Operation Handbook. June union for the co-ordination of transmission of electricity

Transcription

1 Operation Handbook June 2004 union for the co-ordination of transmission of electricity

2 INTRODUCTION

3 I Introduction to the UCTE Operation Handbook (OH) [E] Chapters A. UCTE s basic needs for the Operation Handbook B. Target audience for the Operation Handbook C. Main characteristics of the Operation Handbook D. Main scope of the Operation Handbook E. Basic structure of the Operation Handbook F. Guide for handbook readers G. Procedure for handbook development H. Table of handbook policies and appendices I. UCTE system overview J. Contacts and links History of changes v2.5 draft UCTE Secretariat minor changes, OH development procedure update v2.4 draft OH Team minor changes Current status The "Union for the Co-ordination of Transmission of Electricity" (UCTE) is the association of transmission system operators in continental Europe, providing a reliable market base by efficient and secure electric "power highways". The UCTE (up to the 30 th of June 1999 named UCPTE) has created a Survey of essential UCPTE recommendations for the interconnected operation (dated 31 st of December 1991) and important additional rules and recommendations on specific subjects after that date. Up to now (and if not already replaced by the Operation Handbook) these documents have been in force in the UCTE. The UCTE Operation Handbook (OH) is an up-to-date collection of operation principles and rules for the transmission system operators in continental Europe. Additional references to UCTE operation and security rules and recommendations as well as a list of publications, public statistics and information about the members, organisation, structure and activities of the UCTE in general can be found on the UCTE Web site:! This introduction is the cover paper for the operation handbook policies and appendices. It includes a general overview, the main characteristics and scopes of the handbook, a description of the handbook structure with the table of contents as well as guides and descriptions for readers. The glossary of terms is provided in a separate paper. This version of the document (version 2.5, level E, dated ) has final status 1. This document and other chapters of the UCTE Operation Handbook as well as excerpts from it may not be published, redistributed or modified in any technical means or used for any other purpose outside of UCTE without written permission in advance. 1 : The version numbers of handbook documents currently reflect the developments only. As soon as a document is approved and enforced for the first time, the version number may change.

4 UCTE Operation Handbook Introduction (final v2.5 E, ) "I 2 A. UCTE s basic needs for the Operation Handbook [Union for the Co-ordination of Transmission of Electricity Articles of Association, 2000] The Union for the Co-ordination of Transmission of Electricity (UCTE) co-ordinates the operational activities of transmission system operators in 22 European countries. Their common objective is the security of operation of the interconnected power system. 50 years of joint activities laid the basis for a leading position in the world which the UCTE holds in terms of the quality of synchronous operation of interconnected power systems. Through the networks of the UCTE, 450 million people are supplied with electric energy; annual electricity consumption totals approx TWh. Close co-operation of member companies is required to make the best possible use of benefits offered by interconnected operation. For this reason, the UCTE has developed a number of technical and organisational rules and recommendations in the past that constitute a common reference for smooth operation of the power system. The UCTE Operation Handbook is the successor to these sets of rules and recommendations, that have been continually developed during the decades of construction and extension of the power system since 1950, reflecting the changes in the technical and political framework. Only the consistent maintenance of the high demands on quality will permit in the future to set standards in terms of security and reliability as in the past. Moreover, the strong interconnections in the UCTE grid require common understandings for grid operation, control and security in terms of fixed technical standards and procedures. They are comprised in this UCTE Operation Handbook in an organised form to make consultation easier for members and the general public.

5 UCTE Operation Handbook Introduction (final v2.5 E, ) "I 3 C. UCTE System Overview For the sake of general information and orientation, the following figures show maps of the UCTE system in the overview: the map of the complete UCTE interconnected network / transmission system of 2003 (available from UCTE at!

6 UCTE Operation Handbook Introduction (final v2.5 E, )!I 4 the political map (by countries, membership, connection status) of the UCTE SYNCHRONOUS ZONES as of 2004, the structure and organisation of the CONTROL BLOCKS /AREAS of the UCTE SYNCHRONOUS AREA by countries/companies NL B D RWE CEGEDEL E.ON VEAG D EnBW VKW VE-T BEWAG TIRAG CENTREL PL CZ UCTE Acc. Acc. Area FEP SK F CH A H RO BG E P 7 UKR MOR I SLO HR BIH CG JIEL EKC UCTE South SR AL MK GR

7 UCTE Operation Handbook Introduction (final v2.5 E, ) "I 5 B. Target audience for the Operation Handbook The UCTE Operation Handbook shall support consultation and provide assistance to different parties in issues of system operation, such as to Transmission System Operators (TSOs) / Grid Operators, Co-ordination Centres. Every TSO in the UCTE interconnected network (SYNCHRONOUS AREAS) has declared to follow the technical standards and procedures that are comprised in this UCTE Operation Handbook (main focus of the handbook). This Operation Handbook therefore serves as the reference ( legislation ) for the grid operation by the TSOs and guarantees the UCTE s quality and reliability standards. Generation Companies (GENCOs). Every party operating a generating unit in the UCTE interconnected network (SYNCHRONOUS AREAS) makes use of the transmission network and may have to deliver products for the provision of system services that are indispensable for secure and stable grid operation. The Operation Handbook sets standards for the essential requirements and capabilities regarding generation that contribute to the operation of the grid by the TSOs. Other associations, traders, customers, politicians and decision makers. Operation of an interconnected transmission system is bound to physical principles and technical constraints, that differ significantly from other well-known technical or financial systems. This Operation Handbook explains these differences and characteristics in a transparent manner to the public for a better understanding. It can also serve as a general reference document.

8 UCTE Operation Handbook Introduction (final v2.5 E, ) "I 6 D. Main characteristics of the Operation Handbook The following main characteristics of the UCTE Operation Handbook serve as a guideline for the development and set-up of the handbook: Transparency. Technical and physical principles of transmission grid operation in the UCTE are clearly described and published in the Operation Handbook also for nonexperts. Liability. Following the Articles of Association of the UCTE, as they have been signed by all members, the standards and recommendations of the Operation Handbook were developed as binding for all members (including associated members) of the UCTE and their operation of the grid. Unambiguousness. All standards and recommendations of the Operation Handbook are written to be straightforward and unmistakable for the processes of secure operation of the UCTE SYNCHRONOUS AREA(S). All terms used in the handbook are defined only once. Relevance to the present. Standards and recommendations included in the Operation Handbook are continually adapted to the changed technical and legislative environment. A version history clearly shows the status of each part of the handbook. Minor Redundancy. The Operation Handbook is written to have only the minimum of redundancy that is required. For this purpose, references to other chapters within the handbook are used instead. Modularity. Each chapter, policy, rule and guideline of the Operation Handbook can be seen as a separate document that may be revised independently of the other parts. All chapters use a similar layout and internal structure.

9 UCTE Operation Handbook Introduction (final v2.5 E, ) "I 7 E. Main scope of the Operation Handbook The main objective of the UCTE Operation Handbook as a comprehensive collection of all relevant technical standards and recommendations is to provide support to the technical operation of the UCTE interconnected grid (SYNCHRONOUS AREAS), including operation policies for generation control, performance monitoring and reporting, reserves, security criteria and special operational measures. The basic subject of the Operation Handbook is to ensure the interoperability among all TSOs connected to the SYNCHRONOUS AREAS. Standards for network access of customers, network tariffs, accounting, the commercial part of unintentional deviations, billing procedures and market rules as well as other standards that may be set by national GridCodes, laws or contracts are not within the scope of this Operation Handbook (see next figure). UCTE Interconnected Network Transmission and Distribution Network UCTE Operation Handbook! Rules for Interconnection GridCodes / Laws / Contracts! Rules for Grid Access...

10 UCTE Operation Handbook Introduction (final v2.5 E, ) "I 8 F. Basic structure of the Operation Handbook The UCTE Operation Handbook clearly differentiates between policies, technical appendices, training documents and data collections (in independent documents) and is basically structured as follows: Preface, general information (UCTE history, organisation,...) Introduction, overview, table of contents, versions, basics, operational framework, procedures Glossary of terms, acronyms Operating policies (common structure, list of policies for transmission and ANCILLARY SERVICES) Technical appendices (technical criteria, definitions) Training documents (calculation methods, theory) Collections of data The formal structure of the operation handbook into policies and appendices, each document with chapters and sections, is shown in the following figure. UCTE Operation Handbook Policy x Chapter y Sections z Appendix x Chapter y Sections w The policies themselves have a clear policy-internal structure of standards, rules, criteria, requirements, rights and obligations. The table of all policies can be found in section #I. The policies of the operation handbook themselves are organised in the following main sections: Criteria (C). Criteria introduce or define specific values or a specific naming as given facts, that may be used or cited within the policy. Requirements (R). Requirements are (technical or organisational) prerequisites that are used within a policy. They have to be fulfilled in total before any standard can be applied. Standards (S). Standards define rules that are fixed and binding for the addressees, subject to the specific situation. Standards are usually the core part of a policy. Guidelines (G). Guidelines describe practical ways for typical operation or usage as recommendations, as they may be used by the addressees. Procedures (P). Procedures introduce fixed methods and alternatives for operation or usage as common practice. Measures (M). Measures name the actions to be taken, e.g. if a requirement is not fulfilled, a standard is violated by an addressee or a procedure is not used.

11 UCTE Operation Handbook Introduction (final v2.5 E, ) "I 9 G. Guide for handbook readers The operation handbook makes use of the following internal reference schemes: $document [-chapter [-section]] #chapter [-section] "document page The following examples show how to read the references in the documents: $P1 and $A1 are used as references to the policy or appendix with number 1. Other documents are usually referred to by a single letter, e.g. the introduction by $I. $P1-A is used as reference to the chapter A of Policy 1 (within Policy 1 the reference can also be #A only). $P1-A-C1 is used as reference to the first criterion of section A in policy 1. The same scheme is used for requirements, standards, guidelines, procedures and measures. Pages are numbered by the document identifier ( P1 for Policy 1) followed by the page number, e.g. "P1-8 is the reference to page 8 of Policy 1. According to the basic structure of the UCTE Operation Handbook, the following rough guide for readers can be given: As a good starting point, it is recommended to start reading with this introduction document ($I). Basic principles and frameworks for the complete handbook are described here in detail. Moreover, the introduction includes the full table of operation policies that are part of the handbook. The glossary of terms ($G) needs to be consulted as a reference only. All terms that are formatted in CAPITALISED letters can be found in the glossary of terms. In case of unknown terms, acronyms or units please refer here for definitions and explanations. For reading a policy (policies are numbered by #) it is recommended to start with the introduction of the policy and to consult the corresponding appendices ($A#), before reading the requirements, standards and guidelines. The appendices usually give a general motivation and technical description of the subjects, that is required for reading the policies. The policies themselves ($P#) are organised in independent chapters (starting with A), each of them in sections (identified by letters C, R, S, G, P and M, see above) with numbered paragraphs. Before reading and understanding a policy it is necessary to have background knowledge on the subjects. There is no definite way how to read a policy, usually it is best to start at the beginning. Internal references may point to other paragraphs of this policy before or after the current paragraph, external references may point to other policies or appendices as well. For easy reading, the first pages of policies and appendices are commonly organised in the following layout:

