Protection coordination, also known as discrimination or selective tripping, is a

fundamental aspect of power system design. Its primary objective is to ensure

that when a fault occurs, only the necessary circuit breakers operate to isolate
the faulty section of the power system, leaving the healthy parts undisturbed
and minimizing disruption to the supply. This is crucial for safeguarding
continuity of supply, protecting expensive equipment from damage, and
ensuring the safety of personnel and property.
General Principles of Protection Coordination
The core principles to achieve correct discrimination include:
1. Isolation of Faulty Sections: The protection scheme must accurately
identify and isolate only the part of the network experiencing a fault.
2. Speed: Faults should be cleared as rapidly as possible to limit
consequential damage, maintain system stability, and safeguard
continuity of supply.
3. Reliability: The protection system must operate dependably when
required and, equally importantly, remain stable and refrain from
operating for conditions outside its protected zone (e.g., through-faults or
external events).
4. Sensitivity: Relays and protection schemes should be sensitive enough to
detect minimum fault conditions within their zone.
5. Zones of Protection: The power system is divided into overlapping
protection zones to ensure no part is left unprotected. The circuit breaker
is typically included in both adjacent zones where they overlap.
Methods of Protection Coordination
Protection coordination is generally achieved through two primary methods:
1. Time Grading: This method involves setting protection systems in
successive zones to operate with graded time delays. The relay closest to
the fault operates fastest, while upstream relays are progressively
delayed. This ensures that only the relevant device completes the tripping
function, with others resetting if the fault is cleared by a downstream
device. The speed of response in time-graded systems can depend on the
fault severity and is generally slower than unit systems.
2. Unit Systems (Differential Protection): These protection systems are
designed to respond exclusively to fault conditions occurring within a
clearly defined and restricted zone. They operate by comparing electrical
quantities (e.g., current magnitude and phase) at the boundaries of the
protected zone, typically defined by current transformer (CT) locations.
Unit protection is generally fast, with its speed of response being largely
independent of fault severity, and provides inherent discrimination.
Examples include restricted earth fault and differential protection.
Distance protection, while often operating as a non-unit system in its basic form,
can be adapted to create a unit protection scheme when combined with a
signalling channel. Its coordination relies on careful selection of reach settings
and tripping times for its various zones of measurement.
Protection Coordination in Extra High Voltage (EHV) Power Systems
In EHV systems, the stakes for protection coordination are exceptionally high due
to the critical impact of faults on system stability and synchronism. Fast and
reliable fault clearance is paramount.
 Multiple Primary Protection Systems: For EHV systems, it is common
practice to use multiple primary (main) protection systems operating in
parallel. These systems may be of different types (e.g., distance and unit
protection) to ensure redundancy, speed, and reliability. Back-up
overcurrent protection may also be applied to provide coverage during
maintenance of primary systems. At the highest transmission voltages,
rapid fault clearance often demands two independent protection systems.
 Distance Protection Schemes: Distance protection is widely applied in
EHV systems due to its ability to provide fast operation largely
independent of source impedance variations and its capability for both
primary and remote back-up.
o Zone Settings: EHV distance relays typically have multiple zones
with carefully chosen reach and time settings for coordination.
 Zone 1: Set for instantaneous operation, covering 80-85% of
the protected line. A safety margin of 15-20% is maintained
to prevent over-reaching into the adjacent line section and
losing discrimination.
 Zone 2: Time-delayed, set to cover the remaining portion of
the protected line (at least 120% of line impedance) and
often extended to include 50% of the shortest adjacent line.
This setting helps avoid the need for time grading between
Zone 2 of the protected line and Zone 1 of the adjacent line.
 Zone 3: Provides remote back-up protection for faults on
adjacent lines, with a longer time delay to discriminate with
Zone 2 protection of the adjacent line.
o Teleprotection Schemes: To achieve instantaneous tripping
across the entire feeder length in EHV systems, basic distance
protection is often enhanced with teleprotection signalling channels.
These communication-assisted schemes (e.g., Zone 1 Extension,
Transfer Tripping, Blocking Schemes) transmit information between
relays to speed up or prevent tripping, ensuring rapid and selective
fault clearance.
 Auto-Reclosing: High-speed auto-reclosing is critical for EHV overhead
lines to maintain system stability after transient faults. This necessitates
high-speed protection (e.g., distance or unit schemes with <40ms
operating times) and fast circuit breakers. Ensuring simultaneous tripping
at both ends of a faulted line is crucial for successful high-speed reclosure.
 Zone 1 extension schemes are frequently used in conjunction with auto-
reclose relays.
 Busbar Protection: Due to the severe consequences of busbar faults
(extensive damage, widespread outages), speed and absolute stability are
paramount for EHV busbar protection. Dedicated busbar protection
schemes, such as high-impedance or low-impedance biased differential
