Electric Transmission Preventive

Maintenance Manual
TD-1001M

November 20th, 2018

Revision: 04
 Copyright  2018
By Pacific Gas and Electric Company.
All rights reserved.

No part of this publication may be reproduced, stored in a

retrieval system, or transmitted in any form or by any
means, electronic, mechanical, photocopying, recording, or
otherwise, without the prior written permission of Pacific
Gas and Electric Company. For information, address:

Pacific Gas and Electric Company

Technical Document Management
Mail Code N9H
P.O. Box 770000
San Francisco, CA 94177

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 Introduction

This manual covers preventive maintenance for overhead and underground electric transmission
facilities. These facilities must be inspected and patrolled in accordance with the following sections of
this manual:
1. General Inspection and Patrol Procedures
2. Inspections
3. Patrols
4. Infrared (IR) Inspection Procedures
5. Maintenance Procedures

The procedures outlined in this manual (Sections 1 through 5) have been established to ensure
uniform and consistent required procedures for inspections, patrols, equipment testing, and condition
assessment of electric transmission line facilities.

This standard also includes requirements for the prioritization, scheduling, managing and
documentation of corrective actions identified on existing electric transmission facilities that affect
safety and reliability. These requirements comply with PG&E standards and current industry
practices.

In addition, Section 6 provides specific enhanced inspection and maintenance requirements unique to
facilities serving Diablo Canyon and Morro Bay Power Plants.

This standard supports UO Policy 3-7, “Gas and Electric Operation, Maintenance, and Construction,”
Utility Standard TD-1001S, “Electric Transmission Line Inspection and Preventive Maintenance
Program” and the requirements to comply with California Public Utilities Commission (CPUC) General
Order (G.O.) 165 “Inspection Requirements for Electric Distribution and Transmission Facilities”, as
well as relevant portions of G.O. 95 “Rules for Overhead Electric Line Construction” and G.O. 128
“Rules for Construction of Underground Electric Supply and Communication Systems”. The
requirements described in this document reduce the potential for component failures and facilitate a
proactive approach to repairing or replacing abnormal components. This standard does not
necessarily identify nonconformance to PG&E standards.

This standard is to be reviewed annually for updates, changes, errors, or omissions. When it is
updated, the Filed Maintenance Practice (FMP) with the California Independent System Operator
(CAISO) must also be reviewed and revised, as necessary. Significant changes in the frequency or
scope of patrols and inspections may also trigger a review with the CPUC.

For the acronyms and definition of terms used in this manual, see 8.Appendix A: Acronyms and
Definition of Terms.

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Table of Contents
1. General Inspection and Patrol Procedures ........................................................................... 7
1.1 Record Keeping ..................................................................................................................... 7
1.2 Purpose of Inspection and Patrol Activities ............................................................................ 9
1.3 Documenting Abnormalities and Nonconformance ................................................................ 9
1.4 Inspection Methodology, Facility, Damage and Action Codes .............................................. 14
1.5 Assigning Priority Codes and Due Dates ............................................................................. 18
1.6 Creating and Closing Inspection/Patrol and Maintenance Records...................................... 23
1.7 Overhead Job Aid for Assigning Priority Codes ................................................................... 25
1.8 Overhead Job Aid for Insulator Replacement and Priority Codes ........................................ 31
1.9 Overhead Job Aid for Transmission Line Steel Structures ................................................... 34
1.10 Overhead Job Aid for 500 kV Climbing Inspections ............................................................. 35
1.11 Overhead Job Aid for Conductor Inspections....................................................................... 36
1.12 Overhead Job Aid for Switch Inspection .............................................................................. 36
1.13 Removal of Metal Fence Attachments ................................................................................. 37
1.14 Overloaded Transmission Line Poles .................................................................................. 37
1.15 PAL Nuts – Remedy for Loose or Missing Tower Bolts ........................................................ 38
1.16 Equipment Replacement Notifications ................................................................................. 38
1.17 Overhead Job Aid for Conductor Clearances....................................................................... 39
1.18 Overhead Job Aid for Automatic Guy Strain Deadends and Splices .................................... 41

2. Inspections ............................................................................................................................ 43
2.1 Detailed Overhead Inspections ............................................................................................ 43
2.2 Climbing Inspections (Overhead)......................................................................................... 47
2.3 Underground Inspections..................................................................................................... 47
2.4 Infrared (IR) Inspections ...................................................................................................... 53

3. Patrols.................................................................................................................................... 55
3.1 Procedures .......................................................................................................................... 55
3.2 Patrol Documentation and Actions....................................................................................... 56
3.3 Non-Routine Patrol .............................................................................................................. 57

4. Infrared (IR) Inspection Procedures..................................................................................... 59

4.1 Detailed IR Procedures ....................................................................................................... 59
4.2 IR Inspection Requirements ................................................................................................ 63
4.3 IR Inspection Documentation ............................................................................................... 64

5. Maintenance Procedures ...................................................................................................... 65

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5.1 Overhead ............................................................................................................................ 65

5.2 Underground Job Aid for Maintenance Procedures ............................................................. 65

6. Enhanced Inspection and Maintenance Requirements for Diablo Canyon and Morro Bay
Power Plants Overhead Transmission Facilities ........................................................................... 69
6.1 Detailed Overhead Inspection ............................................................................................. 69
6.2 Overhead Inspection Frequency .......................................................................................... 69
6.3 Climbing/Structure Inspections ............................................................................................ 70
6.4 Patrols ................................................................................................................................. 71
6.5 Infrared (IR)/Corona Inspections.......................................................................................... 72
6.6 Dirty/Contaminated Insulator Cleaning ................................................................................ 72

7. Document Governance ......................................................................................................... 73

7.1 Document Approver(s) ........................................................................................................ 73
7.2 Document Owner(s) ............................................................................................................ 73
7.3 Document Contact(s) ........................................................................................................... 73

8. Revision Notes ...................................................................................................................... 74

Appendix A: Acronyms and Definition of Terms ........................................................................... 77

Appendix B: Equipment, Tools, and Materials .............................................................................. 81

Appendix C: Links to Forms and Flowcharts ................................................................................ 85

Appendix D: Summary of Links to Related Documents................................................................ 87

Appendix E: Line Patrol File Guidelines ........................................................................................ 89

Appendix F: ET AI App Process Guidelines .................................................................................. 91

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List of Tables

Table 1. Vegetation Clearance Distance ............................................................................................ 10

Table 2. Inspection Best-View-Position ............................................................................................. 14
Table 3. Overhead Facility, Damage and Corrective Action Codes ................................................... 16
Table 4. Underground Facility, Damage and Corrective Action Codes ................Error! Bookmark not
defined.7
Table 5. Priority Codes ..................................................................................................................... 19
Table 6. Guide for Assigning Priority Codes ................................................................................... 277
Table 7. Guide for Replacing Damaged Insulators .......................................................................... 333
Table 8. Detailed Description for Repairing Deteriorated Steel Structures ...................................... 344
Table 9. Minimum Conductor-to-Ground Clearance Calculations ................................................... 399
Table 10. Minimum Conductor-to-Conductor (Circuit-to-Circuit) Clearances ..................................... 41
Table 11. Overhead Inspection Frequencies .................................................................................. 455
Table 12. Underground Inspection Frequencies ............................................................................. 488
Table 13. Determining Maintenance Priorities................................................................................. 633
Table 14. Diablo Canyon PP and Morro Bay PP Enhanced Inspection Circuits .............................. 699
Table 15. Overhead Inspection Frequencies-DCPP and Morro Bay PP Transmission Lines ............ 70
Table 16. ESDD Contamination Grades ......................................................................................... 722
Table 17. Acronyms and Definition of Terms .................................................................................. 777
Table 18. Safety Equipment List ....................................................................................................... 81
Table 19. Tool List .......................................................................................................................... 822
Table 20. Materials List................................................................................................................... 833
Table 21. Forms Index .................................................................................................................... 855
Table 22. Links to Related Documents ........................................................................................... 877

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1. General Inspection and Patrol Procedures

1.1 Record Keeping

This section provides general records guidance and retention requirements for the maps, logs,
and notifications used to document the inspections, patrols abnormalities and corrective actions
identified on the electric transmission line system.
1.1.1 General Guidelines for Company Records and Documentation
Records must be stored electronically, unless impractical. REFER to Section 7 of the GOV-
7101S Enterprise Records and Information Management Standard.
1.1.1.1 Electronic Records and Signatures
Transmission line has begun implementing electronic processes for activities such as
notification creation. A mobile computer is utilized with the ET AI App to create notifications.
To ensure proper documentation, both the traditional wet signature and an electronic signature
will be acceptable forms of certifying compliance documents or to satisfy signature or
verification purposes. Note that electronic signatures or verifications must come from a valid
user logged onto a PG&E certified account (such as any account associated with PG&E single
sign-on or SAP).
1.1.1.2 Hand-Written Records
Although use of electronic signatures and certifications are now allowed, the requirements for
hand-written records have not changed.
All hand-written records must be completed using non-erasable ink. To correct an item on a
hand-written record, the following requirements must be met:
 Use a non-erasable black or blue ink pen.
 Do not erase or white out any portion of the log.
 Draw a single line through the entry(s) being deleted.
 Enter the correct information into the log.
 Initial and date the change.
To ensure legibility, personnel must print their full name, initials, or LAN ID, as required, on
these documents. Rubber stamps are not allowed to meet this requirement (Bulletin 247, Gas
and Electric M&O Record Requirements, 12/31/07). All hand-written forms and paperwork
requiring a qualified Company representative (QCR) or supervisor signature must be “wet”
signed by hand in non-erasable blue or black ink by the respective personnel. Computer print
outs with the date and LAN ID are acceptable; however, all signatures on paper must be “wet”.
Routine, non-routine, and emergency circuit inspection or patrol reports generated by the QCR
must be recorded in the appropriate SAP database, and the records maintained in accordance
with the Independent System Operator (ISO) Transmission Control Agreements (TCA). Use
ETPM Forms TD-1001M-F01, “Transmission Line Inspection/Patrol Datasheet - Typical”, TD-
1001M-F06, “Monthly Pipe-Type Routine Inspection - Typical”, TD-1001M-F07, “Detailed Pipe-
Type Inspection Sheet – Typical”, TD-1001M-F08 “Quarterly XLPE Routine Inspection –
Typical”, TD-1001M-F09 “Detailed XLPE Manhole Inspection – Typical”, TD-1001M-F10
“Alarms/SCADA Annual Test Sheet – Typical” and TD-1001M-F11 “Electric Pumping Plant
Annual Calibration Sheet – Typical” to document abnormal conditions identified by the QCR
during inspection and patrol.

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These documents must identify that all structures and facilities were inspected or patrolled,
and that all abnormal conditions observed were corrected or captured as maintenance
notifications during the inspection or patrol.
In general, additional notes and comments should not be added to forms unless they further
describe the findings captured. Acceptable notes for patrol and inspection field documentation
includes:
 Access notes describing the navigation path or procedure used to safely and efficiently
access the target structure or equipment
 Range finder readings describing the target span, temperature, date, time, and laser
range finder (or similar) result
 Status of non-findings being monitored such as woodpecker hole position and size;
ground movement near the structure; species presence.

1.1.2 Records Retention Requirements

Note: A legal hold supersedes all record retention requirements listed in this section. Do not
destroy any records designated as part of a legal hold no matter how old those records are.
All Electric Operations records are still under a legal hold as of publishing of this ETPM.
REFER to Section 9 of the GOV-7101S Enterprise Records and Information Management
Standard for more information on legal holds.
Overhead and underground transmission line inspection and maintenance records must be
maintained in accordance with CPUC General Order (G.O.) 165. Records may be in paper
and/or electronic form and must be kept for 10 years, with the exception of climbing
inspections on the 500 kV system, which must be maintained for 14 years.
When completed, inspection datasheets and forms must be kept in files by circuit name at the
responsible transmission line maintenance supervisor’s headquarters. The clerk will scan the
datasheet and attach it to the patrol in SAP. Refer to Appendix E: Line Patrol File Guidelines
for requirements on how to complete the forms and how to store the files. Annually for each
circuit, two folders should be created. There will be one folder for Annual Patrols and one
folder for the Line Files. Print the appropriate forms and include in the specific folder for each
circuit. The following are typical management reports and records used to track required
inspection and maintenance work. When applicable, these documents should be included in
the respective circuit files at the transmission line maintenance supervisor’s
headquarters/central filing office.
 Underground Transmission Line Inspection Sheets
 Overhead Transmission Line Datasheets
 Completed Notification forms within SAP for maintenance work performed by
transmission employees
 Object lists
 Notification forms submitted to other support groups that will be performing the
maintenance, such as area maintenance and construction (M&C) employees,
contractors, vegetation management (VM) personnel, pole asset management (PAM)
personnel, etc.
 Completion notices in SAP for work performed by transmission employees
 Completion notices for work performed by others
 Poles Inspection Test Reports

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1.2 Purpose of Inspection and Patrol Activities

Inspection and patrol procedures are a key element of the preventive maintenance program. The
actions recommended in this manual reduce the potential for component failures and facility
damage and facilitate a proactive approach to repairing or replacing identified, abnormal
components.
Inspections include detailed visual observations of individual components, structures and
equipment; operational readings; and component testing (i.e., hammer test, etc.) to identify
abnormalities or circumstances that will negatively impact safety, reliability, or asset life.
Patrols include visual observations to identify abnormalities (i.e., obvious structural problems or
hazards) or circumstances that will negatively impact safety.
Electric transmission line maintenance organizations may establish additional inspection, patrol,
testing, and/or preventive maintenance requirements that exceed the requirements in this manual,
based on area experience and local conditions, and as needed for special equipment unique to
the area. Additionally, the Asset Management organization may require electric transmission line
maintenance organizations to undertake unique, non-routine patrols and inspections as dictated
by asset performance or other external factors.

1.2.1 Problem Identification

PG&E performs periodic inspections, patrols, and maintenance on its overhead and
underground transmission facilities. Identify abnormal or potentially hazardous conditions by
any of the following means:
 Periodic inspections or patrols of facilities in accordance with existing standards.
 Condition-based and/or diagnostic testing and monitoring of facilities.
 Observation by any employee during other activities, such as normal job assignments
and emergency patrols QCR must perform a field assessment).
 Corrective Action Program (CAP) issue
 Internal reviews.
 Customer or general public reports (a QCR must perform a field assessment).
 During emergency or storm activities.
 The QCR does not define the specific corrective action to be performed but makes
recommendations.

1.3 Documenting Abnormalities and Nonconformance

1.3.1 Reporting Nonconformance with CPUC General Orders
Any nonconformance with G.O. 95, “Rules for Overhead Electric Line Construction,” and G.O.
128, “Rules for Construction of Underground Electric Supply and Communication Systems,”
that impacts safety or reliability, or an abnormal condition caused by third-parties that
negatively impacts Company facilities, must be documented on an SAP notification. Abnormal
conditions caused by third-parties must be reported to Land Management.

1.3.2 Reporting Abnormalities in Manufacture

Abnormal conditions or failures that could be the result of a manufacturer or workmanship
defect must be reported on a Form 62-0113, “Material Problem Report” (MPR), and submitted

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to supplier quality improvement personnel for follow-up action, as described in SCM-2106P-

01, “Material Problem Report Procedure”.
IF material is sent to Applied Technology Services (ATS) personnel for testing, THEN include
a form TD-1957P-01-F01, “Component Testing Information Sheet.” as described in Utility
Procedure TD-1957P-01, “Electric Transmission Line Equipment Failure Analysis Procedure.”
CAUTION: When collecting failed components, care should be taken to protect the failed
surfaces by avoiding touching the failed sections. Even minimal contact with the failed
surfaces can prevent an accurate failure analysis.
MPR’s are not to be used for material which has failed as a result of end-of-service life or
because of normal wear.

1.3.3 Reporting Vegetation Nonconformance

Initiate an SAP notification if trees or brush are within the vegetation clearance distances or
pose a potential threat to fall into a conductor.
In addition to initiating the notification, take the action required, as based on the voltage class
and the vegetation-to-conductor clearance distance listed in Table 1. Vegetation Clearance
Distance.
Table 1. Vegetation Clearance Distance
Voltage (kV) Clearance Distance Action Required
60/70* 4 feet or less Call VPM (Veg Program Manager)/Forester
115* 10 feet or less Call VPM/Forester
230 10 feet or less Call GCC and VPM/Forester
500 15 feet or less Call GCC and VPM/Forester
* If the line is NERC/CAISO critical (Spaulding – Summit 60kV, Drum-Summit #1 115kV and
Drum-Summit #2 115kV), call the GCC and VPM/Forester as required for 230kV and 500kV
lines.
For all NERC transmission lines, if a tree poses an imminent threat (e.g., the tree is uprooting
and has the potential to fall into conductors), but not within the clearance distances shown in
Table 1. Vegetation Clearance Distance, also perform the required action described in Table
1. Contact the VPM/ Forester directly. A voice mail is not considered notification for an
imminent threat. The information must be given directly to a person. If the VPM/Forester is not
available, contact the next person within VM. The VM department will verify the condition per
Utility Procedure TD-7103P-05, “Transmission Vegetation Management Imminent Threat
Procedure”. Provide the following information:
 Description of the vegetation condition
 Location, including the line name, nearest tower number and approximate distance to
the tower
 Field conditions, including information on environmentally sensitive areas
 Location access
For all vegetation notifications and hazard conditions that are encroaching on the vegetation-
to-conductor clearance distance listed in Table 1. Vegetation Clearance Distance, the SAP
notification form must indicate the following information:
 Facility Code = Vegetation, Damage Code = Overgrown, Action Code = Remove
 Priority A = Emergency Unsafe Condition

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The VM group manages all vegetation notifications and will verify the condition and confirm the
clearance distance per Utility Procedure TD-7103P-09, “T&D Vegetation Management Hazard
Notification”. VM must notify the issuing department when the conditions have been corrected
or resolved and ensure that the notification has been closed.
As part of the routine VM work, VM inspects 100% of overhead lines annually and performs
work necessary to ensure that no vegetation encroaches on PG&E clearance distances (see
Table 1. Vegetation Clearance Distance above). Clearance distances are based on regulatory
clearance requirements plus a buffer and vary by voltage. VM also manages a transmission
reliability program designed to improve reliability and reduce fire risk by clearing incompatible
vegetation from the full width of the right-of-way. This work is planned annually in
collaboration with T-Line Asset Strategy.
In addition, VM performs tower and pole clearing as part of their routine tree work, to allow for
the inspections of tower and pole bases and footings and down guys. The pre-inspection and
tree crew contractors will inspect the vegetation around the poles, towers and down guys while
doing their patrols and inspections. If woody vegetation is in contact with the pole or tower, or
significantly interferes with the inspection of the pole or tower base or footings, then the
contractors will arrange for appropriate vegetation work. If woody vegetation is in contact with
the guy wire, the contractors will determine if vegetation work will be required and arrange for
any necessary work. See Utility Procedures TD-7103P-01, “Transmission Non-Orchard
Routine Patrol Procedure” and TD-7103P-02, “Transmission Orchard Patrol Procedure
(TOPP)”.

1.3.4 Reporting Other Nonconformance with Distribution Facilities

When QCRs are performing patrols and inspections on facilities with distribution assets, a
patrol of the distribution assets should also be performed. Examples of the type of issues that
could be identified are:
 Damaged or broken poles
 Broken or decayed crossarms
 Broken insulators
 Damaged tie wire
 Vegetation issues
 Missing or broken bridging wire
If there is an immediate hazard and/or emergency, contact the transmission line maintenance
supervisor and standby, if needed. If a structural problem or hazard is identified, that is NOT
an emergency, note the issue on the List of the Datasheet. Submit a digital photo
documenting the issue and the pole number. Contact the local PS&R Supervisor, leaving a
voice mail message if not available, including the following information:
 Issue identified (e.g., broken crossarm)
 Transmission pole number (if distribution underbuild) or distribution pole
number
 Confirm that a map will be emailed if there is no pole number.
 Latitude and longitude of the pole
The transmission line maintenance supervisor will review the finding while reviewing the patrol
or inspection documents. The clerk will create an email outlining the above details to the local

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PS&R Supervisor with a cc: to the QCR and the transmission line maintenance supervisor and
attach the copy of the map with the location identified and all photos. The clerk will print a
copy of the email and file it with the completed datasheets.
These steps are outlined in detail in the 5 Minute Meeting ‘5MM – Identifying Issues on
Transmission or Distribution Poles’ issued in 2015.
Note: Based on a recent FERC ruling, Transmission Line (T-Line) is no longer authorized to
complete Distribution bridging work under Transmission FERC funding. As a result, all
Distribution bridging work will be completed under Distribution budget authority. Any
nonconformance regarding bridging at the distribution level should be reported using the steps
outlined in this section.

1.3.5 Reporting Nonconformance With Access Roads and Gates

Access related work generally falls into several primary categories:
 Create road – there is no road or trail and one is needed
 Vegetation clearing – road is overgrown, or vegetation is encroaching so road
needs to be “brushed”. Use Brush/Fuel in ET AI App.
 Vegetation in proximity of lines or vegetation in contact with or obstructing structure
footings – refer to Section 1.3.3 Reporting Vegetation Nonconformance.
 Road work – can be a range of issues from rockslides and small cutslope slumps of
dirt to larger fillslope failures, downed trees or boulders blocking access, rills and
gullies (erosion from drainage problems), blown out crossings, etc.
 Watercourse crossings – (e.g., culverts and bridges) blowout or failed.
 Road work encroachment – refer to Section 1.3.7 Reporting Nonconformance with
Trespass or Encroachment
 Gates – existing gate is broken or damaged and needs to be replaced, gate has
been stolen, or there is no gate and one is needed. (If gate is locked, refer to
Section 1.3.7 Reporting Nonconformance with Trespass or Encroachment)
For any type of access issue, the Corrective Work Form (Facility-Damage-Action) approach to
creating a new line corrective notification should be followed. By selecting Facility type Road,
the appropriate management team will receive the corrective work notification.
If QCR determines access is needed, Damage should be Missing, and Action should be
Install. Use Field Comments to indicate type of vehicle for which access is needed – Bucket
truck; Pickup; OHV – Razor; Foot trail.
If there is a road in the Right-of-Way, treat it like any road, and Damage should be Brush Fuel.
If work area is a hard surface area (e.g., paved or rock) and is greater than 10,000 square
feet, approximately longer than ¼ mile of road, then consider this for Capital work. QCR would
need to make a note of this in the Field Comments.

