austin energy substations name - bidnet

NAME ADDRESS MAP GRID LATITUDE LONGITUDE

AD AUSTIN DAM 3617 Lake Austin Blvd. 30-17-35N 97-47-1WAG ANGUS VALLEY 6509 Yaupon Drive MG-33 30-24-02N 97-46-39W

AMD ADVANCED MICRO DEVICES 5204 E. Ben White Blvd. MK-17 30-12-53N 97-43-25WAU AUSTROP Blake Manor Road, 1 mile North of FM 969 30-15-01N 97-29-12WBA BARTON 2430 S. Capital of Texas Highway 30-15-56N 97-49-9W

BAL BALCONES 3300 Braker Lane MJ-32 30-23-28N 97-43-49WBC BEE CREEK 3602 N. Red Bud Trail MF-24 30-17-38N 97-47-22WBE BERGSTROM 1800 E. Highway 71 30-13-6N 97-40-21WBL BRODIE LANE 9612 Brodie Lane MD-15 30-11-16N 97-50-54WBR BRACKENRIDGE 1300 North IH 35 30-16-20N 97-43-57WBU BURLESON 3700 Todd Lane 30-12-52N 97-44-09WCA CENTRAL AUSTIN 909a W. 45th St MJ-26 30-18-38N 97-44-01WCC CARSON CREEK 3310 McCall Lane 30-12-11N 97-41-10WCF COMMONS FORD 115 River Hills Rd. MC-26 30-18-54N 97-51-17WCL CARDINAL LANE 812 Cardinal Lane MH-19 30-14-01N 97-46-08WCM CAMERON 1312 Rutherford Lane 30-20-23N 97-41-11WDE DESSAU 3200 E. Yager Ln. MM-31 30-22-25N 97-38-35WDG DAFFIN GIN 8015 Decker Lane MQ-26 30-1835N 97-36-55WDL DUNLAP* 7612 Taylor Ln., ManorDP DECKER POWER PLANT 8317 Decker Lane 30-18-11N 97-36-46WEB ED BLUESTEIN 3501 Ed Bluestein Blvd. MN-22 30-15-58N 97-39-47WER ELROY* (at Formula 1 racetrack)FI FIESTA 3909 N. IH35 NB Service Road MK-24 30-17-42N 97-43-07W

FPP FAYETTE POWER PLANT La Grange, Texas 29-54-58N 96-45-13WFV FISKVILLE 9800 Middle Fiskville Road 30-21-44N 97-40-57WGF GARFIELD Elm Ridge Rd., Bastrop, Texas 30-08-33N 97-44-39WGR GROVE 2706 Montopolis Dr. 30-13-0.0N 97-42-41WHA HARRIS 302 E. 24th Street MJ-24 30-24-03N 97-44-39WHC HICROSS 6714 Bluff Springs Road 30-11-11N 97-46-07WHL HOWARD LANE 2305 Gardenia Street 30-25-59N 97-41-19WHM HAMILTON 4603 Hamilton Lane 30-24-2N 97-44-36WHO HOLMAN Fayette County Road 1383 29-47-45N 96-52-42WHP HOLLY POWER PLANT 2401 Holly Street 30-15-1N 97-43-13WHV HIDDEN VALLEY 4501 N. FM 620, Bldg. G MA-32 30-23-02N 97-54-01WJE JETT 6622 Vaught Ranch Rd. MF-31 30-22-30N 97-48-22WJL JUSTIN LANE 7520 North Lamar MK-28JV JOLLYVILLE 13715 County Road 183 30-28-45N 97-46-53WKB KINGSBERY 5001 Alf Street 30-15-55N 97-41-13WKL KOENIG LANE 811 Old Koenig Lane 30-19-41N 97-45-36WLP LOST PINES HWY 21 E, Bastrop, Texas 30-08-52N 97-16-22WLS LAKESHORE 3106 West Lake Drive 30-18-53N 97-46-49WLW LAKEWAY 15310 Kollmeyer Drive 30-22-19N 97-56-39WLY LYTTON SPRINGS Caldwell County Rd. 177 30-0018N 97-40-26WMC MCNEIL 11900 Knollpark 30-23-36N 97-41-20WMP MAGNESIUM PLANT 8914 Research Blvd. 30-22-24N 97-43-20WMT MET CENTER 7315 ½ Metro Center Drive MK-18 30-12-39N 97-41-35WMU MUELLER* 4307 Manor Road ML-25 30-17-58N 97-41-22WNL NORTHLAND 3101 Northland Drive MH-28 30-20-7N 97-45-15NW NORTHWEST 8400 W. Parmer Lane MH-39 30-27-52N 97-45-26WOC ONION CREEK 12705 Fallwell Lane 30-12-37N 97-36-59WOH OAK HILL 5915 McCarty Lane MC-19 30-14-01N 97-51-34WPE PEDERNALES 2302 Haskell MK-21 30-15-00N 97-43-17WPK PILOT KNOB 9908 FM 812 30-09-46N 97-40-54WPL PATTON LANE 6501 W. William Cannon 30-14-16N 97-52-12WRC RINARD CREEK*RP RIVERPLACE 10712 R.M. 2222 MD-33 30-23-55N 97-50-32WRS RAINEY STREET* Lambie and IH-35 MJ-21 30-15-25N 97-44-17WSH SAND HILL POWER PLANT 13005 Fallwell Lane MQ-17 30-12-35N 97-36-51WSK SPRINKLE 10600 Cameron Rd. 30-21-12N 97-38-43WSL SLAUGHTER 1111 Slaughter Lane ME-14 30-10-18N 97-48-40WSP SEAHOLM POWER PLANT 800 Cesar Chavez 30-15-59N 97-45-8W

AUSTIN ENERGY SUBSTATIONS

7/19/2011Attachment 1

SR STONEY RIDGE* 7007 - 1/2 Heine Farm RoadST STECK 3419 Steck Avenue 30-22-1N 97-44-28W

STP SOUTH TEXAS PROJECT Bay City, Texas 28-47-49N 96-03-09WSU SUMMIT 11300 Burnet Road 30-23-53N 97-43-23WSW SALEM WALK 5300 Salem Hill Drive MG-17 30-12-56N 97-47-23WTP TRADING POST 14500 W. Hwy 71 30-18-47N 97-58-17WTR TECHRIDGE 905 W. Howard Lane MN-35 30-25-11N 97-39-57WVE VEGA 6501 W. William CannonWA WARREN 2100 West 35th Street 30-18-38N 97-45-29WWB WELLS BRANCH 14608 1/2 Single TraceWC WALNUT CREEK 7401 FM 969 30-16-26N 97-39-9WWI WILLIAMSON 6505 McNeil Road 30-26-14N 97-45-0.0WWL WHELESS LANE 2106 Wheless Lane 30-18-47N 97-41-4W

*Future Substation

7/19/2011Attachment 1

City of Austin - JOB DESCRIPTION

Power Control System Technician I

FLSA: Standard/Non-Exempt EEO Category: (70) Skill Craft

Class Code: 17090 Salary Grade: ZK0

Approved: October 24, 1997 Last Revised: October 20, 2014

Purpose:

Under direct supervision, perform installation and maintenance activities for all Electric Utility communications, relaying, measurement, monitoring and control equipment installed and associated with the operation of the Energy Control Center and the Electric Energy Delivery System.