protection, are preferred over slower system back-up protection.
Numerical busbar protection, using distributed processing and high-speed
fiber-optic data links, is the modern standard, designed for high reliability
and fault tolerance.
Essence of Chapters Containing Protection Coordination and Cases
The "Protection & Automation Application Guide" extensively covers protection
coordination across various power system elements. Below is a summary of key
chapters highlighting their essence and coordination cases:
 Chapter 2: Fundamentals of Protection Practice
o Essence: Lays the groundwork for protection philosophy, defining
core concepts like "selectivity" (discrimination), "zones of
protection," and the importance of "reliability," "stability," and
"speed" in protection system design. It introduces the fundamental
approaches to discrimination: time grading and unit protection.
o Coordination Cases: Discusses the ideal of overlapping protection
zones to ensure full coverage. Explains the role of primary and
back-up protection in enhancing reliability.
 Chapter 4: Fault Calculations
o Essence: Provides the essential theoretical basis for protection
application by detailing how to calculate fault current distribution
and voltages throughout the system for various fault types (three-
phase, single-phase to earth, etc.).
o Coordination Cases: Emphasizes that knowing "boundary values
of current at any relaying point must be known if the fault is to be
cleared with discrimination". Fault studies determine maximum and
minimum fault currents and maximum through-fault currents, which
are direct inputs for relay setting calculations to achieve proper
coordination.
 Chapter 9: Overcurrent Protection for Phase and Earth Faults
o Essence: Explores the oldest form of discriminative fault protection,
focusing on time/current grading principles. It details standard
Inverse Definite Minimum Time (IDMT) characteristics, relay current
and time multiplier settings, and the application of directional
elements. Earth fault protection, including sensitive earth fault
(SEF), is also covered.
o Coordination Cases: Presents examples of time and current
grading between relays, including for parallel feeders and ring
 mains. It discusses "transient overreach" and co-ordination
challenges, especially in industrial settings with dual-fed substations
[114, 18.7.2]. While less common for primary EHV, it serves as
back-up or in distribution.
 Chapter 10: Unit Protection of Feeders
o Essence: Introduces unit protection as a solution to overcome
limitations of graded overcurrent systems in complex networks,
providing inherent discrimination. It details the "differential
protection" principle (Merz and Price) based on Kirchhoff's laws,
including circulating current and balanced voltage systems.
Discusses the vital role of communication links (e.g., optical fiber,
carrier) between relays. Numerical current differential and phase
comparison schemes are described.
o Coordination Cases: The chapter itself describes unit protection
as achieving inherent discrimination within a clearly defined zone,
making it a key coordination method. It provides an example of unit
protection for a plain feeder and its application to mesh corner and
1 1/2 breaker switched substations.
 Chapter 11: Distance Protection
o Essence: Focuses on distance protection as a high-speed, non-unit
system (but adaptable to unit schemes) that offers fault coverage
largely independent of source impedance variations, making it ideal
for EHV transmission. It details the selection of reach settings and
tripping times for Zone 1, Zone 2, Zone 3, and reverse zones to
ensure coordination. Various relay characteristics (mho,
quadrilateral) are explained.
o Coordination Cases: Provides a comprehensive "Distance Relay
Application Example" for a 230kV network, illustrating the detailed
calculations necessary for setting three-zone distance protection to
ensure proper coordination and coverage.
 Chapter 12: Distance Protection Schemes
o Essence: Expands on basic distance protection by describing
teleprotection schemes that use communication channels to
achieve instantaneous tripping over the entire length of a protected
feeder. It covers "Zone 1 Extension," "Transfer Tripping Schemes"
(e.g., direct under-reach, permissive under-reach, permissive over-
reach), and "Blocking Overreaching Schemes".
o Coordination Cases: These schemes are explicitly designed to
improve fault clearance times and enhance coordination by
ensuring fast and selective operation across the entire line section,
even for end-zone faults that would otherwise be cleared slowly by
Zone 2. The comparison of transfer trip and blocking schemes
highlights their different security and dependability characteristics
for coordination.
 Chapter 13: Protection of Complex Transmission Circuits
o Essence: Addresses the challenges of protecting more complex
EHV configurations, such as parallel feeders, multi-ended feeders,
and series-compensated lines. It details how mutual coupling affects
distance relay measurements and the need for compensation or
specific scheme choices.
o Coordination Cases: Explores specific coordination problems like
"current reversal on double circuit lines" and how they are
mitigated. Discusses the application of unit protection and distance
schemes to multi-ended feeders, noting challenges such as fault
current infeed at multiple terminals. Provides a "Distance Relay
applied to Parallel Circuits" example, demonstrating adjustments to
settings for coordination.
 Chapter 14: Auto-Reclosing
o Essence: Covers the application of automatic reclosing for
overhead line faults, particularly its role in maintaining system
stability on EHV transmission lines. It discusses critical factors like
dead time (for arc de-ionisation) and reclaim time, and the need for
high-speed protection and circuit breakers.