1.3.6 Reporting Nonconformance With Boardwalks

Boardwalk repairs and renovation are part of a program based approach that prioritizes all
issues to determine the need to reconstruct, repair or abandon the boardwalk to ensure safe
and reliable access to facilities. Construction work is complicated due to short construction
windows and alignment with environmental agencies permitting cycles. Natural Resources
Management (NRM) is working with T-Line to rebuild all boardwalks in the service territory.
Currently there are multiple projects underway to rebuild sections of boardwalks; however,

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complete renovation will take 5-7 years. NRM has completed inspections of all boardwalks
which led to the current renovation program. Additional nonconformance notifications are not
necessary.
If it is necessary to utilize a boardwalk, all safety precautions listed in 5MM Boardwalk Access
Safety, issued 05/29/18, must be followed.

1.3.7 Reporting Nonconformance With Trespass or Encroachment

When encroachments or other uses on PG&E property or easements are identified, they are
evaluated for interference with maintaining, operating or constructing electric transmission
facilities as described in Utility Procedure TD-1005P-03, “Evaluating Uses of Company
Transmission Line Easements by Others” and Utility Standard TD-1005S, “Right-of-Way and
Encroachments”.
Evaluate the proposed use or encroachment.
 If the activity poses a threat of potential damage to facilities that could cause an
immediate danger, contact your supervisor immediately.
 Determine if there is interference and whether permanent access can be
maintained for inspections, routine maintenance, reconstruction, growth of facilities
and emergency response.
 Confirm there is sufficient conductor-to-ground clearance, radial line clearances
and clearances around structures.
 Confirm whether excavation, grading, equipment use or land erosion is impacting
pole or tower stability.
 Determine if there are any uses or encroachments that require grounding or there
are any prohibited uses (e.g., buildings, structures, pools or wells).
 Refer to TD-1005S, Attachment 1, “Permissible Uses of Pacific Gas and Electric
Company (Company) Easements”.
Specifically, complete a notification to report any overhead conductors above buildings,
swimming pools, wells or similar structures that are not permitted in the easements. The
exception are buildings that house the equipment of third-parties, but these are subject to
complete and ongoing review.
Verify if the encroachment has already been submitted. If it hasn’t, complete a notification in
SAP, including digital photographs, if appropriate.
The SAP notification form must indicate the following information:
 Facility Code = Right of Way, Damage Code = Encroachment, Action Code = Remove
The QCR’s supervisor reviews the location and sends to electric transmission asset reliability
specialist. The electric transmission asset reliability specialist will approve or disapprove of
any encroachment or other use. The supervisor will send an email or hard copy to the land
agent summarizing:
 How the encroachment or use interferes with utility operation
 What modifications could be implemented to eliminate any interference
 Whether Land Management should abate the encroachment or compel the user to
enter into an encroachment agreement

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 What measures might be taken to protect facilities during future changes or

installations (e.g., maintaining minimum approach distances during construction)
 Any issues that might jeopardize safety or service reliability (e.g., construction near
conductors)
 Any steps to meet regulatory requirements (e.g., grounding metal fences)
 Any utility activity that could damage the new use, with a statement that the
Company is not liable for such damage.
The land agent will negotiate the Company position with the third party, if required, and
discuss the proposed agreement with the electric transmission stakeholders, including the
electric transmission reliability supervising specialist and the transmission line maintenance
supervisor. The electric transmission reliability supervising specialist and the transmission line
maintenance supervisor must review and approve the land agent’s proposed agreement,
which the land agent will present to the third party. When this process is complete, the land
agent will notify the transmission line maintenance supervisor that the work is completed and
the transmission line maintenance supervisor will close the notification in SAP.

1.4 Inspection Methodology, Facility, Damage and Action Codes

1.4.1 Inspection Methodology
This methodology establishes a consistent inspection sequence for components and
determines the type of inspection that provides the best viewing position for identifying
component defects.
Table 2. Inspection Best-View-Position
Ground Ground Climbing
Aerial
Description Inspection Inspection Inspection
Inspection
(below 10 feet) (above 10 feet) (above 10 feet)

Cellular site X X X
Insulators and hardware X X X
Conductor and fittings X X X
Switches and associated
X X X
elements
Road access X X X
Vegetation X X X
Overhead ground wire /
X X X
fiber optic cable (OPGW)
Foundations X
Anchors and guys X X
Structures X X X
Electrical clearances X X
Arms/braces X X X

1.4.2 Facility Codes

Defective elements and abnormal conditions identified during inspections and patrols must be
identified and recorded using the facility codes and damage codes (FDA codes) as shown in

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Table 3 Overhead Facility, Damage, Corrective Action Codes and Table 4 Underground
Facility, Damage, Corrective Action Codes.
The lists in the following tables are not all-inclusive. During inspections, identify any obvious
component defects that are not listed. Where “Other” is selected, additional descriptive
information must be recorded in the SAP Line Corrective (LC) notification form in the ET Asset
Inspection (AI) App to describe the facility, damage, and action prescribed.
IF the QCR identifies inoperable, damaged, misaligned or otherwise non-functional
Obstruction Lighting (see 1.18),
THEN the QCR should refer to TD-1001P-03, “Obstruction Lighting Failure Notification
Process” for procedure on notifying Federal Aviation Administration (FAA) (e.g., the 15-day
periods). The QCR’s supervisor reviews the recommendations for repair codes before they are
entered in SAP with a Priority Code B.

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Table 3. Overhead Facility, Damage and Corrective Action Codes

Facility Damage Action Facility Damage Action
Missing Install Missing Install
Hardware-Steel
Anchor-Steel Repair No Good/Out of Stdrd Replace
No Good/Out of Stdrd
Replace Missing Install
Hardware-Tower
Missing Install No Good/Out of Stdrd Replace
Anchor-Wood Repair Missing Install
No Good/Out of Stdrd Hardware-Wood
Replace No Good/Out of Stdrd Replace
Animal Guard-Steel Missing Install Ground Wash
Insulator Contaminated
Animal Guard-Wood Missing Install Helicopter Wash
Missing Install Repair
Insulator Bond Wire-Steel No Good/Out of Stdrd
Anode-Tower Repair Replace
No Good/Out of Stdrd
Replace Repair
Insulator Bond Wire-Wood No Good/Out of Stdrd
Repair Replace
Auto Guy Wire Splice-Steel No Good/Out of Stdrd
Replace Repair
Insulator-Steel No Good/Out of Stdrd
Repair Replace
Auto Guy Wire Splice-Wood No Good/Out of Stdrd
Replace Repair
Insulator-Wood No Good/Out of Stdrd
Repair Replace
Bay Water-Tower No Good/Out of Stdrd
Replace Jumper-Steel No Good/Out of Stdrd Repair
Missing Install Jumper-Wood No Good/Out of Stdrd Repair
Boardwalk Repair Missing Install
No Good/Out of Stdrd Marker (i.e. signs)-Steel
Replace No Good/Out of Stdrd Install
Debris/Nest/etc. Remove Missing Install
Marker (i.e. signs)-Wood
Conductor-Steel Repair No Good/Out of Stdrd Install
No Good/Out of Stdrd
Replace Air Patrol
Debris/Nest/etc. Remove Non-Routine Patrol Investigate Ground Patrol
Conductor-Wood Repair Infrared Patrol
No Good/Out of Stdrd
Replace Other Other Other
Missing Install Missing Install
Raptor Guard-Steel
Connector Repair No Good/Out of Stdrd Replace
No Good/Out of Stdrd
Replace Missing Install
Raptor Guard-Wood
Crossarm-Steel No Good/Out of Stdrd Repair No Good/Out of Stdrd Replace
Crossarm-Tower No Good/Out of Stdrd Repair Right of Way Encroachment Remove
Repair Brush Fuel Remove
Crossarm-Wood No Good/Out of Stdrd
Replace Encroachment Remove
Missing Install Grade Change Repair
Damper-Steel Road
No Good/Out of Stdrd Replace Missing Install
Missing Install Repair
Damper-Wood No Good/Out of Stdrd
No Good/Out of Stdrd Replace Replace
Fire Replace SCADA-Steel No Good/Out of Stdrd Replace
Emergency Repair SCADA-Wood No Good/Out of Stdrd Replace
Storm Related
Replace Repair
Shield Wire / OPGW-Steel No Good/Out of Stdrd
Emergency-Steel Other Replace Replace
Emergency-Wood Other Replace Repair
Shield Wire / OPGW-Wood No Good/Out of Stdrd
FAA Battery-Steel No Good/Out of Stdrd Replace Replace
FAA Battery-Wood No Good/Out of Stdrd Replace Missing Install
Spacer-Steel
Missing Install No Good/Out of Stdrd Replace
FAA Lighting-Steel Repair Missing Install
No Good/Out of Stdrd Spacer-Wood
Replace No Good/Out of Stdrd Replace
Missing Install Repair
Splice-Steel No Good/Out of Stdrd
FAA Lighting-Wood Repair Replace
No Good/Out of Stdrd
Replace Repair
Splice-Wood No Good/Out of Stdrd
Missing Install Replace
Fault Indicator-Steel
No Good/Out of Stdrd Replace Install
Anti-Climbing Guard
Missing Install Repair
Fault Indicator-Wood
No Good/Out of Stdrd Replace Debris/Nest/etc. Remove
Fee Property Other Other Structure-Steel Idle Remove
Missing Install Repair
No Good/Out of Stdrd
Fence / Gate Repair Replace
No Good/Out of Stdrd
Replace Paint/Coating Other
Earth Covered Tower Repair Install
Anti-Climbing Guard
Foundation/Concrete-Tower Repair Repair
No Good/Out of Stdrd
Replace Idle Remove
Clearance Install Repair
GO95 / Anti Climb Structure-Tower No Good/Out of Stdrd
Ground / Clearance Repair Replace
GO95 Clear Infract-Tower Clearance To Be Corrected Repaint
Paint/Coating
GO95 Clear Infract-Wood Clearance To Be Corrected Replace
Ground Wire-Steel No Good/Out of Stdrd Repair Soil Remove
Missing Install Debris/Nest/etc. Remove
Ground Wire-Tower
No Good/Out of Stdrd Replace Idle Remove
Ground Wire-Wood No Good/Out of Stdrd Repair Repair
Structure-Wood No Good/Out of Stdrd
Guy Pole-Steel No Good/Out of Stdrd Replace Replace
No Good/Out of Stdrd Replace Replace
Rotten
Guy Pole-Wood Replace Stub
Rotten
Stub Switch Out of Adjustment Repair
Guy Stub-Steel No Good/Out of Stdrd Replace Switch-Steel No Good/Out of Stdrd Replace
No Good/Out of Stdrd Replace Repair
Guy Stub-Wood Switch-Wood No Good/Out of Stdrd
Rotten Replace Replace
Missing Install Tie Wire-Steel No Good/Out of Stdrd Replace
Guy Wire Mark /Indic-Steel
No Good/Out of Stdrd Replace Tie Wire-Wood No Good/Out of Stdrd Replace
Missing Install Remove
Guy Wire Mark /Indic-Wood Vegetation Overgrown
No Good/Out of Stdrd Replace Trim
Missing Install Vegetation-Tower Overgrown Cage Clearing
Guy Wire-Steel Repair Agencies (i.e. Muni)
No Good/Out of Stdrd
Replace WRO Request Other
Missing Install Switching
Guy Wire-Wood Repair
No Good/Out of Stdrd
Replace

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Table 4. Underground Facility, Damage and Corrective Action Codes

Facility Damage Action Facility Damage Action
Missing Install Missing Install
Alarm Repair Hardware Repair
No Good/Out of Stdrd No Good/Out of Stdrd
Replace Replace
Repair Repair
No Good/Out of Stdrd No Good/Out of Stdrd
Replace Insulator Replace
Cable Repair Contaminated Clean
Dig In
Replace Ground Patrol
Lock Out
Lockout Ground Patrol Infrared Patrol
Non-Routine Patrol
Repair Ground Patrol
Cable Termination No Good/Out of Stdrd Relay
Replace Infrared Patrol
Missing Install Repair
Leak
Cover/Manhole Repair Oil System Replace
No Good/Out of Stdrd
Replace Inad Pressure Adjust
Missing Install Other Other Other
Cathodic Protection-Anode Repair Repair
No Good/Out of Stdrd Pipe Duct No Good/Out of Stdrd
Replace Replace
Missing Install Repair
Cathodic Protection- Isolator Pump Plant-Control Cabinet No Good/Out of Stdrd
Repair Replace
Surge Protector (ISP) No Good/Out of Stdrd
Replace Repair
Pump Plant-Pump No Good/Out of Stdrd
Missing Install Replace
Cathodic Protection-
Repair Missing Install
Rectifier No Good/Out of Stdrd Riser
Replace No Good/Out of Stdrd Replace
Clearance Infraction Other Other Right of Way Encroachment Remove
Missing Install Missing Install
Distr Temp Sensor (DTS) Repair Repair
No Good/Out of Stdrd No Good/Out of Stdrd
Replace Replace
Road
Repair Brush Fuel Remove
Fire
Replace Encroachment Remove
Repair Grade Change Repair
Emergency Storm
Replace Right of Way Encroachment Remove
Replace Missing Install
Other
Other SCADA Repair
No Good/Out of Stdrd
Repair Replace
No Good/Out of Stdrd
Replace Missing Install
Enclosure/Vault Transition Station-
Flooded Pump Repair
Fence/Gate No Good/Out of Stdrd
Debris Clean Replace
Fee Property Other Other Repair
Transition Station-Lighting No Good/Out of Stdrd
Missing Install Replace
Repair Missing Install
Foundation/Concrete No Good/Out of Stdrd Transition Station-Lock
Replace No Good/Out of Stdrd Replace
Earth Covered Repair Transition Station-Marker Missing Install
Repair (Aerial, signs, etc) No Good/Out of Stdrd Install
Leak
Gas System Replace Remove
Vegetation Overgrown
Inad Pressure Adjust Trim
Missing Install Agency
Gauge Repair Work Requested by Others WRO Other
No Good/Out of Stdrd
Replace Switching
Missing Install
Grounds Repair
No Good/Out of Stdrd
Replace

1.4.3 Damage Codes

At least one damage code must be assigned to defective elements found during inspections
and patrols. These conditions are listed in Tables 3 and 4.
IF the QCR suspects facilities inspected or patrolled are idle and have no future plans for use,
THEN the QCR should indicate on the FDA form in the AI App:
 Facility Code = Structure (Steel, Tower or Wood), Damage Code = Idle, Action Code =
Remove
and reference internal standard TD-1003S, "Management of Idle Electric Transmission Line
Facilities" to nominate for removal.

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1.4.4 Corrective Action Codes

The QCR must recommend the required action(s) to correct the identified abnormal
condition(s). These actions are listed in Tables 3 and 4. IF more than one action is required at
a facility, THEN each must be identified.

1.5 Assigning Priority Codes and Due Dates

1.5.1 Resolving Abnormal Conditions during Patrol or Inspection
The QCR must complete all possible repairs or replacements to correct abnormal conditions
that can be performed safely during the inspection. For abnormal conditions not corrected
during the inspection, the QCR must prepare a notification based on the inspection datasheets
or forms.
In addition, reasonable and appropriate maintenance tasks may be performed by one or two
QCRs during inspection.
1. IF the work performed takes less than 15 minutes per location for Overhead OR
Underground transmission,
THEN note the completed maintenance tasks on the following forms:
 For Overhead, on form TD-1001M-F01, “Transmission Line Inspection/Patrol
Datasheet - Typical”
 For Underground, in the “Comments” section of the forms TD-1001M-F06 through
TD-1001M-F11, depending on the inspection performed.
 Do not record the maintenance tasks in the AI App. For accounting purposes,
consider the work to be part of the inspection.
2. IF the work takes longer than 15 minutes per location for Overhead OR Underground
transmission,
THEN consider the time as a separate maintenance PM notification, and record the completed
maintenance tasks as follows:
 For Overhead:
 On form TD-1001M-F01, “Transmission Line Inspection/Patrol Datasheet –
Typical.”
 Create the LC notification in the AI App
 AND the clerk will record the completed maintenance task(s) in the SAP
database
 AND record the completed maintenance in your time card with the
appropriate accounting.
 For Underground:
 In the “Comments” section of forms TD-1001M-F06 through TD-1001M-F11,
depending on the inspection performed
 Create the LC notification in the AI App
 AND the clerk will record the completed maintenance task(s) in the SAP
database

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 AND record the completed maintenance tasks in your time card with the
appropriate accounting.

1.5.2 Assessing Conditions

Evaluate the condition of the facilities at each location when performing patrols, inspections, or
post-checking the completed work. Section 2. Inspections, identifies many of the field
conditions that need to be evaluated.
Once identified, the QCR determines the severity of the condition, the risk factors, the
appropriate priority level, and a reasonable time frame to plan, design, and complete any
required corrective work. Recommendations of an appropriate priority/repair time frame by the
QCR are based on experience and judgment.
In addition, the QCR must consider the following risk factors and conditions encountered in the
field when recommending priority/repair codes:
 The risk of exposure to the public, workers, or employees
 The abnormality encountered
 Risks if the condition continues to deteriorate
 Likelihood of facility failure
 Impact of the failure to system reliability, customers and service, and/or the potential
for injury
Table 5 lists the priority codes and the associated time frames for typical response/repair
action.

Table 5. Priority Codes

Priority Code Priority Description

The condition is urgent and requires immediate response and continued action
until the condition is repaired or no longer presents a potential hazard. SAP due
A
date will be 30 days to allow time for post-construction processes and notification
close-out.
Corrective action is required within 3 months from the date the condition is
B identified. The condition must be reported to the transmission line supervisor as
soon as practical.
Corrective action is required within 12 months from the date the condition is
E
identified.
Corrective action is recommended within 24 months from the date the condition is
F identified, (due beyond 12 months, not to exceed 24 months). Requires Director
approval.

1. QCRs must report immediately any “Priority Code A” abnormal condition to the
transmission line supervisor and GCC.
2. In addition, QCRs must report any “Priority Code B” condition to the transmission line
supervisor as soon as practical, to ensure that correction occurs within the appropriate
time.
During the Fire Safety Rulemaking in 2017 and 2018, new GO95 requirements impacting
transmission lines were adopted, including the items listed below.
 Rule 21.2D added a definition for High Fire-Threat Districts (HFTD)

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 Zone 1 – Tier 1 High Hazard Zones (HHZ) on the Tree Mortality Map
 Tier 2 – areas on the CPUC Fire-Threat Map where there is an elevated risk for
destructive utility-associated wildfires
 Tier 3 – areas on the CPUC Fire-Threat Map where there is an extreme risk for
destructive utility-associated wildfires
 Where Zone 1 overlaps with Tier 2 and Tier 3 areas, the strictest regulations apply
 Rule 18 added requirements for the prioritization and correction of safety hazards in
HFTDs. The changes impacting transmission were:
 Shortened not to exceed timelines for correcting Level 2 safety hazards in HFTDs
 6 months in Tier 3 (fully implemented 9/1/18)
 12 months in Tier 2 (fully implemented 6/30/19)
 Appendices I and J provide examples of facility conditions in different situations with
different corrective timelines based on the risk and level of impact on safety and reliability

Drawing 072148 Fire Responsibility and Wildland Fire Areas has been updated to reflect the
CPUC HFTDs. ET GIS, MapGuide and Google Earth have also been updated with this
information.

Priority E and F notifications for facilities that are located in Tier 3 of the HFTD map will be
assigned dates with a maximum 6 month duration, and facilities located in Tier 2 of the HFTD
map will be assigned dates with a maximum 12 month duration. This maximum duration will
be set in SAP. If the notification is determined to be non-threatening (e.g., not a Level 2 safety
hazard that would result in a fire risk), the asset strategist will code it as non-threatening and
adjust the Recommended Repair Date based on the Priority Code.

There are no changes to Table 1 Vegetation Clearance Distance.

The following is a list of conditions from GO95, Appendices I and J for transmission line
overhead facilities that may create a fire risk (Level 2 conditions) in the HFTDs, but it is not all-
inclusive. In addition, any conditions found on distribution assets should be reported per
Section 1.3.4 Reporting Other Nonconformances with Distribution Facilities.
 Excessively sagging conductors
 Inadequate separation
 Broken insulators compromising adequate insulation values
 Damaged equipment (e.g. switches)
 Equipment found as burnt, flashed or with evidence of arcing (e.g., insulators, jumpers)
 Deteriorated crossarms
 Damaged or deteriorated bird guards
 Damaged or excessively leaning towers or poles
 Sagging guys
 Insufficient clearance from vegetation
 Vegetation causing strain or abrasion
 Missing or damaged wood pole bridging on underbuild

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Examples of conditions that may not create a fire risk (non-threatening) in the HFTDs and
associated notifications and are not subject to the shorter HFTD durations are shown below.
The asset strategist will code it as non-threatening and adjust the Recommended Repair Date
based on the Priority Code.
 Missing high voltage sign in remote locations, inaccessible to pedestrians or vehicles
 Damaged or missing guy marker in remote locations, inaccessible to pedestrians or
vehicles
 Anchor guy with minimal slack where a pole is straight or leaning towards the anchor
 Climbing space obstruction from vegetation when it does not prevent work from being done
or does not violate Rule 35
 Damaged or loose hardware that is not in the climbing space and does not pose a risk to
employees or the public
 Missing or damaged bolt covers where only exposure is to the QEWs

1.5.3 Notifications Extending Beyond Due Date

It is the Company’s intent to correct identified abnormal conditions by the established due
date. With the exception of notifications approved through the LC past due exemption process,
due dates will not be changed or extended. Past due notifications that are not approved for
exemption must be completed as soon as practicable. Factors that can drive notifications to
extend beyond the due date include, but are not limited to, the following items:
 Inability to obtain clearances, materials, equipment or access
 Environmental permitting restrictions
 Interference from weather
 Subsequent testing or reevaluation of the actual condition

1.5.3.1 LC Notification Past Due Exemption Process

In order for a notification to be exempted from internal late tag reporting and officially
‘exempted’, the LC notification past due exemption process must be followed to ensure field
conditions will permit an extension and that proper documentation is included in SAP. Follow
the procedures in TD-1001M-JA03, “Transmission LC Past Due Exemption Process” and
utilize TD-1001M-F17, “SS LC XMPT Req Form (Notif)”.
The LC Past Due Exemption Process requires:
1) A field visit by a PG&E QEW to assess the current field condition identified and confirm it is
safe to defer completion of the work to a later date
2) Photo documentation of the current condition
3) EDRS approval from the Asset Strategist, Supervisor Maintenance and Compliance,
Superintendent AND the Transmission Line Senior Director with documentation attached in
SAP and a CC to the Manager Work Plan and Maintenance Strategy
NOTE: If it is unsafe to defer completion of the notification, PG&E musts continue to pursue
other methods of completing repairs prior to the required end date.
An LC Notification due date exemption should not be requested until reasonable effort has
been made to complete the notification by its required end date (also known as due date).

