Design Manual for High Voltage Transmission Lines
Content
BULLETIN 1724E-200
DESIGN MANUAL FOR
HIGH VOLTAGE TRANSMISSION LINES
U.S. DEPARTMENT OF AGRICULTURE
RURAL UTILITIES SERVICE
ELECTRIC STAFF DIVISION
Revised May 2009
Bulletin 1724E-200
Page-ii
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Bulletin 1724E-200
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Bulletin 1724E-200
Page-v
TABLE OF CONTENTS
CHAPTER 1 - GENERAL
CHAPTER 2 - TRANSMISSION LINE DOCUMENTATION
CHAPTER 3 - TRANSMISSION LINE LOCATION, ENGINEERING SURVEY AND
RIGHT-OF-WAY ACTIVITIES
CHAPTER 4 - CLEARANCES TO GROUND, TO OBJECTS UNDER THE LINE AND
AT CROSSINGS
CHAPTER 5 - HORIZONTAL CLEARANCES FROM LINE CONDUCTORS
TO OBJECTS AND RIGHT-OF-WAY WIDTH
CHAPTER 6 - CLEARANCES BETWEEN CONDUCTORS AND BETWEEN
CONDUCTORS AND OVERHEAD GROUND WIRES
CHAPTER 7 - INSULATOR SWING AND CLEARANCES OF CONDUCTORS
FROM SUPPORTING STRUCTURES
CHAPTER 8 - INSULATION AND INSULATORS
CHAPTER 9 - CONDUCTORS AND OVERHEAD GROUND WIRES
CHAPTER 10 - PLAN-PROFILE DRAWINGS
CHAPTER 11 - LOADINGS AND LOAD FACTORS
CHAPTER 12 - FOUNDATION STABILITY OF DIRECT-EMBEDDED POLES
CHAPTER 13 - STRUCTURES
CHAPTER 14 - GUYED STRUCTURES
CHAPTER 15 - HARDWARE
CHAPTER 16 - UNDERBUILD
APPENDIX A - TRANSMISSION LINE DESIGN DATA SUMMARY SHEET
AND SUPPORTING INFORMATION
APPENDIX B - CONDUCTOR TABLES
APPENDIX C - INSULATION TABLES
APPENDIX D - AMPACITY, MVA, SURFACE GRADIENT TABLES
APPENDIX E - WEATHER DATA
Bulletin 1724E-200
Page-vi
TABLE OF CONTENTS (CONT)
APPENDIX F - POLE DATA
APPENDIX G - CROSSARM DATA
APPENDIX H - MISCELLANEOUS STRUCTURAL DATA
APPENDIX I - RI AND TVI
APPENDIX J - INSULATOR SWING TABLES
APPENDIX K - SYMBOLS AND ABBREVIATIONS
APPENDIX L - SELECTED SI-METRIC CONVERSIONS
APPENDIX M- INDEX
INDEX OF BULLETINS:
Design, System
Transmission Facilities, Line Manual
ABBREVIATIONS
(See Appendix L for Engineering Symbols and Abbreviations)
AAAC
AAC
AACSR
AC
ACCR
ACAR
ACCC/TW
ACSR
ACSS
ACSR/AW
ACSR/SD
ACSR/TW
ANSI
ASCE
ASTM
AWAC
AWG
BIA
BLM
CADD
CEQ
CFR
COE
DOE
EPA
EHV
EIS
EI&W
EPRI
All Aluminum Alloy Conductor
All Aluminum Conductor
Aluminum Alloy Conductor Steel Reinforced
Alternating Current
Aluminum Conductor Composite Reinforced
Aluminum Conductor Alloy Reinforced
Aluminum Conductor, Composite Core, Trapezoidal Wire
Aluminum Conductor Steel Reinforced
Steel Supported Aluminum Conductor
Aluminum Conductor Steel Reinforced/Aluminum Clad Steel Reinforced
Aluminum Conductor Steel Reinforced/Self Damping
Aluminum Conductor Steel Reinforced/Trapezoidal Wire
American National Standards Institute
American Society of Civil Engineers
American Society for Testing and Materials
Aluminum Clad Steel, Aluminum Conductor
American Wire Guage
Bureau of Indian Affairs
Bureau of Land Management
Computer-Aided Design and Drafting
Council on Environmental Quality
Code of Federal Regulations
Corps of Engineers
Department of Energy
Environmental Protection Agency
Extra High Voltage
Environmental Impact Statement
Extreme Ice & Concurrent Wind
Electric Power Research Institute
Bulletin 1724E-200
Page-vii
ABBREVIATIONS
(continued from previous page)
(See Appendix L for Engineering Symbols and Abbreviations)
Eq.
FAA
FEMA
FERC
FHA
FLPMA
FS
FWS
GIS
GPS
IEEE
LF
LWCF
M&E
MCOV
MOR
MOV
NEPA
NESC
NPDES
NPS
NRCS
OHGW
PL
Psf
RI
RSL
REA
ROW
RTK-GPS
RUS
SHPO
SML
SPCC
SYP
T2
T&D
TIN
TVI
TW
USC
USDA
USDI
USGS
Equation
Federal Aviation Agency
Federal Emergency Management Agency
Federal Energy Regulatory Commission
Federal Highway Administration
Federal Land Policy and Management Act
Forest Service
Fish and Wildlife Service
Geographic Information System
Global Positioning System
Institute of Electrical and Electronics Engineers, Inc.
Load Factor
Land and Water Conservation Fund Act
Mechanical and Electrical
Maximum Continuous Over Voltage
Modulus of Rupture
Metal Oxide Varistor
National Environmental Protection Act
National Electrical Safety Code
National Pollutant Discharge Elimination System
National Park Service
Natural Resource Conservation Service
Overhead Ground Wire
Public Law
Pounds per square foot
Radio Interference
Residual Static Load
Rural Electrification Administration
Right-of-Way
Real Time Kinematic-Global Positioning System
Rural Utilities Service
State Historical Preservation Officers
Specified Mechanical Load
Spill Prevention Control and Countermeasure
Southern Yellow Pine
Twisted Pair Aluminum Conductor
Transmission and Distribution
Triangular Irregular Network
Television Interference
Trapezoidal Wire
United States Code
United States Department of Agriculture
United States Department of the Interior
United States Geological Survey
Bulletin 1724E-200
Page-viii
FOREWORD
Numerous references are made to tables, figures, charts, paragraphs, sections, and chapters.
Unless stated otherwise, the tables, figures, charts, etc. referred to are found in this bulletin.
When the reference is not in this bulletin, the document is identified by title and source. Any
reference to agency means Rural Utilities Service.
ACKNOWLEDGEMENTS
Figures 9-6 and 9-7 of this bulletin are reprinted from IEEE Std 524-1992, “IEEE Guide to the
Installation of Overhead Transmission Line Conductors, Copyright 1992 by IEEE. The IEEE
disclaims any responsibility or liability resulting from the placement and use in the described
manner.
Figures 4-2, 4-4, 5-2, 5-5 and 11-1 and the table on reference heights (page 4-3) of this bulletin
are reprinted from IEEE/ANSI C2-2007, National Electrical Safety Code, Copyright 2007 by
IEEE. The IEEE disclaims any responsibility or liability resulting from the placement and use in
the described manner.
Figures 11-2a to 11-2e, 11-3a to 11-3f, and Tables E-2 and E-3 of this bulletin are reprinted from
ASCE7-05, “Minimum Design Loads for Buildings and Other Structures,” American Society of
Civil Engineers, Copyright 2005. For further information, refer to the complete rest of the
manual (http://www.pubs.asce.org/ASCE7.html?99991330).
Bulletin 1724E-200
Page-ix
LIST OF TABLES
Table
Number
Table Name
Brief Comment
Page
Routing
3-2
3-1
Line Routing Considerations
3-2
Summary of Potential Major Federal Permits Federal permits
or Licenses That May Be Required
3-6
4-1
Recommended Design Vertical Clearances
of Conductors Above Ground, Roadways,
Rails, or Water Surface
Vertical clearance
4-6
4-2
Recommended Design Vertical Clearances
from Other Supporting Structures, Buildings
and Other Installations
Vertical clearance
4-8
4-3
Recommended Design Vertical Clearances
in Feet Between Conductors Where the
Conductors of One Line Cross Over the
Conductors of Another and Where the
Upper and Lower Conductor Have Ground
Fault Relaying
Vertical clearance
4-12
5-1
Recommended Design Horizontal
Clearances (In Feet) From Conductors At
Rest And Displaced By 6 Psf Wind To
Other Supporting Structures, Buildings And
Other Installations
Horizontal clearanceno wind and 6psf wind
5-2
5-2
Recommended Design Horizontal
Clearances (In Feet) From Conductors
Displaced By Extreme Winds To Other
Supporting Structures, Buildings And Other
Installations Or Vegetation
Horizontal clearanceextreme wind
5-5
5-3
Typical Right-of-Way Widths
Right-of-way
5-9
6-1
Recommended Vertical Separation in Feet
Between Phases of the Same or Different
Circuits Attached to the Same Structure
Vertical separation of
conductors
6-3
7-1
Recommended Minimum Clearances in
Inches at Conductor to Surface of Structure
or Guy Wires
Clearances for insulator 7-4
swing
Bulletin 1724E-200
Page-x
LIST OF TABLES
(Continued from previous page)
Table
Number
Table Name
Brief Comment
Page
7-2
Insulator Swing Angle Values in Degrees
Angles of swing
7-6
8-1
Recommended Insulation Levels at Sea
Level (Suspension at Tangent and Small
Angle Structures)
Insulation
8-2
8-2
Recommended Insulation Levels at Sea
Level (Posts at Tangent and Small Angle
Structures)
Insulation
8-3
8-3
Reduced Shielding Angle Values
Shield angles
8-5
8-4
Suggested Leakage Distances for
Contaminated Areas
Leakage distances
8-10
8-5
Summary of Recommended Insulator
Loading Limits
Insulator load limits
8-11
9-1
Recommended Minimum Conductor Sizes
Min. conductor sizes
9-6
9-2
Constants to be Added to the Total
Load on a Wire for NESC District Loads
Constants
9-9
9-3
Recommended Conductor and
Overhead Ground Wire Tension and
Temperature Limits
Tension and temp.
limits
9-10
9-4
Direction of Deviation of Sags from
Predicted Values when Actual and Assumed
(Design) Ruling Span Values are
Significantly Different
Ruling span and sags
9-13
11-1
Ice, Wind, Temperature,and Constants
Loading Districts
11-2
11-2
Wire Velocity Pressure Exposure
Coefficient (kZ)
Wire kZ
11-3
11-3
Wire Gust Response Factor, GRF
Wire GRF
11-3
11-4
Combined Factor kZ*GRF for Common Wire
Heights
Wire kZ*GRF
11-4
11-5
Structure kZ, GRF , and Combined kZ GRF
Factor
kZ, and GRF for
structures
11-4
11-6
Recommended Load Factors and Strength
Factors to be Applied to NESC District
Loads
Load factors and
strength factors
11-17
Bulletin 1724E-200
Page-xi
LIST OF TABLES
(Continued from previous page)
Table
Number
Table Name
Brief Comment
Page
11-7
Recommended Load Factors and Strength
Factors to be Applied to Extreme Wind
Loads and Extreme Ice with Concurrent
Wind
Load factors and
strength factors
11-18
12-1
Classification of Soils Based
on Field Tests
Soil description
12-2
12-2
Presumptive Allowable Bearing
Capacities, ksf
Bearing capacity
12-7
12-3
Suggested Ranges of Presumptive
Ultimate Bearing Capacities, psf
Bearing capacity
12-7
13-1
Designated Stresses for Poles
Wood characteristics
13-3
13-2
Designated Stresses for Crossarms
Wood characteristics
13-3
13-3
Crossbrace Capacities
X-brace
13-15
14-1
Application of Load and Strength Factors
for Guyed Structures (Guys and Anchors)
Load factors
14-2
14-2
Recommended Minimum Clearances in
Inches from Conductor to Surface of
Structure or to Guy Wires
Clearance to guys
14-3
15-1
Strengths for ANSI C135.1 Machine Bolts,
Double Arming Bolts and Double End Bolts
Bolt strengths
15-9
15-2
Strengths of ASTM A325 Heat Treated,
High Strength Bolts
Bolt strengths
15-11
15-3
Galvanic Table of Various Metals
Galvanic table
15-12
16-1
Recommended Minimum Vertical
Clearances to Distribution or
Communication Underbuild on
Transmission Lines in Feet
Clearance to
underbuild
16-3
C-1
Flashover Data for Porcelain String
5-3/4” x 10” Standard Suspension Insulators
C-2
C-2
Flashover Data For Suspension Polymers
(ANSI C29.12-1997)
C-3
C-3
Approximate Weights and Lengths of
Insulator Strings Using Standard 5-3/4” x 10”
Suspension Bells with a Ball Hook
C-4
Bulletin 1724E-200
Page-xii
LIST OF TABLES
(Continued from previous page)
Table
Number
Table Name
Brief Comment
Page
D-1
Ampacity of ACSR Conductors
D-2
D-2
MVA Limits
D-3
E-1
Wind Velocities and Pressures
E-2
E-2
Conversion Factors for Other Mean
Recurrence Intervals
E-3
E-3
Probability of Exceeding Design Wind
Speeds During Reference Period
E-3
F-1
Moments (ft-k) at Groundline Due to a 1 psf
Wind on the Pole
F-2
F-2
Moment Capacities (ft-k) at Groundline
F-3
F-3
Pole Classes
F-4
F-4
Pole Moment (ft-k) Reduction to Bolt Holes
for 1000 psi Fiber Stress
F-21
F-5
Volumes for Douglas Fir and Southern
Yellow Pine Poles, (cu. ft.)