o Coordination Cases: Emphasizes that "high-speed protection
equipment, such as distance or unit protection schemes, giving
operating times of less than 40ms, is essential" for EHV auto-
reclosing. It details how Zone 1 extension schemes in distance
protection aid in rapid, coordinated tripping for auto-reclose
applications.
 Chapter 15: Busbar Protection
o Essence: Highlights the paramount importance of busbar
protection in EHV systems due to the potential for widespread
supply loss and severe damage. It stresses the need for extreme
speed and absolute stability for busbar protection to operate faster
than back-up line protection and maintain system stability. It details
high-impedance and low-impedance biased differential protection as
key methods.
o Coordination Cases: Describes how busbar protection schemes
are designed with overlapping zones across section switches to
ensure no unprotected regions. Numerical busbar protection uses
distributed intelligence and high-speed communication to achieve
reliable and fast operation. "Interlocked Overcurrent Busbar
Schemes" are presented as an alternative for distribution
substations, using feeder relay logic for busbar protection.
 Chapter 16: Transformer and Transformer-Feeder Protection
o Essence: Details the various protection techniques for transformers
against internal and external faults, including overcurrent, restricted
earth fault (REF), differential, and gas/oil actuated devices. It also
 covers the specific challenges like magnetizing inrush and
overfluxing.
o Coordination Cases: Differential and REF schemes are unit
protections that inherently provide discrimination for the
transformer. The necessity of "intertripping" between high and low
voltage circuit breakers is emphasized to ensure complete isolation
of a faulted transformer, which is a key coordination requirement.
Correct CT connections and phase compensation are critical for
accurate differential protection operation.
 Chapter 17: Generator and Generator-Transformer Protection
o Essence: Covers the comprehensive protection needs for
generators and generator-transformer units against a wide array of
electrical and mechanical faults. It discusses differential,
overcurrent, earth fault, and various other protections, and
critically, the protection requirements for "embedded generation"
connected to utility distribution systems.
o Coordination Cases: For large units, fast fault clearance (often by
differential protection) is essential for overall power system stability.
Overcurrent protection typically serves as back-up. The impact of
embedded generation on utility protection settings and the need for
specific protection functions at the "Point of Common Coupling"
(PCC) for safe parallel operation and disconnection are crucial
coordination aspects. Examples detail settings for small industrial
and large generator-transformer units to ensure coordination within
the plant and with the utility.
 Chapter 18: Industrial and Commercial Power System Protection
o Essence: Addresses the unique protection challenges in industrial
plants, which often have complex busbar arrangements and local
generation. It focuses on discrimination between various protection
devices like High Rupturing Capacity (HRC) fuses, Molded Case
Circuit Breakers (MCCBs), and relays.
o Coordination Cases: Emphasizes the need for careful coordination
to avoid spurious trips and ensure selective fault clearance,
especially when multiple devices are in series. Examples illustrate
fuse coordination, and grading of fuses, MCCBs, and overcurrent
relays, and protection of dual-fed substations.
 Chapter 19: AC Motor Protection
o Essence: Covers the extensive range of protection required for AC
motors due to their diverse characteristics and fault types (thermal
overload, start/stall, short-circuit, earth fault, negative phase
sequence, undervoltage, etc.).
o Coordination Cases: Highlights the need to coordinate motor
short-circuit protection with downstream devices (e.g., fused
contactors) to ensure the contactor does not interrupt currents
 beyond its rating. Time delays are often incorporated to prevent
nuisance trips during motor starting inrush or transient voltage dips.
Examples provide detailed setting calculations and grading curves
for HV and LV motors.
 Chapter 20: System Integrity Protection Schemes (SIPS)
o Essence: Describes advanced, "bigger picture" automatic control
systems designed to mitigate widespread power system failures
(e.g., transient instability, voltage/frequency degradation, large
power swings) that go beyond the scope of conventional N-1
contingency protection. These schemes leverage embedded
computing, wide-area communications, and precise time
synchronization (e.g., GPS and synchrophasors).
o Coordination Relevance: SIPS represent the "second and third
lines in the plan to protect the system" by initiating remedial
actions (like generator tripping or load rejection) to correct system
conditions, rather than just isolating faults. They contribute to
overall system-level coordination and stability.
 Chapter 21: Relay Testing and Commissioning
o Essence: Details the various tests (type, production,
commissioning, and periodic maintenance) performed on protection
equipment and schemes to ensure their correct operation and
compliance with standards. It covers secondary and primary
injection tests, and the testing of complex protection scheme logic,
often implemented in software.
o Coordination Relevance: Proper testing is crucial to verify that
the protection scheme will perform its intended coordination
function under realistic fault conditions. Primary injection tests, in
particular, prove the correct installation and operation of the entire
protection scheme, including instrument transformers and wiring,
which are vital for accurate measurement and thus, correct
coordination.