12 UCTE Operation Handbook Introduction (final v2.5 E, ) "I 10 P# Policy #: Title [Level] Chapters A. Chapter A B. Chapter B C. Chapter C Introduction Introduction History of changes v#.# draft developer changes Current Status Status information General notices

13 UCTE Operation Handbook Introduction (final v2.5 E, ) "I 11 H. Procedure for handbook development Following is the description of the development process procedure with the flow chart showing the procedure. The Operation Handbook development process involves following steps: 1. Process initiation 2. Drafting stage 3. Internal consultation 4. Decisions on external consultation 5. External consultation 6. Final approval 7. Policy implementation STEP 1 Process initiation Requests to revise or develop the Policy are submitted to the Steering Committee by the Working Group Operations and Security (WG OS) with a short description of the Policy to be revised or drafted newly. Alternatively, the process is initiated by the Steering Committee. The Steering Committee approves the Policy for development or revision or rejects the request. For each Policy Steering Committee sets a clear deadline for the drafting and revision stage of the process. STEP 2 Drafting stage Once the Policy is accepted for development or revision the WG OS then assigns the request to a Drafting Team which prepares the table of contents and a 1st draft of new or revised Policy. Then the Drafting Team presents the 1st draft for internal consultation. STEP 3 Internal consultation Comments on the 1st draft will be solicited only from UCTE Members (TSOs). Comments can be sent only by using consultation forum on the UCTE website till the date announced by UCTE Secretariat. The minimum period for internal consultation is 1 month. Based on the comments, the Drafting Team prepares the 2nd draft of the Policy. STEP 4 Decisions on external consultation The 2nd draft is the subject of WG OS and corresponding Steering Committee approval for presenting it for external consultation. The bodies can approve the draft Policy for the external consultation or return it for further work to the Drafting Team with a clear statement on how to proceed and what to adapt. STEP 5 External consultation Once the Policy is approved by the Steering Committee for the external consultation, it is published on the UCTE website and the external consultation process starts. The consultation period lasts 4-8 weeks with respect to the extent of the Policy. Duration of the consultation process will be determined by the WG OS or UCTE Secretariat. Comments on the 2nd draft will be actively solicited from all registered participants. Comments will be accepted only on-line using an internet-based consultation forum. All UCTE members will have to substantiate their position, i.e. that also those who do not want to comment will have

14 UCTE Operation Handbook Introduction (final v2.5 E, ) "I 12 to state it. Based on its own review, the Drafting Team revises the draft Policy as needed and presents it to the WG OS. STEP 6 Final approval WG OS approves the Policy and sends the final draft including change marks and for information list of rejected comments to the Steering Committee for final approval. If the WG OS does not approve the Policy, it may return the draft to the Drafting Team for further work with a clear statement on how to proceed and what to adapt. As a rule, the Steering Committee will put the proposed Policy at its next meeting s agenda. If the Policy is not approved, the Steering Committee may return the Policy to the Drafting Team for further work with a clear statement on what to adapt or it may terminate the Policy development. STEP 7 Policy implementation Once the Steering Committee approves a new or modified Policy all members are expected to implement and follow the Policy in accordance with all accepted UCTE rule.

15 UCTE Operation Handbook Introduction (final v2.5 E, ) "I 13 Requests, modifications WG Operations & Security STEP 1 Decision Requests, modifications UCTE Steering Committee Decision Rejection For development STEP 2 STEP 3 Table of contents / topics [A] Development 1st Draft of new Standard [B] Drafting Team Internal consultation UCTE Secretariat&Drafting Team 2nd Draft of new Standard [C] WG Operations & Security Revision Decision STEP 4 STEP 5 2nd Draft of new Standard [C] UCTE Steering Committee Revision Decision Rejection For external consultation External consultation UCTE Secretariat&Drafting Team Final Draft of new Standard [D] WG Operations & Security STEP 6 Decision Final Draft of new Standard [D] UCTE Steering Committee STEP 7 Revision Decision For implementation Final new UCTE Standard [E] UCTE Operation Handbook

16 UCTE Operation Handbook Introduction (final v2.5 E, ) "I 14 The status of policies and appendices during procedure is rated according to the following legend: Level A B C D E Description Table of contents Preliminary internal draft Consultation draft Final draft ready for approval by the WG and SC Approved new UCTE Standard. Process roles: Steering Committee is the executive directing body of UCTE: It: approves the Policy for development approves the 2nd draft for external consultation makes a final approval of the Policy Working Group Operations&Security is the body responsible for overseeing the Operation Handbook development process. It: initiates the process of Policies development or revision assigns the Drafting Team and nominates the DT leader sets deadlines for development, revision and consultation periods actively participate in the internal and external consultation process approves and presents the 2nd draft to SC for approval for external consultation approves the final draft and presents it for SC final approval Drafting Team is a team of technical experts that develops the detail of the Policy. It: prepares the table of contents and first draft of the Policy presents the draft for internal consultation considers and responds to comments (with UCTE Secretariat support) revise the draft after internal consultation presents the draft to WG OS for approval for external consultation revise the draft after external consultation UCTE Secretariat administers the OH development process. It: " ensures the integrity of the development process " ensures consistency of quality and completeness of the OH " structures the consultation process " monitors and guide the web-based consultation forum " publish documents (including layouting according to corporate identity) " supports the Drafting Teams " reports to WG OS on the development progress

17 UCTE Operation Handbook Introduction (final v2.5 E, ) "I 15 I. Table of Handbook Policies and Appendices The following tables of contents list all existing and planned policies /appendices / documents of the UCTE Operation Handbook with their individual table of contents. General part: ID I G Title, contents Introduction A. UCTE s basic needs for the Operation Handbook B. Target audience for the Operation Handbook C. Main characteristics of the Operation Handbook D. Main scope of the Operation Handbook E. Basic structure of the Operation Handbook F. Guide for handbook readers G. Procedure for handbook development H. Table of handbook policies and appendices I. UCTE system overview J. Contacts and links Glossary A. Glossary of Terms B. List of Acronyms C. List of Units Policies: ID Title, contents P1 Load-Frequency-Control and Performance A. Primary Control B. Secondary Control C. Tertiary Control D. Time Control E. Measures for Emergency Conditions P2 Scheduling and Accounting A. Scheduling B. Online Observation C. Accounting P3 Operational Security A. N-1 Security (operational planning and real-time operation) B. Voltage control and reactive power management C. Network faults clearing and short circuit currents D. Stability E. Outages scheduling F. Information exchanges between TSOs for security of system operation P4 Co-ordinated Operational Planning A. Outage Scheduling

18 UCTE Operation Handbook Introduction (final v2.5 E, ) "I 16 B. Capacity Assessment C. Capacity Allocation D. Day Ahead Congestion Forecast E. Congestion Management P5 Emergency Procedures P6 Communication Infrastructure A. The EH Network, Architecture and Operation B. Real Time Data Collection and Exchange C. File Transfer data Exchange D. on the Electronic Highway E. Information Publication in Hyptertext on EH F. Procedures for future Services on EH G. Non-EH communication among TSOs P7 Data Exchanges A. Code of conduct and generic rules to handle the data P8 Operational Training Appendixes: ID A1 A2 Title, contents Load-Frequency-Control and Performance A. Primary Control B. Secondary Control C. Tertiary Control D. Time Control E. Measures for Emergency Conditions Scheduling and Accounting A. Scheduling of Power Exchange B. Online Observation of Power Exchange C. Accounting of Unintentional Deviations

19 UCTE Operation Handbook Introduction (final v2.5 E, ) "I 17 J. Contacts and Links For questions concerning Operation Handbook development process and consultation process please contact Jakub Fijalkowski at For all other information, please contact the UCTE-Secretariat: 15 Boulevard Saint-Michel 1040 Brussels Belgium Tel: Fax: info@ucte.org

20 GLOSSARY

21 G Glossary [E] Chapters A. Glossary of terms B. List of acronyms C. List of units History of changes v2.2 draft UCTE Secreteriat glossary update v2.1 draft UCTE Secretariat new terms added v2.0 draft OpHB-Team minor changes, linguistic review Current status This glossary is a growing list of terms 1, acronyms and units commonly used in the policies and appendices of the Operation Handbook. In order to identify common terms of this glossary when used in any document, all terms listed in this glossary shall be formatted in a CAPITALISED manner (but not written in capital letters). This version of the document (version 2.2, level E, dated ) has final status. This document and other chapters of the UCTE Operation Handbook as well as excerpts from it may not be published, redistributed or modified in any technical means or used for any other purpose outside of UCTE without written permission in advance. 1 : Additional terms to be included shall be submitted to the UCTE secretariat (!Jakub.Fijalkowski@ucte.org) or to the secretary of the UCTE WG Operations & Security (!jens.albrecht@rwe.com).

22 UCTE Operation Handbook Glossary (final v2.2 E, )!G 2 A. Glossary of terms [UCTE ground rule for the co-ordination of the accounting and the organisation of the load-frequency control, 1999] [Articles of association of the UCTE, 2001] [NERC glossary of terms, , ETSO Definitions of Transfer Capacities in liberalised Electricity Markets, 2001] Term (Acronym) {Synonym} ("References) Definition / explanation, CROSS-REFERENCE. Accounting {Energy ~, ~ of Unintentional Deviations} ("P2) After the EXCHANGE PROGRAMS have been validated during the scheduling phase, and taking into account the real-time observation of UNINTENTIONAL DEVIATIONS across a set of OBSERVATION LINES, ACCOUNTING is the organisational process implemented in order to: collect the provisional and the final values of the exchanged energy for each time interval; determine the UNINTENTIONAL DEVIATIONS of energy and set-up the corresponding COMPENSATION PROGRAMS for their offsetting during the following week. Accounting Co-ordination ("P2) ACCOUNTING CO-ORDINATION means a co-ordination service provided to the CONTROL BLOCKS, by the sites in charge of performing the ACCOUNTING CO-ORDINATION for the purpose of carrying out the ACCOUNTING. It consists of the following phases: acquisition and validation of the EXCHANGE PROGRAMS between the CONTROL BLOCKS during the scheduling phase; acquisition of the EMRs values of TIE-LINES 2 among CONTROL BLOCKS to compute the provisional energy exchanges; real-time observation across the previously defined OBSERVATION LINES; computation of the provisional and final UNINTENTIONAL DEVIATIONS; computation of the COMPENSATION PROGRAMS for each CONTROL BLOCK. If these tasks are performed at different locations, a very close co-operation must be ensured among the centres responsible for these activities. Responsibility for correct ACCOUNTING remains with the co-ordinators of the individual CONTROL BLOCKS and CONTROL AREAS. Responsibility for this matter cannot be delegated to the ACCOUNTING CO- ORDINATION. The CONTROL BLOCKS and CONTROL AREAS are responsible for the resources required to provide the results of the ACCOUNTING. In order to be able to monitor and supervise the operation of their CONTROL BLOCK or CONTROL AREA, they all need to be equipped with a real-time data acquisition system. The ACCOUNTING CO-ORDINATION is provided with the necessary data to enable some checking at a global level and to give extra confirmation to the co-ordinators of the CONTROL BLOCKS and CONTROL AREAS that no major mistake has gone undetected or that, if such an error should occur, it would not stay undetected for a long time. Active Power ACTIVE POWER is a real component of the apparent power, usually expressed in kilowatts (kw) or megawatts (MW), in contrast to REACTIVE POWER. 2 Including virtual TIE-LINES that may exist for the operation of jointly owned power plants.

