2012 Wecc Trdtd Users Guide

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Users Manual for Reporting:

WECCTransmission Reliability Database

(TRD) &

NERCTransmission Availability Database Systems

(TADS)

Written by

WECC RPEWG

November 15, 2007Revised February 20, 2008Revised November 20, 2008

Revised July 27, 2009


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Revised October 14, 2010Revised December 6, 2011

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Table of Contents

II.Timelines for Submittals..........................................................................................5 NERC IDs and TO Names..............................................................................................7

III.Forms/Sheets for WECC/NERC Data Submittal....................................................7

a)Form 1.1 Non-Reporting Transmission Owner Statement.......................................7 b)Form 1.2 Reporting Transmission Owner Information............................................8c)Form 2: Forms for Jointly-Owned Facilities ...........................................................8d)Form 2.1 Jointly-Owned AC and DC Circuits ........................................................9e)Form 2.2 Jointly-Owned AC/DC Back-to-Back Converter ...................................10h)Transmission Circuit Attribute Table....................................................................................................................................10i)Transformer Attribute Table....................................................................................15

j)Form 3.3 AC/DC BTB Converter Inventory Data..................................................16k)WECC Common Structure and ROW Reporting TO Form................................17l)FORM 4.4 AC DC BTB Converter Outage.........................................................19

m) Outage Information Table....................................................................................20IV.Applications of Addition and Modifications to the Tables..................................26Appendix A WECC Members ..............................................................................35Appendix B TRD/TADS Outage Cause Codes......................................................39Weather, excluding lightning ....................................................................................39Lightning....................................................................................................................39Environmental............................................................................................................39Contamination ...........................................................................................................39Foreign Interference ..................................................................................................39Fire ............................................................................................................................39Vandalism, Terrorism or Malicious Acts ..................................................................39

Failed AC Substation Equipment...............................................................................39Failed AC/DC Terminal Equipment..........................................................................39Failed Protection System Equipment.........................................................................40Failed AC Circuit Equipment....................................................................................40Failed DC Circuit Equipment....................................................................................40Vegetation .................................................................................................................40Power System Condition ...........................................................................................40Human Error..............................................................................................................40Unknown ...................................................................................................................41Other .........................................................................................................................41Appendix C WECC TRD Definitions.....................................................................41

Common Corridor......................................................................................................42Continuous right-of-way or two parallel right-of-ways with centerline separationless than the longest span length of the two transmission circuits at the point of separation or 500 feet, whichever is greater, and no natural barriers (such as hills,rivers, etc.) between the transmission circuits. This separation requirement does notapply to the last five spans of the transmission circuits entering into a substation.. .42Appendix D NERC TADS Definitions...................................................................43Element......................................................................................................................43

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Protection System......................................................................................................43AC Circuit..................................................................................................................43Transformer ...............................................................................................................45AC Substation............................................................................................................45AC/DC Terminal........................................................................................................45

AC/DC Back-to-Back Converter...............................................................................45DC Circuit..................................................................................................................45Overhead Circuit........................................................................................................45Underground Circuit..................................................................................................45Circuit Mile................................................................................................................45Multi-Circuit Structure Mile......................................................................................46Voltage Class.............................................................................................................46Automatic Outage .....................................................................................................46Momentary Outage ...................................................................................................46AC Multi-Owner Common Structure Flag................................................................47In-Service State..........................................................................................................47

Substation, Terminal, or Converter Name.................................................................51TO Element Identifier................................................................................................51Outage Start Time......................................................................................................51Outage Duration.........................................................................................................51Outage Continuation Flag..........................................................................................51Outage Identification (ID) Code................................................................................52Event..........................................................................................................................52Event Identification (ID) Code..................................................................................52Event Type Number...................................................................................................52

Normal Clearing.........................................................................................................56Even though the Protection System failed to reclose properly, the above sequence of events is still an example of Normal Clearing as defined above. .............................57Element-Initiated Outage...........................................................................................57Other Element-Initiated Outage.................................................................................57AC Substation-Initiated Outage.................................................................................57AC/DC Terminal-Initiated Outage............................................................................57Other Facility-Initiated Outage..................................................................................57Single Mode Outage..................................................................................................57Dependent Mode Initiating Outage............................................................................58Dependent Mode Outage...........................................................................................58Common Mode Outage..............................................................................................58Common Mode Initiating Outage..............................................................................58Initiating Cause Code.................................................................................................59Sustained Cause Code................................................................................................59

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Section 1

I. General:

This document serves as the instructions for submission of outage data for the WECCTransmission Reliability Database, TRD and the NERC Transmission AvailabilityDatabase Systems, TADS. This combined database submittal will serve the two purposesof the voluntary WECC data submittal and the mandatory NERC TADS submittal. Thisdocument also covers Phase II non-automatic outage submittal of TADS.

The data collected through the use of the following Forms and Sheets are to be suppliedto WECC. Then WECC will pull off the data for the WECC TRD database the remainingdata will be used to create the NERC TADS Forms, 3.1, 3.2, 3.4, 4.1, 4.2, 4.3, 5.0, 6.1,6.2 and 6.3. All data submitted to NERC from WECC will be submitted on an individualTO basis.

Forms completed by WECC and submitted to NERC:Form 3.1 AC and DC Circuit Inventory DataForm 3.2 Transformer Data InventoryForm 3.4 Summary Automatic Outage DataForm 4.1 AC Circuit Detailed Automatic Outage DataForm 4.2 DC Circuit Detailed Automatic Outage DataForm 4.3 Transformer Detailed Automatic Outage DataForm 5.0 Event ID Code and Event Type Number DataForm 6.1 AC Circuit Detailed Planned Outage DataForm 6.2 DC Circuit Detailed Planned Outage DataForm 6.3 Transformer Detailed Planned Outages Data

II. Timelines for Submittals

WECC:

The seventh year of the TRD submittal will be for the calendar year outage data of 2012.The TRD timeline is listed below which is coordinated with the TADS timeline. WECCMembers follow the WECC timeline and the NERC timeline will be automaticallycovered.

December, 2011 RPEWG releases to the WECC Members

TADS Data Reporting Instruction Manual5

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TRD/TADS data submittal sheets that will be used for the data collectionfor calendar year 2012 (TRD)Updated TRD and TADS Users Manual for the combined WECC/NERC data collection

October, 2012 A WECC/NERC TRD and TADS data training webinar for all WECC Members

of the data submittal sheets will be held especially focused to the WECC TRDdata submittal.

February 1, 2013

WECC TOs supply data to WECC with CY 2012 transmission outage data in the proper Forms.

.NERC:Table 1.6.2

Schedule for Calendar Year 2011 Data Entry

Date ActionDecember 1, 2012

Re-open webTADS for 2012 calendar year data entry. Instructions for re-startingTADS data entry will be provided by e-mail.

February1, 2013

Reporting TOs complete submission of all calendar year 2012 data.

General Reporting Requirements:

There are 11 Forms listed in the data submittal spreadsheets. These Forms are acombination of the WECC TRD and the NERC TADS. The goal of the RPEWG,Reliability Performance Evaluation Work Group, is to have no duplication of datasubmittal for the WECC and NERC submittals.

The TADS data entry software described in Section 1.5.1 will transmitdata securely. Until this software is completed, transmittals will bemade by e-mail. To securely transmit TADS data securely by e-mail(which contains CEII), the following process should be followed by TOsand REs:

1. Password-protect the document to be transmitted, and sendvia e-mail to the recipient. Do not include the password in this e-mail.2. In a second separate e-mail, send the password to the recipientof the document.


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NERC IDs and TO NamesEach Transmission Owner is identified by a NERC ID. NERC IDs are not region-specific, i.e., the same Transmission Owner may have the same NERC ID in differentregions if the TO owns transmission facilities in different regions. The name of eachTransmission Owner on the NERC Compliance Registry and its NERC ID is available athttp://www.nerc.com/page.php?cid=3|25 under the Compliance Registry Files file atthe bottom of the page. This registry is updated monthly.

1. For TADS, pseudo NERC IDs have been assigned for various purposes, includingallowing for one reporting pseudo TO to make one TADS submission for multiple NERC-registered TOs that are owned by a single entity. For example,five NERC-registered Southern Company TOs were given one pseudo NERC IDfor a pseudo entity named Southern Transmission Company. The pseudo

NERC IDs are for TADS reporting only. A document entitled NERC ID Exceptions for TADS dated February 18, 2008 and posted athttp://www.nerc.com/filez/tadswg.html explains the TOs that have been assigned

pseudo NERC IDs and why they were assigned.