In PPT format

Here is the information on "Protection Co-ordination" presented in a format

resembling a presentation (PPT format):

Protection Co-ordination
Key Concepts & Applications
Drawing from GE Grid Solutions' Protection & Automation Application
Guide

Slide 1: Introduction to Protection Co-ordination

 Purpose of Power System Protection
o To generate and supply electrical energy reliably and economically
to consumers.
o To protect significant capital investment in expensive equipment.

o To ensure safety and prevent severe damage from inevitable faults

(e.g., burning conductors, welding laminations) that can occur
within milliseconds to seconds.
o Adequate protection detects and disconnects faulty elements to
meet system objectives and protect investment.
 Core Objectives of Protection Co-ordination
o To ensure that each protection device isolates only the faulty
section of the power system network, leaving the rest of the system
undisturbed.
o This property is also known as 'discrimination' or 'selectivity'.

Slide 2: General Co-ordination Procedure (Overcurrent Protection)

 Data Requirements for Study
o A one-line diagram of the power system showing device types,
ratings, and associated Current Transformers (CTs).
o Impedances (in ohms, percent, or per unit) of all relevant
components.
o Performance curves of the CTs.

 Relay Setting Determination

o Settings are first chosen to provide the shortest operating times at
maximum fault levels.
o Then, these settings are checked to ensure satisfactory operation at
the minimum expected fault current.
o It is advisable to plot the characteristics of relays and other
protection devices (like fuses) on a common scale. This can be
based on the current expected at the lowest voltage, the
predominant voltage base, a common MVA base, or separate
current scales for each system voltage.
 Basic Co-ordination Rules
 o Whenever possible, use relays with the same operating
characteristic in series.
o Ensure that the relay farthest from the source has current settings
equal to or less than the relays behind it. This means the primary
current required to operate the front relay must be equal to or less
than that required for the relay behind it.

Slide 3: Principles of Time/Current Grading

 Discrimination by Time
o Each relay controlling circuit breakers is assigned an appropriate
time setting.
o The circuit breaker nearest to the fault is designed to open first.

o For a definite-time delay overcurrent relay, the current-sensitive

element initiates the time delay. If its setting is below the fault
current, it does not contribute to discrimination.
o Such a relay's operating time is practically independent of the
overcurrent level.
 Role of IDMT and Instantaneous Relays
o IEC 60255 defines standard Inverse Definite Minimum Time (IDMT)
characteristics to allow for varied tripping times.
o High set instantaneous elements reduce tripping time at high fault
levels, allowing for lower "discriminating curves" for upstream
relays.
o This provides high-speed protection over a large circuit section,
minimizing plant damage, especially if source impedance remains
constant.
o Grading with the relay immediately behind the instantaneous
elements is done at the instantaneous elements' current setting,
not the maximum fault level.
 User-Definable Characteristics
o Some digital/numerical relays offer user-definable curves, where a
series of current/time coordinates are entered and interpolated for a
smooth trip characteristic.
o This feature is rare for standard applications, as standard curves
usually suffice.