F-22
F-6
Pole Weights for Douglas Fir (Treated)
F-22
F-7
Pole Weights for Southern Yellow Pine
(Treated)
F-22
G-1
Crossarm Sizes and Moment Capacities
G-2
H-1
Properties of Common Sections
H-2
H-2
Strengths for Machine Bolts, Double
Arming Bolts, Double End Bolts
H-4
H-3
Strengths of ASTM A325 Heat Treated,
High Strength Bolts
H-4
H-4
Strength of Guy Strands
H-4
I-1
RIV Levels
I-2
I-2
Surface Gradient for Typical Designs
I-5
J-1
Insulator Swing Values for Standard RDUP
Tangent Structures
J-2
Bulletin 1724E-200
Page-xiii
LIST OF FIGURES
Figure
Number
Figure Name
Brief Comment
Page
4-1
Clearance Situations Covered in This
Chapter
Vertical clearances
4-1
4-2
NESC Figure 234-5
Clearance to rail cars
4-4
4-3
Simplified Clearance Envelope
Clearance to rail cars
4-5
4-4
Swimming Pool Clearances
Vertical clearances for
swimming pools
4-5
5-1
Horizontal Clearance Requirement
Horizontal clearances
5-1
5-2
Radial Clearance Requirements to
Vegetation
Clearance to vegetation
5-4
5-3
Clearance to Grain Bins, NESC
Figure 234-4a
Clearance to grain bins
5-6
5-4
Horizontal Clearance to Grain Bins,
Conductors at Rest
Clearance to grain bins
5-6
5-5
Horizontal Clearance To Grain Bins,
Conductors Displaced by 6 psf or Extreme
Wind
Clearance to grain bins
5-6
5-6
NESC Clearance to Grain Bins with
Portable Loading Equipment
Clearance to grain bins
5-7
5-7
Simplified Recommendations for Clearances Clearance to grain bins
to Grain Bins with Portable Loading
Equipment
5-7
5-8
A Top View of a Line Showing Total
Horizontal Clearance Requirements
Horizontal clearance
5-8
5-9
ROW Width for Single Line of Structures
(First Method)
ROW width
5-10
5-10
Clearance Between Conductors of One Line
to Conductor of Another Line
Clearance between
lines
5-11
5-11
Clearance Between Conductors of One Line
and Structure of Another
Clearance between
lines
5-12
6-1
Example of Vertical and Horizontal
Separation Values
Separation of
conductors
6-1
Bulletin 1724E-200
Page-xiv
LIST OF FIGURES
(Continued from previous page)
Figure
Number
Figure Name
Brief Comment
Page
6-2
Minimum Distance Between Conductors
Distance Between
Conductors
6-6
6-3
Guide for Preparation of Lissajous Ellipses
Galloping ellipses
6-8
6-4
Single Loop Galloping Analysis
Galloping
6-9
6-5
Proper Phase Arrangements for Crossarm to
Vertical Construction
Vertical transition of
conductors
6-9
7-1
Illustration of Structure Insulator Swing
Angle Limits and Conditions Under Which
They Apply (Excludes Backswing)
Insulator swing
7-3
7-2
Forward and Backward Swing Angles
Insulator swing
7-5
7-3
Typical Insulator Swing Chart for a TH-230
Tangent Structure
Example swing chart
7-6
7-4
Horizontal and Vertical Spans
Span definitions
7-7
7-5
Typical Insulator Swing Chart for a
TH-233 Medium Angle Structure
Example swing chart
7-8
7-6
Insulator Swing Chart for Example 7-9
Example swing chart
7-11
8-1
A Standard Porcelain Suspension Bell
Suspension bell
8-1
8-2
A Typical Porcelain Horizontal Post
Insulator
Horizontal post
8-1
8-3
Insulation Derating Factor vs. Altitude in
1,000's of Feet
Derating factor
8-3
8-4
Shielding Angle, Pole and Overhead Ground
Wires
Shielding angle
8-6
8-5
Contamination Breakdown Process of a
Single Porcelain Insulator Unit
Insulator contamination 8-8
9-1
Typical ACSR Strandings
ACSR conductor
9-1
9-2
1350 Aluminum Conductor Strandings
1350 conductor
9-2
9-3
Typical ACAR Strandings
ACAR conductor
9-3
9-4
Typical ACSR/SD Strandings
ACSR/SD conductor
9-3
Bulletin 1724E-200
Page-xv
LIST OF FIGURES
(Continued from previous page)
Figure
Number
Figure Name
Brief Comment
Page
9-5
Results of a Typical Economical Conductor
Analysis - 230 kV, 795 vs. 954 vs. 1272
kcmil ACSR
Economic conductor
analysis
9-7
9-6
Nomograph for Determining Level Span
Equivalents of Non-Level Spans
Level span equivalents
9-17
9-7
Analysis for Application of Clipping Offsets
Offset clipping
9-20
9-8
Line Section for Example 9-1
Example of ruling span
9-21
10-1
Sample of a Plan and Profile
P&P sample
10-2
10-2
Conventional Symbols for Plan-Profile
Symbols
10-3
10-3
Specimen Sag Template for Conductor
Sag template
10-6
10-4
Application of Sag Template - Level Ground Level ground span
Span.
10-9
10-5
Check for Uplift
Uplift
10-11
10-6
Sag Low Point, Vertical Spans and Uplift
Vertical spans and uplift
10-12
10-7
Sample Check List for Review of Plan and
Profile
Checklist
10-15
11-1
NESC Loading Districts
NESC districts
11-1
11-2a
Extreme Wind Speed in Miles per Hour at
33 Ft. Above Ground (50-Year Mean
Recurrence Interval)
Western states extreme
wind loads
11-5
11-2b
Extreme Wind Speed in Miles per Hour At
33 Ft. Above Ground (50-Year Mean
Recurrence Interval)
Midwest and Eastern
states extreme wind
loads
11-6
11-2c,
11-2d
Extreme Wind Speed in Miles per Hour at
33 Ft. Above Ground for the Northeast and
Southeast (50-Year Mean Recurrence Int)
Northeast and
Southeast extreme
wind loads
11-7
11-2e
Extreme Wind Speed in Miles per Hour at
33 Ft. Above Ground for the Texas,
Louisiana, and Mississippi (50-Year Mean
Recurrence Interval)
Texas, Louisiana, and
Mississippi extreme
wind loads
11-8
11-3a
Uniform Ice Thickness Due To Freezing
Rain With Concurrent 3-Second Gust Wind
Speeds (50 Yr. Mean Recurrence)
Extreme ice with
concurrent wind loads
for Western US
11-9
Bulletin 1724E-200
Page-xvi
LIST OF FIGURES
(Continued from previous page)
Figure
Number
Figure Name
Brief Comment
Page
11-3b
Uniform Ice Thickness Due To Freezing
Rain With Concurrent 3-Second Gust Wind
Speeds (50 Yr. Mean Recurrence)
Extreme ice with
concurrent wind loads
for Central and eastern
11-10
11-3c
Uniform Ice Thickness Due To Freezing
Rain With Concurrent 3-Second Gust Wind
Speeds For Alaska (50 Year Mean
Recurrence Interval)
Extreme ice with
concurrent wind loads
for Alaska
11-11
11-3d
Uniform Ice Thickness Due To Freezing
Rain With Concurrent 3-Second Gust Wind
Speeds For Lake Superior (50 Yr. Mean
Recurrence)
Extreme ice with
concurrent wind loads
for Lake Superior
11-12
11-3e
Uniform Ice Thickness Due To Freezing
Rain With Concurrent 3-Second Gust Wind
Speeds For Fraser Valley Detail (50 Yr.
Mean Recurrence)
Fraser Valley extreme
ice with concurrent
wind loads
11-12
11-3f
Uniform Ice Thickness Due To Freezing
Rain With Concurrent 3-Second Gust Wind
Speeds For Columbia River Gouge (50 Yr.
Mean Recurrence)
Extreme ice with
concurrent wind loads
for Columbia River
Gouge
11-13
12-1
Embedment Depths in Poor Soil
Embedment depths
12-3
12-2
Embedment Depths in Average Soil
Embedment depths
12-4
12-3
Embedment Depths in Good Soil
Embedment depths
12-4
12-4
Embedment Chart for Medium Dry Sand
Bulletin 1724e-205 “Embedment Depths for
Concrete and Steel Poles”
Embedment depths
12-5
13-1
Selection of Level Ground Span
Level ground span
13-2
13-2
Structure Cost per Mile Related to Pole Height
Economic pole height
13-2
13-3
TS Type Structure
13-5
13-4
TSS-1 Structure
13-7
13-5
Application of Forces (Heavy Loading)
13-7
13-6
TSZ-1 Pole Top Assembly
13-10
13-7
TSZ-1 Example
13-10
Bulletin 1724E-200
Page-xvii
LIST OF FIGURES
(Continued from previous page)
Figure
Number
Figure Name
Brief Comment
Page
13-8
HS vs. VS for TSZ-1
13-10
13-9
TU-1 Structure
13-11
13-9a
Davit Arm
13-12
13-10
VS vs. HS for TUS-1 Structure of Ex.13-3
13-12
13-11
Assumed H-Frame Behavior
H-frame behavior
13-13
13-12
Location of Point of Contraflexure
Pt. of contraflexure
13-13
13-13
Crossbrace
X-brace
13-14
13-14
Pole Top Bracing Arrangements
Pole top for H-frames
13-15
13-15
Pole Top Assembly with Two Outside Braces
Two outside braces
13-16
13-16
13-17
Pole Top Assembly with Inside Braces
Structure 1
Inside braces
13-17
13-19
13-18
Structure 2
13-20
13-19
Structure 3
13-21
13-20
Structure 4
13-21
13-21
Structure 5
13-22
13-22
Structure 6
13-22
13-23
Example of an H-Frame
13-23
14-1
Deadend Structure
14-1
14-2
Comparison of Rods to Show Stability Concept
Stability concept
14-4
14-3
Effective Unbraced Length for Various End
Conditions
Unbraced lengths
14-5
14-4a,
14-4b
End Conditions for Bisector and In-Line
Guyed Structures
End conditions for
guyed poles
14-7
14-5
Axial Loads Induced in a Pole
14-8
14-6
Representation of Axial Loads and Double
Accounting Loads
14-8
Bulletin 1724E-200
Page-xviii
LIST OF FIGURES
(Continued from previous page)
Figure
Number
Figure Name
Brief Comment
Page
15-1
Suspension Clamp with Clevis or Ball and
Socket Type of Connection
15-1
15-2
15-2
15-3
Post Type Insulator with Straight Line
Trunion Clamps
Top Groove Hand Tie
15-4a
Typical Bolted Deadend Clamp
15-3
15-4b
Typical Compression Deadend
15-3
15-5
Suspension Insulators
15-5
15-6
Different Types of Hooks
15-5
15-7
Various Types of Ball and Clevis “Y”
Connections
15-5
15-8
Anchor Shackle; Chain Shackle
15-5
15-9
Armor Rods Used with Suspension
Insulators
15-6
15-10a
Cushioned Suspension Unit
15-6
15-10b
Double Cushioned Suspension (for Line
Angles Greater than 30o)
15-6
15-11
Typical Suspension Damper
15-7
15-12
Spiral Vibration Damper for Small
Conductors
15-7
15-13
Disc Weights, Ball Weights
15-8
15-14
Fasteners
15-9
15-15
Lag Screw
15-9
15-16
Grid Gains
15-10
15-17
Spacer Fitting, Reinforcing Plate
and Gain Plate
15-10
15-18
Small Angle Structure with Swing Angle
Brackets
15-11
16-1
Horizontal Separation Requirements
Between Transmission and Underbuild
16-2
15-2
Bulletin 1724E-200
Page-xix
LIST OF FIGURES
(Continued from previous page)
Figure
Number
Figure Name
Brief Comment
Page
16-2
Vertical Separation Requirements at
Structure for Underbuild
16-2
16-3
16-5
16-4
Transference of the Distribution Circuit to a
Separate Pole at a Large Angle
Use of a Separate Pole to Mount a
Distribution Transformer
16-5
Guying Distribution Underbuild
16-5
E-1
Isokeraunic Levels for the United States
E-4
G-1
Crossarm Loading Chart-Maximum
Permitted Vertical Loads of Various Sizes of
Douglas Fir Crossarms
G-3
H-1
Curve for Locating Plane of Contraflexure in
X-Braced H-Frame Structures
H-3
16-5
Bulletin 1724E-200
Page-xx
Blank Page
Bulletin 1724E-200
Page 1-1
1. GENERAL
1.1 Purpose: The primary purpose of this bulletin is to furnish engineering information for use
in designing transmission lines. Good line design should result in high continuity of service,
long life of physical equipment, low maintenance costs, and safe operation.
1.2 Scope: The engineering information in this bulletin is for use in design of transmission lines
for voltages 230 kV and below. Much of this document makes use of standard Rural Utilities
Service (referred to as the agency) structures and assemblies in conjunction with data provided in
this bulletin. Where nonstandard construction is used, factors not covered in this bulletin may
have to be considered and modification to the design criteria given in this bulletin may be
appropriate.
Since the agency program is national in scope, it is necessary that designs be adaptable to various
conditions and local requirements. Engineers should investigate local weather information, soil
conditions, operation of existing lines, local regulations, and environmental requirements and
evaluate known pertinent factors in arriving at design recommendations.
1.3 National Electrical Safety Code (NESC): This bulletin is based on the requirements of the
2007 edition of the National Electrical Safety Code. In accordance with the Code of Federal
Regulations 7 CFR Part 1724, agency financed lines are to be a minimum of Grade B
construction as defined in the NESC. However, since the NESC is a safety code and not a design
guide, additional information and design criteria are provided in this bulletin as guidance to the
engineer.
The NESC may be purchased from the Institute of Electrical and Electronics Engineers (IEEE)
Operations Center, 445 Hoes Lane, P.O. Box 1331, Piscataway, NJ 08855-1331 or at the
following website:
http://standards.ieee.org/nesc
1.4 Responsibility: The borrower is to provide or obtain all engineering services necessary for
sound and economical design. Due concern for the environment in all phases of construction and
cleanup should be exercised.
1.5 Environmental Regulations: Agency environmental regulations are codified in
7 CFR Part 1794, "Environmental Policies and Procedures." These regulations reference
additional laws, regulations and Executive Orders relative to the protection of the environment.
The Code of Federal Regulations may be purchased from the Superintendent of Documents, U.S.
Government Printing Office, Washington, DC 20402.
Agency environmental regulations may be found on the following website:
http://www.usda.gov/rus/electric/regs/index.htm
Bulletin 1724E-200
Page 1-2
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Bulletin 1724E-200
Page 2-1
2. TRANSMISSION LINE DOCUMENTATION
2.1 Purpose: The purpose of this chapter is to provide information regarding design
documentation for transmission lines financed by the Rural Utilities Service.
2.2 General: Policy and procedures pertaining to construction of transmission lines by agency
electric borrowers are codified in 7 CFR 1724, “Electric Engineering, Architectural Services and
Design Policies and Procedures” and 7 CFR 1726, "Electric System Construction Policies and
Procedures" (http://www.usda.gov/rus/electric/regs/index.htm). The requirements of
7 CFR 1726 apply to the procurement of materials and equipment for use by electric borrowers
and to construction of the electric system if the material, equipment, and construction are
financed, in whole or in part, with loans made or guaranteed by the Rural Utilities Service.
2.3 Design Data Summary: When design data is required by the agency, a design data
summary (or its equivalent) should be submitted. Engineering design information includes
design data, sample calculations, and plan-profile drawings. A ‘Transmission Line Design Data
Summary Form’, which is included in Appendix A of this bulletin, has been prepared to aid in
the presentation of the design data summary. A suggested outline in Appendix A indicates
information that should be considered when preparing a design data summary. Appendix A also
highlights information which should be included in the design data submitted to the agency when
computer software has been used in the design.
Bulletin 1724E-200
Page 2-2
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Bulletin 1724E-200
Page 3-1
3. TRANSMISSION LINE LOCATION, ENGINEERING SURVEY AND RIGHT-OFWAY ACTIVITIES
3.1 Route Selection: Transmission line routing requires a thorough investigation and study of
several different alternate routes to assure that the most practical route is selected, taking into
consideration the environmental criteria, cost of construction, land use, impact to public,
maintenance and engineering considerations.
To select and identify environmentally acceptable transmission line routes, it is necessary to
identify all requirements imposed by State and Federal legislation. Environmental
considerations are generally outlined in agency Bulletin 1794A-601, “Guide for Preparing
Environmental Reports for Electric Projects That Require Environmental Assessments.” State
public utility commissions and departments of natural resources may also designate avoidance
and exclusion areas which have to be considered in the routing process.
Maps are developed in order to identify avoidance and exclusion areas and other requirements
which might impinge on the line route. Ideally, all physical and environmental considerations
should be plotted on one map so this information can be used for route evaluation. However,
when there are a large number of areas to be identified or many relevant environmental concerns,
more than one map may have to be prepared for clarity. The number of maps engineers need to
refer to in order to analyze routing alternatives should be kept to a minimum.
