
o Maximum Hz
o Normal Hz
o Minimum Hz
(viii) Plant Flexibility Performance
o Run-up rate to registered capacity
o Run-down rate from registered capacity
o Synchronising generation
o Regulating range
o Load rejection capability while still Synchronised and able to supply Load.
(ix) Response data for Frequency changes
Prior to the Generating Unit being first Synchronised, the MW loading
points must take the following values:
o MLP1 Designed minimum operating level
o MLP2 Minimum generation
o MLP3 70% of Registered Capacity
o MLP6 Registered Capacity
(x) Primary and Secondary Response to Frequency Fall
Primary and Secondary Response values for a -0.5Hz step are required at six
MW Loading Points (MLP1 to MLP6) as detailed above.
(xi) High Frequency Response to Frequency Rise
High Frequency Response valves for a +0.5Hz step are required at six MW
loading points (MLP1 to MLP6)
8.6. TRANSIENT OVER-VOLTAGE ASSESSMENT DATA
8.6.1. Each User is required to provide the following data with respect to the Connection
Site, current and forecast, together with a Single Line Diagram if not already provided:

(a) Busbar layout plan(s), including dimension and geometry showing positioning
of any current and voltage transformer, through bushings, support insulators,
isolators, circuit breakers, surge arrestor etc. Electrical parameters of any
associated current and voltage transformer, stray capacitance, off wall bushings
and support insulators, and giving capacitances of circuit breakers;
(b) Electrical parameters and physical construction details of lines and cables
connected at the busbar. Electrical parameters of all Plant (e.g. transformers-
including neutral earthing impedance or zigzag transformers if any), series
reactors and shunt compensation Equipment connected at that busbar (or to
the tertiary of a transformer) or by lines or cables to the busbar;
(c) Basic insulation levels of all Equipment connected directly by lines or by cables
to the busbar;
(d) Fault levels at the lower voltage terminals of each transformer connected
directly or indirectly to the TSP Network without intermediate transformation;
and
(e) All transformers operating at 132kV and over, three or five limb cores or single
phase units to be specified and operating peak flux density at nominal voltage.
8.7. USER’S PROTECTION DATA
8.7.1. Protection
The following information is required, which relates only to protection Equipment
which can trip or inter-trip or close any Connection Point circuit breaker or any TCN
circuit breaker. This information need to be supplied once and regular updates made
afterwards:
(a) Full description, including estimated settings, for all relays and protection
systems installed or to be installed on the User’s System;
(b) Full description of auto-reclose facilities installed or to be installed on the User’s
System, including type and time delays;
(c) Full description, including estimated settings, for all relays and Protection
systems installed or to be installed on the Generating Unit, Generating Unit
transformer, Station transformer and their associated connections;
(d) Generating Units having (or intended to have) a circuit breaker at the
Generating Unit terminal voltage, clearance times for electrical faults within the
Generating Unit zone; and/or
(e) Most probable fault clearance time for electrical faults on any part of the User’s
System directly connected to TCN Network.
8.7.2. Harmonic Studies
In the course of operating the Transmission Network, the System Operator or the TSP
will have to evaluate the occurrence of harmonic distortion on the Network or User’s

Systems, especially when Equipment like capacitor banks is involved. For proper
evaluation, in respect of the Connection Site, Users are required to submit current and
forecast data if not already submitted under 8.2 for any sub-Transmission System for
overhead and underground cable circuits:
For transformers connecting the User’s Subtransmission System to a lower voltage:
 Rated MVA
 Voltage Ratio
And at the lower voltage points of those connecting transformers:
 Equivalent positive phase sequence susceptance
 Connection voltage and MVAr rating of any capacitor bank and component
parameters if designed as a filter
 Equivalent positive phase sequence interconnection impedance with other lower
voltage points
 The minimum and maximum Demand (both MW and MVAr) that could occur
 Harmonic current injection sources in Amps at the Connection voltage points
 Details of traction load (e.g. connection phase pairs, continuous variation with time
etc.)
 An indication of which items of Equipment may be out of service simultaneously
during planned Outage condition
8.7.3. Voltage Assessment Studies
In the course of operating the Transmission Network, the System Operator will have to
undertake voltage assessment studies on the Network to examine potential voltage
instability, Voltage Control co-ordination or calculate voltage step changes. Users are
required, to submit current and forecast data if not already submitted under section 8.2
for any Subtransmission System for overhead and underground cable circuits:
(a) For User’s Subtransmission System:

 MVAr rating of any reactive compensation Equipment
(b) For bulk transformers connecting the User’s Subtransmission System to a lower
voltage:
 Rated MVA
 Voltage Ratio
 Tap-changer range
 Number of tap steps
 Tap-changer type: on-load or off-circuit
 AVC/tap-changer time delay to first tap movement
 AVC/tap-changer inter-tap time delay
(c) And at the lower voltage points of those connecting transformers:
 Equivalent positive phase sequence susceptance
 MVAr rating of any reactive compensation Equipment
 Equivalent positive phase sequence interconnection impedance with other lower
voltage points
 Maximum demand (MW, MVAr) that could occur.
8.8. NETWORK DATA
8.8.1. If a User wants to model the Transmission Network, the TSP shall provide the
Network data indicated in 8.8.2 to allow the User properly calculate conditions on the
Network.
8.8.2. Single and Multiple Point Connection
The TSP, or System Operator as applicable, shall provide User with the following data:
(a) Symmetrical three phase short circuit current infeed at the instant of fault from
the Transmission System (I1”)
(b) Symmetrical three phase short circuit current from the Transmission System
after the subtransient fault current contribution has substantially decayed (I1’)
(c) Zero sequence source resistance and reactance values at the Point of
Connection, consistent with the maximum infeed

(d) Pre-fault voltage magnitude at which the maximum fault currents were
calculated
(e) Positive sequence X/R ratio at the instant of fault
(f) Negative sequence resistance and reactance values of the Transmission System
seen from the Point of Connection
(g) Initial positive sequence resistance and reactance values of the two or more
sources and the linking impedances derived from a fault study constituting the π
equivalent and evaluated without the User network and load
(h) Corresponding zero sequence impedance values of the π equivalent
(i) The TSP or System Operator, as applicable, shall provide additional reasonable
and relevant information as requested by User.
The positive sequence X/R ratio and zero sequence impedance will correspond to
the Transmission Network only.

CHAPTER 3: CONNECTION CONDITIONS
9.1. OBJECTIVE
9.1.1. This Connection Conditions Chapter specifies the minimum technical, design and
certain operational criteria which must be complied with by the Users connected to, or
seeking connection to the Transmission Network. They also set out the procedures by which
the Transmission Service Provider (TSP) will process an application for connection to the
Transmission System, seeking to ensure compliance with these criteria as a requirement for
the granting of approval for the connection of a User to the Transmission System.
9.1.2. The provisions of the Connection Conditions shall apply to all connections to the
Transmission Network:
(a) existing at the date when this Grid Code comes into effect;
(b) existing at the date of commencement of the TSP’s approval, where these dates
precede the date in (a) above; and
(c) as established or modified thereafter.
9.1.3. The Connection Conditions are designed to ensure that:
(a) No new or modified connection will impose unacceptable effects upon the
Transmission System or on any User network nor will it be subject itself to
unacceptable effects by its connection to the Transmission System.
(b) The basic rules for connection treat all Users within an equivalent category in a
non-discriminatory fashion.
9.2. PURPOSE
9.2.1. The purpose of this Connection Conditions is:
(a) to specify the technical, design, and operational criteria at each Connection
Point;
(b) to ensure that there is no undue discrimination in the application of the Grid
Code between Users or classes of User;
(c) to facilitate the use of the Transmission System by any User connected to or
seeking connection to the Transmission System, in accordance with a Grid
Connection Agreement;
(d) to define the requirements for a User seeking connection and/or for a
modification of the current connection; and
(e) to enable the TCN to develop, maintain and operate the Transmission System
in a coordinated and economic manner in compliance with its licence.

9.3. SCOPE
9.3.1. The Connection Conditions apply to the System Operator, TSP and to Users of the
Transmission System which in this Connection Conditions are:
(a) Generators;
(b) Distributors;
(c) Interconnected parties;

10. SECTION: TRANSMISSION SYSTEM PERFORMANCE
CHARACTERISTICS
10.1. FREQUENCY AND VOLTAGE
10.1.1. In order to maintain the security and integrity of the Transmission System, it is
necessary that the System Operator operates the Transmission System and Dispatches it in
such a manner as to provide adequate Frequency Control to achieve operation within
applicable Frequency limits at all times.
10.1.2. The nominal Frequency of the system shall be 50Hz. The National Control Centre
will endeavour to control the System Frequency within a narrow operating band of +/- 0.5%
from 50Hz (49.75 – 50.25 Hz), but under System Stress the Frequency on the Power System
could experience variations within the limits of 50 Hz +/- 2.5% (48.75 – 51.25 Hz).
10.1.3. All Equipment and Apparatus connected directly or indirectly to the National Grid
must operate at 50Hz Frequency mode.
10.1.4. Under extreme system fault conditions all Generating Units are permitted to
disconnect (unless otherwise agreed in writing with the System Operator):
(a) at a Frequency greater than or equal to 51.50 Hz, provided that for frequency
excursions up to 51.75Hz of no more than 15 seconds it shall remain
synchronised with the system; or
(b) at a Frequency less than or equal to 47.5 Hz.
10.1.5. The System Operator shall endeavour to control the different busbar voltages to be
within the Voltage Control ranges specified in Table 1:
Voltage level Minimum Voltage
kV (pu)
Maximum Voltage
kV (pu)
330 kV 280.5 (0.85) 346.5 (1.05)
132 kV 112.2 (0.85) 145.2 (1.10)
66 kV 62.04 (0.94) 69.96 (1.06)
33 kV 31.02 (0.94) 34.98 (1.06)
11 kV 10.45 (0.95) 11.55 (1.05)
Table 1: Voltage Control ranges
Under System Stress or following system faults, voltages can be expected to deviate outside the
above limits by a further +/-5% (excluding transient and sub-

transient disturbances).
10.1.6. Due to the effect of travelling waves on the Transmission Network as a result of
atmospheric disturbances or the switching of long transmission lines, transient over-voltage
can occur at certain Node points of the network. The insulation level of all Apparatus must
be coordinated to take account of transient over-voltages and sensitive User Equipment, such
as computer and other solid state Equipment, which should be suitably isolated from this
effect.
10.1.7. The transient over-voltage during lightning strikes is typically experienced over a
voltage range of ± 20% of nominal voltage. Connection Points close to a network lightning
strike will experience voltages higher than this.
10.1.8. Unless otherwise agreed by the TSP, the basic insulation value (BIL) for User
Apparatus shall be as follows:
(a) For the 330 kV system, the BIL is 1050 kV.
(b) For the 132 kV system, the BIL is 650 kV.
10.2. VOLTAGE PERTURBATIONS
10.2.1. “Voltage Flicker” is a rapid change in voltage that is typically caused by User
Equipment that distorts or interferes with the normal sinusoidal voltage waveform of the
Transmission System. Such interference is a product of a relatively large current inrush when
Apparatus, such as a large motor, is suddenly switched on, or resulting from the sudden
increased demand from for example welding Equipment. Such distortions can disturb Users
Equipment and cause, for instance through flickering lights, consumer annoyance. The
current inrush acting over the network impedance is the mechanism that produces the
voltage dip (sudden fall) and the corresponding voltage swell (sudden rise) when the
Apparatus concerned is offloaded. Hence, it is the cause of the “Voltage Flicker”.
10.2.2. Users are required to minimise the occurrence of Voltage Flicker on the Transmission
System as measured at the User’s Connection Point. The Flicker Severity at the Connection
Point of any User shall not be above the maximum values stated in IEC 61000-3 Standard for
more than 3 % of the period. The maximum emission limits produced by any User shall be
below the maximum values stated in IEC 61000-3 Standard.
10.2.3. In cases where, in the reasonable opinion of the System Operator, variations in
generation or demand constitute a risk to Transmission System operation, strict conformity
with the IEC 61000-3-7 flicker curve will be required.
10.2.4. Harmonics are normally produced by User’s Apparatus generating waveforms that
distort the fundamental 50 Hz wave. Such harmonic generation can damage User Apparatus
and can result in failure of Transmission System Apparatus. The limits for harmonic
distortion levels are given in the following documents:
(a) EN 50160:2010 “Voltage characteristics of electricity supplied by public
distribution systems”.

(b) IEC/TR3 61000-3-6 ed2.0 (2008) “Assessment of emission limits for distorting
loads in MV and HV power systems”.
10.2.5. In general, the maximum total levels of harmonic distortion on the System under
Normal Operation conditions, planned outages and fault outage conditions (unless during
System Stress) shall not exceed following values:
(a) 330 kV a Total Harmonic Distortion of 1.5% with no individual harmonic
greater than 1%
(b) 132 kV a Total Harmonic Distortion of 2% with no individual harmonic greater
than 1.5%.
10.2.6. Under Normal Operation, the maximum negative phase sequence component of the
phase voltage of the Transmission System should remain below 1%.
10.2.7. Under planned outage conditions, infrequent short duration peaks with a maximum
value of 2% are permitted for phase unbalance.

11. SECTION: CONNECTION PROCESS
11.1. APPLICATION FOR CONNECTION
11.1.1. Application: Users proposing a connection to the Transmission System, either
through a new substation, a modification of an existing substation, or in an existing
substation shall send an application to the TSP. If this demand for new connection falls
outside the approved Regulatory Long Term Transmission Plan, the cost for such works shall
be borne by the User.
11.1.2. Application information: Users shall submit the application on an application form
for a connection to the Transmission System. Amongst other information, the application
form shall include:
(a) A description of the Plant or Apparatus to be connected to the Transmission
System or, the modification relating to the User's Plant or Apparatus already
connected to the Transmission System
(b) Confirmation that the User’s Plant and Apparatus at the Connection Point will
meet the required technical standards in this Grid Code, as agreed with the TSP
where appropriate.
(c) Confirmation that User’s Plant, Apparatus and procedures will meet the safety
provisions in Section 25.
(d) The technical data as stipulated in Appendixes 5, 6 anticipated for the User’s
modified or new Plant or Apparatus, specifying the Load characteristics and
other data. The TSP shall compile a standard list of details required from the
User; and
(e) The desired connection date and operational date of the proposed User’s
development.
(f) A proposed commissioning schedule, including commissioning tests, for the
final approval of the System Operator and the TSP.
11.1.3. Preliminary planning data: Data supplied in the application form or data submitted
along with the application form that is directly relevant to the application and has been
submitted in support of it shall be treated as preliminary planning data until such time as the
offer for a connection has been made and accepted.
11.1.4. To allow adequate time for consideration of the request, the User shall make this
application well in advance prior to the proposed connection date, and in any case not less
than 3 months before such date. It shall be taken into account that typical time periods
required by TCN to undertake the execution of Transmission System expansion projects
necessary for a new connection are:
(a) overhead transmission lines – 18 months; and
(b) substation – 24 months.

11.1.5. Planning data: Transmission System planning data, together with other data held by
the TSP relating to the Transmission System shall form the basis from which new
applications by any User shall be considered and from which planning of the Transmission
System shall be undertaken. Transmission System planning data shall not be treated as
confidential to the extent that the TSP is obliged:
(a) To use it in the preparation of the forecast;
(b) To use it when considering and/or advising other Users;
(c) To use it for the SO planning purposes; and
(d) Under the terms of a Grid Connection Agreement to pass it on as part of
system information on the Power System.
11.1.6. Type of data: Transmission System planning data is divided into the following type of
data:
(a) Which will always be forecast, known as forecast data;
(b) Which upon connection becomes fixed, known as Registered Information; and
(c) Which relate to Plant, Equipment or Apparatus for the purposes of the Plant
concerned as at the date of submission, known as Registered Information, but
which for the ten succeeding years shall be an estimate of what is expected,
known as estimated Registered Information.
11.1.7. Actual data: Users shall supply the TSP with all outstanding data as stipulated in
Appendixes 6 and 7 not later than the operational date if not previously requested by the
TSP. This shall include confirming any estimated values assumed for planning purposes or,
where practical, replacing them by validated actual values and by updated estimates for the
future and by updating forecasts for forecast data items.
11.1.8. Additional information: The TSP shall request that a User supply additional
information, as the TSP deems necessary to verify the accuracy of the data received, if in the
opinion of the TSP it is incorrect.
11.1.9. Tests for data verification: The TSP or the System Operator shall request that the
User carry out specific tests, at the User’s expense, to verify the data, if it maintains that the
additional information is insufficient to verify the accuracy of the original. Where such a test
or tests are requested, they shall be subject to the provisions of the relevant Section of the
Grid Code.
11.1.10.Costs for tests:
(a) The TSP shall carry all costs incurred as a result of the test or tests in the event
that the initial data as submitted by the User is verified by the test or tests to be
correct.
(b) The User shall carry all costs incurred as a result of the test or tests in the event
that the data as submitted by the User is verified by the test or tests to be
incorrect. If the TSP has to redo or perform additional system studies then the

User shall also bear the costs reasonably incurred as a result of the said
additional work.
11.2. PROCESS OF THE APPLICATION
11.2.1. The TSP shall establish a Procedure for the processing of applications for connection
or modification of an existing connection to the Transmission System. This shall include the
time frames required to process the application and to submit to the User an offer for
connection. This Procedure will be approved by the NERC.
11.2.2. System studies: Based on the data supplied by the User, the TSP will coordinate with
the System Operator to perform the system impact studies required to evaluate in detail the
impact of the proposed User development on the Transmission System (the magnitude and
complexity of any Transmission System extension or reinforcement varies according to the
nature, location and timing of the proposed User’s development).
11.2.3. Users’ studies: Upon request of the User, the TSP shall provide to the User adequate
and sufficient information regarding the Transmission System, to enable the User conduct
Impact Studies on the User’s system, and/or the Transmission System as it considers
appropriate.
11.2.4. Plant parameters: The Users shall provide the TSP with all the relevant Plant or
Apparatus parameters as required from Appendixes 5, 6 and 7 before SO shall proceed with
the above-mentioned System studies.
11.2.5. During the application for connection process, based on the results of the System
Studies, the TSP will agree with the User the voltage level and point of connection to the
Transmission System. The TSP may, eventually, specify a different Connection Point or
connection voltage in order to avoid potential disturbance caused by the User’s Equipment to
other Users of the Transmission System or for other technical reasons, or may agree
alternative methods for minimizing the effects of disturbing loads.
11.2.6. In determining the point of connection, including the voltage level, the following
aspects shall to be taken into consideration:
(a) No discrimination: In assessing the technical requirements of a User's
connection, the TSP shall not unfairly discriminate between Users of a similar
category, location or size, although it shall not be technically or economically
practicable to achieve uniformity of method of connection at all times.
(b) Generator voltage level: the Transmission System voltage level and the busbar
configuration at which a Generator shall be connected to the Transmission
System shall depend upon, but shall not be limited to the following:
(i) The size of the Generating Units and the number of Generating Units
comprised in the potential User’s System;
(ii) Consistency with future development of the Transmission System;
(iii) Proximity to the existing Transmission System; and
(iv) The cost of the proposed connection.

(c) Directly Connected Customers voltage level: The Transmission System voltage
level at which a Directly Connected Customers shall be connected to the
Transmission System shall depend upon, but shall not be limited to the
following:
(i) The size of the Active Power Demand at the Connection Point;
(iii) Proximity to the existing Transmission System; and
(iv) The cost of the proposed connection.
(d) Distribution voltage level: The Transmission System voltage level at which a
Distributor shall be connected to the Transmission System shall depend upon
but shall not be limited to the following:
(i) The size of the Active Power Demand at the Connection Point;
(iii) Consistency with coordinated planning of the Transmission System and of
the Distribution System;
(iv) Proximity to the existing Transmission System; and
(v) The cost of the proposed connection.
(e) Method of connection: The method of connection used may exceed the
relevant standards where the User requires it. In this case the TSP shall accept
this provided:
(i) it has no consequent negative impacts on the System or on other Users; and
(ii) the User pays all relevant costs associated with this higher standard.
11.2.7. After evaluating the application submitted by the User, the TSP shall inform the User
whether the proposed application is acceptable or not. The TSP may disapprove an
application for connection or a modification of an existing connection to the Transmission
System only if it is determined through System Studies that the proposed connection or
modification does not fulfil the technical requirements or results in the degradation of the
Transmission System.
11.2.8. If the application of the User is not acceptable:
(a) The TSP shall notify the User as to why its application is not acceptable.
(b) The TSP shall include in its notification details of the amendments required to
make the User’s application acceptable to the TSP.
(c) The TSP shall immediately report any rejected application to the NERC.
11.2.9. Offer detail: In case the application is accepted, the TSP shall submit to the User an
offer to connect to the Transmission System. This Connection Offer shall include, but shall
not be limited to the following:

(a) Details of how the connection shall be made, including details of the Plant and
Apparatus that shall be required to implement the connection;
(b) A description of any modification that the applicant User shall be required to
pay for;
(c) An indication of the connection date and the operational date; and
(d) An estimate of the charges for connection.
11.2.10.Acceptance of the offer: A connection offer shall provide that the applicant User
accepts it within the period stated in the offer, which shall never be less than forty five (45)
days, after which the offer shall automatically lapse. Acceptance of the offer shall be effected
by execution of the Grid Connection Agreement by both parties, which renders the TSP
works relating to that User development committed and shall bind both parties in accordance
with its terms. The User shall supply the data pertaining to the User’s development within
sixty (60) days of acceptance of the connection offer.
11.2.11.Committed planning data: Once a connection offer has been accepted, all data
supplied in the application form and any other data submitted along with the application
form, shall be treated as committed project planning data.
11.3. GRID CONNECTION AGREEMENT
11.3.1. The acceptance by the User of the TSP proposal shall lead to the signing of a Grid
Connection Agreement. If TSP and the User cannot reach agreement on the proposed
connection, or modification to an existing connection, the User shall have the right to bring
the matter before the NERC for resolution. The NERC shall have reasonable right of access
to any information that it deems fit in order to resolve such disagreement.
11.3.2. Before entering into a Grid Connection Agreement and before connecting a User’s
System at a Connection Point, it will be necessary for the TSP to be reasonably satisfied that
the User’s System at the boundary with the Transmission System will comply with all
appropriate requirements of this Grid Code.
11.3.3. The Grid Connection Agreement is a site specific Agreement between TSP, System
Operator and a User of the Transmission Network. The agreement shall cover all technical
issues involving connection, energisation and operation of generating units connected to the
Transmission Network and/or centrally despatched by the System Operator. Amongst other
topics, the agreement shall cover the following areas:
(a) Construction or upgrading of substation and /or Transmission Network
(b) Connection of Generating Unit or Equipment to substation and / or
Transmission Network
(c) Commissioning and Decommissioning of Generating Units or Equipment
(d) Commercial and Technical Boundaries
(e) Protection, Control and Metering.
(f) Ownership boundaries and access

(g) Operational diagrams
(h) Connection charges.
(i) Supplementary Agreements – Use of System, Ancillary Services.
(j) Emergency operations, Health and Safety.
(k) Reporting and recording of incidence at site.
(l) Emergency, Force Majeure, Disputes Resolution
11.3.4. The Grid Connection Agreement shall include, and shall not be limited to, provisions
for the submission of information and reports, Safety Rules, Test and Commissioning
programmes, electrical diagrams, statement of readiness to connect, certificate of approval to
connect, and other requirements agreed between the parties.

12. SECTION: TECHNICAL CRITERIA FOR PLANT AND
APPARATUS AT THE CONNECTION POINT
12.1. GENERAL
12.1.1. At the Connection Point all User’s Plant and Apparatus shall meet acceptable
technical design and operational criteria. Detailed information relating to a particular
connection will be made available by the TSP on request by the User. Such information will
include, but not be limited to, the following:
(a) Load flow studies.
(b) Short circuit studies.
(c) Power System stability analysis.
(d) Annual/monthly load curves.
(e) Line Forced Outage rates, for the network associated with the proposed
Connection Point.
(f) Telecommunications network associated with the proposed Connection Point.
12.1.2. All Plant and Apparatus connected to or proposed for connection to the
Transmission System are required to meet relevant current international and pan-European
technical standards, such as IEC, ISO, and EN.
(a) Furthermore, Plant and Apparatus shall be designed, manufactured and tested
in accordance with IEC or equivalent approved standard, and quality assurance
requirement of ISO 9001 or equivalent.
(b) The User shall ensure that the specification of Plant and Apparatus at the
Connection Point shall be such to permit operation within the applicable safety
procedures agreed between the User and SO as required in Section 25.
12.2. SCADA, MEASUREMENT AND DATA EXCHANGE
12.2.1. Technical facilities shall be installed on all interconnecting circuits between different
parties’ networks and different Control Areas for exchange of the following information to
both parties in real time:
(a) Status indications of circuit breaker, isolator switches, and earth switches
(b) Measurement of active and reactive power flow, voltages and Frequency
(c) Selected protection information.
12.2.2. The above information shall be made available to all Control Centres that have a
responsibility to monitor or control the applicable circuits or is affected by the operation
thereof.

12.2.3. Requirements: The technical facilities provided shall adhere to the following
minimum requirements:
(a) Double bit status indications measurement;
(b) Three phase Active Power and Reactive Power measurement;
(c) Single-phase Voltage measurement; and
(d) Support open SCADA protocols to allow interface with other vendor’s
Equipment.
12.2.4. Recording facilities: Transient recording facilities shall be installed on the
Interconnecting circuits between different parties’ networks. These facilities shall be
synchronised to the Universal Time Coordinated reference time (UTC time).
12.2.5. Power interchange: Each Control Centre responsible for a Control Area shall provide
the Facilities to schedule the power interchange with other Control Areas effectively on a
frequent and continuous basis.
12.3. TELECOMMUNICATION INSTALLATIONS
12.3.1. Telecommunication facilities at Control Centres: Each Control Centre shall install
adequate and reliable telecommunication facilities for their own needs and those of other
parties to ensure that the effective exchange of information necessary to maintain the
Reliability of the Interconnected network can take place. Wherever possible, there will be
back-up facilities and route diversity.
12.3.2. Hot Line: Direct telecommunication channels (“Hot Line”) shall be provided
between a Control Centre and the Control Centre of each adjacent network, Generators
within the Control Area, and co-ordination centres.
12.3.3. Alternative telecommunication channels: Alternative and physically independent
telecommunication channels shall be provided to back up the direct circuits, including a
Switched Voice Circuit via the Transmission System network, as well as a Switched Voice
Circuit via the public telecommunications network where available.
12.3.4. Data communication: Data communication channels shall be provided to support the
metering, SCADA, and protection systems. Automated channel monitoring and failure alarms
shall be provided for protection communication channels if such failure can cause undesired
protection operation.
12.3.5. Voice recording: A voice recording system shall be provided in each Control Centre
to record all voice communications between Operators during network operation. The
recording of these voice communications should be kept at least 2 months for reference
when needed.
12.3.6. Communication system Reliability and Availability: The Reliability and Availability of
the communication system(s) shall be of acceptable quality levels and in accordance with the
prevailing telecommunication standards.

12.4. POWER SYSTEM CONTROL
12.4.1. Generator installations: Technical facilities must be installed on all Generator
networks to provide the following information to the responsible Control Centre:
(a) Status indications of circuit breaker, isolator switches, and earth switches insofar
as they are required for operation of the network
(b) Measurement of Active and Reactive Power flow in both the import and export
directions, as well as voltages and Frequency
(c) Where applicable, reference values for control (activation/deactivation of
primary/secondary control) and instantaneous Demand value of the secondary
control.
(d) Reference value of the Reactive Power in the form of the schedule or as an
instantaneous value (e.g. for voltage and Reactive Power control).
(e) Selected protection information
12.4.2. Generator Control Centre: The Control Centre of each Generator shall provide the
facilities to effectively schedule the power interchange with the Control Centre of the
Interconnected Network.
12.5. PROTECTION CRITERIA AND METERING
12.5.1. Minimum protection requirements: The minimum requirements for any new and
existing connection will vary depending on many factors such as Load type, earthing methods
and others. However, the minimum requirements shall encompass three-phase over current,
earth fault (to suite earthing requirements); and inter-tripping.
12.5.2. International standards: All protective schemes and systems shall be in accordance
with internationally accepted standards, philosophies and performance.
12.5.3. Protection Schemes: Protection Schemes shall be designed for reliable clearing of all
network faults in an effective manner and within an acceptable time duration, and shall be
secured against unwanted operation for out-of-zone faults, brief overloads, transient surges
or power swings.
12.5.4. The requirements for inter-tripping of protection Apparatus at the Connection Point
shall be coordinated between the User and the TSP. This shall be specified in the respective
Grid Connection Agreement.
12.5.5. Fault Clearance Times: Fault clearance times at the Connection Point and the method
of system earthing including, where relevant, the recommended Generating Unit neutral
earthing configuration, will be provided by the TSP on request.
Typical fault clearance times for main protection schemes are as follows:
(a) 60 ms for faults cleared by busbar protection at 330 kV and 132 kV.
(b) 80 ms for faults cleared by distance protection on 330kV and 132 kV overhead
lines.

(c) 80 ms for faults cleared by transformer protections on HV transformers.
Total fault clearance time shall be from fault inception until the time to arc extinction,
which therefore includes relay operation, circuit breaker operation and
telecommunications signalling times.
12.5.6. Users will be expected to coordinate their protection times according to the clearance
times specified by the TSP. Prospective Users whose proposed protection scheme cannot
achieve these times, or whose Power Station cannot continue operations whilst line faults on
the Transmission System are cleared, may be required to resubmit their proposals for final
approval by the TSP.
12.5.7. Protection philosophy: Each party shall implement the prevailing protection
philosophy, standards and preventive maintenance procedures that shall improve their system
Reliability with the least adverse effects on the Interconnected Network.
12.5.8. Grading: All protection schemes and all modifications to existing protection schemes
that affect the neighbouring system in any way shall be technically coordinated and graded
with the other party’s System.
12.5.9. Back-up protection: Backup protection facilities shall be provided in accordance with
the prevailing protection standards in case of the main protection failing to operate.
12.5.10.Network stability and integrity: High speed relays, high speed circuit breakers and
automatic re-closing Facilities shall be used where studies show that their application shall
enhance the network Stability. Automatic re-closing under out-of-step conditions shall be
prevented by blocking relays.
12.5.11.Under Frequency Load Shedding relays shall be coordinated to ensure system
Stability and integrity.
12.5.12.Metering: Metering installations at the Connection Point shall be designed in
accordance with the Metering Code.
12.6. ADDITIONAL REQUIREMENTS FOR POWER STATIONS
Performance Requirements
12.6.1. The Generating Units shall have, at least, following performance requirements:
(a) Each Generating Unit must be capable of supplying rated power output (MW)
at any point between the limits of 0.85 power factor lagging and 0.95 power
factor leading, at the Generating Unit terminals at rated voltage level in the
Transmission Network within the Power System Frequency range given in
10.1.2.
(b) Each Generating Unit must be capable of continuously supplying its registered
output within the Power System Frequency range given in Section 10.1.2.
(c) The Active Power output under steady state conditions of any Generating Unit
directly connected to the Transmission Network should not be affected by
voltage changes in the normal operating range.