23 UCTE Operation Handbook Glossary (final v2.2 E, )!G 3 Adjacent Control Area {Adjacent System} ("P1-B) An ADJACENT CONTROL AREA (or ADJACENT SYSTEM) is any CONTROL AREA (or system) either directly interconnected with or electrically close to (so as to be significantly affected by the existence of) another CONTROL AREA (or system). Ancillary Services ("P1) ANCILLARY SERVICES are Interconnected Operations Services identified as necessary to effect a transfer of electricity between purchasing and selling entities (TRANSMISSION) and which a provider of TRANSMISSION services must include in an open access transmission tariff. Apparent Power APPARENT POWER is the product of voltage (in volts) and current (in amperes). It consists of a real component (ACTIVE POWER) and an imaginary component (REACTIVE POWER), usually expressed in kilovolt-amperes (kva) or megavolt-amperes (MVA). Already Allocated Capacity (AAC) The ALREADY ALLOCATED CAPACITY is the total amount of allocated transmission rights, whether they are capacity or EXCHANGE PROGRAMS depending on the allocation method. Area Control Error (ACE) ("P1-B) The AREA CONTROL ERROR is the instantaneous difference between the actual and the reference value (measured total power value and scheduled CONTROL PROGRAM) for the power interchange of a CONTROL AREA (UNINTENTIONAL DEVIATION), taking into account the effect of the FREQUENCY BIAS for that CONTROL AREA according to the NETWORK POWER FREQUENCY CHARACTERISTIC of that CONTROL AREA and the overall FREQUENCY DEVIATION. Automatic Generation Control (AGC) ("P1-B) AUTOMATIC GENERATION CONTROL is an equipment that automatically adjusts the generation to maintain its generation dispatch, interchange schedule plus its share of frequency regulation. AGC is a combination of SECONDARY CONTROL for a CONTROL AREA / BLOCK and real-time operation of the generation dispatch function (based on generation scheduling). SECONDARY CONTROL is operated by the TSO, generation scheduling is operated by the respective generation companies (GENCOs). Availability AVAILABILITY is a measure of time during which a generating unit, transmission line, ANCILLARY SERVICE or another facility is capable of providing service, whether or not it actually is in service. Typically, this measure is expressed as a percentage available for the period under consideration. Available Transfer Capacity (ATC) AVAILABLE TRANSFER CAPACITY is a measure of the transfer capability remaining in the physical TRANSMISSION network for further commercial activity over and above already committed uses. AVAILABLE TRANSMISSION CAPACITY is the part of NTC that remains available after each phase of the allocation procedure for further commercial activity. ATC is defined by the following equation: ATC = NTC- AAC

24 UCTE Operation Handbook Glossary (final v2.2 E, )!G 4 Black-start Capability ("P3, "P5) BLACK-START CAPABILITY is the ability of a generating unit to go from a shutdown condition to an operating condition and start delivering power without assistance from the electric system. Capacity CAPACITY is the rated continuous load-carrying ability of generation, transmission, or other electrical equipment, expressed in megawatts (MW) for ACTIVE POWER or megavolt-amperes (MVA) for APPARENT POWER. Compensation program Compensation of UNINTENTIONAL DEVIATIONS is performed by exporting to / importing from the interconnected system during the compensation period by means of schedules of constant power within the same tariff periods as when they occurred (COMP). Consumption See: DEMAND Contingency ("P3) CONTINGENCY is the unexpected failure or outage of a system component, such as a generator, transmission line, circuit breaker, switch, or other electrical element. A CONTINGENCY also may include multiple components, which are related by situations leading to simultaneous component outages. Control Area (CA) ("P1-B) A CONTROL AREA is a coherent part of the UCTE INTERCONNECTED SYSTEM (usually coincident with the territory of a company, a country or a geographical area, physically demarcated by the position of points for measurement of the interchanged power and energy to the remaining interconnected network), operated by a single TSO, with physical loads and controllable generation units connected within the CONTROL AREA. A CONTROL AREA may be a coherent part of a CONTROL BLOCK that has its own subordinate control in the hierarchy of SECONDARY CONTROL. Control Block (CB) ("P1-B) A CONTROL BLOCK comprises one or more CONTROL AREAS, working together in the SECONDARY CONTROL function, with respect to the other CONTROL BLOCKS of the SYNCHRONOUS AREA it belongs to. Control Area Operator A CONTROL AREA OPERATOR is the operator of a CONTROL AREA usually a TSO. ("P2) Control Block Operator The BLOCK OPERATOR is a single TSO that is responsible for SECONDARY CONTROL of the whole CONTROL BLOCK towards its interconnected neighbours / blocks, for ACCOUNTING of all CONTROL AREAS of that block, for organisation of the internal SECONDARY CONTROL within the block, and that operates the overall control of that block. ("P2)

25 UCTE Operation Handbook Glossary (final v2.2 E, )!G 5 Control Program (CP) ("P1-B, "P2) A CONTROL PROGRAM constitutes the SCHEDULE of the total programmed exchange of a CONTROL AREA / BLOCK, the sum of all EXCHANGE PROGRAMS and the COMPENSATION PROGRAM, that is used for SECONDARY CONTROL. Co-ordination centre (CC) The CO-ORDINATION CENTRE is responsible for acquiring and validating the EXCHANGE PROGRAMMES among the CONTROL BLOCKS during the scheduling phase, acquiring the energy meter readings values of TIE-LINES among the CONTROL BLOCKS to compute the UNINTENTIONAL DEVIATIONS and the COMPENSATION PROGRAM to be carried out the following week in order to offset said UNINTENTIONAL DEVIATIONS. This task is shared among the CO-ORDINATION CENTRES UCTE North in Brauweiler and UCTE South in Laufenburg. Curtailment CURTAILMENT means a reduction in the scheduled capacity or energy delivery. Defence Plan The DEFENCE PLAN summarises all technical and organisational measures taken to prevent the propagation or deterioration of a power system incident in order to avoid a collapse. ("P5) Demand {Consumption} DEMAND is the rate at which electric power is delivered to or by a system or part of a system, generally expressed in kilowatts (kw) or megawatts (MW), at a given instant or averaged over any designated interval of time. DEMAND should not be confused with LOAD (a LOAD is usually a device). Disturbance DISTURBANCE is an unplanned event that produces an abnormal system condition. Droop of a Generator ("P1-A, "A1-A) The DROOP OF A GENERATOR is one of the parameters set on the primary speed controller of a GENERATING SET (generator and turbine). It is equal to the quotient of the relative quasi-steady-state FREQUENCY OFFSET on the network and the relative variation in power output from the generator associated with the action of the PRIMARY CONTROLLER. This ratio without dimension is generally expressed as a percentage. Electrical Energy ELECTRICAL ENERGY is a measure of the generation or use of electric power by a device integrated over a period of time; it is expressed in kilowatt-hours (kwh), megawatt-hours (MWh), or gigawatt-hours (GWh). Electric System Losses ELECTRIC SYSTEM LOSSES are total electric energy losses in the electric system. The losses consist of TRANSMISSION, transformation, and distribution losses between supply sources and delivery points. Electric energy is lost primarily due to heating of transmission and distribution elements.

26 UCTE Operation Handbook Glossary (final v2.2 E, )!G 6 Electronic Highway (EH) The ELECTRONIC HIGHWAY represents a secure, fast, reliable and highly available communication infrastructure for real-time and non-real-time data exchanges between TSOs. Energy Meter Readings (EMRs) ("P6) ("P2) ENERGY METER READINGS are performed (in addition to those for internal lines, transformers, generators and LOADS) for actual energy exchanges on TIE-LINES 3 between CONTROL BLOCKS (of CONTROL AREAS) to carry out the ACCOUNTING function (e.g.: to compute, together with scheduled exchanges, the UNINTENTIONAL DEVIATIONS for each time interval). Exchange Program (CAX, CBX) ("P2) An EXCHANGE PROGRAM represents the total scheduled energy interchange between two CONTROL AREAS (CAX) OR BETWEEN CONTROL BLOCKS (CBX). Exchange Schedule (CAS, CBS) ("P2) An EXCHANGE SCHEDULE defines an agreed transaction with regard to its size (megawatts), start and end time, RAMP PERIOD and type (e.g. firmness); it is required for delivery and receipt of power and energy between the contracting parties and the CONTROL AREA(S) (CAS) or between control areas and control blocks (CBS) involved in the transaction. Frequency see: SYSTEM FREQUENCY Frequency Bias see: NETWORK POWER FREQUENCY CHARACTERISTIC Frequency Control See: PRIMARY CONTROL. Frequency Deviation FREQUENCY DEVIATION means a departure of the actual SYSTEM FREQUENCY from the set value frequency. ("P1) Frequency Offset ("P1-D) FREQUENCY OFFSET is the difference between the actual and the nominal value of the SYSTEM FREQUENCY in order to correct the SYNCHRONOUS TIME (TIME CONTROL); it is not identical with FREQUENCY DEVIATION. Generation GENERATION is the rate at which a GENERATION SET delivers electric power to a system or part of a system, generally expressed in kilowatts (kw) or megawatts (MW), at a given instant or averaged over any designated interval of time, see also: DEMAND. 3 Including virtual tie-lines that may exist for the operation of jointly owned power plants.

27 UCTE Operation Handbook Glossary (final v2.2 E, )!G 7 Generation Set A GENERATION SET is a set of machines consisting of a generator (and its driving apparatus) and a turbine of a generation unit. Inadvertent Deviation see UNINTENTIONAL DEVIATION. Interconnected System An INTERCONNECTED SYSTEM is a system consisting of two or more individual electric systems that normally operate in synchronism and are physically connected via TIE-LINES, see also: SYNCHRONOUS AREA. Interconnection An INTERCONNECTION is a transmission link (e.g. TIE-LINE or transformer) which connects two CONTROL AREAS. Intra-Control-Area Transaction ("P1) An INTRA-CONTROL-AREA TRANSACTION is a transaction carried out from one or more generating sources to one or more delivery points where all the sources and delivery points are entirely located within the metered boundaries of the same CONTROL AREA. Island ("P1) An ISLAND represents a portion of a power system or of several power systems that is electrically separated from the main INTERCONNECTED SYSTEM (separation resulting e.g. from the disconnection / failure of transmission system elements). K-Factor ("P1-B) The K-FACTOR is a value, usually given in megawatts per Hertz (MW/Hz), which is normally determined for a (single) CONTROL AREA / BLOCK; it defines the FREQUENCY BIAS of that CONTROL AREA for SECONDARY CONTROL (especially to assure the functionality of the NETWORK CHARACTERISTIC METHOD); it is not to be confused with the NETWORK POWER FREQUENCY CHARACTERISTIC. Load LOAD means an end-use device or customer that receives power from the electric system. LOAD should not be confused with DEMAND, which is the measure of power that a load receives or requires. LOAD is often wrongly used as a synonym for DEMAND. Load-Frequency Control (LFC) See: SECONDARY CONTROL Load-Shedding ("P1, "P3) LOAD-SHEDDING is the disconnection of LOAD from the synchronous electric system, usually performed automatically, to control the SYSTEM FREQUENCY in emergency situations.