Typical physical, biological and human environmental routing considerations are listed in
Table 3-1. The order in which considerations are listed is not intended to imply any priority. In
specific situations, environmental concerns other than those listed may be relevant. Suggested
sources for such information are also included in the table. Sources of information include the
United States Geological Service (USGS), Federal Emergency Management Agency (FEMA),
United States Department of the Interior (USDI), United States Department of Agriculture
(USDA), Natural Resource Conservation Service (NRCS) and numerous local and state
agencies.
For large projects, photogrammetry is contributing substantially to route selection and design of
lines. Preliminary corridor location is improved when high altitude aerial photographs or
satellite imagery are used to rapidly and accurately inventory existing land use. Once the
preferred and alternative corridors have been identified, the engineer should consult USGS maps,
county soil maps, and plat and road maps in order to produce small scale maps to be used to
identify additional obstructions and considerations for the preferred transmission line.
On smaller projects, the line lengths are often short and high altitude photograph and satellite
imagery offer fewer benefits. For such projects, engineers should seek existing aerial
photographs. Sources for such photographs include county planning agencies, pipeline
companies, county highway departments, and land development corporations. A preliminary
field survey should also be made to locate possible new features which do not appear on USGS
maps or aerial photographs.
As computer information systems become less expensive and easier to use, electric transmission
utilities are using Geographic Information Systems(GIS) to automate the route identification
process. GIS technology enables users to easily consolidate maps and attribute information from
various sources and to efficiently analyze what has been collected. When used by routing
experts, automated computer processes help standardize the route evaluation and selection
process, promote objective quantitative analysis and help users select defendable routes. GIS
tools have proven very beneficial to utilities whose goals are to minimize impact on people and
the natural environment while selecting a constructible, maintainable and cost effective route.
Bulletin 1724E-200
Page 3-2
Final route selection, whether for a large or small project, is a matter of judgment and requires
sound evaluation of divergent requirements, including costs of easements, cost of clearing, and
ease of maintenance as well as the effect a line may have on the environment. Public relations
and public input are necessary in the corridor selection and preliminary survey stages.
Physical
•
•
•
•
•
•
•
•
TABLE 3-1
LINE ROUTING CONSIDERATIONS
Sources
Highways
Streams, rivers, lakes
Railroads
Airstrips
Topography (major ridge lines,
floodplains, etc.)
Transmission lines & distribution lines
Pipelines,(water, gas, sewer),
underground Electric
Occupied buildings
Biological
•
•
Woodlands
Wetlands
•
Waterfowl, wildlife refuge areas,
endangered species & critical
Habitat Areas
Human Environmental
•
Rangeland
•
Cropland
•
Urban development
•
•
•
•
Industrial development
Mining areas
Recreation or aesthetic areas,
national parks, state and local parks
Prime or unique farmland
•
Irrigation (existing & potential)
•
Historic and archeological sites
•
Wild and scenic rivers
Other
•
Federal, state and county controlled
lands
USGS, state & county highway department maps
USGS, Army Corps of Engineers, flood insurance maps
USGS, railroad
USGS, Federal Aviation Administration (FAA)
USGS, flood insurance maps (FEMA), Army Corps of
Engineers
USGS, local utility system maps
USGS, local utility system maps
Local tax maps, land use maps, local GIS maps
Sources
USGS, USDA - Forest Service,
USGS, Army Corps of Engineers, USDA National Conservation
Resource Service, USDI Fish and Wildlife Service
USDI - Fish and Wildlife Service, State Fish and Game Office
Sources
USGS aerial survey, satellite mapping, county planning
agencies, state planning agencies, state soil conservation
service, mining bureau, U.S. Bureau of Land Management,
NRCS
USGS, soil surveys, USDA - NRCS, state department of
agriculture, county extension agent
Irrigation district maps, applications for electrical service, aerial
survey, state departments of agriculture and natural
resources, water management districts
National Register of Historic Sites (existing), state historic
preservation officer , state historic and archeological
societies
USGS maps, state maps, state department of natural resources,
Department of Interior
Sources
USGS, state maps, USDI Park Service, Bureau of Land
Management, state department of natural resources, county
maps, etc.
Bulletin 1724E-200
Page 3-3
3.2 Reconnaissance and Preliminary Survey: Once the best route has been selected and a
field examination made, aerial photos of the corridor should be reexamined to determine what
corrections will be necessary for practical line location. Certain carefully located control points
should then be established from an aerial reconnaissance. Once these control points have been
made, a transit line using stakes with tack points should be laid in order to fix the alignment of
the line. A considerable portion of this preliminary survey usually turns out to be the final
location of the line.
In many instances, after route has been selected and a field examination made, digital design data
on a known coordinate system like State Plane is used for centerline alignment and profile. This
alignment is provided to surveyors in a universal drawing file format. The surveyors then
convert it to a format used by their field recording equipment. Once the project location is
known, base control monuments are established along the route at 2 to 5 mile intervals,
depending on topography, with static Global Positioning System (GPS) sessions from known
horizontal and vertical control monuments. GPS equipment and radio transmitter equipment
occupying the base monuments broadcast a corrected signal to roving GPS unit(s). These GPS
units, with the use of an on-board field computer, allow any point or any line segment along the
route to be reproduced in the field. The roving unit can be used to locate and verify wire heights
at crossings, unmarked property lines or any routing concerns that may come up locally. The
equipment can also be used to establish centerline points in open areas so that conventional
survey equipment can be used to mark the line in wooded areas for clearing purposes. Once the
right-of-way (ROW) has been cleared, all structures can be staked with the Real Time
Kinematic-Global Positioning System (RTK-GPS) equipment. Since this entire process uses
data of a known mapping plane, any position along the route can be converted to various formats
and used within databases.
3.3 Right-of-Way: A right-of-way agent (or borrower's representative) should precede the
preliminary survey party in order to acquaint property owners with the purpose of the project, the
survey, and to secure permission to run the survey line. The agent or surveyor should also be
responsible for determining property boundaries crossed and for maintaining good public
relations. The agent should avoid making any commitments for individual pole locations before
structures are spotted on the plan and profile sheets. However, if the landowner feels particularly
sensitive about placing a pole in a particular location along the alignment, then the agent should
deliver that information to the engineer, and every reasonable effort should be made by the
engineer to accommodate the landowner.
As the survey proceeds, a right-of-way agent should begin a check of the records (for faulty
titles, transfers, joint owners, foreclosed mortgages, etc.) against the ownership information
ascertained from the residents. This phase of the work requires close coordination between the
engineer and the right-of-way agent. At this time, the right-of-way agent also has to consider
any access easements necessary to construct or maintain the line.
Permission may also have to be obtained to cut danger trees located outside inside the
right-of-way. Costly details, misuse of survey time and effort, and misunderstanding on the part
of the landowners should be avoided.
3.4 Line Survey: Immediately after the alignment of a line has been finalized to the satisfaction
of both the engineer and the borrower, a survey should be made to map the route of the line.
Based on this survey, plan-profile drawings will be produced and used to spot structures.
Long corridors can usually be mapped by photogrammetry at less cost than equivalent ground
surveys. The photographs will also contain information and details which could not otherwise be
discovered or recorded. Aerial survey of the corridor can be accomplished rapidly, but proper
conditions for photography occur only on a comparatively few days during the year. In certain
Bulletin 1724E-200
Page 3-4
areas, photogrammetry is impossible. It cannot be used where high conifers conceal the ground
or in areas such as grass-covered plains that contain no discernible objects. Necessary delays
and overhead costs inherent in air mapping usually prevent their use for short lines.
When using photogrammetry to develop plan-profile drawings, proper horizontal and vertical
controls should first be established in accordance with accepted surveying methods. From a
series of overlapping aerial photographs, a plan of the transmission line route can be made. The
plan may be in the form of an orthophoto or it may be a planimetric map (see Chapter 10). The
overlapping photos also enable the development of profile drawings. The tolerance of plotted
ground elevations to the actual ground profile will depend on photogrammetric equipment, flying
height, and accuracy of control points.
Survey data can be gathered using a helicopter-mounted laser to scan existing lines and/or
topography. Three dimensional coordinates of millions of points can be gathered while also
taking forward and downward looking videos. These points can be classified into ground points,
structure points and wire points.
If use of photogrammetry or laser-derived survey information for topographic mapping is not
applicable for a particular line, then transit and tape or various electronic instruments for
measuring distance should be used to make the route survey. This survey will generally consist
of placing stakes at 100 foot intervals with the station measurement suitably marked on the
stakes. It will also include the placement of intermediate stakes to note the station at property
lines and reference points as required. The stakes should be aligned by transit between the hub
stakes set on the preliminary survey. The survey party needs to keep notes showing property
lines and topographic features of obstructions that would influence structure spotting. To
facilitate the location of the route by others, colored ribbon or strips of cloth should be attached
at all fence crossings and to trees at regular intervals along the route (wherever possible).
As soon as the horizontal control survey is sufficiently advanced, a level party should start taking
ground elevations along the center line of the survey. Levels should be taken at every 100 foot
stations and at all intermediate points where breaks in the ground contour appear. Wherever the
ground slopes more than 10 percent across the line of survey, side shots should be taken for a
distance of at least 10 feet beyond the outside conductor's normal position. These elevations to
the right and left of the center line should be plotted as broken lines. The broken lines represent
side hill profiles and are needed, when spotting structures, to assure proper ground clearance
under all conductors, and proper pole lengths and setting depths for multiple-pole structures.
3.5 Drawings: As soon as the route survey has been obtained, the plan and profile should be
prepared. Information on the plan and profile should include alignment, stationing, calculated
courses, fences, trees, roads, ditches, streams, and swamps. The vertical and plan location of
telecommunications, transmission and other electric lines should be included since they affect
the proposed line. The drawings should also show railroads and river crossings, property lines,
with the names of the property owners, along with any other features which may be of value in
the right-of-way acquisition, design, construction, and operation of the line. Chapter 10
discusses structure spotting on the plan-profile drawings.
Structure spotting should begin after all of the topographic and level notes are plotted on the plan
and profile sheets. Prints of the drawings should be furnished to the right-of-way agent for
checking property lines and for recording easements. One set of prints certified as to the extent
of permits, easements, etc. that has been secured by the borrower should be returned to the
engineer.
3.6 Rerouting: During the final survey, it may be necessary to consider routing small segments
of the line due to the inability of the right-of-way agent to satisfy the demands of property
Bulletin 1724E-200
Page 3-5
owners. In such instances, the engineer should ascertain the costs and public attitudes towards
all reasonable alternatives. The engineer should then decide to either satisfy the property owner's
demands, relocate the line, initiate condemnation proceedings, or take other action as
appropriate. Additional environmental review may also be required.
3.7 Clearing Right-of-Way: The first actual work to be done on a transmission line is usually
clearing the right-of-way. When clearing, it is important that the environment be considered.
Environmental commitments/mitigations should be included in the construction contracts. It is
also important that the clearing be done in such a manner that will not interfere with the
construction, operation or maintenance of the line. In terrain having heavy timber, prior partial
clearing may be desirable to facilitate surveying. All right-of-way for a given line should be
secured before starting construction. See Chapter 5 for a discussion of right-of-way width.
3.8 Permits, Easements, Licenses, Franchises, and Authorizations: The following list of
permits, easements, licenses, franchises, and authorizations that commonly need to be obtained is
not meant to be exhaustive.
Private property
Railroad
Highway
Other public bodies
City, county or state
Joint and common use pole
Wire crossing
Easement from owner and permission
to cut danger trees
Permit or agreement
Permit from state/county/city
Authorization
Permit
Permit or agreement
Permission of utility
Table 3-2 list required federal permits or licenses required and other environmental review
requirements. The following abbreviations pertain to Table 3-2:
BIA
BLM
CEQ
CFR
COE
DOE
EIS
EPA
FAA
FERC
FHA
FLPMA
FS
FWS
LWCF
NEPA
NPDES
NPS
PL
SHPO
SPCC
USC
Bureau of Indian Affairs
Bureau of Land Management
Council on Environmental Quality
Code of Federal Regulations
Corps of Engineers
Department of Energy
Environmental Impact Statement
Environmental Protection Agency
Federal Aviation Agency
Federal Energy Regulatory Commission
Federal Highway Administration
Federal Land Policy and Management Act
Forest Service
Fish and Wildlife Service
Land and Water Conservation Fund Act
National Environmental Protection Act
National Pollutant Discharge Elimination System
National Park Service
Public Law
State Historical Preservation Officer
Spill Prevention Control and Countermeasure
United States Code
Bulletin 1724E-200
Page 3-6
TABLE 3-2
SUMMARY OF POTENTIAL MAJOR FEDERAL PERMITS OR LICENSES
THAT MAY BE REQUIRED
And other environmental review requirements for transmission line construction and operation
Issue
NEPA (National
Environmental
Protection Act)
Compliance
Right-of-Way
Across Land
Under Federal
Management
Action Requiring
Permit, Approval,
or Review
Agency
Federal; Action to
grant right-of-way
across land under
Federal jurisdiction
Lead Agency –
EIS and Record of
Decision
Preconstruction
surveys; construction,
operation,
maintenance, and
abandonment
Bureau of Land
Management (BLM)
Right-of-way grant and
special use permit
Bureau of Indian
Affairs (BIA), tribe
Right-of-way grant
across American
Indian lands
Special use
authorization permit or
easement
Authorization to cross
National Park Service
lands
Special use permit for
crossing a national
wildlife refuge
Forest Service (FS)
National Park
Service (NPS)
Fish and Wildlife
Service (FWS)
Biological
Resources
Paleontological
Resources
Permit, License,
Compliance or
Review
Relevant Laws and
Regulations
NEPA (42 USC 4321),
CEQ (40 CFR 1500-1508).