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GO95 Rule 18A Part 2b states that “Correction times may be extended under reasonable
circumstances” and lists several examples of reasonable circumstances. TD-1001M-JA03,
“Transmission LC Past Due Exemption Process”, elaborates on the sample circumstances
listed in Rule 18A and outlines the PG&E process for requesting and documenting due date
exemptions for corrective work.
LC notifications for maintenance work that have met the circumstances outlined in that
document, and have been approved through the exemption request process:
 Will be exempt from meeting their Required End Dates
 Will be required to meet a new due date, an updated Required End Date (shown as
Funded Repair Date in SAP)
 Will not be included in internal late LC Notification reports
All exemption requests must be made no later than the notification required end date, with the
exception of notifications that meet the Major Emergencies criteria outlined below. Examples
of conditions that may qualify for an Exemption include:
 Third Party Refusals. Examples:
 Refusals due to right-of-way conflicts
 Prevention of work due to issues with third party utilities
 Inability to acquire clearances due to CAISO limitations or refusals
 No Access. Example:
 Field conditions, such as landslides, water, or snow create an unsafe environment
for crews to complete work
 Permit Delays. Examples:
 Delays in obtaining environmental or land permits to complete work. Permit
request should be submitted at least 60 days prior to the required end date.
 Delays due to city moratoriums on work
 Major Emergencies. Examples:
 Resources diverted due to Major emergencies, such as fires, severe weather
conditions, etc., and the LC required end date falls between the first day of the
OEC activation and 30 calendar days after the OEC deactivation (order status must
be released to construction
 Resources diverted due to routine emergencies, such as car poles, do not qualify
 Unavoidable Internal Delays
 For example, pending substation work that prohibits transmission work from being
completed until the substation work is completed. Not limited to substation; can be
due to distribution, power generation, etc.
Internal process delays do not qualify for exemption. Such exemption requests will be
reviewed by the LC Program Manager on a case-by-case basis. Examples of internal process
delays include, but are not limited to:
 Delays in job cycle handoffs, such as the handoffs of job packages to construction
crews
 Job scope changes
 Scheduling work beyond the notification Required End Date to minimize the impact
of outages due to customers or bundling work for crew efficiencies

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 Permitting/environmental delays due to PG&E’s internal process. For example, a

permit is not obtained in time. PG&E had to opportunity to file a permit sooner, but
did not do so due to internal process delays.
 Unavailability of materials
 Inability to obtain a clearance before the due date as a result of GCC constraints
Prior to the submittal of an Exemption request, a qualified PG&E employee must complete a
field visit to assess the current field condition identified on the LC notification and confirm it is
safe to defer the completion of the work to a later date. At least one picture is required to
document the current field condition (take additional pictures as needed). All requests require
a field safety assessment and photo including static FDA. Exception: A field visit/safety
picture is not required if all the requirements below are met:
 It meets the major emergency criteria
 Is NOT a Priority B tag
 It will be worked within 2 months from the required end date
If it is unsafe to defer the notification, PG&E must continue to pursue other methods of
completing repairs by the prior established notification required end date. For example, if
there is an environmental issue and it is unsafe to defer the work, PG&E must communicate
with the local agency that the work needs to be completed prior to the due date and that it is
unsafe to defer.
1.5.3.2 LC Notification with Rejected Exemptions OR Past Due Date Process
For any notification for which the exemption was rejected and/or is past due and did not meet
the exemption criteria, an EDRS which includes the reason will need to be routed to the
Regional Superintendent for approval. The EDRS must CC the Transmission Line Senior
Director, Manager Work Plan and Maintenance Strategy, Supervisor Maintenance and
Compliance and local Asset Strategist.

1.6 Creating and Closing Inspection/Patrol and Maintenance Records

All inspection and patrol records must be filled out completely and accurately and maintained in
the appropriate files. Refer to TD1001M-JA01, “Patrol, Inspection and Closing Process”, for
directions on completing and reviewing the forms and the SAP closing process. Refer to
Appendix E: Line Patrol File Guidelines for additional requirements on how to complete the forms
and how to store the files. Section 1.6.1 Inspection/Patrol Records – Records and Deadlines
provides specific timelines for QCRs, clerks, supervisors and/or SAP “gatekeepers” to enter all
information into SAP.

1.6.1 Inspection/Patrol Records

Overhead Patrols: Use the overhead ETPM Form TD-1001M-F01, “Transmission Line
Inspection/Patrol Datasheet – Typical,” to document any abnormal conditions as they are
encountered in the field. See 8.Appendix C: Links to Forms and Flowcharts, for a list of and
links to overhead inspection/patrol datasheets.
Overhead Inspections: Use the object list, TD-1001M-F05, “Object List - Typical” and the
datasheet TD-1001M-F01, “Transmission Line Inspection/Patrol Datasheet – Typical,” to
document inspections and to verify the assets. See 8.Appendix C: Links to Forms and
Flowcharts, for a list of and links to overhead inspection/patrol datasheets and object lists.
Underground: Use the underground transmission inspection sheets and forms TD-1001M-
F06 through TD-1001M-F11, depending on the inspection performed, to document test results

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and any abnormal conditions encountered in the field. See Section 5.2 Underground Job Aid
for Maintenance Procedures for typical maintenance procedures and corrective actions.
Records and Deadlines: After an inspection, completed overhead and underground
inspection/patrol datasheets and inspection/patrol forms must be signed, dated, and submitted
to the transmission line supervisor for review and approval. Notwithstanding extraordinary
circumstances, such as a major emergency response, upon completion of the field patrol or
inspection, QCRs are expected to:
 Submit required paperwork to the local clerk within five (5) business days or by the
end of the calendar month the patrol was completed in, whichever is sooner.
Supervisors review forms (either paper or electronic) for accuracy, including completion of all
fields, confirm the priority code and due date, confirm clearance requirements or hot work,
ensure ink was used on paper forms and confirm signature, date and LAN ID. The supervisor
or other SAP gatekeeper is expected to approve or reject all SAP staging notifications within
five (5) business days of their entry into SAP gatekeeper module.
Timeline Detail:
1. QCR finds abnormal condition during inspection/patrol on Day 00
2. QCR delivers completed forms to clerk by business Day 05
3. Clerk enters inspection and patrol information into the SAP system by business Day 15.
4. Gatekeeper reviews and rejects/modifies/approves S5 to create new LC by business Day
20, thus establishes SAP notifications within 20 business days to facilitate proper work
planning, scheduling, and to correct abnormal conditions by the required due dates.
5. Document the reason for non-routine and emergency patrols on the notification.
The overhead TD-1001M-F01, “Transmission Line Inspection/Patrol Datasheet – Typical,” and
the underground transmission “Routine” and “Detailed” inspection forms (TD-1001M-F06
through TD-1001M-F11, depending on the inspection performed) must contain, but is not
limited to, the following information:
 Name of the QCR
 Date of the inspection/patrol
 Name of the circuit inspected/patrolled
 Structure number/s
 FDA condition
 Facility found abnormal
 Damage indicated
 Action, such as recommended maintenance activities and the priority of these
recommendations
 Significant comments regarding special work requirements, access notes, etc.

1.6.2 Maintenance Records

Record routine, non-routine, and emergency maintenance performed in the SAP database or
on inspection/patrol datasheets. Maintain records in accordance with Section 1. General
Inspection and Patrol Procedures, Section 1.1 Record Keeping and Section 1.5.1 Resolving
Abnormal Conditions during Patrol or Inspection. These records must include, at a minimum,
the person responsible for performing the maintenance, the date of the maintenance, the
name of the circuit, the facility maintained, and a description of the maintenance performed.

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Keep these records in the SAP database and field inspection and patrol files at the responsible
transmission line supervisor’s headquarters.

1.6.3 Asset Creation

As assets observed in the field differ from SAP object lists, drawings, schematics, or other
formal references, they should be updated per the Electric Transmission Geographic
Information System (ET GIS) asset creation or maintenance processes (ET GIS Process maps
1.1 through 1.16). These processes apply to overhead and underground assets. Following the
ET GIS asset creation and maintenance processes will ensure the transmission asset registry
and mapping systems are kept current with actual field conditions. New assets or removed
assets must also be entered in ET GIS. Use TD-1001M-F13, “Request to Add Equipment
Records to the Asset Registry” to add new equipment. Use TD-1001M-F14, “Request to
Delete Equipment Records to WM SAP” to delete equipment in ET GIS. Refer to ET GIS SAP
– Request for Work Job Aid – Creation for specific details.

1.7 Overhead Job Aid for Assigning Priority Codes

The inspector’s primary responsibility in an overhead electric facility inspection or patrol is to
examine and record the specific condition of the facilities. This requires a detailed evaluation (e.g.,
visual observation, and potentially, use of measuring devices, tools, or routine diagnostic test) to
determine if there are any structural problems or hazards that will adversely impact safety, service
reliability, or asset life, and to evaluate when each abnormal condition identified warrants
corrective action. Do not create corrective maintenance notifications for abnormal conditions that
do not require corrective action prior to the next scheduled inspection or patrol.
Use the guidelines in Table 6. Guide for Assigning Priority Codes, to grade abnormal conditions
that will adversely impact safety, service reliability, or asset life, that, in the judgment of the
inspector, require corrective action before the next scheduled inspection or patrols. Table 6. does
not provide a comprehensive list of conditions that can be encountered. The Priority Code levels
are for typical adverse conditions and must be adjusted up or down based on the inspector’s
judgment of the actual condition observed. See the following examples:
Example 1:
A missing damper is identified during a routine aerial patrol.
 Table 3. Overhead Facility, Damage and Corrective Action Codes Facility, Damage and
Corrective Action Codes, provides the facility code for missing damper.
 Referring to Table 6. , E is a typical Priority Code for a missing damper.
 The inspection datasheet is completed with the following information:
 Facility Code: Damper-Steel or Damper-Wood
 Damage Code: Missing
 Action Code: Install
NOTE: If the inspector is aware that the transmission line with the missing damper has an
aged conductor with a history of vibration-related problems, the inspector may, based on his
knowledge of the line, assign a Priority Code B (3 months).
Example 2:
A loose “Danger High-Voltage” sign is identified during a routine ground patrol at a wood pole.

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 Table 3. Overhead Facility, Damage and Corrective Action Codes Facility, Damage and
Corrective Action Codes, provide loose markers.
 Table 6. Guide for Assigning Priority Codes, a typical Priority Code for a loose “Danger
High-Voltage” sign would be E.
 The inspection datasheet is completed with the following information:
 Facility Code: Marker (i.e. signs)-Wood
 Damage Code: No Good/Out of Stdrd
 Action Code: Install
Example 3:
A wood pole is identified with significant woodpecker damage during a routine ground patrol.
 Table 3. Overhead Facility, Damage and Corrective Action Codes Facility, Damage and
Corrective Action Codes, for structure wood damage.
 Table 6. Guide for Assigning Priority Codes, a typical Priority Code for severe woodpecker
damage would be B.
 The inspection datasheet is completed with the following information:
 Facility Code: Structure-Wood
 Damage Code: No Good/Out of Stdrd
 Action Code: Replace

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Table 6. Guide for Assigning Priority Codes

Priority Code
Component A B E F
(Immediate) (3 months) (12 months) (24 months)

Rust >50% material Rust 30 - 50% material loss

loss Cracked 33 to 50%
Anchor-Steel Worn 30 - 50% material loss
Worn >50% material Over tension >50% Over tension 10 to
Anchor-Wood Cracked 5 to 33%
loss Broken or missing secondary 50% No 24 month
Cracked >50% Soil Movement/slide/ Twisted tags
members
Guy Wire-Steel standing water
Broken or Missing Clearance from energized
Guy Wire-Wood critical members Slack storm guy
conductors

Cracked 33 to 50%
Gunshot 15 to 20% of strands
Rust >50% material broken
Rust 10 - 50% material loss Cracked 5 to 33%
Conductor-Steel loss Corrosion (heavy)
Broken damper Gunshot 5 to 15% of
Conductor-Wood Cracked >50% Conductor clearances No 24 month
Missing damper strands broken
Gunshot >20% of Broken ground wire or tie tags
Bent damper Corrosion (medium)
Damper-Steel strands broken wire
Out of position damper Vibrating
Damper-Wood Arcing Broken spacer or connector
Loose connector, tie wire, or
weight
Twisted bundled conductor

Electrical
clearances: Tree contacting line Circuit-to-circuit
Grade change
GO95 Clear Infract- or showing signs of Burnt Ground Clearance No 24 month
(Ground Clearance
Tower contact (burnt Trees Clearance < G.O. 95 tags
< G.O. 95)
GO95 Clear Infract- leaves or limbs) < G.O. 95
Wood

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Priority Code
Component A B E F
(Immediate) (3 months) (12 months) (24 months)

Rust 30 - 50%
material loss
Significant soil
erosion or Rust (rebar exposed with Cracked (cracks > For
movement causing >50% material loss) 1/16”) optimization of
lack of support Cracked Earth covered/ permitting,
around the (cracks >1/2”) Not sealed buried foundation estimating, and
foundation. Earth covered (covering steel Soil movement Buried steel stubs engineering
Foundation/
Damage to, or member) (Slide 10 to 15 inches) (due to potential criteria; as well
Concrete-Tower as long-lead
separation of, main Buckled rebar, concrete Bent corrosion)
structural support spalling Exposed wood pile Twisted time materials
members or stub and
Soil movement (movement Soil movement (e.g.,
angle tower leg that environmental
causing significant bowing of erosion or piled dirt,
compromises reviews
tower members) movement causing
structural integrity
some bowing of
tower main legs)

Insulator
Rust >50% material
Insulator-Steel
loss
Insulator-Wood Rust 30 - 50% material loss
Worn >50% material Cracked 33 to 50%
(Insulators with these Worn 30 - 50% material loss No 24 month
loss Contaminated (heavy) Cracked 5 to 33%
conditions, see Contaminated (medium) tags
Cracked >50% Tracking (heavy)
Table 7. , Flashed Tracking (medium)
Contaminated
Cracked, Broken, (arcing)
Gunshot,
Chipped >1½ inches)
Switch Cracked 33 to 50% For
Rust >50% material Rust 30 - 50% material loss
Switch-Steel loss Corrosion (heavy) optimization of
Contaminated (medium)
Switch-Wood Contaminated (heavy) Cracked 5 to 33% permitting,
Cracked >50% Tracking (medium) estimating, and
(Switch insulators Tracking (heavy) Corrosion (medium)
Arcing Heating engineering
with these conditions, Burnt criteria; as well
Open (unlocked) Bent/Bowed
see Hot as long-lead
Inoperable
Table 7. , Flashed, Loose time materials

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Priority Code
Component A B E F
(Immediate) (3 months) (12 months) (24 months)
Cracked, Broken, Broken and
Gunshot, Out of adjustment environmental
Chipped >1½ inches) Missing reviews

Critical/Main
member:
Rust >50% material
loss For
Cracked >33% Rust 30 - 50% material loss optimization of
Worn >50% material permitting,
Missing bolts or single bolt Pack-rust at joints, crevices Vibrating members estimating, and
loss or overlaps
connection on critical Twisted engineering
Structure-Steel Damage to main member Cracked 10 to 33% Out of plumb 1 to 3 criteria; as well
Structure-Tower structural support as long-lead
Single bolt mission of multi- Worn 30 - 50% material loss feet
members time materials
bolt connection Buckled/bent Loose bolts, etc.
compromising and
structural integrity Out of plumb >3 feet environmental
Internal corrosion of reviews
tubular memberrs
Broken (member)
Missing (member)

Facilities or
Markers (i.e. signs)- structures which Cracked
Steel have a recent Broken No 24 month
_ _
Markers (i.e. signs)- history of trespass Loose tags
Wood or third-party Missing
unauthorized access

Right of Way Tree contacting line

Grade change
or showing signs of Tree clearance Encroachments
(Ground Clearance
contact (burnt < G.O. 95 _ to be resolved
Vegetation < G.O. 95)
leaves or limbs) Clearances < G.O. 95 via Land
Vegetation-Tower Encroachments Management

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Priority Code
Component A B E F
(Immediate) (3 months) (12 months) (24 months)

If posing threat to
Access road
facilities due to
Road repair or
wash out or land
replacement
motion

Boardwalk (not
necessary to
submit an LC
Notification)

SCADA-Steel Replace or
Repair SCADA
SCADA-Wood install SCADA

Burnt 40-50% material loss For

Burnt 20-40% material loss optimization of
Cracked >50% Cracked 10 to 50%
permitting,
Broken Twisted (severe) Twisted (medium) estimating, and
Slide >15 feet Slide 10 to 15 feet Erosion >4 feet in engineering
Burnt >50% material
Structure-Wood Out of plumb >15 feet Out of plumb 4 to 15 feet the ground criteria; as well
loss
Erosion 3 to 4 feet in the Worn/woodpecker as long-lead
Soil Movement (Erosion >3
ground damage (medium) time materials
feet in the ground)
and
Worn/woodpecker Standing water Earth covered
environmental
damage (severe) reviews

Removal of idle For planning

facilities posing an optimization of
Idle Facilities (any
immediate threat to - - - removal of non-
facility type)
life, property or emergency idle
reliability facilities

Note: If, on performing the required visual inspection and hammer test, the QCR believes the pole to be suspect, the pole must be tested further in accordance
with Utility Standard TD-2325S, “Wood Pole Inspection, Testing, and Maintenance,” and Work ProcedureTD-2325P-01, “Wood Poles - Testing,
Reinforcing and Reusing.” This standard establishes the requirements for inspecting and testing the structural integrity of wood poles, the requirements
for reinforcing and reusing, and requirements for testing wood poles prior to climbing. After completing the pole inspection, the QCR must complete the
TD-2325P-01-F01, “Attachment 1 - Pole Inspection/Test Report,” and forward it to the supervisor. The supervisor will forward it to the estimating group for
further evaluation and appropriate corrective action identification.

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1.8 Overhead Job Aid for Insulator Replacement and Priority Codes
1.8.1 Insulator Strength and Loading
Usually, dead-end insulators are loaded to a higher percentage of their design strength than
are suspension insulators. Typically, suspension insulators are loaded 30% to 50% of the
design strength of dead-end insulators.
Listed below are the criteria for replacing insulators during maintenance:
 Replace suspension and dead-end insulators if they exhibit signs of deterioration or
corrosion or have been subjected to some unusual loading condition. If insulators are
in good condition, loading and unloading the insulator string during routine
maintenance will not degrade the insulators.
 Replace all suspension or dead-end insulators that have been affected by shock
loading (impact loads that exceed the normal loading and are generally associated with
broken wire conditions on steel structures with normal sag tensions that exceed 3,000
pounds).
 All insulators not listed as approved for purchase or as a salvable substitute are
obsolete and must not be used. Salvable substitute insulators more than 20 years old
are not to be used and should be disposed of. Salvable substitute insulators less than
20 years old that have not been in service may be used. Suspension type porcelain
insulators shall not be used on new construction without approval from transmission
line standards engineer per TD-015014B-001, “Approval Required for Installation
Suspension Type Porcelain Insulators”.

1.8.2 Insulator Conditions

1.8.2.1 Broken Insulators
Broken insulators have one or more of the following conditions:
 Glass or porcelain is broken and only the hub is remaining.
 One or more skirts are broken and a piece is missing.
 The insulator is cracked.
1.8.2.2 Chipped Insulators
Chipped insulators generally have little effect on the reliability of the insulator and do not need
to be addressed, unless one or more of the following conditions is present:
 A crack extends from the chip.
 The chip is larger than 2” in diameter.
 The chip is located next to a grouted fitting where it will trap water and could freeze.
If any of the above conditions exist, evaluate the insulator like it was a broken insulator.
Use the proper Priority Code listed in Table 7.

1.8.2.3 Flashed Insulators

The priority for a flashed insulator depends on the type of insulator. The following information
provides some direction for assigning priorities to the various types of insulators:

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 Porcelain - Replace the entire insulator string or post insulator. Depending on the
weather conditions, contamination present on the insulator, and the contamination
area, assign Priority Code A, B, or E. If assigning a Priority Code B or E, the
insulator must be washed or cleaned as soon as practical to prevent it from flashing
over again before it is replaced.
 Glass - Glass insulators do not always need to be replaced when flashed. If the
glass is intact, cleaning the insulator usually restores its electrical strength.
However, if the glass is broken, replace the insulator(s) and assign the Priority
Code using the criteria for broken insulators.
 Non-Ceramic - If the flashover damaged the insulator sheds or end fittings, assign
Priority Code A and replace the insulator. If there is no visible damage to the
insulator skirts or end fittings, the insulator does not need to be replaced and does
not need a Priority Code.
1.8.2.4 Dirty/Contaminated Insulator Cleaning
Perform insulator washing based on local environmental conditions, operating experience, and
the predetermined wash cycles established in SAP.
 Wash insulators in accordance with the TD-1257M, “Insulator Cleaning Manual”.
The TD-1257M, “Insulator Cleaning Manual” provides guidance on contamination
assessment and insulator cleaning frequency.
 Maintenance plans must be created in SAP for circuits that require annual (or more
frequent) insulator washing, as determined by the local transmission line
maintenance supervisor, based on insulator contamination and performance.
 By agreement, maintenance plans must be created in SAP for Diablo Canyon
Power Plant (DCPP) 500kV and 230kV transmission line circuits utilizing
frequencies specified in Section 2.1.3 and Table 15. Specific wash instructions are
provided for structures near DCPP and Morro Bay Power Plant in Section 6.6.