28 UCTE Operation Handbook Glossary (final v2.2 E, )!G 8 Loop Flows See: PARALLEL PATH FLOWS. Metering METERING describes the methods of applying devices that measure and register the amount and direction of electrical quantities with respect to time. Minute Reserve {15 Minute Reserve} See: TERTIARY CONTROL RESERVE N-1 Criterion ("P3) The N-1 CRITERION is a rule according to which elements remaining in operation after failure of a single network element (such as transmission line / transformer or generating unit, or in certain instances a busbar) must be capable of accommodating the change of flows in the network caused by that single failure. Net Transfer Capacity (NTC) The NET TRANSFER CAPACITY is defined as: NTC = TTC-TRM The NET TRANSFER CAPACITY is the maximum total EXCHANGE PROGRAM between two ADJACENT CONTROL AREAS compatible with security standards applicable in all CONTROL AREAS of the SYNCHRONOUS AREA, and taking into account the technical uncertainties on future network conditions. Network Characteristic Method ("P1-B) The properties required for SECONDARY CONTROL are produced by the NETWORK CHARACTERISTIC METHOD. The purpose of SECONDARY CONTROL is to move the overall FREQUENCY DEVIATION and POWER DEVIATION of the CONTROL AREA / BLOCK considered towards zero. The NETWORK CHARACTERISTIC METHOD (to be applied to all CONTROL AREAS in the same way and at the same time) assures the control of two variables at the same time with one set-point value, as long as the NETWORK POWER FREQUENCY CHARACTERISTIC is used. Network Power Frequency Characteristic ("P1-B, "A1-A) The NETWORK POWER FREQUENCY CHARACTERISTIC defines the sensitivity, given in megawatts per Hertz (MW/Hz), usually associated with a (single) CONTROL AREA / BLOCK or the entire SYNCHRONOUS AREA, that relates the difference between scheduled and actual SYSTEM FREQUENCY to the amount of generation required to correct the power imbalance for that CONTROL AREA / BLOCK (or, vice versa, the stationary change of the SYSTEM FREQUENCY in case of a disturbance of the generation-load equilibrium in the CONTROL AREA without being connected to other CONTROL AREAS); it is not to be confused with the K-FACTOR. The NETWORK POWER FREQUENCY CHARACTERISTIC includes all active PRIMARY CONTROL and SELF-REGULATION OF LOAD and changes due to modifications in the generation pattern and the DEMAND. Observation Line ("P2) An OBSERVATION LINE is a conventional border line separating a part of the SYNCHRONOUS ZONE from the rest of the system for the purpose of real-time error detection and preliminary calculation of UNINTENTIONAL DEVIATIONS. It must run along the borders of CONTROL BLOCKS and must not split any CONTROL BLOCK.

29 UCTE Operation Handbook Glossary (final v2.2 E, )!G 9 Offsetting of Unintentional Deviations ("P2) OFFSETTING OF UNINTENTIONAL DEVIATIONS describes a procedure applied to carry out the compensation in energy of UNINTENTIONAL DEVIATIONS through a corresponding energy EXCHANGE SCHEDULE; the energy is to be delivered to (or imported from) the rest of the system during the following week according to the standards. Observation of Unintentional Deviations The on-line OBSERVATION OF UNINTENTIONAL DEVIATIONS is performed in an autonomous and independent way by each CONTROL BLOCK according to the standards established. A second level exists through real-time observation of UNINTENTIONAL DEVIATIONS across previously defined OBSERVATION LINES. This function allows to improve the detection, as early as possible, of any error concerning on-line telemeasurements (TMs), any misunderstanding which may occur in setting the EXCHANGE PROGRAMS, etc., in order to implement without delay the appropriate corrective actions. This function may be performed in one or more locations which must then closely co-operate. Operating Policies OPERATING POLICIES constitute the doctrine developed for INTERCONNECTED SYSTEMS operation; they form the main part of the Operation Handbook. Each doctrine consists of criteria, standards, requirements, guides, and instructions, and applies to all CONTROL AREAS / BLOCKS / TSOS. Operating Procedures OPERATING PROCEDURES are a set of policies, practices, or system adjustments that may be automatically or manually implemented by the system operator within a specified time frame to maintain the operational integrity of the INTERCONNECTED SYSTEMS. Parallel Path Flows {loop flows, circulating power flows, unscheduled power flows} PARALLEL PATH FLOWS describe the difference between the scheduled and actual power flow, assuming zero inadvertent interchange, on a given transmission path in a meshed grid. Power System The POWER SYSTEM comprises all generation, consumption and network installations interconnected through the network. Power Deviation ("P1) A POWER DEVIATION is a power deficit (negative value) or a surplus (positive value) in a CONTROL AREA / BLOCK of the SYNCHRONOUS AREA 4, usually measured at the borders of the area, with respect to the CONTROL PROGRAM. Primary Control {Frequency Control, Primary Frequency Control} ("P1-A, "A1-A) PRIMARY CONTROL maintains the balance between GENERATION and DEMAND in the network using turbine speed governors. PRIMARY CONTROL is an automatic decentralised function of the turbine 4 Power exchanges over DC-connections are not included in the calculation of the power deviation, they are considered to be either an injection or a load in the CONTROL AREA connected.

30 UCTE Operation Handbook Glossary (final v2.2 E, )!G 10 governor to adjust the generator output of a unit as a consequence of a FREQUENCY DEVIATION / OFFSET in the SYNCHRONOUS AREA: PRIMARY CONTROL should be distributed as evenly as possible over units in operation in the SYNCHRONOUS AREA; the global PRIMARY CONTROL behaviour of an interconnection partner (CONTROL AREA / BLOCK), may be assessed by the calculation of the equivalent droop of the area (basically resulting from the DROOP OF ALL GENERATORS and the SELF-REGULATION OF THE TOTAL DEMAND). By the joint action of all interconnected undertakings, PRIMARY CONTROL ensures the operational reliability for the power system of the SYNCHRONOUS AREA. Primary Control Power ("P1-A) PRIMARY CONTROL POWER is the power output of a GENERATION SET due to PRIMARY CONTROL. Primary Control Range ("P1-A) The PRIMARY CONTROL RANGE is the range of adjustment of PRIMARY CONTROL POWER, within which PRIMARY CONTROLLERS can provide automatic control, in both directions, in response to a FREQUENCY DEVIATION. The concept of the PRIMARY CONTROL RANGE applies to each generator, each CONTROL AREA / BLOCK, and the entire SYNCHRONOUS AREA. Primary Control Reserve ("P1-A) The PRIMARY CONTROL RESERVE is the (positive / negative) part of the PRIMARY CONTROL RANGE measured from the working point prior to the disturbance up to the maximum PRIMARY CONTROL POWER (taking account of a limiter). The concept of the PRIMARY CONTROL RESERVE applies to each generator, each CONTROL AREA / BLOCK, and the entire SYNCHRONOUS AREA. Primary Controller ("P1-A) The PRIMARY CONTROLLER is a decentralised / locally installed control equipment for a GENERATION SET to control the valves of the turbine based on the speed of the generator (for synchronous generators directly coupled to the electric SYSTEM FREQUENCY); see PRIMARY CONTROL. The insensitivity of the PRIMARY CONTROLLER is defined by the limit frequencies between which the controller does not respond. This concept applies to the complete primary controller-generator unit. A distinction is drawn between unintentional insensitivity associated with structural inaccuracies in the unit and a dead band set intentionally on the controller of a generator. Primary Frequency Control See: PRIMARY CONTROL Pseudo-Tie-Line See: VIRTUAL TIE-LINE. Reactive Power REACTIVE POWER is an imaginary component of the apparent power. It is usually expressed in kilo-vars (kvar) or mega-vars (MVAr). REACTIVE POWER is the portion of electricity that establishes and sustains the electric and magnetic fields of alternating-current equipment. REACTIVE POWER must be supplied to most types of magnetic equipment, such as motors and transformers and causes reactive losses on transmission facilities. REACTIVE POWER is provided by generators, synchronous condensers, or electrostatic equipment such as capacitors, and directly influences the electric system voltage. The REACTIVE POWER is the imaginary part of the complex product of voltage and current.

31 UCTE Operation Handbook Glossary (final v2.2 E, )!G 11 Ramp Period ("P1-B) The RAMP PERIOD is the time between ramp start and end times, usually expressed in minutes and applied to SCHEDULES. Reliability 5 ("P3) RELIABILITY describes the degree of performance of the elements of the bulk electric system that results in electricity being delivered to customers within accepted standards and in the amount desired. RELIABILITY on the transmission level may be measured by the frequency, duration, and magnitude (or the probability) of adverse effects on the electric supply / transport / generation. Electric system RELIABILITY can be addressed by considering two basic and functional aspects of the electric system: Adequacy The ability of the electric system to supply the aggregate electrical demand and energy requirements of the customers at all times, taking into account scheduled and reasonably expected unscheduled outages of system elements. Security The ability of the electric system to withstand sudden disturbances such as electric short circuits or unanticipated loss of system elements. Secondary Control {Load-Frequency-Control} ("P1-B, "A1-B) SECONDARY CONTROL is a centralised automatic function to regulate the generation in a CONTROL AREA based on SECONDARY CONTROL RESERVES in order to maintain its interchange power flow at the CONTROL PROGRAM with all other CONTROL AREAS (and to correct the loss of capacity in a CONTROL AREA affected by a loss of production) and, at the same time, (in case of a major FREQUENCY DEVIATION originating from the CONTROL AREA, particularly after the loss of a large generation unit) to restore the frequency in case of a FREQUENCY DEVIATION originating from the CONTROL AREA to its set value in order to free the capacity engaged by the PRIMARY CONTROL (and to restore the PRIMARY CONTROL RESERVES). In order to fulfil these functions, SECONDARY CONTROL operates by the NETWORK CHARACTERISTIC METHOD. SECONDARY CONTROL is applied to selected generator sets in the power plants comprising this control loop. SECONDARY CONTROL operates for periods of several minutes, and is therefore dissociated from PRIMARY CONTROL. This behaviour over time is associated with the PI (proportional-integral) characteristic of the SECONDARY CONTROLLER. Secondary Control Range ("P1-B) The SECONDARY CONTROL RANGE is the range of adjustment of the secondary control power, within which the SECONDARY CONTROLLER can operate automatically, in both directions at the time concerned, from the working point of the secondary control power. Secondary Control Reserve ("P1-B) The positive / negative SECONDARY CONTROL RESERVE is the part of the SECONDARY CONTROL RANGE between the working point and the maximum / minimum value. The portion of the SECONDARY CONTROL RANGE already activated at the working point is the SECONDARY CONTROL POWER. Secondary Controller ("P1-B) A SECONDARY CONTROLLER is the single centralised TSO-equipment per CONTROL AREA / BLOCK for operation of SECONDARY CONTROL. 5 To a great extent, the overall RELIABILITY of the electric power supply (for customers being connected to the distribution grid), that is usually measured, is defined by the RELIABILITY of the power distribution instead of the transmission or generation.