DOE NEPA implementing
Regulations (10 CFR to
1021)
Federal Land Policy and
Management Act (FLPMA)
of 1976 (PL 94-579)
43 USC 1761-1771
43 CFR 2800
25 CFR 169
36 CFR 251
18 USC, 36 CFR 14
50 CFR 25
“Conversion of use” for
a use other than
recreation on lands
reserved with Land
and Water
Conservation Fund Act
(LWCF) monies
NPS
Review of
transmission line
corridor to identify
conflicts with
recreational areas
Land and Water
Conservation Fund Act
PL 88-578, Section 6(f)(3)
Construction,
operation,
maintenance, and
abandonment of
transmission line
across or within
highway rights-of-way
Federal Highway
Administration (FHA)
Permits to cross
Federal Aid Highway;
4 (f) compliance
Department of
Transportation Act
23 CFR 1.23 and 1.27
23 USC 116, 123, and 315
23 CFR 645
23 CFR 771
Grant right-of-way by
federal land-managing
agency
FWS
Endangered Species
Act compliance by
federal land-managing
agency and lead
agency
Endangered Species Act
of 1973 as amended (16
USC 1531 et seq)
Protection of migratory
birds
FWS
Compliance
Protection of bald and
golden eagles
FWS
Compliance
Migratory Bird Treaty Act
of 1918
16 USC 703-712
50 CFR Ch 1
Bald and Golden Eagle
Protection Act of 1972
(16 USC 668)
Ground disturbance on
federal land or federal
aid project
BLM
Compliance with BLM
mitigation and
planning standards for
paleontological
resources of public
lands
FLPMA of 1976
(43 USC 1701-1771)
Antiquities Act of 1906
(16 USC 431-433)
Bulletin 1724E-200
Page 3-7
TABLE 3-2 (Continued)
SUMMARY OF POTENTIAL MAJOR FEDERAL PERMITS OR LICENSES
THAT MAY BE REQUIRED
And other environmental review requirements for transmission line construction and operation
Issue
Ground
Disturbance
and Water
Quality
Degradation
Air Traffic
Action Requiring
Permit, Approval,
or Review
Agency
Permit, License,
Compliance or
Review
Relevant Laws and
Regulations
Clean Water Act
(33 USC 1342)
Section 402 National
Pollutant Discharge
Elimination System
(NPDES) General
Permit for Storm Water
Discharges from
Construction Activities
General easement
10 USC 2668 to 2669
COE
Floodplain use permits
40 USC 961
Construction in or
modification of
floodplain
Federal lead agency
Compliance
Executive Order 11988
Floodplains
Construction or
modification of
wetlands
Federal lead agency
Compliance
Executive Order 11990
Wetlands
Potential discharge
into water of the state
(including wetlands
and washes)
COE (and states);
EPA on tribal lands
Section 401 permit
Clean Water Act
(33 USC 1344)
Discharge of dredge or
fill material to
watercourse
COE; EPA on tribal
lands
404 Permit (individual
or nationwide)
Clean Water Act
(33 USC 1344)
Placement of
structures and
construction work in
navigable waters of the
U.S
COE
Section 10 permit
Rivers and Harbors Act of
1899 (33 USC 403)
Protection of all rivers
included in the
National Wild and
Scenic Rivers System
Affected landmanaging agencies
Review by permitting
agencies
Wild and Scenic Rivers Act
(PL 90- 542)
(43 CFR 83.50)
Potential pollutant
discharge during
construction,
operation, and
maintenance
EPA
Spill Prevention
Control and
Countermeasure
(SPCC) plan for
substations
Oil Pollution Act of 1990
(40 CFR 112)
Location of towers in
regards to airport
facilities and airspace
Federal Aviation
Administration (FAA)
A “No-hazard
Declaration” required if
structure is more than
200 feet in height
Section 1101 Air
Space Permit for air
space construction
clearance
FAA Act of 1958
(49 USC 1501)
(14 CFR 77)
Construction sites with
greater than five acres
of land disturbance
Environmental
Protection Agency
(EPA)
Construction across
water resources
Army Corps of
Engineers (COE)
Crossing 100-year
floodplain, streams,
and rivers
FAA Act of 1958
(49 USC 1501)
(14 CFR 77)
Bulletin 1724E-200
Page 3-8
TABLE 3-2 (Continued)
SUMMARY OF POTENTIAL MAJOR FEDERAL PERMITS OR LICENSES
THAT MAY BE REQUIRED
And other environmental review requirements for transmission line construction and operation
Issue
Cultural
Resources
Rate regulation
Action Requiring
Permit, Approval,
or Review
Agency
Permit, License,
Compliance or
Review
Relevant Laws and
Regulations
Disturbance of historic
properties
Federal lead agency,
State Historical
Preservation Officers
(SHPO), Advisory
Council on Historic
Preservation
Section 106
consultation
National Historic
Preservation Act of 1966
(16 USC 470)
(36 CFR Part 800)
Excavation of
archaeological
resources
Federal landmanaging agency
Permits to excavate
Archaeological Resources
Protection Act of 1979
(16 USC 470aa to 470ee)
Potential conflicts with
freedom to practice
traditional American
Indian religions
Federal lead agency,
Federal landmanaging agency
Consultation with
affected American
Indians
American Indian Religious
Freedom Act
(42 USC 1996)
Disturbance of graves,
associated funerary
objects, sacred
objects, and items of
cultural patrimony
Federal landmanaging agency
Consultation with
affected Native
American group
regarding treatment of
remains and objects
Native American Graves
Protection and
Repatriation Act of 1990
(25 USC 3001)
Investigation of cultural
and paleontological
resources
Affected landmanaging agencies
Antiquities Act of 1906
(16 USC 432-433)
Investigation of cultural
resources
Affected landmanaging agencies
Protection of
segments, sites, and
features related to
national trails
Sales for resale and
transmission services
Affected landmanaging agencies
Permit for study of
historical,
archaeological, and
paleontological
resources
Permits to excavate
and remove
archaeological
resources on Federal
lands; American Indian
tribes with interests in
resources must be
consulted prior to
issuance of permits
National Trails
Systems Act
compliance
Federal Power Act
compliance by power
seller
Federal Power Act
(16 USC 792)
Federal Energy
Regulatory
Commission (FERC)
Archaeological Resources
Protection Act of 1979
(16 USC 470aa to 470ee)
(43 CFR 7)
National Trails System Act
(PL 90-543)
(16 USC 1241 to 1249)
In cases where structures or conductors will exceed a height of 200 feet, or are within
20,000 feet of an airport, the nearest regional or area office of the FAA must be
contacted. In addition, if required, FAA Form 7460-1, "Notice of Proposed Construction
or Alteration," is to be filed. Care must also be given when locating lines near hospital
landing pads, crop duster operations, and military bases.
Bulletin 1724E-200
Page 4-1
4. CLEARANCES TO GROUND, TO OBJECTS UNDER THE LINE AND AT
CROSSINGS
4.1 General: Recommended design vertical clearances for agency financed transmission lines
of 230 kV and below are listed in the Tables 4-1 through 4-3. These clearances exceed the
minimum clearances calculated in accordance with the 2007 edition of the NESC. If the 2007
edition has not been adopted in a particular locale, clearances and the conditions found in this
chapter should be reviewed to ensure that they meet the more stringent of the applicable
requirements.
Clearance values provided in the following tables are recommended design values. In order to
provide an additional cushion of safety, recommended design values exceed the minimum
clearances in the 2007 NESC.
4.2 Assumptions
4.2.1 Fault Clearing and Switching Surges: Clearances in tables 4-1, 4-2, 4-3, and 5-1 are
recommended for transmission lines capable of clearing line-to-ground faults and voltages up to
230 kV. For 230 kV, the tables apply for switching surges less than or equal to 2.0; for higher
switching surges on 230 kV transmission lines see the alternate clearance recommendations in
the NESC.
4.2.2 Voltage: Listed in the chart that follows are nominal transmission line voltages and the
assumed maximum allowable operating voltage for these nominal voltages. If the expected
operating voltage is greater than the value given below, the clearances in this bulletin may be
inadequate. Refer to the 2007 edition of the NESC for guidance.
Nominal Line-to-Line
Voltage (kV)
Maximum Line-to Line
Operating Voltage (kV)
34.5
46
69
115
138
161
230
*
*
72.5
121
145
169
242
*Maximum operating voltage has no effect on clearance
requirements for these nominal voltages.
Table 4-2
Table 4-3
Table 4-3
Table 4-2
Table 4-1
FIGURE 4-1: CLEARANCE SITUATIONS COVERED IN THIS CHAPTER
Bulletin 1724E-200
Page 4-2
4.3 Design Vertical Clearance of Conductors: The recommended design vertical clearances
under various conditions are provided in Table 4-1.
4.3.1 Conditions Under Which Clearances Apply: The clearances apply to a conductor at
final sag for the conditions ‘a’ through ‘c’ listed below. The condition that produces the greatest
sag for the line is the one that applies.
a. Conductor temperature of 32°F, no wind, with the radial thickness of ice for the applicable
NESC loading district.
b. Conductor temperature of 167°F. A lower temperature may be considered where justified by
a qualified engineering study. Under no circumstances should a design temperature be less
than 120°F.
c. Maximum design conductor temperature, no wind. For high voltage bulk transmission lines
of major importance to the system, consideration should be given to the use of 212°F as the
maximum design conductor temperature.
According to the National Electric Reliability Council Criteria, emergency loading for lines of a
system would be the line loads sustained when the worst combination of one line and one
generator outage occurs. The loads used for condition "c" should be based on long range load
forecasts.
Sags of overhead transmission conductors are predicted fairly accurately for normal operating
temperatures. However, it has consistently been observed that sags for ACSR (Aluminum
Conductor Steel Reinforced) conductors can be greater than predicted at elevated temperatures.
If conductors are to be regularly operated at elevated temperatures, it is important that sag
behavior be well understood. Current knowledge of the effects of high temperature operation on
the long term behavior of conductors and associated hardware (splices, etc.) is probably limited;
however, and a clear understanding of the issues involved is essential. The Electric Power
Research Institute (EPRI) has prepared a report on the effects of high temperature conductor and
associated hardware. 1
The traditional approach in predicting ACSR conductor sag has been to assume that the
aluminum and steel share only tension loads. But as conductor temperature rises, aluminum
expands more rapidly than steel. Eventually the aluminum tension will reduce to zero and then
go into compression. Beyond this point the steel carries the total conductor tension. These
compressive stresses generally occur when conductors are operated above 176 °F to 200 °F.
Greater sags than predicted at these elevated temperatures may be attributed to aluminum being
in compression which is normally neglected by traditional sag and tension methods. AAC (All
Aluminum Conductors) and AAAC (All Aluminum Alloy Conductor) or ACSR conductors
having only one layer of aluminum or ACSR with less than 7 percent steel should not have
significantly larger sags than predicted by these traditional methods at higher operating
temperatures. 2
1
Conductor and Associated Hardware Impacts During High Temperature Operations – Issues and Problems, L.
Shan and D. Douglass, Final Report, EPRI TR-109044, Electric Power Research Institute, Palo Alto, California,
December, 1997.
2
Conductor Sag and Tension Characteristics at High Temperatures, Tapani O. Seppa and Timo Seppa, The Valley
Group, Inc., presented at the Southeastern Exchange Annual E/O Meeting, May 22, 1996, in Atlanta, GA.
Bulletin 1724E-200
Page 4-3
4.3.2 Altitude Greater than 3300 Feet: If the altitude of a transmission line (or a portion
thereof) is greater than 3300 feet, an additional clearance as indicated in Table 4-1 must be
added to the base clearances given.
4.3.3 Spaces and Ways Accessible to Pedestrians Only: Pedestrian-only clearances should be
applied carefully. If it is possible for anything other than a person on foot to get under the line,
such as a person riding a horse, the line should not be considered to be accessible to pedestriansonly and another clearance category should be used. It is expected that this type of clearance
will be used rarely and only in the most unusual circumstances.
4.3.4 Clearance for Lines Along Roads in Rural Districts: If a line along a road in a rural
district is adjacent to a cultivated field or other land falling into Category 3 of Table 4-1, the
clearance-to-ground should be based on the clearance requirements of Category 3 unless the line
is located entirely within the road right-of-way and is inaccessible to vehicular traffic, including
highway right-of-way maintenance equipment. If a line meets these two requirements, its
clearance may be based on the "along road in rural district" requirement. To avoid the need for
future line changes, it is strongly recommended that the ground clearance for the line should be
based on clearance over driveways. This should be done whenever it is considered likely a
driveway will be built somewhere under the line. Heavily traveled rural roads should be
considered as being in urban areas.
4.3.5 Reference Component and Tall Vehicles/Boats: There may be areas where it can be
normally expected that tall vehicles/boats will pass under the line. In such areas, it is
recommended that consideration be given to increasing the clearances given in Table 4-1 by the
amount by which the operating height of the vehicle/boat exceeds the reference component. The
reference component is that part of the clearance component which covers the activity in the area
which the overhead line crosses.
For example, truck height is limited to 14 feet by state regulation, thus the reference component
for roads is 14 feet. However, in northern climates sanding trucks typically operate with their
box in an elevated position to distribute the sand and salt to icy roadways. The clearances in
Table 4-1 are to be increased by the amount the sanding truck operating height exceeds 14 feet.
In another example, the height of farm equipment may be 14 feet or more. In these cases, these
clearances should be increased by the difference between the known height of the oversized
vehicle and the reference height of 14 feet.
Reference heights for Table 4-1 are given below:
Item
1.0
2.0
3.0
4.0
5.0
6.0
7.0
Description
Reference height
(feet)
22.0
14.0
14.0
14.0
8.0/10.0
12.5
Track rails
Roads, streets, alleys, etc
Residential driveways
Other lands traversed by vehicles
Spaces and ways--pedestrians only
Water areas--no sail boating
Water areas—sail boating
Less than 20 acres
16.0
20 to 200 acres
30.0
200 to 2000 acres
30.0
Over 2000 acres
36.0
8.0
Areas posted for rigging or launching
See item 7.0
sailboats
From IEEE/ANSI C2-2007, National Electrical Safety Code, Copyright 2006. All rights reserved.
Bulletin 1724E-200
Page 4-4
For reference components to Table 4-2, see Appendix A, Table A-2b of the NESC.
4.3.6 Clearances Over Water: Clearances over navigable waterways are governed by the
U.S. Army Corps of Engineers and therefore the clearances over water provided in Table 4-1
apply only where the Corps does not have jurisdiction.
4.3.7 Clearances for Sag Templates: Sag templates used for spotting structures on a plan and
profile sheet should be cut to allow at least one foot extra clearance than given in Table 4-1, in
order to compensate for minor errors and to provide flexibility for minor shifts in structure
location.
Where the terrain or survey method used in obtaining the ground profile for the plan and profile
sheets is subject to greater unknowns or tolerances than the one foot allowed, appropriate
additional clearance should be provided.
4.4 Design Vertical Clearance of Conductors to Objects Under the Line (not including
conductors of other lines): The recommended design vertical clearances to various objects
under a transmission line are given in Table 4-2.
4.4.1 Conditions Under Which Clearances Apply: The clearances in Table 4-2 apply under
the same loading and temperature conditions as outlined in section 4.3.1 of this chapter. See
NESC Figures 234-1(a) and 234-1(b) and 234-1(c) for transition zones between horizontal and
vertical clearance planes. See Chapter 5 for horizontal clearances.
4.4.2 Lines Over Buildings: Although clearances for lines passing over buildings are shown in
Table 4-2, it is recommended that lines not pass directly over a building if it can be avoided.
4.4.3 Clearances to Rail Cars: The NESC has defined the clearance envelope around rail cars
as shown in Figure 4-2 (NESC Figure 234-5):
V=(item 1.0, Table 4-1) - 20 ft.
V
10'-8"
22'
20'
CLEARANCE
REQUIRED BY
RULE 232
V
3'
Item 9.0
Table 5-1
FIGURE 4-2: NESC FIGURE 234-5
From IEEE/ANSI C2-2007, National Electrical Safety Code, Copyright 2006. All rights reserved.
Bulletin 1724E-200
Page 4-5
To simplify the design process, Figure 4-3, which defines the recommended clearances, may be
used:
10'-8"
Item 1.0
Table 4-1
3'
Item 9.0
Table 5-1
FIGURE 4-3: SIMPLIFIED CLEARANCE ENVELOPE
In cases where the base of the transmission line is below that of the railroad bed, the designer
may be required to install taller poles or to offset further from the track (using the agency
suggested approach) than is indicated by the NESC clearance envelope.
4.4.4 Lines Over Swimming Pools: Clearances over swimming pools are for reference
purposes only. Lines should not pass over or within clearance ‘A’ of the edge of a swimming
pool or the base of the diving platform. Clearance ‘B’ should be maintained in any direction to
the diving platform or tower.
FIGURE 4-4: SWIMMING POOL CLEARANCES (See TABLE 4-2)
From IEEE/ANSI C2-2007, National Electrical Safety Code, Copyright 2006. All rights reserved.
B
C
RADIUS A
POINT
A
A
B
A
C
" C " is the vertical
clearance over adjacent
land.