2. For 2012 calendar year reporting , an Excel file named 2012 TRD_TADScontains the 2012 calendar year consolidated TADS NERC IDs and TO names(i.e., NERC IDs from TOs on the NERC Compliance Registry as well as thosewith pseudo NERC IDs). This file also shows each TOs region and whether theTO is a non-reporting or reporting TO. It may be downloaded athttp://www.nerc.com/filez/tadswg.html .

3. For 2012 calendar year reporting , an Excel file 2012 TRD_TADS contains the2012 calendar year consolidated TADS NERC IDs and TO names (i.e., NERCIDs from TOs on the NERC Compliance Registry as well as those with pseudo

NERC IDs) as of July 27, 2009 and may be downloaded athttp://www.nerc.com/filez/tadswg.html . This file will be updated after theCompliance Registry is updated September 2012. The reporting status of TOswill be updated after Forms 1.1 and 1.2 are received.

III. Forms/Sheets for WECC/NERC Data Submittal

a) Form 1.1 Non-Reporting Transmission Owner Statement

Form 1.1 is for TOs who do not own any TADS Elements as of the date theysubmit it. It will be submitted to WECC by August 1, 2011 for the calendar year of 2012. If a Transmission Owner owns no TADS Elements as of its submission date,it provides the contact information of the person completing the form on behalf of the TO who is attesting to that fact. However, if after submitting From 1.1, a


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http://www.nerc.com/page.php?cid=3%7C25http://www.nerc.com/filez/tadswg.htmlhttp://www.nerc.com/filez/tadswg.htmlhttp://www.nerc.com/filez/tadstf.htmlhttp://www.nerc.com/page.php?cid=3%7C25http://www.nerc.com/filez/tadswg.htmlhttp://www.nerc.com/filez/tadswg.htmlhttp://www.nerc.com/filez/tadstf.html


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TADS Element is added by the TO prior to December 31 of the year prior to thereporting year, the TO must notify NERC and submit Form 1.2.

b) Form 1.2 Reporting Transmission Owner Information

Form 1.2 asks for three types of TO information.

1. It requests the business contact information for the primary and back-upTADS contact person for the Transmission Owner.

a. It contains a list to confirm which forms were filed and which formswere not filed. The list has drop-down menus for Submission Statusand Reason Not Submitted for the TO to explain which forms weresubmitted and if not submitted, why they were not submitted (e.g., TOhas none of the Elements reported on the form, the TO had no outages,etc.). This ensures that inadvertent form omissions are corrected prior to submittal.

b. At the end of the reporting cycle with all other forms.

c. Contact updates or newly registered TOs will need to submit this bySeptember 16, 2012

d. Contact information will automatically be populated for the next yearssubmittal with the information that was provided in the Februarysubmittal.

2. Finally, it lists the NERC default confidentiality status of TO data on eachform. See Section 1.5 for instructions regarding changing the defaultconfidentiality status.

c) Form 2: Forms for Jointly-Owned Facilities

These two forms are used to ensure that one TO takes on the TRD/TADS reportingresponsibility for jointly-owned facilities. If a TO has less than 100% ownership interestin such facilities, each TO must enter this facility on Form 2.1 or 2.2. These multipleentries will be checked by WECC staff. The coordinated entries shouldindicate which single TO will take reporting responsibility. This willavoid duplication of outage and inventory reporting, and the other TOswho are joint-owners must be aware that they should not report to

TADS on that facility . In addition to the names of all owners, their NERC ID is alsorequested. The name of each Transmission Owner as well as its NERC ID is available athttp://www.nerc.com/~org/.If a TO owns 100% of a facility, the reporting responsibility of that facility belongs to theTO. Do not enter the facility on Forms 2.1 or 2.2. For 100% owned AC Circuits,communication among the TOs who own the AC Substations that bound the circuit is


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Section 1

expected for the purpose of identifying data related to the cause of outages which thereporting TO must supply.

d) Form 2.1 Jointly-Owned AC and DC Circuits

The characteristics of each multiple-owner circuit are input on this form (one circuit per row). As discussed in Section 2, we expect TOs to mutually agree on who should reportoutage and inventory information (on Forms 3, 4 and 5) of the multiple-owner circuitinformation for TADS and which other owners should not report. Do not enter circuitsthat you do not partially own.

Table 2.1Column Form 2.1 Descriptor None Questions 1 and 2 in the top of the form ask whether there were any additions of

multiple-owner circuits during the reporting year and if so, whether those changeswere incorporated into the response. These questions apply to the second submittalonly, and appropriate NA responses are provided as an answer associated with afirst submittal.

A The type of circuit (AC or DC), input from a drop-down menu, describes the maincharacteristic of the Element.

B From Substation or Terminal Name. The alphanumeric code designating one of the Substation Names for an AC Circuit or one of the Terminal Names for a DCCircuit.

C To Substation or Terminal Name. The alphanumeric code designating a secondSubstation Name for an AC Circuit or a second Terminal Name for a DC Circuit.

D To2 Substation or Terminal Name. The alphanumeric code designating a thirdSubstation Name for an AC Circuit or a third Terminal Name for a DC Circuit.

E The Voltage Class of the Element, input from a drop-down menu. The 400-599 kVVoltage Class can only be used if AC is selected in column A, and the 400-499kV and 500-599 kV Voltage Classes can only be selected if DC is selected incolumn A. Other Voltages Classes (200-299 kV and 600-799 kV) can be used for either AC or DC Circuits. Data that does not conform to this requirement will berejected and an error notice provided.

F Underground or Overhead. This Element characteristic is input from a drop-downmenu. See the definition of Overhead and Underground in Appendix 6, Section A.

G-H The NERC ID number and name of the TO with TADS outage reportingresponsibility for the multiple-owner circuit.

I The reporting TOs Element Identifier. This is required.J-W The NERC ID numbers and name of the TOs that have an ownership interest in the

Element. Up to ten owner names are provided. One of the TOs must be the TOwith TADS reporting responsibility input in columns G-H


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e) Form 2.2 Jointly-Owned AC/DC Back-to-Back Converterf) The characteristics of each multiple-owner AC/DC Back-to-Back Converter are

input on this form (one Element per row). This form is not to be used for AC/DCBack-to-Back Converters owned 100% by a single TO.

g) Table 2.2

Column Form 2.2 Descriptor None Questions 1 and 2 in the top of the form ask whether there were any additions of

multiple-owner AC/DC BTB Converters during the reporting year and if so, whether those changes were incorporated into the response. These questions apply to thesecond submittal only, and appropriate NA responses are provided as an answer associated with a first submittal.

A Converter Station Name. The alphanumeric code designating the converters name.B HIDDENC The AC Circuit Voltage Class, input from a drop-down menu, on one side of the

converter

D The AC Circuit Voltage Class, input from a drop-down menu, on the other side of theconverter

E-F HIDDENG-H The NERC ID number and name of the TO with TADS reporting responsibility.

I The reporting TOs Element Identifier. This is required.J-Q The NERC ID numbers and names of the TOs that are multiple owners of the

Element. Up to four owner names are provided. One of the TOs must be the TO withTADS reporting responsibility input in column G-H.

h) Transmission Circuit Attribute Table

Reporting Transmission Owner Name:

The company name of the WECC TO with TRD/TADS reporting responsibility. SeeAppendix A for current list of WECC Members.

Reporting TO Element Identifier (Circuit Code):

The circuit code is an operators unique identifier for each reporting transmission circuit.Each operator can define as needed an alphanumeric designator up to 15 characters. Onlyinclude circuits which are normally energized, fully connected to the system, anddeclared commercially in service by the TO.

From:


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The From Bus is a descriptive name of the facility where one of the circuits automaticisolation devices is located.

To:

The To Bus is a descriptive name for the facility where the other circuits automaticisolation devices are located, other than the From Bus.

Tertiary Bus:

The third bus on 3-terminal lines, if applicable.

Miles:

Enter the length of the transmission circuit to the nearest 10th of a mile, including thelength of line taps.

Circuit Type:

Circuit Type identifies the transmission element as overhead or cable depending onwhich is the majority of the circuit length. Majority is the section of the transmissioncircuit that is 50 percent or greater of the total length of the circuit. There are four identified circuit types based on the voltage type and construction. Select one three letter abbreviation list below.

ACO AC overheadACC AC cableDCO DC overheadDCC DC cable

Voltage Class:

The circuits nominal operating voltage. The operating voltage may be different from thedesign voltage. The kV voltage level of the circuit is entered as one of either 200-299,300-399 or 500-599 from the drop down lists on the spreadsheet.

Conductors Per Phase:

Enter the number of conductors per phase.

