UCTE Operation Handbook

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union for the co-ordination of transmission of electricity

June 2004

Operation Handbook


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I N T R O D U C T I O N


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I Introduction to the UCTEOperation Handbook (OH) [E]

Chapters

A. UCTEs basic needs for the Operation Handbook

B. Target audience for the Operation HandbookC. 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 24.06.2004 UCTE Secretariat minor changes, OH developmentprocedure update

v2.4 draft 01.03.2004 OH Team minor changes

Current status

The "Union for the Co-ordination of Transmission of Electricity" (UCTE) is the association oftransmission system operators in continental Europe, providing a reliable market base byefficient and secure electric "power highways".

The UCTE (up to the 30th of June 1999 named UCPTE) has created a Survey of essentialUCPTE recommendations for the interconnected operation (dated 31st of December 1991)and important additional rules and recommendations on specific subjects after that date. Upto now (and if not already replaced by the Operation Handbook) these documents have beenin force in the UCTE.

The UCTE Operation Handbook (OH) is an up-to-date collection of operation principlesand rules for the transmission system operators in continental Europe. Additional referencesto 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 ofthe UCTE in general can be found on the UCTE Web site:

!http://www.ucte.org

This introduction is the cover paper for the operation handbook policies and appendices. Itincludes a general overview, the main characteristics and scopes of the handbook, adescription of the handbook structure with the table of contents as well as guides anddescriptions for readers. The glossary of terms is provided in a separate paper.

This version of the document (version 2.5, level E, dated 24.06.2004) has final status1.

This document and other chapters of the UCTE Operation Handbook as well as excerpts fromit may not be published, redistributed or modified in any technical means or used for anyother purpose outside of UCTE without written permission in advance.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.


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UCTE Operation Handbook Introduction (final v2.5 E, 24.06.2004) "I2

A. UCTEs 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 theoperational activities of transmission system operators in 22 European countries. Their

common objective is the security of operation of the interconnected power system. 50 yearsof joint activities laid the basis for a leading position in the world which the UCTE holds interms of the quality of synchronous operation of interconnected power systems. Through thenetworks of the UCTE, 450 million people are supplied with electric energy; annual electricityconsumption totals approx. 2100 TWh.

Close co-operation of member companies is required to make the best possible use ofbenefits offered by interconnected operation. For this reason, the UCTE has developed anumber of technical and organisational rules and recommendations in the past that constitutea common reference for smooth operation of the power system. The UCTE OperationHandbook is the successor to these sets of rules and recommendations, that have beencontinually developed during the decades of construction and extension of the power systemsince 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 setstandards in terms of security and reliability as in the past. Moreover, the stronginterconnections in the UCTE grid require common understandings for grid operation, controland security in terms of fixed technical standards and procedures. They are comprised in thisUCTE Operation Handbook in an organised form to make consultation easier for membersand the general public.


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C. UCTE System Overview

For the sake of general information and orientation, the following figures show maps of theUCTE system in the overview:

the map of the complete UCTE interconnected network / transmission system of 2003(available from UCTE at !http://www.ucte.org/),


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UCTE Operation Handbook Introduction (final v2.5 E, 24.06.2004) !I4

the political map (by countries, membership, connection status) of the UCTESYNCHRONOUS ZONES as of 2004,

the structure and organisation of the CONTROL BLOCKS /AREAS of the UCTESYNCHRONOUS AREA by countries/companies

Acc.

Acc. Area

FEP

P

D

A

PL

CZ

CH

I

CENTREL

E

SLO

NL

B

F

7

E.ON VEAGBEWAG

RWE UCTE

UCTE SouthGR

RO BG

D

MORHR BIH

JIEL

SRCG

AL

EKCMK

Acc.

Acc. AreaAcc.

Acc. Area

FEP

P

D

A H

PL

CZ

SK

CH

I

CENTREL

E

SLO

NL

B

F

7

E.ONVE-T

RWE UCTE

UCTE SouthGR

RO BG

D

MORHR BIH

JIEL

SRCG

AL

EKCMK

VKW

EnBWCEGEDELTIRAG

UKR


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B. Target audience for the Operation Handbook

The UCTE Operation Handbook shall support consultation and provide assistance todifferent 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 tofollow the technical standards and procedures that are comprised in this UCTE OperationHandbook (main focus of the handbook). This Operation Handbook therefore serves asthe reference (legislation) for the grid operation by the TSOs and guarantees theUCTEs quality and reliability standards.