Slide 4: Key Attributes for Protection Co-ordination

 Reliability
 o The ability of a protection scheme to operate correctly when
required (dependability) and to avoid unwanted operations
(security) [2.4].
o Affected by incorrect design/settings, incorrect installation/testing,
and deterioration in service.
 Selectivity (Discrimination)
o The ability to isolate only the faulty section of the power system,
leaving the rest undisturbed.
o Achieved through time grading or unit systems.

o Unit protection responds only to faults within a clearly defined zone,

offering fast operation independent of fault severity and not
requiring time grading.
 Speed
o Protection systems aim to isolate faults as rapidly as possible to
minimize equipment damage and maintain system stability.
o Rapid operation is critical for generating plant and EHV systems,
typically requiring unit systems.
 Sensitivity
o The minimum operating level (current, voltage, power) of relays or
schemes.
o Modern digital and numerical relays' sensitivity is usually limited by
the application and CT/VT parameters, not the device design.
 Zones of Protection
o Protection is arranged in zones to limit the extent of power system
disconnection for a fault.
o Ideally, zones should overlap to ensure no part is unprotected, with
circuit breakers included in both adjacent zones.

Slide 5: Grading Margins & Calculations

 Recommended Margins
o Overall grading margins are recommended between different
protection devices.
o Practical grading times at high fault current levels vary between
overcurrent relays of different technologies.
o If relays of different technologies are used, the time appropriate to
the downstream relay's technology should be applied.
 Relay Setting Calculation Procedure
 o Requires fault current data (max/min), max load current, and CT
ratios for each relaying point.
o Time/current characteristics are usually plotted on log/log scales to
a common voltage/MVA base.
o For independent (definite) time relays, settings must be below fault
current (minimum plant in service) and above maximum load/motor
starting/transformer inrush transients.
o Time settings are chosen to allow suitable grading margins.

 Earth Fault Settings

o The procedure is identical to overcurrent elements but uses zero
sequence impedances if available and different from positive
sequence impedances.
o Earth fault levels can be higher than phase fault levels with multiple
earth points or on the star side of a solidly earthed delta-star
transformer.

Slide 6: Specific Co-ordination Applications - Directional Relays

 Purpose and Function
o When fault current can flow in both directions through the relay
location, the relay's response may need to be directional.
o This is achieved by adding auxiliary voltage inputs to the relay.

o Directional relays ensure current flows from the substation busbars

into the protected line for operation.
 Connection Characteristics
o 90°-30° Connection: Suitable for plain feeders with a zero
sequence source behind the relaying point.
o 90°-45° Characteristic (45° RCA): Recommended for transformer
feeders or feeders with a zero sequence source in front of the relay.
This is essential for correct operation with parallel transformers or
transformer feeders beyond a star/delta transformer.

Slide 7: Specific Co-ordination Applications - Ring Mains

 Grading Procedure for Single Infeed
o The ring is conceptually opened at the supply point.

o Relays are graded first clockwise, then anti-clockwise.

o Non-directional relays are used at the supply point, while directional

relays are used at intermediate substations where power can flow in
either direction.
 o Fault current divides inversely to impedances in parallel paths,
causing one set of relays to be inoperative due to current direction.
o The faulted line is the only one disconnected, maintaining power
supply to other substations.
 Challenges with Multiple Sources
o With two or more power sources, time-graded overcurrent
protection becomes difficult, and full discrimination may not be
possible.
o Solutions include opening the ring at a supply point with a high-set
instantaneous relay, or treating the section between sources as a
continuous bus protected by a unit system.

Slide 8: Specific Co-ordination Applications - Earth Fault Protection

 Sensitivity and Residual Current
o Earth fault protection is more sensitive than phase fault overcurrent
protection because it responds only to residual current, which exists
only when current flows to earth.
o It is unaffected by load currents, allowing for low settings.