1, 2, 3, or 4


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Overhead Ground Wire:

Enter the number of overhead ground wires.

0, 1, or 2.

Insulation Type:

This indicates the insulation material and assembly. If more than 80% of the circuitlength was constructed using one type insulation material and assembly, enter thatinsulation material and assembly three letter code, otherwise use Mixed for type of material. CEP = Ceramic PostCES = Ceramic SuspensionPOP = Polymer Post

POS = Polymer SuspensionGLS = Glass SuspensionMXD = MixedOTH = Other

Cable Type:

This indicates the type of insulation and trenching structure. Enter the type of insulationand trenching structure three letter codes:

SWD = Solid with conduitSND = Solid with no conduitOWD = Oil filled with conduitOND = Oil filled with no conduitGWD = Gas filled with conduitGND = Gas filled with no conduit.

Structure Materials:

This indicates the type of material used in the construction of the supporting structures. If more than 80% of the circuit length was constructed using one type of material, enter thatmaterial type code, otherwise use Mixed for type of material. If the material is notlisted, use Other code. Enter one of the following three letter abbreviations materialtypes.

AL = Aluminum


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CN = concreteFG = fiberglassST = steelWD = woodCM = composite

OT = other MX = mixed.

Structure Types:

Structure type is the design of the structure use in the circuit. If more than 80% of the lineof the circuit length was constructed using one type of design structure, enter that designstructure three letter code, otherwise use Mixed for type of structure. If the structuredesign structure is different from those listed use Other code. Enter one of thefollowing three letter abbreviations structure types.

DLC = Double Lattice ColumnHFR = H FrameKFR = K FrameLAT = Lattice Tower SPG = Single Pole GuyedSPU = Single Pole Un-guyedDOP = Double PoleSLC = Single Lattice ColumnYTY = Y TypeOTH = other MXD = Mixed.

Circuits Per Structure:

Enter the number of circuit positions per structure that are actually occupied. Do notinclude circuit positions that otherwise are not reported (i.e. circuits below 230 kV)

1, 2, 3, etc.

Terrain:

Terrain describes the type of geography or environment the circuit traverses. If morethan 80% of the line of the circuit length is in one terrain, enter that terrain two letter code, otherwise use Mixed for type of terrain. If multiple terrain types are applicablefor a given area, select the type that is most likely to cause outages. For example, if a linetraverses a forest on the coast, select coastal if airborne salt content is more likely tocause outages. Enter one of the following two letter abbreviations for terrain types:


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CO = CoastalDS = DesertMT = MountainsFR = ForestUR = Urban

PR = PrairieMX = Mixed.

Elevation:

Elevation describes the range of altitude above sea level that the circuit traverses. If morethan 80% of the circuit length is at one elevation range, enter that elevation rangenumber, otherwise use 99 if elevation range is greater than 2000. Enter one of rangeelevation number as indicated below: 1 = less than 2000ft.

2 = 2001 to 4000ft.3 = 4001 to 6000ft.4 = 6001 to 8000ft.5 = 8001 to 10000ft.6 = 10001 to 12000ft.99 = elevation varies more than 2000ft.

In Service Date

Enter the date the transmission circuit was placed in service. This could be as a newcircuit or a reconfiguration for an existing circuit; a significant change in the currentlength of the circuit or change in route. Enter the date in the mm/dd/yyyy format. It isvery important that the install dates of lines entered in the current year are entered;this will allow WECC to calculate the partial year number for the NERC TADSsheets accurately.

Retirement Date

The date the transmission circuit was removed from service. Enter the date in themm/dd/yyyy format.

Parent Code

The parent code is used to record the parent/child relation of reconfigured circuits.Assign a new Circuit Code(s) to these modified lines, and record the original CircuitCode as the Parent code.

Comments:


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Intended for any additional pertinent information that is related to this circuit.

i) Transformer Attribute Table

Reporting TO:

Enter the WECC Member abbreviation of the operator for the circuit. See Appendix Afor current list.

Reporting TO Element Identifier (Transformer Code):

The transformer code is an operators unique identifier for each reporting transmissionelement. Enter one code for all 3 phases of single phase transformer bank or three PhaseTransformer. Each operator can define as needed an alphanumeric designator up to 8characters. Only include circuits which are normally energized, fully connected to thesystem, and declared commercially in service by the TO.

Transformer Location:

Transformer Location indicates the physical location of the transformer. Enter thesubstation name or facility location of the transformer.

High Side kV:The kV voltage level of the high side of the transformer is entered as one of the following200-299, 300-399 or 500-599 from the drop down lists on the spreadsheet.

Low Side kV:The kV voltage level of the low side of the transformer is entered as one of the following200-299, 300-399 or 500-599 from the drop down lists on the spreadsheet.

Single Phase or 3 Phase Bank:

This describes the 3-phase transformer by the type of connection. Enter A or B for thetype of transformer connection.

A = 3 Phase Bank B = Single Phase of 3 phase bank


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Three Phase Bank Rating in MVA

Enter the highest MVA rating of the transformer bank, (such as FO or FOA), continuousrating. For single phase transformers bank, enter the rating for the entire bank.

In Service Date:

Enter the date the transformer was placed in service at present location. Enter the date inthe mm/dd/yyyy format. It is very important that the install dates of lines entered in thecurrent year are entered; this will allow WECC to calculate the partial year number for the NERC TADS sheets accurately.

Retirement Date:

Enter the date the transformer was removed from service from that location. Enter thedate in the mm/dd/yyyy format.

Comments

Intended for any additional pertinent information that is related to this transformer.

(The Transformer Attribute table is intended to describe the location of the transformer,not the transformer.)

j) Form 3.3 AC/DC BTB Converter Inventory DataThe inventory data for AC/DC BTB Converters is input on this form.

Table 3.3

Column Form 3.3 DescriptorA Rows 1-4: The Voltage Class of the reported AC/DC BTB Converters is the

highest AC terminal voltage in the AC/DC BTB Converter. This is a phase-to- phase voltage.

AC/DC BTB Converter Inventory DataAppendix 7 has an example that illustrates the data requirements for the equivalent

number of circuits. The equivalent number of AC/DC BTB Converters follows a similar methodology. Appendix 7 illustrates how to make this calculation for an annual submittal.

B The number of AC/DC BTB Converters that are installed and in-service at theend of the reporting year of in each Voltage Class. This includes multiple-owner AC/DC BTB Converters that are reported by the TO. The term in-service refers to the accounting state of the AC/DC BTB Converter, not its

operational state. If you have no AC/DC BTB Converters in a particular Voltage Class, a blank is the default entry in columns B through F.C The number of AC/DC BTB Converters that were added during the year.D The equivalent number of AC/DC BTB Converters added.E The number of AC/DC BTB Converters that were removed.F The equivalent number of AC/DC BTB Converters removed.


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Column Form 3.3 DescriptorG This is a calculated value for the equivalent annual number of AC/DC BTB

Converters for the reporting year. Note that column E is not used; it isrequested as a sanity check for column F.

k) WECC Common Structure and ROW Reporting TO Form

This Table is to capture WECC Members transmission circuits common exposure tocommon structures and to common ROWs. The Reporting TO is to enter one row in thesheet for each circuits exposure to any of the listed commonalities.

Reporting TO of Circuit #1



The circuit code is an operators unique identifier for each reporting transmissionelement. Each operator can define as needed an alphanumeric designator up to 8characters.

Reporting TO of Circuit #2



The circuit code is an operators unique identifier for each reporting transmissionelement. Each operator can define as needed an alphanumeric designator up to 8characters.

Common Miles

Enter the length in miles of the of the transmission circuit commonality that is reported inthis row.

Common Corridor


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TOC = Common Tower. The circuit in this listed segment is on a common tower withanother TRD/TADS Element.

CRW = Common Right of Way. The circuit in this listed segment is in a Common Rightof Way with another TRD/TADS Element.

.

Example A

NCE bubble is the No Common exposure portion of the D circuit. The TRD/TADScircuit is only on its own structure without Common ROW exposure.


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TOC bubble is the Common Tower exposure portion of the Circuit D. The TRD/TADScircuit is on a Common Tower with another Element. In Example A, this is the portion of the circuit in common with circuit B on a common structure.

CRW bubble is the Common Right of Way exposure of the portion of the Circuit D. The

TRD/TADS circuit is in a Common Right of Way with another Element. In Example A,this is the portion of the circuit in common with Circuit C.

For every TRD/TADS circuit, for each type of exposure for each circuit will begiven a row in the sheet. Even if there are repeats of the commonality, there must bean entry for each. This is because there may be different circuits in the differentcommonalities.

l) FORM 4.4 AC DC BTB Converter Outage

This form contain data for Automatic Outage of an Element, both Sustained andMomentary for only AC-DC BTB Converter Outages. This form does not have rownumbers. Since each line represents an outage and each outage has a unique Outage IDCode, this code is used to identify outage entry.