Generation Companies (GENCOs). Every party operating a generating unit in the UCTEinterconnected network (SYNCHRONOUS AREAS) makes use of the transmission networkand may have to deliver products for the provision of system services that areindispensable for secure and stable grid operation. The Operation Handbook sets

standards for the essential requirements and capabilities regarding generation thatcontribute to the operation of the grid by the TSOs.

Other associations, traders, customers, politicians and decision makers. Operationof an interconnected transmission system is bound to physical principles and technicalconstraints, that differ significantly from other well-known technical or financial systems.This Operation Handbook explains these differences and characteristics in a transparentmanner to the public for a better understanding. It can also serve as a general referencedocument.


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D. Main characteristics of the Operation Handbook

The following main characteristics of the UCTE Operation Handbook serve as a guidelinefor the development and set-up of the handbook:

Transparency. Technical and physical principles of transmission grid operation in theUCTE are clearly described and published in the Operation Handbook also for non-experts.

Liability. Following the Articles of Association of the UCTE, as they have been signed byall members, the standards and recommendations of the Operation Handbook weredeveloped as binding for all members (including associated members) of the UCTE andtheir operation of the grid.

Unambiguousness. All standards and recommendations of the Operation Handbook arewritten to be straightforward and unmistakable for the processes of secure operation ofthe UCTE SYNCHRONOUS AREA(S). All terms used in the handbook are defined only once.

Relevance to the present. Standards and recommendations included in the OperationHandbook are continually adapted to the changed technical and legislative environment. Aversion history clearly shows the status of each part of the handbook.

Minor Redundancy. The Operation Handbook is written to have only the minimum ofredundancy that is required. For this purpose, references to other chapters within thehandbook are used instead.

Modularity. Each chapter, policy, rule and guideline of the Operation Handbook can beseen as a separate document that may be revised independently of the other parts. Allchapters use a similar layout and internal structure.


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E. Main scope of the Operation Handbook

The main objective of the UCTE Operation Handbook as a comprehensive collection of allrelevant technical standards and recommendations is to provide support to the technicaloperation of the UCTE interconnected grid (SYNCHRONOUS AREAS), including operation

policies for generation control, performance monitoring and reporting, reserves, securitycriteria and special operational measures. The basic subject of the Operation Handbook is toensure the interoperability among all TSOs connected to the SYNCHRONOUS AREAS.

Standards for network access of customers, network tariffs, accounting, the commercial partof unintentional deviations, billing procedures and market rules as well as other standardsthat may be set by national GridCodes, laws or contracts are not within the scope of thisOperation Handbook (see next figure).

UCTE Interconnected Network

UCTE Operation Handbook! Rules for Interconnection

Transmission and

Distribution Network

GridCodes /Laws /Contracts! Rules forGrid Access

...


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F. Basic structure of the Operation Handbook

The UCTE Operation Handbook clearly differentiates between policies, technicalappendices, training documents and data collections (in independent documents) and isbasically 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 ANCILLARYSERVICES)

Technical appendices (technical criteria, definitions)

Training documents (calculation methods, theory)

Collections of data

The formal structure of the operation handbook into policies and appendices, eachdocument 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 mainsections:

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 asrecommendations, as they may be used by the addressees.

Procedures (P). Procedures introduce fixed methods and alternatives for operation orusage 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.


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G. Guide for handbook readers

The operation handbook makes use of the following internal reference schemes:

$document [-chapter [-section]] #chapter [-section] "document pageThe 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 thereference can also be #A only).

$P1-A-C1 is used as reference to the first criterion of section A in policy 1. Thesame scheme is used for requirements, standards, guidelines, procedures andmeasures.

Pages are numbered by the document identifier (P1 for Policy 1) followed by thepage 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 guidefor readers can be given:

As a good starting point, it is recommended to start reading with this introductiondocument ($I). Basic principles and frameworks for the complete handbook aredescribed here in detail. Moreover, the introduction includes the full table of operationpolicies that are part of the handbook.

The glossary of terms ($G) needs to be consulted as a reference only. All terms thatare formatted in CAPITALISED letters can be found in the glossary of terms. In case ofunknown 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 theintroduction of the policy and to consult the corresponding appendices ($A#), beforereading the requirements, standards and guidelines. The appendices usually give ageneral motivation and technical description of the subjects, that is required forreading the policies.