Bulletin 1724E-200
Page 4-6
TABLE 4-1
RECOMMENDED DESIGN VERTICAL CLEARANCES OF CONDUCTORS ABOVE
GROUND, ROADWAYS, RAILS, OR WATER SURFACE (in feet) (See Notes A, F & G)
(Applicable NESC Rules 232A, 232B, and Table 232-1)
Line conditions under which the NESC states vertical clearances shall be met (Calculations are
based on Maximum Operating Voltage):
- 32°F, no wind, with radial thickness of ice, if any, specified in Rule 250B of the NESC for the
loading district concerned.
- Maximum conductor temperature for which the line is designed to operate, with no horizontal
displacement
Nominal Voltage, Phase to Phase (kVLL)
34.5
69
115
138
161
230
& 46
Max. Operating Voltage, Phase to Phase
(kVLL)
---72.5
120.8 144.9
169.1 241.5
Max. Operating Voltage, Phase to Ground
(kVLG)
---41.8
69.7
83.7
97.6
139.4
NESC Basic
Clear.(Note F)
Clearances in feet
1.0 Track rails
26.5
29.2
29.7
30.6
31.1
31.5
32.9
2.0 Roads, streets, etc., subject to truck traffic
18.5
21.2
21.7
22.6
23.1
23.5
24.9
3.0 Driveways, parking lots,
and alleys
18.5
21.2
21.7
22.6
23.1
23.5
24.9
4.0 Other lands cultivated etc., traversed
by vehicles (Note B)
18.5
21.2
21.7
22.6
23.1
23.5
24.9
5.0 Spaces and ways accessible to
pedestrians only (Note C)
14.5
17.2
17.7
18.6
19.1
19.5
20.9
6.0 Water areas – no sail boating
17.0
19.7
20.2
21.1
21.6
22.0
23.4
7.0 Water areas – sail boating suitable
(Notes D & E)
Less than 20 acres
20 to 200 acres
200 to 2000 acres
Over 2000 acres
20.5
28.5
34.5
40.5
23.2
31.2
37.2
43.2
23.7
31.7
37.7
43.7
24.6
32.6
38.6
44.6
25.1
33.1
39.1
45.1
25.5
33.5
39.5
45.5
26.9
34.9
40.9
46.9
8.0 Public or private land and water areas
posted for rigging or launching sailboats
(Note E)
Less than 20 acres
20 to 200 acres
200 to 2000 acres
Over 2000 acres
25.5
33.5
39.5
45.5
28.2
36.2
42.2
48.2
28.7
36.7
42.7
48.7
29.6
37.6
43.6
49.6
30.1
38.1
44.1
50.1
30.5
38.5
44.5
50.5
31.9
39.9
45.9
51.9
.02
.05
.07
.08
.12
ALTITUDE CORRECTION TO BE ADDED TO VALUES ABOVE:
Additional feet of clearance per 1000 feet of
.00
altitude above 3300 feet
Bulletin 1724E-200
Page 4-7
TABLE 4-1
(continued from previous page)
RECOMMENDED DESIGN VERTICAL CLEARANCE OF CONDUCTORS ABOVE
GROUND, ROADWAYS, RAILS, OR WATER SURFACE (in feet) (See Notes A, F & G)
(Applicable NESC Rules 232A, 232B, and Table 232-1
Notes:
(A) For voltages exceeding 98 kV alternating current to ground, or 139 kV direct current to ground, the NESC states
that either the clearance shall be increased or the electric field, or the effects thereof, shall be reduced by other
means, as required, to limit the current due to electrostatic effects to 5.0 milliampere (mA), rms, if the largest
anticipated truck, vehicle or equipment under the line were short circuited to ground. The size of the anticipated
truck, vehicle, or equipment used to determine these clearances may be less than but need not be greater than that
limited by Federal, State, or local regulations governing the area under the line. For this determination, the
conductors shall be at final unloaded sag at 120° F.
Fences and large permanent metallic structures in the vicinity of the line will be grounded in accordance with the
owner’s grounding units for the structure concerned to meet the 5.0 milliampere requirement. There should be
adequate ground clearance at crossings and along the right-of-way to meet the minimum requirement of 5 mA due to
the electrostatic field effects on the anticipated vehicles under the transmission line.
Consideration should be given to using the 5.0 mA rule to the conductor under maximum sag condition of the
conductor.
(B) These clearances are for land traversed by vehicles and equipment whose overall operating height is less than
14 feet.
(C) Areas accessible to pedestrians only are areas where riders on horses or other large animals, vehicles or other
mobile units exceeding 8 feet in height are prohibited by regulation or permanent terrain configurations or are not
normally encountered nor reasonably anticipated. Land subject to highway right-of-way maintenance equipment is
not to be considered as being accessible to pedestrians only.
(D) The NESC states that “for uncontrolled water flow areas, the surface area shall be that enclosed by its annual
high-water mark. Clearances shall be based on the normal flood level; if available, the 10 year flood level may be
assumed as the normal flood level. The clearance over rivers, streams, and canals shall be based upon the largest
surface area of any one mile-long segment which includes the crossing. The clearance over a canal, river, or stream
normally used to provide access for sailboats to a larger body of water shall be the same as that required for the
larger body of water.”
(E) Where the U.S. Army Corps of Engineers or the state, has issued a crossing permit, the clearances of that permit
shall govern.
(F) The NESC basic clearance is defined as the reference height plus the electrical component for open supply
conductors up to 22 kVL-G.
(G) An additional 2.5 feet of clearance is added to the NESC clearance to obtain the recommended design
clearances. Greater values should be used where survey methods to develop the ground profile are subject to
greater unknowns. See Chapter 10, paragraph 10.3 of this bulletin.
Bulletin 1724E-200
Page 4-8
TABLE 4-2
RECOMMENDED DESIGN VERTICAL CLEARANCES FROM OTHER SUPPORTING
STRUCTURES (See Note B), BUILDINGS AND OTHER INSTALLATIONS (in feet)
(Applicable NESC Rules: 234A, 234B, 234C, 234D, 234E, 234F, 234I, Tables 234-1, 234-2, 234-3)
Line conditions under which the NESC vertical clearances shall be met (Calculations are based on
Maximum Operating Voltage.):
•
•
32°F, no wind, with radial thickness of ice, if any, specified in Rule 250B of the NESC for the loading
district concerned.
Maximum conductor temperature for which the line is designed to operate, with no horizontal displacement
Nominal Voltage, Phase to Phase (kVLL)
Max. Operating Voltage, Phase to Phase
Max. Operating Voltage, Phase to Ground
(kVLL)
(kVLG)
34.5
& 46
-------
69
115
138
161
72.5
41.8
120.8
69.7
144.9
83.7
169.1
97.6
NESC Basic
Clear.(Note D)
230
(E)
241.5
139.4
Clearances in feet
1.0 From a lighting support, traffic signal support,
or supporting structure of a second line
5.5
7.5
7.5
8.2
8.6
9.1
10.8
2.0 From buildings not accessible to pedestrians
12.5
14.7
15.2
16.1
16.6
17.0
18.4
3.0 From buildings – accessible to pedestrians and
vehicles but not truck traffic
13.5
15.7
16.2
17.1
17.6
18.0
19.4
4.0 From buildings – over roofs accessible to truck
traffic
18.5
20.7
21.2
22.1
22.6
23.0
24.4
5.0 From signs, chimneys, billboards, radio & TV
antennas, tanks & other installations
not accessible to personnel.
8.0
10.2
10.7
11.6
12.1
12.5
13.9
6.0 From bridges – not attached (Note C )
12.5
14.7
15.2
16.1
16.6
17.0
18.4
7.0 From grain bins probe ports
18.0
20.2
20.7
21.6
22.1
22.5
23.9
27.2
27.7
28.6
29.1
29.5
30.9
19.2
19.7
20.6
21.1
21.5
22.9
.00
.02
.05
.07
.08
.12
25.0
8.0 Clearance in any direction from swimming pool
edge and diving platform base
(Clearance A, Figure 4-4)
Clearance in any direction from diving structures
17.0
(Clearance B, Figure 4-4)
ALTITUDE CORRECTION TO BE ADDED TO VALUES ABOVE
Additional feet of clearance per 1000 feet of altitude
above 3300 feet
Notes:
(A) An additional 2.0 feet of clearance is added to NESC clearance to obtain the recommended design clearances.
Greater values should be used where the survey method used to develop the ground profile is subject to greater
unknowns.
(B) Other supporting structures include lighting supports, traffic signal supports, or a supporting structure of another
line.
(C) If the line crosses a roadway, then Table 4-1, line 2.0 clearances are required.
(D) The NESC basic clearance is defined as the reference height plus the electrical component for open supply
conductors up to 22 kVLG except row ‘1.0’ where voltage referenc is 50 kVLG
(E) For 230 kV, clearances may be required to be higher if switching surges are greater than 2.0 per unit. See NESC
Tables 234-4 and 234-5.
Bulletin 1724E-200
Page 4-9
4.4.5 Examples of Clearance Calculations: The following examples demonstrate the
derivation of the vertical clearances shown in Tables 4-1 and 4-2.
To determine the vertical clearance of a 161 kV line crossing a road (category 2.0 of Table 4-1),
the clearance is based on NESC Table 232-1 and NESC Rule 232.
NESC Vertical Clearance = NESC Basic Clearance(Table 232-1) + .4(kVL-G – 22)/12
= 18.5 feet + .4(97.6-22)/12 feet
= 18.5 feet + 2.52 feet
NESC Vertical Clearance = 21.02 feet
Recommended Clearance
= NESC Vertical Clearance + Agency Adder
= 21.02 feet + 2.5 feet
= 23.52 feet (23.5 feet in Table 4-1)
To determine the vertical clearance of a 230 kV line over a building roof not accessible to
pedestrians (category 2.0 of Table 4-2), the clearance is based on NESC Table 234-1 and NESC
Rule 234.
NESC Vertical Clearance = NESC Basic Clearance(Table 234-1) + .4(kVL-G – 22)/12
= 12.5 feet + .4(139-22)/12 feet
= 12.5 feet + 3.9 feet
NESC Vertical Clearance = 16.4 feet
Recommended Clearance = NESC Vertical Clearance + Agency Adder
= 16.4 feet + 2.0 feet
= 18.4 feet (18.4 feet in Table 4-2)
4.5 Design Vertical Clearance Between Conductors Where One Line Crosses Over or
Under Another: Recommended design vertical clearances between conductors when one line
crosses another are provided in Table 4-3. The clearance values in Table 4-3 are for
transmission lines which are known to have ground fault relaying. The clearances should be
maintained at the point where the conductors cross, regardless of where the point of crossing is
located on the span.
4.5.1 Conditions Under Which Clearances Apply: The clearances apply for an upper
conductor at final sag for the conditions ‘a’ through ‘c’. The condition that produces the greatest
sag for the line is the one that applies.
a. A conductor temperature of 32°F, no wind, with a radial thickness of ice for the loading
district concerned.
b. A conductor temperature of 167°F. A lower temperature may be considered where justified
by a qualified engineering study. Under no circumstances should a design temperature be less
than 120°F.
c. Maximum conductor temperature, no wind. See paragraph 4.3.1. The same maximum
temperature used for vertical clearance to ground should be used.
Bulletin 1724E-200
Page 4-10
At a minimum the NESC requires that (1) the upper and lower conductors are simultaneously
subjected to the same ambient air temperature and wind loading conditions and (2) each is
subjected individually to the full range of its icing conditions and applicable design electrical
loading.
4.5.2 Altitude Greater than 3300 Feet: If the altitude of the crossing point of the two lines is
greater than 3300 feet, additional clearance as indicated in Table 4-3 is added to the base
clearance given.
4.5.3 Differences in Sag Conditions Between Lower and Upper Conductors: The reason for
the differences in sag conditions between the upper and lower conductor at which the clearances
apply is to cover situations where the lower conductor has lost its ice while the upper conductor
has not, or where the upper conductor is loaded to its thermal limit while the lower conductor is
only lightly loaded.
4.5.4 Examples of Clearance Calculations: The following example demonstrates the
derivation of the vertical clearance of a category in Tables 4-3 of this bulletin.
To determine the vertical clearance of a 161 kV line crossing a distribution conductor (item 3 of
Table 4-3), the clearance is based on NESC Table 233-1 and NESC Rule 233.
NESC Vertical Clearance= NESC Basic Clearance(Table 233-1) + .4(kVL-G – 22)/12
= 2.0 feet + .4(97.6-22)/12 feet
= 2.0 feet + 2.5 feet
NESC Vertical Clearance = 4.5 feet
Recommended Clearance
= NESC Vertical Clearance + Agency Adder
= 4.5 feet + 1.5 feet
= 6.0 feet (6.0 feet in Table 4-3)
4.6 Design Vertical Clearance Between Conductors of Different Lines at Noncrossing
Situations: If the horizontal separation between conductors as set forth in Chapter 5 cannot be
achieved, then the clearance requirements in section 4.5 should be attained.
4.7 Example of Line-to-Ground Clearance: A portion of a 161 kV line is to be built over a
field of oats that is at an elevation of 7200 feet. Determine the design line-to-ground clearance.
4.7.1 Solution of the Additional Clearance for Altitude: Because the altitude of the 161 kV
line is greater than 3300 feet, the basic clearance is to be increased by the amount indicated in
Table 4-1. The calculation follows:
(7200-3300)(.08)/1000 = 0.32 feet
Bulletin 1724E-200
Page 4-11
4.7.2 Total Clearance: Assuming the line meets the assumptions given in section 4.2 and
Table 4-1, the recommended design clearance over cultivated fields for a 161 kV line is
23.5 feet. Therefore, the recommended clearance, taking altitude into account, is 23.8 feet.
0.32 feet + 23.5 feet = 23.8 feet
An additional one foot of clearance should be added for survey, construction and design
tolerance.
4.8 Example of Conductor Crossing Clearances: A 230 kV line crosses over a 115 kV line in
two locations. At one location the 115 kV line has an overhead ground wire which, at the point
of crossing, is 10 feet above its phase conductors. At the other location the lower voltage line
does not have an overhead ground wire. Determine the required clearance between the 230 kV
conductors and the 115 kV conductors at both crossing locations. Assume that the altitude of the
line is below 3300 feet. Also assume that the sag of the overhead ground wire is the same as or
less than the sag of the 115 kV phase conductors. The 230 kV line has ground fault relaying.
Solution: The first step in the solution is to determine if the line being crossed over has
automatic ground fault relaying. We are able to determine that the lower line has automatic
ground fault relaying.
From Table 4-3, (item 4), the required clearance from a 230 kV conductor to a 115 kV conductor
is 9.0 feet. From Table 4-3, (item 2), the required clearance from the 230 kV conductor to the
overhead ground wire is 7.4 feet; adding 10 feet for the distance between the overhead ground
wire (OHGW) and the 115 kV phase conductors, the total required clearance is 17.4 feet.
When the lower circuit has an overhead ground wire, clearance requirements to the overhead
ground wire govern and the required clearance between the upper and lower phase conductor is
17.4 feet.
Where there is no overhead ground wire for the 115 kV circuit, the required clearance between
the phase conductors is 9.0 feet.
It is important to note that the above clearances are to be maintained where the upper conductor
is at its maximum sag condition, as defined in section 4.5.1b or 4.5.1c above, and the lower
conductor is at 60°F initial sag.
4.9 Vertical Clearances to Vegetation: The best practice is usually to remove all substantive
vegetation (such as trees and vines) under and adjacent to the line. In certain areas, such as
canyons, river crossings, or endangered species habitat, vegetation can be spanned. For vertical
clearances (intended to meet NERC FAC 003), refer to radial clearances discussed in Section
5.2.2 of this bulletin.