The first several columns (A-I) contain information that generally describes the Elementthat was outaged. The single exception is the Event ID Code. The remaining columns (J-P) describe the outage itself. Since there is so much similarity between the columns, alldescriptors will be provided once, using the generic term of Element instead of ACCircuit, Transformer, etc.

Although we maintain the same column letter designations, some columns do not apply

to some types of Elements and are therefore hidden. The hidden columns are listed below.

Form No. Hidden Columns4.4 H, I

Table 4.4

Data for AC-DC BTB Converter That Had an Automatic OutageColumn Form 4.4 Descriptor

A The Outage ID Code assigned to the outage. This is assigned by the TO. SeeAppendix 6, Section B for the definition of Outage ID Code.

B The Event ID Code associated with the outage. This is assigned by the TO onForm 5. See Appendix 6, Section B for the definition of Event ID Code. The

Event ID Code must be appended with the reporting year (e.g., WXY-2008).C The Elements Voltage Class. This is consistent to the Voltage Class definitions

used for Inventory Data on Forms 3.1-3.3.AC/DC BTB Converter= highest AC terminal voltage(phase-to-phase)

D-F Data that provides a description of the physical location of the Element.AC/DC BTB Converter= Its name


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Data for AC-DC BTB Converter That Had an Automatic OutageColumn Form 4.4 Descriptor

G The TO Element Identifier is a required alphanumeric field that has the TOsinternal identifier of the Element. This could be a circuit or transformer number or other identifier recognized by the TO.

H

IThe descriptions that follow use defined terms that the TO should become familiar with. Theywill not be repeated here. Most data fields have drop-down menus. They each describe variousfacets of the outage.

J The Fault Type (if any) for each circuit Outage, input from a drop-down menu.K The Outage Initiation Code, input from a drop-down menu.L The Outage Start Time, in Universal Coordinated Time (UTC), not local time.

There is one exception : TOs who submit outage data into webTADS using thegraphical user interface (GUI) may select the appropriate local time for their data;webTADS will then convert it to UTC and store the time as UTC withinwebTADS. This feature is not available for bulk loading UTC must be enteredon bulk-loaded data .

The use of UTC will allow related outaged occurring on Elements reported bydifferent Transmission Owners to be linked. See instructions Section 4.1 below for outages that continue beyond the end of the reporting calendar year.

M The Outage Duration expressed as hours and minutes. Momentary Outages willenter a 0 (zero) in this field since we round to the nearest minute. A zero entry incolumn M tells the reviewer that the outage was Momentary. See instructions inSection 4.1 below for outages that continue beyond the end of the reporting year.

Note that the format is a text field and requires a colon (:) be entered between thehours and minutes. Enter 860 hours and 20 min. as 860:20. If the colon is absent the entry will be interpreted as hours. If the Outage Duration exceeds thenumber of hours remaining in the year (based upon the Outage Start Time), thedata will be rejected and an error notice provided. If the previous entry of 860:20 were entered as 86020, it would be read as 86, 020 hours and rejected.

N 1. The Initiating Cause Code, input from a drop-down menu. All MomentaryOutages must supply this code.

O The Sustained Cause Code, input from a drop-down menu. This only applies toSustained Outages. Momentary Outages enter NA-Momentary.

P The Outage Mode, input from a drop-down menu.Q The Outage Continuation Flag described whether the outages stated and ended

within the reporting year or not. The flag is explained in a footnote on the dataform as well as in Appendix 6, Section B where the term is fully defined.

m) Outage Information TableThis form contains information for both forced and non-automatic outages. For non-

automatic outages use either the Planned or Operational codes but never use both for anoutage.

Reporting TO/TOP:


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Equipment Code:

Enter the Circuit Code or Transformer Code from attributes tables.

Start Date/Time:

Enter the date in mm/dd/yyyy format and the Time in GMT to nearest second, if available, otherwise to the nearest minute of when the outage started.

End Date/Time: Enter the date in mm/dd/yyyy format and the Time in GMT to nearest second, if available, otherwise to the nearest minute of when the outage ended.

If an outage begins in a reporting calendar year and continues beyondthe end of the year(December 31) 2012, the calculation of a total Outage Duration is notpossible. In this case, the following process will be observed.

1. Two separate Outage Durations will be input.a. For the reporting year when the outage started, the TO inputs

the Outage Start Time and calculates an Outage Duration fromthe Outage Start Time until the end of the reporting year. TheOutage Continuation Flag is input as 1.b. For the next reporting year, the same Event ID Code and sameOutage ID Code will be entered for the outage with an OutageStart Time equal to January 1, 00:00UTC of that reporting year . If the outage is concluded in that

reporting year, anOutage Duration is calculated from the Outage Start Time. If the

outage continuesto the subsequent reporting year, the Outage Duration is entered

as 8760:00, or8784:00 for a leap year. The Outage Continuation Flag is input as2.

c. Most outages that are not concluded by the end of a reportingyear will conclude in the next reporting year. However, an outage


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may span three or more reporting years. This process describedin b. above continues until the outage ends .

Cause Code

Enter one of the three letter causes from the Cause Code Table, multiple common modeevents must have the same Cause Code; dependant outages may have different CauseCodes. See Appendix B for cause code details. For Non-Automatic Outage codes seePlanned or Operational Cause codes below.

1 1. Weather, excluding lightning2. Lightning

1 3. Environmental

1 4. Contamination

1 5. Foreign Interference

1 6. Fire

1 7. Vandalism, Terrorism or Malicious Acts

1 8. Failed AC Substation Equipment

1 9. Failed AC/DC Terminal Equipment

1 10. Failed Protection System Equipment

1 11. Failed AC Circuit Equipment

1 12. Failed DC Circuit Equipment

1 13. Vegetation

1 14. Power System Condition

1 15. Human Error

1 16. Unknown

1 17. OtherPlanned Outage Cause Codes:Used for Non-Automatic outages only. See Appendix B for cause code details.

1. NA-used if the outage is a Operational outage2. Maintenance and Construction3. Third Party Request4. Other Planned Outage


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Operational Outage Cause Codes:Used for Non-Automatic outages only. See Appendix B for cause code details.

1. NA- used if the outage is a Planned Outage2. Emergency

3. System Voltage Limit Mitigation4. System Operating Limit Mitigation, ex Voltage5. Other Operational Outage

Outage Mode Codes:

The outage mode describes the initiating characteristics of an outage. . See Appendix Cfor definitions on initiating modes. Enter the initiating outage mode defined in theDefinitions Section: For Non-Automatic Outages this section is not needed.

IND Independent Mode

DEP Dependent ModeCOM - Common modeDEPI - Initiating outage for a Dependent ModeCOMI Initiating Common Mode outage for Dependent Mode outage(s)

Note:If an initiating event is not within the scope of this database, the event will may not havea DEPI, e.g., a 500kV breaker failure causing a 500kV line outage.

Fault Type:

The descriptor of the fault, if any, associated with an Automatic Outage. Several choicesare possible. For Non-Automatic Outages this section is not needed.

1 - No fault2 - Phase to Phase fault3 - Single Phase to Ground fault4 - Phase-Phase-Ground, 3 Phase, or 3 Phase-Ground fault5 - Unknown Fault Type.

Outage Initiation Code:

The Outage Initiation Codes describe where an Automatic Outage was initiated on the power system. Non-Automatic Outages use either Planned or Operational.

1 Element-Initiated Outage2 Other Element-Initiated Outage3 AC Substation-Initiated Outage


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4 AC/DC Terminal-Initiated Outage5 Other Facility-Initiated Outage6 Planned7 Operational

Outage Type:

Used to identify if the event was automatic versus manual forced. Options are Auto,Forced Manual and Manual. An automatic outage is one which is protective equipmentinitiated, and a forced manual outage is one that was operator initiated and could not bedelayed beyond 30 minutes and Manual is for Planned and Scheduled outages.

Event Type Number: Not needed for Planned outages.

Two tables are provided for Event Type Numbers that fall into two distinct categories.

Normal Clearing: This table applies under two conditions

When a fault has occurred and the Element is isolated under Normal Clearing.

1. When a fault has not occurred, but the Element is isolated by the proper and intended operation of the Protection System. For example, a circuit breaker may be openeddue to the detection of circuit breaker low gas pressure, causing the Protection Systemto operate. Or a Transformer may be isolated by the Protection System due to highoil temperature. Both of these events are categorized as Normal Clearing.