(d) The Reactive Power output of a Generating Unit having a synchronous
alternator must, under steady state conditions, be fully available within the
voltage range ± 10% of nominal voltage at the Connection Point.
(e) A Generating Unit having a synchronous alternator must be capable of start-up,
synchronize and pick up load:
(i) From cold, within 14 hours.
(ii) From warm, within 6 hours.
(iii) From hot within 3 hours.
(f) A steam-turbine or gas-turbine Generating Unit which has been synchronised
must be capable of ramping up pursuant to a Dispatch instruction at a rate of at
least 3% of Registered Capacity per minute. A steam-turbine or gas-turbine
Generating Unit must be capable of de-loading at a rate of at least 3% of
Registered Capacity per minute.
12.6.2. All steam turbine Generating Units must be fitted with a turbine controller, which is
designed and operated to the requirements of IEC 60045, or equivalent standards. All gas
turbine Generating Units must be fitted with a turbine Governor Control System capable of
power related speed droop characteristic of between 4% and 6%.
Each steam turbine and gas turbine Generating Unit must be fitted with a fast acting
Governor Control System. The turbine speed control principle shall be that the
Generating Unit output shall vary with rotational speed according to a proportional
droop characteristic (“Primary Control”). Superimposed load control loops shall have no
negative impact on the steady state and transient performance of the turbines rotational
speed control.
The Governor Control System shall be sufficiently damped for both isolated and
interconnected operation modes. Under all operation conditions, the damping coefficient
of the Turbine Speed Control shall be above 0.25 for speed droop settings above 3% for
gas turbines and 5% for steam turbines. For Generating Unit oscillations with
frequencies below 2 Hz, the Governor Control System shall have no negative effect on
Generating Unit oscillation damping.
The Governor Control System and any other superimposed control loop (Load control,
gas turbine temperature limiting control, etc.) shall contribute to the Primary Control to
maintain the unit within the Generating Unit capability limits.
The Primary Control characteristics shall be maintained under all operational conditions.
Additionally, in the event that a Generating Unit becomes isolated from the System but
is still supplying Demand the Generating Unit must be able to provide Primary Control
to maintain Frequency and voltage.
12.6.3. A continuous Automatic Voltage Regulator (AVR) acting on the excitation system is
required to provide constant terminal voltage of the Generating Unit without instability over
the entire operating range of the Generating Unit. Control performance of the voltage

control loop shall be such that under isolated operating conditions, the damping coefficient
shall be above 0.25 for the entire operating range.
The Automatic Voltage Regulator (AVR) shall have no negative impact on Generating
Unit oscillation damping. If required, the appropriate Power System Stabiliser (PSS) shall
be provided. Control principle, parameter setting and switch on/off logic shall be
coordinated with the System Operator and specified in the Grid Connection Agreement.
12.6.4. Each Generating Unit shall be required to withstand, without tripping, the negative
phase sequence loading experienced during clearance of a close-up phase-to-phase fault by
System back-up protection on the Transmission Network.
12.6.5. The System Frequency could rise to 51.5 Hz or up to 51.75Hz for no more than 15
seconds or fall to 47.5 Hz and Generating Units must continue to operate within this
Frequency range unless the System Operator has agreed to any Frequency-level relays and/or
rate-of-change-of-Frequency relays which shall trip such Generating Units within this
Frequency range, as stated in the Grid Connection Agreement.
12.6.6. Generators shall be responsible for protecting all their Generating Units against
damage should System Frequency variations exceed 51.75 Hz or over 51.5 Hz for up to 15
seconds or go below 47.5 Hz or such limits agreed with the System Operator. In the event
that such variations occur, the Generator shall disconnect the Generating Unit for reasons of
safety of personnel, Apparatus, and/or Plant.
Protection Arrangements
12.6.7. Each connection between a Generating Unit and the Transmission Network must be
controlled by a circuit breaker capable of interrupting the maximum short circuit current at
the point of connection as determined by the System Operator and/or the TSP.
12.6.8. The System Operator and/or the TSP shall provide each Generator at each
Connection Point where its Power Station is connected with the appropriate voltage signals
to enable the Generator to obtain the necessary information to synchronise its Generating
Units to the Power System.
12.6.9. Electrical protection of the Generating Unit shall take precedence over operational
controls (e.g. Voltage Controllers, excitation Equipment) and the Generating Unit shall
disconnect from the network should unacceptable Operational States arise as a result of
failure of the operational controls. This shall apply in particular when spontaneous faults
occur (e.g. earth faults, short-circuits).
12.6.10.The settings for the electrical protection Equipment must be agreed upon between
the TSP and the Generator, and reflected in the Grid Connection Agreement. The possibility
of protection and switchgear failures must also be taken into account. Consideration must be
given to the following points:
(a) External short-circuits
(b) Load unbalance
(c) Stator and rotor overload
(d) Under-excitation

(e) Over Frequency, under Frequency
(f) Asynchronous operation
(g) Torsional strain
(h) Drive failure (operation as motor)
(i) Measures against breaker failure
(j) Back-up protection.
12.6.11.To cater for the possibility that the indicated fault clearance times are not met as a
result of failure in the operation of the main protection systems, the Generator shall provide
the necessary back up protection. The TSP shall also provide back-up protection which shall
be coordinated to provide discrimination and protect Equipment from damage.
12.6.12.Where System requirements dictate, the TSP and/or the System Operator shall
specify in the Grid Connection Agreement a requirement for Generators to fit pole slipping
protection on their Generating Units.
Work on Protection Apparatus at the Connection Point
12.6.13.No busbar protection, circuit breaker fail protection, AC or DC wiring on the
Interconnection Facilities may be worked upon or altered:
a) by the TSP personnel in the absence of a representative from the Generator; and
b) by Generator personnel in the absence of a representative from the TSP.

CHAPTER 4: OPERATION
13.1. OBJECTIVE
13.1.1. The general objective of this part of the Chapter is to specify the required System
Operator and User actions in order to ensure that the Power System in Nigeria is operated in
a way to maintain adequate and safe transportation of Energy, plus System security at all
times.
13.1.2. This adequate and secure operation is achieved through:
(a) Adequate and economic ancillary services:
(i) Frequency Control and Operating Reserve (Section 15)
(ii) Voltage Control (Section 16)
(iii) Black Start Capability (Section 17)
(b) Outline the general restoration strategy adopted by the System Operator in the
event of a Partial or Total Shutdown (Section 18)
(c) Specifying procedures for Operational Planning in the short to medium term
(Section 19)
(d) Provision of information regarding risks or events in the Transmission System
(Section 20)
(e) Determining the actions that the System Operator shall undertake to perform
the economic dispatch, and to provide Generators with running orders for the
Dispatch Day. (Section 21)
(f) Defining the requirements for notification of Generation Outages to the System
Operator (Section 22).
(g) Defining the reliability criteria that the System Operator and the TSP have to
adhere to in operating and developing the Transmission System (Section 23).
(h) Establishing central co-ordination and control of System Tests required by the
System Operator, TSP or Users (Section 24)
(i) Setting safety procedures for works to be carried out at the interface between
User networks and the Transmission Network (Section 25)
13.2. SCOPE
13.2.1. The Operation Chapter applies to the System Operator, TSP and Users of the
Transmission System which are:
(a) Generators;

(b) Distributors;
(c) Interconnected parties;

14. SECTION: POWER SYSTEM CONTROL
14.1. OBJECTIVE
14.1.1. The objective of this Section is to specify the required System Operator and User
actions in order to ensure that the Power System in Nigeria is operated in such a way as to
maintain adequate and safe transportation of Energy, plus System security at all times.
14.2. GENERAL
14.2.1. The System Operator shall carry out Power System Planning, Switching and Control
Actions, which may from time to time affect User operations or the security of supply to
Users.
(a) Power System Planning is required for technical and design criteria and
procedures to be applied by the System Operator for adequate and secure
development of the Transmission Network by the TSP for the benefit of all
Users.
(b) Network switching is required to implement the Transmission Outage
scheduling programme, routine operation of the Transmission Network and in
response to emergency and fault situations on the Transmission Network.
(c) Additionally, network switching may occur automatically and without advance
warning due to operation of protection Equipment in isolating or clearing faults
on the Transmission System or on User’s Apparatus that is connected to the
14.2.2. All network Control Actions carried out on the Transmission System have the
potential to affect Users. To attempt to inform Users of every Control Action is not
practicable and in most cases the information will not be of value to the User, as the User will
not take or cause any specific action as a result of receipt of the information.
(a) It may not always be possible for the System Operator to inform Users in
advance of the switching or other Control Actions. This would be the case
when the System Operator needs to carry out urgent switching or other network
Control Actions resulting from a Power System condition or fault. The System
Operator shall endeavour to inform Users where time permits, but this shall not
delay timely implementation of Control Actions as required.
(b) In the event of a Power System fault or protection operation or other automatic
operation, it will not be possible for the System Operator to invoke standing
procedures prior to the occurrence of the Control Action.

14.3. POWER SYSTEM CONTROL ACTIONS
14.3.1. The System Operator shall be responsible for operating the Power System in such a
way as to maintain System security, achieve highest degree of reliability practicable and take
appropriate remedial action promptly to relieve any abnormal condition that may lead to
dangerous operation.
14.3.2. Consultation
The System Operator shall consult with Users and take into consideration Users’
reasonable requirements in controlling the Transmission System.
14.3.3. Network switching
The System Operator shall carry out operational network switching for a number of
purposes, which shall include:
(a) Outages of Transmission Apparatus for maintenance, new works, System Tests,
protection testing and work by Users;
(b) Outages of Transmission Apparatus due to suspected or potential faults and
emergency repairs;
(c) Voltage Control; and
(d) Limiting power flows on the Transmission System to levels consistent with the
capabilities of the Transmission Plant and System security.
14.3.4. Identification of Control Actions
The System Operator shall identify the Control Actions that may be needed to carry
out maintenance and operation of the Transmission System and respond to
Transmission System faults and emergencies.
14.3.5. Automatic switching sequences
The System Operator shall establish automatic switching sequences to limit power
flows or voltage dip or Frequency deviations in the event of faults on the Power
System.
14.4. NOTIFICATION TO ALL USERS
14.4.1. The System Operator shall notify Users of the Transmission Network of a Control
Action (if planned and where time permits), in accordance with this Code.
14.5. CONTROL UNDER FAULT OR EMERGENCY CONDITIONS
14.5.1. Notification after action
In the event that the System Operator needs to implement Control Actions urgently and
without informing Users, then unless the situation is of a temporary nature and has been

rectified to normal, the System Operator shall inform Users of the occurrence of the
actions.
Generators shall promptly inform System Operator of the tripping of a Generating Unit,
with reasons, in accordance with the guidelines in Section 21 of the Grid Code and other
operational event/incident reporting procedures operating at the time. The System
Operator shall keep a written log of all such tripping, including the reasons for the
purpose of demonstrating the effect on system performance and identifying the need for
remedial measures. The Generators shall submit a detailed report of their Generating
Unit tripping to the System Operator every month.
14.5.2. Duration of condition
The System Operator shall also inform Users as to the likely duration of the condition
and shall update this prognosis as appropriate. Additionally, the System Operator shall
inform Users when the condition has ended.
14.6. DE-ENERGISATION OF PLANT
14.6.1. The System Operator shall have the right to De-energise a Generating Unit, as stated
in the Grid Connection Agreement if it identifies any of the following causes, or any other
causes detailed in the Grid Connection Agreement:
(a) Risk to the safety of personnel;
(b) Risk to the stability of the Power System;
(c) Risk to the Power System or any User’s Apparatus;
(d) Power System elements that are or could become loaded beyond their
emergency limits;
(e) Voltage Fluctuations on the Power System outside the specified ranges;
(f) Any behaviour outside normal Power System operating range;
(g) Any material breach of a connection condition; and
(h) Any action (or inaction) that places the System Operator in breach of any legal,
statutory or regulatory obligation.
14.6.2. On a similar basis a Generator shall have the right to De-energise a Generating Unit,
as stated in the Grid Connection Agreement if it identifies any of the following causes, or any
other causes detailed in the Grid Connection Agreement:
(a) Risk to the safety of personnel;
(b) Risk to the Generating Unit;
(c) Frequency variations outside specified limits
(d) Voltage Fluctuations on the Power System outside the specified ranges;

(e) Any behaviour outside normal Power System operating range;
(f) Any material breach of a connection condition; and
(g) Any action (or inaction) that places the Generator in breach of any legal,
statutory or regulatory obligation.
14.7. OPERATING PROCEDURES INCLUDING FAULT REPORTING
14.7.1. Approach
(a) The System Operator shall develop and maintain Operating Procedures for the
safe operation of the Transmission Network, and for Apparatus connected to
the Transmission Network. These Operating Procedures shall be adhered to by
Users when operating Apparatus on the Transmission Network or connected to
the Transmission Network.
(b) Each User shall be responsible for his own safety rules and procedures at least
in compliance with the relevant safety legislation. Users shall ensure that these
rules and procedures are compatible with System Operator Procedures.
(c) Users shall enter into Operating Agreements as defined in the Grid Connection
Agreement with System Operator.
14.7.2. Fault reporting and analysis/incident investigation
(a) Generator operators shall report loss of output, tripping and pole slipping of
Units and change of status of Generating Unit Governing control within 15
minutes of the event occurring.
(b) In the event of a multiple unit trip (either more than one unit tripping at the
same time or one unit tripping many times), the relevant Generator shall take
the following action:
(i) The Generator shall submit a written report to the System Operator within
48 hours of the cause of any unit trip that could in future cause is reasonably
anticipated to result in heightened risk of tripping of that unit or others,
identifying the root causes of the incident and the corrective actions taken.
(ii) In addition, provide a full report as per this Grid Code (in particular item
(e)(ii) below).
(c) Off-takers, shall report the loss of major loads (>10MW) to the System
Operator within 15 minutes of the event occurring. Notification of intent to
reconnect such loads shall be given at least 30 minutes in advance.
(d) Incidents on the Power System involving sabotage or suspected sabotage, as
well as threats of sabotage, shall be reported to the System Operator.

(e) The System Operator shall investigate any incident that materially affected the
quality of service to a User. These include interruptions of supply,
disconnections, under or over voltage or Frequency incidents, quality of supply
contraventions, etc.
(i) a preliminary incident report shall be available after three working days and a
final report within three months.
(ii) the System Operator shall initiate and coordinate such an investigation,
arrange for the writing of the report and involve all affected Users. All these
Users shall make all relevant information available and participate where
reasonably required.
(iii) the System Operator shall make the report available to any requesting User
within the confidentiality constraints, and submit it to the NERC.
(f) Any User shall have a right to request an independent audit of the report, at its
own cost. If these audit findings disagree with the report, the User may follow
the dispute resolution mechanism. If the audit agrees with the report, the report
recommendations shall stand.
(g) User shall implement NERC-approved recommendations to reduce the
likelihood of a recurrence of the incident within the time frames specified.

15. SECTION: FREQUENCY CONTROL AND OPERATING
RESERVE
15.1. OBJECTIVE
15.1.1. The objectives of this Section are:
(a) To specify the System Operator requirements to ensure that adequate
Frequency Control capability is provided on the Transmission System to enable
operational Frequency Control by the System Operator, so as to achieve the
applicable limits, and
(b) To specify the Operating Reserve and Reliability Must-run requirements the
System Operator has to adhere to in order to achieve the mentioned Frequency
Control and adequate system reliability.
15.2. GENERAL
15.2.1. In order to maintain the security and integrity of the Transmission System it is
necessary that the System Operator operate the Transmission System and Dispatch it in such
a manner in order to provide adequate Frequency Control so as to achieve operation within
applicable Frequency limits at all times. Frequency Control can be obtained by using primary
or secondary Reserve.
15.2.2. Depending on network condition, Generating Units will be required to move to or
from Frequency Sensitive mode in combinations agreed in the relevant Ancillary Services
Agreement or as instructed by the System Operator.
15.2.3. In order to achieve this Control, the System Operator shall operate the System with
adequate Operating Reserve. Operating Reserve is additional Active Power output provided
from Generating Units, or a reduction in consumer Demand, which must be realisable in
real-time operation to contain and correct any potential Power System Frequency deviation to
an acceptable level.
Operating Reserve is required to secure capacity that will be available for reliable and
secure balancing of supply and demand.
15.3. FREQUENCY LIMITS
15.3.1. The Frequency shall be maintained at 50 Hz. The National Control Centre will
endeavour to control the System Frequency within a narrow operating band of +/- 0.5%
(49.75 – 50.25 Hz) from 50 Hz, at least 97 % of the time during Normal Conditions. Under
System Stress the Frequency Control on the Power System will be exercised within the limits
of 50 Hz +/- 2.5% (48.75 – 51.25 Hz).

15.4. FREQUENCY CONTROL
15.4.1. During Normal Conditions, Frequency Control will be exercised utilizing the
Spinning Reserve (Primary and Secondary Reserve). Occasionally, also the Emergency
Reserve will be used.
15.4.2. The Nigerian Power System requires a minimum Spinning Reserve that is sufficient to
cover the Largest Credible Trip in order to secure the network. The “Largest Credible Trip”
is the largest loss of power inflow that could be caused by a single trip, which will normally be
the largest Generating Unit synchronised to the system; however it could be an inflow from
an exporting area that flows through a single circuit. (As at 2012 the largest Generating Unit
on the system is 220MW.):
(a) The System Operator shall distribute the required Spinning Reserve power
among the contributing Generating Units.
(b) The Generators shall be responsible for continuous secure maintenance of their
primary Frequency Control Equipment as instructed by the System Operator.
15.4.3. Shortfall: The System Operator shall evaluate the Frequency Control performance
during the day of operation and identify any shortfall. The System Operator shall instruct a
Generator(s) to perform Frequency Control to counteract the shortfall.
15.5. COMPONENTS OF OPERATING RESERVE
15.5.1. There are two types of Operating Reserve namely Quick Reserve and Slow Reserve.
15.5.2. Quick Reserve is the reserve that can respond within ten seconds and be fully active
within 30 minutes of activation. This Reserve is used for second-by-second balancing of
supply and demand, and to restore Frequency to nominal values following a disturbance.
Quick Reserve shall consist of Spinning Reserve and Emergency Reserve
(a) Spinning Reserve: Spinning reserve is the additional output from a
synchronised Generating Unit, which must be realisable to respond to any
Frequency deviation to contain and restore the Frequency to an acceptable level
in the event of a loss of generation or a mismatch between generation output
and demand. The Spinning Reserve from the Generating Unit must be capable
of providing response in two distinct ways and time scales: Primary Reserve and
Secondary Reserve.
(i) Primary Reserve: Primary Reserve is an automatic increase/decrease in
Active Power output of a Generating Unit in response to a System
Frequency fall/rise, in accordance with the primary control capability and
additional mechanisms for acquiring active power. This change in active
power output must be in accordance with the technical characteristics and
loading of the Generating Unit, without any time delays other than those
necessarily inherent in the design of the Governor Control System.

(ii) Secondary Reserve: Secondary reserve is the automatic response to
Frequency changes which is fully available by 30 seconds from the time of
Frequency change to take over from the Primary Reserve, and which is
sustainable for a period of at least 30 minutes.
(b) Emergency Reserve: Emergency Reserve is typically made up from
contracted interruptible load, gas turbines and Emergency Generation.
Emergency Reserve is a less frequently used reserve and is used when the
Transmission Network is not in a normal condition and to return the
Transmission Network to normal conditions while slower reserves are being
activated. The Reserve can be used by the System Operator for supply and
demand balancing, network stability and voltage constraints. This Reserve shall
be activated, on request, within ten minutes and shall be sustainable for two
hours.
15.5.3. Slow Reserve: Slow Reserve is the component of the Operating Reserve not
connected to the Transmission System but capable of serving demand within a specified time.
Slow Reserve is used to restore Quick Reserve when required. Slow Reserve shall consist of
Hot Standby and Cold Standby.
(a) Hot Standby: Hot Standby is a condition of readiness in relation to any
Generating Unit that is declared available, where it is ready to be synchronised
and attain an instructed load within 30 minutes, and subsequently maintain such
load continuously.
(b) Cold Standby: Cold Standby is a condition of readiness in relation to any
Generating Unit that is declared available, to start, synchronise and attain target
loading within a pre-defined period of time, typically up to 14 hours.
15.6. OPERATING RESERVE POLICY
15.6.1. The System Operator shall, in consultation with the Users, specify the Operating
Reserve policies, including its allocation of the permissible mix of Spinning and Quick
Reserve, and procedure for applying Operating Reserve in practice, and the limitations, if any,
upon the amount of Interruptible Load which may be included. The System Operator shall
submit the Operating Reserve policy to the NERC for approval.
15.6.2. In developing the Operating Reserve Policy, due consideration shall be taken of
relevant factors, including, but not limited to the following:
(a) The cost of providing Operating Reserve at any point in time;
(b) The magnitude and number of the largest Generation in-feeds to the
Transmission System at that time, including in-feeds over Interconnections and
also over single Transmission feeders within the Transmission System;
(c) Ambient weather conditions, insofar as they may affect (directly or indirectly)
Generating Unit and/or Transmission System Reliability;

(d) The predicted Frequency drop on loss of the Largest Credible Trip as
determined through simulation using a dynamic model of the Power System;
(e) Constraints imposed by agreements in place with externally interconnected
parties;
(f) Historical Availability and Reliability performance of individual Generating
Units;
(g) Notified risk to the Reliability of individual Generating Units; and
(h) Demand Forecasting uncertainties.
15.6.3. Unless proved to be technically impossible, or the economic burden imposed on the
dispatch cost excessive, the Operating Reserve Policy shall be developed under following
premises:
(a) Primary Reserve: It shall be ensured that enough primary reserve is available to
maintain system Frequency within acceptable limits, following a contingency
such as a unit trip or a sudden surge in load, without any Under-Frequency
Load Shedding.
The Frequency shall stabilize above 49.00Hz following the Largest Credible Trip.
(b) Secondary Reserve: Sufficient Secondary Reserve shall be carried to ensure
that any decay in Primary Reserve is replaced.
(c) The minimum Operating Reserve shall be sufficient to cover 150% of capacity
of the Largest Credible Trip.
(d) Operating Reserve mix: The mix of Operating Reserve shall be as follows:
(i) An amount of Spinning Reserve, responsive to AGC, which is sufficient to
provide Normal Regulating Margin; plus
(ii) An additional amount of Operating Reserve sufficient to reduce Area
Control Error to zero within 10 minutes following loss of generating capacity
which would result from the most severe single contingency. Interruptible
Load may be included in the Quick Reserve provided that it can be
interrupted within 10 minutes and can remain off until replacement
Generation can be made available;
(iii) At least 50% of these Operating Reserves shall be spinning and the other
50% shall be Quick Reserve;
(e) Operating Reserve shall be dispersed throughout the system and shall consider
the effective use of capacity in an emergency, time required to be effective,
transmission limitations, and local area requirements.
15.6.4. The System Operator shall, in consultation with the other Users, review probable
contingencies frequently to determine the adequacy of Operating Reserve Policy, maintain it
permanently under review. On an annual basis, it shall submit to the NERC an amended
version for approval, taking into consideration the previous year’s Frequency recovery
performance.

15.6.5. Record keeping: The System Operator shall keep records of significant alterations to
the Operating Reserve policy.
15.7. AMOUNT OF OPERATING RESERVE
15.7.1. The System Operator shall be responsible for determining the amount of Operating
Reserve required for each Dispatch Period of the Dispatch Day, to be carried at any time to
ensure system security, according to the Operating Reserve Policy approved by the NERC.
15.7.2. The Operating Reserve shall consist of Quick Reserve (Spinning Reserve and
Emergency Reserve), and Slow Reserve.
15.7.3. In order to adequately and efficiently determine the amount of Operating Reserve:
(a) Each Generator shall keep the System Operator informed of the Availability of
its Generating Units.
(b) The System Operator shall keep proper records of the Availability of its
transmission resources.
(c) The System Operator shall have information, including weather forecasts and
past Load patterns, available to predict the Power System's future Load.
15.7.4. The System Operator shall operate the Power System to provide for a level of
Operating Reserve sufficient to account for such factors as errors in forecasting, generation
and Transmission Equipment unavailability, number and size of Generating Units, system
Equipment Forced Outage rates, maintenance schedules and regulating requirements. The
System Operator shall take appropriate steps to protect the Power System against the next
contingency, following the loss of Generation resources or Load.
15.8. OPERATING RESERVE PROCUREMENT
15.8.1. Operating Reserve is an Ancillary Service. This Ancillary Service shall be considered
mandatory. The System Operator shall contract for Operating Reserve to enable it operate
the Transmission System securely at all times.
Primary Reserve
15.8.2. Governor Control System. In order that adequate Frequency Control is maintained
on the Power System at all times, Generators are required to provide the Primary Reserve
specified by the System Operator, complying with the following requirements:
(a) Generating Units, when Synchronised to the Power System, shall operate at all
times under the control of a Governor Control System, unless otherwise

specified by the System Operator, with characteristics within the appropriate
ranges as specified in connection conditions;
(b) No time delays other than those necessarily inherent in the design of the
Governor Control System shall be introduced;
(c) No Frequency dead bands shall be applied to the operation of Governor
Control Systems.
15.8.3. Restriction of governor action: The Generator shall only restrict governor action
where:
(a) the action is essential for the safety of personnel and/or to avoid damage to
Plant; or
(b) in order to secure the Reliability of the Generating Unit; or
(c) the restriction has been agreed upon between the System Operator and the
Generator in advance; or
(d) the restriction is in accordance with a Dispatch Instruction given by the System
Operator. The System Operator shall record the nature of the restriction, the
reasons, and the time of occurrence and duration of the restriction.
Other types of Operational Reserve
15.8.4. Reserve Responsibilities:
(a) The System Operator shall be responsible for contracting for the required
Operating Reserve and shall Dispatch it economically between all the
participating Generators, Distribution Network Operators and Eligible
Customers (in the case of Interruptible Load).
(b) The System Operator shall agree on an annual basis with the Generators all the
conditions relating to Frequency Control. This shall include the possible range
that each participating Generating Unit can comply to and the time of the year
when it shall be possible technically. The System Operator shall decide on the
scheduling of the different Generating Units to perform Frequency Control.
The System Operator shall base this on an economic evaluation and Availability
of the Generating Units. The System Operator shall instruct the Generating
Units one day before they will be required to perform Frequency Control. The
Generator shall be informed of the time interval and the range required.
(c) Generators that are contracted for Secondary Reserve are required to respond
with at least contracted capacity for low frequencies or according to the agreed
droop characteristic. The response is required fully within thirty (30) seconds, to
an increase or decrease in system Frequency above/below the allowable dead-
band. This response must be sustained for at least thirty (30) minutes.
(d) When the System Operator decides to implement Frequency regulation under
AGC control, following rules shall apply:

(i) The AGC shall act as a secondary Frequency Control device and shall raise
or lower the Generating Unit output according to an economic analysis of
the participating Generating Units. This economic analysis takes the
registered operating characteristics of Generating Units, Generator
Nominations, Transmission System losses and Availability of Plant into
account to determine optimal Generating Unit output.
(ii) The System Operator shall ensure the balance between Generation and the
Load. The System Operator shall achieve this by the deployment of
secondary Frequency Control (AGC);
(iii) The secondary Frequency Control (Spinning Reserve) shall be contracted to
Generators that have installed the required technical means for this purpose
in conjunction with the System Operator
(iv) On the basis of an annual Dispatch Schedule, the System Operator and the
corresponding Generators shall enter into Bilateral Agreements for operation
under secondary Frequency Control (providing of Secondary Reserve);
(v) Based upon these conditions and the Dispatch Schedule, the System
Operator shall decide which Generators to involve in secondary Frequency
Control (providing Secondary Reserve) and at what time intervals, in
accordance with the principle of minimum costs and Availability;
(vi) The AGC shall be managed via the SCADA system at the National Control
Centre.
15.8.5. Reliability Must-Run Requirements: The System Operator shall contract
Reliability Must-run Generating Units to cater for situations where Emergency Reserve
power is needed to keep the Power System secure.
The System Operator shall determine the needed Reliability Must-run
requirements by performing extensive Reliability studies on the Power
System, taking the scheduled Outages into account.
The System Operator shall quantify the risk the Transmission System is
exposed to due to unanticipated Outages. Based on this risk assessment,
additional Reliability Must-run Agreements might be needed.
The System Operator shall report on all Reliability Must-run Agreements by
including the details in the Reliability annual assessment report on an annual
basis to the NERC. This report shall address the reasoning for each
Reliability Must-run Agreement and the achieved performance of each
Reliability Must-run Unit.

16. SECTION: VOLTAGE CONTROL
16.1. OBJECTIVE
16.1.1. The objective for Voltage Control is to achieve a healthy voltage profile for the
Power System.
16.2. GENERAL
16.2.1. The System Operator shall endeavour to maintain sufficient Availability of dynamic
and static Reactive Power in order to maintain the Power System voltages at Connection
Points within the levels specified, at all times.
16.2.2. The System Operator should use the effects of Power System capacitance in
controlling the Power System voltage.
16.2.3. The System Operator can operate the Power System voltage towards the upper
portion of the allowable control range at times of high Reactive Power Demand (normally
times of high Active Power Demand).
16.2.4. The System Operator can operate the Transmission System voltage towards the lower
portion of the allowable control range at times of low Reactive Power Demand (normally
times of low Active Power Demand).
16.3. VOLTAGE CONTROL
16.3.1. Responsibility: The System Operator shall be responsible for:
(a) maintaining voltage stability of the Power System; and
(b) maintaining Power System voltages at User Connection Points within
operational limits.
16.3.2. Dispatch: The System Operator shall, by means of Dispatch Instructions, instruct
Generators to adjust the voltage level at the Connection Point or the Reactive Power output
of Generating Units.
16.3.3. Control facilities: The System Operator shall adjust Power System voltages, using
available control facilities. This is to achieve the Reactive Power capacity necessary in order to
maintain Power System voltages at Connection Points within the specified levels.
16.4. VOLTAGE CONTROL POLICY
16.4.1. Transmission System losses: The System Operator shall control system voltages in
order to maximize the reliability of the Power System, trying, when possible, to minimise
Transmission System losses and the cost of the Ancillary Services.