1.8.3 Assigning Insulator Priority Codes

Table 7. Guide for Replacing Damaged Insulators, provides guidance for assigning the proper
Priority Code for broken insulator strings. Use this information for the various voltages, types
of construction, and contamination districts to provide consistent responses and ensure
system reliability.

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Table 7. Guide for Replacing Damaged Insulators

G.O. 95 # of Broken Units
Minimum 2 or
Contamination Requirements Design # Minimum 1
Voltage Configuration more
District Dry of Units # of Units
# of
Flashover Priority Code
Units
*
Dead-end AAA 34 32 E B
Dead-end B, C, D 28 26 E B
Vee String AAA 36 34 E B
500kV 1,190 kV 23
Vee String B, C, D 28 26 E B
Suspension AAA 34 32 E B
Suspension B, C, D 25 23 E B
Dead-end AAA 24 20 E B
Dead-end A 22 18 E B
230kV Dead-end B, C, D 582 kV 12 17 15 E B
Suspension AAA 16 13 E B
Suspension A, B, C, D 15 13 E B
Dead-end AAA 12 10 E B
Dead-end A 11 9 E B
Dead-end B 10 8 E B
115kV Dead-end C, D 333 kV 6 9 8 E B
Suspension AAA 10 6 E B
Suspension A, B 9 6 E B
Suspension C, D 8 6 E B
Dead-end AAA 7 5 E B
Dead-end A, B 7 5 E B
60/70kV Dead-end C, D 180 kV 3 6 5 E B
Suspension AAA, A, B 5 3 E B
Suspension C, D 4 3 E B
* The dry flashover (FO) is based on ANSI C29.1 test procedures.
Notes:
1. This table is based on dry flashover insulator characteristics. If possible, replace insulators
before the onset of wet weather.
2. Consider local conditions. Insulator strings near the coast, at Diablo Canyon, 500 kV, etc., may
be more critical and replaced more urgently.
3. Adjust the Priority Code based on the various conditions that may exist, including
 Priority Code A (fix immediately) for 2 or more insulators less than the G.O. 95 requirement
 Priority Code B (fix within 3 months) for 1 insulator or less than the G.O. 95 requirement
 Priority Code E (fix within 1 year) if less than design, but more than the G.O. 95
requirement
4. For barehand work, refer to the TD-1248M, “Electric Transmission Live Line Barehand Work
Procedures Manual” for the minimum number of insulators and clearance requirements.
5. If an insulator string has broken insulators and the remaining number of good insulators in the
string exceeds the design number of units, assign Priority Code E.

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1.9 Overhead Job Aid for Transmission Line Steel Structures

1.9.1 General
Inspect transmission line towers on a regular basis. If abnormal conditions are found during
this process, use ET AI App to record the physical condition of the structure. It is
recommended to use digital pictures in conjunction with this form.
See Table 6. Guide for Assigning Priority Codes, for information about assigning notification
priorities for the condition found.

1.9.2 Analysis of Condition by Engineering

See Section 1.16 Equipment Replacement ,.

1.9.3 Detailed Description for Repairing Deteriorated Steel Structures

Table 8. Detailed Description for Repairing Deteriorated Steel Structures

Priority Code Characteristics Action Notes
Major corrosion (severe rusting on Replace the structure to
more than 50% of the structure steel avoid a catastrophic failure.
and isolated pitting) and/or physical
damage to main structural members,
A: compromising structural integrity.
Immediate Severely rusted legs, packed-rust at
attention bolted joints, and/or internal corrosion
required. of tubular members.
Catastrophic failure of structure is an
immediate possibility.

B: Members and/or bolts missing. Repair as needed to restore

Attention structural integrity.
required within
3 months.
Rust 30-50% material loss. Repair as needed to restore CAUTION:
Moderate corrosion (surface rusting on structural integrity. If pack-rust is significant
more than 50% of the structures) and Replace areas of isolated and the area(s) cannot
E: loss of galvanizing. Reddish brown steel members with serious be replaced, replace the
Attention rust of zinc-iron alloy with less than a pack-rust, if possible. structure within 5 years.
required within mil of zinc left on the surface.
12 months. If pack-rust is present,
Pack-rust at joints, crevices, or contact transmission line
overlaps. civil engineering.

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Physical damage on one or more Modify the structure

easily replaceable members. according to civil
Any coating, if previously applied over engineering
galvanizing, is more than 50% recommendations to
deteriorated, exposing surface rust. eliminate vibrations.
Any coating at steel-concrete Replace twisted members.
transition (aka stub-concrete interface) Clean rust from stub-
is more than 50% deteriorated concrete interface, wipe
exposing surface rust. dust clean with denatured
Any soil or vegetation is within 18 alcohol or isopropyl alcohol,
inches or covering greater than 30 and recoat with approved
inches of stub-concrete interface coating, typically black bitu-
mastic material.
Vibrating or twisted members.
Remove soil/vegetation or
Loose bolts.
add proper compacted
medium and/or reinforce
footing according to civil
engineering
recommendations.
Priority Code Characteristics Action Notes
No significant evidence of structural or Inspect at least every 5 Long lead time material
surface deterioration or corrosion. years as a precaution. required.
F: Galvanizing still in good condition with Structure replacement.
Attention a minimum of 2 mils zinc present.
required within Environmental/permitting
24 months. Any coating previously applied over requirements.
galvanizing is in good condition with No Attention Required
no significant deterioration. for at Least 5 Years.

1.10 Overhead Job Aid for 500 kV Climbing Inspections

1.10.1 General
Inspect 500 kV transmission towers on a regular basis. Use ETPM Form TD-1001M-F03,
“500kV Climbing Inspection Form and Tower Diagrams,” to record the physical condition of the
structure. Digital pictures may be used in conjunction with this form. Enter the conditions found
in the SAP system and submit the form to the transmission line asset management supervisor
in accordance with the instructions on the form. TD1001M-JA02, “Detailed Climbing
Inspection Job Aid” and TD-1001M-JA04, “Identifying Levels of Corrosion and Foundation
Condition on Transmission Line Structures and Supports” should be referenced for additional
instructions to complete the forms.

1.10.2 500 kV Climbing Inspection Form and Tower Diagrams

TD-1001M-F03 provides a ready reference to ensure a thorough inspection. It is intended that
the items on Pages 2-4 of the form will be inspected during the climbing inspection. Page 5 of
the form provides a reference to aid the inspector in recording other line-related component
deficiencies that might be noticed during the inspection.
The “Tower Diagrams” part of TD-1001M-F03 provides a framework to record guy tensions.

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1.11 Overhead Job Aid for Conductor Inspections

1.11.1 General
Patrol and inspect transmission lines and their associated conductors on a regular basis. If an
abnormal condition is found during this process, use the ET AI App to record the physical
condition of the conductor. Refer to Table 6. Guide for Assigning Priority Codes for
information about assigning Priority Codes.

1.11.2 Analysis of Condition by Engineering

If a conductor is not in immediate risk of failure, but is considered beyond economical repair,
follow the process described in Section 1.16 Equipment Replacement .

1.11.3 OPGW and ADSS Cable Inspection

Some installations of OPGW have been deteriorating due to the non-standard installation of
the hanging hardware, as well as internal corrosion build up. The non-standard installation
includes, but is not limited to, the following: incorrect placement of U-Bolt Dead-End spacer
bar, incorrect U-Bolt Dead-End ground types, missing vibration dampers, improperly placed
down-lead cushions, and not maintaining minimum separation between OPGW cables on
splice towers. This situation has resulted in broken outer layer OPGW strands and
corrosion. Some installations of ADSS cable have been deteriorating due to dry band
arcing/tracking. This is the situation where the electric field is too high for the ADSS cable to
survive and over time the electric field has burned through the cable jacket. During patrols
and inspections, as possible, examine the cable and hardware installation of the OPGW and
ADSS cable. If you see signs of tracking, broken strands, separating strands, bare fiber or
exposed buffer tubes, create an SAP notification indicating the following:

Facility Code = Shield Wire/OPGW (Steel or Wood), Damage Code = No Good/Out of
Stdrd, Action Code = Repair or Replace
Take photos as possible, with comments describing the condition found and if there are
recommendations for repairing or replacing.

1.12 Overhead Job Aid for Switch Inspection

1.12.1 General
Transmission line switches must be inspected in accordance with circuit inspection cycles, and
maintained in accordance with FDA Processes as per TD-1006P-02, “Switch Maintenance and
Inspection Program for Electric Transmission” and TD-1006P-02-JA-01 “Electric Transmission
Line Switch Inspection/Function Test Job Aid”.

1.12.2 Overhead Switch Numbering

Transmission line switches must be numbered in accordance with TD-1006B-004 “Procedure
for Marking Duplicate Transmission Switches”.

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1.12.3 Analysis of Condition by Engineering

If a switch is not in immediate risk of failure, but is considered beyond economical repair,
follow the process described in Section 1.16 Equipment Replacement ,.

1.13 Removal of Metal Fence Attachments

Third-party attachments of metal fences (cyclone, barbed wire, etc.) to steel towers, wood
poles, and/or transmission down guys is not permitted. Remove all attachments and instruct
the fence owner that this attachment or contact is not allowed.

1.14 Overloaded Transmission Line Poles

1.14.1 General
Over-stressed/overloaded wood poles can occur as a result of underbuilt distribution facilities,
underbuilt third-party facilities, or as a result of reconductoring without an associated pole
replacement.

1.14.2 Required Action

If there is any reason to believe or suspect that wood poles are overloaded or over stressed,
record specific information about the situation and send it to the appropriate transmission line
estimating office for further action. The information recorded must include, but is not limited to,
the following items:
 Line name, structure number, and location
 Wire size, cable size, span length, attachment height
 Pole size and class
 Any additional information deemed necessary for identification or explanation
Complete the notification form in the ET AI App using the FDA codes provided in Section 1.4.
Inspection Methodology, Facility, Damage and Action Codes.

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1.15 PAL Nuts – Remedy for Loose or Missing Tower Bolts

1.15.1 General
An evaluation after a Type HVD 500 kV tower failed due to missing bolts determined the
optimum locking device to use on tower bolts. Though a properly center-punched tower bolt
will prevent a nut from backing off, it is difficult to determine when a standard bolt has been
properly center-punched. Using a PAL nut over the standard tower nut to prevent the tower nut
from backing off due to vibration is the preferred method.

1.15.2 Required Action

Install PAL nuts at the discretion of the supervisor when a tower has a history of loose or
missing bolts, or at critical tower locations where the failure of the structure could have serious
consequences.
Field experience has shown that PAL nuts are easier to install with a ratchet-type box-end
wrench to prevent the wrench catching on the underlying standard nut. Install PAL nuts with
the flat side toward the standard nut.
This requirement applies to towers of all voltages.
The code numbers for PAL nuts are as follows:
 190774 for use with 1/2” bolts
 190775 for use with 5/8” bolts
 190776 for use with 3/4” bolts

1.16 Equipment Replacement Notifications

1.16.1 General
If a structure, foundation, conductor, or switch is not in immediate risk of failure, but is
considered to be beyond economic repair, complete an LC notification in the ET AI App
showing:
 Damage Code = No Good/Out of Stdrd, Action Code = Replace
Asset strategy engineering will evaluate the facility or equipment and make the determination
of when and how it should be replaced. An overall yearly review of notifications and projects
are part of the annual planning process.

For FAA lighting that is not functioning properly, and repairs are impractical or uneconomic,
complete an LC notification in the ET AI App with the appropriate information below.
 Facility Code = FAA Battery (Steel or Wood), Damage Code = No Good/Out of Stdrd,
Action Code = Replace
OR
 Facility Code = FAA Lighting (Steel or Wood), Damage Code = Missing, Action Code =
Install
OR
 Facility Code = FAA Lighting (Steel or Wood), Damage Code = No Good/Out of Stdrd,
Action Code = Remove or Replace

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THEN
 Priority Code = B

1.17 Overhead Job Aid for Conductor Clearances

1.17.1 General
Perform conductor clearance checks when conducting detailed inspections. Verify that
clearances meet G.O. 95 and Company design requirements. Check the clearance at the mid-
span of the conductor or where the clearance is at a minimum.
The minimum clearances shown in Table 9. Minimum Conductor-to-Ground Clearance
Calculations and Table 10. Minimum Conductor-to-Conductor (Circuit-to-Circuit) Clearances,
include a conductor sag buffer to account for variations in load and ambient conditions.

1.17.2 Conductor-to-Ground Clearance

Use Table 9. Minimum Conductor-to-Ground Clearance Calculations, to determine if the
existing conductor- to-ground clearance meets the minimum requirements. See Engineering
Drawing 064588, “Graphs for Ground Clearance Reduction Due to Ambient Air Temperature
Rise for Overhead Line Conductors Light Loading Area” (Sheet 1 and Sheet 2), to help
determine conductor sag for changes in ambient temperature and loading.
Conductor-to-ground clearance calculations are based upon G.O. 95 Rule 37 Table 1. If the
appropriate clearance is not met, submit a corrective maintenance notification designated
Priority Code E to correct the clearance infraction. To aid in evaluating the clearance problem,
provide the ambient air temperature and wind condition, and the date and time the clearance
measurement was taken.
If a QCR is uncertain whether current physical conductor-to-ground clearance conforms with
Table 9, a measurement should be taken using one of the methods below and recorded in the
Object list of the patrol.
1. Telescoping measuring disconnect tool (cleaned, tested, and date stamped)
2. Conductor Distance Meter (CDM) or Contour Range Finder
When either one of the options listed above cannot be applied, contact Land Management and
arrange for land surveyors to verify field measurements or review annual LiDAR
measurements.

Table 9. Minimum Conductor-to-Ground Clearance Calculations

60, 70, 115 60, 70, 115 kV 230 kV (over 500 kV (over
Voltage 230 kV 500 kV
kV (over railroad) railroad) railroad)
Minimum
1 1 1 1 1 1
Clearance 30 feet 34 feet 30 feet 34 feet 35 feet 39 feet
Requirement
Notes:
(1) If the measured conductor to ground clearance is less than shown on this table, consult transmission line
engineering to determine the optimal conductor-to-ground clearance for the location in question and whether
remediation is required.

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(2) Clearances must be measured at the low point in the span. Across uneven terrain, this might not be at the
mid-span. See Figure 1. Clearance Checks on Uneven Terrain.

Figure 1. Clearance Checks on Uneven Terrain

1.17.3 Conductor-to-Conductor (Circuit-to-Circuit) Clearances

Use Table 10. Minimum Conductor-to-Conductor (Circuit-to-Circuit) Clearances, to determine
conductor-to-conductor (circuit-to-circuit) clearances for transmission circuits with distribution
underbuilt. For circuits attached on the same structure, measure clearances at mid-span, not
at the support structure.
If there is a distribution pole interset under the transmission circuit, measure the circuit-to-
circuit clearances at the location of the interset pole.
When less than the prescribed separation is suspected, verification of circuit-to-circuit
separation as depicted in Table 10. , will require one of the same techniques listed in 1.17.2 to
accurately measure and record non-compliance of circuit-to-circuit separation.
If circuit-to-circuit distance is less than described in Table 10, create a corrective maintenance
notification with a Priority B (3 Month Tag).
NOTE: It is the SAP gatekeeper’s responsibility to determine if the work can be completed in
the 3 month time frame,” based on risk factors, location, or the need for engineering solutions
that might require changing the impaired clearance into a 1 year notification.

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Table 10. Minimum Conductor-to-Conductor (Circuit-to-Circuit) Clearances

115 kV 115 kV
Voltage 60/70 kV
(Wood) (Non Wood)
Minimum Separation for Circuits
48 inches 84 inches 120 inches
Supported on Same Structure
Minimum Separation to Distribution
96 inches 120 inches 120 inches
on an Interset Pole

1.18 Overhead Job Aid for Automatic Guy Strain Deadends and Splices
1.18.1 General
Guy wires are primarily installed to support mechanical strength in dead-ends, angles and
spans where tensions run higher than adjacent spans. This connector can be subject to
various types of exposure, such as dampness or soil disturbance due to construction or
agriculture activities. Inspect and replace when necessary by means of utilizing a U-shape guy
preform. Existing guy wire splices must be capable of supporting the intended strains.

1.18.2 Required Action

During detailed inspections, the QCR will inspect all guy wire assemblies, looking for any
indication which may suggest the guy splice or automatic guy deadend has internal
deterioration occurring per TD-06537B-001, “Automatic Guy Strand Dead Ends and Splices
Supporting Transmission Facilities”. Create notifications to replace or repair deadends and
splices.
 Coastal environment; visual indications of deterioration, Priority B, 3 months.
 All other areas; visual indications of deterioration, Priority E, 12 months.

Conditions driving preventive maintenance for an automatic deadend/splice installed in

support of transmission facilities include the following:
 Loss of galvanizing on guy wire
 Internal corrosion “bleeding” down the guy wire
 External contact with supporting structure (car/pole)
 Any visible cracking or splitting in the body of the splice or automatic deadend
 Any visible markings indicating the gripping action is slipping outward (jaw marks)
 Visible outer body has lost its protective coating (rust occurring)
 Outer body has visible port holes located at the center of the splice and shows signs of
contaminants embedded within the inner body.
If in doubt of whether the splice can support the intended strains, replace or repair regardless
of the visual condition if warranted.

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1.18.3 Acceptable Repair/Reinforcement Options

Two reinforcement options for guy assemblies are currently allowable. Inspect the existing
guy assembly to ensure all other components are in an acceptable condition and will not pose
a hazard during either option for reinforcement.
1.18.3.1 Option 1
 Take two guy preforms sized for the existing wire size.
 Straighten-out by reshaping to appear as armor rod.
 Position the area of the preformed armor rod which is not formed over the guy
splice and wrap both above and below the splice
 Apply the second set in the same manner as the first set.
Note: Care should be taken to minimize any slack over the splice.

1.18.3.2 Option 2
 Utilize the appropriate size hoist and grips. Leave adequate space between the
grips to install one guy strain insulator and two guy preforms.
 After taking the strain, thus relaxing the guy splice, cut-out the suspect guy splice,
THEN, install preforms and guy strain insulator. Utilize existing work practices for
this application.
 Once installed, shunt-out the guy strain insulator by applying a short piece of guy
wire to connect the ends by means of a U-bolt guy clamp, thereby creating a shunt
by-passing the guy insulator.

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2. Inspections
These inspection procedures are a key element of the preventive maintenance program. The
recommended actions reduce the potential for component failures and facility damage and facilitate a
proactive approach to repairing or replacing identified abnormal components and correcting
circumstances that negatively impact safety, reliability, or asset life.

2.1 Detailed Overhead Inspections

Inspected facilities include overhead assets, rights-of-way, fiber-optic facilities, and vegetation.
The overhead inspections include an external visual evaluation of the overhead facilities. See
Section 5. Maintenance Procedures, for requirements that are part of the Company’s overall
maintenance program and are in addition to the visual inspection items identified in this section
A detailed ground, aerial, or climbing inspection of the asset looks for abnormalities or
circumstances that will negatively impact safety, reliability, or asset life. Individual elements and
components are examined carefully through visual and/or routine diagnostic tests, and each
abnormal condition is graded and/or recorded.
Inspect overhead line facilities in accordance with the provisions in Section 1. General Inspection
and Patrol Procedures. The inspections include detailed visual observations and physical testing
as needed (wood pole hammer/bore test, guy tension, etc.) to identify abnormalities or
circumstances that will negatively impact safety, reliability, or asset life. When performing the
required visual inspection and hammer test on a wood pole, it might be determined that pole
should be further evaluated by a bore test.

2.1.1 Procedures
The primary responsibility of a QCR performing an overhead facility inspection is to examine
the facilities and record any abnormal conditions. This inspection requires an extensive
evaluation (e.g., visual observation, which could include using measuring devices or tools) to
detect any abnormal structural problems or hazards that will adversely impact safety, service
reliability, or asset life, and to evaluate when each identified abnormal condition warrants
maintenance.
Inspections require viewing all sides of the facilities (including line equipment). Evaluating line
equipment requires a visual inspection of:
 disconnect switches
 control cabinets
 switch platforms
 lightning arrestors, etc.
FAA obstruction lighting must be reviewed for obvious defects (e.g., damaged, misaligned,
dirt/debris on solar panels) and must be verified operational. Abnormal conditions that will
adversely impact safety, service reliability, or asset life, and are identified by the inspector as
requiring maintenance before the next inspection cycle, must be graded based on the
inspector’s observation and judgment.
The ET AI App uses the Facility, Damage and Corrective Action Codes listed in Table 3
representing the conditions to consider during overhead inspections. The list of options is not
complete or all-inclusive.

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QCRs must be thoroughly familiar with all of the standards, safety rules, and procedures
associated with the facilities and equipment.
To complete repairs during the inspection, the inspector must be equipped with the
appropriate safety equipment, tools, and materials. (See 8.Appendix B: Equipment, Tools, and
Materials for a reference list of these items.) Guidance on the extent of repairs to be
completed during inspections is provided in Section 1.5.1 Resolving Abnormal Conditions
during Patrol or Inspection.

2.1.2 Substituting Aerial Inspections for Ground Inspections

It may not always be possible to perform ground inspections of lines or line sections due to
access restrictions.
Using an aerial inspection to replace a ground inspection must be authorized by the
transmission line superintendent on a case-by-case basis. If an air inspection is performed, the
next detailed inspection must be a ground inspection.
Exception: If the original condition that prevented a detailed ground inspection still exists, a
detailed aerial inspection is performed, but the QCR must be accompanied by the
transmission line supervisor.
In addition, the reason for the aerial inspection must be recorded and kept on file as part of the
inspection record.