Duties, Functions and Responsibilities:

Essential duties and functions, pursuant to the Americans with Disabilities Act, may include the following. Other related duties may be assigned.

1. Installs, enhances, troubleshoots, calibrates and repairs systems and/or equipment including: SCADA/AGC, EnergyManagement System, active map board, low power radio, multi-address radio, voice radio, digital telephone peripheralequipment.

2. Installs & maintains substation electrical equipment i.e., circuit breakers, transformers, OCBs, switches, motors,meters, relays, remote terminal units, analog/digital telemetry, relay communications systems, fault recording systems,and fault locating systems, etc.

3. Uses various electrician hand tools i.e., snips, screwdrivers, pliers, wire cutters, etc.4. Connects power cables to equipment e.g., generators, alarm systems, lighting systems, etc.5. Installs optical fiber, wire, conduit, coaxial cable, etc. Installs and maintain power transformers. Installs protective

relays. Installs electronic measuring (metering) systems.6. Operates electronic testing equipment.7. Maintains stock and parts inventories. Maintains documentation for all systems.8. Responds to scheduled/unscheduled on call duties9. Answers customer questions and provide assistance as needed.

Responsibilities - Supervisor and/or Leadership Exercised:

Knowledge, Skills, and Abilities:

Must possess required knowledge, skills, abilities and experience and be able to explain and demonstrate, with or without reasonable accommodations, that the essential functions of the job can be performed. Knowledge of utility communication, relaying and monitoring and control systems. Knowledge of applicable processes, techniques, and methods. Knowledge of Federal, State, Local laws, and ordinances. Knowledge of Electric Utility policy, and procedures. Skill in oral and written communication. Skill in using computers and related software applications. Skill in data analysis and problem solving. Skill in reviewing and interpreting of blueprints and schematics for relay applications. Ability to work with frequent interruptions and changes in priorities. Ability to quickly recognize and analyze irregular events.

Minimum Qualifications:

Associate Degree from an accredited college or university with major course work in Engineering, Electronics, or in afield related to the job.

Experience may substitute for education up to two (2) years.

Licenses and Certifications Required:

If position resides in Electric Substation Maintenance, it may require a CDL. Valid drivers license

This description is intended to indicate the kinds of tasks and levels of work difficulty required of the position given this title and shall not be construed as declaring what the specific duties and responsibilities of any particular position shall be. It is not intended to limit or in any way modify the right of management to assign, direct and control the work of employees under supervision. The listing of duties and responsibilities shall not be held to exclude other duties not mentioned that are of similar kind or level of difficulty.

ATTACHMENT 2

Power Control System Technician II

Approved: October 24, 1997 Last Revised: June 05, 2008

Purpose:

Under general supervision, perform installation and maintenance activities for all Electric Utility communications, relaying, measurement, monitoring and control equipment installed and associated with the operation of the Energy Control Center and the Electric Energy Delivery System.

1. Install, enhance, troubleshoot, calibrate and repair systems and/or equipment including: SCADA/AGC, EnergyManagement System, active map board, low power radio, multi-address radio, voice radio, digital & wirelesstelephone peripheral equipment. Install, configure and test electronic measuring (metering) systems. Operateelectronic testing equipment.

2. Install and maintain substation electrical equipment i.e., circuit breakers, transformers, OCBs, switches, motors,meters, relays, remote terminal units, analog/digital telemetry, relay communications systems, fault recordingsystems, and fault locating systems, etc. Install optical fiber, wire, conduit, coaxial cable, etc. Install and maintainpower transformers. Install, configure and test protective relays.

3. Familiar with ANSI Standards for electric systems, ERCOT Protocols and Operating Guides, and communicationnetwork protocols; DNP 3.0, TCP/IP, IEEE 802b, Modbus, and ICCP.

4. Maintain stock and parts inventories. Use various electrician hand tools i.e., snips, screwdrivers, pliers, wirecutters, to perform installation, modification and preventative maintenance of various systems.

5. Proficient with schematics, blueprints, cable schedules, wire diagrams, one-lines. Perform trip checks, point-to-point checks, circuit analysis, and in-service checks of substation equipment.

6. Connect power cables to equipment e.g., generators, alarm systems, lighting systems, etc.7. Coordination with project engineers to ensure systems reliability is met by reviewing blueprints and schematics for

the installation, testing and revisions of various systems.8. Maintain documentation for all systems and proficient with computer software.

Maintain compliance for ISO and ERCOT reports.9. Answer customer questions and provide assistance as needed.

May provide leadership, work assignments, evaluation, training, and guidance to others.

Must possess required knowledge, skills, abilities and experience and be able to explain and demonstrate, with or without reasonable accommodations, that the essential functions of the job can be performed.

Knowledge of utility communication, relaying and monitoring and control systems. Knowledge of applicable processes, techniques, and methods. Knowledge of Federal, State, Local laws, and ordinances. Knowledge of Electric Utility policy, and procedures. Knowledge of leadership and training techniques Skill in oral and written communication. Skill in using computers and related software applications. Skill in data analysis and problem solving. Skill in reviewing and interpreting of blueprints and schematics for relay applications. Ability to work with frequent interruptions and changes in priorities. Ability to train others. Ability to quickly recognize and analyze irregular events.

Associate Degree from an accredited college or university with major course work in a field related to the job, plustwo (2) years of experience in a field related to the job

Experience may substitute for education up to two (2) years

ATTACHMENT 2

Valid driver's license.

Power Control System Technician III

Class Code: 17084 Salary Grade: ZN0

Approved: January 22, 2006 Last Revised: October 20, 2014

Purpose:

Under minimal supervision, perform installation and maintenance activities for all Electric Utility communications, relaying, measurement, monitoring and control equipment installed and associated with the operation of the Energy Control Center and the Electric Energy Delivery System.

1. Installs, enhances, troubleshoots, calibrates and repairs systems and/or equipment including: SCADA/AGC,Energy Management System, active map board, low power radio, multi-address radio, voice radio, digital andwireless telephone peripheral equipment.

2. Installs and maintains substation electrical equipment i.e., circuit breakers, transformers, OCBs, switches, motors,meters, relays, remote terminal units, analog/digital telemetry, relay communications systems, fault recordingsystems, and fault locating systems, etc.

3. Configures intelligent electronic devices (IED's) for electric system automation i.e. protective relays, solid statemeters, remote terminal units, voltage regulators using applicable manufacturer's software.