16.4.2. Procedures: The System Operator shall determine and modify, as appropriate,
general procedures for controlling voltages on the Power System. The procedures shall be
formulated considering the relevant economics of Power System operation and Power
System Reliability. In determining these procedures, the System Operator shall consider daily,
weekly and seasonal factors. The System Operator shall determine:
(a) suitable target voltages in order to limit/control the effect of Transmission
Capacitance;
(b) best utilisation of dedicated Voltage Control facilities; and
(c) Reactive Power dynamic reserve requirements.
16.5. VOLTAGE CONTROL METHODS
16.5.1. The System Operator shall use the following Voltage Control methods:
(a) Transformer tap-changing, cable switching, reactor and capacitor switching, and
other control methods which involve utilisation of Transmission System Plant
only;
(b) Tap-changing on Generating Unit transformers;
(c) Demand power factor correction;
(d) Utilisation of Generating Unit Reactive Power capability, both by means of
AVR control and also Reactive Power Dispatch Instructions issued by the
System Operator to Generators; or
(e) Eventually, and only if Reliability of the Transmission System is not heavily
affected, the switching of Transmission Lines in order to reduce the capacitive
contribution of the Transmission System.
16.5.2. Monitoring: The System Operator shall monitor the Transmission System Voltages
continuously. Appropriate voltage operating points shall be determined by the System
Operator, taking account of the Voltage Control policy and in particular of system conditions
prevailing at the time of operation.
16.6. VOLTAGE CONTROL DURING EMERGENCIES
16.6.1. The System Operator shall utilise additional Voltage Control mechanisms in the event
of System Emergency Conditions. These shall include the following:
(a) Generators may be requested to operate Generating Units at Reactive Power
levels (delivering or absorbing) outside their currently registered operating
characteristics. This will be done by agreement between the Generators and the
System Operator and Generators will not be penalised for non-compliance with
this Subsection;
(b) System wide restoration of voltages by instructing Generators to carry out a tap-
change on the main Generating Unit transformer of several Generating Units
simultaneously; and

(c) Load shedding may be used to prevent Voltages from contravening Low
Voltage limits at Connection Points.
16.7. PROVISION OF VOLTAGE CONTROL
16.7.1. Voltage Control is an Ancillary Service. Minimum requirements for this Ancillary
Service that all Users are obliged to provide are established in this Code. The System
Operator may establish contract for Voltage Control with some Users in order to enable the
Power System to be operated efficiently and securely at all times.
(a) Each Generator shall inform the System Operator of the Capability Chart of
each Generating Unit. In case there exists a seasonal or permanent technical
restriction that could prevent the Generating Unit from producing reactive
power within the limits of this curve, this situation shall be reported to the
System Operator.
(b) The Generating Unit shall normally be operated under the control of a
continuously acting AVR, which shall be set so as to maintain a constant
terminal voltage within the voltage range specified by the System Operator.
While the reactive power produced by the Generating Unit is within the limits
indicated in the Capability Chart, the Generator may only disable or restrict
AVR action:
(i) where the action is essential for the safety of personnel and/or Plant;
(ii) in order to secure the Reliability of the Generating Unit; or
(iii) where the restriction has been agreed upon between System Operator and
the Generator in advance.
(c) When a Generator identifies that, due to technical or operational problems or
constraints, its capability to provide reactive power has reduced compared to
the normal capability informed to the System Operator, then it shall inform as
soon as practical the System Operator of this constraint.
(d) Generating Unit restrictions: The System Operator may impose restrictions
on the operation of the Generating Unit in accordance with Good Utility
Practice in the event of a Generating Unit not operating under AVR. This shall
provide for safe and secure operation of the Power System and operation within
prescribed standards, including where necessary instructing the Generator to
De-energise the Generating Unit.
(e) Minimum Requirements for Off-takers: the Off-takers shall maintain a
lagging Power Factor not less than 0.90 at the Connection Point.
16.7.2. During the Medium Term Stage:
(a) Minimum Requirements for Generating Units

(i) The minimum amount of reactive power each Generating Unit shall be able
to produce, if required by the System Operator, is defined by the following
limits:
a.i.1) Inductive: 25 % of the rated active power (cos  = 0.97 at full output)
a.i.2) Capacitive: 15 % of the rated active power (cos  = 0.989 at full output)
The Generating Unit shall be able to deliver this reactive power within the whole
range of generated active power (from technical minimum to rated capacity)
(ii) Each Generating Unit shall normally be operated under the control of a
continuously acting AVR, which shall be set so as to maintain a constant
terminal voltage within the voltage range specified by the System Operator.
The Generator shall not disable or restrict the operation of the AVR except
for the conditions identified below, in which event the Generator shall notify
the System Operator without delay.
(iii) AVR restriction: While the reactive power produced by the Generating Unit
is within the limits indicated in Section 12 of the Connection Conditions the
Generator may only disable or restrict AVR action-
a.iii.1) where the action is essential for the safety of personnel and/or Plant;
a.iii.2) in order to secure the Reliability of the Generating Unit; or
a.iii.3) where the restriction has been agreed upon between System Operator
and the Generator in advance.
(iv) Generating Unit restrictions: The System Operator may impose restrictions
on the operation of the Generating Unit in accordance with Good Utility
Practice in the event of a Generating Unit not operating under AVR. This
shall provide for safe and secure operation of the Power System and
operation within prescribed standards, including where necessary instructing
the Generator to De-energise the Generating Unit. The System Operator
shall consult with the Generator as soon as possible after such actions had
been taken in order to determine a safe operating regime, which causes
minimum restriction on the operation of the Generating Unit.
(b) Minimum Requirements for Off-takers
(i) The Off-takers shall maintain a Power Factor not less than 0.95 at the
Connection Point.
(c) Additional requirements for Voltage Control
(i) In case the System Operator considers that additional means of Voltage
Control are required in the Transmission System (in excess of those
previously stated), it can procure them, establishing contracts with Users.

17. SECTION: BLACK START
17.1. OBJECTIVE
17.1.1. The objective of this Section is to stipulate the Black Start requirements the System
Operator has to cater for.
17.2. GENERAL
17.2.1. Generating Units have to be identified that can start on own resources from a total
De-energised state which may be due to emergency condition declared by System Operator as
in Section 18 or Appendix 8 of this Code. Such Generating Units may be necessary to start
other Generating Units and revive the Power System following a Total Shutdown. The
necessary contracts must be executed between the System Operator and Generators to
provide Black Start Capability and appropriate tests must be done on a regular basis to ensure
that the Power System can be reactivated following such an extreme emergency situation.
17.3. ANCILLARY SERVICE
17.3.1. Black Start is a mandatory Ancillary Service. The System Operator shall contract for
Black Start to enable it to operate the Power System securely at all times.
(a) Existing Generators can appeal to the SO for derogation from this duty; or
(b) New Generators can appeal to SO/TSP for derogation on the basis of:
technological incapability (e.g. wind and photo-voltaic), size (e.g. small hydro) or
excessive cost (no in this case the SO may choose to cover the extra cost in the
Ancillary Service Agreement).
17.4. REQUIREMENTS
17.4.1. The System Operator shall set out the requirements for Black Start Stations to enable
recovery of the Power System from a Partial Shutdown or Total Shutdown.
17.4.2. Requirements for Black Start Stations:
(a) Black Start Stations shall have the ability for at least one of its Generating Units
to start-up from shutdown and to energise a part of the total system, or be
Synchronised to the System.
(b) The Black Start Stations shall perform Black Start upon instruction from the
System Operator, without an external electrical power supply.
(c) The Black Start Power Station shall inform the System Operator if during the
Demand restoration process any Black Start unit cannot, because of the
Demand being experienced, keep within its safe operating parameters.
(d) The System Operator shall where possible, either instruct Demand to be altered
or will re-configure the Transmission System or will instruct a User to re-

configure its system in order to alleviate the problem being experienced by the
Generator.
(e) However, the System Operator may decide to keep a Generating Unit in a
Power Station operating outside its safe operating parameters, for a limited
period of time. The System Operator shall accept that the Generator operator
may change Generation on that unit if it believes it is necessary for safety
reasons. The Generator shall inform the System Operator as soon as reasonably
practical if such a change is made without prior notice.

18. SECTION: EMERGENCY OPERATION AND RESTORATION
18.1. OBJECTIVE
18.1.1. The objective of this Section is to outline the general restoration strategy, which shall
be adopted by the System Operator in the event of a Partial or Total Shutdown of the
Transmission System, emergency condition or that indicated in Appendix 8. This includes the
need for a restoration plan and an Under-Frequency Load Shedding scheme.
18.2. GENERAL
18.2.1. The Operating States of a Power System are classified into five Operating States,
namely normal, alert, emergency, extreme and restorative.
18.2.2. The different Operating States can be defined as follows:
(a) Normal Operating State
The Power System variables, voltage and lines, are within the normal range and no
Equipment is being overloaded. The Power System operates in a secure manner and
can withstand any single contingency without violating any of the limits.
The Power System should be in this mode of operation for most of the time. The
System Operator shall endeavour to operate the Power System such that it is in the
normal Operating State.
(b) Alert Operating State
The Power System will move into this state of operation once the security level falls
below a certain limit. This could also be due to the possibility of a disturbance due
to bad weather conditions, such as a severe storm.
The Power System variables, voltage and lines, are within acceptable operating range
and limits. However, the Power System is weakened and the next contingency could
cause an overload or voltage violation.
(c) Emergency Operating State
The Power System will move into this state of operation if a severe disturbance
occurs or under a civil emergency situation as in Appendix 8, when the system is in
the alert operating state. Some of the busbar voltages will be low and/or Equipment
will exceed its short-term emergency ratings. The system will still be intact and can
return to the alert Operating State once the emergency actions have been initiated,
such as fault clearing, excitation control, generating tripping and Load curtailment.
(d) Extreme Operating State
The Power System will move into this state of operation once the emergency actions
have failed to be effective. This will result in a possible cascade tripping of the
transmission lines and Generating Units and a possible Shutdown of a part of the
Power System. The Power System can then be saved by the initiation of Under

Frequency Load Shedding and controlled separation of portions of the Power
System.
(e) Restorative Operating State
The System Operator shall reconnect all the facilities and restore the system Load
during this Operating State either through the approach in this Section 18 or any
other safe method deemed necessary by System Operator. The Operating State of
the Power System will then move from Extreme Operating State to Restorative
Operating State until it has once again reached the Normal Operating State.
18.3. EMERGENCY OPERATION
18.3.1. Operating State Responsibility
System Operator shall always be in a position to determine the Operating State of the Power
System. The System Operator shall be responsible for informing all Users involved once the
Operating State changes from one Operating State to another.
18.3.2. System Operator shall develop and maintain contingency plans to manage system
contingencies and emergencies that are relevant to the performance of the Transmission
Network. Such contingency plans shall be developed in consultation with all Users, which
shall be consistent with the actual situation of the Nigerian Power System and international
utility best practices. It shall include but not be limited to:
(a) Under-Frequency Load Shedding
(b) meeting system disaster management requirements including the necessary
minimum Load requirements
(c) Forced Outages at all points of interface, and
(d) supply restoration.
18.3.3. Emergency plans shall allow for quick and orderly recovery from a partial or complete
system collapse, with least cost solution and minimum impact on Users and customers.
18.3.4. The System Operator shall periodically verify contingency and/or emergency plans by
actual tests to the greatest practical extent possible. In the event of such tests causing undue
risk or undue cost to a User, the System Operator shall take such risks or costs into
consideration when deciding whether to conduct the tests. Any tests shall be carried out at a
time that is least disruptive to the User and customers. The costs of these tests shall be borne
by the respective asset owners. The System Operator shall ensure the co-ordination of the
tests in consultation with all affected Users.
18.3.5. The System Operator shall specify minimum emergency requirements for
Distribution Control Centres, Power Station Control Centres and substations to ensure
continuous operation of their control, recording and communication facilities.
Other Users shall comply with the System Operator’s reasonable requirements for
contingency and emergency plans.

18.3.6. The System Operator shall set the requirements for automatic and manual load
shedding. Users shall make available loads and schemes to comply with these requirements.
18.3.7. The System Operator, in consultation with the TSP shall be responsible for
determining all operational limits on the Transmission Network, updating these periodically
and making these available to the Users.
18.3.8. The System Operator shall conduct load flow studies regularly (at least monthly) to
determine the effect that various component failures would have on the reliability of the
Transmission Network. At the request of the System Operator, Distribution Network
Operators shall perform related load flow studies on their part of the network and make the
results available to the System Operator.
18.3.9. Procedures and facilities
System Operator shall ensure that the necessary procedures and facilities are in place to
support quick and secure re-establishment of the Shutdown parts and restore supply to Users.
18.3.10.Safety
The System Operator shall De-energise certain Plant in order to provide for safe and secure
operation of the Transmission System within prescribed standards, including:
(a) During a System Emergency Condition;
(b) During Power System restoration; and
(c) Following the issue of a declaration of being in an Extreme Operating State.
18.4. RESTORATION OF SUPPLY
18.4.1. Restoration plan
The System Operator shall develop and maintain a well-documented Power System
restoration plan for the Nigerian Power System. The System Operator shall consult with all
the stakeholders on at least an annual basis to review the restoration of supply in Nigeria. The
Power System restoration plan shall include the restoration of the Power System from a Total
Shutdown and shall also address a Partial Shutdown.
The System Operator shall inform all the Users of the Procedure for Power System
restoration at the time of a Partial or Total Shutdown. Each User shall abide by the System
Operator's instructions during the restoration process, subject to the safety of personnel and
the Users’ Plant.
18.4.2. Training
The System Operator shall be responsible for the training of all personnel who may be
involved in Power System restoration. They must be familiar with, and adequately trained and
experienced in their standing instructions and other obligations so as to be able to implement
the Procedures and comply with any Procedures notified by the System Operator.
18.4.3. Extreme Operating State test

The System Operator shall, in consultation with all stakeholders, issue an Extreme Operating
State declaration at least once each year. This will be a test and not a real situation. The
purpose of this would be to ensure proper training of all personnel involved. The
stakeholders shall be notified in advance of the content of the tests and a date and time for
execution of the tests shall be agreed. The stakeholders must, acting in accordance with Good
Utility Practice, co-operate with any such testing.
18.5. BACK-UP CONTROL CENTRE
18.5.1. Plan
The System Operator shall have a plan to continue its operations in the case of the National
Control Centre becoming inoperable. This plan could include a permanent Back-up Control
Centre shadowing the main National Control Centre with the appropriate trained staff on
site. In this case the Back-up Control Centre shall be located remote from the site of the
National Control Centre.
18.5.2. Training
The System Operator shall also ensure that the staff members of the Back-up Control Centre
have been well informed and well trained to enable them to operate the Power System
securely. This site shall also be equipped with the required telecommunication infrastructure
capable of transferring all relevant data and the required voice communications needed to
operate the Power System.
18.6. EMERGENCY CO-ORDINATION FACILITY
18.6.1. The System Operator shall make provision for an emergency co-ordination facility as
part of the restoration plan.
18.6.2. The emergency co-ordination facility shall mean a site, remote from the National
Control Centre, providing at least the minimum level of communication capabilities necessary
for operation of the Power System. The emergency co-ordination facility shall be utilised in
the event that an emergency situation or major failure of facilities at the NCC (and/or Back-
up Control Centre if applicable) prevents operation from either the NCC or the Back-up
Control Centre.
18.6.3. In the event of the emergency co-ordination facility being utilised, the System
Operator shall be able to communicate with the following stakeholders during such an
emergency:
(a) All Users;
(b) The Commission;
(c) The Federal Government; and
(d) The Defence force.

18.6.4. The System Operator shall ensure that the emergency co-ordination facility is
equipped with up to date Single Line Diagrams, operating diagrams and operating procedures
at least once a year.
18.7. UNDER-FREQUENCY LOAD SHEDDING
18.7.1. Policy and analysis
The Under-Frequency Load Shedding shall be the last step during an emergency. All other
remedial steps should have been taken already.
The Under-Frequency Load Shedding scheme shall be studied by the Operational Planning
staff on an annual basis and it shall be the responsibility of the TSP to promptly implement
any modifications.
Under-Frequency Load Shedding shall be in steps related to one or more of the following:
Frequency, rate of Frequency decay, voltage level, rate of voltage decay or power flow.
The System Operator shall be responsible for compiling a proper Under-Frequency Load
Shedding scheme policy. This policy shall be revised as necessary and the scheme shall be
revised on an annual basis or when the policy changes. As initial policy, five Under-Frequency
Load Shedding steps can be recommended. However, this needs to be studied in detail by the
Operational Planning staff. These five steps are:
(a) 10 % of the maximum Demand at 49.2 Hz with a 0.3 second delay;
(b) 10 % of the maximum Demand at 49.0 Hz with a 0.3 second delay;
(c) 10 % of the maximum Demand at 48.8 Hz with a 2 second delay;
(d) 10 % of the maximum Demand at 48.5 Hz with a 2 second delay; and
(e) 10 % of the maximum Demand at 48.2 Hz with a 2 second delay.
[Note: The above-mentioned steps are an example only. The specific conditions in Nigeria
need to be studied in order to develop suitable steps for the Nigerian Power System].
18.7.2. Under Frequency Load Shedding scheme
The System Operator shall ensure that the Power System is equipped with a well-coordinated
Under-Frequency Load Shedding scheme.
The Under-Frequency Load Shedding scheme shall automatically be activated by the
relays for insufficient Generation or Transmission capacity to safeguard the Power
System.
The System Operator shall ensure that the under Frequency Load shedding relays are
located on circuits where it is less likely that the Loads can be switched away.
18.7.3. Co-ordination
Under Frequency Load shedding shall be coordinated throughout the Power System with
other under Frequency isolation, such as Generating Unit tripping or isolation, shunt

capacitor tripping, and other automatic actions which occur during abnormal Frequency or
voltage conditions.
18.7.4. Testing
Under Frequency Load shedding relays shall be tested at six-monthly intervals to ensure that
they are still connected and in good working order.
18.7.5. Manual Load shedding
Should the Under-Frequency Load Shedding not be sufficient, the System Operator shall
shed Load manually if the System can still be saved from a Total Shutdown.
18.7.6. Re-Synchronisation
The System Operator shall shed additional Load manually before re-Synchronising the
different islands after the Power System separates into various islands and there is insufficient
generating capacity in the islands to restore the Power System Frequency following Under-
Frequency Load Shedding.

19. SECTION: OPERATIONAL PLANNING
19.1. OBJECTIVE
19.1.1. The objective of Operational Planning is to specify technical, design, information
exchange and procedures to be applied by the System Operator to ensure proper operation of
the Transmission System in the short to medium term. This also includes the studying and
documentation of short and medium-term events. It shall ensure that the System Operator is
prepared for short to medium term situations and emergencies. This Section describes the
different technical activities necessary to ensure that Users and System Operator are well
informed of the status of the System during maintenance, planned Outage and following a
Forced Outage condition.
19.2. GENERAL
19.2.1. The following activities shall be performed by the System Operator to enable it
operationally plan for a stable Power System at all times:
(a) Create a data base for:
(i) Steady state;
(ii) Sequence data; and
(iii) Dynamic data.
(b) Compile a representative model for:
(i) Peak and minimum loading for present year; and
(ii) Peak and minimum loading for the next five years.
(c) Perform load flow studies for all cases involved, checking the power flow and
the voltage profile for the existing network;
(d) Calculate maximum and minimum fault levels at all substations on at least an
annual basis;
(e) Use the daily Demand Forecast to conduct n-1 / n-2 contingency studies to
prepare for the next operational day, or any other situation in the near future.
All the maintenance plans shall be studied to see the feasibility of that Outage in
the next day or near future. This shall prepare the National Control Centre for
any unexpected conditions that could occur. This is important considering any
maintenance on major transmission lines that could be planned for the next day;
(f) Conduct contingency studies for 2 years in advance and prepare a strategy of
how to achieve the Reliability indices pursuant to Subsection 23.4
(g) The results of the contingency studies shall be documented in a contingency
plan. This plan shall be needed when the remaining lines overload or have
severe voltage depression. The contingency plan shall be studied to arrive at a

viable operational solution. The primary aim shall be to maintain supply to the
Users;
(h) In order to prepare the contingency plan, the thermal rating of all the links
should be determined for the relevant areas of the network. It should also
include the transformer rating and breaker breaking capacity. It is important to
have information of both the 75ºC and 90ºC thermal limits of all the power
Equipment involved;
(i) The results shall be in the form of a load flow diagram, and the contingency
plan shall consist of the load flow diagram and detailed switching instructions
and precautions that should be taken prior to any operational activity;
(j) The dynamic data shall be used to perform studies related to voltage collapse
that could occur during certain contingencies. It shall also be used to see the
dynamic behaviour of the system during certain major contingencies. It can
also be used to check the optimum ARC dead time for the circuits. Some of
these times can be optimised and subsequently lead to the improvement of the
Quality of Supply to Users;
(k) Voltage collapse studies should also be performed using steady-state data. This
shall be necessary to determine the maximum transfer across a part of network.
These studies shall indicate at what stage more expansion would be needed
given the rate of consumer Load growth in a particular area;
(l) The System Operator’s Operational Planning staff shall ensure that the
contingency plan documentation is in the control room and that these
documents are always updated to the latest expansion of the Power System; and
(m) System Operator’s Operational Planning staff shall study the implementation of
the Under-Frequency Load Shedding scheme. These studies shall be updated on
at least an annual basis and the new settings and requirements shall be given to
the TSP to implement as soon as possible.
19.3. FUNCTIONS OF THE OPERATIONAL PLANNING STAFF
19.3.1. The Operational Planning staff of the System Operator shall perform the following
functions.
(a) Development of plan
The System Operator shall develop a set of operational plans, which are designed to
evaluate options and documented procedures for reliable operation.
(b) Maintenance of operational plans
The System Operator shall maintain a set of operational plans, which are designed to
evaluate options and documented procedures for reliable operation.
(c) Plan implementation

The System Operator shall utilise the appropriate staff to implement operational
plans and to assure that the System is operated reliably and securely.
(d) Information and training
The System Operator shall also ensure that the National Control Centre and the
relevant Control Centre staff are well informed and trained to use this information.
(e) Reviews
The Operational Planning staff of the System Operator shall be responsible for
reviewing the Under-Frequency Load Shedding scheme, as defined in Subsection
18.7.2 on at least an annual basis.
19.3.2. The Operational Planning staff shall be experienced in the operation and planning of
a Power System. The required areas of expertise are the following:
(a) Technical Operational Studies
(i) Load flows;
(ii) Contingency studies;
(iii) Under-Frequency studies
(iv) Dynamic studies (Power System stability);
(v) Voltage collapse;
(vi) Fault level (short circuit) studies; and
(vii) Energisation studies.
(b) Operational Documentation
(i) System operation guidelines;
(ii) System Operation Procedures; and
(iii) Database creation, storage and achieving.
(c) Emergency operation and Power System restoration
The System Operator Operational Planning staff will have major inputs into the
restoration plans of the System Operator as defined in Subsection 18.4.
19.4. DATA REQUIRED FOR MEDIUM TERM AND OPERATIONAL
PLANNING
19.4.1. By week 32 of each Calendar year, each User shall provide the System Operator with
the data requested below (except Demand solely related to Power Station Auxiliary Plant
when fed in accordance with pre-agreed feeding arrangements), for the next two Calendar
years.
19.4.2. Profiles

Users shall supply the following information in writing to the System Operator annually in
advance:
(a) Typical monthly maximum and minimum Demand values of the anticipated
Demand per Connection Point over a year;
19.4.3. Generating Units
Users shall supply typical Active and Reactive Power profiles for their operation, and
Availability as appropriate, for Generating Units under their control and for Embedded
Generating Units where the total registered capacity of Generating Units on a single site
exceeds 5MW. The method for submitting these data schedules for such Generating Units
shall be the same as provided for in the Market Rules or other agreements with the SO.
19.4.4. On the last Business Day of every calendar week, Users shall provide the System
Operator with the data requested below (except Demand solely related to Power Station
Auxiliary Plant when fed in accordance with pre-agreed feeding arrangements), for the
following 14 days after the submission.
19.4.5. Day-ahead Demand and Availability Forecast
(a) Demand Forecast factors
The System Operator shall take the following factors into account when conducting
Day-ahead Demand Forecasting:
(i) Historical Demand data;
(ii) Weather forecasts and the current and historical weather conditions;
(iii) The incidence of major national and local events or activities that are known
to the System Operator in advance;
(iv) Transmission System losses;
(v) Embedded Generating Units;
(vi) Demand Control of 1 MW or more proposed to be exercised by any
Distribution Network Operator and of which the System Operator has been
informed;
(vii) Other information supplied by Users; and
(viii) Interconnection transfers.
(b) Demand Forecast methodology
System Operator shall use a Demand Forecast methodology based on factors in
19.4.5(a) to produce, by standard utility means, unbiased forecasts of Demand
including that to be met by Embedded Generating Units. Demand shall be
calculated from these forecasts, but shall also take into account factors (e), (f), (g)
and (h) in Subsection 19.2.1
(c) Demand Profiles

Users shall supply the following information in writing to the System Operator 14
days in advance:
(i) Typical weekly maximum and minimum Demand values of the anticipated
Demand per Connection Point over a 14 day period;
(d) Demand Off-takers shall supply Active and Reactive Power demand profiles by
8:00 hours on the Pre-Dispatch Day of the amount and duration of anticipated
Demand Control per Connection Point that may result in a Demand change of
1 MW or more during each Dispatch Period of the Dispatch Day.
(e) Generating Units
Users shall supply typical Active and Reactive Power profiles for their operation,
and Availability as appropriate, of Generating Units under their control and those
Embedded Generating Units where the total registered capacity of Generating Units
on a single site exceeds 5MW. The method for submitting these data schedules for
such Generating Units shall be the same as provided for in the Market Rules (or by
such electronic data transmission facilities as have been agreed upon with the
System Operator) or other agreements with the SO.
19.5. ACTUAL DEMAND CONTROL DATA
19.5.1. Off-takers shall supply the following in writing (or by such electronic data
transmission facilities as have been agreed upon with the System Operator) to System
Operator each day:
(a) By 01:00hr: Active Power profiles per Connection Point for the previous
Dispatch Day of the amount and duration of Demand reduction achieved from
the use of Demand Control of 5MW or more (averaged over Dispatch Periods
on any Connection Point), for each Dispatch Period.
(b) by 12:00hr: Off-takers Customers shall notify System Operator of their
intending Demand Control including customers demand management which
may result in change of 5MW or more power on the Transmission Network.
19.6. CONNECTIONS
19.6.1. New connections
Users shall provide to the System Operator written information pertaining to new
connections or additional Generation or Demand greater than 1 MW immediately when
this information becomes available. This information shall include:
(a) Anticipated connection date;
(b) Location of connection;
(c) Size of consumers category of connection (e.g. residential, industrial etc.); and
(d) The typical profiles of the anticipated Generation or Demand on half hourly
basis for defined categories of day type as determined by the System Operator;

19.6.2. Disconnection
Users shall provide to the System Operator written information pertaining to
disconnection of existing Generation or Demand immediately and not more than 12
Calendar weeks when this information becomes available. This information shall include:
(a) Anticipated disconnection date;
(b) Location of connection;
(c) Size of connection; and
(d) The revised typical profiles of the anticipated Generation or Demand on a half
hourly basis at the Connection Point for defined categories of day type as
determined by the System Operator;
19.7. CHANGES TO INFORMATION ALREADY SUPPLIED
19.7.1. Changes
Users shall inform the System Operator of any changes to the information already
supplied as soon as this information is available. This information shall be provided in
writing, or as otherwise agreed between Users and the System Operator, such agreement
not to be unreasonably withheld.
19.7.2. Monthly confirmation
The Off-takers shall confirm in writing on the 5th
Business Day before the end of every
month that the most recently submitted Active Power Demand profiles for the following
two months are in accordance with their current best estimate of these values.
19.7.3. Weekly Confirmation
Users shall confirm in writing on the last Business Day of every week that the most
recently submitted data profiles for the following 14 days are in accordance with their
current best estimate of these values.
19.8. TIMING AND PUBLICATION
19.8.1. The System Operator shall provide a day ahead Demand forecast for the
Transmission System each Pre-dispatch Day by 11:00 for each Dispatch Period for the next
Dispatch Day. This information shall be provided by being posted in the System Operator
Website or other agreed medium and shall be in a format reasonably determined by the
System Operator and Users as being suitable.
19.8.2. The Demand Forecast shall include Transmission System losses.

20. SECTION: INFORMATION EXCHANGE
20.1. OBJECTIVE
20.1.1. The objective of this Section is to provide for the exchange of information so that the
implications of an Operational error and/or Power System Event can be considered. The
possible risks must be assessed and appropriate action taken by the relevant party in order to
assist in maintaining a secure Power System. The correct information needs to be identified
and communicated to the correct structures in the Nigeria ESI.
20.2. GENERAL
20.2.1. This Section sets out the requirements for the exchange of information particularly in
relation to Operations and/or events on the Power System, which have had or shall have an
operational effect, and thereby have become Power System incidents (being an “Abnormal
Operation” or an “Event”:
(a) On the Transmission System in the case of an Abnormal Operation and/or
Event occurring on a User’s system; and
(b) On a User’s system in the case of an Abnormal Operation and/or Event
occurring on the Transmission System.
20.2.2. The System Operator shall report any Event or Abnormal Operation on the
Transmission System to all Users. This notification is expected to report what shall happen or
what has happened on the Power System.
20.2.3. The System Operator shall have information available for system incident analyses by
means of:
(a) The System Operator’s SCADA system(s) and other data collection systems;
and
(b) Information provided to the System Operator by Users under other Subsections
of this Code.
20.3. REQUIREMENT TO NOTIFY
20.3.1. The System Operator Transmission Service Provider and the Users shall agree to
review from time to time which Abnormal Operations and Events shall be required to be
notified.
20.4. NOTIFICATION OF AN ABNORMAL OPERATION
20.4.1. The System Operator shall establish and implement operating instructions,
Procedures, standards and guidelines to cover the operation of the network under normal and
abnormal conditions.