32 UCTE Operation Handbook Glossary (final v2.2 E, )!G 12 Security Limits {Operating Security Limits} ("P3) SECURITY LIMITS define the acceptable operating boundaries (thermal, voltage and stability limits). The TSO must have defined SECURITY LIMITS for its own network. The TSO shall ensure adherence to these SECURITY LIMITS. Violation of SECURITY LIMITS for prolonged time could cause damage and/or an outage of another element that can cause further deterioration of system operating conditions. Self-Regulation of Load ("P1-A) The SELF-REGULATION OF LOAD is defined as the sensitivity of consumers demand to variations in the SYSTEM FREQUENCY (a decrease of the SYSTEM FREQUENCY results in a decrease of the LOAD), generally expressed in % / Hz. Stability ("P3) STABILITY is the ability of an electric system to maintain a state of equilibrium during normal and abnormal system conditions or disturbances. Small-Signal Stability The ability of the electric system to withstand small changes or disturbances without the loss of synchronism among the synchronous machines in the system while having a sufficient damping of system oscillations (sufficient margin to the border of stability). Transient Stability The ability of an electric system to maintain synchronism between its parts when subjected to a disturbance of specified severity and to regain a state of equilibrium following that disturbance. Supervisory Control and Data Acquisition (SCADA) SUPERVISORY CONTROL AND DATA ACQUISITION is a system of remote control and telemetry used to monitor and control the electric system. Synchronous Area ("P1) A SYNCHRONOUS AREA is an area covered by INTERCONNECTED SYSTEMS whose CONTROL AREAS are synchronously interconnected with CONTROL AREAS of members of the association. Within a SYNCHRONOUS AREA the SYSTEM FREQUENCY is common on a steady state. A certain number of SYNCHRONOUS AREAS may exist in parallel on a temporal or permanent basis. A SYNCHRONOUS AREA is a set of synchronously INTERCONNECTED SYSTEMS that has no synchronous interconnections to any other INTERCONNECTED SYSTEMS, see also: UCTE SYNCHRONOUS AREA. Synchronous Time ("P1-D) SYNCHRONOUS TIME is the fictive time based on the SYSTEM FREQUENCY in the SYNCHRONOUS AREA, once initialised on UTC time and with the clock frequency being 60/50 of the SYSTEM FREQUENCY. If the SYNCHRONOUS TIME is ahead / behind of the UTC time (TIME DEVIATION), the SYSTEM FREQUENCY has on average been higher / lower than the nominal frequency of 50 Hz. TIME CONTROL action will return a TIME DEVIATION to zero again. System Frequency {Frequency} ("P1, "A1-A) SYSTEM FREQUENCY is the electric frequency of the system that can be measured in all network areas of the SYNCHRONOUS AREA under the assumption of a coherent value for the system in the time frame of seconds (with minor differences between different measurement locations only).

33 UCTE Operation Handbook Glossary (final v2.2 E, )!G 13 Tertiary Control ("P1-C, "A1-C) TERTIARY CONTROL is any (automatic or) manual change in the working points of generators (mainly by re-scheduling), in order to restore an adequate SECONDARY CONTROL RESERVE at the right time. Tertiary Control Reserve {Minute Reserve} ("P1-C) The power which can be connected (automatically or) manually under TERTIARY CONTROL, in order to provide an adequate SECONDARY CONTROL RESERVE, is known as the TERTIARY CONTROL RESERVE or MINUTE RESERVE. This reserve must be used in such a way that it will contribute to the restoration of the SECONDARY CONTROL RANGE when required. The restoration of an adequate SECONDARY CONTROL RANGE may take, for example, up to 15 minutes, whereas TERTIARY CONTROL for the optimisation of the network and generating system will not necessarily be complete after this time. Tie-Line ("P1) A TIE-LINE is a circuit (e.g. a transmission line) connecting two or more CONTROL AREAS or systems of an electric system. Time Deviation ("P1-D) The TIME DEVIATION normally is the time integral of the FREQUENCY DEVIATION. In practice, an electrical clock that follows the SYSTEM FREQUENCY is compared with the astronomical time (UTC). Time Control TIME CONTROL is a control action carried out to return an existing TIME DEVIATION between SYNCHRONOUS TIME and UTC time to zero. ("P1-D, "A1-D) Total Transfer Capacity (TTC) TOTAL TRANSFER CAPACITY is the maximum EXCHANGE PROGRAM between two ADJACENT CONTROL AREAS that is compatible with operational security standards applied in each system (e.g. GridCodes) if future network conditions, generation and load patterns are perfectly known in advance. Transmission TRANSMISSION is the transport of electricity on the extra-high or high-voltage network (transmission system) for delivery to final customers or distributors. Operation of TRANSMISSION includes as well the tasks of system operation concerning the management of energy flows, reliability of the system and availability of all necessary system services / ANCILLARY SERVICES. Transmission Reliability Margin (TRM) The TRANSMISSION RELIABILITY MARGIN is a security margin that copes with uncertainties on the computed TTC values arising from: UNINTENTIONAL DEVIATIONS of physical flows during operation due to the physical functioning of SECONDARY CONTROL Emergency exchanges between TSOs to cope with unexpected unbalanced situations in real-time Inaccuracies, e. g. in data collection and measurements

34 UCTE Operation Handbook Glossary (final v2.2 E, )!G 14 Transmission System Operator (TSO) A TRANSMISSION SYSTEM OPERATOR is an company that is responsible for operating, maintaining and developing the transmission system for a CONTROL AREA and its INTERCONNECTIONS. UCTE Synchronous Area ("P1) A UCTE synchronous area is a part of a SYNCHRONOUS AREA covered by INTERCONNECTED SYSTEMS / TSOs which are members of the association. Different UCTE SYNCHRONOUS AREAS may exist in parallel on a temporal or permanent basis. Unintentional Deviation {Inadvertent Deviation} ("P1-B) In the SECONDARY CONTROL function, the UNINTENTIONAL DEVIATION is the difference between the actual energy exchange that has taken place in a given time interval (unintended physical power exchange of a CONTROL AREA) and the scheduled CONTROL PROGRAM of a CONTROL AREA (or a CONTROL BLOCK), without taking into account the effect of the frequency bias (see: AREA CONTROL ERROR), following the sign convention. Virtual Tie-Line {Pseudo-Tie-Line} ("P1-B) A VIRTUAL TIE-LINE represents a telemetered reading or value that is updated in real-time and used as a TIE-LINE flow in the AGC/ACE equation but for which no physical tie or energy metering actually exists. The integrated value is used as a metered MWh value for interchange ACCOUNTING purposes.

35 UCTE Operation Handbook Glossary (final v2.2 E, )!G 15 B. List of Acronyms AAC ACE AGC ATC BRP CA CAS CAX CB CBS CBX CC CCS CoC CP DACF EH EIC EMR ESS ET EVT GENCO GMT GPS HV LFC NTC OpHB PI SCADA SVC TM TSO TRM TTC UCTE UD UHV UTC WAMS Already Allocated Capacity Area Control Error Automatic Generation Control Available Transmission Capacity Balance Responsible Party Control Area Control Area Schedule Control Area Exchange Control Block Control Block Schedule Control Block Exchange Control Centre Co-ordination Centre Schedule Co-ordination Centre Control Program Day Ahead Congestion Forecast Electronic Highway ETSO Identification Code Energy Meter Reading European Scheduling System Tie-line Flows Virtual Tie-line Flows Generation Company Greenwich Mean Time Global Positioning System High Voltage Load-Frequency Control Net Transfer Capacity Operation Handbook Proportional-Integral Supervisory Control and Data Acquisition Static Var Compensator Tele-measurement Transmission System Operator Transmission Reliability Margin Total Transfer Capacity Union for the Co-ordination of Transmission of Electricity Unintentional Deviation Ultra High Voltage Universal Time Co-ordinated Wide Inter-Area Measurement System

36 UCTE Operation Handbook Glossary (final v2.2 E, )!G 16 C. List of Units A ampere d day GW gigawatt ( W) GWh gigawatt-hour h, hrs hour Hz hertz (1/s) kv kilovolt (1000V) kva kilovoltampere kvar kilovars kw kilowatt (1000W) kwh kilowatt-hour mhz milli-hertz (1/1000 Hz) min minute ms milli-second (1/1000 s) MVA megavolt-ampere MVAr mega-vars MW megawatt ( W) MWh megawatt-hour s, sec second TW terawatt ( W) V volt W watt

37 POLICY 1 LOAD-FREQUENCY CONTROL AND PERFORMANCE

38 P1 Policy 1: Load-Frequency Control and Performance [E] Chapters A. Primary Control B. Secondary Control C. Tertiary Control D. Time Control E. Measures for Emergency Conditions Introduction The GENERATION of power units connected to the UCTE network needs to be controlled and monitored for secure and high-quality operation of the SYNCHRONOUS AREAS. The generation control, the technical reserves and the corresponding performance measurements are essential to allow TSOs to perform daily operational business. Control actions are performed in different successive steps, each with different characteristics and qualities, and all depending on each other: PRIMARY CONTROL (see section!p1-a) starts within seconds as a joint action of all undertakings involved. SECONDARY CONTROL (see section!p1-b) replaces PRIMARY CONTROL after minutes and is put into action by the responsible undertakings / TSOs only. TERTIARY CONTROL (see subsection!p1-c) frees SECONDARY CONTROL by re-scheduling generation and is put into action by the responsible undertakings / TSOs. TIME CONTROL (see subsection!p1-d) corrects global TIME DEVIATIONS of the SYNCHRONOUS TIME in the long term as a joint action of all undertakings / TSOs. Please refer to the glossary of terms of the UCTE Operation Handbook (see!g) for detailed definitions of terms used within this policy and to Appendix 1 (see!a1) for basics and principles of load-frequency control and performance. History of changes v2.2 draft Final wording v2.1 draft OH-Team Changes after consultation Current status This document summarises current UCTE rules and recommendations relating to loadfrequency control and performance issues in a new structure, with additional items describing today s common practice. This policy replaces previous UCTE ground rules and recommendations regarding PRIMARY and SECONDARY frequency and active POWER CONTROL, regulation reserves and correction of SYNCHRONOUS TIME. This version of the document (version 2.2, level E, dated ) has final policy status. This document and other chapters of the UCTE Operation Handbook as well as excerpts from it may not be published, redistributed or modified in any technical means or used for any other purpose outside of UCTE without written permission in advance.