Bulletin 1724E-200
Page 4-12
TABLE 4-3
RECOMMENDED DESIGN VERTICAL CLEARANCES IN FEET
BETWEEN CONDUCTORS WHERE THE CONDUCTORS OF ONE LINE
CROSS OVER THE CONDUCTORS OF ANOTHER AND WHERE THE UPPER AND
LOWER CONDUCTORS HAVE GROUND FAULT RELAYING
Voltage between circuits = Voltage line to ground Top Circuit + Voltage line to ground Bottom Circuit (Calculations are
based on the maximum operating voltage.)
The NESC requires that clearances not be less than that required by application of a clearance envelope developed
under NESC Rules 233A1 & 233A2. Structure deflection shall also be taken into account. Agency recommended
values in this table are to be adders applied for the movement of the conductor and deflection of structures, if any.
UPPER LEVEL CONDUCTOR (Note F)
34.5
Nominal Voltage, Phase to Phase kV L-L
69
115
138
161
230
& 46
Max. Operating Voltage, Phase to Phase
(kVLL)
---72.5 120.8 144.9 169.1 241.5
Max. Operating Voltage, Phase to Ground
(kVLG)
---41.8
69.7
83.7
97.6
139.4
NESC
Basic
(kVLG)
Clearances in feet
Clear.
(Note H)
LOWER LEVEL CONDUCTOR
1. Communication
5.0
6.7
7.2
8.1
8.6
9.0
10.4
2. OHGW (Note G)
2.0
3.7
4.2
5.1
5.6
6.0
7.4
3. Distribution conductors
2.0
3.7
4.2
5.1
5.6
6.0
7.4
4. Transmission conductors of lines that
have ground fault relaying. Nominal
line – to – line voltage in kV. (Note F)
230 kV
161 kV
138 kV
115 kV
69 kV
46 kV and below
2.0
2.0
2.0
2.0
2.0
2.0
7.6
7.1
6.2
5.7
8.5
8.1
7.6
6.7
6.2
11.3
9.9
9.5
9.0
8.1
7.6
139.4
97.6
83.7
69.7
41.8
26.4
3.8
4.8
4.3
6.7
5.6
5.2
Notes:
(A) The conductors on other supports are assumed to be from different circuits
(B) This table applies to lines with ground fault relaying.
(C) The NESC requires that the clearance shall be not less than that required by application of a clearance envelope
developed under NESC Rule 233A2 to the positions on or within conductor movement envelopes developed under
Rule 233A1 at which the two wires, conductors or cables would be closest together. For purposes of this
determination, the relevant positions of the wires, conductors, or cables on or within their respective conductor
movement envelopes are those which can occur when (1) both are simultaneously subjected to the same ambient air
temperature and wind loading conditions and (2) each is subjected individually to the full range of its icing conditions
and applicable design electrical loading.
Bulletin 1724E-200
Page 4-13
TABLE 4-3 (continued)
RECOMMENDED DESIGN VERTICAL CLEARANCES IN FEET
BETWEEN CONDUCTORS WHERE THE CONDUCTORS OF ONE LINE
CROSS OVER THE CONDUCTORS OF ANOTHER AND WHERE THE UPPER AND
LOWER CONDUCTORS HAVE GROUND FAULT RELAYING
(D) An additional 1.5 feet of clearance is added to NESC clearance to obtain the recommended design clearances.
Greater values should be used where the survey method used to develop the ground profile is subject to greater
unknowns.
(E) ALTITUDE CORRECTION TO BE ADDED TO VALUES ABOVE
Total altitude
=
Correction for
+
correction factor
upper conductors
Correction for
lower conductors
For upper conductors use correction factor from Table 4-1 of this bulletin.
For lower conductors:
Categories 1, 2, 3 above use no correction factors
Category 4 uses correction factors from Table 4-1 of this bulletin
(F) The higher voltage line should cross over the lower voltage line
(G) If the line on the lower level has overhead ground wire(s), this clearance will usually be the limiting factor at
crossings.
(H) The NESC basic clearance is defined as the reference height plus the electrical component for open supply
conductors up to 22 kVL-G.
Bulletin 1724E-200
Page 4-14
Blank Page
Bulletin 1724E-200
Page 5-1
5. HORIZONTAL CLEARANCES FROM LINE CONDUCTORS TO OBJECTS AND
RIGHT-OF-WAY WIDTH
5.1 General: The preliminary comments and assumptions in Chapter 4 of this bulletin also
apply to this chapter.
5.2 Minimum Horizontal Clearance of Conductor to Objects: Recommended design
horizontal clearances of conductors to various objects are provided in Table 5-1 and minimum
radial operating clearances of conductors to vegetation in Table 5-2. The clearances apply only
for lines that are capable of automatically clearing line-to-ground faults.
Clearance values provided in Table 5-1are recommended design values. In order to provide an
additional margin of safety, the recommended design values exceed the minimum clearances in
the 2007 NESC. Clearance values provided in Table 5-2 are minimum operating clearances to be
used by the designer to determine appropriate design clearances for vegetation maintenance
management.
5.2.1 Conditions Under Which Horizontal Clearances to Other Supporting Structures,
Buildings and Other Installations Apply:
Conductors at Rest (No Wind Displacement): When conductors are at rest the clearances apply
for the following conditions: (a) 167°F but not less than 120°F, final sag, (b) the maximum
operating temperature the line is designed to operate, final sag, (c) 32°F, final sag with radial
thickness of ice for the loading district (0 in., ¼ in., or ½ in.).
Conductors Displaced by 6 psf Wind: The clearances apply when the conductor is displaced by
6 lbs. per sq. ft. at final sag at 60°F. See Figure 5-1.
δ
li
Sf
∅
x
y
FIGURE 5-1: HORIZONTAL CLEARANCE REQUIREMENT TO BUILDINGS
where:
φ =
Sf =
x =
ℓi =
y =
δ =
conductor swing out angle in degrees under 6 psf. of wind
conductor final sag at 60°F with 6 psf. of wind
horizontal clearance required per Tables 5-1 for conductors
displaced by 6 psf wind (include altitude correction if necessary)
insulator string length (ℓi = 0 for post insulators or restrained
suspension insulators).
total horizontal distance from insulator suspension point
(conductor attachment point for post insulators) to structure with
conductors at rest
structure deflection with a 6 psf. Wind
Bulletin 1724E-200
Page 5-2
TABLE 5-1
RECOMMENDED DESIGN HORIZONTAL CLEARANCES (in feet) FROM CONDUCTORS
AT REST AND DISPLACED BY 6 PSF WIND TO OTHER SUPPORTING STRUCTURES,
BUILDINGS AND OTHER INSTALLATIONS
(NESC Rules 234B, 234C, 234D, 234E, 234F, 234I, Tables 234-1, 234-2, 234-3)
Conditions under which clearances apply:
No wind: When the conductor is at rest the clearances apply at the following conditions: (a) 120°F, final sag, (b) the maximum
operating temperature the line is designed to operate, final sag, (c) 32°F, final sag with radial thickness of ice for the loading
district (1/4 in. for Medium or 1/2 in. Heavy).
Displaced by Wind: Horizontal clearances are to be applied with the conductor displaced from rest by a 6 psf wind at final sag at
60°F. The displacement of the conductor is to include deflection of suspension insulators and deflection of flexible structures.
The clearances shown are for the displaced conductors and do not provide for the horizontal distance required to account for blowout of
the conductor and the insulator string. This distance is to be added to the required clearance. See Equation 5-1.
Clearances are based on the Maximum Operating Voltage
Nominal voltage, Phase to Phase, kVL-L
34.5
& 46
-------
Max. Operating Voltage, Phase to Phase, kVL-L
Max. Operating Voltage, Phase to Ground, kVL-G
Horizontal Clearances - (Notes 1,2,3)
1.0 From a lighting support, traffic signal support
or supporting structure of another line
At rest
(NESC Rule 234B1a)
Displaced by wind (NESC Rule 234B1b)
2.0 From buildings, walls, projections, guarded
windows, windows not designed to open,
balconies, and areas accessible to pedestrians
At rest
(NESC Rule 234C1a)
Displaced by wind (NESC Rule 234C1b)
3.0 From signs, chimneys, billboards, radio, & TV
antennas, tanks & other installations not
classified as buildings
At rest
(NESC Rule 234C1a)
Displaced by wind (NESC Rule 234C1b)
4.0 From portions of bridges which are readily
accessible and supporting structures are not
attached
At rest
(NESC Rule 234D1a)
Displaced by wind
(NESC Rule 234D1b)
5.0 From portions of bridges which are ordinarily
inaccessible and supporting structures are not
attached
At rest
(NESC Rule 234D1a)
Displaced by wind (NESC Rule 234D1b)
69
115
138
161
230
72.5
41.8
120.8
69.7
144.9
83.7
169.1
97.6
241.5
139.4
NESC
Basic
Clear
Clearances in feet
5.0
4.5
6.5
6.2
6.5
6.7
7.2
7.6
7.6
8.1
8.1
8.5
9.5
9.9
7.5
4.5
9.2
6.2
9.7
6.7
10.6
7.6
11.1
8.1
11.5
8.5
12.9
9.9
7.5
4.5
9.2
6.2
9.7
6.7
10.6
7.6
11.1
8.1
11.5
8.5
12.9
9.9
7.5
4.5
9.2
6.2
9.7
6.7
10.6
7.6
11.1
8.1
11.5
8.5
12.9
9.9
6.5
4.5
8.2
6.2
8.7
6.7
9.6
7.6
10.1
8.1
10.5
8.5
11.9
9.9
Bulletin 1724E-200
Page 5-3
TABLE 5-1 (continued)
RECOMMENDED DESIGN HORIZONTAL CLEARANCES (in feet) FROM CONDUCTORS
AT REST AND DISPLACED BY 6 PSF WIND TO OTHER SUPPORTING STRUCTURES,
BUILDINGS AND OTHER INSTALLATIONS
(NESC Rules 234B, 234C, 234D, 234E, 234F, 234I, Tables 234-1, 234-2, 234-3)
Conditions under which clearances apply:
No wind: When the conductor is at rest the clearances apply at the following conditions: (a) 120°F, final sag, (b) the
maximum operating temperature the line is designed to operate, final sag, (c) 32°F, final sag with radial thickness of ice
for the loading district (1/4 in. for Medium or 1/2 in. Heavy).
Displaced by Wind: Horizontal clearances are to be applied with the conductor displaced from rest by a 6 psf wind at final sag
at 60°Funder extreme wind conditions (such as the 50 or 100-year mean wind) at final sag at 60°F. The displacement of the
conductor is to include deflection of suspension insulators and deflection of flexible structures.
The clearances shown are for the displaced conductors and do not provide for the horizontal distance required to account for
blowout of the conductor and the insulator string. This distance is to be added to the required clearance. See Equation 5-1.
Clearances are based on the Maximum Operating Voltage
Nominal voltage, Phase to Phase, kVL-L
Max. Operating Voltage, Phase to Phase, kVL-L
Max. Operating Voltage, Phase to Ground, kVL-G
Horizontal Clearances - (Notes 1,2,3)
34.5
& 46
-------
69
115
138
161
230
72.5
41.8
120.8
69.7
144.9
83.7
169.1
97.6
241.5
139.4
NESC
Basic
Clear
6.0 Swimming pools – see section 4.4.3 of
Chapter 4 and item 9 of Table 4–2.
(NESC Rule 234E)
Clearance in any direction from swimming
25.0
pool edge (Clearance A, Figure 4-2 of this bulletin)
Clearance in any direction from diving
17.0
structures (Clearance B, Figure 4-2 of this bulletin)
7.0 From grain bins loaded with permanently
attached conveyor
At rest
(NESC Rule 234F1b)
15.0
Displaced by wind (NESC Rule 234C1b)
4.5
8.0 From grain bins loaded with a portable conveyor.
Height ‘V’ of highest filling or probing port on bin
must be added to clearance shown. Clearances for ‘at
rest’ and not displaced by the wind. See NESC
Figure 234-4 for other requirements.
Horizontal clearance envelope (includes area of
sloped clearance per NESC Figure 234-4b)
9.0 From rail cars (Applies only to lines parallel to
tracks) See Figure 234-5 and section 234I (Eye) of
the NESC
Clearance measured to the nearest rail
ALTITUDE CORRECTION TO BE ADDED TO VALUES ABOVE
Additional feet of clearance per 1000 feet of altitude above
3300 feet
Clearances in feet
27.2
27.7
28.6
29.1
29.5
30.9
19.2
19.7
20.6
21.1
21.5
22.9
17.2
6.7
17.7
7.2
18.6
8.1
19.1
8.6
19.5
9.0
20.9
10.4
(24+V) + 1.5V (Note 3)
14.1
.02
14.1
15.1
15.6
16.0
17.5
.02
.05
.07
.08
.12
Notes:
1. Clearances for categories 1-5 in the table are approximately 1.5 feet greater than NESC clearances.
2. Clearances for categories 6 to 9 in the table are approximately 2.0 feet greater than NESC clearances.
3. “V” is the height of the highest filling or probing port on a grain bin. Clearance is for the highest voltage of 230 kV.
Bulletin 1724E-200
Page 5-4
5.2.2 Considerations in Establishing Radial and Horizontal Clearances to Vegetation:
The designer should identify and document clearances between vegetation and any overhead,
ungrounded supply conductors, taking into consideration transmission line voltage, the effects of
ambient temperature on conductor sag under maximum design loading, and the effects of wind
velocities on conductor sway. Specifically, the designer should establish clearances to be
achieved at the time of vegetation management work and should also establish and maintain a set
of clearances to prevent flashover between vegetation and overhead ungrounded supply
conductors. As a mimimum, these clearances should apply to all transmission lines operated at
200 kV phase-to-phase and above and to any lower voltage lines designated as critical (refer to
NERC FAC 003).
The designer should determine and document appropriate clearance distances to be achieved at
the time of transmission vegetation management work based upon local conditions and the
expected time frame in which the Transmission Owner plans to return for future vegetation
management work. Local conditions may include, but are not limited to: operating voltage,
appropriate vegetation management techniques, fire risk, reasonably anticipated tree and
conductor movement, species types and growth rates, species failure characteristics, local
climate and rainfall patterns, line terrain and elevation, location of the vegetation within the
span, and worker approach distance requirements.
The designer should determine and document specific radial clearances to be maintained
between vegetation and conductors under all rated electrical operating conditions. These
minimum clearance distances are necessary to prevent flashover between vegetation and
conductors and will vary due to such factors as altitude and operating voltage. These specific
minimum clearance distances should be no less than those set forth in the Institute of Electrical
and Electronics Engineers (IEEE) Standard 516-2003 (Guide for Maintenance Methods on
Energized Power Lines) and as specified in its Section 4.2.2.3, Minimum Air Insulation
Distances without Tools in the Air Gap. Where transmission system transient overvoltage factors
are not known, clearances shall be derived from Table 5, IEEE 516-2003, phase-to-ground
distances, with appropriate altitude correction factors applied.Where transmission system
transient overvoltage factors are known, clearances shall be derived from Table 7, IEEE 5162003, phase-to-phase voltages, with appropriate altitude correction factors applied. Table 5-2
contains radial clearances determined from Table 5, IEEE 516-2003, where transmission system
transient overvoltage factors are not known.
i
Sf
Ø
xv
yv
FIGURE 5-2: RADIAL CLEARANCE REQUIREMENT TO VEGETATION
Bulletin 1724E-200
Page 5-5
where:
φ
=
Sf =
xv =
ℓi =
y
=
δ =
conductor swing out angle in degrees under all rated operating
conditions
conductor final sag at all rated operating conditions
radial clearance (include altitude correction if necessary)
insulator string length (ℓi = 0 for post insulators or restrained
suspension insulators).
horizontal clearance at the time of vegetation management work
structure deflection at all rated operating conditions
TABLE 5-2
RADIAL OPERATING CLEARANCES (in feet) FROM IEEE 516 FOR USE IN
DETERMINING CLEARANCES TO VEGETATION FROM CONDUCTORS
(NERC Standard FAC-003.1 Transmission Vegetation Management Program, IEEE 516,
Guideline For Maintenance Methods Of Energized Power Lines)
Conditions under which clearances apply:
Displaced by Wind: Radial operating clearances are to be applied at all rated operating conditions.The designer should
determine applicable conductor temperature and wind conditions for all rated operating conditions. The displacement of the
conductor is to include deflection of suspension insulators and deflection of flexible structures.