Abnormal Clearing: T his table applies under two conditi ons

1. When a fault has occurred and the Element is isolated under Abnormal Clearing.

2. When a fault has not occurred, but the Element is isolated by the failure or unintended operation of the Protection System. For example a low gas pressuresensor which is part of the Protection System may provide an incorrect sensor readingand cause the Protection System to operate when it would not otherwise haveoperated, but since the sensor and its controls are part of the Protection System itsoperation is abnormal (not-proper). The isolation of the Element was due to theProtection Systems improper operation of a protection sensor. Since an AutomaticOutage was due to Abnormal Clearing, the event is categorized as AbnormalClearing. Another example of Abnormal Clearing is where a relay has incorrectsettings applied (either by design or by misapplication) and the relay causes an outageto the Element.

Events with NORMAL CLEARING 1 EventType

Description


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05 Single bus section fault or failure (200kV or above) resulting in one or more Automatic Outages.

06 Single internal circuit breaker fault (200kV or above) resulting in one or more Automatic Outages 2.

11 Automatic Outage of a single Element.13 Automatic Outage of two or more Elements within one NCCBS.31 Automatic Outages of two or more TADS adjacent AC Circuits or DC Circuits on

common structures. To qualify as Event Type 31 the Automatic Outages mustbe the direct result of the circuits occupying common structures 3.

49 Automatic Outage(s) with Normal Clearing not covered by Event Types 05through 31 above 4.

Events with AbnormalClearing 5 EventType

Description

60 Breaker Failure: One or more Automatic Outages with Delayed FaultClearing due to a 200kV and above circuit breaker being stuck, slow to openor failure to interrupt current.

61 Dependability (failure to operate): One or more Automatic Outages withDelayed Fault Clearing due to failure of a single Protection System (primaryor secondary backup) under either of these conditions:

a. failure to initiate the isolation of a faulted power system Element asdesigned, or within its designed operating time, or

b. In the absence of a fault, failure to operate as intended within itsdesigned operating time. (Item b is a very rare type of event.)

62 Security (unintended operation): One or more Automatic Outages causedby improper operation (e.g. overtrip) of a Protection System resulting inisolating one or more TADS Elements it is not intended to isolate, either during a fault or in the absence of a fault.

90 Automatic Outage(s) with Abnormal Clearing not covered by Event Types 60through 62 above 6.

Event ID Code :

Up to 10 alphanumeric characters - Each event shall have a unique Event ID. Dependentmode and common mode outages have the same Event ID. For Non-Automatic Outagesthis section is not needed.

Disturbance Reported:

Select if an outage report (EOP-004) was filed at NERC for this event or not.Options are Yes, No, and Dont Know.


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Outage Continuation Code: If an outage begins in a reporting calendar year and continues beyondthe end of the year(December 31) or, the calculation of a total Outage Duration is not possible. In this case,

the following process will be observed.1. Two separate Outage Durations will be input.a. For the reporting year when the outage started, the TO inputs

the Outage Start Time and calculates an Outage Duration fromthe Outage Start Time until the end of the reporting year. TheOutage Continuation Flag is input as 1.b. For the next reporting year, the same Event ID Code and sameOutage ID Code will be entered for the outage with an OutageStart Time equal to January 1, 00:00UTC of that reporting year . If the outage is concluded in that

reporting year, an

Outage Duration is calculated from the Outage Start Time. If theoutage continuesto the subsequent reporting year, the Outage Duration is entered

as 8760:00, or8784:00 for a leap year. The Outage Continuation Flag is input as

2.c. Most outages that are not concluded by the end of a reportingyear will conclude in the next reporting year. However, an outagemay span three or more reporting years. This process describedin b. above continues until the outage ends .

IV. Applications of Addition and Modifications to the Tables

Additions and Modifications to the Transmission Circuit AttributeTable

Attribute and outage information tables were designed with the understanding that mosttransmission system operators record or have access to the data required. Unless the datais a mandatory requirement, the operator will have to enter data to the best of their

knowledge until more accurate data is available.The operator is to provide the attribute data for circuits and transformers with a nominaloperating voltage above 200kV in order to comply with outage data requirements. Thereare two types of transmission circuit attributes, operational and physical characteristics.The operational characteristics provide data that describes the transmission circuit in


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terms of system operation and identifying parameters. These include systemidentification of the circuit, start and end dates of service, nominal voltage of thetransmission element, points of connection to the system and origin (parent code). The

physical characteristics describe the circuit in terms of its physical properties and providedata that describes the elements environment. The physical properties data include

circuit type, structure and material type, length, conductors per phase, overhead groundwire, and insulator type. The circuit environment is described by the terrain, elevation,and common corridor data.

Data entry maybe done by a translation program or manually depending on the number of data records required. It is expected that the first submission of data will require the mosteffort. Subsequent data submission will basically be a replication of the existing data withminor updates for configuration changes to the system and new additions. The followingis an explanation of the methodology to address the entry of new data records.

The primary need for a new data record is the addition of a newly constructed circuit that

was place in service during the current reporting year. Circuits have to be included inorder to have a link for assigning outage data In Example 1.1, the operator and thealphanumeric circuit code were entered to uniquely identify the circuit. Most operatorswill use an alpha numeric number to identify transmission elements within their system.As long as the identifier conforms to WECC outage data submission for circuit codes, theoperator circuit identification can be used. All other data will describe the circuit by itsoperating and physical attributes.

Example 1.1

Operator CircuitCode From To

XYZ A1B2C3D4

A second requirement for the creation of a new data record is for an extension or rerouting of an existing circuit that effectively changes the exposure of the circuit. Asseen in Figure 1.1, the circuit length may also increase due to a radial section beingtapped off an existing circuit. For this case, the circuit code for the existing circuit willhave to be retired and a new circuit code created for the new circuit length addition.

Figure 1.1


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In Figure 1.1, the original circuit had its length increased by the addition of a radial tap, but the circuits bounds did not change. Example 1.2 shows the changes required in theTransmission Circuit Attribute table for the circuits in Figure 1.1. Shown as RetiredCircuit Code table in Example 1.2, the original circuit was retired by simply placing aretirement date on the existing circuit code. An entry was made in the Comments columnthat provides an explanation for the retirement of the original circuit in Figure 1.1. In the

New Circuit Code example, a new circuit code was created to account for the addition of the tap: the circuit length was increased, the original circuit code was noted as the parentcode, and a comment was added to provide an explanation for the new circuit code.

Example 1.2

Original Circuit Code


CircuitLength in

Miles

InserviceDate

RetirementDate

ParentCode

XYZ A1B2C3D4 6.7 1/15/1975


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Original Circuit Configuration

New Circuit Configuration

Bkr Bkr

Bkr Bkr

Bus A

Bus A

Bus B

Bus B

Bus C


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Retired Circuit Code

Operator

Circuit

Code From To Miles

Inservice

Date

Retirement

Date

Parent

CodeXYZ A1B2C3D4 6.7 1/15/1975 2/25/2005 Ad

New Circuit Code


CircuitLength in

Miles

InserviceDate

RetirementDate

ParentCode

XYZ B2C3D4E5 7.5 2/25/2005 A1B2C3D4 Ad

New data records are also created by the reconfiguration of an existing circuit. Systemreconfigurations can occur when an isolation device is inserted between the existingisolation devices (breakers) that bound a circuit. These reconfigurations may or may notchange the length or reroute the existing circuit, but do create a new isolation boundary.The reconfiguration of an existing circuit will create two new circuit codes and retire anexisting circuit code in the Transmission Circuit Attribute table. The creation of the two

new circuit codes is independent of the insertion point of the new isolation device.

Figure 1.2


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Section 1

Figure 1.2 shows a reconfiguration of a circuit by the insertion of a breaker between twoexisting breakers that bound the original circuit. The changes required to theTransmission Circuit Attribute table are shown in Example 1.3.

In Example 1.3, the original circuit configuration circuit record is shown as OriginalCircuit Code. The original circuit has a circuit code PODX1234. PODX1234 was placedin service in 1/15/1975 and has a length of 100 miles between Bus A and Bus B. A new

breaker was inserted at Bus C between Bus A and Bus B in 9/14/2001. The reconfigured

existing circuit code was retired and two new circuit records were created in the table.Shown as Retired Circuit Code table in Example 1.3, the original circuit was retired by placing a retirement date on the existing circuit code and comment explaining theretirement of the circuit code record. In this example, two new circuit code table recordswere created. Shown as New Circuit Codes in Example 1.3, the two new circuit codes arePODX2485 and PODX2486. PODX2485 has a length of 25 miles and is bounded by the

breakers at Bus A and Bus C. PODX2486 is 75 miles long and is bounded by the breaker at Bus B and Bus C. Bus C is a common isolation point for both new circuits.