4. Proficient with ANSI Standards for electric systems. Proficient with ERCOT Protocols and Operating Guidelines.Proficient with communication network protocols; DNP 3.0, TCP/IP, IEEE 802b, Modbus. Proficient withschematics, blueprints, cable schedules, wire diagrams, one-lines. Proficient with various manufacturers' softwarepackages to operate electronic test equipment.

5. Assists with engineering design, changes.6. Uses various electrician hand tools i.e., snips, screwdrivers, pliers, wire cutters, etc.7. Connects power cables to equipment e.g., generators, alarm systems, lighting systems, etc.8. Installs optical fiber, wire, conduit, coaxial cable, etc. Installs and maintains power transformers. Installs,

configures and tests protective relays. Installs, configures and tests electronic measuring (metering) systems.9. Performs trip checks, point-to-point checks, circuit analysis, and in-service checks of substation equipment.

10. Maintains stock and parts inventories. Maintains documentation for all systems.11. Responds to scheduled/unscheduled on call duties. Answers customer questions and provide assistance as

needed.

May provide leadership, work assignments, evaluation, training, and guidance to others

Must possess required knowledge, skills, abilities and experience and be able to explain and demonstrate, with or without reasonable accommodations, that the essential functions of the job can be performed. Knowledge of utility communication, relaying and monitoring and control systems. Knowledge of applicable processes, techniques, and methods. Knowledge of Federal, State, Local laws, and ordinances. Knowledge of Electric Utility policy, and procedures. Knowledge of leadership and training techniques Skill in oral and written communication. Skill in using computers and related software applications. Skill in data analysis and problem solving. Skill in reviewing and interpreting of blueprints and schematics for relay applications. Ability to work with frequent interruptions and changes in priorities. Ability to train others. Ability to quickly recognize and analyze irregular events.

Associate Degree from an accredited college or university with major course work in Engineering, Electronics, orin a field related to the job, plus four (4) years experience related to installation and maintenance of electronic

ATTACHMENT 2

communications, computer and peripheral equipment or control and instrumentation equipment. Experience may substitute for education up to two (2) years

If position resides in Electric Substation Maintenance, it may require a CDL. Valid driver's license.

Power Control System Supervisor

Approved: October 24, 1997 Last Revised: October 20, 2014

Purpose:

Provide supervision to perform installation and maintenance activities for all Electric Utility communications, relaying, measurement, monitoring and control equipment installed and associated with the operation of the Energy Control Center and the Electric Energy Delivery System. Activities include: designing, installing, configuring, monitoring, administering and troubleshooting.

1. Supervises the installation, enhancement, troubleshooting, calibration and repair process for systems and/orequipment including: SCADA/AGC, Energy Management System, active map board, low power radio, multi-address radio, voice radio, digital and wireless telephone peripheral equipment.

2. Supervises the installation and maintenance of substation electrical equipment i.e., circuit breakers, transformers,OCBs, switches, motors, meters, relays, remote terminal units, analog/digital telemetry, relay communicationssystems, fault recording systems, and fault locating systems, etc.

3. Configures intelligent electronic devices (IED's) for electric system automation i.e. protective relays, solid statemeters, remote terminal units, voltage regulators using applicable manufacturer's software packages.

4. Proficient with ANSI Standards for electric systems. Proficient with ERCOT Protocols and Operating Guidelines.Proficient with communication network protocols; DNP 3.0, TCP/IP, IEEE 802b, Modbus, and ICCP. Performsemergency electric system restoration as necessary.

5. Performs complex diagnostic testing and repair on SCADA equipment, including computers, front-endprocessors, printers and other peripherals. Analyzes and resolves problems and discrepancies related to RemoteTerminal Unit (RTU) communications and data. Ensure that Operations has reliable and accurate data.

6. Proficient with schematics, blueprints, cable schedules, wire diagrams, one-lines. Proficient with variousmanufacturers' software packages to operate electronic test equipment.

7. Provides input into the development of Capital and O&M budgets.8. Interprets, explains and enforces City policies, procedures, building codes, specifications and ordinances.9. Communicates with schedulers/project management regarding work orders. Interfaces with city departmental and

intergovernmental entities. Answers customer questions and provide assistance.10. Monitors safety issues for work group.11. Responds to scheduled/unscheduled on call duties.

Responsible for the full range of supervisory activities including selection, training, evaluation, counseling, andrecommendation for dismissal

Must possess required knowledge, skills, abilities and experience and be able to explain and demonstrate, with or without reasonable accommodations, that the essential functions of the job can be performed. Knowledge of utility communication, relaying and monitoring and control systems. Knowledge of applicable processes, techniques, and methods. Knowledge of Federal, State, Local laws, and ordinances. Knowledge of Electric Utility policy, and procedures. Knowledge of leadership and training techniques Skill in oral and written communication. Skill in using computers and related software applications. Skill in data analysis and problem solving. Skill in reviewing and interpreting of blueprints and schematics for relay applications. Ability to work with frequent interruptions and changes in priorities. Ability to train others. Ability to quickly recognize and analyze irregular events. Knowledge of supervisory and managerial techniques and principles Skill in handling conflict and uncertain situations.

ATTACHMENT 2

Ability to establish and maintain effective communication and working relationships with city employees and the public.

Associate Degree from an accredited college or university with major course work in Engineering, Electronics, orrelated to the job, plus six (6) years experience in a field related to the installation and maintenance of electronic communications, computer and peripheral equipment or control and instrumentation equipment, two (2) years of which were in a lead or supervisory capacity.

Experience may substitute for education up to two (2) years

If position resides in Electric Substation Maintenance, it may require a CDL. Valid driver's license

TRIP CHECK GUIDELINE- CAPACITOR BANK PROTECTION

SUBSTATION ____ PROJECT _________________ _

TECHNICIAN(S) ----------------------ENGINEER COMPLETIO~N~D~A~T=E~---------------

This checklist is intended to help field personnel in the testing and commissioning of transmission level capacitor bank protection. The checklist is arranged in a logical sequence of testing and commissioning as it relates to issued for construction (IFC) drawings and the physical location of the equipment. For example, the R2 & R3 drawings (one-line & AC schematics) involve checking equipment current and potential circuits to the relays; the R4 drawings (DC schematics) involve testing the DC circuits (trip circuits, close circuits, relay inputs & outputs); followed by testing the relay settings and the final tests involve the DNP and hardwired SCAD A points. GENERAL

N!A Completed

0 0 0 0 0

Daily tailgate meeting prior to checkout including identification of safety risks, system risks, and work to be performed

A final walk through involving engineering and field operation supervisor(s) must be performed before any piece of equipment is energized. A continuity check must be performed to prove the "R-4s" intended protection and function. Validate the appropriate ratio, polarity, acb, vcb, and diagnostic tests were perfonned on equipment to be placed in service. (Maintenance dept.) Relays connected to time source and time verified. Trips must be isolated to avoid unwanted operation of in service equipment by tagging, utilizing isolation devices or disconnecting wires. This shall be verified by two personnel.