The policies themselves ($P#) are organised in independent chapters (starting withA), each of them in sections (identified by letters C, R, S, G, P and M, see above) withnumbered paragraphs. Before reading and understanding a policy it is necessary tohave background knowledge on the subjects. There is no definite way how to read apolicy, usually it is best to start at the beginning. Internal references may point to otherparagraphs of this policy before or after the current paragraph, external referencesmay point to other policies or appendices as well.

For easy reading, the first pages of policies and appendices are commonly organised in thefollowing layout:


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P# Policy #: Title [Level]

Chapters

A. Chapter A

B. Chapter B

C. Chapter C

Introduction

Introduction

History of changes

v#.# draft 01.12.2003 developer changes

Current Status

Status information

General notices


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H. Procedure for handbook development

Following is the description of the development process procedure with the flow chartshowing the procedure.

The Operation Handbook development process involves following steps:

1. Process initiation2. Drafting stage3. Internal consultation4. Decisions on external consultation5. External consultation6. Final approval7. Policy implementation

STEP 1

Process initiation

Requests to revise or develop the Policy are submitted to the Steering Committee by theWorking Group Operations and Security (WG OS) with a short description of the Policy to berevised or drafted newly. Alternatively, the process is initiated by the Steering Committee. TheSteering 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 stageof 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 revisedPolicy. 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 canbe sent only by using consultation forum on the UCTE website till the date announced byUCTE Secretariat. The minimum period for internal consultation is 1 month. Based on thecomments, 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 forpresenting it for external consultation. The bodies can approve the draft Policy for the externalconsultation or return it for further work to the Drafting Team with a clear statement on how toproceed and what to adapt.

STEP 5

External consultation

Once the Policy is approved by the Steering Committee for the external consultation, it ispublished 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 theconsultation process will be determined by the WG OS or UCTE Secretariat. Comments onthe 2nd draft will be actively solicited from all registered participants. Comments will beaccepted only on-line using an internet-based consultation forum. All UCTE members willhave to substantiate their position, i.e. that also those who do not want to comment will have


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to state it. Based on its own review, the Drafting Team revises the draft Policy as needed andpresents it to the WG OS.

STEP 6

Final approval

WG OS approves the Policy and sends the final draft including change marks and forinformation list of rejected comments to the Steering Committee for final approval. If the WGOS does not approve the Policy, it may return the draft to the Drafting Team for further workwith 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 meetings agenda. Ifthe Policy is not approved, the Steering Committee may return the Policy to the DraftingTeam for further work with a clear statement on what to adapt or it may terminate the Policydevelopment.

STEP 7

Policy implementation

Once the Steering Committee approves a new or modified Policy all members are expectedto implement and follow the Policy in accordance with all accepted UCTE rule.


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UCTE Secretariat&Draftin Team

UCTE O eration Handbook

Drafting Team

WG O erations & Securit

UCTE Steerin Committee


1st Draft of new Standard B

Internal consultation

2nd Draft of new Standard C

Decision

Decision

Decision

Final new UCTE Standard [E]

For external consultation

For development

Rejection

Rejection

Revision

Revision

2nd Draft of new Standard C

Re uests, modifications

Table of contents / to ics A

Development

UCTE Secretariat&Draftin Team

External consultation

WG O erations & Securit

Final Draft of new Standard D


Final Draft of new Standard D

DecisionRevision

STEP 1

STEP 2

STEP 4

STEP 5

STEP 6

STEP 7

STEP 3

WG Operations & Security

Requests, modifications

Decision

Decision

For implementation


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The status of policies and appendices during procedure is rated according to the followinglegend:

Level Description

A Table of contents

B Preliminary internal draft

C Consultation draft

D Final draft ready for approval by the WG and SC

E 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 OperationHandbook 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


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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 Title, contents

I Introduction

A. UCTEs 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

G 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 schedulingF. Information exchanges between TSOs for security of system operation

P4 Co-ordinated Operational Planning

A. Outage Scheduling


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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. E-Mail 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 ExchangesA. Code of conduct and generic rules to handle the data

P8 Operational Training

Appendixes:

ID Title, contents

A1 Load-Frequency-Control and Performance

A. Primary Control

B. Secondary Control

C. Tertiary Control

D. Time Control


A2 Scheduling and Accounting

A. Scheduling of Power Exchange

B. Online Observation of Power Exchange

C. Accounting of Unintentional Deviations


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J. Contacts and Links

For questions concerning Operation Handbook development process and consultationprocess please contact Jakub Fijalkowski at [email protected].