 Role of VTs and CTs in Directional Earth Fault

o Directional earth fault protection requires a polarizing quantity,
typically the system's residual voltage.
o This is obtained from the vector sum of individual phase voltages,
often via a broken delta connection of a Voltage Transformer (VT).
o The primary star point of the VT must be earthed.

 Challenges with Grading

o Grading can be problematic because all relays in the affected
section will detect the fault.
o While definite-time grading may be possible, full discrimination is
generally not achieved using this technique.

Slide 9: Co-ordination Challenges in Industrial Systems

 Earth Fault Protection Issues
o For four-wire systems using residually-connected CTs, the earth fault
relay element must be set above the highest single-phase load
current to prevent nuisance tripping.
o Harmonic currents can also lead to spurious tripping.
 o If a neutral CT is omitted, the relay sees neutral current as earth
fault current, requiring an increased setting to prevent tripping
under normal load.
 Dual-Fed Substations & Utility Infeed
o In systems with dual feeds (e.g., two transformers feeding a
busbar), co-ordination calculations are complex.
o Protection on the primary side of transformers must grade with
downstream relays and withstand curves, potentially leading to
excessively long operation times.
o Utility infeed adds another layer of relays and time grading, almost
certainly causing excessive fault clearance times at the Utility
interface.
o Solutions may involve accepting total loss of supply in non-normal
operating conditions or accepting a lack of discrimination in some
areas.
 Impact of Motor Fault Contribution
o Induction motors contribute fault current for a short time (decaying
exponentially).
o While generally not critical for protection calculations (due to
assumed 5-cycle clearance time), it can be important for time
grading through-fault protection and peak voltage calculation for
high-impedance differential schemes.
o Motor contribution is more critical for switchgear/busbar fault rating
determination. Large LV motor loads and all HV motors should be
considered in fault level calculations.

Slide 10: Co-ordination in Distance Protection Schemes

 Zone Settings
o Zone 1: Instantaneous, set to 80-85% of the protected line
impedance. A 15-20% safety margin prevents over-reaching and
loss of discrimination with protection on the next line section.
o Zone 2: Time-delayed, set to at least 120% of the protected line
impedance for full coverage and error allowance. Often set to the
protected line + 50% of the shortest adjacent line to avoid grading
Zone 2 time settings.
o Zone 3: Time-delayed, provides remote backup protection, typically
120% of the sum of the protected and adjacent lines. Requires
careful consideration of fault current infeed at remote busbars.
 Maintaining Discrimination
 o Careful selection of reach settings and tripping times across various
zones is crucial for correct co-ordination between distance relays.
o Proper co-ordination of multiple relay elements (e.g., directional and
impedance units) is needed to achieve reliable performance,
especially during evolving fault conditions.
 Impact of System Impedance
o The ratio of source impedance to line impedance (ZS/ZL) affects
relay voltage.
o Fault current infeed at remote busbars can significantly increase the
impedance seen by the relay, which must be factored into Zone 3
settings.
o Earthing resistance affects the source angle and source-to-line
impedance ratio for earth faults, impacting relay performance
assessment.

Slide 11: Ensuring Co-ordination: Testing & Commissioning

 Importance of Testing
o Commissioning tests are performed on-site before protection
equipment is put into service.
o Aims include ensuring equipment is undamaged, installation is
correct, and the entire protection scheme functions properly.
o Primary injection tests check the entire circuit (CTs, relays,
trip/alarm circuits, wiring) without disturbing connections, but are
time-consuming and expensive.
o Wiring errors or incorrect CT/VT polarity may not be found until in-
service (spurious tripping or loss of discrimination) if primary
injection is omitted.
 Relay Setting Checks
o Alarm and trip settings of relay elements must be entered and
verified.
o Software supplied by manufacturers is typically used for data entry
and record-keeping, simplifying the process.
o Settings must be checked for compliance with recommended values
from the protection study.
o Recorded settings are a vital part of commissioning documentation.

 Proving Scheme Logic

o Protection schemes often use logic (e.g., Programmable Scheme
Logic or PSL in numerical relays) to determine tripping conditions.
o This logic, implemented in software, offers flexibility for
modifications and uses standard programming languages (e.g.,
ladder logic, Boolean algebra).
o Testing ensures this logic functions correctly as per the scheme
design.