20.4.2. The System Operator shall notify all Users of any Abnormal Operations on the
Transmission System, which shall have, in the reasonable opinion of the System Operator, an
operational effect on any User.
20.4.3. The System Operator may proceed with urgent operations without notifying all Users
and without the required procedures. This can only be done if it is of a temporary nature and
less than 15 minutes. The System Operator shall notify all Users of any operations on the
Transmission System without any delay as soon as the System has been restored to normal.
The System Operator shall also inform the Users as to the likely duration of the condition
and shall update this prognosis as appropriate. The System Operator shall additionally inform
the Users as soon as reasonably possible when the condition has ended.
20.4.4. The User shall notify the System Operator of Abnormal Operations on the User’s
system, which shall have an operational effect on the Transmission System. The System
Operator shall notify any Users on whose system(s) the Abnormal Operation shall have an
operational effect.
20.5. FORM OF NOTIFICATION OF AN ABNORMAL OPERATION
20.5.1. A notification of an Abnormal Operation shall be of sufficient detail to describe the
Abnormal Operation and to enable the recipient of the notification to reasonably consider
and assess the implications and risks arising.
20.5.2. A notification shall include the name of the individual reporting the Abnormal
Operation on behalf of the System Operator or the User, as the case may be.
20.5.3. The recipient of the notification may ask questions to clarify the notification and the
System Operator or the User shall answer any questions raised.
20.6. RECORDING OF AN ABNORMAL OPERATION
20.6.1. The notification shall be given in writing whenever possible before carrying out an
Abnormal Operation. The notification shall be given orally if there is insufficient time before
the operation is scheduled to take place for notification to be given in writing. If either the
User or the System Operator requests it, it shall be submitted as soon as possible, after the
system has returned to normal, in writing.
20.6.2. The System Operator shall maintain a database of notifications on the System.
20.7. TIMING IN RESPECT OF AN ABNORMAL OPERATION
20.7.1. A notification shall be given as far in advance as possible and in any event shall be
given in sufficient time as will reasonably allow the recipient to consider and assess the
implications and risks arising.

20.8. NOTIFICATION OF EVENTS
20.8.1. The System Operator shall notify the Users of Events which in the reasonable
opinion of the System Operator are significant system incidents having an operational effect
on the Users.
20.8.2. The Users shall notify the System Operator of Events which may be significant
system incidents affecting the Transmission System. The System Operator may use this
information in notifying any other Users of the Event.
20.9. FORM OF NOTIFICATION OF AN EVENT
20.9.1. A notification of an Event shall describe the Event clearly. The information shall be
of sufficient detail to enable the recipient of the notification to consider and assess the
implications and risks arising.
20.9.2. A notification shall include the name of the individual reporting the Event on behalf
of the System Operator or the User, as the case may be.
20.9.3. The recipient of the notification may ask questions to clarify the notification and the
System Operator or the User shall answer any questions raised.
20.10.PROVISION OF FURTHER INFORMATION
20.10.1.The System Operator shall provide additional information to a User after the User
has reported an Event. The User may request the fault level at the time of the incident to
perform more accurate assessments following an Event.
20.11. RECORDING OF AN EVENT
20.11.1.Notification of an Event shall be given orally in the first instance. Significant System
incidents must be reported in writing if requested by either the User’s or the System
Operator.
20.11.2.The System Operator shall maintain a database of Events on the system.
20.12.TIMING IN RESPECT OF AN EVENT
20.12.1.A notification of an Event shall be given as soon as practicable after the occurrence
of the Event. A notification of an Event shall be given within fifteen minutes, except in an
emergency.
20.13.OPERATIONAL COMMUNICATION AND DATA RETENTION
20.13.1.It is necessary that adequate communication facilities and procedures be established
between the System Operator and Users to allow for the timely transfer of information, in
order that the System Operator may fulfil its obligations with regard to the operation of the

20.13.2.The objectives are:
(a) To establish contact locations for the System Operator and each class of User;
(b) To detail the communication facilities required between the System Operator
and each class of User;
(c) To establish the Procedure for communication of information between the
System Operator and Users;
(d) To establish the Procedure for the authorisation of the System Operator
personnel to act on behalf of the System Operator, and User’s personnel to act
on behalf of the Users in the communication of information between the
System Operator and Users; and
(e) To establish the general procedures for the retention of data.
20.13.3.Both the System Operator and Users shall be obliged to adopt the use of new
technologies and methodologies for communication of information, where there is a
recognisable benefit from doing so, and to do so would be reasonable in the circumstances.
20.14.CONTACT LOCATIONS
20.14.1.The System Operator
The contact location within the System Operator for communication on matters
pertaining to the real-time operation of the Transmission System shall be the National
Control Centre (NCC) or if designated the Back-up Control Centre.
The System Operator shall, from time to time, notify all the Users of the relevant details
for contacting the System Operator.
The System Operator shall, from time to time, distribute to each User an organisational
chart and list of personnel and contact numbers in order to assist the Users in
communicating with the System Operator.
20.14.2.Generators
The Generators’ contact locations and personnel shall be notified to the System
Operator by the Generator prior to connection and thereafter it shall be updated as
appropriate.
The Generator shall be required to provide a control Facility (control room to control
the Power Station). The Generator shall ensure by acting in accordance with Good
Utility Practice that the control Facility is staffed at appropriate staffing levels at all times.
The control Facility shall be staffed by a responsible operator(s) who shall respond to
communications from the System Operator without undue delay. The operators shall be
of suitable experience and training and shall be authorised to perform the following
functions on behalf of the Generator:
(a) To accept and execute Dispatch Instructions; and

(b) To receive and acknowledge receipt of requests, for amongst other matters,
operation outside the registered values of Availability, Ancillary Service
capability, or operating characteristics of the Generating Units during System
Emergency Conditions as stipulated in Appendix 8.
At any point in time, a single person shall be designated as the Responsible Manager by
the Generator and notified to the System Operator. The Responsible Manager shall be
responsible for dealing with the System Operator on matters relating to the Grid Code.
In the event that the Responsible Manager is not a person on duty at the control Facility,
then the Responsible Manager must be capable of being contacted from the control
Facility at all times. In the event that the System Operator issues a request to the control
Facility requiring the Responsible Manager to contact the NCC, the Responsible
Manager shall comply with the request without undue delay and in any case within 15
minutes of the request.
The Responsible Manager shall be authorised by the Generator to perform the following
functions on behalf of the Generator:
(a) To make estimates in accordance with Good Utility Practice as to the
Availability, Ancillary Service capability and operating characteristics of each
Generating Unit;
(b) To make declarations for each Generating Unit; and
(c) To communicate with respect to issues regarding Outages of each Generating
Unit.
The Generator may, from time to time, notify a replacement contact location and
personnel, which meets the foregoing requirements.
20.14.3.Directly Connected Customers
The Directly Connected Customer shall notify the System Operator of its contact locations
and the detail of its personnel prior to connection and thereafter it shall be updated as
appropriate.
The Directly Connected Customer is required to provide the System Operator with the
contact information of a responsible operator(s) who shall respond to communications from
the System Operator without undue delay. The operators shall be of suitable experience and
training and shall be authorised to perform functions on behalf of the Directly Connected
Customer.
The responsible operator shall have the ability to attend to the site of the Directly Connected
Customer within 60 minutes of an instruction being issued by the System Operator.
At any point in time, the Directly Connected Customer shall notify the System Operator of a
single person designated by the Directly Connected Customer as the Responsible Manager.
The Responsible Manager shall be responsible for dealing with the System Operator on
matters relating to the Grid Code. In the event that the Responsible Manager is not a person
on duty at the site of the Customer Connected to the Transmission System, then the
Responsible Manager must be capable of being contacted from the site of the Directly

Connected Customer at all times. In the event that the System Operator issues a request to
the site of Directly Connected Customer requiring the Responsible Manager to contact the
NCC, the Responsible Manager shall comply with the request without undue delay and in any
case within 60 minutes of the request.
20.14.4.Distribution Network Operators
The Distribution Network Operator shall notify the System Operator of its contact locations
and the detail of its personnel prior to connection and thereafter it shall be updated as
appropriate.
The Distribution Network Operator shall be required to provide a control Facility.
The Distribution Network Operator shall ensure by acting in accordance with Good Utility
Practice that the control Facility is staffed at appropriate staffing levels at all times.
The Distribution Network Operator shall operate its control Facility according to the
provisions agreed upon with the System Operator as set out in the Distribution Network
Operator’s and the System Operator agreement.
20.15.COMMUNICATION FACILITIES
20.15.1.All communication facilities to be provided shall be in accordance with the provisions
of this Code.
20.15.2.All Equipment to be provided by the Users shall comply with the applicable
International Telecommunications Union (ITU) and International Electrotechnical
Commission (IEC) standards. This shall apply for SCADA and communications Equipment
and shall meet such standards as notified in advance by the System Operator of their design
or procurement and shall be provided at the cost of the Users, except where otherwise
specified.
20.16.SUPERVISORY CONTROL AND DATA ACQUISITION (SCADA)
20.16.1.SCADA Remote Terminal Units shall be required in all the control rooms of the
System Operator and at the Off-taker’s boundary site and the Generator’s control room for
the transmission of signals and indications to and from the NCC. The signals and indications,
which must be provided by Users for transmission by SCADA Equipment to the NCC, shall
be the signals and indications as agreed to by the System Operator and may from time to time
be changed by agreement.
20.16.2.Interface cabinets shall be installed in the relevant control room and the User shall
provide and maintain wiring and signalling from the User's Plant and Apparatus to the
interface cabinet. In the case of the System Operator RTUs the TSP shall take this
responsibility.

20.17.COMPUTER EQUIPMENT
20.17.1.Each User shall comply with the System Operator requirements and provide
appropriate computer and data networking Equipment to allow data exchange, such as
electronic mail, Dispatch Instructions etc. between the System Operator and the User. The
User shall only use this Equipment for operational communications with the System
Operator.
20.17.2.Each User shall be responsible for optimising the Reliability and security of the
computer Equipment including the provision, at no charge, of an uninterruptible power
supply.
20.18.TELEPHONE/FACSIMILE
20.18.1.Each User shall be responsible for the provision and maintenance of telephone and
facsimile Equipment.
20.18.2.The System Operator shall provide one or more telephone extension to be connected
to the System Operator private operational telephone system. This Facility shall be reserved
for operational purposes only, and shall be attended continuously by an authorised
operational person and answered without undue delay. Users shall be responsible for
optimising the Reliability and security of this telephone service including the provision at no
charge of an uninterruptible power supply.
20.18.3.Users shall provide a public switched telephone network circuit to the
communications and control room.
20.18.4.Users shall provide no less than two separate public switched telephone network
circuits to the control Facility.
20.18.5.Users shall provide no less than one facsimile unit, connected to a dedicated public
switched telephone network circuit at the control Facility.
20.19.ACCESS AND SECURITY
20.19.1.All SCADA, metering Equipment, computer and communications Equipment that
interfaces with the System Operator, and the information carried by it must be secured
against unauthorised access. Procedures governing security and access shall be agreed with
the Users in the operation instructions, but shall allow for adequate access to the Equipment
and information by the System Operator for the purposes of maintenance, repair, testing and
the taking of readings.
20.20.TIME STANDARDS
20.20.1.Time shall be set by a standard determined by the System Operator. The time
standard shall be broadcast to relevant telecommunications devices in order to maintain time
coherence.

20.21.COMMUNICATION BETWEEN THE USERS
20.21.1.Communication between the System Operator, the Users on matters pertaining to the
real-time operation of the Transmission System shall take place between the NCC and the
User’s control Facility, unless where specifically provided for in other Sections of this Code.
20.21.2.The System Operator shall ordinarily notify the Users as soon as practicable after the
decision to move the NCC to a different location. This shall be no less than seven (7) days
prior to the move, but in the event of an emergency it may instead notify them as soon as
practicable after the move.
20.21.3.All instructions given by NCC and communications between NCC and the User’s
control facilities shall be given by means of the specified communication facilities, unless
otherwise specified in the Grid Code.
20.21.4.The System Operator, the Users shall accept any automatic recording of
communications given by means of telephony, electronic means, facsimile transfer or telex as
evidence of instructions or communications.
20.22.DATA AND NOTICES
20.22.1.Data and notices shall be submitted in accordance with relevant rules and procedures.
20.22.2.Data and notices to be submitted to the System Operator or to the Users, under the
Grid Code shall be in writing and shall be delivered by hand or sent by pre-paid post, by
telex, receipted email or facsimile transfer.
20.22.3.Data and notices to be submitted to the System Operator under the Grid Code shall
be addressed to the person, and at the address, notified by the System Operator to the Users
for such purpose in their respective Agreements.
20.22.4.Data and notices to be submitted to the Users under the Grid Code shall be
addressed to the Users representatives as nominated in the Agreements. Or to such other
person or address as the Users may notify to the System Operator from time to time.
20.22.5.All data items, where applicable, shall be referenced to nominal Voltage and
Frequency unless otherwise stated.
20.22.6.All operational data shall be supplied in accordance with the timetables as set out in
the Grid Code.
20.23.DATA RETENTION
20.23.1.This provision has to be read in conjunction with the Market Rules to form the
complete requirement with regard to data retention.
20.23.2.Operational data is all data to be supplied by Users under this Code and any other
data expressly provided to be operational data under this Code. Operational data to be
supplied by the Users shall be submitted to the department or address as the System
Operator may from time to time advise.

20.23.3.The Users shall keep all operational data confidential.
20.23.4.System Operator shall maintain a complete and accurate record of all operational data
supplied or maintained under the Grid Code. The format for the retention of records shall be
as the System Operator may reasonably determine. All operational data shall be maintained
for a period of no less than three (3) years commencing from the date the operational data
was first supplied (or first created, if earlier).
20.23.5.The System Operator shall allow the Users access to its records (and copies thereof)
of operational data and/or data required to be maintained, on reasonable notice.

21. SECTION: SCHEDULING AND DISPATCH
21.1. OBJECTIVE
21.1.1. The objective of this Section is to provide Generators with provisional running orders
for the Dispatch Day ahead, such that Generating Units will be made available in the correct
timescale to enable the System Operator to Dispatch them whilst maintaining the required
Operating Reserve. In order to achieve the primary objective, this Section details the
timescale for the System Operator to make specific information available to Generators and
other Users.
21.1.2. A further objective of this Section is to establish a framework to enable the System
Operator to issue Dispatch Instructions to:
(a) Generators with respect to their Generating Units; and
(b) Users in relation to Ancillary Services.
Dispatch Instructions are primarily issued such that available Generation is matched to
Demand with appropriate margin of Operating Reserve whilst maintaining the integrity and
security of the Transmission System with acceptable Quality of Supply.
21.2. GENERAL
21.2.1. The System Operator shall dispatch Generating Units according to Market Rules,
subject to constraints of safety of personnel, Equipment, System Security, System Stability,
Reliability and the environmental requirements.
21.2.2. The Dispatch of Generating Units is necessary to ensure that the most economical
combination of Generating Units possible is used for each Dispatch Period. This optimal
combination of Generating Units must meet the Demand such that the necessary Frequency
Control can be achieved.
21.2.3. In order to achieve this, the System Operator will have to calculate the optimal
combination of Generating Units on a continuous basis using specialised software suitable for
this. These calculations by the System Operator are based on Day-ahead Nominations from
Generators for each Generating Unit and the anticipated Demand.
21.3. DATA AND PROCESS
21.3.1. The System Operator shall forecast the Power System Demand in accordance with
Subsection 19.4.5 that shall be used in the Dispatch process.
21.3.2. System Operator shall set the level of Reserve that shall be used in the Dispatch
process.
21.3.3. System Operator shall include in the Dispatch Instructions the Active Power Output
level of a Generating Unit, Synchronising or De-synchronising time, if appropriate and
Ancillary Services to be provided.

21.3.4. System Operator shall adjust Generating Unit Active Power Output by using a merit
order based (this may be manual or by using specialist software) on the Day-ahead
Nominations provided by Generators for each Generating Unit as variations occur due to
such factors as Demand or Availability variations.
21.4. DISPATCH SCHEDULING
21.4.1. Production of a Dispatch Schedule
Each day between 13:00 hours and 16:00 hours the System Operator shall produce the two
Dispatch Schedules pursuant to Subsections 21.4.2 and 21.4.3 for the Dispatch Day. The
System Operator may produce the Dispatch Schedule more or less frequently, or reasonably
delay its production in response to changes in Availability and other events that may arise.
The Dispatch Schedule is utilised by the System Operator in its scheduling and in its
preparation for Dispatch of Generating Units.
In preparing the Dispatch Schedule, the System Operator shall schedule Day-ahead
Nominations to minimise the offered cost of meeting Load forecast according to the
principles set out in Subsection 23.3, taking into account the following factors:
(a) Forecast Demand and geographical Demand distribution;
(b) Generating Units’ Registered Information, including operating characteristics,
Ancillary Service capability and Availability;
(c) Generator Day-ahead Nominations, including Nominations by Hydro Generating
Units;
(d) Declared abnormal risks to Generating Units;
(e) Ancillary Service requirements, including Frequency Control, Operating Reserve and
Voltage Control;
(f) Reliability Must-run requirements;
(g) Transmission System constraints, including Network and Generating Unit
constraints;
(h) Transmission System losses;
(i) System Operator and Users’ monitoring and test requirements;
(j) Transmission System stability implications;
(k) Interconnector Capacity Entitlements and Interconnector Energy Trade
Nominations pursuant to Rule 25 of the Market Rules;
(l) Interconnection Agreements;
(m) Other factors as may be reasonably considered by the System Operator to be
relevant to the Dispatch Schedule.
21.4.2. Pre-dispatch Day constrained Schedule

The System Operator shall produce a Pre-dispatch Day constrained Schedule for each
Dispatch Day by 16:00 hours on the Pre-dispatch Day.
The System Operator shall issue provisional running orders based upon the Dispatch
Schedule for the Dispatch Day to the Generator for each Generating Unit by 16:00 hours on
the Pre-dispatch Day.
The provisional running orders issued to each Generating Unit by the System Operator, shall
indicate the planned Generating Unit Active Power Output pattern specifying:
(a) Forecast start-up and shut-down times, if relevant;
(b) Forecast Active Power Dispatch levels for each Dispatch Period; and,
(c) Forecast levels of Operating Reserve provision for each Dispatch Period, if the
Generating Unit is contracted for Operating Reserve requirements.
Provisional running orders are indicative only, provided as a guide to the expected output
requirements from Generating Units and are not Dispatch Instructions.
21.4.3. Pre-dispatch Day unconstrained Schedule
The System Operator shall produce a Pre-dispatch Day unconstrained Schedule for each
Dispatch Day by 16:00 hours on the Pre-dispatch Day. The same principles specified in
Condition 21.4.1 shall be applied with the following change:
(a) The known Transmission System constraints must be excluded.
This Schedule shall be used to forecast the Day-ahead Price consistent with the
appropriate Market Rules.
21.4.4. Dispatch Day schedule
If the System Operator forecasts a significant difference between the provisional running
orders and anticipated Dispatch Instructions, in the interval between the issue of
provisional running orders and the issue of relevant Dispatch Instructions, the System
Operator shall endeavour to notify this difference to impacted Generators.
21.4.5. System congestion
System Operator shall install and commission such real time Equipment and software as
to calculate Transmission Constraints and Reliability margins per Dispatch Period.
System Operator shall change the Dispatch Schedule of the Generating Units in order to
eliminate Transmission System congestion and to ensure the security and Reliability of
system operation.
System Operator shall reduce the Load in the importing region contributing to the
congestion if it was not possible to eliminate congestion by changing the Dispatch of the
Generating Units.
System Operator shall further instruct all Users to take specific action in order to avoid
more major disturbances in emergency situations.
21.4.6. Ex-post Unconstrained Dispatch Schedule

The System Operator shall produce an Ex-post Unconstrained Dispatch Schedule for
each Dispatch Day by no later than 12:00 hours on the Calculation Day. This leaves the
System Operator sufficient time to calculate the System Marginal Price for each Dispatch
Period pursuant Rule 33.2 of the Market Rules. The same principles specified in
Subsection 21.4.1 shall be applied with the following two changes:
(a) The actual Load readings must be used; and
(b) The Transmission System constraints must be excluded.
21.5. GENERATION DISPATCH
21.5.1. Dispatch Instructions to Generators
The System Operator shall issue Dispatch Instructions relating to the Dispatch Day at any
time during the period beginning immediately after the issue of the Dispatch Schedule in
respect of that Dispatch Day.
The System Operator shall give a Dispatch Instruction to a Generator for a specific
Generating Unit to change the output of Active Power, Reactive Power or an instruction to
provide an Ancillary Service.
The System Operator shall give Dispatch Instructions to a Generator orally, by phone or by
electronic means including by means of Automatic Generation Control. The Dispatch
Instruction shall identify the relevant Generating Unit by specifying the Generator’s and
Generating Unit’s unique identification number pursuant Rule 15.5.1 of the Market Rules.
A Generator shall immediately and formally acknowledge a Dispatch Instruction in respect of
a Generating Unit by telephone, or immediately provide a reason for non-acceptance. The
reason for non-acceptance shall only be on safety grounds (relating to personnel or Plant) or
because the Dispatch Instruction is not in accordance with the Nomination or the Registered
Information relevant to the time and period to which the Dispatch Instruction relates.
The System Operator shall be notified without delay by telephone in the event that in
carrying out the Dispatch Instruction, an unforeseen problem arises, caused on safety
grounds (relating to personnel or Plant).
The System Operator shall maintain a record of all daily Dispatch Instructions issued to
Generators.
21.5.2. Generation Synchronising and De-synchronising Times
The System Operator shall determine the required Synchronising and De-synchronising times
for Generating Units.
The System Operator shall issue Dispatch Instructions to Generators to Synchronise (or De-
synchronise) specific Generating Units in accordance with their Registered Information.
If a Dispatch Instruction to a Generator to Synchronise a specific Generating Unit does not
also contain an Active Power Output to be achieved then it shall be assumed that the

instruction is to increase output (following Synchronisation) up to the level of minimum
generation of the Generating Unit as specified in the Registered Information.
Where a Synchronising time is issued by the System Operator to a Generator for a specific
Generating Unit and the Generator identifies that the Generating Unit will not be
Synchronised within +/- 10 minutes of the instructed time, the Generator shall immediately
(at the time the discrepancy is identified) inform the System Operator of the situation and the
estimated new Synchronising time.
The allowable tolerance appropriate to Synchronising times shall be based on the times set
out in the Registered Information.
21.5.3. Generation Active Power Dispatch
Based on the Day-ahead Nominations of the Generators, on System conditions, and on other
factors as may arise from time to time, the System Operator shall issue Dispatch Instructions
to a Generator in relation to a specific Generating Unit, which has been instructed to be
Synchronised, to adjust its Active Power Output.
When a Generator has received and accepted a Dispatch Instruction for a Generating Unit to
change the level of Active Power, it shall without delay adjust the level of output of the
Generating Unit to achieve the new target in line with its Registered Information and its
Quantity Nomination.
A Generating Unit shall be deemed to have complied with a Dispatch Instruction when it
achieves an output within the allowable tolerance as specified in Rule 27.5 of the Market
Rules. Deviations outside the allowable tolerance band will be treated according to Rule 27.5
of the Market Rules.
The adjustment of Active Power Output of a Generating Unit operating in a Frequency
sensitive mode for System Frequency other than an average of 50Hz, shall be made in
accordance with the current registered value of Governor Droop for the Generating Unit.
The System Operator shall be notified immediately by telephone in the event that while
carrying out the Dispatch Instruction an unforeseen problem arises caused by safety reasons
(relating to personnel or Plant).
21.5.4. Generator Reactive Power Dispatch
The System Operator shall issue Dispatch Instructions to Generators to adjust the Reactive
Power output of any Generating Unit that has been instructed to be Synchronised.
(a) A Generator shall be able to provide Reactive Power within the Generating Unit
Capability Chart. The System Operator shall control the amount of reactive
power.
(b) For the avoidance of doubt the MVAr instruction may be to maintain a specific
Voltage utilising the Automatic Voltage Regulator. Where this Voltage target
cannot be achieved by the Generator due to its MVAr limits it shall inform the
System Operator.
(c) Voltage control and the supply or consumption of Reactive Power are inter-
related in the sense that the voltage is affected by changes in the Reactive Power

flow. System stability depends on the voltage profile across the System. In view of
these considerations it is necessary from time to time to employ certain Power
Stations to supply or consume Reactive Power, whether or not they are producing
Active Power, for the purpose of Voltage Control.
The Reactive Power output of any Generating Unit in respect of which a Dispatch
Instruction is given shall then, without delay be adjusted in accordance with its Registered
Information, to the new target Reactive Power so instructed, within, a tolerance of +/- 2%
of the target or +/- 2MVAr whichever is greater. The Reactive Power output of a
Generating Unit shall not be adjusted (other than under AVR action) other than in
response to a Dispatch Instruction from the System Operator.
Generators having achieved the new target Reactive Power output should not attempt to
sustain this level of Reactive Power output as the System Voltage varies but should, rather,
allow the Reactive Power output to vary under AVR control in accordance with registered
Ancillary Service capabilities in the Registered Information.
While a Reactive Power Dispatch Instruction shall normally specify a new Reactive Power
target for a Generating Unit, the System Operator may also from time to time instruct
Generators to perform one or more tap changes on the Generating Unit Transformer of a
Generating Unit if it has on-load tap-change capability. The instruction for tap changes
may be a simultaneous tap change instruction whereby the tap change shall be effected by
the Generator in response to an instruction from the System Operator issued
simultaneously to relevant Power Stations. The instruction, which is normally preceded by
advance warning, shall be effected within 1 minute of receipt from the System Operator of
the instruction.
Where a Generating Unit has off-load tap-change capability the SO shall before it
synchronises instruct it to the appropriate tap position.
a. Where the SO does not give such instruction the Generator shall request the SO to
give this instruction.
Dispatch Instructions in relation to Reactive Power shall include target Voltage levels to
be achieved by the Generating Unit on the Transmission System at the Connection Point
(or on the Off-taker System at the Off-taker System Entry Point in the case of an
Embedded Generating Unit) namely on the higher voltage side of the Generating Unit
step-up transformer). Where a Generating Unit is instructed to a specified target voltage,
the Generator shall achieve that target within a tolerance of 1 kV by tap changing on the
Generating Unit step-up transformer unless otherwise agreed with the System Operator.
Under normal operating conditions, once this target Voltage level has been achieved, the
Generator shall not tap change again without prior consultation with and agreement of
the System Operator.
Under certain conditions such as low System Voltage, an instruction to maximum Reactive
Power output at instructed Active Power Output shall be given and the Generator shall
take appropriate action to maximise Reactive Power output unless constrained by Plant
operational limits or safety grounds relating to personnel or Plant.

Under certain conditions such as high System Voltage, a Dispatch Instruction to maximum
Reactive Power absorption at instructed Active Power Output shall be given and the
Generator shall take appropriate action to maximise Reactive Power absorption unless
constrained by Plant operational limits or safety grounds relating to personnel or Plant.
The issue of Dispatch Instructions for Active Power shall be made with due regard to any
resulting change in Reactive Power capability and shall include reduction in Active Power
Generation in order to increase Reactive Power capability (i.e. take account of the
Generating Unit Capability Chart).
The excitation system, unless otherwise agreed with the System Operator, shall be operated
only in its constant terminal voltage mode of operation with Reactive Power limiters in
service, with any constant Reactive Power output control mode or constant power factor
output control mode always disabled, unless agreed otherwise with the System Operator.
In the event of any change in System Voltage, a Generator shall not take any action to
override automatic Reactive Power response which is produced as a result of constant
terminal voltage mode of operation of the automatic excitation control system unless
instructed otherwise by the System Operator or unless immediate action is necessary to
comply with stability limits or unless constrained by Plant operational limits or safety
grounds (relating to personnel or Plant).
A Dispatch Instruction relating to Reactive Power shall be implemented without delay and
will be achieved not later than 2 minutes after the instruction time, or such longer period as
the System Operator may instruct.
Where Dispatch Instructions relating to Active Power and Reactive Power are given
together, and to achieve the Reactive Power output would cause the Generating Unit to
operate outside its Capability Chart as a result of the Active Power instruction being met at
the same time, then the timescale of implementation of the Reactive Power instruction
shall be extended to be no longer than the timescale for implementing the Active Power
instruction but in any case to achieve the Reactive Power Dispatch Instruction as soon as
possible.
For Power Stations with on-load tap change capability:
a) In circumstances where the System Operator issues new instructions in relation
to more than one Generating Unit at the same Power Station at the same time
tapping shall be carried out by the Generator one tap at a time either alternately
between (or in sequential order, if more than two), or at the same time on, each
Generating Unit, as the case may be.
b) Where the instructions require more than two taps per Generating Unit meaning
that the instructions cannot be achieved within 2 minutes of the instruction time,
(or such longer period at the System Operator may have instructed), the
instructions shall each be achieved with the minimum of delay after the expiry of
that period.
c) On receiving a new Active Power Dispatch Instruction, no tap changing shall be
carried out to change the Reactive Power output unless there is a new Reactive
Power Dispatch Instruction.

Where an instruction to Synchronise is given, or where a Generating Unit is
Synchronised and an Active Power Dispatch Instruction is given, a Reactive Power
Dispatch Instruction consistent with the Generating Unit's relevant parameters shall be
given. In the absence of a Reactive Power Dispatch Instruction with an instruction to
Synchronise, the Reactive Power output should be 0 MVAr.
Where an instruction to De-synchronise is given, a Reactive Power Dispatch Instruction,
compatible with shutdown, shall be given prior to De-synchronisation being achieved. In
the absence of a separate Reactive Power Dispatch Instruction, it is implicit in the
instruction to De-synchronise that Reactive Power output should at the point of
Synchronism be 0 MVAr at De-synchronisation.
It should be noted that should System conditions require, the System Operator may need
to instruct maximum Reactive Power output to be achieved as soon as possible, but in
any event no later than 2 minutes after the instruction is issued.
On receipt of a Dispatch Instruction relating to Reactive Power, the Generator shall take
such action as is necessary to maintain the integrity of the Generating Unit (including,
without limitation, requesting a revised Dispatch Instruction), and shall contact the
System Operator without delay.
Reactive Power Dispatch Instructions issued by the System Operator shall reflect the
limits contained in the Registered Information regarding Ancillary Service capabilities
and Quantity Nominations.
Under System fault conditions it is possible for AVR action to drive Reactive Power
output for a Generating Unit outside of its limits as contained in its Registered
Information. The Generator shall immediately inform the System Operator of the
situation. However if the Generator reasonably believes that the situation may be
dangerous to personnel or Plant, then limited action shall be taken to improve the
situation following which it must inform the SO.
21.5.5. System alerts
The System Operator shall notify Generators, by one of several means, of the existence
of a System Emergency Condition.
21.5.6. System Emergency Conditions
The System Operator may instruct Generators to operate outside the limits implied by
the then current Registered Information in order to maintain Transmission System
integrity under System Emergency Conditions.
Where the System Operator has issued an emergency instruction requiring operation of a
Generating Unit outside the limits applied by the then applicable Quantity Nomination
and Registered Information, then the Generator shall comply with the emergency
instruction if, in the reasonable opinion of the Generator, the safety of personnel,
and/or Plant is not compromised in complying with the request.
21.5.7. Failure To Comply With A Dispatch Instruction

The Generator shall inform the System Operator by telephone without delay if at any
time a Generating Unit is unable to comply with any Dispatch Instruction correctly
issued by the System Operator in respect of any Generating Unit.
21.5.8. Constrained Generation
Constrained generation is the service supplied by a Generator at one of its Power
Stations to the System Operator by constraining its power output below (alternatively
above) the unconstrained schedule level. The service is required to ensure that the
Transmission Network remains between appropriate operational limits (e.g. thermal,
voltage or stability limits).
If in providing the service, the Generator experiences a financial loss, for which it shall
be compensated by the Transmission Service Provider according to the Market Rules.
Constrained generation is required to meet network Reliability as there are no current
rules for market splitting across transmission constraints or the handling of units in
strategic positions.
The identification of the specific Transmission Network constraints applicable at any
point in time shall be the responsibility of the System Operator.