For all other information, please contact the UCTE-Secretariat:

15 Boulevard Saint-Michel1040 BrusselsBelgium

Tel: +32 2 741 69 40Fax: +32 2 741 69 49E-mail: [email protected]


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G L O S S A R Y


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G Glossary [E]

Chapters

A. Glossary of terms

B. List of acronyms

C. List of units

History of changes

v2.2 draft 24.06.2004 UCTE Secreteriat glossary update

v2.1 draft 12.05.2004 UCTE Secretariat new terms added

v2.0 draft 01.03.2004 OpHB-Team minor changes, linguistic review

Current status

This glossary is a growing list of terms1

, acronyms and units commonly used in the policies andappendices 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 24.06.2004) 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 ([email protected]) or to

the secretary of the UCTE WG Operations & Security ([email protected]).


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UCTE Operation Handbook Glossary (final v2.2 E, 24.06.2004) !G2

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, 08.1996, 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 ofUNINTENTIONAL DEVIATIONS across a set ofOBSERVATION 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 thescheduling phase;

acquisition of the EMRs values ofTIE-LINES2 among CONTROL BLOCKS to compute the provisionalenergy 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 theirCONTROL 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.

2Including virtual TIE-LINES that may exist for the operation of jointly owned power plants.


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Adjacent Control Area {Adjacent System} ("P1-B)

An ADJACENTCONTROL 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 (REACTIVEPOWER), 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 ofSECONDARY 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).

AvailabilityAVAILABILITY 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


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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.

CapacityCAPACITY 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 ofUNINTENTIONAL 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 ofSECONDARY 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 ("P2)

A CONTROL AREA OPERATOR is the operator of a CONTROL AREA usually a TSO.

Control Block Operator ("P2)

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.


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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 ("P5)

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.

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 generallyexpressed 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.


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Electronic Highway (EH) ("P6)

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) ("

P2)ENERGY METER READINGS are performed (in addition to those for internal lines, transformers, generators

and LOADS) for actual energy exchanges on TIE-LINES3

between CONTROL BLOCKS (ofCONTROL 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 EXCHANGESCHEDULE 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 ("P1)

FREQUENCY DEVIATION means a departure of the actual SYSTEM FREQUENCY from the set valuefrequency.

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.

3Including virtual tie-lines that may exist for the operation of jointly owned power plants.


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Generation Set ("P1)

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.

InterconnectionAn INTERCONNECTION is a transmission link (e.g. TIE-LINE or transformer) which connects two

CONTROL AREAS.

Intra-Control-Area Transaction

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 ofLOAD from the synchronous electric system, usually performed

automatically, to control the SYSTEM FREQUENCY in emergency situations.


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Loop Flows

See: PARALLEL PATH FLOWS.

Metering

METERING describes the methods of applying devices that measure and register the amount and directionof 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 bus-

bar) 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 ofSECONDARY 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 SYNCHRONOUSAREA, 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 fromthe rest of the system for the purpose of real-time error detection and preliminary calculation of

UNINTENTIONAL DEVIATIONS. It must run along the borders ofCONTROL BLOCKS and must not split any

CONTROL BLOCK.


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Offsetting of Unintentional Deviations ("P2)

OFFSETTING OF UNINTENTIONAL DEVIATIONS describes a procedure applied to carry out the

compensation in energy ofUNINTENTIONAL 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-lineOBSERVATION 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 ofUNINTENTIONAL 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, unscheduledpower 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 AREA4, 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

4Power 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.


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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 theSYNCHRONOUS 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 theDROOP 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 ofPRIMARY CONTROL POWER, within whichPRIMARY 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 ControlSee: 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 ontransmission 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.


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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 energyrequirements 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 shortcircuits 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 afterthe 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 ofSECONDARY CONTROL.

5To 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.


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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 ofSECURITY 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 partswhen 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. T IME 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 ofseconds (with minor differences between different measurement locations only).


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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 ofan 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 ("P1-D,"A1-D)

TIME CONTROL is a control action carried out to return an existing TIME DEVIATION between

SYNCHRONOUS TIME and UTC time to zero.