Example 1.3

Original Circuit Code


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Original Circuit Configuration

New Circuit ConfigurationBus A Bus B

Bus BBus A Bus C

Bkr Bkr

Bkr Bkr Bkr


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Section 1

Operator CircuitCode From To Miles

In serviceDate

RetirementDate

ParentCode

ABC PODX1234 Bus A Bus B 100.0 1/15/1975

Retired Circuit Code


In serviceDate

RetirementDate

ParentCode

ABC PODX1234 Bus A Bus B 100.0 1/15/1975 9/14/2001 New

New Circuit Code

Operator

Circuit

Code From To Miles

In service

Date

Retirement

Date

Parent

CodeABC PODX2485 Bus A Bus C 25.0 9/14/2001 PODX1234 New

New Circuit Code


In serviceDate

RetirementDate

ParentCode

XYZ PODX2486 Bus B Bus C 75.0 9/14/2001 PODX1234 New

Modifications to the Transformer Attribute Table

Modifications to the Transformer Attributes table are different than modification to theTransmission Circuit table. The Transformer Attribute table describes the location of thetransformer, not the transformer. For this reason, retirement of transformers can only take

place when the location of the transformer bank is actually retired from service. Thiseliminates the need to create a new Transformer Attribute record for a single phase of athree phase bank being removed from service or the transformer is moved from its

present location and replaced with another transformer.

Additions and Modifications to the Outage Information Table


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Most Outage Information table data is generally already recorded by most operators.There may be a need for a conversion in both time entry information and cause codes.

The time entries for outage records should be in GMT (Greenwich Mean Time) for theStandard Time where the outage occurred. If possible, the recording time should

mm/dd/yyyy format for the date and should be recorded to the nearest second.

GMT Example: A Standard Mountain Time of 9:00AM will be 15:00 PM GMT.

Cause codes for outages should be reported using one of the WECC General OutageCause code for each equipment outage. This may require the operator to translate fromthe operator outage cause code to one of the WECC General Outage Cause code. If atransmission equipment outage is an element of a dependent mode outage, it may or maynot have the same cause code as the initiating outage. For example, lightning may haveinitiated the original outage for a set of dependent outages, but the sequent outages may

have been caused by system protection failure. The initiating outage will be assigned theLightning (LIG) cause code and the subsequent outage will be assigned the cause codeTerminal Equipment (TER) for system protection failure.

Outage Mode not may be part of most WECC operators outage recording information or may be recorded differently. The Outage Information table requires two record entries toaccount for different initiating modes. The first of the entries is the Outage Mode. TheOutage Mode describes the initiating mode for an outage or set of equipment outages.There are five Outage modes: Independent, Dependent, Initiating Dependent, Commonand Common Initiating. Most outage will be classified as Independent Mode outages.The Event ID is use to identify the outage within the table and also serves as a link toidentify a set of dependent or common mode outages. Dependent and Common modeoutages will be assigned only one Event ID per related outages. A group of Dependentmode outages will usually have an Initiating Dependent Mode (DEPI) and a DependentMode (DEP) outage mode. If an initiating event is not within the scope of this database,the event will may not have a DEPI. This may include outages such as a 500kV breaker failure causing a 500kV line outage or a 69 kV under built circuit causing a 230kVoutage.

Independent Mode outages are outages that were isolated within the transmission elementisolation devices and did not impact other elements in the system. As seen in Example1.4, these outages records will only require an IND in the Outage Mode column andEvent ID in the Outage Information table. Example 1.4


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Operator Equipment Code Start Date/Time (GMT) End Date/Time (GMT) Cause Code Outage Mode Event IDCBA J36X100 11/12/2003 18:06:39 11/12/2003 18:15:23 TER IND 789123456

Common Mode outages involve two or more transmission elements and occur almostsimultaneously due to the same outage cause. Shown in Example 1.5, Common Modeoutages should have the same outage Cause Code and Event ID. The duration for theelements could be different in a Common Mode outage.

Example 1.5

Operator Equipment Code Start Date/Time (GMT) End Date/Time (GMT) Cause Code Outage Mode Event IDXYZ 150 06/08/2004 21:32:11 08/06/2004 22:31:16 WEA COM AUG6803AXYZ 361 06/08/2004 21:32:11 08/06/2004 23:26:00 WEA COM AUG6803A

Dependent Mode outages occur from an initiating outage and subsequently cause theoutage of other transmission element(s) in the system. Example 1.6 shows that the EventID for a Dependent Mode outage should be the same for all the associated elements. Theinitiating outage should be identified by placing the Initiating Dependent Mode (DEPI)identifier in the Outage Mode column. The restoration time for the elements in aDependent Mode outage may differ in length. The initiating outage may not be within thescope of recordable outage data required for the Outage Information table. Outages thatdo not have an initiating outage within the scope of the Outage Information tablerequirements will not have a DEPI for the set of dependent outages.

Example 1.6

Operator Equipment Code Start Date/Time (GMT) End Date/Time (GMT) Cause Code Outage Mode Event IDABC CGE54 07/12/2005 18:22:59 07/13/2005 02:22:59 FIR DEPI T-5588ABC FRG55 07/12/2005 18:23:01 07/12/2005 18:35:59 TER DEP T-5588ABC 153 07/12/2005 18:23:01 07/12/2005 18:35:59 LOS DEP T-5588

A Common Mode outage could be the initiating outage event for a set of subsequentoutage. As shown in Example 1.7, these outages should be identified with a CommonMode Initiating (COMI) identifier in the Outage Mode column and subsequent outages

should have the same Event ID.

Example 1.7


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Operator Equipment Code Start Date/Time (GMT) End Date/Time (GMT) Cause Code Outage Mode Event IDGTO T525099 05/17/2002 16:33:44 05/17/2002 18:52:25 TER COMI GT517C2GTO T525100 05/17/2002 16:33:44 05/17/2002 18:52:25 TER COMI GT517C2GTO T525136 05/18/2002 16:34:16 05/18/2002 18:35:25 TER DEP GT517C2

All outage records in the Outage Information table should be submitted complete. Theaccuracy of the start and End time should be the only variance.


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Section 1

Appendix A WECC Members

ADOE Alberta Department of Energy

AESO Alberta Electric System Operator AEUB Alberta Energy and Utilities BoardAESC Allegheny Energy Supply Company, LLCALTA AltaLink L.P.AWEA American Wind Energy AssociationWPE Aquila Networks-WPCACC Arizona Corporation CommissionAEPC Arizona Electric Power Cooperative, Inc.APA Arizona Power Authority

APS Arizona Public Service CompanyATCO ATCO Electric Ltd.AUR Auriga CorporationAPX Automated Power Exchange, Inc.AVA Avista Corp.BEPC Basin Electric Power CooperativeBMI Battelle Memorial Institute

BHP Black Hills Power BPAP Bonneville Power Administration Power Business LineBPAT Bonneville Power Administration Transmission Business LineBCHA British Columbia Hydro and Power AuthorityBCME British Columbia Ministry of Energy & MinesBCTC British Columbia Transmission CorporationBCUC British Columbia Utilities CommissionBURB Burbank Water and Power CBC California British Columbia TransmissionCompany, LLCCDWR California Department of Water ResourcesCEOB California Electricity Oversight BoardCEC California Energy CommissionCFBF California Farm Bureau FederationCISO California Independent System Operator CORA California Office of Ratepayer AdvocatesCPUC California Public Utilities CommissionCALP Calpine CorporationCES Cambridge Energy SolutionsCRGL Cargill Power Markets, LLCCEOE CE Obsidian EnergyCAWC Central Arizona Water Conservation DistrictCINE Cinergy Services, Inc.HHWP City and County of San Francisco Hetch Hetchy Water & Power ANHM City of AnaheimGLEN City of Glendale Public Service DepartmentRDNG City of ReddingRVSD City of RiversideCOPC Colorado Public Utilities CommissionCSU Colorado Springs Utilities

CFE Comision Federal de ElectricidadCOMP Compusharp Inc.CCG Constellation Energy Commodities Group, Inc.DGT Deseret Generation & Transmission Co-operativeDENA Duke Energy North America, LLCDETM Duke Energy Trading and Marketing, LLCECON Economic InsightEMMT Edison Mission Marketing & Trading, Inc.


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EQI EleQuant, Inc.EPE El Paso Electric CompanyECI Electrical Consultants, Inc.ENW Energy NorthwestESL Energy Strategies LLCENMX ENMAX CorporationEMC EPCOR Merchant and Capital L.P.EMCU EPCOR Merchant and Capital (US) Inc.