22. SECTION: OUTAGE CO-ORDINATION
22.1. OBJECTIVE
22.1.1. The objective of this Section is to define the obligations for formal notification of
Outages by Users and TSP to the System Operator.
22.2. GENERAL
22.2.1. Secure operation of an electricity system requires that the maintenance of the
Generating Units should be coordinated with the Outages of critical Transmission lines. This
is essential in order to enable the System Operator to fulfil its obligations relating to the
operation of the Transmission System, and to enable Users and TSP to plan their Outages in
an orderly way. The mechanisms by which this is achieved will be formalised in this Section.
22.3. OUTAGE SCHEDULING
22.3.1. The System Operator and Users and TSP shall establish schedules for inspection and
preventive maintenance of their Generation, Distribution, Transmission, protection, control,
communication and other Auxiliary Equipment. These maintenance and inspection
schedules shall be coordinated to ensure an Equipment Outage pattern that shall not violate
Power System Reliability and minimise customer disturbance.
22.3.2. Planning and co-ordination
The System Operator shall coordinate all Outage plans for the Users and TSP, on an annual
basis. These plans shall be ready by October of every year. The System Operator shall then be
responsible for performing pertinent Reliability studies to ensure the secure operation of the
Power System during the Outages as have been agreed in the annual Outage plans.
Scheduled Generation and Transmission Outages that may affect the Reliability of Power
System operations shall be planned and coordinated (notification of cancellation at least 24
hours in advance) amongst the affected parties. Special attention shall be given to the results
of pertinent studies. The Planned Outage shall be advised at least 2 weeks in advance and
confirmed in writing. The System Operator shall advise all Users and TSP of the return of
any of the Equipment.
22.3.3. Voltage regulating Equipment
System Operator shall coordinate all scheduled Outages of System Voltage regulating
Equipment, such as AVRs on Generating Units, supplementary excitation control,
synchronous condensers, shunt and series capacitors, reactors, etc. These Outages must be
coordinated with the Outages of Transmission circuits in the vicinity.
22.3.4. Metering and control Equipment
The System Operator shall coordinate scheduled Outages of metering and control
Equipment and associated communication channels.

22.3.5. Generator and TSP obligations
(a) Generators shall specify with regard to each of their Generating Units, the start
date, time and duration of each Outage. Statutory Outage plans for Generating
Units for the year after the current year must reach the System Operator by the
1st
of August of the current year pursuant to Section 22.3.1.
(i) The Generator shall ensure under its fuel supply and fuel transport
agreements or under any fuel supply or transport code that it is informed of
any outage planned in its fuel supply.
(ii) This information should be given sufficiently in advance to the SO such that
it can be taken into account in this outage planning process.
(b) TSP shall specify with regard to each of their items of Equipment the start date,
time and duration of each Outage for the year after the current year. This must
reach the System Operator by the 1st
of August of the current year pursuant to
Section 22.3.1.
(c) TSP and each Generator shall act in accordance with Good Utility Practice in
planning their Outages, so as to avoid a situation arising in which TSP or a
Generator is obliged to schedule an Outage at short notice.
(d) Generators (and TSP where relevant) shall specify the following, unless they
reasonably substantiate that an Outage is inflexible:
(i) An alternative preferred windows of opportunity within the year for any
Outage;
(ii) The minimum Outage duration which would be acceptable, if less than the
scheduled Outage duration;
(iii) Situations where the paralleling of Outages of two or more of its Generating
Units may be required, desirable, undesirable or not possible;
(iv) A priority order associated with the various Outages scheduled by the
Generator; and
(v) Any Outages where it is particularly desirable that they should take place
within the year scheduled.
(e) Any Outage where its timing is dependent on Generating Unit operating hours,
equivalent operating hours or starts.
22.3.6. Distribution Network Operator and Directly Connected Customer Obligations
Each Distribution Network Operator shall act in accordance with Good Utility Practice
in planning their circuit Outages. Each Distribution Company (and Directly Connected
Customers where relevant) shall furnish by 1st
of August of each year the following
information:
(a) Load in MW not to be available from any Connection Point.

(b) Identification of Equipment and /or Apparatus at the Connection Point where
there will be an Outage.
(c) Period during which a circuit at or near a Connection Point will be unavailable
with Start-date and Start-time and End-date and End-time.
22.3.7. Outage scheduling programme
The System Operator shall present the coordinated Outage plans as well as the results of the
Reliability studies in report format to the Commission for approval.
22.4. CHANGES TO THE COMMITTED OUTAGE SCHEDULING
PROGRAMME
22.4.1. System Operator change request
The System Operator can, providing the relevant reasons, request a Generator to change the
timing or duration of any Outage of one of the Generator's Generating Units in the Outage
scheduling programme.
22.4.2. The System Operator can, providing the relevant reasons, request TSP to change the
timing or duration of any Outage.
22.4.3. Generator or TSP response
A Generator may respond either by declining the request, or by agreeing to the request.
Generators shall make every reasonable effort to co-operate with reasonable changes
requested by the System Operator.
TSP may respond either by declining the request, or by agreeing to the request. TSP shall
make every reasonable effort to co-operate with reasonable changes requested by the System
Operator.
22.4.4. Agreement to conditions
If a Generator or TSP responds by agreeing to the request subject to specific conditions,
the System Operator may respond by either confirming agreement to those conditions or
by declining agreement. Where the System Operator agrees to the conditions, then the
Outage scheduling programme shall be amended accordingly. Where the System
Operator declines to agree to the conditions, then the System Operator may negotiate
with the Generator or TSP as to revised or alternative conditions, which would be
acceptable.
22.4.5. Generator or TSP change request
A Generator or TSP may at any time request the System Operator for a change in the
timing or duration of any Outage of one of the Generator's Generating Units or TSP
Equipment in the Outage scheduling programme. The System Operator may accept or
decline the request. The Outage scheduling programme shall be amended accordingly or
the System Operator shall negotiate with the Generator or TSP conditions, which shall
be acceptable to both parties.

22.4.6. Deviations from Outage scheduling programme
The System Operator shall compile an annual report to indicate how the Outage
scheduling programme of the previous year was adhered to. Specific reasons shall be
provided for each deviation to the original approved Outage scheduling programme.
The Commission shall review this report in order to ensure the improvement of the
System Operator’s performance over a number of years.
22.5. OTHER INFORMATION TO BE NOTIFIED
22.5.1. Ancillary Services
Generators shall inform the System Operator of any proposed maintenance, in addition
to Outages, which shall, or is likely to, affect the capability of the Generating Unit to
provide Ancillary Services.
22.5.2. Security of supply
The System Operator shall request alterations to maintenance, where security of supply
or the secure operation of the Transmission System would be at risk. The System
Operator shall make reasonable endeavours to give as much notice as possible for such
requests for alterations. Where the System Operator makes such a request, the Generator
or TSP shall use reasonable endeavours to comply with the request in arriving at the
Generator's or TSP’s final programme for such maintenance.

23. SECTION: RELIABILITY MEASURES
23.1. OBJECTIVE
23.1.1. The objective of this Section is to define the Reliability criteria and measures the
System Operator and the TSP have to adhere to in operating, maintaining and developing the
23.2. GENERAL
23.2.1. In order to maintain reliable operation of the Transmission System, it is necessary that
all SO, TSP and Users observe and subscribe to certain minimum planning criteria.
23.2.2. The criteria and principles provided in this document serve as a guideline to develop
criteria and methodologies applicable to the TSP, System Operator, Users and related
Interconnections.
23.2.3. Reliability measures
Traditionally the measurement of transmission Reliability is achieved through the
deterministic N-1 Criteria. This criterion should be regarded as a minimum standard.
Additional to this the System Operator should develop probabilistic criteria. The
fundamental attributes for Reliability measures to be considered to evaluate risk of probable
extreme events include:
(a) The frequency of events (e.g. frequency of circuit overload – 0.72 events/year);
(b) Duration of events (e.g. duration of circuit overload – 2.5 hours/year); and
(c) Severity of events (how does event impact on load curtailment)
From these attributes other indices to quantify network performance can be calculated. To
enable the definition of applicable indices, which may apply to the TSP and System Operator,
a number of concepts and definitions related to network, configuration and aspects
influencing network performance are discussed in Appendix 3.
23.3. APPLICABLE RELIABILITY CRITERIA
23.3.1. The System Operator shall study and assess the overall Reliability (adequacy and
security) of the Power System, both existing and as planned, to ensure that the Power System
development conforms to the Transmission Planning Criteria.
23.3.2. The System Operator shall develop Applicable Reliability Criteria for the
Transmission System for approval by the Commission.
23.4. RELIABILITY INDICATORS
23.4.1. The Applicable Reliability Criteria as stated in Appendix 3 shall itemise specific
measurable Reliability indicators. These can be expanded based on the System Operator, TSP

and Users’ needs. All of these indicators must be measurable and calculable for a defined
recording period. The length of the period should be measured in years to facilitate
comparison.
23.5. REPORTING
23.5.1. The System Operator shall prepare and publish an annual assessment report of the
Reliability of the Transmission System for review by the Commission.
23.5.2. To carry out these tasks, sufficient data and input must be made available to evaluate
and analyse the Applicable Reliability Criteria.

24. SECTION: SYSTEM TESTING ON THE NETWORK
24.1. OBJECTIVE
24.1.1. The objective of this Section is to establish the approach to central co-ordination and
control of a System Test required by the System Operator, the TSP or a User, where such test
shall or may:
(a) Affect the secure operation of the Transmission System;
(b) Have a significant effect on the operation of the Transmission System or a
User's System;
(c) Affect the economic operation of the Transmission System or a User's System;
or
(d) Affect the quality or continuity of electricity supply to Users.
24.2. GENERAL
24.2.1. This Section deals with the responsibilities and procedures for arranging and carrying
out System Tests that may have an effect on the systems of the TSP and/or Users.
24.2.2. By their nature, System Tests may have an impact on either or both of:
(a) The System Operator's responsibilities in respect of the Transmission System,
including Dispatch of Generation; and
(b) The operations of Users and the quality and continuity of supply of electricity to
Users.
24.2.3. To minimise disruption to the operation of the Transmission System and to the
Systems of other Users, it is necessary that tests that affect the operation of the Transmission
System or Users’ Systems be subject to central co-ordination and control.
24.2.4. These tests are not intended to deal with tests that may be called for routinely by TSP
or SO in order to assess compliance of Users with their defined design, operating and
connection characteristics.
24.3. TESTS REQUIRED BY TSP OR SYSTEM OPERATOR
24.3.1. System Operator’s responsibility
The System Operator as operator of the Transmission System shall carry out System Tests in
accordance with Good Utility Practice, in order to maintain and develop operational
procedures, to train staff, and to acquire information in respect of Power System behaviour
under abnormal system conditions. The System Operator shall endeavour to limit the
frequency of occurrence, scope, extent of effects and type of System Tests to those required
by Good Utility Practice.
24.3.2. Range of tests

System Tests required by the System Operator or the TSP from time to time shall include,
but shall not be limited to the following:
(a) Tests involving the controlled application of Frequency and/or Voltage variations
aimed at gathering information on Power System behaviour;
(b) Power System restoration tests (i.e. Black Start test at a Power Station);
(c) Testing of standing procedures for System Emergency Conditions; and
(d) Testing or monitoring of power quality under various Power System conditions and
Dispatch configurations.
24.3.3. Notice to Users
Where the System Operator or TSP intends to carry out a System Test, and such test will or
may have an operational effect on a User’s system, the System Operator shall provide notice
to the relevant User of the scheduled time and effect of the System Test as is reasonable in all
the circumstances and shall keep the relevant User informed as to any changes to the
scheduled time and nature of the System Test.
24.3.4. Request for additional time
A User, having been informed about a System Test may contact the System Operator to
request additional time to consider the impact of the test on the User. The System Operator
shall co-operate with the User to assess the risks. The test shall not proceed until all Users are
satisfied unless, in the System Operator’s view, a User is acting unreasonably.
24.4. TESTS REQUIRED BY USER(S)
24.4.1. Users’ responsibility
Operation of Users’ Plant in accordance with Good Utility Practice requires System Testing
in order to maintain and develop operational procedures, develop and measure Plant
performance, comply with statutory or other industry obligations and to train staff.
In accordance with Good Utility Practice each User shall endeavour to limit the Frequency of
occurrence of System Tests and to limit the effects of such System Tests on the Transmission
System.
24.4.2. Procedure for requesting System Tests
Users shall submit a request for a System Test in time. As part of the request, the Users,
when requesting a System Test, shall supply sufficient detail to the System Operator to allow
any operational consequences of the test to be adequately assessed. This shall include the
following information:
(a) The reason for the proposed test;
(b) The preferred time or times for the test;
(c) The milestones for individual stages of the System Test;

(d) Whether there may be an adverse material impact on the User if the System Test is
cancelled at short notice or delayed; and
(e) Where the User is a Generator, the Dispatch required by the Generator for
completion of the test.
Additionally, the factors that influence the completion of the stages should be outlined to the
System Operator, e.g., if the procedure to be followed for a certain stage depends on the
outcome of a previous stage.
24.4.3. Generator Specific request
A request by a Generator for a System Test requiring a Generating Unit to be Dispatched to
a particular Active Power output or operating condition shall not be considered a re-
declaration of Availability, Ancillary Service capability or operating characteristics.
24.5. EVALUATION OF PROPOSED SYSTEM TESTS
24.5.1. Impact assessment
The System Operator shall, on receipt of a System Test request from a User, assess the
impact of the proposed test on the operation of the Power System. The System Operator
may request additional information from the User in order to evaluate the impact of the test.
24.5.2. Objections and sensitivity
The System Operator shall evaluate the impact of the System Test with Users that might be
significantly affected. Any reasonable objections from any such Users shall be considered.
When discussing the System Test with any affected User, the System Operator shall not
disclose what it reasonably believes to be commercially sensitive or otherwise potentially
sensitive information to Users without the consent of the User requesting the test.
24.5.3. Generator Dispatch outside currently registered values
Where a System Test requested by a Generator in respect of one of its Generating Units
requires a Dispatch that is outside the currently registered values of Availability, Ancillary
Service capability or operating characteristics of the Generating Unit, then the System
Operator may so Dispatch the Generating Unit for the period required for the System Test.
24.6. APPROVAL FOR SYSTEM TESTS
24.6.1. Approval criteria
The criteria for approving System Tests shall include:
(a) The impact of the System Test on Transmission System operational security;
(b) The impact of the System Test on Transmission System operational economics;
(c) The impact of the System Test on other Users’ systems; and
(d) The effect of the System Test on continuity and quality of electricity supply.
24.6.2. Proposed Dispatch procedure and schedule

On approval by the System Operator of a System Test requested by a User, who is a
Generator, the System Operator shall contact the Generator outlining the proposed Dispatch
procedure and schedule.
On receipt of the proposed Dispatch procedure and schedule of the System Test, the test
requestor shall notify the System Operator without undue delay, of the test requestor's
acceptance or rejection of the proposed Dispatch procedure and schedule for the System
Test.
24.6.3. Rejection of Dispatch procedure and schedule
On notification of rejection of the proposed Dispatch procedure and schedule for the System
Test by the test requestor, the System Test shall not take place. The test requestor may enter
into discussions with the System Operator as to an alternative schedule for the System Test,
or may request a different System Test, or may request the System Test at an alternative time.
24.6.4. Acceptance of Dispatch procedure and schedule
On notification of acceptance of the proposed Dispatch procedure and schedule for the
System Test by the test requestor, the System Operator shall inform other Users as to the
scheduled time and nature of the test, if in the opinion of the System Operator those Users
shall or may be significantly affected by the test, or otherwise as dictated by standing
arrangements.
24.6.5. Concerns by affected Users
If Users that might be significantly affected are not satisfied with the proposed System Test,
they shall promptly advise the System Operator of their concerns. If the System Operator
considers these objections to be unreasonable the proposed System Test shall not be
cancelled. If operationally affected Users are still not satisfied with the System Test being
approved they may appeal the decision to the Commission. In this latter case the affected
Users must promptly inform the System Operator that they intend to appeal and the System
Test shall not be allowed to take place until the Commission has decided in favour of it.
24.7. SCHEDULING OF SYSTEM TESTS
24.7.1. Where the System Operator requires a System Test, either:
(a) The Generator/User shall nominate half-hourly Active Power outputs and
constraints and the System Operator shall then Dispatch consistent with the planned
System Test, or
(b) Where System Test costs and conditions have been agreed in advance between the
Generator/User and the System Operator, the Generator shall nominate in
accordance with the System Operator requirements for the System Test.
24.7.2. Test prioritisation
The System Operator shall use reasonable endeavours to promptly schedule System Tests
where the test requestor has notified the System Operator that System Tests are required in
accordance with licence conditions, statutory regulations or safety Codes or that a delay in the
execution of the tests may have an adverse material impact on the User.

24.8. DISPATCHING OF SYSTEM TESTS
24.8.1. Dispatch Instructions
The System Operator shall issue Dispatch Instructions for System Tests in the manner
for issuing normal Dispatch Instructions.
The System Operator shall use reasonable endeavours to ensure that scheduled System
Tests are Dispatched in accordance with the agreed Dispatch procedures.
24.8.2. Revised test procedure
Where the System Operator assesses that the impact of a System Test on Transmission
System security or on the continuity and Quality of Supply or operation of a User may or
is likely to be significantly greater than originally estimated, the System Operator may
contact the test requestor to discuss a revised test procedure or schedule.
24.8.3. Possibility of cancellation or postponement
Where the System Operator foresees a requirement or likely requirement to cancel,
postpone or otherwise significantly alter an agreed Dispatch procedure and schedule,
then the System Operator shall inform the test requestor as soon as reasonably possible.
24.8.4. Cancellation, interruption or postponement of test
The System Operator may where it considers it necessary, cancel, interrupt or postpone a
System Test at any time, but shall, where possible, utilise the agreed procedures prior to
taking such action where the cancellation, interruption or postponement is for other than
technical reasons.
24.8.5. Cancellation by test requestor
If the test requestor wishes to cancel a System Test either before commencement of the
test or during the test, the test requestor shall notify the System Operator. Nominations
and Dispatch Instructions shall remain valid when System Tests are cancelled.
24.9. TEST REPORTING
24.9.1. Scheduled completion time
Upon conclusion of the scheduled time for a System Test, the test requestor shall notify
the System Operator as to whether the test, or sections of the test, if divided into
sections, has been completed.
24.9.2. Reporting
At the conclusion of the System Test, the test requestor shall be responsible for
preparing a written report on the System Test which shall be available to the System
Operator, operationally effected Users and the Commission on request within 30 days of
the conclusion of the System Test.

The Report shall include a description of the Plant and/or Apparatus tested and a
description of the system test carried out together with the results, conclusions and
recommendations as they relate to the System Operator and operationally affected Users.
24.9.3. Report confidentiality
The Report shall not be submitted to any person who is not a representative of the
System Operator or the test requestor unless the System Operator and the test requestor,
having reasonably considered the confidentiality issues arising shall have unanimously
approved such submission.
24.10.DISPUTES
Disputes shall be handled according to relevant industry rules and regulations as
approved by NERC.

25. SECTION: SAFETY AND CO-ORDINATION
25.1. OBJECTIVE
25.1.1. The objective of this Section is to achieve Safety on the network when either:
(a) work on TSP Equipment necessitates the provision of Safety Precautions on
User Equipment; or
(b) work on User Equipment necessitates the provision of Safety Precautions on
TSP Equipment.
25.1.2. A flow chart in Appendix 4C illustrates the process utilised in this Section to achieve
Safety on the network. In the case of a conflict between the flow chart and the provisions of
this Section, this Section will prevail.
25.2. GENERAL
25.2.1. This Section specifies the standard operating procedures to be used by System
Operator, TSP and Users of the network for the co-ordination, establishment and
maintenance of necessary Safety Precautions when work is to be carried out on the
Transmission Network or on a User’s Apparatus and when there is a need for Safety
Precautions on the high voltage Equipment on the other’s system for work to be carried out
safely. The term “work” includes testing, other than Network Tests. This Section applies
between System Operator, TSP and Users and does not impose a particular set of Safety
Rules on SO, TSP and Users; the Safety Rules to be adopted and used by SO, TSP and Users
shall be those chosen by them. This Safety procedure applies to:
(a) TSP
(b) System Operator
(c) Generators
(d) Distribution Network Operators
(e) Directly Connected Customers
25.3. INTERPRETATION
25.3.1. In this Section 25, the following terms shall have the meaning:
(a) “High Voltage Equipment” means high voltage electrical circuits forming part
of a System, on which Safety from the System may be required or on which
Safety Precautions may be applied to allow work to be carried out on a circuit.
(b) “Isolation” means the disconnection of Equipment from the remainder of the
network in which the Equipment is situated by either of the following:
(i) an Isolating Device maintained in an isolating position. The isolating position
must either be:

b.i.1) maintained by immobilising the Locking and Isolating Device in the
isolating position and affixing a Caution Notice to it. Where the
Isolating Device is Locked with a Safety Key, the Safety Key must be
secured in a Key Safe. The Key Safe must be retained in a safe custody;
or
b.i.2) maintained and/or secured by such other method which must be in
accordance with the Local Safety Instructions of SO or that of the User,
as the case may be; or
(ii) an adequate physical separation which must be in accordance with, and
maintained by, the method set out in the Local Safety Instructions of SO or
that of the User as the case may be, and, if it is a part of that method, a
Caution Notice must be placed at the point of separation.
(c) “Earthing” means a way of providing a low impedance connection between
conductors and the earth by an Earthing Device which is either:
(i) immobilised and Locked in an earthing position. Where the Earthing Device
is Locked with a Safety Key, the Safety Key must be secured in a Key Safe.
The Key Safe must be retained in a safe custody; or
(ii) maintained and/or secured by such other method which must be in
accordance with the Local Safety Instructions of the SO or that of the User,
as the case may be.
25.4. PROCEDURE
25.4.1. Approval of Local Safety Instructions
(a) In accordance with the timing requirements of its Grid Connection Agreement
with the TSP, each User will supply to the SO a copy of its Local Safety
Instructions relating to its side of the Connection Point at each Connection Site.
(b) In accordance with the timing requirements of each User Agreement, the SO
will supply to each User a copy of its Local Safety Instructions relating to the
TSP side of the Connection Point at each Connection Site.
(c) Prior to connection each party must have approved the other’s relevant Local
Safety Instructions in relation to Isolation and Earthing.
(d) Either party may require that the Isolation and/or Earthing provisions in the
other party’s Local Safety Instructions affecting the Connection Site should be
made more stringent in order that approval of the other party’s Local Safety
Instructions can be given. Provided that these requirements are not
unreasonable, the other party will make such changes as soon as reasonably
practicable.
If approved, a party that wishes to change the provisions in its Local Safety Instructions
relating to Isolation and/or Earthing after approval, must inform the other party. If the
change is to make the provisions more stringent, then the other party merely has to note the

changes. If the change is to relax the provisions, then the other party need to assess and
approve the new provisions and procedures referred to in 25.4.1(c).
25.4.2. Safety Coordinators
For each Connection Point, the SO and each User must at all times have person(s) “Safety
Coordinator(s)” to be responsible for the coordination of Safety Precautions when work is to
be carried out on the network or parts of it which necessitates the provision of Safety
Precautions on High Voltage Equipment pursuant to this Section of the Grid Code. A Safety
Coordinator may be responsible for the coordination of safety at more than one Connection
Point on the network.
Each Safety Coordinator shall be authorised by the SO or a User, as the case may be, as
competent to carry out the functions set out to achieve Safety from the Network at all times.
Only Authorised Persons of the SO and the User(s) will carry out Safety activities at all times.
Contact between Safety Coordinators at SO and User(s) will be made via normal operational
channels, and accordingly separate telephone numbers for Safety Coordinators need to be
registered and available at SO and Users at all times.
If work is to be carried out on the network which necessitates the provision of Safety
Precautions, in accordance with the provisions of this Section, the Requesting Safety
Coordinator who requires Safety Precautions to be provided shall contact the relevant
Implementing Safety Coordinator to coordinate the establishment of Safety Precautions
throughout the work.
25.5. RECORD OF NETWORK SAFETY PRECAUTIONS (RNSP)
25.5.1. The SO and Users will use the format of the RNSP forms set out in Appendix 4A,
and 4B of this Code. The one set out in Appendix 4A and designated as “RNSP-R” shall be
used by the SO when the SO is Requesting Safety Coordinator, and the one in Appendix 4B
designated as “RNSP-I” used by the SO when the SO is Implementing Safety Coordinator.
The same shall apply to the User mutatis mutandis. Proformas of RNSP-R and RNSP-I must
be provided by the SO and Users for use at all times when Safety Precaution is required.
25.5.2. All references to RNSP-R and RNSP-I shall be taken as referring to the
corresponding parts of the alternative forms or other tangible written records agreed between
the SO and the User.
25.5.3. RNSP-R will have an identifying number written or printed on it, comprising a prefix
which identifies the location at which it is issued, and a unique serial number consisting of
four digits and suffix “R” for the SO and the User.
25.5.4. Each User shall apply to the SO for approval of its proposed prefix
25.5.5. The SO shall consider the proposed prefix to see if it is the same as a prefix used by
the SO or another User and that it is not confusing. The SO shall respond in writing within
ten days of its decision on the prefix to the User.

25.5.6. If the SO disapproves, it shall explain in its response why it has disapproved and will
suggest an alternative prefix. In this situation, the User shall either notify the SO in writing of
its acceptance of the suggested alternative prefix or it shall apply in writing to the SO with its
revised prefix proposal and the above procedure shall apply.
25.6. SAFETY PRECAUTIONS ON HIGH VOLTAGE EQUIPMENT
25.6.1. Safety Precautions
For the purpose of coordination of safety relating to High Voltage Equipment, the term
“Safety Precautions” means Isolation and /or Earthing.
25.6.2. Agreement of Safety Precautions
The Safety Coordinator requesting Safety Precautions on Equipment or parts of the
Transmission Network will contact the relevant Implementing Safety Coordinator to
agree the location of the Safety Precautions to be established. This agreement will be
recorded in the respective Safety Logs.
It is the responsibility of the implementing Safety Coordinator to ensure that adequate
Safety Precautions are established and maintained. This can be in terms of his own
Equipment and/or Equipment of another party connected to his Equipment, to enable
Safety from the Equipment to be achieved on the High Voltage Equipment, specified by
the Requesting Safety Coordinator which is to be identified in RNSP.
When the Implementing Safety Coordinator is of the reasonable opinion that it is
necessary for Safety Precautions on the System of the Requesting Safety Coordinator,
other than on the High Voltage Equipment specified by the Requesting Safety
Coordinator, which is to be identified in RNSP, he shall contact the Requesting Safety
Coordinator and the details shall be recorded in the RNSP forms. It is the responsibility
of the Requesting Safety Coordinator to establish and maintain such Safety Precautions.
In the event where the Requesting Safety Coordinator and the Implementing Safety
Coordinator are unable to agree the location of the Isolation and (if requested) Earthing,
both shall be at the closest available points on the infeeds to the High Voltage
Equipment on which Safety from the network is to be achieved as indicated on the
operating diagram.
25.6.3. Implementation of Isolation
Following the agreement of the Safety Precautions in accordance with 25.6.2 the
Implementing Safety Coordinator shall then establish the agreed Isolation.
The Implementing Safety Coordinator shall confirm to the requesting Safety Coordinator
that the agreed Isolation has been established, and identify the Requesting Safety
Coordinator’s High Voltage Equipment up to the Connection Point, for which the
Isolation has been provided. The confirmation shall specify:
(a) For each location, the identity (by means of High Voltage Equipment name,
nomenclature and numbering or position as applicable) of each point of

Isolation, whether Isolation has been achieved by an isolating Device in the
isolating position or by an adequate physical separation;
(b) Where an Isolating Device has been used whether the isolating position is
either:
(i) Maintained by immobilising and Locking the Isolating Device in the isolating
position and affixing a Caution Notice to it. Where the Isolating Device has
been Locked with a Safety Key that the Safety Key has been secured in a Key
Safe and the Key Safe will be retained in a safe custody;
(c) Where an adequate physical separation has been used that will be in accordance
with, and maintained by the method set out in the Local Safety Instructions of
SO or that of the User, as the case may be, and, if it is part of that method, that
a Caution Notice be placed at the point of separation.
(d) The confirmation of Isolation shall be recorded in the respective Safety Logs.
25.6.4. Implementation of Earthing
The Requesting Safety Coordinator will confirm to the Implementing Safety Coordinator
that the relevant Isolation of its Equipment in the Safety Precautions agreed in 25.6.2 has
been performed, in order that the Implementing Safety Coordinator may proceed to the
Earthing phase.
The Implementing Safety Coordinator shall confirm to the Requesting Safety
Coordinator that the agreed Earthing has been established, and identify the Requesting
Safety Coordinator’s High Voltage Equipment for which Earthing has been provided.
The confirmation shall specify:
(a) For each location, the identity (by means of the High Voltage Equipment name,
nomenclature and numbering or position, as is applicable) of each point of
Earthing; and
(b) In respect of the Earthing Device used, whether it is:
(i) Immobilised and Locked in the Earthing position. Where the Earthing
Device has been Locked with a Safety Key, that the Safety Key has been
secured in a Key Safe and the Key Safe will be retained in safe custody; or
(ii) Maintained and/or secured in position by such other method which is in
accordance with the Local Safety Instruction of the SO or that User, as the
case may be.
The confirmation of Earthing shall be recorded in the respective Safety Logs.
The Implementing Safety Coordinator shall ensure that the established Safety
Precautions are maintained until requested to be removed by the relevant Requesting
Safety Coordinator.
25.6.5. Procedure for Issuing RNSP
Where Safety Precautions on Equipment are being provided to enable work on the
Requesting Safety Coordinator’s Equipment, before any work commences they must be

recorded by the RNSP being issued. The RNSP is applicable to High Voltage Equipment
up to the Connection Point identified in the RNSP-R and RNSP-I forms.
Where Safety Precautions are being provided to enable work to be carried out on both
sides of the Connection Point an RNSP will need to be issued for each side of the
Connection Point with the SO and the respective User each enacting the role of
Requesting Safety Coordinator. This will result in an RNSP-R and RNSP-I form being
completed by each of the SO and the User, with each Safety Coordinator issuing on
RNSP number.
Once the Safety Precautions have been established, the Implementing Safety
Coordinator shall complete form RNSP-I recording the details specified in 25.6.2, 25.6.3
and 25.6.4.
The Requesting Safety Coordinator shall complete form RNSP-R, making a precise copy
of the details received. On completion, the Requesting Safety Coordinator shall read the
entries made back to the sender and check that an accurate copy has been made.
The Requesting Safety Coordinator shall then issue the number of the RNSP taken from
the RNSP-R, to the Implementing Safety Coordinator who will ensure that the number,
including the prefix and suffix, is accurately recorded in the designated space on the
RNSP-I form.
The Requesting Safety Coordinator and the Implementing Safety Coordinator shall
complete and sign appropriate parts of the RNSP-R and RNSP-I forms respectively and
then enter the time and date. When signed no alteration to the RNSP is permitted; the
RNSP may only be cancelled.
The Requesting Safety Coordinator is then free to authorise work (including a test that
does not affect the Implementing Safety Coordinator’s Equipment. Where testing is to
be carried out which affects the Implementing Safety Coordinator’s Equipment, the
procedure set out in 25.6.7 shall be implemented.
25.6.6. RNSP Cancellation Procedure
When the Requesting Safety Coordinator decides that Safety Precautions are no longer
required, he will contact the relevant Implementing Safety Coordinator to effect
cancellation of the associated RNSP.
The Requesting Safety Coordinator will inform the relevant Implementing Safety
Coordinator of the RNSP identifying number (including the prefix and suffix), and agree
it is the RNSP to be cancelled.
The Requesting Safety Coordinator and the relevant Implementing Safety Coordinator
shall then respectively complete RNSP-R and RNSP-I forms with their names and
contact address and shall then exchange details. On exchange of details the respective
RNSP is cancelled.
Neither Safety Coordinator shall instruct the removal of any Isolation forming part of
the Safety Precautions as part of the returning of the High Voltage Equipment to service
until it is committed to each by each other that every earth on each side of the

Connection Point, within the points of isolation identified on the RNSP has been
removed or disconnected by the provision of additional Points of Isolation.
Subject to provisions in this Subsection the Implementing Safety Coordinator is then
free to arrange the removal of the Safety Precautions, the procedure to achieve that being
entirely an internal matter for the party the Implementing Safety Coordinator is
representing. Nothing in this Code prevents the SO and Users agreeing to a
simultaneous cancellation and issue a new RNSP, if both agree.
25.6.7. Testing Affecting Another Safety Coordinator’s Equipment
The carrying out of a test may affect Safety Precautions on RNSPs or work being carried
out which does not require an RNSP. Testing can, for example include the application of
an independent test voltage. Accordingly, where the Requesting Safety Coordinator
wishes to authorise the carrying out of such a test to which the procedures in this Section
of the Grid Code apply he may not do so and the test will not take place unless the steps
in (a) to (c) below have been followed and confirmation of completion has been
recorded in the respective Safety Logs:
(a) Confirmation must be obtained from the Implementing Safety Coordinator
that:
(i) no person is working on, or testing, or has been authorised to work on, or
test, any part of its Equipment or another Equipment (other than the
Equipment of the Requesting Safety Coordinator) within the points of
Isolation identified on the RNSP form relating to the test which is proposed
to be undertaken, and
(ii) no person will be so authorised until the proposed test has been completed
(or cancelled) and the Requesting Safety Coordinator has notified the
Implementing Safety Coordinator of its completion (or cancellation);
(b) Any other current RNSP which relates to the parts of the Equipment in which
the testing is to take place must have been cancelled in accordance with
procedures set out in 25.6.6
(c) The Implementing Safety Coordinator must agree with the Requesting Safety
Coordinator to permit the testing on that part of the Equipment between the
points of Isolation identified in the RNSP associated with the test and the
points of Isolation on the Requesting Safety Coordinator's Equipment.
(d) The Requesting Safety Coordinator will inform the Implementing Safety
Coordinator as soon as the test has been completed or cancelled and the
confirmation shall be recorded in the respective Safety Logs.
(e) When the test gives rise to the removal of Earthing which it is not intended to
re-apply, the relevant RNSP associated with the test shall be cancelled at the
completion or cancellation of the test in accordance with the procedure set out
in either 25.6.5 or 25.6.6. Where the Earthing is re-applied following the
completion or cancellation of the test, there is no requirement to cancel the
relevant RNSP associated with the test pursuant to this Subsection.