2.1.3 Overhead Inspection Frequency

Inspect overhead transmission facilities per Table 11. Overhead Inspection Frequencies.
Establish schedules such that inspection frequencies meet the SAP maintenance dates.
The schedules indicated in Table 11. do not preclude assigning a more frequent inspection
cycle to a circuit when warranted by sound business reasons. However, increasing inspection
frequency requires appropriate justification and approval by the transmission line
superintendent or designee. Inspections on less frequent cycles than those listed in Table 11.
are not allowed.
For circuits composed of both steel and wood structures, the inspection frequency is based on
the cycle for the majority structure type (i.e., for a circuit with 51% or more steel structures, the
inspection frequency is every 5 years). Light-duty steel poles are considered steel structures
for these circuits. The transmission line maintenance supervisor may modify the inspection
frequency to 2 years, based on local knowledge and exposure of the circuit.
Infrared inspections may be performed in conjunction with overhead inspections, but must not
be considered as, or substituted for, an overhead inspection.

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Table 11. Overhead Inspection Frequencies

Voltage Inspection Frequency
Inspection Type Structure Type
(kV) (years)
Detailed inspection (ground) Steel 3
* Climbing Steel (non-critical) 12 (and as triggered)
500
* Climbing Steel (critical) 3 (and as triggered)
Infrared Steel 5 (and as triggered)
Detailed inspection (ground or aerial) Steel 5
Detailed climbing or aerial lift Steel As triggered
Bay Waters Foundation Inspection Steel 5
230
Detailed inspection (ground or aerial) Wood 2
Climbing or aerial lift Wood As triggered
Infrared Steel or Wood 5 (and as triggered)
Detailed inspection (ground or aerial) Steel 5
Detailed climbing or aerial lift Steel As triggered
Bay Waters Foundation Inspection Steel 5
115
Detailed inspection (ground or aerial) Wood 2
Climbing or aerial lift Wood As triggered
Infrared Steel or Wood 5 (and as triggered)
Detailed inspection (ground or aerial) Steel 5
Detailed climbing or aerial lift Steel As triggered
Bay Waters Foundation Inspection Steel 5
60/70
Detailed inspection (ground or aerial) Wood 2
Climbing or aerial lift Wood As triggered
Infrared Steel or Wood 5 (and as triggered)
* Note: Detailed 500 KV climbing inspections must include information about guy tensions.

Triggers are specific conditions that require follow-up inspections and/or maintenance
scheduled by the supervisor, independent of the routine schedule.
The following triggers can be applied to one unit of inspection or many units, either grouped or
spread over a line section/area:
 Component defects identified by inspection
 Component failure (including failure in like components)
 Components proven defective by testing
 Wire/structure strike
 Burned area or high fire hazard
 Failures caused by natural disaster or storm
 Third-party observations and complaints
 Observed third-party development or construction conflict
 Marginal capability components of a re-rated line section
 Known, recurring conditions that jeopardize line integrity
 Suspected vegetation clearances or concerns about fast growth of vegetation

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2.1.4 Inspection Documentation

ETPM forms TD-1001M-F01, “Transmission Line Inspection/Patrol Datasheet – Typical,” and
TD-1001M-F05, “Object List - Typical” provide adequate, consistent, and auditable inspection
records, and must be used to document the inspection.
The inspection documentation process, as described below, is the responsibility of the
transmission supervisor, QCR, and the clerk.
1. Before starting an inspection, the QCR must obtain the following documents for the
inspection area:
 TD-1001M-F01, “Transmission Line Inspection/Patrol Datasheet – Typical,”
 TD-1001M-F05, “Object List - Typical”
 An SAP report of all open notifications for the lines to be inspected, with enough
information provided to understand the nature of the problems.
2. Field reviews must be performed on any pending (open) notifications to address the
following issues:
 Did the condition of the facilities deteriorate faster than expected?
 Has the work already been completed?
 Is the required completion date still appropriate?

3. Use the ETPM Form TD-1001M-F01, “Transmission Line Inspection/Patrol Datasheet –

Typical,” to document any new abnormalities and minor or incidental work corrected at
the time of inspection. Document the required information to support the creation of
individual notifications detailing each abnormality as it was identified during the
inspection. For work requiring engineering and/or estimating, attaching a copy of the
inspection map to the request is recommended. If FAA obstruction lighting is damaged
or inoperable, refer to TD-1001P-03, “Obstruction Lighting Failure Notification Process”
for procedure on notifying Federal Aviation Administration (FAA).
4. The applicable transmission line maintenance supervisor (or relief) must review and
initial the QCR’s inspection logs.
 The clerk will input the notification into SAP as a staged notification and must
record the corresponding notification number for each entry in the appropriate
column on the ETPM Form TD-1001M-F01, “Transmission Line Inspection/Patrol
Datasheet – Typical,” .
 The applicable transmission line maintenance supervisor will review for approval
and release the staged SAP notifications.
5. Inspection information must be entered into the SAP database and reviewed for
approval and release the staged SAP notifications as soon as practical (not to exceed
20 business days from the end of the inspection and before January 31 of the following
year). This ensures that SAP notifications will be established in time to facilitate the
proper planning, scheduling, and work to correct abnormal conditions by the due dates.
6. If a piece of equipment has been identified as damaged or inoperative, the
transmission supervisor or designee must notify the GCC of the equipment condition.
 GCC personnel enter the equipment into the Transmission Operations Tracking &
Logging (TOTL).and assign a Critical Operating Equipment (COE) personal
identification number (PIN).

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 The QCR must add the COE PIN to the notification’s short text field in SAP and
notify the GCC of the notification number associated with the PIN.
Inspection/patrol logs and notification forms are listed in 8.Appendix C: Links to Forms and
Flowcharts and are available in the Technical Information Library on the Company Intranet.

2.2 Climbing Inspections (Overhead)

A climbing inspection is a detailed, supporting-structure-based observation of the facilities installed
to determine if there are any abnormal or hazardous conditions that adversely impact safety,
service reliability, or asset life, and to evaluate when each identified abnormal condition warrants
maintenance.
Perform routine, time-based 500 kV climbing inspections, focusing primarily on structural
components, on all 500 kV structures, in accordance with the inspection frequencies listed in
Section 2.1.3 Overhead Inspection Frequency. Climbing inspections extend from the ground line
to the top of the tower. In addition to the documentation and recordkeeping requirements
associated with other routine inspections, forward the results of 500 kV climbing inspections to the
Transmission Tower Davis Headquarters for record retention.
Climbing inspections also might be required for specific structures or components to assess a
condition that could not be adequately assessed when identified during a ground or aerial
inspection or patrol. Such conditions trigger a follow-up inspection to assign the proper Priority
Code. In some cases, this requires a climbing inspection.
See Section 0 All non-routine patrols will be completed under a Priority B – 3 Month tag. This
will allow for sufficient timekeeping, receipt of miscellaneous charges (e.g., helicopter, natural
causes (fire, snow)) and collection of all necessary paperwork to complete the tag.
Overhead Non-Routine Patrol for triggers that might require a follow-up climbing inspection, and
Error! Reference source not found.Table 2, Inspection Best-View Position, for the best vantage
points for inspections of specific items.
All inspection forms must be reviewed by the local tower supervisor or designee prior to being filed
as specified on TD-1001M-F03, “500kV Climbing Inspection Form and Tower Diagrams” and TD-
1001M-F04, “Steel Structure Detailed Climbing Inspection (Non-500kV Structures)”. TD1001M-
JA02, “Detailed Climbing Inspection Job Aid” and TD-1001M-JA04, “Identifying Levels of
Corrosion and Foundation Condition on Transmission Line Structures and Supports” should be
referenced for additional instructions to complete the forms.

2.3 Underground Inspections

2.3.1 Underground Inspection Frequencies
See Table 12. Underground Inspection Frequencies for the underground inspection
frequencies. Use the underground transmission inspection sheets and forms TD-1001M-F06
through TD-1001M-F11, depending on the inspection performed, to document test results and
any abnormal conditions encountered in the field.
2.3.1.1 Detailed Inspection Frequencies
 XLPE - Perform detailed inspections once every 2 calendar years in accordance
with Section 2.3.2 Detailed Inspections for XLPE Circuits.
 Pipe-type cable – Perform detailed inspections annually in accordance with Section
2.3.3 Detailed Inspections for Pipe-Type Circuits.

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 Submarine cable - Perform detailed inspections once every calendar year for the
first 5 years of service in accordance with Section 2.3.2 Detailed Inspections for
XLPE Circuits. After 5 years, adjust to every 2 calendar years if warranted.
 Land portion of the submarine cable – Perform same detailed inspection as for
XLPE cable.
2.3.1.2 Routine Inspection Frequencies
 XLPE - Perform routine inspections every 3 months in accordance with Section
2.3.4 Routine Inspections for XLPE Circuits.
 Pipe-type cable – Perform routine inspections once each month in accordance with
Section 2.3.5 Routine Inspections for Pipe-Type Circuits.
 Submarine cable - Perform routine inspections every 3 months in accordance with
Section 2.3.4 Routine Inspections for XLPE Circuits.
 Land portion of the submarine cable – Perform same routine inspection as for
XLPE cable.
2.3.1.3 Infrared (IR) Inspection
Perform IR inspections of underground riser terminations once every 2 years in accordance
with Section 2.4.2 Infrared (IR) Inspections - Underground.
Table 12. Underground Inspection Frequencies
Voltage Inspection Inspection Frequency
Cable Type
(kv) Type (years)

Detailed Pipe-type Once every calendar year

Detailed XLPE Once every 2 calendar years

Routine Pipe-type Once each month

All
Routine XLPE Once every 3 months
Infrared Pipe-type Every 2 calendar years on riser terminations

Infrared XLPE Every 2 calendar years on riser terminations

Once every for first 5 years, then adjust to every
Detailed Submarine
2 calendar years, if warranted

Routine Submarine Once every 3 months

Marine
Submarine Various (under development)
Monitoring

2.3.1.4 Substitution of Inspections

 It is permissible to substitute a detailed inspection of XLPE or pipe-type cable
circuits for a routine inspection.
 It is not permissible to substitute routine inspections of either XLPE or pipe-type
cable circuits for detailed inspections.
 It is not permissible to substitute an infrared inspection for either a detailed or
routine inspection. It is also not permissible to substitute a detailed or routine
inspection for an infrared inspection.

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2.3.2 Detailed Inspections for XLPE Circuits

Perform detailed inspections on XLPE circuits and components as described below.
If a component is found to be suspect during an inspection, take proper action to correct the
problem, assign a specific date to correct the problem, or follow up with additional inspections
or testing of suspect components according to the established Priority Codes.
Note: The QCR must fill out a notification with the inspection form.
Detailed inspections include, but are not limited to, the following items:
 Cable racking - Inspect for corrosion or breakage.
 Cable clamps - Inspect for corrosion, breakage or looseness.
 Foundations - Inspect for failing, deteriorating, or damaged concrete.
 Grounds - Inspect for loose, missing, or broken connections.
 Link boxes - Inspect for deterioration, damage, missing bonding or ground wires. If
suspect Sheath Voltage Limiters (SVLs) (i.e., conductor temperature increase of cable
section), open box and test SVLs.
 Hardware - Inspect for broken or deteriorating components.
 Manholes and vaults - Inspect for failing, deteriorating, or damaged concrete; water
leaks; cracked and/or damaged manhole covers; and deteriorating or damaged circuit
markings.
 Splice covering - Inspect for damage and deterioration.
 Terminals - Inspect for oil or gas leaks, broken porcelain skirts, and insulator coating.
Inspect coatings for discoloration, peeling, contamination, and aging.
 Structures - Inspect for missing, deteriorating, or damaged circuit markings or steel
members, deteriorating protective coating, and missing or loose bolts. For concrete
footings, inspect for failing, deteriorating, or damaged concrete.
 Communication cables - Inspect communication cables (hard wire or fiber) for damage
where present in transmission manholes
 Rights-of-way - Inspect for encroachments and installation of other facilities that might
have been installed without proper authority and that interfere with clear and passable
access to the terminal structures and manholes.
 Access roads - Inspect access roads for damage or erosion.

2.3.3 Detailed Inspections for Pipe-Type Circuits

Perform detailed inspections on pipe-type circuits and components as described below.
If a component is found to be suspect during an inspection, take proper action to correct the
problem, assign a specific date to correct the problem, or follow up with additional inspections
or testing of suspect components according to the established Priority Codes.
Note: The QCR must fill out a notification with the inspection form.
Detailed inspections include, but are not limited to, the following items:
 Ducts and pipes - Inspect for damage to pipe coatings in manholes and terminal risers,
corrosion of exposed metallic pipes, and system leaks.

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 Pipe-to-soil readings at manholes and terminal risers – For pipe-to-soil readings below
0.850 V, note and contact a transmission engineer and/or transmission specialist. Also,
refer to the TD-2355M, “Electric Maintenance and Construction Manual”.
 Pumping plants - Test and/or calibrate plant alarms, pump plant controls, relief valves,
and/or other components per the manufacturer’s recommendations. Perform trip
checks. Inspect for oil leaks. Contain leaks and/or repair them. If a leak is contained
but cannot be repaired at the time, schedule it for repair. Refer to the pumping plant
manufacturer’s operation manual. Follow Inspection Procedures TD-1001P-06 “Electric
Underground Transmission Pump Plant Inspections for San Mateo-Martin 230kV High
Pressure Fluid-Filled (HPFF)”, TD-1001P-07 “Electric Underground Transmission
Pump Plant Inspections for HZ-1 and HZ-2 230kV, and High Pressure, Fluid Filled
(HPFF)”, TD-1001P-08 “Electric Underground Transmission Pump Plant Inspections
for Figarden Tap #1 and #2 230kV (HPFF)”, TD-1001P-09 “Fulton-Lakeville #1A and
#1B (Oakmont) Pump Plant Test Procedures”. Documents for Geyser #9-Lakeville #2
are under development.
 Cable pressures - Calibrate and/or test alarms and pressure switches. Oil-filled cable
pressures can vary from line to line. Refer to the manufacturer’s operation manual. For
gas-filled cables, low-low pressure alarms and trip switches typically are set at 140
psig. The low alarm is set at 185 psig.
 Isolation surge protectors (ISP) - Use pre-packaged diagnostic software to test all
units. (The reference voltage should be 0.5 V to 2.25 V.)
 Foundations - Inspect for failing, deteriorating, or damaged concrete.
 Grounds - Inspect for loose, missing, or broken connections.
 Hardware - Inspect for broken or deteriorating components.
 Manholes and vaults - Inspect for failing, deteriorating, or damaged concrete; water
leaks; cracked and/or damaged manhole covers; and deteriorating or damaged circuit
markings.
 Splice casings - Inspect for oil or gas leaks, and the condition of cathodic protection
coating.
 Terminals - Inspect for oil or gas leaks, broken porcelain skirts, and insulator coating.
Inspect coatings for discoloration, peeling, contamination, and aging.
 Structures - Inspect for missing, deteriorating, or damaged circuit markings or steel
members, deteriorating protective coating, and missing or loose bolts. For concrete
footings, inspect for failing, deteriorating, or damaged concrete.
 Communication cables - Inspect communication cables (hard wire or fiber) for damage
where present in transmission manholes.
 Rights-of-way - Inspect for encroachments and installation of other facilities that might
have been installed without proper authority and that interfere with clear and passable
access to the terminal structures and manholes.
 Access roads - Inspect access roads for damage or erosion.

2.3.4 Routine Inspections for XLPE Circuits

Perform routine inspections and operational readings on XLPE circuits and components as
described below.

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If, during the inspection, a component is found to be suspect, take proper action to correct the
problem or assign a specific date to correct the problem according to the established Priority
Codes.
Note: The QCR must fill out a notification form with the inspection form.
 Terminals - Inspect for oil leaks, broken porcelain skirts, and damaged insulator
coating. Inspect insulator and insulator coating for discoloration, peeling, and simple
aging. Check for leaks at terminals. Contain the leaks and/or repair them. If a leak is
contained but cannot be repaired at the time, schedule repairs as soon as possible.
 Structures - Inspect for missing, deteriorating, or damaged circuit markings or steel
members, deteriorating protective coating, and missing or loose bolts. For concrete
footings, inspect for failing, deteriorating, or damaged concrete.
 Rights-of-way - Inspect for encroachments and installation of other facilities that might
have been installed without proper authority and that interfere with clear and passable
access to the terminal structures and manholes.
 Access roads - Inspect access roads for damage or erosion.

2.3.5 Routine Inspections for Pipe-Type Circuits

Perform routine inspections and operational readings once a month for all underground pipe-
type transmission circuits and components listed below.
If during the inspection, a component is found to be suspect, take proper action to correct the
problem or assign a specific date to correct the problem according to the established Priority
Codes.
Note: The QCR must fill out a notification form with the inspection form.
Routine inspections include, but are not limited to, the following items:
 Terminals - Inspect for oil or gas leaks, broken porcelain skirts, and damaged insulator
coating. Inspect insulator and insulator coating for discoloration, peeling and aging.
Check for leaks at terminals and pressure cabinet instruments. Contain the leaks
and/or repair them. If a leak is contained but cannot be repaired at the time, schedule
repairs as soon as possible.
 Pumping plants - Inspect for oil leaks. Contain the leaks and/or repair them. If a leak is
contained but cannot be repaired at the time, schedule repairs as soon as possible.
 Fluid or gas leaks - Check for leaks at terminals and pressure cabinet instruments.
Contain the leaks and/or repair them. If a leak is contained but cannot be repaired at
the time, schedule repairs as soon as possible.
 Isolator surge protector (ISP) - Check the red indicator light (red light indicates unit
malfunction) and the reference voltage. (The reference voltage should be 0.5 V to 2.5
V.)
 Rectifiers - Inspect for direct current (dc) output. On circuits with rectifiers, the dc
output can vary, depending on the line being protected. If there is no dc output, check
for alternating current (ac) voltage or a blown fuse.
 Rights-of-way - Inspect for encroachments and installation of other facilities that might
have been installed without proper authority and that interfere with clear and passable
access to the terminal structures and manholes.
 Access roads - Inspect access roads for damage or erosion.
Record operational readings for the following items:

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 Pumping plant oil and nitrogen pressures - Oil pressures can vary from line to line.
Refer to the manufacturer’s operations manual. Maintain the nitrogen pressure
between 3 and 10 psig.
 Pumping plant oil volumes - Oil volume can vary from line to line. Refer to the
manufacturer’s operations manual for proper volumes.
 Cable nitrogen and oil pressures - Maintain gas at desirable pressures between 195
and 225 psig, not to exceed 250 psig. Oil pressures can vary from line to line. Refer to
the manufacturer’s operations manual for correct pressures.
 Cathodic protection reference voltages - The reference voltage should be 0.5 V to
2.5 V.

2.3.6 Detailed Inspections for Submarine Circuits

Submarine circuits are comprised of three interconnected, but different, subcomponents:
subsea cable laid under water, transition point manholes, and land-based XLPE-cabling. This
section pertains to detailed inspection of the underwater portion and transition points.
If a component is found to be suspect during an inspection, take proper action to correct the
problem, or follow the corrective maintenance notification creation process and assign a
specific date to correct the problem.
Detailed inspections include, but are not limited to, the following items:
Subsea Portion – Submarine cabling is not subject to detailed physical inspections on a
recurring basis. Real-time monitoring of submarine cable performance is provided via a
Distributed Temperature Sensing (DTS) system station near the terminals.
 DTS – Record temperatures and cable ratings as shown on the display. If DTS unit is
inoperable, arrange for repair by vendor.
 Cable alignment – Periodic survey of submarine cable alignments to record any
movement of cables. Periodic diver inspections of cables at transition bore exits (cable
landings) and locations of abnormalities as indicated by alignment surveys.
In Transition Point Manholes:
 Cable racking - Inspect for corrosion or breakage.
 Racking anodes - Inspect for depletion and loss of connections
 Cable clamps - Inspect for corrosion, breakage or looseness.
 Foundations - Inspect for failing, deteriorating, or damaged concrete.
 Grounds - Inspect for loose, missing, or broken connections.
 Link boxes - Inspect for deterioration, damage, missing bonding or ground wires. If
suspect SVLs (i.e., conductor temperature increase of cable section), open box and
test SVLs.
 Hardware - Inspect for broken or deteriorating components.
 Manholes structure - Inspect for failing, deteriorating, or damaged concrete; water
leaks from link seals; cracked and/or damaged manhole covers; and deteriorating or
damaged circuit markings.
 Transition splice - Inspect for damage, deterioration or movement out of position.
 Submarine cable anchors - Inspect for missing, deteriorating, or damaged cable armor,
deteriorating anchor racking and anchor bolts.

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 Rights-of-way - Inspect for encroachments and installation of other facilities that might
have been installed without proper authority and that interfere with clear and passable
access to the terminal structures and manholes.
 Access roads - Inspect access roads for damage or erosion.

Land Cable Portion - See Section 2.3.2 Detailed Inspections for XLPE Circuits. Land cable
items inside of transition vaults (i.e., racking grounds and link boxes) should be inspected at
the same time as the submarine cable inspection.

2.3.7 Routine Inspections for Submarine Circuits

Perform routine inspections and operational readings on submarine circuits and components
as described below.
If a component is found to be suspect during an inspection, take proper action to correct the
problem, or follow the corrective maintenance notification creation process and assign a
specific date to correct the problem.
Subsea Portion – Submarine cabling is not subject to routine physical inspections on a
recurring basis. Real-time monitoring of submarine cable performance is provided via a DTS
system station near the terminals.
 DTS – Record temperature and cable ratings as shown on the display. If DTS unit is
inoperable, arrange for repair by vendor.

Land Cable Portion - See Section 2.3.4 Routine Inspections for XLPE Circuits. Land cable
items inside of transition vaults should be inspected at the same time as the submarine cable
inspection.

2.4 Infrared (IR) Inspections

IR inspection is an effective tool in a preventive maintenance program. IR inspection reduces the
potential for component failures and facility damage and facilitates a proactive approach to
identifying abnormal components for repair/or replacement. See Section 4. Infrared (IR) Inspection
Procedures, for the procedures and requirements.