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 ofTRANSMISSION 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 ofSECONDARY CONTROL

Emergency exchanges between TSOs to cope with unexpected unbalanced situations in real-time

Inaccuracies, e. g. in data collection and measurements


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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.


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B. List of Acronyms

AAC Already Allocated Capacity

ACE Area Control Error

AGC Automatic Generation ControlATC Available Transmission Capacity

BRP Balance Responsible Party

CA Control Area

CAS Control Area Schedule

CAX Control Area Exchange

CB Control Block

CBS Control Block Schedule

CBX Control Block Exchange

CC Control CentreCCS Co-ordination Centre Schedule

CoC Co-ordination Centre

CP Control Program

DACF Day Ahead Congestion Forecast

EH Electronic Highway

EIC ETSO Identification Code

EMR Energy Meter Reading

ESS European Scheduling System

ET Tie-line FlowsEVT Virtual Tie-line Flows

GENCO Generation Company

GMT Greenwich Mean Time

GPS Global Positioning System

HV High Voltage

LFC Load-Frequency Control

NTC Net Transfer Capacity

OpHB Operation Handbook

PI Proportional-Integral

SCADA Supervisory Control and Data Acquisition

SVC Static Var Compensator

TM Tele-measurement

TSO Transmission System Operator

TRM Transmission Reliability Margin

TTC Total Transfer Capacity

UCTE Union for the Co-ordination of Transmission of Electricity

UD Unintentional Deviation

UHV Ultra High Voltage

UTC Universal Time Co-ordinated

WAMS Wide Inter-Area Measurement System


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C. List of Units

A ampere

d day

GW gigawatt (1.000.000.000W)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 (1.000.000W)

MWh megawatt-hour

s, sec second

TW terawatt (1.000.000.000.000W)

V voltW watt


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L O A D - F R E Q U E N C Y C O N T R O L

A N D P E R F O R M A N C E

P O L I C Y 1


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P1 Policy 1: Load-Frequency Controland Performance [E]

Chapters

A. Primary Control

B. Secondary ControlC. Tertiary Control

D. Time Control


Introduction

The GENERATION of power units connected to the UCTE network needs to be controlled andmonitored for secure and high-quality operation of the SYNCHRONOUS AREAS. The generationcontrol, the technical reserves and the corresponding performance measurements are

essential to allow TSOs to perform daily operational business. Control actions are performedin different successive steps, each with different characteristics and qualities, and alldepending on each other:

PRIMARY CONTROL (see section !P1-A) starts within seconds as a joint action of allundertakings involved.

SECONDARY CONTROL (see section !P1-B) replaces PRIMARY CONTROL after minutes andis put into action by the responsible undertakings / TSOs only.

TERTIARY CONTROL (see subsection !P1-C) frees SECONDARY CONTROL by re-schedulinggeneration and is put into action by the responsible undertakings / TSOs.

TIME CONTROL (see subsection !P1-D) corrects global TIME DEVIATIONS of theSYNCHRONOUS 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 detaileddefinitions of terms used within this policy and to Appendix 1 (see !A1) for basics andprinciples of load-frequency control and performance.

History of changes

v2.2 draft 20.07.2004 Final wording

v2.1 draft 17.06.2004 OH-Team Changes after consultation

Current status

This document summarises current UCTE rules and recommendations relating to load-frequency control and performance issues in a new structure, with additional items describingtodays common practice.

This policy replaces previous UCTE ground rules and recommendations regardingPRIMARYandSECONDARY frequency and activePOWER CONTROL, regulation reserves and correction ofSYNCHRONOUS TIME. This version of the document (version 2.2, level E, dated 20.07.2004)has final policy status.

This document and other chapters of the UCTE Operation Handbook as well as excerpts fromit may not be published, redistributed or modified in any technical means or used for anyother purpose outside of UCTE without written permission in advance.


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UCTE OH Policy 1: Load-Frequency Control (final policy 2.2 E, 20.07.2004) "P12

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 andconsumption (DEMAND) within the SYNCHRONOUS AREA, using turbine speed or turbinegovernors. By the joint action of all interconnected undertakings / TSOs, PRIMARY CONTROLaims at the operational reliability of the power system of the SYNCHRONOUS AREA andstabilises the SYSTEM FREQUENCY at a stationary value after a disturbance or incident in thetime-frame of seconds, but without restoring the reference values of SYSTEM FREQUENCY andpower exchanges (see !P1-B for SECONDARY CONTROL). Adequate PRIMARY CONTROLdepends 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 latestUCPTE-Ground Rules concerning primary and secondary control of frequency and activepower within the UCPTE, dated 1998.