25.6.8. Emergency Situations
There may be circumstances where Safety Precautions need to be established in relation
to an unintended electrical connection or situations where there is an unintended risk of
electrical connection between the Transmission Network and a User’s Equipment, for
example resulting from an incident where one line becomes attached or unacceptably
close to another.
In those circumstances, if both the SO and the respective User agree, the relevant
provisions of 25.6.5 will apply as if the electrical connections or potential connections
were, solely for the purposes of this Section, a Connection Point.
The relevant Safety Coordinator shall be that for the electrically closest existing
Connection Point to that User's Equipment or such other local Connection Point as may
be agreed between the SO and the User, with discussions taking place between the
relevant local Safety Coordinators. The Connection Point to be used shall be known in
this Subsection as the "Relevant Connection Point".
(a) The Local Safety Instructions shall be those which apply to the Relevant
Connection Point.
(b) The prefix for the RINSP will be that which applies for the Relevant
Connection Point.
25.6.9. Loss of Integrity of Safety Precautions
In any instance when any Safety Precautions may be ineffective for any reason the
relevant Safety Coordinator shall inform the other Safety Coordinator(s) without delay of
that being the case and of the reasons why.
25.6.10.Safety Log
The SO and Users shall maintain Safety Logs which shall be a chronological record of all
messages relating to Safety Coordination under this Code sent and received by the Safety
Coordinator(s). The Safety Logs must be retained for a period of not less than one year.
26. SIGNIFICANT INCIDENT AND ACCIDENT REPORTING
26.1.1. Significant Incident
Every case where either, or a combination of the following happens:
 malfunctioning of Equipment, Apparatus connected to the Transmission Network;
 a person receives an electric shock, whether mild or serious or suffers an injury or
burn, directly or indirectly due to electrical causes;
shall be treated as a Significant Incident. The System Operator personnel in charge of the
concerned Equipment, Apparatus or area shall report the incident immediately to the
highest responsible officer of the System Operator in charge within 12 hours. A
designated officer from the System Operator should reach the spot within 24 hours and
assess the situation and probable cause of the accident, losses to consumers, and damage
to Equipment, Apparatus of the TSP and or the User(s).

26.1.2. Whenever an accident occurs resulting in or likely to have resulted in loss of life or
injury to human beings the above report should be followed by a detailed report within 48
hours. The System Operator shall take all other statutorily required actions, such as reporting
to the police etc.
26.1.3. The System Operator shall send a preliminary report to the Nigerian Electricity
Regulatory Commission of all Significant Incidents in the Power System which results in
interruption to service, substantial damage to Equipment, loss of life, injury to human beings
within 36 hours of its occurrence followed by a detailed report within two weeks.
26.1.4. For every Significant Incident relating to 26.1.2, NERC shall order an enquiry of the
event. It should be completed with the least possible delay, in any case, not exceeding twenty
days to guard against the possibility of destruction or disappearance of material evidence
being presented, to escape responsibility. It should be a searching probe that may or not
involve members of the security forces to uncover the root causes of the accident, which
sometimes are quite difficult to ascertain. The enquiry should not only fix responsibility for
the accident, but it is more important, to spell out steps to be taken to prevent such accidents
in future.
26.1.5. The System Operator and the affected person or their agent shall establish a format
and procedure for exchange of information for any Significant Incident event.
26.1.6. Users or their agent shall furnish information to the System Operator regarding any
major incident occurring on their Systems promptly.

1. APPENDIX 1: DEFINITIONS
ELECTRICAL TERMS USED IN THE APPENDICES TAKE THEIR
STANDARD INTERNATIONAL MEANINGS.
1.1. Table A 1
“Abnormal Operation” has the meaning assigned in Subsection 20.2.1;
“AC” means alternating current;
“ACC” means area Control Centre;
“Act” means the Electric Power Sector Reform Act, 2005,
as amended;
“Active Power” means the product of voltage and the in-phase
component of alternating current measured in units
of Watts and standard multiples thereof:
1000 Watts = 1 kW
1000 kW = 1 MW
1000 MW = 1 GW
1000 GW = 1 TW;
“Active Power Output” means the sent out Active Power from a
Generating Unit or Power Station as appropriate;
“Agreements” has the meaning assigned to that term in the Market
Rules;
“Ancillary Service” means a service, other than the primary production
of electricity, which is used to operate a stable and
secure Power System including but not limited to:
Reactive Power, Operating Reserve, Frequency
Control and Black Start Capability;
“Apparatus” means all TSP Equipment, or User Equipment, as
the case may be, in which electrical conductors are
used, supported or which they form a part;
“Applicable Reliability
Criteria”
means the Reliability criteria that will ensure that
the Power System development conforms to
minimum planning criteria;
“ARC” means automatic recloser;

“Area Control Error
(ACE)”
means the instantaneous difference between actual
and scheduled interchange, taking into account the
effects of Frequency bias (and time error or
unilateral inadvertent error if automatic correction
for either is part of the system's AGC);
“Authorised Person” means a person authorised in writing by the SO or a
User to carry out safety activities;
“Automatic Generation
Control (AGC)”
means the process whereby electronic Equipment
automatically adjusts a Control Area’s Generation
from a central location to maintain its Interchange
Transaction Schedule plus Frequency bias;
Automatic Load Shedding means Under-Frequency Load Shedding or Under-
Voltage Load Shedding;
“Automatic Voltage
Regulator (AVR)”
means a continuously acting automatic closed loop
control system acting on the excitation system so as
to maintain a Generating Unit's terminal voltage at
a desired set point;
“Auxiliary” means any item of Plant and/or Apparatus not
directly a part of the boiler Plant or Generating
Unit, but required for the boiler Plant's or
Generating Unit's functional operation;
“Availability” means a measure of the time a Generating Unit,
transmission line or other Facility as the case may
be is capable of delivering Energy to the
Transmission System at the delivery point or of
providing Ancillary Services to the Transmission
System and the term “Available” shall be construed
accordingly;
“Back-up Control Centre” means the alternative national Control Centre used
in emergencies when the NCC is out of action;
“Black Start” means the procedure necessary for a recovery from
a Total Shutdown or Partial Shutdown;
“Black Start Capability” means the capability of a Power Station to
commence operation without an outside Energy
supply so as to energise a defined position of a
TCN controlled grid;
“Black Start Station” means a Power Station, which has Black Start
Capability;

“Bulk Power Energy
Curtailment Index”
means the sum of load (MW) lost multiplied by the
frequency of such an event, divided by the actual
amount of load (MW) in the Power System. Given
in equivalent number of Shutdowns per year;
“Business Day” Has the meaning given in Subsection 2.8.1;
“Calculation Day” has the meaning given in the Market Rules;
“Capability Chart” means a chart, which shows the MW and MVAr
capability limits at Generating Unit terminals within
which a Generating Unit will be expected to operate
under steady state conditions;
“Caution Notice” A notice conveying a warning against interference;
“CCGT” Combine Cycle Gas Turbine. A generating unit
comprising one or more gas turbine units (or other
gas based units) and one or more team units where
in normal operation, the waste heat from the gas
turbine is passed to the water/steam system of the
associated steam unit(s) directly connected to the
hot gas line which enable those units to contribute
to improve efficiency of the combined cycle
operation of the module;
“Code” means this Code, (including the Appendices)
as amended from time to time, and approved
by the Commission, in accordance with the
Market Rules;
“Commission” or
“Regulator” or “NERC”
has the meaning assigned to that term in the Act or
in the case of the definition NERC in Section 2.3.1;
“Conditions Precedent” has the meaning assigned to that term in the Market
Rules;
“Connection Point” means the physical point where the User’s Plant is
joined to the Transmission System;
“Connection Site” means for each User’s Connection Point the
associated substation;
“Control Action” means any action required by the System Operator
in controlling the Power System securely;
“Control Area” means a Power System with Interconnections that
is capable of maintaining continuous balance
between the generation under its control, the

consumption of electricity in the Control Area and
the scheduled interchange with other Control
Areas. The Nigerian Power System forms one
Control Area;
“Control Centre” means the centre responsible for monitoring and
operation of the applicable network;
“CT” means current transformer;
“Customer Damage
Function (CDF)”
means the variation of a customer’s perception with
regard to the worth of service Reliability as a
function of interruption duration;
“Day-ahead Demand
Forecast”
means the Demand Forecast for the following
24hrs starting at 00:00hrs;
“Day-ahead Nomination” has the meaning assigned to that term in the Market
Rules;
“Day-ahead Price” has the meaning assigned to that term in the Market
Rules;
“DC” means direct current;
“De-energisation” or “De-
energise(d)”
means the operation of any isolating device, breaker
or switch or the removal of any fuse whereby no
Electricity can flow to or from the relevant System
through the User's Equipment;
“Demand” means the rate at which electric Energy is delivered
by the System or part of the System comprising of
both Active and Reactive Power, unless otherwise
stated;
“Demand Control” means all or any of the methods of achieving a
Demand reduction or an increase in Demand;
“Demand Forecast” means an estimate of future Demand typically
worked out by using mathematical forecasting
techniques and historical Demand data, weather
forecasts and other pertinent information;
“De-synchronise” means the process of taking a Generating Unit off a
Power System to which it has been Synchronised,
by opening any circuit breaker, and like terms shall
be construed accordingly;
“Directly Connected means a customer that is directly connected to the

Customer” transmission system;
“Disconnection” is the permanent physical disconnection of the
User's Equipment or Apparatus at any given
Connection Site which permits removal thereof
from the Connection Site or removal of all the
TSP’s Assets there from (as the case may be);
“Dispatch” means the process by which the System Operator
directs the operation of the Facility to cause a
specified amount of Energy or Ancillary Services to
be provided to or taken off the Power System.
Inclusive of curtailment of Demand and
Interchange Transaction Schedules in real time, to
relieve congestion, to maintain the Reliability of the
Power System and to comply with Applicable
Reliability Criteria, as more particularly described in
the Grid Code;
“Dispatch Day” has the meaning assigned to that term in the Market
Rules;
“Dispatch Instruction” means the physical operating instruction issued by
the System Operator to a User for its Dispatch in
accordance with the Grid Code;
“Dispatch Period” means any hour interval during a Dispatch Day, the
first of which shall commence at 00:00 hours of the
Dispatch Day and the last of which shall end at
24:00 hours of that Dispatch Day;
“Dispatch Schedule” means the schedule developed by the System
Operator in accordance with the Grid Code for a
Dispatch Period not later than two hours prior to
the commencement of the relevant Dispatch
Period;
“Distribution” means conveying Energy at voltages of less than
132kV;
“Distribution Network” or
“Distribution System”
means all electric lines used for Distribution of
Energy to final consumers and includes any
structures and Equipment used for that purpose
which is connected to the Transmission System;
“Distribution Network
Operator” or
“Distribution System
Operator”
means the Distributor who owns, operates and
maintains a Distribution Network;

“Distributor” means a User who is licensed to distribute electricity
under Part IV section 67 of the Act;
“Eligible Customer” has the meaning assigned to that term in the Act;
“Earthing” has the meaning given in Section 25;
“Earthing Device” means a device providing a low impedance
connection between conductors and the earth;
“Embedded Generating
Unit”
means a Generating Unit connected to a
Distribution System or to a Directly Connected
Customer System;
“Emergency Generation” means the short-term generation of the Plant above
its rated capacity;
“Energy” has the meaning assigned to that term in the Market
Rules;
“Equipment” Any machinery, Apparatus (stand alone or
connected) that forms part of a System or sub
System involve in production, transportation and
consumption of electricity;
“ESI” means Electricity Supply Industry;
“Event” Has the meaning assigned in Subsection 20.2.1;
“Expected Unserved
Energy”
means the sum of Energy lost due to system
unreliability and is measured in MWh per annum;
“Expert” has the meaning given in Subsection 3.3.3;
“Facility” has the meaning assigned to that term in the Market
Rules;
“Fault Level” means prospective current that would flow into a
short circuit at a stated point on the System and
which may be expressed in kA or, if referred to a
particular voltage, in MVA;
“Flicker” means impression of unsteadiness of visual
sensation induced by a light stimulus whose
luminance or spectral Distribution fluctuates with
time;
“Force Majeure” has the meaning assigned to that term in the Market
Rules;

“Forced Outage” means an unanticipated or automatic removal from
service of, the temporary de-rating of, restriction of
use of, or reduction in performance of Equipment;
“Frequency” means the number of alternating current cycles per
second (expressed in Hertz) at which a System is
running;
“Frequency Control” means the retention of the Frequency on the Power
System within acceptable limits;
“Gas Turbine Unit” means a Generating Unit driven by a gas turbine
(e.g. an aero-engine);
“Generate and
Generation”
has the meaning assigned to that term in the
Market Rules;
“Generating Unit” Any Apparatus or Equipment which produces
electricity, including, for the avoidance of
doubt, a CCGT unit;
“Generator” A person or corporate entity who produces
electricity under licence or exemption under the
Electric Power Sector Reform Act, 2005 or its
successor Act;
“Good Utility Practice” means any of the international practices, methods
and acts engaged in or approved by a significant
portion of the electric utility industry during the
relevant time period and under similar conditions as
exist in Nigeria, or any of the practices, methods
and acts in which, in the exercise of reasonable
judgement in light of the faith known at the time
the decision was made, could have been expected to
accomplish the desired result at a reasonable cost
consistent with good business practice, Reliability,
safety and expedition; however for the sake of
clarity, it is not intended that the item Good Utility
Practice be limited to optimum practice, method or
act to the exclusion of all others, but rather than
intention is to refer to acceptable practices,
methods or acts internationally;
“Governor Control
System”
means a self-correcting system that will adjust
Active Power output of a Generating Unit , in
response to a change in System Frequency, such
that the Generating Unit assists in the recovery to
Target Frequency;

“Governor Droop” means the percentage steady state drop in the
Frequency that would cause the Generating Unit
under free governor action to change its output
from zero to stated capacity;
“Grid Code” means this Code as defined in the Act, , as amended
from time to time, and approved by the
Commission, in accordance with the Market Rules;
“Grid Connection
Agreement”
means an agreement, approved by the Commission,
between the TSP and a User for Connection of the
Facilities of the User to the Power System and the
interface between User, TSP and SO. As the
context dictates this may be construed to include
the Transmission Use of System Agreement which
covers the charges the TSP applies to the User for
using its Transmission System;
“Harmonics” means sinusoidal currents with a Frequency equal to
an integer multiple of the fundamental Frequency
of the connection voltage;
“High Voltage” means a voltage, used for the supply of electricity,
whose lower limit of nominal root-mean-square
value is greater than or equal to 132kV;
“High Voltage
Equipment”
Has the meaning given in Section 25 and applies in
Section 25 and Appendix 4;
“Hot Line” means a direct voice line between two locations
which are 100 % of the time available and not
subject to any switching via the communication
switch network;
“HP” means High Pressure;
“HV” means High Voltage;
“Hz” means Hertz (Frequency);
“IEC” means International Electrotechnical Commission;
“Imbalance Energy” has the meaning assigned to that term in the
Market Rules;
“Interconnected
Network”
means a network with more than one Control
Area Synchronously Connected which in terms
of this Code means the West African Power
Pool or part of it. For the avoidance of doubt

the practice of feeding parts of Niger and
Benin disconnected from the rest of their
countries’ systems does not make an
Interconnected Network;
“Interconnection
Agreement”
has the meaning assigned to that term in the
Market Rules;
“Interconnection
Facilities”
means the facilities at the Connection Point as
defined in the relevant Grid Connection
Agreement;
“Interconnector Capacity
Entitlement”
has the meaning assigned to that term in the Market
Rules;
“Interconnector Energy
Trade Nomination”
Rules;
“Interrupted Energy
Assessment Rate (IEAR)”
means the factor that relates the customer losses
caused by electric power interruptions to the worth
of electric service Reliability;
“Interruptible Load” means a portion or a combination of a Distributor
Load or an Directly Connected Customer Load that
can be interrupted or reduced by remote control or
on instruction from the System Operator pursuant
to a contract between such Distributor or Directly
Connected Customer and the TCN;
“IP” means Intermediate Pressure;
“Isolating Device” means a device which ensures the disconnection of
Equipment from the remainder of the network;
“Isolation” Has the meaning defined in Section 25;
“Key Safe” means a safe in which keys used to ensure Isolation
and Earthing are kept;
“kV” means kilovolt;
“kVA” means kilovolt-ampere;
“Load” means the amount of electric power delivered or
required at any specified point or points on a
System;
“Load Factor” means the ratio of the actual electrical Energy
produced by a Generating Unit to the possible

maximum electrical Energy that could be produced
by that Generating Unit in any defined period;
“Load Shedding Severity
Index”
means the annual expected duration of load
curtailment and is measured in minutes;
“Local Safety
Instructions”
means the safety instructions of the SO or User as
applicable;
“Locked” means a secured Isolating or Earthing Device;
“Locking and Isolating
Device”
means an Isolating Device that is lockable;
“Low Voltage” means a voltage, used for the supply of electricity,
whose upper limit of nominal root-mean-square
value is 1kV;
“LP” Means Low Pressure;
“LV” means Low Voltage;
“Market Rules” or “Rules” means the electricity market rules as defined in the
Act, as amended from time to time, and approved
by the Commission;
“Medium Term Stage” has the meaning assigned to that term in the Market
Rules;
“Medium Voltage” means a voltage, used for the supply of electricity,
whose nominal root-means-square value lies
between 1kV and 132kV;
“Meter” means a device that measures and registers electrical
parameters including active or reactive Energy or
Power and voltage or current;
“Meter Data” has the meaning assigned to that term in the Market
Rules;
“Metering Installation” means any Apparatus used to measure the Energy
flowing through a specified point in the Power
System, which provides remote access to Meter
Data and which may provide remote monitoring of
Equipment conditions, including Meters,
instrument transformers, secondary circuitry,
secondary devices, meter data services, related
communication Facilities and related local
Equipment;

“MVA” means megavolt-ampere;
“MVAr” means megavar (1,000,000 vars), the unit for
Reactive Power;
“MVArh” means megavar hour;
“MW” means megawatt (1,000,000 watts), the unit for
Active Power;
“MWh” means megawatt hour;
“National Control Centre
(NCC)”
means the national Control Centre of the Nigerian
Transmission System;
“Network Constrained
Capacity”
has the meaning assigned in 8.3.2;
“Nigerian Bulk Electricity
Trader (NBET)”
“Nigerian Electricity
Supply Industry”
means the entity responsible for purchasing Energy
and Ancillary Services from Generators;
means the electricity industry of Nigeria including
all traders, Users of the Transmission System and
Participants in the electricity market;
“Node” means the busbars at the end terminal of a branch
of the Power System;
“Nomination” has the meaning assigned to that term in the Market
Rules;
“Normal Regulating
Margin”
means the minimum on-line capacity that can be
increased or decreased to allow the system to
respond to all reasonable Demand changes;
“N-1 Criteria” means that a system is sufficiently reliable if it is
able to operate acceptably under any unplanned
outage of Equipment due to a single cause;
“Off-taker” means a Distribution Network Operator or a
Directly Connected Customer;
“Operating Agreement” means an agreement between the System Operator
and a User covering operational issues such as for
example intertripping;
“Operating Reserve” means the unused capacity above System Demand,
which is required to cater for regulation, short-term
Load forecasting errors, and unplanned Plant
Outages. It consists of Spinning Reserve, Quick

Reserve and Slow Reserve;
“Operating Reserve
Policy”
means the document prepared by the System
Operator and approved by NERC which specifies
the permissible mix of different types of reserve
that will be used during the dispatch and real time
operation;
“Operating Security” means the ability of a Power System to withstand or
limit the adverse effects of any credible contingency
to the system including overloads beyond
emergency ratings, excessive or inadequate voltage,
and loss of stability or abnormal Frequency
deviations;
“Operating State” means any or all of the states as defined in Section
18.2.2 of this Code;
“Operational Planning” means all those actions as defined in Section 19 of
this Code;
“Outage” means the removal of Equipment from service,
unavailability for connection of Equipment,
restriction of use for any reason including, but not
limited to, to permit the performance of
inspections, tests or repairs on Equipment, and
shall include a Planned Outage, an Unplanned
Outage and a Forced Outage;
“Partial Shutdown” means that there is a partial loss of the Power
System, and that there has been substantial
Generation and Load loss ;
“Planned Outage” unless otherwise agreed between all relevant
Control Centres, Planned Outages shall mean
Outages, which are scheduled as part of the Outage
scheduling plan and confirmed two weeks in
advance.;
“Plant” means fixed and movable Equipment used in the
generation and/or transmission and/or distribution
of electricity other than Apparatus. For the
avoidance of doubt, Equipment may be considered
to be Plant even though it contains LV conductors
that provide electrical power for that Plant item;
“PLC” means power line carrier;
“Power Station” has the meaning assigned to that term in the Market

Rules;
“Power System” means a network of Power Stations, Load Facilities,
Transmission Systems and Distribution Systems,
including the associated Equipment electrically or
mechanically connected;
“Power System Stabiliser
(PSS)”
means a device that injects a supplementary signal
into the AVR (Automatic Voltage Regulator) in
order to improve Power System damping;
“Pre-dispatch Day” has the meaning assigned to that term in the Market
Rules;
“Primary Reserve” reserve that is provided automatically and
immediately to correct drops in frequency;
“Procedure” means a document governing the actions of the
System Operator, TSP and Users in an orderly
manner which is subservient to this Code:
 it can be a “System Operation Procedure”
where the System Operator has
responsibility for it; or
 a transmission Procedure where the TSP
has responsibility for it;
“Protection Scheme” means the provisions for detecting abnormal
conditions in the Power System and initiating fault
clearance or actuating signals or indications;
“Quality of Supply” means the quality of electrical power as measured at
Connection Points. Typical parameters of power
quality are the harmonic content; flicker and voltage
fluctuations;
“Quantity Nomination” has the meaning assigned to that term in the Market
Rules;
“Quick Reserve” means Interruptible Load or capacity readily
available, which can be started and Synchronized
within 30 minutes to meet the system Demand.
This includes hydro Plant, gas turbines and pumped
storage;
“Reactive Power” means the product of voltage and current and the
sine of the phase angle between them measured in
units of volt-amperes reactive and standard
multiples thereof i.e.

1000VAr = 1kVAr
1000kVAr = 1MVAr;

“Record Of Network
Safety Precautions
(RNSP)”
has the meaning given in Section 25.5 and can
either be a “Record Of Network Safety Precautions
- Requesting (RNSP-R)” or a “Record Of Network
Safety Precautions - Implementing (RNSP-I)”;
“Registered Capacity” for a Generating Unit other than a CCGT Module,
the normal full load capacity (MW) of the
Generating Unit as declared by the Generator, less
the MW consumed by the Generating Unit’s unit
transformer when producing at full load. For a
CCGT Module, the normal full load capacity (MW)
of a CCGT Module as declared by the Generator,
being the Active Power declared deliverable by the
CCGT Module at the Grid or Interconnected Entry
Point to a network;
“Registered Information” has the meaning assigned to that term in the Market
Rules;
“Regulatory Long Term
Transmission Plan”
means the plan developed by the System Operator
and approved by NERC which specifies the
additions or refurbishments to be developed in the
Transmission System in a predefined period in the
future;
“Relevant Connection
Point”
has the meaning ascribed in Subsection 25.6.8;
“Reliability” means in respect of the Power System, the ability of
the Power System to operate and deliver Energy
within Applicable Reliability Criteria in an adequate
and secure manner;
“Reliability Must-run
Agreement”
Rules;
“Reliability Must-run
Unit”
Rules;
“Remote Terminal Unit”
or “RTU”
means the computer unit in the substation that
communicates readings and status changes of
Equipment to the main SCADA computer at NCC;
“Responsible Manager” means the person representing the User and shall
be responsible for dealing with issues relating to
this Code;
“Rotational Load
Shedding”
means the manual disconnection of customer or
User circuits to reduce load on the system over a

period of time. This will be done by some rota
system agreed with the Commission and/or the
Ministry of Power;
“Safety” means the operation of the Power System in such a
manner as not to cause risk of injury or death to
any person or risk of damage to any Equipment;
“Safety Coordinators Has the meaning given in Section 25.4.2 they can
either be a “Requesting Safety Coordinator” or an
“Implementing Safety Coordinator”;
“Safety Key” means a key used for locking an Earthing or
Isolating Device;
“Safety Log” means the log book in the relevant Control Room
where Safety Precautions, instructions and incidents
are logged;
“Safety Precautions” Has the meaning given in Subsection 25.6.1;
“Secondary Reserve” means the capability of a Generating Unit to have
its generated outputs adjusted frequently so that any
Power System Frequency variations can be
corrected;
“Section” means a provision in the body of this Code if the
reference is in the body or to a provision in an
Appendix if the reference is in that Appendix;
“Single Line Diagram” means a drawing of electrical circuits where three
phase circuits are represented by a single line rather
than three lines;
“Slow Reserve” means available capacity ready for Synchronisation
to the Transmission System within 24 hours. The
purpose of Slow Reserve is to replace any
Generating Units on Unplanned Outages or to
meet forecast Demand;
“Spinning Reserve” means the unused capacity of Synchronised
Generating Units, which can be delivered without
manual intervention;
“Station Capacity” means the capacity of a Power Station being the
sum of the Generating Unit Registered Capacities
minus the Station Transformer load;

“Station Transformer” or
“Station Service
Transformer”
means the transformer at a Power Station or a
Transmission substation that directly supplies the
station load;
“Subsection” means a specific provision in this Code;
“Subtransmission” means at voltages just below those of the
Transmission Network i.e. 11kV, 33kV or 66kV;
“Subtransmission System” means a Distributor or Directly Connected
Customer System that is at Subtransmission
voltages which may contain Embedded Generating
Units or connect in parallel between Connection
Points;
“Supervisory Control and
Data Acquisition
(SCADA)”
means a system of remote control and telemetry
used to monitor and control the Power System;
“Switched Voice Circuit” means a voice line between different Users which
are established via the communication network
through a process of exchanging various switching
actions before the voice connection is established
between the Users;
“Synchronise” means the process of connecting two Energy
supplies together in parallel or the selection of the
appropriate time for switching a synchronous
Generating Unit onto energised busbars or into
parallel with another normally running synchronous
Generating Unit and like terms shall be construed
accordingly;
“System” User(s) or TSP Apparatus or Equipment which can
be stand alone or connected to other Equipment or
Apparatus, employed in activities involving
production, supply and consumption of electricity;
“System Disturbance” means any disturbance that results in localised or
widespread loss of load or resulting in one or more
of the following phenomena: system instability,
cascading Outages, formation of islands, or
undesirable voltage or Frequency;
“System Emergency
Condition”
means the condition that the Power System is in
when under stress. This is normally related to a
shortage of generation and the Power System
Frequency dropping to below predefined
emergency limits;

“System Marginal Price” has the meaning assigned to that term in the Market
Rules;
“System Minutes” means the sum of Energy (MW Minutes) lost,
divided by the peak Demand (MW) in the Power
System;
“System Operator” or
“SO”
means the holder of a System Operation License;
“System Stability” means the dynamic behaviour of the Power System
following a disturbance, being its ability to
automatically return to a normal state;
“System Tests” means those tests which involve simulating
conditions and recording them or the controlled
application of irregular, unusual or extreme
conditions on the Power System or any part of it
and recording them, but not including routine
testing, commissioning or re-commissioning tests;
“TCN” means the Transmission Company of Nigeria;
“Total Shutdown” means the complete failure of the Power System to
function;
“Transitional Stage” has the meaning assigned to that term in the
Market Rules;
“Transmission” means conveying Energy at voltages of greater than
or equal to 132kV;
“Transmission Constraint” means a limit imposed on power transfer across any
part of the Transmission System due to thermal
overload, voltage or stability considerations;
“Transmission Planning
Criteria”
means a set of criteria to be used to plan and
develop the Transmission System;
“Transmission Service
Provider (TSP)”
means the division of TCN that owns and
maintains the Transmission Network;
“Transmission System” or
“Transmission Network”
means the system or network of electric lines
comprising wholly or mainly high voltage lines and
electric Plant and which is used for Transmission of
Energy from a Power Station to a substation, from
one Power Station to another, from one substation
to another or to or from any Interconnector or to
final consumers, and includes any structures and

Equipment’s for that purpose;
“Under-Frequency” means Frequencies below the nominal Frequency
of 50Hz;
“Under-Frequency Load
Shedding”
means the automatic tripping of customer Load by
means of one or more relays set to trip at specific
Under-Frequencies which during a sudden
mismatch between Generation and customer Load
attempts to prevent system shutdown;
“Unplanned Outage or
Emergency Outage”
means unless otherwise agreed between all relevant
Control Centres, Unplanned Outages shall mean
Outages which are not scheduled with the necessary
advance notice;
“Unreliability” has the meaning assigned in Appendix 3.3 and
applies to Appendix 3;
“Usage Charge” has the meaning assigned to that term in the Market
Rules;
“Users” A person or party using Transmission System as
agreed and permitted by the TSP and NBET;
“Voltage” is a measure of electrical pressure or potential. One
volt being the potential difference between two
points where there is a current flow of one amp
through a resistance of one ohm;
“Voltage Control” means the retention of the Voltage on the System
within acceptable limits;
“Voltage Dip” means a sudden reduction of the voltage to a value
between 90% and 100% of the nominal voltage
followed by a voltage recovery after a short period
of time;
“Voltage Fluctuations” means a series of rapid voltage changes, which may
be regular or irregular;
“Voltage Reduction” means the method to temporarily control Demand
by reduction of the entire System voltage;
“Voltage Support” means injection or withdrawal of Reactive Power by
means of changing the excitation of Generating
Units or operation of reactive compensation
devices to maintain voltages across the Power
System within a specified range;

“Voltage Unbalance” means a condition in a three-phase network in
which the root-mean-square value of the phase
voltages or the phase angles between consecutive
phases is not equal;
“VT” means voltage transformer; and
“West African Power Pool
(WAPP)”
has the meaning defined in the relevant inter-
governmental agreement between the participating
countries in West Africa.