SWITCHY ARD EQUIPMENT Capacitor Bani{

N! A Completed 0 0 Confirm grounding method of capacitor bank

D D Measure individual capaCitor can capacitance and record in maintenance records

Capacitor Bank Circuit Breaker Completed

VerifY AC control power

VerifY DC control power

High priority alarm

Low priority alarm

Low gas alarm (if applicable)

Annunciator DCF

CT Visual inspection

CT's in use are unshmted & properly grounded

CT's not in use are shorted with jumpers & properly grounded

Primary current injection (if applicable)

0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 VerifY phasing and voltage level ofMB potentials to sync close unit

Comments

Doc ID: ESD Operating-100394 Trip Check Guideline-Cap .. Ver:1.2.0.0 Eff.Date:06/01/11

Pagel of3 Version 1.2.0.0

This document when printed is uncontrolled and for reference purposes only

Attachment 4

CAPACITOR BANK PROTECTION Breaker Trip & Close Circuits

N/ A Completed

Close circuit

Trip circuit 1

Trip circuit 2 (if applicable)

D D D D D D D D Relay output contacts pulsed and appropriate open/close operation verified

87V relay (451) 0 Other ________ _ N/ A Completed

0 0 Perform DC checks (Power Supply & Inputs)

Perfonn Relay Tests

Test Voltage alarm & trip settings

Test Overcurrent alarm & trip settings

D D D D D D D D D D D D D D D D D D

Test any other TRIP and SEL Logic Variable equations/elements

VerifY Output contacts

Test alarms, analogs, and inputs

VerifY Display points

VerifY passwords changed

Relay connected to DNP. SEL-203x, and Ethernet & communications verified

50/62 relay (3518) N/ A Completed

0 0 Perform DC checks (Power Supply & Inputs)

D D D D D D D D D D D D D D

86CAP Lockout Relay Nl A Completed

Perform Relay Tests

Test Retrip & breaker failure time delays

Test Voltage alarm & trip settings

VerifY Display points

Overcurrent settings

VerifY Passwords changed

Relay connected to SEL-2030 & communications verified

D D Relay DC check

D D Appropriate relay output contacts pulsed & lockout relay operation verified

0 0 Verify trip and lockout of all connected equipment/devices

SCADA/DNP Checkout (Confirmed with SCAD A System/ECC) N/A Completed

D D Verify all Control & Indications

D D VerifY all Alarms

0 0 VerifY all Analog values

D D VerifY all Statuses Points

Comments

Doc ID: ESD Operating-100394 Trip Check Guideline-Cap .. Ver:1.2.0.0 Eff.Date:06/01/11

Version 1.2.0.0 This document when printed is uncontrolled and for reference purposes only

Attachment 4

FINAL COMMISSIONING OF CAPACITOR BANK PROTECTION Energize Capacitor Bank

N/ A Completed 0 D During initial energization of capacitor bank, open associated 86B and/or 86BF test switches

except for the capacitor bank breaker providing interruption. Measure, confirm, and record all bus, neutral, and capacitor bank voltages (as applicable) in each relay Press appropriate push button on 87V ( 451) to display the compensation voltage magnitude and angle and manually place in the 87V (451) Automation settings AUTO _23 & AUTO _24 respectively

Remove (1) fuse in Capacitor Bank N/ A Completed

0 D Verify that both 87V and 50/62 relay generates a Capacitor Bank Alarm but does not trip

0 D Verify that alarm is received at ECC Remove (2) fuses in Capacitor Bank

NIA Completed 0 D Verify that both 87V and 50/62 relay issues a trip to the Capacitor Bank Breaker and Lockout

0 D Verify that alarm is received at ECC

Doc ID: ESD Operating-100394 Trip Check Guideline-Cap .. Ver:1.2.0.0 Eff.Date:06f01/11

Version 1.2.0.0 This document when printed !s uncontrolled and for reference purposes only

Attachment 4

7/21/2011

Page Circuit Device Name DNP Address

3 CL-PNL D-2032 2032 2030

CL-900 87V N/A

4 CL-900 50/51 9001

CL-900 50/62 N/A

CL-900-CAP-BANK-DNP .xis DNP Addresses

CL CAP BANK ADDITION DNP ADDRESSES

Relay Type Location RTU/Port Dymec Star

2032 PNL 24 2 STAR2

287V PNL5 N/A N/A

351·6 PNL 5 1 STAR 1

501 PNL 5 N/A N/A

CL-900-CAP-BANK-DNP.xls

Star Port Ethernet Comments

3 IP xx.x.xxx.xxx Existing Relay/IP

Attachment 5

7/21/2011

FUNCTION

CL-900-CAP-BANK-DNP .xis CL RTU HARDWIRE PTS

CL RTU HARDWIRED POINTS

POINT REMARKS

CL-900 SUPV TRIP/CLOSE/IND 3 CONTROL & INDICATION

CL-900 SUPV CNTL ENABLE/DISABLE 10 INDICATION

CL-900 287V LOP ALARM 11 INDICATION

CL-900 287V CAP ALARM 12 INDICATION

STATUS

NEW POINT

Attachment 5

7/21/2011

2030 PNLD Sellndex PI# Name #

0 SPARE 1 SPARE 2 SPARE 3 SPARE 4 SPARE 5 SPARE 6 SPARE 7 SPARE 8 SPARE 9 SPARE 10 SPARE 11 SPARE 12 SPARE 13 SPARE 14 SPARE 15 SPARE 16 SPARE 17 SPARE 18 SPARE 19 SPARE 20 SPARE 21 SPARE 22 SPARE 23 SPARE 24 SPARE

All scaling per point

Processors Analoqs Total Analogs

CL-900-CAP-BANK-DNP.xls PNL D SEL-2032

SEL-2032 DNP Point List Analog Inputs

Primary Full Scale Bandwidth Units Llim3 Llim2

Deadband REPORT ON= 1.00%

1 21 21

Limits llim1 Hlim1 Hlim2 Hlim3

Attachment 5

7/21/2011

Sel Index# PI#

0 0 1 1 2 2 3 3 4 4 5 5 6 6 7 7 8 8 9 9 10 10 11 11 12 12 13 13 14 14 15 15 16 16 17 17 18 18 19 19 20 20 21 21 22 22 23 23 24 24

CL-900-CAP-BANK-DNP.xls PNL D SEL-2032

SEL-2032 DNP Point List Digital Input Digital Outputs

Relay Word Sellndex Name Bit 0 state 1 state Normallnd PI# Name #

CL-900 351-6 REL FAIL IN13 Normal Alarm 0 CL-900 501 REL FAIL IN14 Normal Alarm 0 CL-900 287V REL FAIL IN15 Normal Alarm 0 SPARE SPARE SPARE SPARE SPARE SPARE SPARE SPARE SPARE SPARE SPARE SPARE SPARE SPARE SPARE SPARE SPARE SPARE SPARE SPARE SPARE SPARE