2.4.1 Overhead
IR inspections are performed as required per TD-1004P-04, “Conductor Rerate Process for
Overhead Transmission Circuits” or as triggered.
Typically, infrared inspections are performed on overhead transmission circuits on a 5 year
cycle, with approximately 20% of the lines scheduled for an infrared inspection each year.
However, for circuits with critical operational impact, maintenance plans must include periodic
IR inspections, if recommended by the local transmission line maintenance supervisor. Local
transmission line maintenance supervisors should also consider adding lines to the annual
summer readiness IR patrol in their area for conditions such as listed below:
 High concentration of bolted connectors on dissimilar conductors (copper to
aluminum).
 Line averages 1 sleeve failure every 3 to 5 years.

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 Radial line where previous splices/sleeves have been replaced as normal maintenance
with signs of deterioration.
 Line has experienced at least 2 or more tree contacts annually (high fault current),
which could have caused stresses on sleeves/connectors.
 Type of terrain and vegetation on the path of the line circuit.
 Age of line exceeds (70+ years) with original insulators, mechanical connectors, and
hot end hardware showing signs of deterioration.

2.4.2 Underground
Perform IR inspections on underground transmission circuits once every 2 years. See Section
4. Infrared (IR) Inspection Procedures, for IR inspection procedures and requirements.

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3. Patrols
Patrol procedures are a key element of the preventive maintenance program. The recommended
actions reduce the potential for component failures and facility damage and facilitate a proactive
approach to repairing or replacing identified, abnormal components.
A patrol supplements the detailed facility inspection. All overhead transmission line facilities are
patrolled annually. Patrol schedules are measured in terms of calendar years. A detailed facility
inspection may be considered as a patrol, but a patrol cannot be considered as, or substituted for, a
detailed inspection.
An overhead patrol may be performed by walking, driving, or flying (helicopter only). All patrols must
be conducted in a manner that will ensure the identification of the typical problems listed in Section
3.1.1 Typical Electric Overhead Transmission Problems. Proper documentation and superintendent
approval are required to substitute an air patrol for a scheduled ground patrol.

3.1 Procedures
Before performing any patrol, the QCR must obtain from the SAP database all the pending
notifications for the facilities to be patrolled. This prevents duplicating maintenance notifications in
SAP.
The QCR’s primary responsibility when conducting an overhead electric facility patrol is to observe
the electric facilities visually, looking for obvious structural problems or hazards without using
measuring devices, tools, or diagnostic tests, and to record that the facilities have been patrolled.
Abnormal conditions that, in the opinion of the QCR, warrant maintenance before the next
scheduled patrol or inspection, must be identified, assigned a Priority Code, and recorded. The
following list gives examples of some typical problems, but is not complete or all-inclusive:

3.1.1 Typical Electric Overhead Transmission Problems

 Inadequate tree clearances
 Damaged or broken conductor
 Broken or leaning poles
 Missing or bent tower members
 Broken guys
 Broken crossarms/framing
 Broken or flashed insulators
 Inadequate conductor clearances
 Damaged line equipment
 Rights-of-way encroachments
 Bent, broken, or missing dampers
 Defective FAA obstruction lights (e.g., inoperable, damaged, misaligned) or dirt/debris
on the solar panels
Assess and document any abnormal condition (other than those already documented in SAP)
identified by the patrol in accordance with the requirements in Section 1. General Inspection
and Patrol Procedures.
If a condition cannot be assessed properly during a patrol, a follow-up inspection must be
conducted to assess the condition and assign a Priority Code.

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During the patrol, review pending notifications to:

 Confirm conditions still exist
 Determine if the work has already been completed

3.2 Patrol Documentation and Actions

Adequate, auditable records (inspection/patrol datasheets) must be kept to document all the
facilities patrolled. Maintain the inspection/patrol datasheets in the same manner as specified for
detailed inspections. Use SAP to schedule and track all patrols before the year they will be
performed.
The patrol documentation process, as described below, is the responsibility of the transmission
supervisor, QCR, and the clerk.
Before starting a patrol, the QCR must obtain the following documents for the patrol area:
 TD-1001M-F01, “Transmission Line Inspection/Patrol Datasheet – Typical,”
 An SAP report of all open notifications for the lines to be inspected, with enough
information provided to understand the nature of the problems.

3.2.1 Patrol Recordkeeping and Closeout

Use the ETPM form TD-1001M-F01, “Transmission Line Inspection/Patrol Datasheet –
Typical,” to document any new abnormalities and minor or incidental work corrected at the
time of patrol. Document the required information in the inspection/patrol log to support
individual notifications created in the ET AI App, detailing each abnormality as it was identified
during the patrol.
Inspection/patrol log forms are listed in 8.Appendix C: Links to Forms and Flowcharts, and are
available in the Technical Information Library on the Company Intranet.
The QCR must fill out completely each required field in the inspection/patrol log heading and
record each abnormality encountered during the patrol. Use inspection/patrol logs in
conjunction with the notifications in the ET AI App to capture the information needed to
document the necessary maintenance work or action(s).
The applicable supervisor (or a designee) must review and initial the QCR’s patrol logs before
the information is entered in the SAP database.
It is recommended to check the SAP database to ensure that duplicate notification data is not
entered. For work requiring engineering and/or estimating, attaching a copy of the inspection
map to the request is recommended.
Patrol information must be entered into the SAP database and reviewed for approval and
release any SAP notifications as soon as practical (not to exceed 20 business days from the
end of the patrol and before January 31 of the following year). This ensures that SAP
notifications will be established in time to facilitate the proper planning, scheduling, and work
to correct abnormal conditions by the due dates.

3.2.2 Reporting Inoperative Equipment

If a piece of equipment has been identified as damaged or inoperative, the supervisor or
designee must notify the GCC of the equipment condition.
GCC personnel enter the equipment into the Transmission Operations Tracking & Logging
(TOTL) and assign a Critical Operating Equipment (COE) personal identification number (PIN).

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The QCR must add the COE PIN to the notification’s short text field in SAP and notify the GCC
of the notification number associated with the PIN.

3.3 Non-Routine Patrol

All non-routine patrols will be completed under a Priority B – 3 Month tag. This will allow for
sufficient timekeeping, receipt of miscellaneous charges (e.g., helicopter, natural causes (fire,
snow)) and collection of all necessary paperwork to complete the tag.

3.3.1 Overhead Non-Routine Patrol

Specific conditions require follow-up inspections scheduled by the supervisor, independent of
the routine schedule.
The following are examples of situations that could prompt a non-routine patrol:
 Component defects identified from a less-than-ideal vantage point.
 Component failure (failure in like components) or components proven defective by
testing or documented on a Form 62-0113, “Material Problem Report” (MPR).
 Wire/structure strike.
 Burned area or high fire hazard.
 Severe or prolonged storms or flood areas
 Failures caused by natural disaster or storm.
 Third-party observations and complaints.
 Observed third-party development or construction conflict.
 Marginal capability components of a re-rated line section.
 Known, recurring conditions that jeopardize line integrity or reliability performance.
 Suspected vegetation clearances less than required, less than legal vegetation
clearances, or concerns about the fast-growth of vegetation.
 For all 60kV, 70kV and 115kV momentary outages, the line will be patrolled as soon as
practical, but no later than the next business day. Examples:
(a) If the momentary outage occurs on Tuesday, the line will be patrolled as soon as practical,
but no later than Wednesday.
(b) If the momentary outage occurs on Friday and cannot be patrolled on that day, then the
patrol will be conducted on Monday (or the next scheduled regular business day).
 For all 230kV and 500kV momentary outages, the line will be patrolled as soon as
practical, but no later than the next calendar day. Examples:
(a) If a momentary outage occurs early in the morning, and responsible protection engineer
confirms target information and a location, then the line will be patrolled on the same day.
(b) If the momentary outage occurs late in the afternoon or early in the evening, and it is not
practical to attempt a patrol immediately due to darkness, then the line will be patrolled the
next day. This requirement is in effect regardless of whether or not the next day is a regular
work day.

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3.3.2 Underground Non-Routine Patrol

Specific conditions require follow-up inspections scheduled by the supervisor, independent of
the routine schedule.
The following are examples of situations that could prompt a non-routine patrol:
 Component failure (like components) or components proven defective by testing
 Failures caused by natural disaster or storm
 Third-party observations and complaints
 Observed third-party development or construction conflict
 Known, recurring conditions that jeopardize line integrity or reliability performance
 Directional drilling or trenching in the vicinity of an underground transmission line not
identified by Underground Service Alert (USA) locating and marking
 Encroachment of the underground easement by third parties affecting access to
underground transmission line for inspection or repairs
 Public events with extremely large attendance.

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4. Infrared (IR) Inspection Procedures

IR inspection procedures are a key element of the preventive maintenance program. The
recommended maintenance priorities reduce the potential for component failures and facility damage
and facilitate a proactive approach to repairing or replacing identified abnormal components.
Perform IR inspections when required by Utility Procedure TD-1004P-04, “Conductor Rerate Process
for Overhead Transmission Circuits,” or as triggered.
In addition, lines that have exceeded their emergency ratings for 30 minutes or more must be
IR-inspected for possible component damage. Schedule this inspection as soon as possible or when
conditions allow (line loading, weather, etc.).
It is the responsibility of the GCC to notify the local electric transmission supervisor that a condition as
specified above has occurred.
Additional IR inspections might be required as triggered per Section 3.3 Non-Routine Patrol.

4.1 Detailed IR Procedures

Electric transmission system inspections and preventive maintenance programs use IR
imaging and temperature-measuring systems to identify faulty components and initiate repairs
or replacement proactively.
Based on industry specifications, connectors should experience lower operating temperatures
than their respective conductors. This means that any time the temperature of a connector is
greater than the temperature of its respective conductor, a higher-resistance connection exists
and a failure can be expected, but not precisely predicted. It is probable that degradation will
occur faster with an increase in load or temperature.
Conductor manufacturers recommend a usual maximum operating temperature for tensioned,
bare conductor of 185F.
Conductor manufacturers recommend the following maximum operating temperatures for
insulated conductors:
 167F for high-molecular-weight polyethylene (HMWPE).
 194F for cross-linked polyethylene (XLPE).
 194F for ethylene-propylene rubber (EPR).
With insulated conductor systems, the temperature measured at the surface of an insulated
conductor or component could be between 20% and 50% of the actual temperature of the
targeted conductor or component (e.g., if the actual temperature of the component is 212ºF,
the measured temperature could be between 68ºF and 122ºF, respectively).
IR imaging systems detect and record all of the heat being radiated in their fields of view. IR
cameras use an image-scanning technique to identify heat radiated from a target and its
background. IR imaging systems capture and store the heat images pictorially for immediate
or future evaluation. By using IR imaging systems, the operator can pinpoint the precise
location of the hottest spot on the target being observed.
The recommended maintenance is based on the measured operating temperature of both the
target and its respective connectors or conductors, the temperature differentials between the

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target and its respective, adjacent components, or thermal image showing component hot, as
well as the operational risk associated with each.

4.1.1 Equipment
Video-imaging equipment used for IR inspections must meet the following minimum
specifications:
 Image storage – Equipment must have the ability to store images for future analysis
 Lens interchangeability – The IR camera must have lens interchangeability, or
personnel must have access to a camera with lens interchangeability, to enable
inspections at varying distance to the object to be inspected.
 Wave length – The IR system must be “Long Wave,” responding to wave lengths of 8
to 14 microns.
 Camera lens – A 3x to 10x telescopic lens is required for accurate IR measurements at
a safe distance.
 Palette – IR system must have color palette with unique and easily distinguishable
colors for over-temperature conditions in order to locate hot spots and to verify that the
image is not saturated. A gray-scale palette with a color-distinguishing minimum and
maximum saturation threshold is preferred.
 Camera mount – For helicopter IR inspections, a gimbal or gyro-stabilized remote-
controlled camera mount attached to the exterior of helicopter is preferred to dampen
vibration.
 Calibration – IR cameras that provide temperature readings must have been factory-
calibrated within 1 year before the patrol. IR cameras or systems that do not provide
temperature readings do not require calibration within 1 year before the patrol. Hand
held IR cameras used for overhead only must have been factory-calibrated within 2
years (due to the minimal use of camera).
 Recording media –The system must be capable of recording IR or color video of the
entire inspection scan for special requests, along with color and IR still photos of each
anomaly found.
 Audio input - For helicopter IR inspections, the system must be capable of recording
audio input from the helicopter intercommunication system.
Systems used for aerial (helicopter) IR inspections by contractors must be used in accordance
with the manufacturer’s requirements. The equipment used for aerial IR inspections must
meet all requirements above.

4.1.2 Setting Up the IR Camera

Establishing the proper IR-imaging system setup parameters for emissivity and background
temperature is critical to obtaining accurate measurements with IR cameras. The other
system-setup parameters are used primarily to record and assist initial or future evaluations of
heat radiated from a target and its background.
Setting the emissivity value at 1.0 eliminates the need to set the background temperature. The
target, in this case, is considered to be a blackbody, totally reflective and non-transmissive.
With highly emissive targets, the actual reflected energy is so small with respect to the emitted
energy that the temperature measurement is well within reason for predictive maintenance
applications.

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As the emissivity value of the target decreases, the influence of background radiation
increases, and consequently, so does the potential for errors based on background
temperature settings. If the emissivity value is set at less than 1.0 and the background
temperature setting is adjusted inaccurately, the resulting temperature measurement of the
target could have more error than it would if the emissivity value were set at 1.0.
For example, with an emissivity setting less than 1.0, if the background temperature setting is
higher than the actual background temperature, the target’s temperature measurement will be
less than it should be. If the background temperature setting is lower than the actual
background temperature, then the target’s temperature measurement will be higher than it
should be. The measurement deviation compounds as the emissivity setting decreases from
1.0.
Setting the emissivity value at 1.0 eliminates the need to determine exact emissivity and
background temperature values, simplifies the system operation, and results in reasonably
accurate measurements. For example, when IR measurements are taken on overhead
systems where the ceiling (sky) is unlimited, an accurate background temperature is nearly
impossible to determine. Furthermore, most targets have dark surfaces and therefore will have
emittance values very close to 1.0.

4.1.3 Infrared (IR) Scanning Technique

4.1.3.1 Overhead
1. Center the targeted component in the viewer or sight of the IR scanning device and
observe the temperature(s) measured.
2. Scan 1 to 2 feet of the conductor or cable entering and/or leaving the targeted
image and observe the temperature(s) measured.
3. Center the respective, adjacent components in the viewer or sight of the IR
scanning device and observe the temperature(s) measured.
4. Repeat Step 2 for each respective, adjacent component.
5. IF the temperature of the targeted component is greater than those listed in
Table 13. Determining Maintenance Priorities, OR shows hot with IR system that
does not provide temperature readings,
THEN record the information requested in Section 4.3 IR Inspection Documentation, using the
TD-1001M-F15, “Transmission Line Infrared Data Sheet.” Attach the datasheet to the
notification created for abnormal finding.
4.1.3.2 Underground – Cable Terminals
1. Center the targeted component (terminal—composite or porcelain) in the viewer or
sight of the IR scanning device and observe the temperature(s) measured. See
Figure 2. Pipe-Type and XLPE Terminals.
2. Center the respective, adjacent components (terminal ferrule or aerial connector
stub) in the viewer or sight of the IR scanning device and observe the
temperature(s) measured.
3. Scan 1 to 2 feet of the conductor connected to the terminal ferrule or aerial
connector stub and observe the temperature(s) measured.
4. Repeat Step 2 for each respective, adjacent component.

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5. IF the temperature of the targeted component is greater than those listed in

Table 13. Determining Maintenance Priorities, OR shows hot with IR system that
does not provide temperature readings,
THEN record the information requested in Section 4.3 IR Inspection Documentation, using the
TD-1001M-F15, “Transmission Line Infrared Data Sheet.” Attach the datasheet to the
notification created for abnormal finding.

Figure 2. Pipe-Type and XLPE Terminals

4.1.4 Determining the Maintenance Priority

To assess and prioritize the relative severity of the conditions found during the IR inspection,
as based on the measured temperatures and/or temperature rise, refer to Table 13.
Determining Maintenance Priorities. (If IR system does not provide temperature readings, and
there are no obvious visual signs of deterioration, then make a Priority B tag and complete as
soon as possible.)

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4.1.5 Determining Maintenance Priorities

Table 13. Determining Maintenance Priorities

Transmission Facilities Temperature Priority/Remarks

Differential (T)
Priority A: Notify supervisor and repair, replace,
Overhead & Underground >100F
or make component safe immediately.
Direct heat
(See Notes) Priority B: Repair or replace component within
25 F to 99F
3 months.

Underground
Notify supervisor. Contact Underground
Indirect heat 20F and over
Engineering to determine mitigation
(See Notes)

Notes:
1. If excessively high operating temperatures (>100F) are found, or obvious physical damage is
observed, immediate action must be taken (Priority A).
2. B priority tags should be given a high priority. B tags should be corrected as soon as possible,
preferably within 60 days, but not to exceed a period of 3 months.
3. Underground – Upon completion of repair or replacement, perform another IR inspection to verify
that the abnormal condition was corrected and is operating under normal condition.
4. Temperature taken at underground cable terminals illustrated in Figure 2. Pipe-Type and XLPE
Terminals.: Location 1 is an indirect reading; Location 2 is a direct reading.

4.2 IR Inspection Requirements

It is generally necessary for lines, or segments of lines, to be loaded to 40% or greater of the
operating ratings in order to perform a meaningful IR inspection. IR inspections are less likely to
yield useful results if the lines are not heavily loaded. On single-source generation lines and some
tap lines, loads often cannot be switched to achieve the load needed to perform a meaningful IR
inspection. When practical, IR inspections should be performed on lines loaded to at least 40% of
the operating ratings. An IR inspection cannot be substituted for an aerial inspection.

4.2.1 Weather Considerations

Weather conditions can have an adverse effect on IR inspection results. Do not perform IR
inspections under the following conditions:
 Winds in excess of 25 miles per hour (mph)
 Steady rain in progress

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4.3 IR Inspection Documentation

The QCR or thermographer must document abnormal findings, record the information listed below
in form TD-1001M-F15, “Transmission Line Infrared Data Sheet,” and attach the form to the IR
finding notification. This form is generated by SAP.
 Name of the employee performing the inspection (thermographer)
 Time and date of the inspection
 Circuit SAP number
 Identification of the “hot item” type and phase location (e.g., connector, jumper, etc.).
 Weather conditions
 Disk (or file name) and photo numbers
 Load amperes
QCRs using IR cameras with the capacity to provide temperature readings should record the
following information as well:
 Background (or ambient) temperature setting
 Emissivity setting
 Fault temperature
 Reference temperature (like piece of equipment)
 Temperature rise
 Temperature-differential grade

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5. Maintenance Procedures
Before scheduling clearances for maintenance work, identify all maintenance work on a transmission
line by using object lists, notifications, and other sources to minimize the number of clearances
required on any given circuit.
Inspectors must complete all repairs of abnormal conditions that can be done safely by an individual
at the time of inspection. Section 5.1.1 Minor/Incidental Maintenance provides a guide for the types of
maintenance that can be performed at the time of inspection.

5.1 Overhead
The following exhibits contain procedures and flowcharts that provide required, step-by-step
processes for performing maintenance to correct abnormal conditions identified during routine
inspections:
 Exhibit 1, “Notification Initiation Flowchart”
 Exhibit 2, “Notification/Completed Patrol Review”

5.1.1 Minor/Incidental Maintenance

Minor / incidental work is completed by the inspector at the time of the inspection and recorded
on an ETPM form TD-1001M-F01, “Transmission Line Inspection/Patrol Datasheet - Typical.”
To facilitate completing repairs during the inspection, the inspector must be equipped with the
appropriate safety equipment, tools, and materials to perform required maintenance.
For a list of common safety equipment, tools, and maintenance materials, refer to the tables
listed in 8.Appendix B: Equipment, Tools, and Materials:
 Table 18. Safety Equipment List
 Table 19. Tool List

 Table 20. Materials List

5.2 Underground Job Aid for Maintenance Procedures

5.2.1 Requirements
Appropriate maintenance activity is determined based on inspection results, historical
operation of the facilities, utility best practices, sound engineering, and economic judgment.
Refer to Section 2. Inspections for inspection procedures.
Schedule the frequency of maintenance as stated in Section 2.3 Underground Inspections.
Also, maintenance can be condition-based, triggered by specific events, or as identified during
emergency, routine, and/or detailed field inspections. Conditions requiring maintenance are
assigned a Priority Code on a notification, and repairs must be performed within the period
determined by the Priority Code.

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5.2.2 Terminals
 For oil and gas leaks, tighten connections, replace O-rings and gaskets, and check
torque values, per the manufacturer’s recommendations.
 Consult with the transmission engineering group to determine corrective action for the
following:
 Broken porcelain
 Broken standoff insulator and deteriorated riser coating
 Loose, missing, or broken connections and grounds

5.2.3 Pumping Plants

 Calibrate and/or test alarms, Supervisory Control and Data Acquisition (SCADA), pump
plant controls, relief valves, pressure switches, and/or any other component, per the
manufacturer’s or the transmission engineering group’s recommendations.
 Repair or replace defective components to maintain fluid pressures. Consult with the
supervisor to determine corrective action.

5.2.4 Manhole and Vault Integrity

 Covers – Replace broken covers.
 Circuit markings – Re-mark as needed.
 Deteriorating or damaged concrete – Consult with the transmission engineering group
to determine corrective action.
 Splice casings – Replace coating as needed.
 Manholes – Repair water leaks; and replace ladders rigging eyes and racking, as
needed.
 Racking – Replace corroded racking components. If protected by anodes, check for
depletion of anodes and replace if needed.

5.2.5 Fluid and Gas Pressures/Alarms

 Calibrate and/or test alarms, pressure switches, and SCADA.
 Add fluid or gas to the system when pressures or storage volumes fall below the
recommended normal operating levels.