39 UCTE OH Policy 1: Load-Frequency Control (final policy 2.2 E, ) "P1 2 A. Primary Control [UCTE Operation Handbook Appendix 1 Chapter A: Primary Control, 2004] Introduction The objective of PRIMARY CONTROL is to maintain a balance between GENERATION and consumption (DEMAND) within the SYNCHRONOUS AREA, using turbine speed or turbine governors. By the joint action of all interconnected undertakings / TSOs, PRIMARY CONTROL aims at the operational reliability of the power system of the SYNCHRONOUS AREA and stabilises the SYSTEM FREQUENCY at a stationary value after a disturbance or incident in the time-frame of seconds, but without restoring the reference values of SYSTEM FREQUENCY and power exchanges (see!p1-b for SECONDARY CONTROL). Adequate PRIMARY CONTROL depends on generation resources made available by generation companies to the TSOs. Please refer to appendix 1 (see!a1-a) for basics and principles of PRIMARY CONTROL. This policy section replaces the corresponding sections for primary control in the latest UCPTE-Ground Rules concerning primary and secondary control of frequency and active power within the UCPTE, dated Criteria C1. Nominal frequency. The set-point frequency (or scheduled frequency) f 0 (see!p1- D) defines the target value of the SYSTEM FREQUENCY f for system operation. Outside periods for the correction of SYNCHRONOUS TIME (see!p1-d), the nominal frequency value in the SYNCHRONOUS AREA is 50 Hz. C2. Frequency deviations. A FREQUENCY DEVIATION f (the departure f f 0 of the actual SYSTEM FREQUENCY f from the scheduled frequency f 0 ) results from a disturbance or an incident and may occur during normal system operation. Different criteria are used to distinguish the size of this deviation: C2.1. Calling up of Primary Control. To avoid calling up of PRIMARY CONTROL in undisturbed operation at or near nominal frequency, the FREQUENCY DEVIATION should not exceed ±20 mhz. PRIMARY CONTROL is activated if the FREQUENCY DEVIATION exceeds ±20 mhz (the sum of the accuracy of the local frequency measurement and the insensitivity of the controller, see!p1-a-r1 and!p1- A-R2). C2.2. Maximum Quasi-Steady-State Frequency Deviation. The quasi-steady-state FREQUENCY DEVIATION in the SYNCHRONOUS AREA must not exceed ±180 mhz (maximum permissible steady-state FREQUENCY DEVIATION; under the condition of SELF-REGULATION OF THE LOAD according to!p1-a-c4). C2.3. Minimum Instantaneous Frequency. The instantaneous frequency must not fall below 49.2 Hz (that corresponds to -800 mhz as maximum permissible dynamic FREQUENCY DEVIATION from the nominal frequency!p1-a-c1) in response to a shortfall in generation capacity equal to or less than the reference incident according to!p1-a-c3. C2.4. Load-Shedding Frequency Criterion. LOAD-SHEDDING (automatic or manual, including the possibility to shed pumping units) starts from a SYSTEM FREQUENCY of 49.0 Hz (or below). The detailed step-plans for LOAD-SHEDDING (in the responsibility of the TSOs, with the possibility to perform earlier shedding of pumping units at higher frequency value as an operational measure, with the lowest value of 47.5 Hz and the need of progressive stages in between) define additional frequency criteria for further measures. C2.5. Maximum Instantaneous Frequency. The instantaneous frequency must not exceed 50.8 Hz (that corresponds to +800 mhz as maximum permissible dynamic FREQUENCY DEVIATION from the nominal frequency!p1-a-c1) in response to a loss of load or interruption of power exchanges equal to or less than the reference incident according to!p1-a-c3.

40 UCTE OH Policy 1: Load-Frequency Control (final policy 2.2 E, )!P1 3 C3. Reference Incident. The maximum instantaneous deviation between generation and demand in the SYNCHRONOUS AREA (by the sudden loss of generation capacity, loadshedding / loss of load or interruption of power exchanges) to be handled by PRIMARY CONTROL starting from undisturbed operation depends on the size of the area / zone 1 and on the size of the largest generation unit or generation capacity connected to a single bus bar located in that area 2. C3.1. First Synchronous Zone. For the first synchronous zone as in 2003 the maximum power deviation to be handled is 3000 MW, assuming realistic characteristics concerning system reliability and size of loads and generation units. C3.2. Second Synchronous Zone. For the second synchronous zone as in 2003, the maximum power deviation to be handled is 540 MW. C3.3. Other Synchronous Areas. For other SYNCHRONOUS AREAS (UCTE SYNCHRONOUS AREAS), that are not connected to the main synchronous zone, the size of the reference incident needs to be defined in each particular case with respect to the size of the area and the size of the largest generation units located in that area. C3.4. Observation Incident. Incidents, such as the sudden loss of generation or load, that exceed 1000 MW in the first synchronous zone or 250 MW in the second synchronous zone are considered to be relevant for system observation in that zone 3. C4. Frequency Characteristics. Key values of the frequency characteristics are defined on the basis of system observation 4. C4.1. Self-Regulation of Load. The self-regulation of the load in all SYNCHRONOUS AREAS is assumed to be 1 %/Hz, that means a load decrease of 1 % occurs in case of a frequency drop of 1 Hz. C4.2. Security Margin. For FREQUENCY CONTROL, a static security margin of 20 mhz is defined, identical with the calling up of PRIMARY CONTROL (see "P1-A-C2.1). C5. Deployment Times of Primary Control Reserve. The time for starting the action of PRIMARY CONTROL is a few seconds starting from the incident, the deployment time for 50 % or less of the total PRIMARY CONTROL RESERVE is at most 15 seconds and from 50 % to 100 % the maximum deployment time rises linearly to 30 seconds. C6. Frequency Change Indicators. For special use in a post-operation analysis, the following criteria are defined to measure the characteristics of absolute changes of the SYSTEM FREQUENCY within a short period of time. C6.1. Periods of Time. Typical periods of time are ±60 minutes, ±15 minutes and ±5 minutes around the time of an incident or the change of the hour. 1: The definitions of synchronous zones (first and second zone as existing today as a result of the Balkan war) are temporal only due to the planned reconnection of the UCTE area. The reconnection is scheduled for The system load for the first SYNCHRONOUS AREA typically varies between 150 GW off-peak and 300 GW peak. 2: The final values used in the definition of the reference incidents are determined by the UCTE SG TSO-Forum and finally confirmed by the UCTE WG Operations and Security and the UCTE SC. The values given are under consideration. 3: The values have been adapted by the UCTE SG TSO-Forum in 2001 and are reviewed annually. 4: The final values used in the definition are determined by the UCTE SG TSO-Forum and finally confirmed by the UCTE WG Operations and Security and the UCTE SC. The values given are under consideration.

41 UCTE OH Policy 1: Load-Frequency Control (final policy 2.2 E, ) "P1 4 C6.1. Periods of Time. Typical periods of time are ±60 minutes, ±15 minutes and ±5 minutes around the time of an incident or the change of the hour. C6.2. Maximum Time Grid. The values used for frequency change indicators are based on a maximum time grid of 10 seconds. C6.3. Frequency Patterns. Typical patterns of the frequency within a short period of time can be: constant with / without offset, decrease, increase, peak up, peak down, peak up down and peak down up. C6.4. Peak Frequency Range within Period. The peak frequency range is calculated as the difference between the maximum and the minimum frequency within the given period of time. C6.5. Peak Frequency Derivative within Period. The peak frequency derivative is determined as the maximum or minimum derivative of the frequency within the given period of time. Requirements R1. Accuracy of Frequency Measurements. For PRIMARY CONTROL, the accuracy of local frequency measurements used in the PRIMARY CONTROLLERS must be better than or equal to 10 mhz. R2. Insensitivity of Controllers. The insensitivity range of PRIMARY CONTROLLERS should not exceed ±10 mhz. Where dead bands exist in specific controllers, these must be offset within the CONTROL AREA / BLOCK concerned. R3. Primary Control Reserve. PRIMARY CONTROL RESERVE needs to have certain characteristics to be usable for PRIMARY CONTROL. R3.1. Reserve Distribution. In general, the PRIMARY CONTROL RESERVE must be physically distributed as evenly as possible between the different regions (usually between the CONTROL AREAS / BLOCKS) in the SYNCHRONOUS AREA (see also!p1-b and the distribution procedure). R3.2. Total Size of Reserve. The total PRIMARY CONTROL RESERVE (in MW) required for operation of a SYNCHRONOUS AREA is of the same size as the reference incident for that area (see!p1-a-c3). R3.3. Availability of Reserves. In total and as a minimum, the full PRIMARY CONTROL RESERVE for each area must be available continuously without interruption, not depending on the unit commitment in detail. R3.4. Operational Usability of Reserves. The entire PRIMARY CONTROL RESERVE (and each share of it) must be fully activated in response to a quasi-steadystate FREQUENCY DEVIATION of ±200 mhz or more. R4. Network Power Frequency Characteristic. The NETWORK POWER FREQUENCY CHARACTERISTIC describes the real dependency between SYSTEM FREQUENCY and POWER IMBALANCE with a linear approximation. R4.1. Constant Network Power Frequency Characteristic. In order to ensure that the principle of joint action is observed, the NETWORK POWER FREQUENCY CHARACTERISTICS of the various CONTROL AREAS is taken to remain as constant as possible. This applies particularly to small FREQUENCY DEVIATIONS, where the "dead bands" of generators may have an unacceptable influence upon the supply of PRIMARY CONTROL energy in the CONTROL AREAS concerned. R4.2. Share of Primary Control. The NETWORK POWER FREQUENCY CHARACTERISTIC of PRIMARY CONTROL only for the first synchronous zone is calculated out of!p1-a-r3.2 and!p1-a-c2.2 (including the security margin!p1-a-c4.2) to MW/Hz.