Processors 1 Processors 1 Status 25 Controls 0 Total Status 25 Total Control 0

Accumulators Sellndex

PI# Name # 0 1 2

Processors 1 Accum 0 Total 0

Attachment 5

7/21/2011

Cl-900 351S

I Sel index • DNPPt#

CL-900-CAP-BANK-DNP.xls CL-900 351-6

High Vultdge Breaker SEL-351-6 DNP Point List Analog Inputs

Nama Pn~:i:"" Oeadband Units um11s

CL-900 BAMP llnsl 32767 10 ,;rs Amps CL-900 CAMP linSI 32767 10CTS Amps

L-900 linsl 32767 10CTS w:t

I Relay Ph Setting

~ Relay DNP SeHing

Dec I I Mise' 'lace I 2

I Analogs I 51 I

11 Hlim2 Hlim3

Attachment 5

7/21/2011 CL-900-CAP-BANK-DNP.xls CL-900 351-6

High Voltage Breaker SEL-351-6 DNP Point List Digital Inputs u•~ .. c~l Outputs Accumulators

I in::~ Ptffl ~

;,~~·~it 0 stat I state I Nom allnd I PI Name in~=~• p • Name I Dnp P" I

CL·900 351~ ) PRI !SV14T lo,mal arm 10: DIAGWR lorrnal "m

I I I 362 L-900 LO PRI ~7 Normal (Alarm 0

~ L-900 ANNUN DCF No,mal (Alarm

" '""' ~·~R4 26

~~~~:~~~0 27

29 "l:~l!·~~h 32 :;:~·

trip, close pairs

£ 11 IB,eake<s 11

(Total Control Of (Total Of

Attachment 5

DocID: OP0001552 Ver: 1.0 Effective: 05/23/2013 Uncontrolled when printed.

PRE-ENERGIZATION CHECKLIST

Employees:__________________________________ Date:__________Station:___________________ Project:__________________________

Verify that RSO transmittal has been signed by Relay Setting Engineer

Have all Relay Settings verified by Relay Setting Engineer

Verify that all PT circuits are fused and connected per AC Schematics

Verify that all CT circuits are connected per AC Schematics and un- shorted

Verify that all CT, PT, control, and alarm circuits are lugged and tightened properly

Verify that all prints are hi-lighted and complete

Review and verify that the engineering trip check guidelines are completed and signed

Verify that all communication avenues are up and talking

Verify that there are no alarms locally or at Control Center

Verify that device labeling is correct or a temporary label is in place

Perform visual inspection of work performed verifying any temporaries have been removed and/or disconnected devices/wiring have been put back in service or properly tagged

Verify that all test switches are closed

Verify that no grounds are installed on equipment to be energized

Verify that no phasing is required before energization

Verify that the equipment to be energized is open

Comments:________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________

Completion Date: __________________________________________

Signature: ______________________________________________

REVISED GUIDELINES UPDATED OCTOBER 2013

GUIDELINES FOR FILLING OUT RTS VARIABLE INFORMATION UNDER RELAY DATA TAB.FILL OUT ALL IN CAPITAL LETTERS. EACH VARIABLE HAS TO BE FILLED OUT! THE COLUMNS BELOW THAT ARE UNDERLINED CAN BE DEFAULTED IN RTS UNDER THE DEVICE DATA TAB ON THE RIGHT HAND SIDE UNDERNEATH DEFAULT VALUES.TESTED BY: TECHNICIAN’S FULL NAME, (ERIC PORTER), (RICK

FERRARO) ***PERFORM ON ALL TESTING DOCUMENTS***DIVISION: AUSTIN ENERGYLOCATION: FULL NAME OF STATION (STONEY RIDGE)NMV: 345000, 138000, 69000, 13200, 12500, 12470PANEL #: 1, 2, 3--IN THE HOUSE, UNIT #2, UNIT #3--IN THE SWITCHGEAREQUIP #: JV-961, TR-1004, HC-963, SL-7, HV-965, BA-101112DEVICE: SEL-387, SEL-351S-7, SEL-351-6, RFL-9300, KF, CO-9, IAC53ANSI: 21,50,51,62,79,81,85,87,87B,87L,87T ANSI #’S ON PANELRLY FUNC: USE PRIMARY FUNCTION THAT IS LABELED FIRST AND IS THE

MAIN PROTECTIONC ELEMENT OF RELAY...DISTANCE, DIFFERENTIAL, OVERCURRENT, BREAKER FAILURE (USE FUNCTION THAT IS LABELED FIRST. EG…21/79 WOULD BE DISTANCE LEAVING OUT RECLOSER)

MANUFAC: MUST SPELL OUT…SCHWEITZER, RFL, ASEA BROWN BOVERI, GENERAL ELECTRIC, BASLERRLY MOD: 0311C01H2425461, 264C901A07IL./IB SEL-311L MANUAL, SEL-487V MANUAL, RFL-9300 MANUALSERIAL #: 200103746798, N/ABULK ES: 100KV ABOVE=YES, BELOW=NO- USE HIGHEST VOLTAGE ON

RELAY BEING PROTECTED. EG. XFMR DIFF=138KV HIGH SIDE, 12.5 LOW SIDE WOULD BE ANSWEREDYES.

MAINT INT: ELECTROMECHANICAL=4 YEARS, MICROPROCESSOR=10 YEARS

PREV DATE: IF IT IS KNOWN ENTER IT OTHERWISE RTS DEFAULTS IT TO 1/1/1900

CURR DATE: THIS WILL AUTOPOPULATE ONCE TEST ROUTINE IS SAVEDNEXT DATE: THIS WILL AUTOPOPULATE ONCE MAINTENANCE INTERVAL

IS ENTERED AND CURRENT TEST DATE IS POPULATED. TST ST CAL:USE STICKER TEST SET CALIBRATION DATE ON TEST SET.

THIS NEEDS TO BE WITHIN ONE CALENDAR YEAR FROM DATE YOU ARE TESTING RELAY ON.

ALL TEST DATE VARIABLES WILL BE AUTOMATICALLY POPULATED WHEN RESULT S AND ROUTINES ARE SAVED.

Relay Commissioning and Testing Requirements

AE-RLY

Relay Commissioning and Testing Requirements

1. Scope

1.1. This document provides the general guidelines and procedures required tocommission various relay schemes throughout AE’s utility system, but does not cover all possible scenarios.

1.2. With various diagnostic testing tools, this task performs the commissioningand testing of the relay package and associated monitoring and control devices.

2. References

2.1. Austin Energy Safety Manual

2.2. Tailboard

2.3. ESD Relay Construction Process

2.4. ESD Relay Construction Work Instructions

2.5. Guidelines for RTS

2.6. Pre-Energization Checklist

2.7. Equipment Manufactures Instruction Manuals and Drawings

2.8. Trip Check Guidelines

2.9. Net Zero Form

2.10. Voltage and Current Readings Checklist When Applicable

2.11. Relay Asset Form

3. Precautions

3.1. Perform tailboard, wear proper PPE, and know employees responsibility for safety.

3.2. Always isolate energy sources.

3.3. Prior to performing any relay trip testing, determine if any transfer trip andbreaker failure schemes are present and take the necessary precautions.

3.4. Always disable trip outputs prior to testing relays.

3.5. Be aware of the proper sequence when closing CT/PT knife switches prior toclosing trip switches.

3.6. Before measuring resistance with a multi-meter, always check for standingvoltage across open contacts.

3.7. Identify equipment to be worked on and protection schemes impacted by equipment (i.e. Bus Tie Breaker involves two bus schemes when commissioning one bus remain cognizant on impact to second bus. Transmission line relays impact other substation transmission line is tied to for example transfer trip).

4. Equipment Used

4.1. Multimeter

4.2. Relay Test Set

4.3. Equipment Manufactures Instruction Manuals and Leaflets

4.4. 3 Phase Meter

4.5. Test leads rated for task, paddles, etc.

4.6. Phasing Sticks (meters), note - use anytime bus has been modified, rebuilt or is a new build and anytime a line connected to a substation device has been reconfigured or reconductored, etc.

5. Acceptance Criteria

5.1. Relay commissioning work instruction insures that the complete protectionpackage operates as designed. This includes all auxiliary relays, communicationschemes and if functional testing is performed as per AE Reliability Process Manual the clearing devices are operating correctly.

6. Procedure

6.1. Drawing Check Acceptance

6.1.1. There shall be only one set of drawings used for circuit highlighting for all checkouts. The set of acceptance drawings shall be used by the technicianto determine the progress of the testing towards the completion of scheme verification.