5.2.6 Cathodic Protection

 Rectifiers – Replace if there is no voltage or current output.
 Pipe-to-soil – If the profile falls below 0.850 V, check the rectifier and anode output,
and check the connections. Check for foreign contact in manholes or where pipes are
exposed at construction sites and verify that the bypass switch is open at the polar
cells/ISP cabinet.
 Replace or paint cabinets as needed. Consult with the transmission engineering group
to determine corrective action.
 Repair or replace pipe-wrap in manholes and riser pipe as needed.
 Isolator surge protector (ISP) – Refer to the manufacturer’s operating guidelines.

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5.2.7 Valve Replacement

Repair and/or replace valve components within the period determined by the Priority Code.

5.2.8 Silicone Terminal Coating

Repair and/or replace terminal coating. Consult with the transmission engineering group to
determine corrective action.

5.2.9 Anodes
Replace or add anode components if there is no current output. Consult with the transmission
engineering group/PG&E corrosion engineer to determine corrective action.

5.2.10 Link Boxes

Inspect for deterioration, damage, missing bonding or ground wires. If suspect SVLs (i.e.,
observed conductor temperature increase of cable section), open box and test SVLs.

5.2.11 Structures
 Circuit markings – Re-mark as needed.
 Deteriorating foundations or damaged concrete – Consult with the transmission
engineering group to determine corrective action.
 Damaged hardware – Consult with the transmission engineering group to determine
corrective action.
 Damaged steel members – Consult with the transmission engineering group to
determine corrective action.
 Protective coating – Replace as needed. Consult with the supervisor to determine
corrective action.

5.2.12 Right-of-Way
Clear obstructions and consult with the transmission engineering group to determine corrective
action. If there is an encroachment on the Right-of-Way, refer to Section 1.3.7, Reporting
Nonconformance With Trespass or Encroachment, using the Facility Code Right of Way.

5.2.13 Access Roads

If there is an issue with the access road, address any immediate issue, such as clearing
drainage obstructions. If more work is needed, refer to Section 1.3.5, Reporting
Nonconformance With Access Roads and Gates, using the Facility Code Road.

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6. Enhanced Inspection and Maintenance Requirements for

Diablo Canyon and Morro Bay Power Plants Overhead Transmission
Facilities
The enhanced inspection and maintenance requirements contained within Section 6 apply to
the 230kV and 500kV circuits listed in Table 14.

Table 14. Diablo Canyon PP and Morro Bay PP Enhanced Inspection Circuits
230kV 500kV
Morro Bay-Diablo 230kV * Diablo Unit #1 500kV **
Morro Bay-Mesa 230kV * Diablo Unit #2 500kV **
Diablo PP Stand-By Supply 230kV ** Diablo-Gates #1 500kV *
Diablo-Mesa 230kV * Diablo-Midway #2 500kV *
Diablo-Midway #3 500kV *
* Transmission Line Maintenance Supervisor, Pismo Beach responsibility
** DCPP Switchyard Supervisor responsibility

6.1 Detailed Overhead Inspection

Inspected facilities include overhead assets, rights-of-way, fiber-optic facilities, and vegetation.
The overhead inspections include an external visual evaluation of the overhead facilities. See
Section 5. Maintenance Procedures for requirements that are part of the Company’s overall
maintenance program and are in addition to the visual inspection items identified in this section
A detailed ground, aerial, or climbing inspection of the asset looks for abnormalities or
circumstances that will negatively impact safety, reliability, or asset life. Individual elements and
components are examined carefully through visual and/or routine diagnostic tests, and each
abnormal condition is graded and/or recorded.
Inspect overhead line facilities in accordance with the provisions in Section 1. General
Inspection and Patrol Procedures. The inspections include detailed visual observations and
physical testing as needed (wood pole hammer/bore test, guy tension, etc.) to identify
abnormalities or circumstances that will negatively impact safety, reliability, or asset life.

6.2 Overhead Inspection Frequency

Inspect overhead transmission facilities per Table 15. Overhead Inspection Frequencies-DCPP
and Morro Bay PP Transmission Line Facilities. Establish schedules such that inspection
frequencies meet the SAP maintenance dates.
The schedules indicated in Table 15 do not preclude assigning a more frequent inspection
cycle to a circuit when warranted by sound business reasons. However, increasing inspection
frequency requires appropriate justification and approval by the transmission line
superintendent or designee. Inspections on less frequent cycles than those listed in Table 15
are not allowed.

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Infrared inspections may be performed in conjunction with overhead inspections, but must not
be considered as, or substituted for, an overhead inspection.
Table 15. Overhead Inspection Frequencies-DCPP and Morro Bay PP Transmission Lines
Voltage
Inspection Type Structure Type Inspection Frequency
(kV)
Detailed inspection (ground) Steel Annually
Climbing * Steel 3 years (and as triggered)
500 Patrol ** Steel Quarterly
Annually (and as
Infrared/Corona Steel
triggered)
Detailed inspection (ground or aerial) Steel Annually
Climbing or aerial lift Steel As triggered
Patrol ** Steel Quarterly
230
Structure Inspection *** Steel 3 years (and as triggered)
Annually (and as
Infrared/Corona Steel
triggered)
* Note: Detailed 500 KV climbing inspections must include information about guy tensions.
** Note: This patrol is only performed during the quarters when a Detailed Inspection is not
completed.
*** Note: Structure inspections are to only be performed on DCPP Structures 0/1A and 0/1B of the
Diablo PP Stand-By Supply 230kV overhead transmission line.

Triggers are specific conditions that require follow-up inspections and/or maintenance
scheduled by the supervisor, independent of the routine schedule.
The following triggers can be applied to one unit of inspection or many units, either grouped or
spread over a line section/area:
 Component defects identified by inspection
 Component failure (including failure in like components)
 Components proven defective by testing
 Wire/structure strike
 Burned area or high fire hazard
 Failures caused by natural disaster or storm
 Third-party observations and complaints
 Observed third-party development or construction conflict
 Marginal capability components of a re-rated line section
 Known, recurring conditions that jeopardize line integrity
 Suspected vegetation clearances less than required or less than legal vegetation
clearances, or concerns about fast growth of vegetation

6.3 Climbing/Structure Inspections

A climbing inspection is a detailed, supporting-structure-based observation of the facilities installed
to determine if there are any abnormal or hazardous conditions that adversely impact safety,

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service reliability, or asset life, and to evaluate when each identified abnormal condition warrants
maintenance.
A structure inspection is a detailed ground or aerial lift based observation of the facilities installed
to determine if there are any abnormal or hazardous conditions that adversely impact safety,
service reliability, or asset life, and to evaluate when each identified abnormal condition warrants
maintenance.
Perform routine, time-based 500 kV climbing inspections, focusing primarily on structural
components, on all 500 kV structures, in accordance with the inspection frequencies listed in
Section 6.2 Overhead Inspection Frequency. Climbing inspections extend from the ground line to
the top of the tower. In addition to the documentation and recordkeeping requirements associated
with other routine inspections, forward the results of 500 kV climbing inspections to the
Transmission Tower Davis Headquarters for record retention.
Climbing inspections also might be required for specific structures or components to assess a
condition that could not be adequately assessed when identified during a ground or aerial
inspection or patrol. Such conditions trigger a follow-up inspection to assign the proper Priority
Code. In some cases, this requires a climbing inspection.
See Section 3.3.1 Overhead Non-Routine Patrol, for triggers that might require a follow-up climbing
inspection, and Section 1. General Inspection and Patrol Procedures, Table 2, Inspection Best-
View Position for the best vantage points for inspections of specific items.
Perform routine, time-based 230kV structure inspections; focusing primarily on structural
components, on the specified 230kV structures, in accordance with the inspection frequencies
listed in Section 6.2 Overhead Inspection Frequency. In addition to the documentation and
recordkeeping requirements associated with other routine inspections, forward the results of 230
kV structure inspections to the Transmission Tower Davis Headquarters for record retention.
All inspection forms must be reviewed by the local tower supervisor or designee prior to being filed
as specified on TD-1001M-F03, “500kV Climbing Inspection Form and Tower Diagrams” and TD-
1001M-F04, “Steel Structure Detailed Climbing Inspection (Non-500kV Structures)”. TD1001M-
JA02, “Detailed Climbing Inspection Job Aid” and TD-1001M-JA04, “Identifying Levels of Corrosion
and Foundation Condition on Transmission Line Structures and Supports” should be referenced for
additional instructions to complete the forms.

6.4 Patrols
Overhead patrol procedures are a key element of the preventive maintenance program. The
recommended actions reduce the potential for component failures and facility damage and
facilitate a proactive approach to repairing or replacing identified, abnormal components.
A “patrol” supplements the detailed facility inspection. Patrol frequencies on those facilities listed in
Table 14 shall be in accordance with the schedule listed in Table 15. A detailed facility inspection
may be considered as a patrol, but a patrol cannot be considered as, or substituted for, a detailed
inspection.

An overhead patrol may be performed by walking, driving, or flying (helicopter only). All patrols
must be conducted in a manner that will ensure the identification of the typical problems listed in
Section 3.1.1 Typical Electric Overhead Transmission Problems. Proper documentation and
superintendent approval are required to substitute an air patrol for a scheduled ground patrol.

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6.5 Infrared (IR)/Corona Inspections

IR and corona inspection are effective tools in a preventive maintenance program. IR and corona
inspection reduces the potential for component failures and facility damage and facilitates a
proactive approach to identifying abnormal components for repair/or replacement. See Section 4.
Infrared (IR) Inspection Procedures, for the procedures and requirements.
Infrared and corona inspections on DCPP and Morro Bay PP 500kV and 230kV transmission line
facilities listed in Table 14 are performed on a specified schedule as listed in Table 15, due to their
critical operational impact. Maintenance plans for the listed circuits must include periodic IR and
corona inspections at intervals listed in Table 15.

6.6 Dirty/Contaminated Insulator Cleaning

Perform insulator washing based on local environmental conditions, operating experience, and the
predetermined wash cycles established in SAP. Wash insulators in accordance with the TD-1257M,
“Insulator Cleaning Manual”, Section 3, “Program.” Maintenance plans must be created in SAP for the
circuits (or portions of circuits) listed in Table 14 that require quarterly insulator washing.
For the Diablo PP Stand-By Supply 230kV circuit, de-energized insulator washing will be performed
during scheduled plant outages. For all other circuits in Table 14, hot washing of insulators will be
performed on a quarterly basis for structures within one mile of DCPP and for structures within two
miles of Morro Bay PP. It may be possible to defer a scheduled wash for these facilities to coordinate
with scheduled plant outages. These deferrals would only be considered for a specific exception, and
not on a routine basis. If a deferral is requested, the facilities should be assessed for contamination
levels. Use Equivalent Salt Deposit Density (ESDD) samples to assess the amount of contamination.
The supervisor responsible for the circuits will decide if a schedule wash should be considered for
deferral. The supervisor will arrange for the wipe samples to be taken and sent to ATS for
processing. ATS will process the wipe samples and send the results to the requesting supervisor and
save the results in the ATS records. The contamination grade listed in Table 16. ESDD Contamination
Grades will be used to determine the ability to defer a scheduled wash. The supervisor will review the
results and, if necessary, make a recommendation (including the ESDD results) via EDRS for
approval of the deferral. For circuits that are under the DCPP responsibility, the Transmission Line
Maintenance and Construction Director will concur and the DCPP Switchyard Supervisor will approve
in EDRS based on the results of the DCPP PM deferral process. For circuits that are under the
transmission line responsibility, the DCPP Switchyard Supervisor will concur and the Transmission
Line Maintenance and Construction Director will approve in EDRS. As noted in Table 16, the
maximum deferral will be 90 days.
Table 16. ESDD Contamination Grades
Contamination Grade* ESDD (mg/cm2) Washing Schedule
Light 0.03 – 0.08 Wash may be deferred to scheduled outage, not to
exceed 90 days without an additional wipe test
Medium 0.08 – 0.25 Wash may be deferred, but not more than 60 days
without an additional wipe test
Heavy 0.25 – 0.60 Wash may not be deferred
Extra Heavy > 0.60 Wash must be done immediately
* From IEEE C57.19.100-2012

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7. Document Governance

7.1 Document Approver(s)

Eric Back, Sr. Director Transmission Lines

7.2 Document Owner(s)

Robert Cupp, Superintendent
Jeff Painter, Superintendent
Mickey Willey, Superintendent

7.3 Document Contact(s)

Stacie Doyle, Supervisor
Jennifer Burrows, Manager
Feven Mihretu, Sr. Standards Engineer

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8. Revision Notes
Document Date of Change Log
Location Change
Change Log 05/2017 Added change log.
Entire Document 05/2017 Minor revisions and change to verbiage.
Section 1.3.4 – 05/2017 Added reference to October 2015 5MM with additional process details
Reporting DO and link to said document. Added language clarifying bridging as
nonconformance Distribution work funded through the GRC rate case as communicated
in 04/2016 bulletin ‘TD-1001B-001 Transmission Bridging Tag Creation
and Completion’.
Section 1.6.1 – 05/2017 Updated verbiage to reflect 07/2016 bulletin ‘TD-1001B-002
Inspection/Patrol Inspection/Patrol Records and Deadlines’ clarifying timing of paperwork
Records handoff between QCR and clerical.
Section 1.7; Table 6 – 05/2017 Updated verbiage to reflect 08/2016 bulletin ‘TD-1001B-003
Guide for Assigning Foundations Priority Code F’ clarifying allowance of priority code F (24
Priority Codes months) for foundation repair work, especially in sensitive
environmental areas where typical permitting and project timelines are
significantly longer.
Section 1.5.3 & 05/2017 Modified Section 1.5.3 – Notifications Extending Beyond Due Dates
1.5.3.1 and added Section 1.5.3.1 – LC Past Due Exemption Process outlining
the requirements of the past due exemption process and referencing
the job aid with full details (TD-1001M-JA03).
This change incorporates 04/2017 bulletin ‘TD-1001B-004 – LC Past
Due Exemption Process’.
Section 1.1 – Record 05/2017 Updated verbiage to reflect 01/2017 bulletin ‘TD-1001B-005 Electronic
Keeping Signature’ clarifying that PG&E single sign-on electronic devices can
be used as signatures for all purposes formerly requiring wet paper
signature (e.g., email, SAP gatekeeper).
Section 1.1.2 – 05/2017 Added a note on legal holds & provided notice that as of publishing
Records Retention date Electric Operations is still under a legal hold for all records.
Requirements
09/2018 Minor revisions, updated FDA codes, updated links, updated table
Entire Document
numbers and change to verbiage.
Section 1.3.3 09/2018
Added NERC/CAISO critical lines and updated section per Vegetation
Reporting Vegetation
Management
Nonconformance
Sections 1.3.5 09/2018 Updated sections per Land Operations and added more specific
through 1.3.7 information on encroachment
Section 1.4 OH 09/2018
Methodology, Facility, Updated section to reflect ET AI App and new codes for overhead and
Damage and Action underground. Deleted cause codes
Codes
Section 1.5 09/2018 Added and Due Dates to the title

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Document Date of Change Log

Location Change
Section 1.5.1 09/2018
Resolving Abnormal Updated method for charging maintenance tasks > 15 minutes and
Conditions during how to capture on the time card
Patrol or Inspection
09/2018 Noted Director approval for Priority Code F and added information on
Section 1.5.2
High Fire Threat Districts
Section 1.5.3.2 09/2018 Added new section on approval of past due notifications
Section 1.6 Creating 09/2018
and Closing
Updated based on electronic work and timelines
Inspection/Patrol and
Maintenance Records
09/2018 Updates from experts throughout table for Priority Codes. Added to
Table 6
Note regarding Pole Test and Treat reference.
Section 1.8.1 09/2018
Insulator Strength Added information on suspension type porcelain insulators
and Loading
09/2018 Added section on OPGW and ADSS cable to focus on during patrols
Section 1.11.3
inspection
Section 1.16 09/2018
Updated to reflect no LR notifications through the LC notification and
Equipment
how asset strategy reviews notifications for equipment replacement.
Replacement
Also updated FAA notifications to reflect Priority B
Notifications
Section 2.1.1 09/2018
Updated to reflect ET AI App instead of form F02
Procedures
Section 2.2 Climbing 09/2018
Clarified non-routine patrols are Priority B
Inspections
Section 2.3.3 Detailed 09/2018
Added Fulton-Lakeville #1A and #1B (Oakmont) Pump Plant Test
Inspections for Pipe-
Procedures
Type Circuit
Section 2.3.6 09/2018 Added updates for roads and right-of-ways
Section 2.3.7 Routine 09/2018
Removed Transition Manhole information that is covered in other
Inspection for
sections
Submarine Circuits
Section 5.2 UG Job 09/2018
Aid For Maintenance Removed information on polarization cells and chart motors
Procedures
Appendix A: 09/2018
Acronyms and Removed definitions that were not used
Definition of Terms
Appendix B: 09/2018
Equipment, Tools, Updated codes
and Materials
Appendix C: Links to 09/2018
Forms and Removed F02 since it is the ET AI App
Flowcharts

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Document Date of Change Log

Location Change
Appendix D: 09/2018
Summary of Links to Added new documents
Related Documents

Appendix E: Line 09/2018

Updated to reflect ET AI App and new deadlines
Patrol File Guidelines

Appendix F: ET AI 09/2018
App Process New
Guidelines
TD-1001M-F01 and 09/2018
Removed old FDA codes
TD-1001M-F12
TD-1001M-F02 09/2018 Deleted
TD-1001M-F03 and 09/2018
Replaced with updated form
TD-1001M-F04

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Appendix A: Acronyms and Definition of Terms

The following definitions of terminology are used in this manual.

Table 17. Acronyms and Definition of Terms
Terms Definitions
A condition that adversely impacts or has the potential to adversely impact safety,
Abnormal Condition
service reliability, or asset life.
The prevailing temperature in the immediate vicinity of the object or target, i.e., the
Ambient Temperature
temperature of the target’s environment.
Temperature (or “Fault” Temperature): The temperature of the targeted surface that
Apparatus
the thermographer is evaluating.
Documentation, written and electronic, that shows the results of an inspection (as
Auditable Records defined in this section), the facility condition assessment, and the subsequent
maintenance and/or repair activity.
Bay Waters Saltwater environments located in the nine counties of the San Francisco Bay area.
CAISO California Independent System Operator.
January 1 through December 31 of any year. For maintenance interval purposes,
for example, if a task is performed on June 17, 2009 and is on a “1 calendar year
Calendar Year
interval,” the task is required to be performed again on or before December 31,
2010
A specific item of a unit of inspection, e.g., structure, terminal, right-of-way,
Component
pumping plant, manhole, insulator, etc.
Maintenance activities that restore facilities that have failed or contributed to an
unacceptable operation condition, typically following an unusual and unforeseen
Corrective Maintenance
incident. These may include inspection, assessment, repair, and replacement
activities associated with restoring the facility.
The 2% most critical 500 kilovolt (kV) towers, as identified in the Pacific Gas and
Electric Company (Company) “500 kV Emergency Restoration Study” (1993),
Critical 500 kV Towers
based upon an equal weighting of the “susceptibility to failure” and “benchmark
restoration time” factors.
Wood that has lost its strength due to insect infestation or decomposition caused
Decayed Wood
by fungi.
Rights-of-way (R/Ws), fee property, fences, buildings, conductors, structures, and
Electric Transmission
associated hardware and equipment that operate at voltages above 50,000 volts
Asset
(V).
A patrol performed as a result of a momentary or sustained outage caused by an
unknown condition on an overhead or underground transmission line. It is a visual
Emergency Patrol check made either by ground or air to look for the specific condition that caused the
outage. An emergency patrol must not be considered as, or substituted for, an
inspection of electric transmission facilities.
The relative ability of a surface to emit heat by radiation. Emissivity is the ratio of
Emissivity
the heat emitted by a surface compared to that emitted by a blackbody.
The ratio of the intensity of thermal radiation, at a given wavelength or spectral
Emittance Value waveband, from a target to the thermal radiation emitted by a blackbody of the
same temperature as the target.

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Terms Definitions
The size of the scene surrounding the target, as observed by the infrared scanner
Field of View and expressed as the ratio between the size of the scene surrounding the target
and the distance between the target and the scanner.
An apparatus, device, or equipment found to have excessive apparatus (“fault”)
Hot Item
temperature.
Identified Maintenance Abnormal conditions that require corrective action before the next inspection cycle.
Condition
Infrared (IR) Inspection A diagnostic test using IR thermography technology to identify abnormal conditions.
IR radiation (or energy) is a part of the electromagnetic spectrum lying outside of
the visible spectrum on the red end. Visible light and IR have similar behavior; the
Infrared (IR) Radiation
main difference is wavelength. IR has a wavelength between 2 and 1,000
micrometers. Visible light has a wavelength of between 0.4 and 0.75 micrometers.
A datasheet or form used to document the inspection and/or patrol of a facility, and
to identify abnormalities that require corrective action or follow-up inspection; for
example, the ETPM form TD-1001M-F01, “Transmission Line Inspection/Patrol
Inspection/Patrol
Datasheet - Typical,” and the underground inspection datasheets shown in the
Datasheet or Form
ETPM forms:
TD-1001M-F06, “Monthly Pipe-Type Routine Inspection - Typical” and
TD-1001M-F07, “Detailed Pipe-Type Inspection – Typical.”
A detailed ground, aerial, or climbing observation of the asset installed, looking for
abnormalities or circumstances that will negatively impact safety, reliability, or asset
Inspection life. Individual elements and components are examined carefully through visual
and/or routine diagnostic tests, and the abnormal conditions of each are graded
and/or recorded.
A specified, maximum time period between inspections of overhead and
Interval
underground electric transmission facilities.
A group of structures and conductor, terminal-to-terminal, excluding line breakers
Line Section
and associated disconnect switches.
Long Wave The portion of the electromagnetic spectrum that ranges from 8 to 14 microns.
Preventive or corrective actions to ensure the safety and reliability of electric
transmission facilities. It includes capital and expense expenditures for tasks
Maintenance
associated with the inspection, repair, refurbishment, and possible replacement of
existing electric transmission facilities to ensure safe and reliable operation.
A report written to document damage resulting from faulty materials or
Material Problem
workmanship, impacts from sources other than the asset or its intended use,
Report (MPR)
sabotage, criminal acts, negligence, etc.
A unit of length equal to one millionth of a meter, which is used to describe the
Micron
wavelength of infrared radiation. “Micron” is the popular name for “micrometer.”
Work that can safely be accomplished at the site by a QCR during a detailed and/or
Minor/Incidental Work
routine inspection.
Used to describe a component that is required, but not present. It is not intended to
Missing describe components that are not required to be present (i.e., dampers or high-
voltage signs that are not required are not considered to be “missing”).
A document identifying an abnormality that requires corrective action, follow-up
inspection, or referral to other departments or entities. Notifications generated in
Notification
the field by QCRs at the time the abnormal condition is observed must be entered
into the Systems Application and Products in Data Processing (SAP) program.