2. APPENDIX 2: CONDITIONS PRECEDENT
The Conditions Precedent for this Code are already in place.
Order No. NERC/GL022 empowers this Code.

3. APPENDIX 3: RELIABILITY CONCEPTS AND DEFINITIONS
3.1 Introduction
The Nigerian Power System consists of those Generation and Transmission facilities, which are
controlled by the TCN System Operator and which function as part of an integrated and
coordinated power supply network.
In order to maintain reliable operation of the Transmission System, it is necessary that all
systems observe and subscribe to certain minimum planning criteria. The criteria and principles
provided in this Appendix serve as a guideline to develop criteria and methodologies applicable
to the TCN and related interconnections and customers.
This Appendix 3 consists of this introduction and a conclusion together with three sections as
follows:
Section 2 provides guidelines to transmission contingency criteria based on NERC standards,
Section 3 provides guidelines to the measuring of Reliability indices in order to produce annual
performance figures, and
Section 4 provides guidelines with regard to the measurement of the value of network
infrastructure.
This Appendix thus provides guidelines that can be used to direct the TCN planning and
operational criteria in future. It does not provide the procedures and measures required to
ensure that the criteria are followed. Neither does the Appendix direct responsibility to any of
the TCN divisions. These issues will need to be developed and resolved before criteria of this
nature can effectively be implemented.
3.2 Transmission Reliability Criteria
In general an interconnection philosophy is to minimize loss of load by remaining
interconnected. Interconnected System planning will include steady state and dynamic
simulated testing to represent specific occurrences for each type of contingency specified
below or listed in Table A2 of this Planning Standard. The contingency tests will be
performed for reasonable variations of load level, Dispatch Schedules, planned Transmission
line maintenance outages, and anticipated power transfers. At a minimum, this should
include projected loads for the upcoming dry and wet seasons and a ten-year planning
horizon. The Transmission providers involved should plan to resolve any unacceptable test
results through the provision of Transmission Facilities, the alteration of System Operating
Procedures, or other means as appropriate.
While the requirements listed in Table A2 address most planning concerns, tests will also be
conducted to ensure that the planned system conforms to the following additional
requirements:
The contingency loss of a double-circuit Transmission line in length (either without a fault or
subsequent to a normally-cleared non-three-phase fault) with all other facilities normal
should not cause:
a. cascading or uncontrolled outages,
b. instability of Generating Units at multiple Plant locations, or

c. interruption of service to firm Demand or Generation other than that
isolated by the double-circuit loss,
following the execution of all automatic operating actions such as relaying and
special protection systems.
Furthermore, the loss should result in no damage to or failure of Equipment and,
following the execution of specific non-automatic predefined operator-directed
actions such as re-dispatch, curtailment of interruptible load, or curtailment of
unplanned transfers, should not result in applicable voltage or thermal ratings
being exceeded.
With any single Generating Unit unavailable, and with any other generation pre-emptively re-
dispatched, the contingency loss of a single transmission element (either without a fault or
subsequent to a normally-cleared non-three-phase fault) with all other facilities normal
should not cause:
a. cascading or uncontrolled outages,
b. instability of Generating Units at multiple Plant locations, or
c. interruption of service to firm Demand or generation other than that isolated
by the transmission element,
following the execution of all automatic operating actions such as relaying and
special protection systems.
Furthermore, the loss should result in no damage to or failure of Equipment and,
following the execution of specific non-automatic predefined operator-directed
actions such as re-dispatch, curtailment of interruptible load, or curtailment of
unplanned transfers, should not result in applicable voltage or thermal ratings
being exceeded.
3.2.1 Report and Testing
Annual preparation of adequacy indices of the TCN power system will be required. This
should be read in conjunction with the long-term planning reports for infrastructure
additions with possible quantification of the worth of these network additions as outlined in
Section 4. These working papers to report the results of system tests future planning reports
will provide the basis for statements concerning the adequacy of the planned TCN System.

Table A2. Transmission Systems Standards — Normal and Contingency Conditions
Category Contingencies System Limits or Impacts
Initiating Event(s) and Contingency
Component(s)
Components
Out of Service
Thermal
Limits
Voltage
Limits
System
Stable
Loss of
Demand or
Curtailed Firm
Transfers
Cascading c
Outages
A – No Contingencies
All Facilities in Service None Normal Normal Yes No No
B – Event resulting in the
loss of a single
component.
Single Line Ground (SLG) or 3-
Phase (3Ø) Fault, with Normal
Clearing:
1.Generating Unit
2.Transmission Circuit
3.Transformer
Loss of a Component without a
Fault.
Single
Single
Single
Single
Applicable Rating a
(A/R)
A/R
A/R
A/R
Applicable Rating a
(A/R)
A/R
A/R
A/R
Yes
Yes
Yes
Yes
No b
No b
No b
No b
No
No
No
No

C – Event(s) resulting in
the loss of two or more
(multiple) components.
SLG Fault, with Normal Clearing:
1 Bus Section
2.Breaker (failure or internal fault)
Multiple
Multiple
A/R
A/R
A/R
A/R
Yes
Yes
Plannedd
Plannedd
No
No
SLG or 3Ø Fault, with Normal
Clearing, Manual System
Adjustments, followed by another
SLG or 3Ø Fault, with Normal
Clearing:
3.Category B (B1, B2, B3)
contingency, manual system
adjustments, followed by another
Category B (B1, B2, B3) contingency
Multiple A/R A/R Yes Plannedd No
Fault (non 3Ø), with Normal
Clearing:
4.Double Circuit line
Multiple A/R A/R Yes Plannedd No
SLG Fault, with Delayed Clearing:
5.Generating Unit 7.Transformer
6.Transmission Circuit 8.Bus Section
Multiple
Multiple
A/R
A/R
A/R
A/R
Yes
Yes
Plannedd
Plannedd
No
No
D e – Extreme event
3Ø Fault, with Delayed Clearing (stuck breaker or
protection system failure):
Evaluate for risks and consequences.

resulting in two or more
(multiple) components
removed or cascading
out of service
1.Generating Unit
3.Transformer
2.Transmission Circuit
4.Bus Section
3Ø Fault, with Normal Clearing:
5.Breaker (failure or internal fault)
Other: 6.Loss of line with three or more circuits
7.All transmission lines on a common right-of way
8.Loss of a substation (one voltage level plus
transformers)
9.Loss of a switching station (one voltage level plus
transformers)
10.Loss of all generating units at a station
11.Loss of a large load or major load centre
12.Failure of a fully redundant special protection
system (or remedial action scheme) to operate when
required
13.Operation, partial operation, or mis-operation of a
fully redundant special protection system (or remedial
action scheme) for an event or condition for which it
was not intended to operate
14. Impact of severe power swings or oscillations from
disturbances in another Regional Council.
May involve substantial loss of customer demand and generation in a widespread area or
areas.
Portions or all of the interconnected systems may or may not achieve a new, stable operating
point.
Evaluation of these events may require joint studies with neighbouring systems.
Document measures or procedures to mitigate the extent and effects of such events.
Mitigation or elimination of the risks and consequences of these events shall be at the
discretion of the entities responsible for the reliability of the interconnected Transmission Systems.
Footnotes to Table A2.
a) Applicable rating (A/R) refers to the applicable normal and emergency Facility thermal rating or system voltage limit as determined and
consistently applied by the system or Facility owner.

b) Planned or controlled interruption of Generating Units or electric supply to radial customers or some local network Customers,
connected to or supplied by the faulted component or by the affected area, may occur in certain areas without impacting the overall security of
the interconnected transmission systems. To prepare for the next contingency, system adjustments are permitted, including curtailments of
contracted firm (non-recallable reserved) electric power transfers.
c) Cascading is the uncontrolled successive loss of system elements triggered by an incident at any location. Cascading results in widespread
service interruption which cannot be restrained from sequentially spreading beyond an area predetermined by appropriate studies.
d) Depending on system design and expected system impacts, the controlled interruption of electric supply to customers (Load Shedding),
the planned removal from service of certain Generating Units, or the curtailment of contracted firm (non-recallable reserved) electric power
transfers may be necessary to maintain the overall security of the Interconnected Transmission Systems.
e) A number of extreme contingencies that are listed under Category D and judged to be critical by the transmission planning entity (ies) will
be selected for evaluation. It is not expected that all possible Facility Outages under each listed contingency of Category D will be evaluated.

3.3 Reliability Measures
3.3.1 Reliability indices
The fundamental attributes for probabilistic Reliability measures to be considered to evaluate
risk of probable extreme events as discussed in Table A2 include:
 The Frequency of events (e.g. frequency of circuit overload – 0.72 events/year),
 Duration of events (e.g. duration of circuit overload – 2.5 hours/year), and
 Severity of events (how does event impact on load curtailment)
From these attributes other indices to quantify network performance can be calculated. To
enable the definition of applicable indices, which may apply to the TCN, a number of
concepts and definitions related to network, configuration and aspects influencing network
performance are discussed below. These concepts and definitions are taken from Reference
[1]1
.
3.3.2 Concepts and Definitions
Bulk system Reliability performance is normally measured in terms of the amount of
Unreliability created by events in the bulk system, such as discussed in Table A2.
“Unreliability” denotes the inability to provide the required supply to all customers connected
to the bulk system. This involves loss of load to the bulk system, or maybe indirectly through
the Distribution System.
Furthermore, a bulk system unreliability event can be defined as an event in the bulk system
representing the inability to supply load to one or more customers. This inability may be a
consequence of manual actions or of automatic operations of protective devices.
3.3.2.1 Manual Actions to Avoid Unreliability
These are defined as actions to:
 Adjust voltage and power flow through transformer tap changers,
 Re-dispatch generation,
 Reduce sales/ increase purchases from interconnections, and
 Manual actions such as switching operations.
Unreliability by Reducing Load.
These are defined as actions such as:
 Shed interruptible loads,
 Reduce system-wide voltage,
 Appeal to public or key customers to reduce demand, and
1
C.C. Fong, R. Billinton, R.O. Gunderson, P.M. O’Neill, J. Raksany, A.W. Schneider, Jr, B. Silverstein, “Bulk System Reliability – Measurement
and Indices”, IEEE Trans. On Power Systems, Vol.4, No32, August 1989, pp. 829-835

 Institute Rotational Load Shedding.
3.3.2.2 Automatic Operations Signifying Unreliability
Automatic, intentional load shedding by devices designed to prevent or minimize a System
Disturbance.
Interruption of supply due to bulk system Equipment Outages causing loss of continuity.
System Disturbance that is widespread load loss involving one or more of the following
phenomena: system instability, cascading Outages, formation of islands, or undesirable
Voltage or Frequency.
The manual actions to avoid unreliability listed above are usually taken to avoid violation of
Operating Security limits in anticipation of further Outages that may cause Unreliability. The
manual actions to confine Unreliability, on the other hand, are usually taken when a condition
such as capacity or energy shortfall has already occurred, in order to minimize its
consequences.
Summarizing, the proposed measurement system concentrates on the following Unreliability
events:
 Interruption of supply due to loss of continuity,
 System Disturbance, and
 Automatic and Rotational Load Shedding.
3.3.2.3 Monitoring Points
With the above in mind, two types of monitoring points are defined. They are illustrated
conceptually in Figure 1: and are defined as follows:
Radial Delivery Point: A radial delivery point is:
A low voltage bus of a Transformer. The bus radially supplies a Distribution System, or
A point in the bulk system, which is an interface between Transmission System and Directly
Connected Customer-owned facilities. The point radially supplies the Directly Connected
Customer.
Meshed Delivery Points: a set of points on the boundary between the Transmission System
and a discrete part of the Distribution System.
Significant point: This is a bus or a point within the bulk system, where SO deems it
important to monitor the reliability of service. This type of monitoring point recognizes that
there may be special purpose monitoring points that are different from radial or meshed
delivery points.
This distinction between radial and meshed delivery points is that interruption of radial
delivery points result in load loss, whereas interruption of meshed delivery points does not
always result in load loss but could result in inadequate service conditions.

Bulk System
A
B
B
B
Load
Load
LoadRadial
Distribution
System
Meshed Distribution
System
A: Radial Delivery Point
B: Meshed Delivery Point
C: Significant Point
Figure 1: Measurement Points
C
Figure 2: further illustrates the two types of delivery points.
G
Load Load
Load Load
Load Load
G
G
G
Load
Load Load Load
Radial
Distribution
System
Meshed Distribution System
330 kV
330 kV
330 kV
330 kV
330 kV
132 kV
132 kV
132 kV
132 kV
132 kV
11 kV
33 kV
11 kV
33 kV
A
C
D
Radial delivery point
Meshed delivery point
Customer's system
Figure 2: NEPA Bulk System
3.3.3 Basic Indices

Several fundamental indices are proposed. These can be expanded based on the TCN needs.
All of these indices can be calculated for a defined recording period. The length of the
period should be measured over multiple years to facilitate comparison.
Delivery Point Interruption Indices
(a) Individual Delivery Point Indices: For each delivery point (radial or meshed):
 YearsPeriod
onsInterruptiofNo
FrequencyonInterrupti
.

)(YearsPeriod
DurationsonInterruptiofSum
DurationonInterruptiAnnual 
onsInterruptiofNo
onInterruptiperDurationAverage
.

 YearsPeriod
dInterrupteMWofSum
dInterrupteLoadAnnual 
 YearsPeriod
EnergypliedUnofSum
EnergyliedUnAnnual
sup
sup 
iYearinMWLoadPeakPoDelivery
iYearinutesMWEnergypliedUnTotal
SeverityonInterruptiPoDelivery
i )(int
)min(sup
int 
(b) System-Wide Delivery Point Indices: For the bulk system and for each type of delivery
point (radial or meshed):
yearsPoDelivery
onsInterruptiofNo
FrequencyonInterruptiAverageSystem


int
.
YearsPoDelivery
DurationonInterruptiAverageSystem


int
onsInterruptiofNumber
DurationstorationAverageSystem Re
YearsPoDelivery
dInterrupteMWofSum
dInterrupteLoadAverageSystem


int
YearsPoDelivery
EnergypliedUnofSum
EnergypliedUnAverageSystem


int
sup
sup
iYearinMWLoadPeakSystem
iYearinMinutesMWEnergypliedUnTotal
SeverityonInterruptiSystem
i )(
)(sup

Indices for Interruption of a Significant Point
For each significant point
 YearsPeriod
onsInterruptiofNo
FrequencyonInterrupti
.


 YearsPeriod
DurationsnInteruptioofSum
DurationonInterruptiAnnual 
The monitoring of significant points is very specific to the needs of individual operations.
“System-wide” average indices are not suggested here but may be considered, for groups of
significant points.
Automatic and Rotational Load Shedding Indices
For each type of load shedding:
 YearsPeriods
EventsofNo
Frequency
.

iYearinMWPeakSystem
iYearinMinutesMWEnergypliedUnTotal
SeveritySheddingLoad
i )(
)(sup

These indices may also be calculated for a specific automatic scheme, to indicate its impact
on bulk system reliability. The Load Shedding Severity Index is expressed in System Minutes.
System Disturbance Indices
For an individual System Disturbance:
 
 MWPeakSystemAnnual
MinutesMWEnergypliedUn
SeverityeDisturbancSystem
sup

This index is expressed in System Minutes. It is again fundamentally the same as the Bulk
Power Energy Curtailment Index, but is applied to an individual System Disturbance in this
case.
3.4 Value of Network Performance
Broadly speaking, the cost of an interruption from a customer’s perspective is related to the
nature of the degree to which the activities interrupted are dependent on electricity. This
dependency can be translated to a Customer Damage Function (CDF) that provides the
severity of an interruption in relation to the duration of the interruption for a specific
customer or group of customers. In turn, this dependency is a function of both customer
and interruption characteristics.
Customer characteristics include:
 Type of customer;
 Nature of the customer’s activities;
 Size of operation, and other demographic data;
 Demand, and energy requirements; and
 Energy dependency as a function of time of day, etc.
Interruption characteristics include:
 Duration;

 Frequency;
 Time of occurrence of interruptions;
 Whether an interruption is complete or partial;
 If advance warning or duration information is supplied by the utility; and
 Whether the area affected by the outage is localized or widespread.
3.4.1 Application of Customer Interruption Cost
The broadest application of a Customer Damage Function is its use to relate the composite
customer losses to the socio-economic worth of electric service Reliability for an entire Utility
Service Area2
. The cost estimates can be obtained by multiplying the Expected Unserved
Energy to customers due to interruptions by a suitable factor, designated as the Interrupted
Energy Assessment Rate (IEAR) expressed in $/kWh.
3.4.2 Feedback into the System Planning Process
Some countries with extremely high reliability have attempted to introduce obligations on
Distributors to make some form of payment to customers based on lost load. However this is
not the common application of the Customer Damage Function.
The standard application of the Customer Damage Function is as feedback into the planning
process. This is in order to support the planning security of supply analysis.
3.5 Conclusion
This Appendix serves as a guideline for the TCN to develop applicable Reliability measures
and methodologies to maintain reliable operation of the Transmission System.
The Appendix provided fundamental concepts relating to:
 Transmission contingency criteria based of NERC standards,
 The measuring of Reliability indices in order to produce annual performance figures, and
 Guidelines with regard to the measurement of the value of network infrastructure.
2
Li Wenyuan, R. Billinton, “A Minimum Cost Assessment Method for Composite Generation and Transmission System Expansion Planning”,
IEEE Trans. On Power Systems, Vol.8, No.2, May 1993, pp. 628-635

4. APPENDIX 4A – RECORD OF NETWORK SAFETY
PRECAUTIONS (RNSP)
[TCN] [__________________ CONTROL CENTRE/SITE]
RECORD OF NETWORK SAFETY PRECAUTIONS REQUEST (RNSP-R)
(Requesting Safety Coordinator's Record)
RNSP NUMBER……………………..
PART 1
1.1 High Voltage Equipment Identification
Safety Precautions have been established by the implementing Safety Coordinator (or
by another User on that User's Equipment connected to the implementing Safety
Coordinator's Equipment) to achieve (in so far as it is possible from that side of the
Connection Point) Safety From the Equipment on the following High Voltage
Equipment on the Requesting Safety Coordinator's Equipment:
[State identity - name(s) and, where applicable, identification of the high voltage
circuit(s) up to the Connection Point]:
_____________________________________________________________________
________________
_____________________________________________________________________
________________
Further Safety precautions required on the requesting Safety Coordinator’s
Equipment as notified by the implementing Safety Coordinator.
_____________________________________________________________________
________________
1.2 SAFETY PRECAUTIONS ESTABLISHED
(a) ISOLATION
[State the Location(s) at which Isolation has been established (whether on the
implementing Safety Coordinator's Equipment or on the Equipment of another User
connected to the implementing Safety Coordinator's Equipment). For each Location,
identify each point of Isolation. For each point of Isolation, state the means by which
the Isolation has been achieved, and whether, immobilised and Locked, Caution
Notice affixed, other safety procedures applied, as appropriate.]
_____________________________________________________________________
________________

_____________________________________________________________________
________________
_____________________________________________________________________
________________
(b) EARTHING
[State the Location(s) at which Earthing has been established (whether on the
implementing Safety Coordinator's Equipment or on the System of another User
connected to the implementing Safety Coordinator's System). For each Location,
identify each point of Earthing. For each point of Earthing, state the means by which
Earthing has been achieved, and whether, immobilised and Locked, other safety
procedures applied, as appropriate].
_____________________________________________________________________
________________
_____________________________________________________________________
________________
_____________________________________________________________________
________________
1.3 ISSUE
I have received confirmation from _________________________________________
(name of Implementing Safety Coordinator) at
_________________________________________ (location) that the Safety
Precautions identified in paragraph 1.2 have been established and that instructions will
not be issued at his location for their removal until this RNSP is cancelled.
Signed ................................................................(Requesting Safety Coordinator)
at .......................................(time) on .................................................. (Date)
PART 2
2.1 CANCELLATION
l have confirmed to _________________________________________ (name of the
implementing Safety Coordinator) at
________________________________________ (location) that the Safety
Precautions set out in paragraph 1.2 are no longer required and accordingly the RNSP is
cancelled.
Signed ................................................................(Requesting Safety Coordinator)
at ........................................(time) on ................................................. (Date)

4. APPENDIX 4B – RECORD OF NETWORK SAFETY
PRECAUTIONS
[TCN] [_________________ CONTROL CENTRE/SITE]
RECORD OF NETWORK SAFETY PRECAUTIONS IMPLEMENTATION
(RNSP-I)
(Implementing Safety Coordinator's Record)
PART 1
RNSP NUMBER ………………..
1.1 High Voltage Equipment IDENTIFICATION
Safety Precautions have been established by the implementing Safety Coordinator (or
by another User on that User's Equipment connected to the implementing Safety
Coordinator's Equipment) to achieve (in so far as it is possible from that side of the
Connection Point) Safety from the System on the following High Voltage
Equipment on the Requesting Safety Coordinator's Equipment.
[State identity - name(s) and, where applicable, identification of the high voltage
circuit(s) up to the Connection Point]:
_____________________________________________________________________
________________
_____________________________________________________________________
________________
Recording of notification given to the Requesting Safety Coordinator concerning
further Safety Precautions required on the Requesting Safety Coordinator’s
Equipment.
1.2 SAFETY PRECAUTIONS ESTABLISHED
(a) ISOLATION
[State the Location(s) at which Isolation has been established (whether on the
connected to the implementing Safety Coordinator's Equipment). For each Location,
identify each point of Isolation. For each point of Isolation, state the means by which
the Isolation has been achieved, and whether, immobilised and Locked, Caution
Notice affixed, other safety procedures applied, as appropriate.]
_____________________________________________________________________
________________
_____________________________________________________________________
________________

_____________________________________________________________________
________________
(b) EARTHING
[State the Location(s) at which Earthing has been established (whether on the
connected to the Implementing Safety Coordinator's System). For each Location,
identify each point of Earthing. For each point of Earthing, state the means by which
Earthing has been achieved, and whether, immobilised and Locked, other safety
procedures applied, as appropriate].
_____________________________________________________________________
________________
_____________________________________________________________________
________________
_____________________________________________________________________
________________
1.3 ISSUE
I have confirmed to ________________________________________ (name of
Requesting Safety Coordinator) at
__________________________________________ (location) that the Safety
Precautions identified in paragraph 1.2 have been established and that instructions will
not be issued at my location for their removal until this RNSP is cancelled.
Signed ...............................................................(Implementing Safety Coordinator)
at ...............................................(time) on ...................................................... (Date)
PART 2
2.1 CANCELLATION
l have received confirmation from _________________________________________
(name of the Requesting Safety Coordinator) at
________________________________________ (location) that the Safety
Precautions set out in paragraph 1.2 are no longer required and accordingly the RNSP is
cancelled.
Signed ................................................................(Implementing Safety Coordinator)
at ................................................(time) on ........................................................ (Date)
(Note: This form to be of a different colour from RNSP-

4. APPENDIX 4C – RNSP ISSUE PROCESS
If work is required to both
sides of the Connection
Point, each party takes the
role of RSC for the work on
his side & separate RNSPs
are required
Work required across
boundary
RSC contacts ISC & each
confirms authority to act
pursuant of Section 25
RSC and ISC agree
location of Safety
Precautions
Log
ISC establishes
isolation on his
equipment
ISC confirms isolation is
established to RSC
All isolation by RSC and ISC completed
ISC initiates establishment of earthing (if agreed)
ISC confirms earthing
is established to RSC
Log
ISC completes
RNSP-I.
Details exchanged
RSC completes
RNSP-R
RSC can now authorise
the work
RNSP cancellation
process
Contacts RSC if isolation
is required on RSC
Equipment Record on
RNSP
RSC establishes &
maintains isolation
on RSC Equipment
RNSP process completed
for work on one side of the
Connection Point
If unable to agree Safety
Precautions follow GC
If required, provide isolation
on other equipment
If the work includes testing
which affects another
equipment
See Appendix
4E
RSC – Requesting Safety Coordinator
Person requiring Safety Precaution from another
User
ISC – Implementing Safety Coordinator
Person who co-ordinates provision of Safety
Precautions
If reqd, provide earthing on other
equipment

4. APPENDIX 4D – RNSP CANCELLATION PROCESS
Work / testing completed or
cancelled
RSC contacts ISC to
inform safety precautions
are no longer required
RSC informs ISC of RNSP
document to be cancelled
(including identity
numbers)
The RSC and ISC complete their
respective parts of section 2.1 on
RNSP-R and RNSP-I
The RSC and ISC exchange the details
including respective names, times and
date
RNSP is now
cancelled
Agree removal of Safety
Precautions
Agreed between RSC
and ISC that all earths
are removed
Removal of isolation agreed
between RSC and ISC
Section 2.1
completed
Removal of earthing during
testing across the Connection
Point is as set out in 25
Removal being an
internal matter for
the party the ISC
represents
RSC – Requesting Safety
Coordinator
Person requiring Safety
Precaution from another User
ISC – Implementing Safety
Coordinator
Person who co-ordinates
provision of Safety Precautions

4. APPENDIX 4E – RNSP TESTING PROCESS
RSC – Requesting Safety Co-ordinator
Person requiring Safety Precaution from
another User
ISC – Implementing Safety Co-ordinator
Person who co-ordinates provision of Safety
Precautions
Continue from
Appendix 4C
Testing will not take place by
RSC until
Any RNSP other
than for the
proposed test shall
be cancelled
Test can now
take place
When test is complete
or cancelled RSC
informs ISC
Log
If testing
required the
removal of
earthing the
RNSP process is
as set out in
section 25
Earthing not
reapplied
RNSP cancellation
process
See Appendix 4D
ISC confirms that no
person is working or
testing or authorised to,
on his equipment or
another equipment
within the points of
Isolation on the RNSP
Log
No person will be
so authorised until
proposed test is
completed (or
cancelled) by the
RSC
The ISC agrees to the
testing between the
points of Isolation on the
RNSP and RSC
Equipment
Earthing
reapplied
RNSP can stay in
force, if required

5. APPENDIX 5 – DATA REGISTRATION REQUIREMENTS
5.1 Introduction:
The System Planning specifies the technical and design criteria and procedures to be
adopted by the TCN for the planning and development of the Transmission System. The
Users of the Transmission System shall take the Data Registration for system planning
into account for planning and development of their own Equipment or Apparatus.
5.1.1 Reinforcements and extensions to the Transmission Network arise due to many reasons
of which a few are mentioned below:
1. A development on a User's Equipment or Apparatus already connected to the
Transmission Network as a User development.
2. Introduction of a new Connection Point between a User's Equipment or
Apparatus and the Transmission Network.
3. The need to increase Transmission Network capacity, removal of operational
constraints, maintenance of Security Standards and meeting general increases in
Demand.
4. Steady state and transient stability considerations.
5. Cumulative effects of any combination of the above four.
5.1.2 The work of such reinforcement and extension to the Transmission Network may also
involve work at a connecting point (entry or exit) of a Power Station/Distributor to the
5.1.3 The development of the Transmission Network must be planned in advance duly
allowing sufficient lead time, considering the following:
1. Time required for obtaining all the necessary statutory approvals like
Environmental Impact Assessment clearance, Forest clearance, Road or Railway
clearance, clearance from aviation authorities, etc., and the right of way
permissions wherever required,
2. Time required for detailed engineering, design and construction work to be
carried out. This Network Planning, therefore, enforces the time scales for
exchange of information between the TCN and the User(s). All the concerned
parties, wherever appropriate, shall have due regard to the confidentiality of such
information.
To enable the TCN to discharge its responsibilities under its Transmission Licence
Conditions by conducting System Studies and preparation of perspective plans for
Demand, Generation and Transmission Network expansion as detailed under the Grid
Code, all Users of the Transmission Network shall furnish all the data to the TCN from
time to time detailed below under Data Registration Requirement of Sections 8 and 12.
BASIC DATA REQUIREMENTS BASED ON SECTIONS 8, 12
Configurations of sites will vary hence the data requirements below are broadly phrased.
The interpretation of the requests for data is to be based on what the User owns or has necessary
access to.
Ancillary Services (Power Quality Services)

The provision of Ancillary Services by Generators is critical to the secure operation of the Power
System. The requirement to provide them is compulsory on Generators under the Market Rules,
Grid Code and the Generator Licence.
On all timescales the Generator must provide the SO with its AS capability covering:
1) Reserve and Frequency Control
a) Reserve capability at all operating levels
i) Based on Frequency drop
ii) Response time
iii) Sustainability
b) automatic deloading capability at high frequencies
2) Voltage Control
a) Maximum and minimum MVAr levels
b) MVAr response to Voltage change
3) Black Start
a) This is a compulsory service.
PART-1 - GENERATION
To be furnished by Generators to TCN
5A Standard Planning Data (Generation)
THERMAL
I. GENERAL: -
1. Site: i. Furnish location map to scale showing roads, Railway lines,
Transmission lines, Rivers, and reservoirs if any.
ii. Fuel linkage (Natural Gas, Naptha, Oil pipeline)
iii. Furnish information on means of Coal transport from
mines or means of coal carriage if coal is to be brought from
distance.
iv. In case of other fuels, furnish details of sources of fuel
and their transport.
v. Water Sources (furnish information on availability of water
for operation of the Power Station).
vi. Environmental (State whether forest, lands mining clearance
areas are affected).
2. Site Map:
(To scale)
Showing area required for Power Station coal linkage,
coal yard, water pipe line, ash disposal area, colony etc.