6.2. General Relay Package Commissioning.

6.2.1. Relay Diagnostics: Test each relay using standard RTS test plan forproper function and accuracy. Insure relays are set in accordance with themost current relay settings.

6.2.2. All settable relays that are part of the protection package shall be tested.This may include multiple setting groups in some applications.

6.2.3. Verify proper relay settings (CT ratio matches drawing, logic settings on correct output, proper relay identification etc…). Do not make changes without informing relay engineering. This is not intended for relay technician to make calculations and verify settings required of engineer only obvious settings that require no calculations and can be verified with a drawing or issued relay settings.

6.2.4. Every input and output contact on every relay shall be checked for correct operation.

6.2.5. Test reports shall include relay, date, location, type and style of relay, and firmware version of the device, if applicable. Test reports shall include all expected and actual operating times and/or measurements found of the tested devices.

6.3. Functional Testing

6.3.1. Relay Scheme Testing

6.3.1.1. Every AC "Potential and Current" and DC "Control and Alarm" circuit shall be checked for correctness versus the schematic diagrams that have been supplied. Every circuit that is verified shall be highlighted on the set of acceptance drawings as to prove each wire and circuit has been checked for correctness. Any discrepancy found in the drawings or wiring shall be reported to engineering so a determination can be made as to the corrective action.

6.3.2. AC Circuits

6.3.2.1. High current injection should be done on the distribution switchgear throat through distribution breaker and with transmission through the breakers. Secondary current will be used on transmission systems and any distribution that allows access. A one-amp AC current shall be connected to the terminals of each individual CT so each phase can be checked for magnitude and polarity in all relays, proper CT going to proper relay or meter and test switches. Shorting switches shall be checked for proper operation.

6.3.2.2. All CT circuits shall be checked for a single ground on any CT circuit.

6.3.2.3. All AC voltage circuits shall be tested that no shorts exists before energizing and verified that only one ground exists for each circuit. A voltage of at least 67 volts shall be applied at the PT junction box or PT cabinet so each phase can be checked to verify that it is correct in all meters, relays, and any other device that may be connected.

6.3.2.4. All CT and PT circuits should be highlighted to verify they have been checked.

6.3.3. DC Circuits

6.3.3.1. Every DC Close, Trip 1, Trip 2, and relay control scheme shall have every circuit checked. DC circuit checks shall consist of verifying, starting from the battery bank to the DC panels, that polarity, conductor size, fuse size, and breaker size match the provided schematics. Each circuit shall be checked for shorts, grounds, and correct polarity.

6.3.3.2. Each DC circuit shall be checked for complete accuracy versus the supplied schematics. As circuits are checked, each input and output from any electromechanical or microprocessor relay shall be verified via display, computer, and/or manual operation. Electromechanical and microprocessor relays shall have all inputs and outputs highlighted on the acceptance drawing set to indicate they have been checked.

6.3.3.3. Any DC circuit that has a backup DC or AC source shall be checked for correct operation, polarity, grounds, and voltage levels.

6.3.4. Communications Schemes

6.3.4.1. Every communication port on all relays, meters, and other devices shall be verified that they are working correctly. This includes SEL data to 2032s, SEL protection channels between Jungle Mux or other multiplexer equipment, DNP SCADA communications to the communications processor, RTAC, or RTU, and all Ethernet connections to 2032s, relays, meters, and other equipment. There is also communications from the transformer tap changer controls along with temperature sensors that communicate with other Intelligent Electronic Devices (IEDs). The communications shall be a combination of fiber multimode, single mode, and plastic type and copper RS-232, RS-485, and Ethernet type connections.

6.3.4.2. The relay protective communications shall be extensively tested during scheme tests. All protection modes shall be tested under normal, hot standby, and abnormal conditions to verify the proper relay operation and alarm conditions.

6.3.5. Scheme Checkout

6.3.5.1. Transmission relay schemes shall be fully tested via end-to-end tests including communications. The minimum tests to be performed are the following:

6.3.5.2. Current Differential Schemes (see Line Relay Trip Check Guideline)

6.3.5.3. These relays shall have fault values injected via a test set from each end of the line to verify proper tripping for in-line faults and proper restraint for out-of-line faults. The relays shall have their direct transfer trip functions checked from each terminal for DTT receive and transmit conditions. All inputs from breaker failure relays, control switches shall actually be simulated and verified that they operate the DTT channels correctly. Reclosing shall be blocked for all DTT operations. The circuit breaker shall be operated for each one of these tests to prove the entire system. Each trip to Trip 1 and Trip 2 shall be independently verified by disabling the other trip circuit while testing. Phase and ground elements shall be checked independently for proper pickup and operation. All alarms that go to annunciators, relay displays, and SCADA shall be verified and documented. The 87 test switch for these schemes shall have each position verified for correct operation. Protection trips shall be tested with normal and failed communications. All data transmitted via communications shall be tested and verified. Proper targeting of the relay for all operations shall be verified and documented.

6.3.6. POTT Impedance/Time Stepped Schemes (see Line Relay Trip Check Guideline)

6.3.6.1. These relays shall have fault values injected via a test set to verify proper tripping for in-line faults and proper restraint for out-of-line faults. The Zone 1, 2, 3, and 4 elements shall be tested for reach, targeting and distance measurement by the relay. The relays shall have their direct transfer trip functions checked from each terminal for DTT receive and transmit conditions. All inputs from breaker failure relays, control switches shall actually be simulated and verified that they operate the DTT channels correctly. Reclosing shall be blocked for all DTT operations. Reclosing for Zone 1 and Zone 2 Communication Trips shall be verified and Zone 2 Time, Zone 3 and Zone 4 shall be verified for no reclosing. The circuit breaker shall be operated for each one of these tests to prove the entire system. Each trip to Trip1 and Trip 2 shall be independently verified by disabling the other trip circuit while testing. Phase and ground elements shall be checked independently for proper pickup and operation. All alarms that go to annunciators, relay displays, and SCADA shall be verified and documented. Protection trips shall be tested with normal and failed communications. All data transmitted via communications shall be tested and verified. Proper targeting of the relay for all operations shall be verified and documented.