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Terms Definitions
A recorded document identifying a specific facility condition that requires corrective
Notification Form action, follow-up inspection, or referral to other departments or entities. These
forms are part of the ET Asset Inspection (AI) App.
An SAP-generated form that lists (by circuit) structure numbers, SAP equipment
numbers, structure framing and description; Geographic Information System (GIS)
Object List coordinates, and access information. The object list is used as a daily inspection
log and to verify overhead assets. The “Note” section is used for recording access
information only.
PAM Pole Asset Management.
A brief, visual inspection of applicable utility facilities (equipment and structures) that is
designed to identify obvious structural problems and hazards. Patrols may be carried
out in the course of other Company business, provided certain requirements are met.
Patrol
An emergency patrol, which is usually precipitated by an unusual system incident, must
not be considered as, or substituted for, a regularly scheduled inspection or patrol of
electric transmission line facilities.
Activities that ensure facilities and their associated components will continue to
Preventive Maintenance perform within accepted parameters. These activities may include inspection,
(PM) assessment, maintenance, and replacement activities that occur before an
abnormal condition exists.
A Company representative, who, by knowledge, required training, and/or work
Qualified Company experience, is able and allowed to perform a specific job. For the purposes of this
Representative (QCR) manual, QCR refers to an employee qualified to prepare an accurate and complete
assessment of electric transmission facilities.
Radiate To emit. When an object radiates, it emits or sends out electromagnetic waves.
The temperature of a like piece of equipment at the same location as that
Reference Temperature
registering the apparatus (“fault”) temperature.
The ability of a target to reflect or send back rays. A mirror has a reflective surface
Reflective
with respect to visible light.
Reflectivity The amount of radiation that is reflected from a surface. Reflected radiation is not
(also known as absorbed or transmitted. The reflectivity of a surface equals 1 - (emittance +
reflectance) transmittance).
Mechanical technique(s) that restores the strength of a wood pole, decayed at or
Reinforcement
near the ground line, to serviceable condition.
Mechanical techniques(s) that restores the shell or the heart of a wood pole,
Restoration
decayed or damaged above the ground line, to serviceable condition.
Systems Application and Products in Data Processing. An information system used
SAP
to record, schedule, and manage work activities such as inspection maintenance.
Usually a short length of steel truss or wood pole, driven or set into the ground and
Stub attached to the existing pole by suitable and adequate fastenings. A stub provides
the support originally afforded by the pole butt.
Subject Pole A pole that is “non-exempt” per the Power Line Fire Prevention Field Guide.
System One or more line section(s) that perform the same defined function.
Temperature Rise The difference in temperature between the apparatus (“fault”) temperature and the
(or Temperature reference temperature.
Differential)
A method or process used to conduct an examination or trial to obtain a positive
Testing
indicator, along with recording data from the event.
A person who performs an IR inspection to obtain information concerning a target,
Thermographer
object, structure, system, or process.
Any photographic, videotaped, computer-generated, or graphic record of
Thermography
information derived from an IR inspection.
Transmission Control An inspection and maintenance agreement filed with the CAISO that outlines the
Agreement (TCA) Company’s Electric Transmission Inspection and Maintenance Program.

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Terms Definitions
Conductors, structures, and/or associated equipment that are constructed to
Transmission Facilities
transport electric power of 50,000 V and above, from one point to another.
The ability of a medium to allow electromagnetic radiation to pass through it without
Transmissive being reflected or absorbed (to send or transmit rays from one point to another).
Glass is highly transmissive to visual light.
Transmissivity The amount of radiation that is transmitted through a surface. Transmitted radiation
(also known as is not reflected or absorbed.
transmittance) The transmissivity of a surface equals 1 - (emittance + reflectance).
A condition that may require follow-up inspection and/or maintenance of facilities at
Trigger
a frequency different than the intervals determined by line prioritization or condition
(Non-Routine Patrol)
assessment.
Any conductors and associated equipment that are constructed at or below ground
Underground
level for the purpose of transporting electric power of 50,000 V and above, from one
Transmission Facilities
point to another.
Unit of Inspection A portion of a line section identified as a structure and its “ahead” span.
The inspection, trimming, and removal of trees and brush within the vicinity of
Vegetation Management
electric facilities to ensure safe and reliable transmission service. The acronym VM
(VM)
also is used to refer to the Company’s Vegetation Management Department.

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Appendix B: Equipment, Tools, and Materials

The tables below list items an employee or QCR may need to perform inspections and minor
maintenance activities. The tables are intended as a reference resource and include safety equipment
to ensure worker and public safety, and tools and materials that enable inspectors to perform
minor/incidental maintenance work. The material codes are listed to assist with procuring these items
when establishing the contents of vehicles used during the inspection process.

Table 18. Safety Equipment List

Description Information Source Code

Barricade Frame, Manhole Code of Safe Practices, Section 7, Rule 708 M205092
Barrier Tape, 3 Inches Wide Work Area Protection Guide (623151) E620421
Cones, Traffic, 18 Inches High Work Area Protection Guide (623151) E206240
Cones, Traffic, 28 Inches High Work Area Protection Guide (623151) M206391
Flag, Red Work Area Protection Guide (623151) E202416
Hard Hat, Cap Style Code of Safe Practices, Section 1, Rule 3 E207761
Hard Hat, Standard Style Code of Safe Practices, Section 1, Rule 3 M206153
Safety Glasses, Black Frame Code of Safe Practices, Section 1, Rule 17 Various
Stand, for Sign and Flag Work Area Protection Guide (623151) E030512
Vest, Traffic, Size Large Work Area Protection Guide (623151) RHPVF-3091E-L
Vest, Traffic, Size X Large Work Area Protection Guide (623151) RHPVF-3091E-XL
Note: “M”-coded items indicate PG&E Material Codes; “E”-coded items are purchased thru Ariba.

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Table 19. Tool List

Description Code Description Code

Air Monitor, Personal M231805 Kit, First Aid E622724

Binoculars 231088 Knife, Dexter E200632
Bit, 9/16-Inch x 18-Inch, Shaper Auger E200038 Knife, Putty, 1¼-Inch E200510
Blades, for Hacksaw M200886 Ladder, 10-Foot M203122
Broom, House M209004 Line, Hand NA
Brush, Wire M209013 Manhole Lifting Tool E202439
Case, Carrying, for Extension Stick M205548 Meter, Volt, Fluke #77 M244287
Chasers, Thread, Set ¼-Inch to
E205794 Pigtail, With Pulling Eye M205447
1-Inch
Computers, Hammerhead With GPS/GIS NA Pin, Clothes, Clamp, Plastic E206187
Cutters, Bolt, 18-Inch Handles E202974 Press, MD6 NA
Cutters, Cable, HK Ptr. #8690 Various Press, XMJ, Nicopress #53 M201009
Cutters, Cable, T&B #364 M201553 Pump, Water, Hand M202565
Rope, Hot, ½-Inch Diameter,
Die, WBG M202848 E102020
100-Foot
Die, W249 M203039 Saw, Chain, 14-Inch (Optional) 210603
Drill, Hand, Brace NA Saw, Hack M201110
Drill, Rechargeable,
NA Saw, Tree, Hand, Fanno #7 E200986
½-Inch Drive
Driver, Screw, 6-Inch, Philips NA Saw, Tree, With Pruner E201946
Driver, Screw, 6-Inch, Standard M200598 Scabbard, for Fanno #7 Saw M200987
Driver, Screw, 10-Inch, Standard M200600 Shears, Pruning NA
Extinguisher, Indian Backpack E481006 Shotgun, 6-Foot M205395
Eye, Guy-Pulling M201114 Shovel, Flat M200609
Flashlight Rechargeable Mag. M200306 Shovel, Round M200608
Fault-Indicator Reset Tool M202248 Socket, Penthead M202233
Stick, SL Catalog #2596, 1¼-
Gun, Caulking NA M205565
Inch Diameter, 8-Foot
Gun, Infrared, 3M NA Tape, Measuring, 100-Foot E201877
Tool, Combination, for
Hammer, Claw, 22-Ounce M200432 M208094
Pad-Mounted Equipment
Hardhat Light E204958 Weed Eater NA
Switch Lock, 2 ¼ inch long
Hook, Manhole, Flexible Type E200479 M170030
shank SEECO
Hook, Manhole, Ridged Type E200480 New Switch Locks TBD
Hook, Switch Fuse, With QC M205668 - -

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Table 20. Materials List

Description Code Description Code

Nut, With Spring, ½-Inch, 13 NC Thread
Bolt, Penthead, ⅜-Inch x 1¼-Inch 192831 580143
(P1010) (Old Penthead Cast in Frame)
Nut, With Spring, ½-Inch, 13 NC Thread
Bolt, Penthead, ⅜-Inch x 2-Inch 192896 580152
(P4010) (Horizontal With Wood Enclosure)
Paint, for Pad-Mounted Equipment, Green,
Bolt, Penthead, ½-Inch x 1-Inch 192081 130458
Aerosol Can
Paint, Zinc Rich Primer for
Bolt, Penthead, ½-Inch x 1¾-Inch 192832 130479
Pad-Mounted equipment, Aerosol Can
Bolt, Penthead, ½-Inch x 2-Inch NA Plug, Set Screw, Bus Bar, CMC 019683
Bolt, Penthead, ½-Inch x 2½-Inch 192853 Plug, Set Screw, Bus Bar, Homac 019684
Bolt, Penthead, ½-Inch x 3½-Inch 017488 Plug, Wooden Dowel, ⅝-Inch NA
Screw, 5/16-Inch, Allen, Flat Head, SS, ½-
Bolt, Penthead, ½-Inch x 4½-Inch 017489 193391
Inch x ¾-Inch (# Plate Holders)
Bolt, Penthead, Coil Thread,
190068 Splice, Auto Guy, 7/32-Inch 186150
½-Inch x 1¾-Inch
Bolt, Penthead, Coil Thread,
031412 Splice, Auto Guy, 5/16-Inch 186128
½-Inch x 2-7/16-Inch
Caulking, Sealant 495228 Splice, Auto Guy, ⅜-Inch 186129
Ground Molding, Plastic U-Shape,
360008 Splice, Auto Guy, 7/16-Inch 186130
1½-Inch Diameter
Ground Molding, PVC Conduit, Tag, High Voltage/Clearance Label for Pad-
360368 621599
½-Inch Diameter Mounted Equipment
Tag, High Voltage/PG&E Nameplate for
Guy Guard, Cattle 186186 015543
Underground Enclosures
Guy Marker, Plastic 186045 Tags, Phase and Voltage See Note
Tag, High Voltage/Clearance Label for Pad-
Guy Marker, Steel 186176 621599
Mounted Equipment
Guy, Preform, 7/32-Inch 186149 Tags, Red Plastic, Write-On 031811
Guy, Preform, 5/16-Inch 186118 Tags, Yellow Plastic, Write-On 031809
Guy, Preform, ⅜-Inch 186119 Visibility Strip, Barrier Post 374440
Lock, Corporation 016583 Visibility Strip, Guy 373278
Lock, Equipment Safety, 1-Inch 170115 Visibility Strip, Pole 373271
Lock, Equipment Safety, 2-Inch 170116 Wire, Six-Strand, Copper, Hand Coil 290072
Molding, Hardwood 149005 Wire, Four-Strand, Copper, Hand Coil NA
Nut, With Spring, ⅜-Inch, 16 NC Wire, Two-Strand, Copper, Hand Coil NA
580142
Thread (Old Penthead Cast in Frame)
Nut, With Spring, ½-Inch, 13 NC - -
580211
Thread (AS-100) (Covers Before 1986)
Note: See Numbered Document 033582, “Tags for Identifying Underground Cables and Equipment,”
Table 1.

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Appendix C: Links to Forms and Flowcharts

Table 21. Forms Index

Forms Index
Overhead Inspection Forms
TD-1001M-F01, “Transmission Line Inspection/Patrol Datasheet - Typical”

TD-1001M-F03, “500kV Climbing Inspection Form and Tower Diagrams”

TD-1001M-F04, “Steel Structure Detailed Climbing Inspection (Non-500kV Structures)”

TD-1001M-F05, “Object List - Typical”

TD-1001M-F16, "Pile Foundation Inspection Form"

Underground Inspection Forms
TD-1001M-F06, “Monthly Pipe-Type Routine Inspection - Typical”

TD-1001M-F07, “Detailed Pipe-Type Inspection - Typical”

TD-1001M-F08,” Quarterly XLPE Routine Inspection - Typical”

TD-1001M-F09, “Detailed XLPE Inspection - Typical”

TD-1001M-F10, "Alarms/SCADA Annual Test Sheet - Typical”

TD-1001M-F11, “Electric Pumping Plant Annual Calibration Sheet - Typical”

TD-1001M-F12, “Corrective Work Form Electric Transmission Underground”

Equipment Record Forms
TD-1001M-F13, “Request to Add Equipment Records to the Asset Registry”

TD-1001M-F14, “Request to Delete Equipment Records to WM SAP”

Infrared Forms

TD-1001M-F15, “Transmission Line Infrared Data Sheet” (Excel)

Material Forms
Form 62-0113, “Material Problem Report” (MPR)
TD-1957P-01-F01, “Component Testing Information Sheet.”
Flowcharts
These flowcharts illustrate typical processes for overhead electric transmission maintenance procedures:
Exhibit 1, "Notification Initiation Flowchart"
Exhibit 2, "Notification/Completed Patrol Review"
Exhibit 4, “Transmission Vegetation Management Notifications – Steel Structure Clearing”
Exhibit 5, “Transmission Vegetation Management Notifications – Wood Pole Clearing”
Exhibit 6, “Transmission Vegetation Management Notifications – VM Compliance Work”
Exhibit 7, “Transmission Vegetation Management Notifications – Access Work”

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Appendix D: Summary of Links to Related Documents

The following table contains a summary of the links contained in this manual, with the exception of those
already listed in Appendix C: Links to Forms and Flowcharts.

Table 22. Links to Related Documents

TD-1248M, “Barehand Work Procedures Manual”

Engineering Document 033582, “Tags for Identifying Underground Cables and Equipment,”

ET GIS SAP – Request for Work Job Aid – Creation

General Order (G.O.) 95, “Rules for Overhead Electric Line Construction”

General Order (G.O.) 128, “Rules for Construction of Underground Electric Supply and
Communication Systems”

General Order (G.O.) 165 “Inspection Requirements for Electric Distribution and Transmission
Facilities”

TD-015014B-001, “Approval Required for Installation Suspension Type Porcelain Insulators”

TD-06537B-001, “Automatic Guy Strand Dead Ends and Splices Supporting Transmission
Facilities”

TD-1257M, “Insulator Cleaning Manual”

Power Line Fire Prevention Field Guide

SCM-2106P-01, "Material Problem Report Procedure."

TD1001M-JA01, “Patrol, Inspection and Closing Process”

TD1001M-JA02, “Detailed Climbing Inspection Job Aid”

TD1001M-JA03, “Transmission LC Past Due Exemption Process”

TD1001M-JA04, ‘Identifying Levels of Corrosion and Foundation Condition on Transmission

Line Structures and Supports”

TD-1001P-03, “Obstruction Lighting Failure Notification Process”

TD-1001P-06, “Electric Underground Transmission Pump Plant Inspections for San Mateo-
Martin 230kV High Pressure Fluid-Filled (HPFF)”

TD-1001P-07, “Electric Underground Transmission Pump Plant Inspections for HZ-1 and HZ-
2 230kV, High Pressure, Fluid Filled (HPFF)”

TD-1001P-08, “Electric Underground Transmission Pump Plant Inspections for Figarden Tap
#1 and #2 230kV (HPFF)”

TD-1001P-09 “Fulton-Lakeville #1A and #1B (Oakmont) Pump Plant Test Procedures”

TD-1001S, “Electric Transmission Line Inspection and Preventive Maintenance Program”

TD-1003S, "Management of Idle Electric Transmission Line Facilities"

TD-1004P-04, “Conductor Rerate Process for Overhead Transmission Circuits”

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TD-1005P-03, “Evaluating Uses of Company Transmission Line Easements by Others”

TD-1005S, “Right-of-Way and Encroachments”

TD-1006P-02, “Switch Maintenance and Inspection Program for Electric Transmission”

TD-1006P-02-JA-01, “Electric Transmission Line Switch Inspection/Function Test Job Aid.”

TD-1006B-004, “Procedure for Marking Duplicate Transmission Switches”

TD-1957P-01, “Electric Transmission Line Equipment Failure Analysis Procedure”

TD-2325P-01, “Wood Poles - Testing, Reinforcing and Reusing”

TD-2325P-01-F01, “Attachment 1 - Pole Inspection/Test Report”

TD-2325S, “Wood Pole Inspection, Testing, and Maintenance”

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Appendix E: Line Patrol File Guidelines

The following lists contain a summary of what should be included in the folders that are in the transmission
line maintenance supervisor’s office. Annually for each circuit, two folders should be created. There will be
one folder for Annual Patrols and one folder for the Line Files. Print the appropriate forms and include in the
specific folder for each circuit.

Figure 3. Line Folder Examples

Folder 1- Annual Patrols (Line Name, Year, Patrols)

1) Detailed Inspections
a) Operational Control Ticket (9010)
b) Transmission Line Inspection Datasheet (9970)
i) Datasheets must be filled out completely. QCR must complete top of datasheet, sign and date the
body of the datasheet.
ii) One notification must be created for each finding, except for minor maintenance work (less than 15
minutes) that has been completed. The datasheets should include each finding with the
notification number AND any minor maintenance completed in the field.
iii) List on the datasheet if no findings were found.
iv) Supervisors must sign and date.
v) Scan completed datasheet and attach to the order.
c) Transmission Line Object List (9971)
i) Each page should have QCR’s name and inspection date listed at the top.
ii) Check only one box.
iii) Include changes in directions, combination lock codes, LIDAR measurements (one location/mile
with height, temperature, date and time), etc.
iv) Any changes on the object list must be scanned and an RW created.
d) List of existing notifications (IW28) from SAP
e) Map of line with species (Fresno, Midway & Victor only)

2) Air and Ground Patrols

a) Operation Control Ticket (9010)
b) Transmission Line Inspection Datasheet (9970)
i) Datasheet must be filled out completely. QCR must complete top of datasheet, sign and date the
body of the datasheet.
ii) One notification must be created for each finding. The datasheets should include each finding with
the notification number.
iii) List on the datasheet if no findings were found
iv) Supervisors must sign and date.
v) Scan completed datasheet and attach to the order.
c) Transmission Line Object List Coversheet (9971 or 9972, either form is appropriate)
i) For 9971:

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(1) Each page should have QCR’s name and inspection date listed at the top
(2) Check only one box
(3) Include changes in directions, combination lock codes, LIDAR measurements (one
location/mile with height, temperature, date and time), etc.
(4) Any changes on the object list must be scanned and a RW created
ii) For 9972:
(1) Sign and date with the structures completed, e.g., 1/1 through 20/155
d) List of existing notifications (IW28 from SAP)

Folder 2-Line File (Line Name, Year, Line File)

Within the Line File Folder, file the completed notifications and miscellaneous information.
1) Non-Routine Patrols
a) Completed Notification must be scanned and attached to notification in SAP.

2) Completed Notifications
a) Only print notification (computer generated SAP notification) when work completed thus including the
most updated information.
b) Completed notifications must include what work was completed, the date completed and the signature
and LAN ID of the person who completed the work.
c) Each notification should have a Construction Completion Standard Checklist (CCSC) attached. If the
location has underbuild, there must be a Distribution CCSC form attached also.
d) If notification is noted as found in field completed, then the notification should be set for deletion. If the
notification is linked to a capital order, the notification should be de-linked before deleting and notify
engineering to cancel the order. If the notification is linked to an expense order, notify the
asset/maintenance planner to cancel the order.
e) If the crew finds a problem at an adjacent location and corrects the problem while working a
notification, then:
i) Foreman completes the notification, signs and dates
ii) Supervisor reviews and signs
iii) SAP notification created electronically

THERE SHOULD BE NO PENDING FILE OR WORKING FILE IN YOUR LINE FILES.

3) Miscellaneous Information
a) Miscellaneous Information
i) Miscellaneous notifications should be kept to a minimum
ii) Important information should be scanned and attached to the completed notification. Do not copy
unnecessary information into the body of a notification (e.g., emails).
iii) Information unrelated to notifications should be kept to a minimum

DO NOT COPY UNNECESSARY INFORMATION INTO THE BODY OF A NOTIFICATION i.e., EMAILS.
ANYTHING NOTED ON A NOTIFICATION CAN BE VIEWED BY AUDITORS. ATTACHMENTS ARE FOR
INTERNAL VIEWING.
Note--- Capital notifications should not be filed in the capital jobs or in the line files. Completed capital
jobs should be filed in a completed capital file by line name also by year.

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Appendix F: ET AI App Process Guidelines

The following screenshots shows the data input screens to use during inspections and patrols when
notifications are created.

Figure 4: Start a Report

Figure 5: Validate Facility and Location

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Figure 6: Choose Facility, Damage and Corrective Action

Figure 7: Attach Photo(s) and Determine if a Clearance is Required

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Figure 8: Describe Field Conditions

Figure 9: Set Appropriate Priority Code, Adjust Date if Necessary and Determine Crew Size and Hours

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Figure 10: Review Data, Confirm and Submit

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