Criteria

C1. Nominal frequency. The set-point frequency (or scheduled frequency) f0 (see !P1-D) defines the target value of the SYSTEM FREQUENCYffor system operation. Outsideperiods for the correction of SYNCHRONOUS TIME (see !P1-D), the nominal frequencyvalue in the SYNCHRONOUS AREA is 50 Hz.

C2. Frequency deviations. A FREQUENCY DEVIATIONf (the departure ff0 of the actualSYSTEM FREQUENCY f from the scheduled frequency f0) results from a disturbance oran incident and may occur during normal system operation. Different criteria are usedto distinguish the size of this deviation:

C2.1. Calling up of Primary Control. To avoid calling up of PRIMARY CONTROL inundisturbed 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 frequencymeasurement 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 conditionof SELF-REGULATION OF THE LOAD according to!P1-A-C4).

C2.3. Minimum Instantaneous Frequency. The instantaneous frequency must notfall below 49.2 Hz (that corresponds to -800 mHz as maximum permissibledynamic FREQUENCY DEVIATION from the nominal frequency !P1-A-C1) inresponse to a shortfall in generation capacity equal to or less than thereference 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 SYSTEMFREQUENCY of 49.0 Hz (or below). The detailed step-plans for LOAD-SHEDDING(in the responsibility of the TSOs, with the possibility to perform earliershedding of pumping units at higher frequency value as an operationalmeasure, with the lowest value of 47.5 Hz and the need of progressive stagesin between) define additional frequency criteria for further measures.

C2.5. Maximum Instantaneous Frequency. The instantaneous frequency must notexceed 50.8 Hz (that corresponds to +800 mHz as maximum permissibledynamic FREQUENCY DEVIATION from the nominal frequency !P1-A-C1) inresponse to a loss of load or interruption of power exchanges equal to or lessthan the reference incident according to !P1-A-C3.


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UCTE OH Policy 1: Load-Frequency Control (final policy 2.2 E, 20.07.2004) !P13

C3. Reference Incident. The maximum instantaneous deviation between generation anddemand in the SYNCHRONOUS AREA (by the sudden loss of generation capacity, load-shedding / loss of load or interruption of power exchanges) to be handled by PRIMARYCONTROL starting from undisturbed operation depends on the size of the area / zone1and on the size of the largest generation unit or generation capacity connected to asingle bus bar located in that area2.

C3.1. First Synchronous Zone. For the first synchronous zone as in 2003 themaximum power deviation to be handled is 3000 MW, assuming realisticcharacteristics concerning system reliability and size of loads and generationunits.

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 (UCTESYNCHRONOUS AREAS), that are not connected to the main synchronous zone,the size of the reference incident needs to be defined in each particular casewith respect to the size of the area and the size of the largest generation unitslocated in that area.

C3.4. Observation Incident. Incidents, such as the sudden loss of generation orload, that exceed 1000 MW in the first synchronous zone or 250 MW in thesecond synchronous zone are considered to be relevant for systemobservation in that zone3.

C4. Frequency Characteristics. Key values of the frequency characteristics are definedon the basis of system observation4.

C4.1. Self-Regulation of Load. The self-regulation of the load in all SYNCHRONOUSAREAS is assumed to be 1 %/Hz, that means a load decrease of 1 % occurs incase of a frequency drop of 1 Hz.

C4.2. Security Margin. For FREQUENCY CONTROL, a static security margin of 20 mHzis 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 ofPRIMARY CONTROL is a few seconds starting from the incident, the deployment time for50 % or less of the total PRIMARY CONTROL RESERVE is at most 15 seconds and from50 % to 100 % the maximum deployment time rises linearly to 30 seconds.

C6. Frequency Change Indicators. For special use in a post-operation analysis, thefollowing criteria are defined to measure the characteristics of absolute changes of theSYSTEM 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 theBalkan war) are temporal only due to the planned reconnection of the UCTE area. The reconnection isscheduled for 2005. The system load for the first SYNCHRONOUS AREA typically varies between 150 GWoff-peak and 300 GW peak.