6.3.7. Breaker Failure Schemes (see Line Relay Trip Check Guideline)

6.3.7.1. These relays shall have fault values injected via a test set to verify proper re-tripping of the circuit breaker and to verify all appropriate breaker failure and other timed delayed lockout trips. Breaker failure initiated from the proper trip coils shall be tested under actual trip conditions and verified and documented. The breaker failure can have a classic type, a 52A switch type scheme, or SF6 arming and tripping type scheme employed. SCADA and control switch operation shall not initiate breaker failure and shall be checked and verified. Proper targeting of the relay for all operations shall be verified and documented.

6.3.7.2. All breaker failure schemes need to be tested with a GO- 2 NO GO test. NO GO is with current or BFI only. GO is with both current and BFI.

6.3.8. High Voltage Bus Differential Relay - SEL-587z (see Trip Check Guideline-Transmission Bus Differential)

6.3.8.1. This relay shall have fault values injected via a test set to verify over-current and current differential elements for proper tripping of high voltage bus faults. The relay shall trip an 86 bus differential lockout (86B1). 86B1 shall trip and lockout all high voltage devices (i.e. line breakers, circuit switchers, and capacitor bank breakers). Each close inhibit and trip to Trip1 and Trip 2 shall be independently verified by disabling the other trip circuit while testing. All phase and differential elements for all windings shall be checked independently for proper pickup and operations. All alarms that go to RTUs and SCADA shall be verified and documented. All data transmitted via communications shall be tested and verified. Proper targeting of the relay for all operations shall be verified and documented.

6.3.8.2. Also located on the Bus Diff panel shall be an 86 breaker failure lockout (86BF1). 86BF1 shall trip and lockout all high voltage devices (i.e. line breakers, circuit switchers, and capacitor bank breakers). Each close inhibit and trip to Trip1 and Trip 2 shall be independently verified by disabling the other trip circuit while testing. Breaker failure trips from all breaker fail relays shall trip the 86BF1. All alarms that go to RTUs and SCADA shall be verified and documented.

6.3.9. Distribution relay schemes shall be fully tested including communications. The minimum tests to be performed are the following:

6.3.10. Primary Feeder Relay (see Trip Check Guideline-Unit Switchgear)

6.3.10.1. These relays shall have fault values injected via test set to verify proper tripping for in-line faults. The relays shall have their breaker failure functions checked. Reclosing shall be blocked for all high set phase and ground over current operations. The circuit breaker shall be operated for each one of these tests to prove the entire system. Each trip to Trip 1 and Trip 2 shall be independently verified by disabling the other trip circuit while testing. All phase and ground elements shall be checked independently for proper pickup and operation. All alarms that go to annunciators, relay displays, and SCADA shall be verified and documented. All data transmitted via communications shall be tested and verified. Proper targeting of the relay for all operations shall be verified and documented.

6.3.11. Current Differential Schemes Tie Breaker (see Trip Check Guideline-Unit Switchgear)

6.3.11.1. These relays shall have fault values injected via a test set to verify proper tripping for in-line faults and proper restraint for out-of-line faults. The relays shall have their direct transfer trip functions checked from each terminal for DTT receive and transmit conditions. All inputs from breaker failure relays and control switches shall actually be simulated and verified that they operate the DTT channels correctly. Reclosing shall be blocked for all DTT operations. The circuit breaker shall be operated for each one of these tests to prove the entire system. Each trip to Trip1 and Trip 2 shall be independently verified by disabling the other trip circuit while testing. Phase and ground elements shall be checked independently for proper pickup and operations. All alarms that go to annunciators, relay displays, and SCADA shall be verified and documented. The 87 test switch for these schemes shall have the position verified for correct operation. Proper targeting of the relay for all operations shall be verified and documented.

6.3.12. Backup Over current/Breaker Failure Relay (see Trip Check Guideline-Unit Switchgear)

6.3.12.1. All phase and ground elements shall be checked independently for proper pickup and operations. These relays shall have fault values injected via a test set to verify proper re-tripping of the circuit breaker and to verify all appropriate breaker failure and other timed delayed lockout trips. Breaker failure initiated from the proper trip coils shall be tested under actual trip conditions and verified and documented. The breaker failure can have a classic type, 52A switch type scheme, or SF6 arming and tripping type scheme employed. SCADA and control switch operation shall not initiate breaker failure and shall be checked and verified. Proper targeting of the relay for all operations shall be verified and documented.

6.3.12.2. All breaker failure schemes need to be tested with a GO- 2 NO GO test. NO GO is with current or BFI only. GO is with both current and BFI.

6.3.13. Transformer Differential Relays (see Trip Check Guideline-Unit Switchgear)

6.3.13.1. These relays shall have fault values injected via a test set to verify proper tripping for internal faults and restraint for external faults. The circuit breaker and lockouts shall be operated for each one of these tests to prove the entire system. Each trip to Trip 1 and Trip 2 shall be independently verified by disabling the other trip circuit while testing. All phase, ground, and differential elements for all windings shall be checked independently for proper pickup and operations. All alarms that go to annunciators, relay displays, and SCADA shall be verified and documented. All data transmitted via communications shall be tested and verified. Proper targeting of the relay for all operations shall be verified and documented.

6.3.14. SCADA Testing

6.3.14.1. SCADA testing and verification shall be broken down into three distinct areas: Control, Analogs, and Status-Alarms. These SCADA points shall be generated by a combination of hardwired points and DNP points originating IEDs with the majority of the points being DNP. The project point list along with the relay drawing package identifies the points required for checkout. Some points are general alarms and therefore require that each individual alarm summed by the general alarm must be verified as well.