The operating clearances shown are for the displaced conductors and do not provide for the horizontal distance required to
account for blowout of the conductor and the insulator string. This distance is to be added to the required clearance. See
Equation 5-1.
Clearances are based on the Maximum Operating Voltage.
Nominal voltage, Phase to Phase, kVL-L
Max. Operating Voltage, Phase to Phase, kVL-L
Max. Operating Voltage, Phase to Ground, kVL-G
Radial Table 5 IEEE Standard 516 Operating
Clearances
34.5
& 461
-------
691
1151
1381
1611
2301,2
72.5
41.8
120.8
69.7
144.9
83.7
169.1
97.6
241.5
139.4
Clearances in feet
Operating clearance at all rated operating
conditions
1.8
1.8
1.9
2.3
2.5
2.7
Design adder for survey and installation tolerance
1.5 feet for all voltages
Design adder for vegetation
Determined by designer (see Note 3 below)
ALTITUDE CORRECTION TO BE ADDED TO VALUES ABOVE
Additional feet of clearance per 1000 feet of altitude above
.02
.02
.05
.07
.08
.12
3300 feet
Notes:
1.
2.
3.
These clearances apply to all transmission lines operated at 200 kV phase-to-phase and above and to any lower
voltage lines designated as critical (refer to NERC FAC 003).
The 230 kV clearance is based on 3.0 Per Unit switching surge.
The design adder for vegetation, applied to conductors displaced by wind, should account for reasonably anticipated
tree movement, species types and growth rates, species failure characteristics, and local climate and rainfall patterns.
The design adder for vegetation, applied to conductors at rest, should account for worker approach distances in
addition to the aforementioned factors.
Bulletin 1724E-200
Page 5-6
5.2.3 Clearances to Grain Bins: The NESC has defined clearances from grain bins based on
grain bins that are loaded by permanent or by portable augers, conveyers, or elevator systems.
In NESC Figure 234-4(a), the horizontal clearance envelope for permanent loading equipment is
graphically displayed and shown Figure 5-2.
P = probe clearance, item 7, Table 4-2
H = horizontal clearance, item 7, Table 5-1
T = transition clearance
V1 = vertical clearance, item 2&3,
Table 4-2
V2 = vertical clearance, Table 4-1
FIGURE 5-3: CLEARANCE TO
GRAIN BINS
NESC FIGURE 234-4a
V1
P
T
V2
H
Permanent
Elevator
V1
V1
P
Probe
Ports
V1
P
T
Grain Bin
Grain Bin
H
V2
From IEEE/ANSI C2-2007, National Electrical Safety Code, Copyright 2006. All rights reserved.
Because the vertical distance from the probe in Table 4-2, item 7.0, is greater than the horizontal
distance, (see Table 5-1, item 7.0), the user may want to simplify design and use this distance as
the horizontal clearance distance as shown below:
No overhead lines
FIGURE 5-4: HORIZONTAL
CLEARANCE TO GRAIN
BINS, CONDUCTORS AT REST
P = clearance from item 7, Table 4-2
P
Permanent
Elevator
Grain Bin
FIGURE 5-5: HORIZONTAL
CLEARANCE TO GRAIN BINS,
CONDUCTORS DISPLACED
BY 6 PSF WIND
P
Probe
Ports
Grain Bin
No Overhead Lines
Item 7.0
Table 5-1
Permanent
Elevator
Grain Bin
or Table 5-2
Probe
Ports
Grain Bin
Bulletin 1724E-200
Page 5-7
The clearance envelope for portable loading equipment from NESC Figure 234(b), is shown in
1.5
Figure 5-6.
1
1.5
18'
1
15'
H
V
See NESC Rule 232
See NESC Rule 232
V=Height of highest filling or probing port on grain bin
H=V- 18'
1.5:1
slope
1.5:1
slope
Flat top of
clearance
envelope
1.5:1
slope
LOADING
SIDE
15'
H
NON-LOADING
SIDE
1.5:1
slope
NESC
RULE 232
AREA
AREA OF SLOPED
CLEARANCE
1.5:1
slope
FIGURE 5-6: NESC CLEARANCE TO GRAIN BINS WITH
PORTABLE LOADING EQUIPMENT
From IEEE/ANSI C2-2007, National Electrical Safety Code, Copyright 2006. All rights reserved.
In order to simplify the clearance envelope, the horizontal clearances in category 8 of Table 5-1
is shown as ‘H’ in the drawing below:
LOADING SIDE
No Overhead
Lines
NON-LOADING
15'
H
FIGURE 5-7: SIMPLIFIED RECOMMENDATIONS FOR CLEARANCES
TO GRAIN BINS WITH PORTABLE LOADING EQUIPMENT
5.2.4 Altitude Greater Than 3300 Feet: If the altitude of the transmission line or portion
thereof is greater than 3300 feet, an additional clearance as indicated in Table 5-1 and 5-2 has to
be added to the base clearance given.
Bulletin 1724E-200
Page 5-8
5.2.5 Total Horizontal Clearance to Point of Insulator Suspension to Object: As can be
seen from Figure 5-1, the total horizontal clearance (y) is:
y = (l i + S f )sin φ + x + δ
Eq. 5-1
Symbols are defined in Section 5.2.1 and figure 5-1. The factor "δ" indicates that structure
deflection should be taken into account.
For the sake of simplicity when determining horizontal clearances, the insulator string should be
assumed to have the same swing angle as the conductor. This assumption should be made only
in this chapter as its use in calculations elsewhere may not be appropriate.
The conductor swing angle ( φ ) under wind can be determined from the formula.
φ = tan
where:
−1
⎛ (d c )(F ) ⎞
⎟⎟
⎜⎜
⎝ 12 w c ⎠
Eq. 5-2
dc = conductor diameter in inches
wc = weight of conductor in lbs./ft.
F = wind force;
The total horizontal distance (y) at a particular point in the span depends upon the conductor sag
at that point. The value of (y) for a structure adjacent to the maximum sag point will be greater
than the value of (y) for a structure placed elsewhere along the span. See Figure 5-7.
Conductor
position with no
wind blowing.
Conductor in blown
out position.
Top view of line
y
x
x = clearance from wind-displaced conductor, y= total horizontal clearance from conductor at
rest
FIGURE 5-8: A TOP VIEW OF A LINE SHOWING TOTAL
HORIZONTAL CLEARANCE REQUIREMENTS
Bulletin 1724E-200
Page 5-9
5.2.6 Examples of Horizontal Clearance Calculations: The following examples demonstrate
the derivation of the horizontal clearance in Table 5-1 of this bulletin.
To determine the horizontal clearance of a 115 kV line to a building (category 2.0 of Table 5-1),
the clearance is based on NESC Table 234-1 and NESC Rule 234.
At rest:
NESC Horizontal Clear.
NESC Horizontal Clear.
= NESC Basic Clearance(Table 234-1) + .4(kVL-G – 22)/12
= 7.5 feet + .4(69.7-22)/12 feet
= 7.5 feet + 1.59 feet
= 9.09 feet
Recommended Clearance = NESC Horizontal Clearance + Adder
= 9.09 feet + 1.5 feet
y = 10.59 feet (10.60 feet in Table 5-1)
Conductors displaced by 6 psf wind:
NESC Horizontal Clear. = NESC Basic Clearance (Table 234-1) + .4(kVL-G – 22)/12
= 4.5 feet + .4(69.7-22)/12 feet
= 4.5 feet + 1.59 feet
NESC Horizontal Clear. = 6.09 feet
Recommended Clearance = NESC Horizontal Clearance + Adder
= 6.09 feet + 1.5 feet
x = 7.59 feet (7.6 feet in Table 5-1)
5.3 Right-of-Way (ROW) Width: For transmission lines, a right-of-way provides an
environment allows the line to be operated and maintained safely and reliably. Determination of
the right-of-way width is a task that requires the consideration of a variety of judgmental,
technical, and economic factors.
Typical right-of-way widths (predominantly H-frames) that have been used by agency borrowers
in the past are shown in Table 5-2. In many cases a range of widths is provided. The actual
width used will depend upon the particulars of the line design.
TABLE 5-3
TYPICAL RIGHT-OF-WAY WIDTHS
Nominal Line-to-Line Voltage in kV
ROW Width, ft.
69
115
138
161
230
75-100
100
100-150
100-150
125-200
5.4 Calculation of Right-of-Way Width for a Single Line of Structures on a Right-of-Way:
Right-of-way widths can be calculated using the method described below. The calculated values
for right-of-way widths are directly related to the particular parameters of the line design. This
method provides sufficient width to meet clearance requirements to buildings of undetermined
height or vegetation located directly on the edge of the right-of-way. See Figures 5-8 and 5-9.
Bulletin 1724E-200
Page 5-10
i
Sf
Ø
x
y
A
W
FIGURE 5-9: ROW WIDTH FOR SINGLE LINE OF STRUCTURES
(
)
W = A + 2 l i + S f sin φ + 2δ + 2 x
Eq. 5-3
where:
W = total right-of-way width required
A = separation between points of suspension of insulator
strings for outer two phases
x = clearance required per Table 5-1 and appropriate
clearance derived from Table 5-2 of this bulletin
(include altitude correction if necessary)
y = clearance required per Section 5.2.1 and Table 5-1 and
appropriate clearance derived from Section 5.2.2. and
Table 5-2 of this bulletin (include altitude correction if
necessary)
Other symbols are as previously defined. In some instances, clearance “x”
may control. In other instances, clearance “y” may control.
There are two ways of choosing the length (and thus the sag) on which the right-of-way width is
based. One is to use a width based on the maximum span length in the line. The other way is to
base the width on a relatively long span, (the ruling span, for instance), but not the longest span.
For those spans that exceed this base span, additional width is added as appropriate.
5.5 Right-of-Way Width for a Line Directly Next to a Road: The right-of-way width for a
line next to a road can be calculated based on the two previous sections with one exception. No
ROW is needed on the road side of the line as long as the appropriate clearances to existing or
possible future structures on the road side of the line are met.
If a line is to be placed next to a roadway, consideration should be given to the possibility that
the road may be widened. If the line is on the road right-of-way, the borrower would generally
be expected to pay for moving the line. If the right-of-way is on private land, the highway
Bulletin 1724E-200
Page 5-11
department should pay. Considerations involved in placing a line on a road right-of-way should
also include evaluation of local ordinances and requirements.
5.6 Right-of-Way Width for Two or More Lines of Structures on a Single Right-of-Way:
To determine the right-of-way width when the right ROW contains two parallel lines, start by
calculating the distance from the outside phases of the lines to the ROW edge (see Section 5.4).
The distance between the two lines is governed by the two criteria provided in section 5.6.1. If
one of the lines involved is an extra high voltage (EHV) line (345 kV and above), the NESC
should be referred to for additional applicable clearance rules not covered in this bulletin.
5.6.1 Separation Between Lines as Dictated by Minimum Clearance Between Conductors
Carried on Different Supports: The horizontal clearance between a phase conductor of one
line to a phase conductor of another line shall meet the larger of C1, or C2 below, under the
following conditions: (a) both phase conductors displaced by a 6 psf wind at 60°F, final sag; (b)
if insulators are free to swing, one should be assumed to be displaced by a 6 lbs/sq. ft. wind
while the other should be assumed to be unaffected by the wind (see Figure 5-10). The assumed
wind direction should be that which results in the greatest separation requirement. It should be
noted that in the Equations 5-5, and 5-6, the ‘δ1-δ2’ term, (the differential structure deflection
between the two lines of structures involved), is to be taken into account. An additional 1.5 feet
have been added to the NESC clearance to obtain design clearances ‘C1’and ‘C2’. Note Equation
5-6 has been revised from previous versions due to the voltage adder change in the 2007 NESC
edition.
C1 = 6.5 + (δ 1 − δ 2 ) (NESC Rule 233B1)
C 2 = 6.5 +
.4
[(kVLG1 + kVLG 2 ) − 22] + (δ 1 − δ 2 ) (NESC Rule 233B1)
12
where:
C1,C2 = clearance requirements between conductors on
different lines in feet (largest value governs)
kVLG1 = maximum line-to-ground voltage in kV of line 1
kVLG2 = maximum line-to-ground voltage in kV of line 2
δ1 = deflection of the upwind structure in feet
δ2 = deflection of the downwind structure in feet
δ1
δ2
C1 ,C 2
FIGURE 5-10: CLEARANCE BETWEEN CONDUCTORS OF ONE LINE
TO CONDUCTOR OF ANOTHER LINE
Eq. 5-5
Eq. 5-6
Bulletin 1724E-200
Page 5-12
5.6.2 Separation Between Lines as Dictated by Minimum Clearance of Conductors From
One Line to the Supporting Structure of Another: The horizontal clearance of a phase
conductor of one line to the supporting structure of another when the conductor and insulator are
displaced by a 6 psf wind at 60°F final sag should meet Equation 5-7.
C3 = 6'+
where:
.4
(kVLG − 22) + (δ1 − δ 2 )
12
Eq. 5-7
kVLG = the maximum line-to-ground voltage in kV
C3 = the clearance of conductors of one line to structure of
another in feet
Other symbols are defined in Figure 5-1.
Additional 1.5 feet have been added to the NESC clearance and included in equation 5-7 to
obtain the design clearance ‘C3’.
.
δ1
δ2
C3
FIGURE 5-11: CLEARANCE BETWEEN CONDUCTORS OF ONE LINE
AND STRUCTURE OF ANOTHER
The separation between lines will depend upon the spans and sags of the lines as well as how
structures of one line match up with structures of another. In order to avoid the unreasonable
task of determining separation of structures span-by-span, a standard separation value should be
used, based on a worst case analysis. Thus if structures of one line do not always line up with
those of the other, the separation determined in section 5.6.2 should be based on the assumption
that the structure of one line is located next to the mid-span point of the line that has the most
sag.
5.6.3 Other Factors: Galloping should be taken into account in determining line separation. In
fact, it may be the determining factor in line separation. See Chapter 6 for a discussion of
galloping.
Bulletin 1724E-200
Page 5-13
Standard phase spacing should also be taken into account. For example, if two lines of the same
voltage using the same type structures and phase conductors are on a single ROW, a logical
separation of the two closest phases of the two lines should be at least the standard phase
separation of the structure.
5.6.4 Altitude Greater than 3300 Feet: If the altitude at which the lines included in the design
are installed greater than 3300 feet, NESC Section 23 rules provide additional separation
requirements.
Bulletin 1724E-200
Page 5-14
BLANK PAGE
Bulletin 1724E-200
Page 6-1
6. CLEARANCES BETWEEN CONDUCTORS AND BETWEEN CONDUCTORS AND
OVERHEAD GROUND WIRES
6.1 General: The preliminary comments and assumptions of Chapter 4, section 4.2, also apply
to this chapter.