3. Approximate period of construction.
4. Guaranteed Plant Load Factor.
5. Annual Generation.
II. Connection:
1. Point of connection Furnish Single Line Diagram of the proposed
connection with the system.
2. Step up voltage for connection in kV
III. Station Capacity:
1. Total Power Station
capacity (MW).
2. Ancillary Services
provided
MW
3. No. of Units and Unit
size MW.
State whether development will be carried out in
phases and if so, furnish details.
4. Generating Unit Data: 4 Steam Turbine- State Type, capacity, steam pressure, steam
temperature, heat rate, efficiency etc.
5 Generating Unit:
a) Type
b) Rating (MVA)
c) Terminal Voltage (kV)
d) Rated Power Factor
e) Frequency Response Table
f) Reactive Power capability (MVAr) in the range 0.95 leading
and 0.85 lagging.
g) Short Circuit Ratio
h) Direct axis transient reactance (% on MVA rating)
i) Direct axis sub-transient reactance (% on MVA rating)

j) Auxiliary Power requirement
6 Generating Unit Transformer / Station Transformer
a) Rated Capacity (MVA)
b) Voltage Ratio (HV/LV)
c) Tap change range (+% to -%)
d) On-load or off-load tap change
e) Percentage Impedance (Positive Sequence at Full load).
5B Hydro Electric:
1. General:
1. Site Furnish location map to scale showing roads, railway
lines, Transmission lines
2. Site Map (To scale) Map showing proposed dam, reservoir area, water
pipe system, fore bay, powerhouse etc.
3. Submerged Area Furnish information on area of villages submerged,
forestland, agricultural land etc.
4. Approximate period of construction.
5. Commissioning Date
6. Annual Generation: expected water flow, expected Energy, annual load factor
5B.1. Connection:
1. Point of connection Furnish Single Line Diagram of
proposed connection with the
Transmission System
Step up voltage for connection kV
5B.2. Station Capacity:
1. Total Power Station capacity MW State whether development would be
carried out in phases and if so furnish
details

2. No. of Units and unit size MW.
5B.3 Generating Unit Data:
1. Operating Head (In Mtr) Maximum
Minimum
Average
2. Turbine State type and capacity
3. Generating Unit a) Type
b) Rating (MVA)
c) Terminal Voltage (kV)
d) Rated Power Factor
e) Reactive Power capability (MVAr) in the range of
0.95 leading and 0.85 of lagging.
f) Short Circuit Ratio
g) Direct axis transient reactance (% on rated MVA)
h) Direct axis Sub-transient reactance (% on rated
MVA)
i) Auxiliary Power Requirement
4. Generating Unit –
Transformer
a) Type
b) Rated Capacity (MVA)
c) Voltage Ratio HV/LV
d) Tap change Range (+ % to - %)
e) On-load or off-load tap change
f) Percentage Impedance (Positive sequence at Full
load rating)
5C Detailed Planning Data (Generation)
5C.1 Thermal Power Stations
I. General:
1. Name of Power Station:
2. No. and capacity of Generating Units (MW):
3. Ratings of all major Equipment:

a) Boilers and Major accessories (Steam temperature/pressure)
b) Coal Mill (KW)
c) Feed water Pumps (KW)
d) Major Fans (KW)
e) Turbines
f) Alternators
g) Generating Unit Transformers (MVA)
h) Station Transformers
4. Auxiliary Transformers (MVA)
5. Single Line Diagram of Power Station and switchyard.
6. Relaying and metering diagram.
7. Neutral Grounding of Generating Units.
8. Excitation control (type - E.g. Static Excitation System, Fast Brushless)
9. Earthing arrangements with earth resistance values.
5C.2. Protection and Metering:
1. Full description including settings for all relays and protection systems installed on the
generating Unit, Generating Unit Transformer, Auxiliary Transformer and electrical motor
of major Equipment listed.
2. Full description including settings for all relays installed on all outgoing circuits from Power
Station substation switchyard, tie circuit breakers, incoming circuit breakers.
3. Full description of inter-tripping of Breakers at the point or points of Connection with the
4. Most probable fault clearance time for electrical faults on the User's system.
5. Full description of operational and commercial metering schemes.
5C.3 Switchyard:
1. In relation to interconnecting transformers between High Voltage Transmission System and
the Generating Unit:
a) Rated MVA
b) Voltage Ratio
c) Vector Group
d) Positive sequence reactance (maximum, minimum, normal Tap(% on MVA)
e) Positive sequence resistance (maximum, minimum, normal Tap (% on MVA)
f) Zero sequence reactance (% on MVA)
g) Tap changer Range (+ % to - %) and steps
h) Type of Tap changer (off-load/on-load)
2. In relation to switchgear including circuit breakers, isolators on all circuits connected to the
points of connection:
a) Rated Voltage (KV)

b) Type of Breaker (MOCB/ABCB/SF6)
c) Rated short circuit breaking current (kA) 3 Phase
d) Rated short circuit breaking current (kA) 1 Phase
e) Rated short circuit making current (kA) 3 Phase
f) Rated short circuit making current (kA) 1 Phase
g) Provisions of auto reclosing with details.
3. Lightning Arresters: technical data.
4. Communication- Details of PLC Equipment installed at points of connections.
5. Basic Insulation Level (kVp).
a) Busbar.
b) Switchgear.
c) Transformer Bushings.
d) Transformer windings.
5D. Generating Units: -
5D.1. Parameters of Generating Units:
1. Rated terminal voltage (KV)
2. Rated MVA
3. Rated MW
4. Inertia constant (MW Sec./MVA) of Generating Unit, Exciter and Turbine
5. Short circuit ratio
6. Direct axis synchronous reactance (% on MVA)
7. Direct axis transient reactance (% on MVA)
8. Direct axis sub-transient reactance (% on MVA)
9. Quadrature axis synchronous reactance (% on MVA)
10. Quadrature axis transient reactance (% on MVA)
11. Quadrature axis sub-transient reactance (% on MVA)
12. Direct axis transient open circuit time constant (Sec)
13. Direct axis sub-transient open circuit time constant (Sec)
14. Quadrature axis transient open circuit time constant (Sec)
15. Quadrature axis sub-transient open circuit time constant (Sec)
16. Stator Resistance (Ohm)
17. Stator leakage reactance (Ohm)
18. Stator time constant (Sec)
19. Rated Field current (A)

20. Open Circuit saturation characteristic for various terminal voltages giving the exciting current
to achieve the same.
21. Generating Unit Capability Chart
22. SCADA details
23. Communication details
5D.2 Parameters of Excitation control system:
1. Type of Excitation
2. Maximum Field voltage
3. Minimum Field voltage
4. Rated Field voltage
5. Gain Factor
6. Feedback Strength
7. Time constant for control amplifier
8. Time constant for Exciter
9. Time constant for Feedback
10. Output voltage of control amplifier
11. Maximum Output voltage of control amplifier
12. Minimum Output voltage of control amplifier
13. Details of excitation loop in Block Diagrams showing transfer functions of individual
elements using IEEE symbols along with set values.
14. Dynamic characteristics of over - excitation Limiter
15. Dynamic characteristics of under -excitation Limiter
Note: Using IEEE Committee Report symbols the following parameters shall be furnished: D,
A, BSx, Ka, Ke, Kf, Ta, Yf, Vr(max), Vr(min), Sa, Sb.
5E. Parameters of Governor:
1. Governor average gain (MW/Hz)
2. Speeder motor setting range
3. Time constant of steam or fuel Governor valve
4. Governor valve opening limits.
5. Governor valve rate limits.
6. Time constant of Turbine

7. Governor Block Diagram showing transfer functions of individual elements using IEEE
symbols along with set values.
5F. Plant Performance:
1. Daily Demand Profile (Last Year) Peak and Average in time
marked 30 minutes
throughout the day.
2. Daily Demand Profile (forecast) In time marked 30 minutes
throughout the day.
3. Units Generated (MWh)
4. Units consumed in Auxiliaries (MWh)
5. Units supplied from system to Auxiliary Load
6. Seasonal Generation
5G Operational Parameters:
1. Min. notice required for Synchronizing a Generating Unit.
2. Min. time between Synchronizing different Generating Units in a Power Station.
3. The minimum block load requirements on Synchronizing.
4. Time required for Synchronizing a Generating Unit for the following conditions:
a) Hot
b) Warm
c) Cold
5. Maximum Generating Unit loading rate for the following conditions:
a) Hot
b) Warm
c) Cold
6. Maximum Generating Unit deloading rate
7. Minimum on-load time
8. Minimum off-load time
9. Minimum load
10. Minimum load without oil support (MW)

11. Any staffing constraints (e.g. only day and evening shifts are employed so no overnight
operation)
5H Hydroelectric Stations:
I. General:
1. Name of Power Station:
2. No. and capacity of Units (MVA)
3. Expected level of Generation
4. Impeller type: only in exceptional circumstances will non-Kaplan machines be accepted on
the system.
5. Reserve capability: full details
6. Period of Generation (in months) per year
7. Whether the Plant is based on water released from dam/canal for irrigation purposes
8. Rating of all major Equipment.
a) Turbine (HP):
b) Generating Units (MVA):
c) Generating Unit Transformers (MVA):
d) Auxiliary Transformers (MVA):
9. Single Line Diagram of Power Station and switchyard.
10. Relaying and metering diagram.
a) Neutral grounding of Generating Unit.
b) Excitation control.
c) Earthing arrangements with earth resistance values.
11. SCADA details
II. Reservoir Data:
Salient features:
1. Type of Reservoir: Multipurpose/Power only
2. Operating Table with:
a) Area capacity curves,
b) Unit capability at different net heads,
c) FRL/MDDL.
III. Protection:

1. Full description including settings for all relays and protection systems installed on the
Generating units, Generating Unit transformer, Auxiliary transformer and electrical motor of
major Equipment {included}, but not limited to those listed under General.
2. Full description including settings for all relays installed on all outgoing feeders from Power
Station switchyard, tie breakers, and incoming breakers.
3. Full description of inter-tripping of breakers at the point or points of Connection with the
4. Most probable fault clearance time for electrical faults on the User's system.
IV. Switchyard:
1. Interconnecting Transformers:
a) Rated MVA
b) Voltage Ratio
c) Vector Group
d) Positive sequence reactance for maximum, minimum, normal Tap (% on MVA)
e) Positive sequence resistance of maximum, minimum, normal Tap (% on MVA).
f) Zero sequence reactance (% on MVA)
g) Tap changer Range (+ % to - %) and steps
h) Type of Tap changer (off-load/on-load)
2. Switchgear (including circuit breakers, Isolators on all circuits connected to the points of
connection):
a) Rated voltage (KV)
b) Type of Breaker (MOCB/ABCB/SF6)
c) Rated short circuit breaking current (KA) 3 Phase.
d) Rated short circuit breaking current (KA) 1 Phase.
e) Rated short circuit making current (KA) 3 Phase.
f) Rated short circuit making current (KA) 1 Phase.
g) Provisions of auto reclosing with details.
h) Details of Instrument Transformers.
3. Lightning Arresters, Technical data.
4. Communications: Details of communications Equipment installed at points of connections.
5. Basic Insulation level (KV):
a) Bus bar
b) Switchgear
c) Transformer Bushings
d) Transformer Windings
6. Generating Units:
i. Parameters of Generating Unit:

a) Rated terminal voltage (KV)
b) Rated MVA
c) Rated MW
d) Inertia constants (MW Sec./MVA) of Generating Unit, Exciter and Turbines
e) Short circuit ratio
f) Direct axis synchronous reactance. (% on MVA)
g) Direct axis transient reactance. (% on MVA)
h) Direct axis sub-transient reactance (% on MVA)
i) Quadrature axis synchronous reactance (% on MVA)
j) Quadrature axis sub-transient reactance (% on MVA)
k) Direct axis transient open circuit time constant (SEC)
l) Direct axis sub-transient open circuit time constant (SEC)
m) Stator Resistance (Ohm)
n) Stator leakage reactance (Ohm)
o) Stator time constant (Sec)
p) Rated Field current (A)
q) Open Circuit saturation characteristics of the Generating Unit for various terminal
voltages giving the compounding current to achieve this.
r) Generating Unit Capability Chart
ii. Type of Turbine:
a) Type:
b) Operating Head (Mtr.)
c) Discharge with Full Gate Opening (Cumecs)
d) Speed Rise on total Load throw off (%)
iii. Parameters of Excitation Control system
(AS APPLICABLE TO THERMAL POWER STATIONS)
iv. Parameters of Governor
(AS APPLICABLE TO THERMAL POWER STATIONS)
7. Operational parameters:
a) Minimum notice required for Synchronizing a Generating Unit.
b) Minimum time between Synchronizing different Generating Units in a Power Station.
c) Minimum block load requirements on Synchronizing.
d) Maximum and minimum flow rates
e) Equivalent maximum and minimum generation at various head levels
f) Any inter Generating Unit constraints.
5I Planning Data Generation
(For submission on request by Transmission Licensee)

5I.1 For Thermal Power Stations:
5I.1.1 General:
1. Detailed Project report.
2. Status Report:
a) Land
b) Fuel type
c) Cooling Method
d) Environmental clearance
e) Rehabilitation of displaced persons.
3. Approval by Nigeria Electricity Regulatory Commission
4. Financial tie-up in place.
5. Connection Agreement and Use of System Agreement in place
5I.1.2 Connection:
1. Report of studies of parallel operation with Transmission System:
a) Load flow studies
b) Stability studies
c) Short Circuit studies
2. Proposed connection with Transmission System:
a) Voltage
b) No. of circuits
c) Point of connection
5I.2. Hydroelectric Power Stations:
5I.2.1 General:
1. Detailed Project Report
2. Status Report
a) Topographical survey
b) Geological Survey
c) Land
d) Environmental clearance
e) Rehabilitation of displaced persons

3. Approval by Nigeria Electricity Regulatory Commission
4. Financial Tie-up in place.
5. Connection Agreement and Use of System Agreement in place
5I.2.2 Connection:
1. Reports of studies for parallel operation with TCN System.
a) Load flow studies
b) Short Circuit studies
c) Stability studies
2. Proposed Connection with Transmission System:
a) Voltage
b) No. of Circuits.
c) Point of connection.

6. APPENDIX 6 - DISTRIBUTION NETWORK DATA
(To be furnished by the Distributor to the TCN)
6A. Standard Planning Data: Distribution
To enable the TCN to discharge its responsibilities under its Transmission Licence Conditions by
conducting System Studies and preparation of perspective plans for Demand, Generation and
Transmission Network expansion as detailed under the Grid Code, all Users of the Transmission
Network shall furnish all the data to the TCN from time to time detailed below under Data
Registration Requirement of Sections 8 and 12.
Configurations of sites will vary hence the data requirements below are broadly phrased.
The interpretation of the requests for data is to be based on what the Distributor owns or has
necessary access to.
I. General:
1. Area map Marking on the map (to scale) of Distribution Licensee
franchise area in Nigeria.
2. Consumer Data Furnish categories of consumers, their numbers and
average connected loads
Where there are regional variations in the Distributor
area, details must be provided
II. Connection:
1. Points of connection: Furnish Single Line Diagram
showing points of connection to the
Transmission Network (Grid Supply
Points).
2. Voltage of supply at points of connection:
3. Names of Grid Sub-Station feeding the points of connection.
III. Lines and Sub-stations:

1. Line Data: Furnish length of line and voltages within the area.
2. Sub-station Data: Furnish details of 132/33 kV Sub-station, 33/11 KV,
Sub-stations, capacitor or reactor installations:
IV. Loads:
1. Loads drawn at points of connection:
2. Details of loads fed at
11kV or above:
Give name of consumer, voltage of supply,
contract demand and name of Grid Sub-station
from which line is drawn, length of line from Grid
Sub-station to consumer's premises.
V. Demand Data (For all Loads 1 MW and above):
1. Type of load: State whether furnace loads,
rolling mills, traction loads, other
industrial loads, pumping loads
etc.
2. Rated voltage:
3. Electrical loading of Equipment: State number and size of motors,
types of drive and control
arrangements.
4. Sensitivity of load to voltage and Frequency of supply:
5. Power Factor of load for night and day
6. Maximum harmonic content of load:
7. Average and maximum phase unbalance of load:
8. Nearest sub-station from which load is to be fed:
9. Location map to scale: Map shall show the location of
load with reference to lines and
sub-stations in the vicinity.
VI. Load Forecast Data:
1. Peak load and energy forecast for each category of loads for each of the succeeding 5 years.
2. Details of methodology and assumptions on which forecasts are based.

3. If supply is received from more than one sub-station, the sub-station breaks up of peak load
and energy projection for each category of loads for each of the succeeding 5 years along with
estimated daily load curve.
4. Details of load 1MW and above.
a) Name of prospective consumer.
b) Location and nature of load/complex.
c) Sub-station from which to be fed.
d) Voltage of supply.
e) Phasing of load.
6B. Detailed Planning Data: Distribution
6B.1 General:
1. Distribution map (To scale). Showing all lines up to 11 kV and sub-stations belonging to the
Licensee.
2. Single Line Diagram of distribution system (showing distribution lines from points of
connection with transmission system 132/33 kV Sub-station, 33/11 kV sub-station,
consumer bus if fed directly from Transmission System)
3. Numbering and nomenclature of lines and sub-stations (Identified with feeding Grid sub-
stations of the Transmission System and concerned 33/11 kV sub-station of supplier).
4. Monitoring Distribution Losses (Methods adopted for reduction of losses to be stated).
6B.2 Connection:
1. Points of connection (Furnish details of existing arrangement of Connection)
2. Details of metering at points of connection.
6B.3 Loads:
1. Connected Load (Category-wise) - Furnish consumer details, No. of consumers category-wise
details of loads 1 MW and above)
2. Information on diversity of load and coincidence factor.
3. Daily demand profile (current and forecast) on each 33kV/11kV sub-station.
4. Cumulative Demand Profile of Distribution (current and forecast)
6B.4 Detailed Planning Data: Distribution

(For submission on request by the TCN)
I. General:
1. Detailed Project Report (For new and system improvement schemes)
2. Status Report
(a) Load Survey
(b) Load forecast for next five years
3. Single Line Diagram showing proposed new lines and Sub-stations
II. Connection:
1. Points of connection as applied for
(a) New
(b) Upgrading existing connection
2. Changes in metering at points of connection
3. SCADA details
III. Loads:
1. Details of loads as per the forecast in next 5 years
2. Distribution of loads 33/11 kV Sub-station wise projected for next 5 years
3. Details of major loads of 1 MW and above to be contracted for next 5 years
IV. Improvement Schemes for reduction of Distribution Losses:
1. Statement of estimated Distribution losses for next five years
2. Brief indication of improvement scheme for reduction of losses (excerpts from Detailed
Project Report)
(a) New lines
(b) Upgrading of lines
(c) New Sub-station/Upgrading of Sub-stations
(d) Rearrangement of loads
(e) Installation of capacitors.

7. APPENDIX 7 – NETWORK EXPANSION PLANNING DATA
REQUIREMENTS:
To enable the TCN to discharge its responsibilities under its Transmission Licence by conducting
System Studies and preparation of plans for Demand, Generation and Transmission Network
expansion as detailed under the Grid Code, all Users of the Transmission Network shall furnish
all the data to the TCN from time to time detailed below under Data Registration Requirement
of Sections 8 and 12.
[In pursuance of Sections 8 and 12 of the Grid Code, items in this Appendix must be
included in the yearly 5 year planning study report of TCN and provided to Users (e.g.
Generating Companies, Discos) on an annual basis.]
7A. Standard Planning Data: Transmission
This is a list of planned circuits
Note: - The compilation of the data is currently the internal matter of the Licensee, and as such
the Licensee shall make arrangements for getting the required data from different Departments
of the Licensee to up-date its standard planning Data in the format given below:
1. Name of the line: (Indicating Power Stations and Sub-stations to be connected)
2. Voltage of line (KV):

3. No. of Circuits:
4. Route length (Circuit KM):
5. Conductor sizes:
6. Line parameters (PU on 100 MVA base
or ohmic values):
(a) Resistance/KM
(b) Series Inductive Reactance /KM
(c) Shunt Susceptance/KM
7. Approximate power flow MW & MVAr: MVAr at both ends
8. Terrain of route: Give information regarding nature
of terrain i.e., forestland, fallow
land, agricultural and river basin, hill
slope etc.
9. Route Map (to scale): Furnish topographical map showing
the proposed route showing existing
power lines and telecommunication
lines
10. Purpose of connection:
11. Approximate period of construction:
7B Detailed System Data: Transmission
7B.1 General:
(a) Single Line Diagram of the User’s system from 132 KV bus and above at grid sub-station:
(b) Name of sub-station
(c) Power Station connected
(d) Number and length of Circuits
(e) Interconnecting transformers
(f) Sub-station bus layouts
(g) Power Transformers
(h) Reactive compensation Equipment
1. The details of capacitors installed
2. Additional capacitors to be commissioned along with additional loads.
(i) Lightning Arresters
(j) Bus and/or Line Reactors

(k) Series Capacitors
7B.2 Sub-station layout diagrams showing:
(a) Bus bar layouts
(b) Electrical circuitry, lines, cables, transformers, switchgear etc.
(c) Phasing arrangements
(d) Earthing arrangements
(e) Switching facilities and interlocking arrangements
(f) Operating voltages
(g) Numbering and nomenclature
i. Transformers
ii. Circuits
iii. Circuit Breakers
iv. Isolating switches
7B.3.1 Line parameters: (For all Circuits)
(a) Designation of line
(b) Length of line (KM)
(c) No. of circuits, size, type and number of conductors, thermal rating
(d) Per Circuit values
i. Operating voltage (KV)
ii. Positive phase sequence reactance - ohms/KM
iii. Positive phase sequence resistance - ohms/KM
iv. Positive phase sequence susceptance - mhos/KM
v. Zero phase sequence reactance - ohms/KM
vi. Zero phase sequence resistance - ohms/KM
vii. Zero Phase sequence susceptance - mhos/KM
7B.3.2 Transformer parameters: (For all transformers)
(a) Rated MVA and sharing ratio if multiple voltage
(b) Voltage Ratio(s)
(c) Vector Group
(d) Positive sequence reactance on rated MVA base (Max., min. & normal)

(e) Positive sequence resistance on rated MVA base (max., min. & Normal)
(f) Zero sequence reactance on rated MVA base
(g) Tap change range (+% to -%) and steps
(h) Details of tap changer (off-load/on-load)
(i) Neutral Grounding Transformer/Resistor Values
7B.3.3 Equipment Details: (For all Sub-stations):
(a) Circuit Breakers
(b) Isolating switches
(c) Current Transformers
(d) Potential Transformers
(e) Lightning Arresters
7B.3.4 Relaying and metering:
(a) Relay protection installed for all transformers and Feeders along with their settings and level
of co-ordination with other Users.
(b) Metering Details:
(c) SCADA details
(d) Communication details
7B.4.1 Demand Data: (For all sub-stations)
(a) Demand Profile (Peak and lean load)
i. Current
ii. Forecast for next 5 years
7B.4.2 Reactive Compensation Equipment:
(a) Type of Equipment (fixed or variable)
(b) Capacities and/or inductive rating (Voltage and MVAr) or its operating range.
(c) Details of control
(d) Point of Connection to the system.

7B.5 Detailed Planning Data (Transmission)
(To be submitted by TSP upon request from the SO)
7B.5.1 General:
1. Detailed Project Report (For new and System Improvement Schemes)
2. Status Report
3. Line:
a) Route Survey
b) Forest Clearance
4. Sub-Stations
a) Land
b) Environmental Clearance
c) Financial Tie-up
7B.5.2 Connection:
1. Single Line Diagram showing position of connection
2. Sub-station layout diagram
a) New
b) Addition and Alteration
3. Changed parameters for revised system studies by SO
4. Point of Connection
a) Voltage
b) Length of circuit
c) Circuit parameters
d) PLC facilities
e) Relaying with inter tripping arrangements to inter trip system breaker at point of
connection to isolate on fault
f) Metering at point of connection.

8. APPENDIX 8: CIVIL EMERGENCIES
Upon the declaration of civil emergency affecting the production, transportation and/or
consumption of electrical power by competent authority in Nigeria, it is the obligation on
the TCN to prepare and maintain plans for mitigating the effects of any civil emergency
and fuel security situation, which may occur in accordance with the Electricity Supply
Emergency directive issued by the Industry Regulator. That directive shall describe the
steps which authority might take to deal with an electricity production and supply
emergency situation and sets down the actions which Companies in the Electricity Supply
Industry should plan to take and which may be needed or required in order to deal with
such an emergency.
In an electricity emergency it may become necessary to restrict User’s Demand for and
consumption of electricity and may be achieved by one or more of the following
methods:
a) Appeals by the Industry Regulator to the public for voluntary restraint
b) The issue of order(s) under competent Nigeria Authority requiring restrictions
on consumption by industry, commerce and other Users deem appropriate.
c) The issue of order(s) under competent Nigeria Authority requiring rotating
disconnections and associated restrictions.
In the event that the Industry Regulator issues directions to TCN to implement rotating
disconnections, the TCN will establish an Emergency Coordinating Centre and as soon as
possible establish communications with such relevant Users as is necessary to ensure
operational liaison. The plans to be implemented will be similar or separate from the
schemes outlined in Section 18 of the Grid Code.
The plans shall make provision for the need to maintain supply, so far as practicable, to
consumers in protected categories. For the purpose of the Grid Code Security
installations, Communication Facilities and Hospitals and other designated Facilities
deemed appropriate by competent Nigeria Authority shall be deemed to be protected
Facility in accordance with the provisions of the Civil Emergency Order.

9. APPENDIX 9: GRID CODE REVIEW PANEL
9.1 The Nigerian Electricity Regulatory Commission (NERC) shall establish the Grid Code
Review Panel. The Panel shall be responsible for developing and improving the Code through
regular review, consultation, research and the consideration of amendment submissions by Users,
TSP, SO or other interested parties and other methodologies deemed appropriate from time to
time. The funding and maintenance of the Panel shall be the responsibility of the SO, including
the location of the Panel’s secretariat.
The Panel shall be a standing body to carry out the functions referred to in paragraph 9.2.
9.2 The Grid Code Review Panel shall:
i. keep the Grid Code and its working under review;
ii. review all amendments to the Grid Code which NERC or any User or TCN may wish to
submit for consideration by the Panel from time to time;
iii. publish recommendations as to amendments to the Grid Code that TCN or the Panel
feels are necessary or desirable and the reasons for the recommendations;
iv. issue guidance in relation to the Grid Code and its implementation, performance and
interpretation when asked to do so by any User;
v. consider what changes are necessary to the Grid Code arising out of any unforeseen
circumstances referred to it by TCN; and
vi. consider and identify changes to the Grid Code to remove unnecessary Section(s) or
clause(s) that are of irrelevant to the effective operation of the Nigeria Power System.
9.3 The Panel shall consist of:
i. the Head of System Operations shall be Chairman;
ii. 4 members appointed by TCN from Network , System , Market and Safety Operations of
TCN;
iii. a person appointed by the Nigerian Electricity Regulatory Commission; and
iv. 3 persons representing Generating Companies one of which must represent hydro Power
Stations;
v. 3 persons representing the Distribution Companies;
vi. a person representing the Rural Electrification Agency;
vii. a person representing Directly Connected Customers and also Customers with a
maximum demand greater than or equal to 1MW; and
viii. a person representing the Nigerian Bulk Electricity Trader.
Each of the Panel members shall be appointed by their respective industry sector
pursuant to the rules issued by the Panel in 9.4.

9.4 The Panel shall establish and comply at all times with its own rules and procedures
relating to the conduct of its business, which shall be approved by NERC. Meetings of the Panel
shall be held at regular intervals and at least every month at such time and place as the Panel shall
decide.
9.5 The Panel shall consult in writing all Industry Stakeholders and Operators which are liable
to be affected in relation to all submitted amendments to the Grid Code and shall review and
discuss all submitted amendments and comments to the Grid Code prior to coming up with
recommendations to amending the Grid Code. The Panel however has the right to treat an
amendment as frivolous in accordance with the Market Rules.
9.6 The Panel through TCN shall establish (and, where appropriate, revise from time to time)
joint working arrangements with industry stakeholders or operators to facilitate the identification,
coordination and implementation of change to their operations consequent on an amendment to
the Grid Code in a full and timely manner. These working arrangements shall be such as to
enable development and evaluation of proposed amendments to the Grid Code, how operators
will proceed in a full and timely manner to changes to their operations consequent to an
amendment to the Grid Code to be made and given effect wherever possible (subject to any
necessary consent of the Nigerian Electricity Regulatory Commission) at the same time as such
approved amendment is made and given effect.

Grid code 2014

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