6.3.14.2. Testing shall be checked as per the following paragraphs:

6.3.14.2.1. Controls

6.3.14.2.1.1. Energy Control Center (ECC) shall issue each type of control and the end device (e.g. transformer tap changer(voltage increases or decreases based on raise or lower command some LTC’s ie. auto’s work in reverse LTC raise lowers voltage and LTC lower raises voltage), circuit breaker, recloser cutoff, etc.) shall operate properly and provide the correct indication back to ECC.

6.3.14.2.2. Analogs

6.3.14.2.2.1. All analogs outputs from relays and meters shall have test voltage and currents injected into them from 0 through full scale positive and negative and verify that all alarm limits on SCADA, along with individual values on the one-line and tabular pages, are correct. Relay and meter displays as well as any other device shall be verified and recorded.

6.3.14.2.3. Alarms

6.3.14.2.3.1. All alarms shall be generated from the alarm device and verified to the annunciator, LED indication in the RTU, relay, meter or other device all the way to the ECC for complete verification. Checking alarms from point to point at the substation is not acceptable. For example, the tester must go to the breaker mechanism and simulate a loss of SF6 at the breaker and verify that it comes to the breaker annunciator, then the correct alarm point lights up in the RTU and the alarm actually appears on the correct screens at ECC. For stations that use relays instead of conventional RTUs, the tester shall verify the alarm shows up at the relay via display or relay word bit and then verify that the alarm actually appears on the correct screens at ECC. This procedure shall used to check every alarm in the station.

6.3.15. Perform trip checks from all outputs to associated devices checking for actuation of device.

6.3.16. Where lockout relays are present, the trip outputs of the lockout relay shall be disabled and the lockout relay operated by all of the protective relays. All contacts from the lockout relay will then be operated to the device.

6.3.17. Relay Settings: Verify all relays are set in accordance with the most current relay settings when testing is complete. Verify proper relay settings (CT ratio matches drawing, logic settings on correct output, proper relay identification etc…). Do not make changes without informing relay engineering. This is not intended for relay technician to make calculations and verify settings required of engineer only obvious settings that require no calculations and can be verified with a drawing or issued relay settings.

6.3.18. Relay Alarm Outputs: If applicable, verify all relay alarm outputs are received locally and by Dispatch through SCADA.

6.4. Complete Trip Check Guidelines before Energizing and/or Commissioning.

6.5. Commissioning

6.5.1. Verify with quick metering glance all readings are reasonable to identify potential problems before performing other steps.

6.5.2. Take load reads of any CT’s that were added to existing relay protection schemes (ex. Buss CT, XFMR CT).

6.5.3. Take snapshot of all relays with load. Compare to other relay loads to verify accuracy and correct reading. Snapshots to be taken anytime a piece of equipment is placed into service.

6.5.4. Complete Net Zero Form.

7. Record Retention

7.1. Compile all test forms, drawings, and ISO documents and submit to Supervisor for record retention.

7.1.1. Scanned as-Builts.

7.1.2. RTS Reports.

7.1.3. NetZero Form.

7.1.4. Trip Check Guidelines.

7.1.5. Pre-EnergizationChecklist.

7.1.6. RSO Settings Checklist.

7.1.7. Print Transmittal.

7.1.8. In-Service Meter Snapshots.

7.1.9. Relay Asset Form.

7.2. Drawing set highlighted for circuit testing shall be signed by the technicianthat is clear and legible. Recommended to print, date, and sign.

7.3. File name of documents should be CASCADE equip number, WO number,date, test title and equipment description.

7.4. Supervisor to submit completed records to scheduler in electronic form.

7.5. Relay Asset Form to include all relays added and removed from service with clear notes indicating addition or removal.

8. Comments:

8.1. Document any tests not completed and why not. Protection and ControlEngineering Relay Support authorization is required for any tests not completed. Note the person’s name that made the authorization.

8.2. Document all changes that were made and authorizing engineer and anyuser comments or reference information as required.

SUB NAME SUB ABBR. HOUSE/SWGRPNL/UNIT NUMBER

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BREAKERSUB XFRM

SUB DISTRIBUTIO

N & TIE BREAKER

YES/NOBUS

BREAKERSUB XFRM

SUB DISTRIBUTIO

N & TIE BREAKER

YES/NOBUS

BREAKERSUB XFRM

SUB DISTRIBUTIO

N & TIE BREAKER

YES/NOBUS

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SUB DISTRIBUTIO

N & TIE BREAKER

YES/NOBUS

BREAKERSUB XFRM

SUB DISTRIBUTIO

N & TIE BREAKER

YES/NOBUS

BREAKERSUB XFRM

SUB DISTRIBUTIO

N & TIE BREAKER

YES/NOBUS

BREAKERSUB XFRM

SUB DISTRIBUTIO

N & TIE BREAKER

YES/NOBUS

BREAKERSUB XFRM

SUB DISTRIBUTIO

N & TIE BREAKER

YES/NOBUS

BREAKERSUB XFRM

SUB DISTRIBUTIO

N & TIE BREAKER

YES/NOBUS

BREAKERSUB XFRM

SUB DISTRIBUTIO

N & TIE BREAKER

YES/NOBUS

BREAKERSUB XFRM

SUB DISTRIBUTIO

N & TIE BREAKER

YES/NOBUS

BREAKERSUB XFRM

SUB DISTRIBUTIO

N & TIE BREAKER

YES/NOBUS

BREAKERSUB XFRM

SUB DISTRIBUTIO

N & TIE BREAKER

YES/NOBUS

BREAKERSUB XFRM

SUB DISTRIBUTIO

N & TIE BREAKER

YES/NOBUS

BREAKERSUB XFRM

SUB DISTRIBUTIO

N & TIE BREAKER

ANSI DEVICE NAME

RELAY MFG. RELAY TYPEEM/MP/CLK/C

IN SERVICE YES/OOS

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IN SERVICE YES/OOS

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IN SERVICE YES/OOS

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IN SERVICE YES/OOS

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IN SERVICE YES/OOS

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IN SERVICE YES/OOS

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ANSI DEVICE NAME

IN SERVICE YES/OOS

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IN SERVICE YES/OOS

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IN SERVICE YES/OOS

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IN SERVICE YES/OOS

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IN SERVICE YES/OOS

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IN SERVICE YES/OOS

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CATALOGUE/S.O. NUMBER

MW In MVAR In Amps In0.00 0.00 0.00

MW Out MVAR Out Amps Out0.00 0.00 0.00

MW Total MVAR Total Amps Total0.00 0.00 0.00

Equipment MW MVAR Amps

Substation:

Signature:

Net Zero Calculations

Station or Bus Metering Values (+) =out (-)= in

Summation

DocID: OP0001510 Ver: 2.0 Effective: 02/01/2016 Uncontrolled when printed.v1.0

austin energy substations name - bidnet

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