42 UCTE OH Policy 1: Load-Frequency Control (final policy 2.2 E, ) "P1 5 R4.3. Share of Self-Regulation.. The NETWORK POWER FREQUENCY CHARACTERISTIC of SELF-REGULATION only for the first synchronous zone is calculated out of!p1-a-c4.1 and!p1-a-c3 to 3000 MW/Hz. R4.4. Overall Network Power Frequency Characteristic. The overall NETWORK POWER FREQUENCY CHARACTERISTIC for the first synchronous zone is set to MW/Hz and for the second synchronous zone set to 3000 MW/Hz. Standards S1. System Reliability. In case of a first contingency or incident according to!p1-a-c3, such as the loss of generation or load or interruption of power exchanges in an undisturbed situation, PRIMARY CONTROL must maintain reliable system operation. S2. Primary Control Action. The action of the individual generators performing PRIMARY CONTROL must have the following characteristics, to be ensured by all TSOs: S2.1. Adjustment of Generation. Power generation under PRIMARY CONTROL must be constantly adjusted to follow changes of SYSTEM FREQUENCY. S2.2. Deployment. Total PRIMARY CONTROL within the entire SYNCHRONOUS AREA (as well as within each CONTROL AREA / BLOCK) must follow the deployment times of PRIMARY CONTROL RESERVE (see!p1-a-c5). Each TSO must check the deployment times within his CONTROL AREA / BLOCK on a regular basis. S2.3. Duration of Delivery. PRIMARY CONTROL POWER must be delivered until the power deviation is completely offset by the SECONDARY CONTROL RESERVE of the CONTROL AREA / BLOCK in which the power deviation has occurred (the minimum duration for the capability of delivery for primary control is 15 minutes, see!p1-b). S3. Primary Control Target. Starting from undisturbed operation (see!p1-a-c2), a reference incident (see!p1-a-c3) must be offset by PRIMARY CONTROL alone, without the need for LOAD-SHEDDING in response to a FREQUENCY DEVIATION. In addition, where the self-regulating effect of the load is assumed according to!p1-a-c4, the FREQUENCY DEVIATION must not exceed the quasi-steady-state frequency deviation (see!p1-a-c2). S4. Principle of Joint Action. PRIMARY CONTROL is based on the principle of joint action to ensure system reliability and interconnected operation. This includes an overall distribution of reserves and control actions, as determined and decided by the UCTE SG TSO-Forum on an annual basis for the next calendar year. S4.1. Contributions to Primary Reserves. Each CONTROL AREA / BLOCK must contribute to the PRIMARY CONTROL RESERVE as required. The respective shares are defined by multiplying the calculated reserve for the entire SYNCHRONOUS AREA (see!p1-a-r3 and!p1-b) and the contribution coefficients c i of the various CONTROL AREAS / BLOCKS. The sum of all shares must amount to the total PRIMARY CONTROL RESERVE. S4.2. Contribution to Control. Each CONTROL AREA / BLOCK must contribute to the correction of a disturbance in accordance with its respective contribution coefficient c i for PRIMARY CONTROL. S4.3. Contribution Coefficients. The contribution coefficients must be determined and published annually for each CONTROL AREA / BLOCK. The contribution coefficients are binding for the corresponding interconnection partner / TSO for one calendar year. They are based on the share of the energy generated within one year in relation to the entire SYNCHRONOUS AREA. The sum of all contributions coefficients must amount to 1.

43 UCTE OH Policy 1: Load-Frequency Control (final policy 2.2 E, ) "P1 6 Procedures P1. Contribution Coefficients. The UCTE SG TSO-Forum determines and decides about the contribution coefficients of each CONTROL AREA / BLOCK for each SYNCHRONOUS ZONE on an annual basis (published before the 1 st of December) and sets these values into operation on the 1 st of January of the next year. P2. Observation of Outages. Outages in production or consumption exceeding the size of the observation incident (see!p1-a-c3) are recorded for analysis. The corresponding information about location, time, size and type of the disturbance / incident is recorded and made available to the members of the association. P3. Frequency Analysis. The detailed analysis of the characteristics of the SYSTEM FREQUENCY is made according to that of the following procedures. P3.1. Frequency Change Analysis. The frequency change analysis 5, see appendix, uses the frequency change indicators (see!p1-a-c6) for evaluation and comparison. P4. Control Performance Measurement. The NETWORK POWER FREQUENCY CHARACTERISTIC is calculated in response to a disturbance (such as an observation incident), based on measurements of the SYSTEM FREQUENCY and other key values and on a statistical analysis. P4.1. Control Performance Report. UCTE publishes results of a control performance analysis on a regular basis in the Regular Report of the Performance of the Primary and Secondary Load Frequency Control, prepared by the UCTE SG TSO-Forum. Guidelines G1. Measurement Cycle for Primary Control. Typically the cycle for measurements for PRIMARY CONTROL action must be in the range of 0.1 seconds to 1 second. G2. Measurement Cycle for Observation. The cycle for measurements of the SYSTEM FREQUENCY for central system observation must be in the range of 1 second (strongly recommended) to at most 10 seconds. 5: Also known as frequency measurement campaign.

44 UCTE OH Policy 1: Load-Frequency Control (final policy 2.2 E, ) "P1 7 B. Secondary Control [UCTE Operation Handbook Appendix 1 Chapter A: Secondary Control, 2004] [UCPTE Rule 44: Control of active power in the grid of the UCPTE, 1990] [UCPTE-Ground Rules concerning primary and secondary control of frequency and active power within the UCPTE, 1998] Introduction SECONDARY CONTROL maintains a balance between GENERATION and consumption (DEMAND) within each CONTROL AREA / BLOCK as well as the SYSTEM FREQUENCY within the SYNCHRONOUS AREA, taking into account the CONTROL PROGRAM, without impairing the PRIMARY CONTROL that is operated in the SYNCHRONOUS AREA in parallel but by a margin of seconds (see!p1-a). SECONDARY CONTROL makes use of a centralised AUTOMATIC GENERATION CONTROL, modifying the active power set points / adjustments of GENERATION SETS in the time-frame of seconds to typically 15 minutes. SECONDARY CONTROL is based on SECONDARY CONTROL RESERVES that is under automatic control. Adequate SECONDARY CONTROL depends on generation resources made available by generation companies to the TSOs. Please refer to Appendix 1 (see!a1-b) for basics and principles of SECONDARY CONTROL. This policy section replaces the corresponding sections for secondary control in the latest UCPTE-Ground Rules concerning primary and secondary control of frequency and active power within the UCPTE, dated Criteria C1. K-Factor. The K-FACTOR defines the dependency between SYSTEM FREQUENCY and deviation of power exchanges for SECONDARY CONTROL. C1.1. Frequency Control Gain. The common gain defined for FREQUENCY CONTROL within SECONDARY CONTROL is set to 1.1 (110 %), used to overcome the uncertainty of the SELF-REGULATING effect. C1.2. K-Factor Calculation. The K-FACTOR K ri of a CONTROL AREA / BLOCK for SECONDARY CONTROL is calculated by the product of the frequency control gain 1.1 (see!p1-b-c1.1), the contribution coefficient c i of that area (see!p1-a- S4.3) and the total NETWORK POWER FREQUENCY CHARACTERISTIC (see!p1- A-R4.4). C1.3. Total K-Factor for Secondary Control. The total K-FACTOR for SECONDARY CONTROL in the FIRST SYNCHRONOUS ZONE amounts to MW/Hz for the year The total K-FACTOR for SECONDARY CONTROL in the SECOND SYNCHRONOUS ZONE comes to 3301 MW/Hz for the year C2. Area Control Error. Within each CONTROL AREA / BLOCK, the individual AREA CONTROL ERROR G (ACE) needs to be controlled to zero on a continuous basis. The ACE is calculated as the sum of the power control error and the frequency control error (G= P+ K* f). C2.1. Power Control Error. The power control error P of a CONTROL AREA / BLOCK is the total POWER DEVIATION of that area in interconnected operation, calculated as the difference between the total active power flow (sum of all related measurements) and the CONTROL PROGRAM (sum of all related exchange schedules and the compensation programs). C2.2. Frequency Control Error. The frequency control error K* f of a CONTROL AREA / BLOCK is the product of the FREQUENCY DEVIATION f (see!p1-a-c2) and the K-FACTOR of the CONTROL AREA / BLOCK K ri (see!p1-b-c1.2). 6: The final values are determined by the UCTE SG TSO-Forum on a regular basis.

45 UCTE OH Policy 1: Load-Frequency Control (final policy 2.2 E, ) "P1 8 C3. Secondary Control Deviation. A disturbance or an incident (inside or outside of the CONTROL AREA / BLOCK) will result in an AREA CONTROL ERROR. Different criteria are used to distinguish the size of this deviation (see!a1 for further details, look for Calling up of SECONDARY CONTROL ). C4. Island Operation. In contrast to interconnected operation, island operation is the unusual operation mode, where all interconnections / TIE-LINES of a CONTROL AREA / BLOCK are disconnected (e.g. after a disturbance the CONTROL AREA is not connected to the SYNCHRONOUS AREA any more) and thus no EXCHANGE PROGRAMS are possible. C5. ACE Change Indicators. For special use in a post-operation analysis, special criteria are defined to measure the characteristics of absolute changes of the ACE of a CONTROL AREA / BLOCK within a short period of time (see also!p1-a-c6). Requirements R1. Control Area / Block. The following preconditions are defined for CONTROL AREAS / BLOCKS in the UCTE: R1.1. Control program. A CONTROL AREA / BLOCK is capable to maintain the control program towards all other CONTROL AREAS / BLOCKS of the SYNCHRONOUS AREA at the scheduled value. R1.2. Control Hierarchy and Organisation. Each CONTROL AREA / BLOCK may divide up into sub-control areas that operate their own underlying generation control. A CONTROL BLOCK organises the internal SECONDARY CONTROL according to one of the following schemes (basically, the type of internal organisation must not influence the behaviour or quality of SECONDARY CONTROL between the CONTROL BLOCKS): Centralised: SECONDARY CONTROL for the CONTROL BLOCK is performed centrally by a single controller (as one CONTROL AREA); the operator of the block has the same responsibilities as the operator of a CONTROL AREA. Pluralistic: SECONDARY CONTROL is performed in a decentralised way with more than one CONTROL AREA; a single TSO, the BLOCK CO-ORDINATOR, regulates the whole block towards its neighbours with its own controller and regulating capacity, while all the other TSOs of the block regulate their own CONTROL AREAS in a decentralised way on their own. Hierarchical: SECONDARY CONTROL is performed in a decentralised way with more than one CONTROL AREA; a single TSO, the BLOCK CO- ORDINATOR, operates the superposed block controller which directly influences the subordinate controllers of all CONTROL AREAS of the CONTROL BLOCK; the BLOCK CO-ORDINATOR may or may not have regulating capacity on its own. R1.3. Area Demarcation. Each CONTROL AREA / BLOCK is physically demarcated by the position of the points for measurement of the interchanged power to the remaining interconnected network. R2. Responsible Operator. Each CONTROL AREA / BLOCK must be operated by an individual TSO that has the responsibility for the transmission system operation of this area (usually coincident with the territory of a company or a country), including the responsibility for availability, operation and provision of PRIMARY CONTROL and SECONDARY CONTROL within the CONTROL AREA / BLOCK to maintain the POWER INTERCHANGE of his CONTROL AREA / BLOCK at the scheduled value and, consequently, to support the restoration of FREQUENCY DEVIATIONS in the interconnected network. The operator is also responsible for accounting within its territory (see!p2). R3. Secondary Controller. In order to control the ACE (see!p1-b-c2) to zero, SECONDARY CONTROL must be performed in the corresponding control centre by a single automatic SECONDARY CONTROLLER, that needs to be operated in an on-line and closed-loop manner.