EWEB Eugene Water & Electric BoardFARM Farmington Electric Utility System FBC FortisBCFPLE FPL Energy LLCGEO Geo-Energy Partners-1983 Ltd.GBPP Gila Bend Power Partners, LLCPGR Gila River Power, L.P.GBT Great Basin Transmission, LLCHGC Harquahala Generating Company, LLCHESI Henwood Energy Services, Inc.HPLP Hunt Power, L.P.IPC Idaho Power CompanyIPUC Idaho Public Utilities CommissionIID Imperial Irrigation DistrictKEMA KEMA Inc.LCG LCG ConsultingLAC Los Alamos CountyLDWP Los Angeles Department of Water and Power MLCI Merrill Lynch Commodities, Inc.MWD Metropolitan Water District of Southern CaliforniaMTI Micron Technology Inc.MIR Mirant Americas, Inc.MID Modesto Irrigation DistrictMATL Montana Alberta Tie Ltd.MDEQ Montana Department of Environmental QualityMPSC Montana Public Service CommissionMWEC Morenci Water & Electric Company

NGU National Grid USA Service Company, Inc. NREL National Renewable Energy Laboratory NCI Navigant Consulting, Inc. NVOE Nevada State Office of Energy NMPRC New Mexico Public Regulation Commission NTD New Transmission Development Company[A Trans-Elect Company]

NAPG North American Power Group, Ltd. NCPA Northern California Power Agency NPCC Northwest Power and Conservation Council NWMT NorthWestern Energy NRG NRG Power Marketing, Inc.OCES Oak Creek Energy Systems, Inc.OOE Oregon Department of EnergyOPUC Oregon Public Utility CommissionPG&E Pacific Gas and Electric CompanyPAC PacifiCorpPACM PacifiCorp Merchant FunctionPASA Pasadena, City of PBEC Peabody Energy CorporationPRPA Platte River Power AuthorityPGE Portland General Electric CompanyPWX PowerexPPLE PPL EnergyPlus, LLC

PPLM PPL Montana, LLCPPM PPM Energy, Inc.PRAX Praxair, Inc.PSC Public Service Company of ColoradoPNM Public Service Company of New Mexico

NPUC Public Utilities Commission of NevadaCHPD Public Utility District No. 1 of Chelan CountyDOPD Public Utility District No. 1 of Douglas County


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Section 1

GCPD Public Utility District No. 2 of Grant CountyPSE Puget Sound EnergyREI Reliant Energy, Inc.RES RES-North AmericaRVE Roseville ElectricSMUD Sacramento Municipal Utility DistrictSRP Salt River ProjectSDGE San Diego Gas & Electric Company

SME Saracen Merchant Energy LP

WECC Members (continued)

SBP Sea Breeze PacificRegional Transmission Systems, Inc.SCL Seattle City LightSWPC Siemens Westinghouse Power CorporationSER Sempra Energy ResourcesSETC Sempra Energy Trading Corp.STGP Shell TradingSPR Sierra Pacific Resources TransmissionSNCL Silicon Valley Power City of Santa ClaraSNPD Snohomish County Public Utility District No. 1SCE Southern California Edison Company

SWTC Southwest Transmission Cooperative, Inc.SWPG Southwestern Power Group II, LLCSUEZ SUEZ Energy Marketing NA, Inc.SC2G SWRTA Class 2 GroupTPWR Tacoma Power TNSK TenaskaTNP Texas-New Mexico Power CompanyAES The AES CorporationBOE The Boeing CompanyTAUC TransAlta Utilities CorporationTCP TransCanada Energy Ltd.TANC Transmission Agency of Northern CaliforniaTSGT Tri-State Generation and TransmissionAssociation, Inc.TSMD Tri-State Generation and TransmissionAssociation, Inc.TEP Tucson Electric Power Company

TIDC Turlock Irrigation DistrictUSBR U.S. Department of Interior,Bureau of ReclamationUSDO (Denver Office)USGP (Great Plains)USLC (Lower Colorado)USMP (Mid-Pacific)USPN (Pacific Northwest)USUC (Upper Colorado)UAMP Utah Associated Municipal Power SystemsUCCS Utah Committee of Consumer ServicesDPU Utah Division of Public UtilitiesUEO Utah Energy OfficeUMPA Utah Municipal Power AgencyUPSC Utah Public Service CommissionUSE Utility System Efficiencies, Inc.VEA Valley Electric Association, Inc.OTED Washington State Office of Trade & EconomicDevelopmentWUTC Washington Utilities and TransportationCommissionWECI Wellhead Electric Company, Inc.WAPA Western Area Power AdministrationWAHQ (Golden, Colorado)WACM (Loveland, Colorado)


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Section 1

WALC (Phoenix, Arizona)WASN (Sacramento, California)WAUC (Salt Lake City, Utah)WAUW (Billings, Montana)WLB Westmoreland Coal CompanyWEMT Williams Power Company, Inc.WIA Wyoming Infrastructure AuthorityWPSC Wyoming Public Service Commission


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Appendix B TRD/TADS Outage Cause Codes

There are no differences in these outages codes between WECC and NERC.

Weather, excluding lightningAutomatic Outages caused by weather such as snow, extreme temperature, rain, hail, fog,sleet/ice, wind (including galloping conductor), tornado, microburst, dust storm, andflying debris caused by wind.

LightningAutomatic Outages caused by lightning.

EnvironmentalAutomatic Outages caused by environmental conditions such as earth movement(including earthquake, subsidence, earth slide), flood, geomagnetic storm, or avalanche.

ContaminationAutomatic Outages caused by contamination such as bird droppings, dust, corrosion, saltspray, industrial pollution, smog, or ash.

Foreign InterferenceAutomatic Outages caused by foreign interference from such objects such as an aircraft,machinery, a vehicle, a train, a boat, a balloon, a kite, a bird (including streamers), ananimal, flying debris not caused by wind, and falling conductors from one line intoanother. Foreign Interference is not due to an error by a utility employee or contractor.Categorize these as Human Error.

FireAutomatic Outages caused by fire or smoke.

Vandalism, Terrorism or Malicious ActsAutomatic Outages caused by intentional activity such as shot conductors or insulators,removing bolts from structures, and bombs.

Failed AC Substation EquipmentAutomatic Outages caused by the failure of AC Substation; i.e., equipment inside thesubstation fence including Transformers and circuit breakers but excluding ProtectionSystem equipment. Refer to the definition of AC Substation.

Failed AC/DC Terminal EquipmentAutomatic Outages caused by the failure of AC/DC Terminal equipment; i.e., equipmentinside the terminal fence including PLC (power-line carrier) filters, AC filters, reactorsand capacitors, Transformers, DC valves, smoothing reactors, and DC filters butexcluding Protection System equipment. Refer to the definition of AC/DC Terminal.


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Failed Protection System EquipmentAutomatic Outages caused by the failure of Protection System equipment. Includes anyrelay and/or control misoperations except those that are caused by incorrect relay or control settings that do not coordinate with other protective devices. Categorize these asHuman Error.

Failed AC Circuit EquipmentAutomatic Outages related to the failure of AC Circuit equipment, i.e., overhead or underground equipment outside the substation fence. Refer to the definition of ACCircuit.

Failed DC Circuit EquipmentAutomatic Outages related to the failure DC Circuit equipment, i.e., overhead or underground equipment outside the terminal fence. Refer to the definition of DCCircuit. However, include the failure of a connecting DC bus within an AC/DC Back-to-Back Converter in this category.

VegetationAutomatic Outages (both Momentary and Sustained) caused by vegetation, with theexception of the following exclusions which are contained in FAC-003-1:

1. Vegetation-related outages that result from vegetation falling into lines fromoutside the right of way that result from natural disasters shall not be consideredreportable with the Vegetation Cause Code. Examples of disasters that couldcreate non-reportable Vegetation Cause Code outages include, but are not limitedto, earthquakes, fires, tornados, hurricanes, landslides, wind shear, major stormsas defined either by the Transmission Owner or an applicable regulatory body, icestorms, and floods, and

2. Vegetation-related outages due to human or animal activity shall not beconsidered reportable under the Vegetation Cause Code. Examples of human or animal activity that could cause a non-reportable Vegetation Cause Code outageinclude, but are not limited to, logging, animal severing tree, vehicle contact withtree, arboricultural activities or horticultural or agricultural activities, or removalor digging of vegetation.

Outages that fall under the exclusions should be reported under another Cause Code andnot the Vegetation Cause Code.