2: The final values used in the definition of the reference incidents are determined by the UCTE SGTSO-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 finallyconfirmed by the UCTE WG Operations and Security and the UCTE SC. The values given are underconsideration.


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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 arebased 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, peakdown, peak up down and peak down up.

C6.4. Peak Frequency Range within Period. The peak frequency range iscalculated as the difference between the maximum and the minimumfrequency within the given period of time.

C6.5. Peak Frequency Derivative within Period. The peak frequency derivative isdetermined as the maximum or minimum derivative of the frequency within thegiven period of time.

Requirements

R1. Accuracy of Frequency Measurements. For PRIMARY CONTROL, the accuracy of localfrequency measurements used in the PRIMARY CONTROLLERS must be better than orequal to 10 mHz.

R2. Insensitivity of Controllers. The insensitivity range of PRIMARY CONTROLLERS shouldnot exceed 10 mHz. Where dead bands exist in specific controllers, these must beoffset within the CONTROL AREA/BLOCK concerned.

R3. Primary Control Reserve. PRIMARY CONTROL RESERVE needs to have certaincharacteristics to be usable for PRIMARY CONTROL.

R3.1. Reserve Distribution. In general, the PRIMARY CONTROL RESERVE must bephysically 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) requiredfor operation of a SYNCHRONOUS AREA is of the same size as the referenceincident for that area (see !P1-A-C3).

R3.3. Availability of Reserves. In total and as a minimum, the full PRIMARY CONTROLRESERVE for each area must be available continuously without interruption, notdepending 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-steady-

state FREQUENCY DEVIATION of 200 mHz or more.R4. Network Power Frequency Characteristic. The NETWORK POWER FREQUENCY

CHARACTERISTIC describes the real dependency between SYSTEM FREQUENCY andPOWER IMBALANCE with a linear approximation.

R4.1. Constant Network Power Frequency Characteristic. In order to ensure thatthe principle of joint action is observed, the NETWORK POWER FREQUENCYCHARACTERISTICS of the various CONTROL AREAS is taken to remain asconstant as possible. This applies particularly to small FREQUENCY DEVIATIONS,where the "dead bands" of generators may have an unacceptable influenceupon the supply of PRIMARY CONTROL energy in the CONTROL AREASconcerned.

R4.2. Share of Primary Control. The NETWORK POWER FREQUENCY CHARACTERISTICof 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) to15000 MW/Hz.


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R4.3. Share of Self-Regulation. . The NETWORK POWER FREQUENCYCHARACTERISTIC of SELF-REGULATION only for the first synchronous zone iscalculated out of !P1-A-C4.1 and!P1-A-C3 to 3000 MW/Hz.

R4.4. Overall Network Power Frequency Characteristic. The overall NETWORKPOWER FREQUENCY CHARACTERISTIC for the first synchronous zone is set to18000 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 anundisturbed situation, PRIMARY CONTROL must maintain reliable system operation.

S2. Primary Control Action. The action of the individual generators performing PRIMARYCONTROL must have the following characteristics, to be ensured by all TSOs:

S2.1. Adjustment of Generation. Power generation under PRIMARY CONTROL mustbe constantly adjusted to follow changes of SYSTEM FREQUENCY.

S2.2. Deployment. Total PRIMARY CONTROL within the entire SYNCHRONOUS AREA (aswell as within each CONTROL AREA/BLOCK) must follow the deployment timesof PRIMARY CONTROL RESERVE (see !P1-A-C5). Each TSO must check thedeployment times within his CONTROL AREA/BLOCK on a regular basis.

S2.3. Duration of Delivery. PRIMARY CONTROL POWER must be delivered until thepower deviation is completely offset by the SECONDARY CONTROL RESERVE ofthe CONTROL AREA / BLOCK in which the power deviation has occurred (theminimum duration for the capability of delivery for primary control is 15minutes, see!P1-B).

S3. Primary Control Target. Starting from undisturbed operation (see !P1-A-C2), areference incident (see!P1-A-C3) must be offset by PRIMARY CONTROL alone, withoutthe 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, theFREQUENCY 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 actionto ensure system reliability and interconnected operation. This includes an overalldistribution of reserves and control actions, as determined and decided by the UCTESG TSO-Forum on an annual basis for the next calendar year.