46 UCTE OH Policy 1: Load-Frequency Control (final policy 2.2 E, ) "P1 9 R3.1. Controller Type and Characteristic. In order to have no residual error, the SECONDARY CONTROLLER must be of PI (proportional-integral) type. The integral term must be limited in order to have a non-windup control action, able to react immediately in case of large changes or a change of the sign of the ACE. Measurement cycle times, integration times and controller cycle time must be co-ordinated. R3.2. Availability and Reliability. The automatic SECONDARY CONTROLLER, operated on-line and closed-loop, must have a high availability and must operate highly reliable. R3.3. Controller Cycle Time. The cycle time for the automatic SECONDARY CONTROLLER should be between 1 second and 5 seconds, to minimise the total time delay between occurrence, reaction and response in the scope of the overall control performance of the control area 7. R3.4. Programmed Values. Programmed values for SECONDARY CONTROL (e.g. for power exchanges and frequency set-points) must be entered into the controller as time-dependant set-point values based on schedules. See!P2 for details on scheduling. R3.5. Frequency Control. The gain for FREQUENCY CONTROL within SECONDARY CONTROL must be set to the K-FACTOR (see!p1-b-c1.2). In case of ISLAND operation (see!p1-b-c4) the SECONDARY CONTROLLER of a CONTROL AREA / BLOCK must perform automatic frequency control for the CONTROL AREA / BLOCK. R3.6. Power Exchange Set-Point Value. The algebraic sum of the programmed power exchanges between a CONTROL AREA / BLOCK and ADJACENT CONTROL AREAS / BLOCKS constitutes the POWER EXCHANGE set point of the CONTROL AREA S / BLOCK S SECONDARY CONTROLLER. R3.7. Ramping of Schedules. In order to prevent excessive FREQUENCY DEVIATIONS when changes of CONTROL PROGRAMS occur, it is necessary that each change be converted to a ramp with a ramp period of 10 minutes, starting 5 minutes before the agreed time of change (the change of the hour or of the quarter, see!p2 for definition of exchange schedules) and ending 5 minutes later. It is required that the ramping be performed in the same way by all controllers of the SYNCHRONOUS AREA. R3.8. Manual Control Capability. In case of deficiency of the automatic SECONDARY CONTROL, manual control action must be possible. R4. Secondary Control Reserve. An adequate SECONDARY CONTROL RESERVE must be available at all times to cover expected DEMAND fluctuations and the loss of a generating unit. If the loss of the largest generating unit is not already covered by the requisite SECONDARY CONTROL RESERVE, additional TERTIARY CONTROL RESERVE {15 MINUTE RESERVE} is required to offset the shortfall within a short time, see!p1-c. R4.1. Availability of Resources. Adequate SECONDARY CONTROL depends on generation resources made available by generation companies to the TSO. R4.2. Sufficient Controllable Generation. In each CONTROL AREA / BLOCK, sufficient controllable generation or load control (under automatic control) must be available in order to be able to control the AREA CONTROL ERROR to zero. R4.3. Backup by Tertiary Control Reserve. SECONDARY CONTROL keeps the CONTROL AREA S / BLOCK S balance, in normal operating conditions, and contributes to restore it, in case of a sudden unbalance due to an incident (see also!p1-a-c3). In case of a sudden large unbalance or a sustained DEMAND 7: In order to reflect current practice of SECONDARY CONTROL and operational experiences, the target value of 1 s to 2 s for the future of the former UCTE rule and recommendation has been replaced accordingly.

47 UCTE OH Policy 1: Load-Frequency Control (final policy 2.2 E, ) "P1 10 variation, TERTIARY CONTROL RESERVE is required to restore the SECONDARY CONTROL RESERVES (see!p1-c). R5. Tie-Lines. Certain criteria / characteristics need to be matched by different types of TIE-LINES that may be in use for SECONDARY CONTROL. R5.1. Transmission Lines, Transformers. The list of TIE-LINES of the CONTROL AREA / BLOCK in operation is maintained and updated on a regular basis. R5.2. Radial Operation of Generating Units. In case of the radial operation of generating units these are considered as internal generating units within the CONTROL AREA / BLOCK (e.g. using VIRTUAL TIE-LINES). R5.3. Jointly Owned Generating Units. Jointly owned generating (with GENERATION shares belonging to different CONTROL AREAS) shall be equipped with metering and measurement equipment providing function of VIRTUAL TIE-LINE between two or more CONTROL AREAS, unless the share of the production is delivered via SCHEDULE. R5.4. Metering and Measurement. All TIE-LINES from a CONTROL AREA to adjacent CONTROL AREAS (across the border) must have measurements and meters in operation to record the actual active (and reactive) power flow in MW (MVAr) in real-time and the energy in MWh in the time-frame for power exchanges that is used (one hour at the maximum, see!p2). R5.5. Transmission of Measurements. The measurements must be transmitted in a reliable manner to the SECONDARY CONTROLLER. R5.6. Accuracy of Measurements. The accuracy of the active power measurements on each TIE-LINE must be better than 1.5 % of its rated value (the complete measurement range, including discretisation). The measurement cycle time should not exceed 5 seconds and the measurement times of measurement values should not differ more than 5 seconds. Measurement cycle times, controller cycle times and controller integration times shall be coordinated. R6. System Frequency. The following requirements are defined for the use of the SYSTEM FREQUENCY for SECONDARY CONTROL: R6.1. Accuracy of Measurement. For SECONDARY CONTROL, the accuracy of frequency measurement must be between 1.0 mhz and 1.5 mhz (target value for the future). R6.2. Frequency Set-Point. The actual frequency set-point value (nominal value of 50 Hz, see!p1-a-c1) for TIME CONTROL (see!p1-d-s4) must be used within the SECONDARY CONTROLLER for calculation of the FREQUENCY DEVIATION, to be able to limit the deviation between SYNCHRONOUS TIME and UTC. R7. Data Recordings. Each TSO must be equipped with a recording of all values needed for monitoring of the response of (PRIMARY and) SECONDARY CONTROLLERS and for analysis of normal operation and incidents in the INTERCONNECTED SYSTEM. Standards S1. Operation of Secondary Control: Each TSO operates sufficient generating capacity under automatic control by the SECONDARY CONTROLLER to meet its obligation to continuously balance its generation and interchange schedules to its load for the CONTROL AREA / BLOCK. S2. Usage of Secondary Control. SECONDARY CONTROL must only be used in order to correct an AREA CONTROL ERROR. SECONDARY CONTROL must not be used for other purposes, e.g. to minimise unintentional power exchanges or to correct other imbalances. SECONDARY CONTROL shall not counteract PRIMARY CONTROL under

48 UCTE OH Policy 1: Load-Frequency Control (final policy 2.2 E, ) "P1 11 emergency conditions, with possible impact on the usage of SECONDARY CONTROL in such situations in a co-ordinated way. S3. Control Target. One quality criterion for SECONDARY CONTROL is the time taken for a CONTROL DEVIATION to return to zero, i.e. the time taken to restore the SYSTEM FREQUENCY to its set point value and to restore power interchanges to their set point (programmed) values. In practice, PRIMARY CONTROL action begins within a few seconds of a FREQUENCY DEVIATION, and takes full effect not more than 30 seconds later. Frequency and power interchanges must begin to return to their set point values as a result of SECONDARY CONTROL after 30 seconds, with the process of correction being completed after 15 minutes with a reasonable ramp rate and without overshoot. S3.1. Compliance with large Program Changes. In order to prevent unintentional FREQUENCY DEVIATIONS and major control deviations under normal operating conditions (see!p1-e-c1.1), system operators are required to maintain careful compliance with times for program changes, particularly where changes in the interchange program of several hundred MW are involved. In particular, care must be taken to ensure that generating capacity is brought on line or disconnected on a staggered basis, e.g. for tariff changes at 6 a.m. and 10 p.m, and that the ramp (see!p1-b-r3.7) is followed accurately. A substantial change in scheduling or the scheduled modification of power plant operation must not have a negative impact upon system operation. S4. K-Factor Settings. In order to ensure that SECONDARY CONTROL will only be called up in the CONTROL AREA / BLOCK which is the source of the disturbance, all controller values for K ri must match to the K-FACTORS (see!p1-b-c1). In this meaning, SECONDARY CONTROL must help PRIMARY CONTROL and must not counteract it in any case. Under no circumstances should K ri be modified during an incident, since this action would go against the principle of SECONDARY CONTROL. Guidelines G1. Secondary Controller. The following recommendations and guidelines are given for the setup of the SECONDARY CONTROLLER (see!p1-b-r3 for the complementary requirements on the SECONDARY CONTROLLER): G1.1. Controller Type and Characteristic. In case of a very large control deviation, the control parameters β i and T n of the SECONDARY CONTROLLER (for proportional and integral part) may be adjusted automatically for a given period of time. The control parameters β i, and T n are closely linked. At present, values ranging from 0 to 50% may be set for the proportional term β i of the area controller. The time constant represents the "tracking" speed of the SECONDARY CONTROLLER with which the controller activates the control power of participating generators. Values ranging from 50 seconds to 200 seconds may be set for the time constant T n. G2. Tie-Lines. The following recommendations are given for all TIE-LINES and related equipment that may be in use for SECONDARY CONTROL (see!p1-b-r5 for the complementary requirements on TIE-LINES): G2.1. Metering and Measurement. All TIE-LINE measurements in MW and MWh should be telemetered to both control centres affected (and in parallel to the co-ordination centre, if necessary), using commonly agreed primary equipment (e.g. the ELECTRONIC HIGHWAY, if applicable, see!p6). G2.2. Transmission of Measurements. The measurements shall be transmitted in a reliable manner to the SECONDARY CONTROLLER, at least two ways are recommended, with an alarm in case of deficiency of a data transmission. The largest transmission delay must not exceed 5 seconds; it must be as small as possible and below the controller cycle time.

49 UCTE OH Policy 1: Load-Frequency Control (final policy 2.2 E, ) "P1 12 G2.3. Substitute Measurements. Substitute measurements and reserve equipment should always be available in parallel to the primary measurement. Substitute measurements are obligatory for all TIE-LINES with major operational impact. Accuracy and cycle times for the substitute TIE-LINE measurements must fulfil the same characteristics (see!p1-b-r5). G3. Recommended Secondary Control Reserve. In CONTROL AREAS / BLOCKS of different sizes, load variations of varying magnitude must be corrected within approximately 15 minutes. To this end, the following minimum value for the SECONDARY CONTROL RESERVE related to load variations (derived from the empirical curve shown in the figure below) is recommended for a CONTROL AREA / BLOCK: R = a L max + b 2 b R = the recommendation for SECONDARY CONTROL RESERVE in MW L max = the maximum anticipated load in MW for the CONTROL AREA / BLOCK The parameters a and b are established empirically with the following values for the UCTE: a = 10 MW and b = 150 MW The following figure shows the recommended SECONDARY CONTROL RESERVE as a function of the maximum anticipated load: Procedures P1. Trumpet Curve Method. The trumpet curve method for NETWORK POWER FREQUENCY CHARACTERISTIC analysis is used after incidents, see description in detail in Appendix 1 (see!a1-b).