Power System ConditionAutomatic Outages caused by power system conditions such as instability, overload trip,out-of-step, abnormal voltage, abnormal frequency, or unique system configurations(e.g., an abnormal terminal configuration due to existing condition with one breaker already out of service).

Human ErrorAutomatic Outages caused by any incorrect action traceable to employees and/or contractors for companies operating, maintaining, and/or providing assistance to theTransmission Owner will be identified and reported in this category. Also, any human


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failure or interpretation of standard industry practices and guidelines that cause an outagewill be reported in this category.

UnknownAutomatic Outages caused by unknown causes should be reported in this category.

OtherAutomatic Outages for which the cause is known; however, the cause is not included inthe above list.

Appendix C WECC TRD Definitions

Transmission Element:

The Transmission Element is the reporting element (transmission line, cable or atransformer) bound by automatic protective devices (a.k.a. breaker to breaker).

In-Service:The transmission element is energized and fully connected to the system.

Outage:The transmission element is not in the in-service state; i.e., it is partially or fully isolatedfrom the system. Single pole successful re-closing events are not considered outages.

De-rated:

This is a state where the operation of the transmission element is only possible in a lessthan full design capability, which is in the In-Service State.

Automatic Outage:An outage initiated by an automatic protection device.

Manual Outage:An outage initiated by intentional or inadvertent operator action.

Forced Outage:An Automatic Outage or a Manual Outage that cannot be deferred more than 30 minutes.

Planned (Scheduled) Outage:An intentional Manual Outage that could have been deferred more than 30 minutes.

Operational Outage:An intentional Manual Outage for the purpose of an emergency or to maintain the systemwithin its limits.


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Momentary (transient) outage:A Forced Outage of duration of less than one minute and is therefore recorded as zeroduration. Generally, it covers only automatic re-closure events.

Sustained Outage:A Forced Outage of duration of one minute or more. It does not include automatic re-closure events.

Outage Mode:One of three initial outage characteristics: independent, dependent, and common mode.

Independent Outage Mode: A Forced Outage of a single transmission element that does not impact other transmissionelements.

Dependent Outage Mode:

An outage that would not have occurred without an initiating outage on another circuit.Example: The outage of a 500kV circuit that causes the outage of 230kV circuits that areradial fed from the 500kv line.

Dependent Mode Initiating: The initiating outage that cause outage(s) on another circuit(s).

Common Mode Outage: A common mode outage is an outage that results from the same outage cause as another concurrent outage; example, double circuit tower failure.

Common Mode Initiating: An initiating common mode outage that initiated outage(s)on another circuit(s).

Operator:The operating agent has operational control of the transmission element. The operatingagent may not be the owner of the transmission element or conduct maintenance on thecircuit.

Common Corridor

Continuous right-of-way or two parallel right-of-ways with centerline separation less than

the longest span length of the two transmission circuits at the point of separationor 500 feet, whichever is greater, and no natural barriers (such as hills, rivers, etc.)

between the transmission circuits. This separation requirement does not apply tothe last five spans of the transmission circuits entering into a substation.


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Appendix D NERC TADS Definitions

ElementThe following are Elements for which TADS data are to be collected:

1. AC Circuits 200 kV (Overhead and Underground)2. Transformers with 200 kV low-side voltage3. AC/DC Back-to-Back Converters with 200 kV AC voltage, both sides4. DC Circuits with +/-200 kV DC voltage

An Element may also be referred to as a TADS Element in the Manual. They have the samemeaning.

Protection SystemProtective relays, associated communication systems, voltage and current sensingdevices, station batteries and DC control circuitry. 1

AC CircuitA set of AC overhead or underground three-phase conductors that are bound by ACSubstations. Radial circuits are AC Circuits.

The boundary of an AC Circuit extends to the transmission side of an AC Substation. Acircuit breaker, Transformer, and their associated disconnect switches are not considered

part of the AC Circuit but instead are defined as part of the AC Substation. The ACCircuit includes the conductor, transmission structure, joints and dead-ends, insulators,ground wire, and other hardware, including in-line switches. The AC Circuit includes in-line switches used to sectionalize portions of the AC Circuit as well as seriescompensation (capacitors and reactors) that is within the boundaries of the AC Circuit

even if these in-line devices are within an AC Substation. If these devices are notwithin the AC Circuit boundaries, they are not part of the AC Circuit but instead are partof the AC Substation. The diagrams on the next several pages explain this concept. Thered arcs define the AC Circuit boundaries. 2

In Figure 1 (next page), the series capacitor, bypass circuit breaker, and numerousdisconnect switches are in a fenced AC Substation that is within the boundaries of the ACCircuit itself. When the series capacitor is connected and the bypass breaker is open, thecapacitor and its disconnect switches are part of the AC Circuit. When the bypass

breaker is closed, the bypass breaker and its disconnect switches (not shown) are part of the AC Circuit.

1 This definition is in the current NERC Glossary of Terms Used in Reliability Standards .2 To simplify future diagrams, disconnect switches may not be shown.


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In Figure 2, the series reactor and in-line switches are part of the AC Circuit since theyare within the AC Circuit boundaries even though they are within the AC Substation

boundaries. In Figure 3, they are not part of the AC Circuit because they are not withinthe AC Circuit boundaries.

O O

A BNC

Figure 1

Two in-line NC switches and one series capacitor are partof the AC Circuit between AC Substations A and B. Whenthe bypass breaker and its disconnect switches (notshown) are closed and the capacitor switches opened, thebreaker and its switches are part of the AC Circuit.

NC

NO

O O O O

A BNC

Figure 1

Two in-line NC switches and one series capacitor are partof the AC Circuit between AC Substations A and B. Whenthe bypass breaker and its disconnect switches (notshown) are closed and the capacitor switches opened, thebreaker and its switches are part of the AC Circuit.

NC

NO

Figure 2

Two in-line NC switch and one series reactor are partof the AC Circuit between AC Substations A and B. The

AC Circuit boundaries are the breaker disconnect switchin AC Substation A and the high-side disconnect switchon the Transformer in AC Substation B.

O O

A B

NCNC

NO

Figure 2

Two in-line NC switch and one series reactor are partof the AC Circuit between AC Substations A and B. The

AC Circuit boundaries are the breaker disconnect switchin AC Substation A and the high-side disconnect switchon the Transformer in AC Substation B.

O O O O

A B

NCNC

NO

Figure 3

Two in-line NC switches and one series reactor are part of the AC Substation

and not part of the AC Circuit between AC Substations A and B

O

A

O

B

NCNC

NO

Figure 3

Two in-line NC switches and one series reactor are part of the AC Substation

and not part of the AC Circuit between AC Substations A and B

O O

A

O O

B

NCNC

NO


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TransformerA bank comprised of three single-phase transformers or a single three-phase transformer.A Transformer is bounded by its associated switching or interrupting devices.

AC Substation

An AC Substation includes the circuit breakers and disconnect switches which define the boundaries of an AC Circuit, as well as other facilities such as surge arrestors, buses,Transformers, wave traps, motorized devices, grounding switches, and shunt capacitorsand reactors. Series compensation (capacitors and reactors) is part of the AC Substationif it is not part of the AC Circuit. See the explanation in the definition of AC Circuit.Protection System equipment is excluded.

AC/DC TerminalA terminal that includes all AC and DC equipment needed for DC operation such as PLC(power-line carrier) filters, AC filters, reactors and capacitors, Transformers, DC valves,smoothing reactors and DC filters. On the AC side, an AC/DC Terminal is normally

bound by AC breakers at the AC Substation bus where it is connected. On the DC side, itis bound by DC converters and filters. Protection System equipment is excluded.

AC/DC Back-to-Back ConverterTwo AC/DC Terminals in the same location with a DC bus between them. The

boundaries are the AC breakers on each side.

DC CircuitOne pole of an Overhead or Underground DC line which is bound by an AC/DCTerminal on each end.

Overhead CircuitAn AC or DC Circuit that is not an Underground Circuit. A cable conductor AC or DCCircuit inside a conduit which is not below the surface is an Overhead Circuit. A circuitthat is part Overhead and part Underground is to be classified based upon the majoritycharacteristic (Overhead Circuit or Underground Circuit) using Circuit Miles.

Underground CircuitAn AC or DC Circuit that is below the surface, either below ground or below water. Acircuit that is part Overhead Circuit and part Underground Circuit is to be classified basedupon the majority characteristic (Overhead Circuit or Underground Circuit) using CircuitMiles.

Circuit MileOne mile of either a set of AC three-phase conductors in an Overhead or UndergroundAC Circuit, or one pole of a DC Ci

Documents

2012 Wecc Trdtd Users Guide