S4.1. Contributions to Primary Reserves. Each CONTROL AREA / BLOCK mustcontribute to the PRIMARY CONTROL RESERVE as required. The respectiveshares are defined by multiplying the calculated reserve for the entireSYNCHRONOUS AREA (see !P1-A-R3 and !P1-B) and the contributioncoefficients ci of the various CONTROL AREAS/BLOCKS. The sum of all sharesmust amount to the total PRIMARY CONTROL RESERVE.

S4.2. Contribution to Control. Each CONTROL AREA/BLOCK must contribute to thecorrection of a disturbance in accordance with its respective contributioncoefficient ci for PRIMARY CONTROL.

S4.3. Contribution Coefficients. The contribution coefficients must be determinedand published annually for each CONTROL AREA / BLOCK. The contributioncoefficients are binding for the corresponding interconnection partner / TSO forone calendar year. They are based on the share of the energy generatedwithin one year in relation to the entire SYNCHRONOUS AREA. The sum of allcontributions coefficients must amount to 1.


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Procedures

P1. Contribution Coefficients. The UCTE SG TSO-Forum determines and decidesabout the contribution coefficients of each CONTROL AREA / BLOCK for eachSYNCHRONOUS ZONE on an annual basis (published before the 1st of December) andsets these values into operation on the 1st of January of the next year.

P2. Observation of Outages. Outages in production or consumption exceeding the sizeof the observation incident (see !P1-A-C3) are recorded for analysis. Thecorresponding 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 SYSTEMFREQUENCY is made according to that of the following procedures.

P3.1. Frequency Change Analysis. The frequency change analysis5, see appendix,uses the frequency change indicators (see !P1-A-C6) for evaluation andcomparison.

P4. Control Performance Measurement. The NETWORK POWER FREQUENCY

CHARACTERISTIC is calculated in response to a disturbance (such as an observationincident), based on measurements of the SYSTEM FREQUENCY and other key valuesand on a statistical analysis.

P4.1. Control Performance Report. UCTE publishes results of a controlperformance analysis on a regular basis in the Regular Report of thePerformance 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 SYSTEMFREQUENCY for central system observation must be in the range of 1 second (stronglyrecommended) to at most 10 seconds.

5: Also known as frequency measurement campaign.


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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 theSYNCHRONOUS AREA, taking into account the CONTROL PROGRAM, without impairing thePRIMARY CONTROL that is operated in the SYNCHRONOUS AREA in parallel but by a margin ofseconds (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 ofseconds to typically 15 minutes. SECONDARY CONTROL is based on SECONDARY CONTROLRESERVES that is under automatic control. Adequate SECONDARY CONTROL depends on

generation resources made available by generation companies to the TSOs. Please refer toAppendix 1 (see!A1-B) for basics and principles of SECONDARY CONTROL.

This policy section replaces the corresponding sections for secondary control in the latestUCPTE-Ground Rules concerning primary and secondary control of frequency and activepower within the UCPTE, dated 1998.

Criteria

C1. K-Factor. The K-FACTOR defines the dependency between SYSTEM FREQUENCY anddeviation 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 theuncertainty of the SELF-REGULATING effect.

C1.2. K-Factor Calculation. The K-FACTOR Kri of a CONTROL AREA / BLOCK forSECONDARY CONTROL is calculated by the product of the frequency control gain1.1 (see !P1-B-C1.1), the contribution coefficient ci 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 SECONDARYCONTROL in the FIRST SYNCHRONOUS ZONE amounts to 19801 MW/Hz for theyear 2004. The total K-FACTOR for SECONDARY CONTROL in the SECONDSYNCHRONOUS ZONE comes to 3301 MW/Hz for the year 20046.

C2. Area Control Error. Within each CONTROL AREA/BLOCK, the individual AREA CONTROLERROR G (ACE) needs to be controlled to zero on a continuous basis. The ACE iscalculated 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 Pof a CONTROL AREA/BLOCKis the total POWER DEVIATION of that area in interconnected operation,calculated as the difference between the total active power flow (sum of allrelated measurements) and the CONTROL PROGRAM (sum of all relatedexchange 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 DEVIATIONf (see !P1-A-C2)and the K-FACTOR of the CONTROL AREA/BLOCKKri (see!P1-B-C1.2).

6: The final values are determined by the UCTE SG TSO-Forum on a regular basis.


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C3. Secondary Control Deviation. A disturbance or an incident (inside or outside of theCON

UCTE Operation Handbook

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