This chapter considers design limits related to conductor separation. It is assumed that only
standard agency structures will be used, thus making it unnecessary to check conductor
separation at structures. Therefore, the only separation values left to consider are those related to
span length and conductor sags.
Maximum span lengths may be controlled by conductor separation. Other factors which may
limit span length, but are not covered in this chapter, are structure strength, insulator strength,
and ground clearance.
6.2 Maximum Span as Limited by Horizontal Conductor Separation: Sufficient horizontal
separation between phases is necessary to prevent swinging contacts and flashovers between
conductors where there is insufficient vertical separation.
6.2.1 Situations Under Which Maximum Span as Limited by Horizontal Separation are to
be Met:
If the vertical separation
(regardless of horizontal
displacement) of phase
conductors of the same or
different circuit(s) at the
structure is less than the
appropriate values provided in
Table 6-1,then the
recommendations in sections
6.2.2, 6.2.3, and 6.2.4 of this
section should be met.
H
V
FIGURE 6-1: EXAMPLE OF VERTICAL AND HORIZONTAL
SEPARATION VALUES
6.2.2 Horizontal Separation Recommendations: Equation 6-1 gives an horizontal phase
spacing (relative to conductor sag, and thus indirectly to span length) that should be sufficient to
prevent swinging contacts or flashovers between phases of the same or different circuits.
H = (0.025)kV + Fc S f + l i (sin φmax )
Eq. 6-1
Bulletin 1724E-200
Page 6-2
where:
H = horizontal separation between the phase conductors at the
structure in feet.
kV = (phases of the same circuit) the nominal line-to-line voltage
in 1000's of volts for 34.5 and 46 kV and 1.05 times the
nominal voltage in 1000's of volts for higher voltages
kV = (phases of different circuits) 1.05 times the magnitude of the
voltage vector between the phases in 1000's of volts. kV
should never be less than 1.05 times the nominal line-toground voltage in 1000's of volts of the higher voltage circuit
involved regardless of how the voltage vectors add up. The
voltage between the phases should be taken as the sum of the
two line-to-ground voltages, based on 1.05 times nominal
voltage.
Fc = experience factor
Ømax = maximum 6 psf insulator swing angle for the structure in
question. See Chapter 7 of this bulletin.
Sf = final sag of the conductor at 60°F, no load, in feet
l i = length of the insulator string in feet, l i = 0 for post or
restrained suspension insulators
V = vertical separation between phase conductors
at the structure in feet
The experience factor (Fc) may vary from a minimum of 0.67 to a maximum of 1.4, depending
upon how severe the wind and ice conditions are judged to be. The following are values of Fc
that have proved to be satisfactory in the past.
Fc = 1.15 for the light loading zone
Fc = 1.2 for the medium loading zone
Fc = 1.25 for the heavy loading zone
Any value of Fc in the 0.67 to 1.4 range may be used if it is thought to be reasonable and
prudent. There has been significant favorable experience with larger conductor sizes that have
horizontal spacing based on an Fc factor of 0.67. Therefore, Fc factor values significantly less
than the values listed above may be appropriate. If Fc values less than those given above are
used, careful attention should be paid to galloping as a possible limiting condition on the
maximum span length.
Bulletin 1724E-200
Page 6-3
TABLE 6-1
RECOMMENDED VERTICAL SEPARATION IN FEET BETWEEN PHASES
OF THE SAME OR DIFFERENT CIRCUITS ATTACHED TO THE SAME STRUCTURE
(For separations less than those shown, Equation 6-1 applies) (See Notes E & F)
Nominal voltage, Line-to-Line Voltage in kV
Max. Operating Voltage, Phase to Phase, kV
Max. Operating Voltage, Phase to Ground, kV
34.5 &
46
-------
69
115
138
161
230
72.5
41.8
120.8
69.7
144.9
83.7
169.1
97.6
241.5
139.4
Vertical Separation
Separation in feet
Minimum Vertical Separation at Support
1. Phases of the same circuit (Note A)
(Based on NESC Table 235-5)
3.2
4.0
5.6
6.4
7.2
9.6
2. Phases of different circuits (Notes B & D)
(Based on NESC Table 235-5,footnote 7
criteria for different utilities)
5.4
6.3
8.2
9.1
10.1
12.8
3. Phase conductors and overhead ground
wires (Based on NESC 235C and 233C3)
Minimum Vertical Separation in Span
2.5
2.9
3.9
4.3
4.8
6.4
4. Phases of the same circuit (Notes A & G)
(Based on NESC Table 235-5), H ≥ 1.0 ft.,
Figure 6-4
2.5
3.3
4.9
5.7
6.5
9.0
5. Phases of different circuits (Notes C, D & G)
(Based on NESC Table 235-5, footnote
7 criteria for different utilities NESC Rule
235C2b.), H ≥ 1.0 ft.,
Figure 6-4
4.2
5.2
7.0
7.9
8.9
11.7
6. Phase conductors and overhead ground
1.5
2.1
3.0
3.6
4.0
wires (H ≥ 1.0 ft., Figure 6-4), Notes D & G
ALTITUDE CORRECTION TO BE ADDED TO VALUES IN CATEGORY ‘2’ ABOVE (NONE
REQUIRED FOR CATEGORY ‘1’):
5.4
Additional feet of clearance per 1000 feet of
altitude above 3300 feet
.12
.02
.02
.05
.07
.08
Notes:
(A) There are no NESC values specified for vertical separation of conductors of the same circuit for
voltages above 50 kV line-to-line.
(B) Assumes both circuits have the same nominal voltage. If they do not, the vertical separation can be
determined using Equation 6-2 below.
V=
40 .4
6
+ (kVLG1 + kVLG 2 − 8.7 ) + ( NoteD )
12 12
12
where:
kVLG1
kVLG 2
=
=
Line to ground voltage circuit one, kilovolts.
Line to ground voltage circuit two, kilovolts.
Eq. 6-2
Bulletin 1724E-200
Page 6-4
TABLE 6-1 (continued)
RECOMMENDED VERTICAL SEPARATION IN FEET BETWEEN PHASES
OF THE SAME OR DIFFERENT CIRCUITS ATTACHED TO THE SAME STRUCTURE
(For separations less than those shown, Equation 6-1 applies) (See Notes E & F)
(C) Assumes both circuits have the same nominal voltage. If they do not, the vertical separation can be
determined using Equation 6-2a below.
6
⎡ 40 .4
⎤ .4
V = .75⎢ + (50 − 8.7)⎥ + (kVLG1 + kVLG 2 − 50) + ( NoteD ) Eq. 6-2a
12
⎣ 12 12
⎦ 12
(D) An additional 0.5 feet of clearance is added to the NESC clearance to obtain the recommended
design clearances.
(E) The values in this table are not recommended as minimum vertical separations at the structure for
non-standard agency structures. They are intended only to be used on standard agency structures to
determine whether or not horizontal separation calculations are required.
(F) The upper conductor is at final sag at the maximum operating temperature and the lower conductor
is at final sag at the same ambient conditions as the upper conductor without electrical loading and
without ice loading; or, the upper conductor is at final sag at 32º with radial ice from either the medium
loading district or the heavy loading district and the lower conductor is at final sag at 32ºF.
(G) In areas subjected to icing, an additional 2.0 feet of clearance should be added to the above
clearances when conductors or wires are directly over one another or have less than a one foot
horizontal offset. See section 6.3 of this bulletin.
6.2.3 Additional Horizontal Separation Equation: Equation 6-3 below, commonly known as
the Percy Thomas formula, may be used in addition to (but not instead of) equation 6-1 for
determining the horizontal separation between the phases at the structure. Equation 6-3 takes
into account the weight, diameter, sag, and span length of the conductor.
H = (.025)kV +
(Ec )(d c )(S p )
wc
+
li
2
Eq. 6-3
where:
dc = conductor diameter in inches
wc = weight of conductor in lbs/ft.
Ec = an experience factor. It is generally recommended that (Ec)
be larger than 1.25.
Sp = sag of conductor at 60°F, expressed as a percent of span
length
All other symbols are as previously defined.
By using the Thomas formula to determine values of Ec, the spacing of conductors on lines
which have operated successfully in a locality can be examined. These values of Ec may be
helpful in determining other safe spacings.
6.2.4 Maximum Span Based on Horizontal Separation at the Structure: Equation 6-1 can
be rewritten and combined with Equation 10-1 (Chapter 10) to yield the maximum allowable
Bulletin 1724E-200
Page 6-5
span, given the horizontal separation at the structure and the sag and length of the ruling span.
See Chapter 9 for a discussion of ruling span.
⎛ H − (.025)kV − l i sin φmax ⎞
⎟
Eq. 6-4
Lmax = (RS )⎜
⎜
⎟
F
S
c
RS
⎝
⎠
where:
Lmax = maximum span as limited by conductor separation in feet
RS = length of ruling span in feet
SRS = sag of the ruling span at 60°F final sag in feet
Other symbols are as previously defined for Eq. 6-1.
6.2.5 Maximum Span Based on Vertical Separation: Since vertical separation is related to
the relative sags of the phase conductors involved, and since sags are related to span length, a
maximum span as limited by vertical separation can be determined. The formula for the
maximum span as limited by vertical separation is:
Lmax = (RS )
where:
Lmax
Dv
B
Sl
Su
RS
=
=
=
=
=
=
Dv − B
Sl − Su
Eq. 6-5
maximum allowable span in feet
required vertical separation at mid-span in feet
vertical separation at supports in feet
sag of lower conductor in feet without ice
sag of upper conductor wire in feet with ice
ruling span in feet
6.2.6 Example of Clearance Calculations: The following example demonstrates the derivation
of the vertical separation at a support for phases of different circuits in Tables 6-1 of this bulletin.
To determine the vertical separation of a 115 kV line to another 115 kV circuit, the clearance is
based on NESC Table 235-5 and NESC Rule 235.
At the support, phases of different circuits:
NESC Vertical Separation = 40 inches/12 in./ft + .4(kVL-G + kVL-G – 8.7)/12 ft.
= 3.333 ft. + .4(69.7+69.7-8.7)/12 ft.
= 3.33 ft.+ 4.36 ft.
NESC Vertical Separation = 7.69 feet
Recommended
Vertical Separation
= NESC Vertical Separation + suggested Adder
= 7.69 feet + 0.5 feet
= 8.19 feet (8.2 feet in Table 6-1)
Bulletin 1724E-200
Page 6-6
In the span, phases of different circuits:
NESC Vertical Separation
⎡ 40 .4
⎤ .4
= 0.75⎢ + (50 − 8.7)⎥ + (kVLG1 + kVLG 2 − 50)
⎣ 12 12
⎦ 12
= 0.75(3.33+1.37) ft + (.4/12)(69.7+69.7-50) feet
= 3.53 ft. + 2.98 feet
NESC Vertical
Separation in the Span = 6.51 feet
Recommended
Clearance
= NESC Vertical Separation + suggested Adder
= 6.51 feet + .5 feet
= 7.01 feet (7.0 feet in Table 6-1)
6.3 Maximum Span as Limited by Conductor Separation Under Differential Ice Loading
Conditions
6.3.1 General: There is a tendency among conductors covered with ice, for the conductor
closest to the ground to drop its ice first. Upon unloading its ice the lower conductor may jump
up toward the upper conductor, possibly resulting in a temporary short circuit. After the lower
conductor recovers from its initial ice-jump it may settle into a position with less sag than before,
which may persist for long periods of time. If the upper conductor has not dropped its ice, the
reduced separation may result in a flashover between phases.
The clearance recommendations provided in paragraph 6.3.2 of this section are intended to
insure that sufficient separation will be maintained during differential ice loading conditions with
an approach towards providing clearance for the ice-jump.
6.3.2 Clearance Recommendations: The minimum vertical distance (Dv) in span between
phase conductors, and between phase conductors and overhead ground wires under differential
ice loading conditions, are provided in Table 6-1. These vertical separations in span are
recommended in cases where the horizontal separation between conductors (H) is greater than
one foot (H ≥1.0 ft). When conductors or wires are directly over one another or have less than a
1 foot horizontal offset, it is recommended that an additional 2 feet of clearance be added to the
values given in Table 6-1. The purpose of this requirement is to improve the performance of the
line under ice-jump conditions. It has been found that a horizontal offset of as little as 1 foot
significantly lessens the ice-jump problem. Figure 6-4 indicates the horizontal and vertical
components of clearance and their relationship.
Upper
Upperconductor
conductoratat32ºF,
32° Ffinal sag,
ice
for
medium
or
heavy
final sag, maximum ice loading district.
Dv
H
Lower conductor at 32° F,
final sag, no ice.
FIGURE 6-2: MINIMUM DISTANCE BETWEEN CONDUCTORS
Bulletin 1724E-200
Page 6-7
6.3.3 Conditions Under Which Clearances Apply: Lines should be designed so that
clearances are considered with the upper conductor at 32°F, final sag, and a radial thickness of
ice equal to the ice thickness from either the medium loading district or the heavy loading
district. The lower conductor should be at 32°F, final sag, no ice. The designer is reminded to
check clearances for the upper conductor at the maximum operating temperature (no wind) and
the lower conductor at ambient temperature (see Note F of Table 6-1).
6.4 Overhead Ground Wire Sags and Clearances: In addition to checking clearances
between the overhead ground wire (OHGW) and phase conductors under differential ice loading
conditions, it is also important that the relative sags of the phase conductors and the OHGW be
coordinated so that under more commonly occurring conditions, there will be a reasonably low
chance of a mid-span flashover. Adequate midspan separation is usually assured for standard
agency structures by keeping the sag of the OHGW at 60°F initial sag, no load conditions to
80 percent of the phase conductors under the same conditions.
6.5 Maximum Span as Limited by Galloping
6.5.1 The Galloping Phenomenon: Galloping, sometimes called dancing, is a phenomenon
where the transmission line conductors vibrate with very large amplitudes. This movement of
conductors may result in: (1) contact between phase conductors or between phase conductors
and overhead ground wires, resulting in electrical outages and conductor burning, (2) conductor
failure at support point due to the violent stress caused by galloping, (3) possible structure
damage, and (4) excessive conductor sag due to the overstressing of conductors.
Galloping usually occurs only when a steady, moderate wind blows over a conductor covered by
a layer of ice deposited by freezing rain, mist or sleet. The coating may vary from a very thin
glaze on one side to a solid three-inch cover and may give the conductor a slightly out-of-round,
elliptical, or quasi-airfoil shape. The wind blowing over this irregular shape results in
aerodynamic lift which causes the conductor to gallop. The driving wind can be anything
between 5 to 45 miles per hour at an angle to the line of 10 to 90 degrees and may be unsteady in
velocity or direction.
During galloping, the conductors oscillate elliptically at frequencies on the order of 1-Hz or less
with vertical amplitudes of several feet. Sometimes two loops appear, superimposed on one
basic loop. Single-loop galloping rarely occurs in spans over 600 to 700 feet. This is fortunate
since it would be impractical to provide clearances large enough in long spans to prevent the
possibility of contact between phases. In double-loop galloping, the maximum amplitude usually
occurs at the quarter span points and is smaller than that resulting from single-loop galloping.
There are several measures that can be incorporated at the design stage of a line to reduce
potential conductor contacts caused by galloping, such as designing the line to have shorter
spans, or increased phase separation. The H-frame structures provide very good phase spacing
for reducing galloping contacts.
6.5.2 Galloping Considerations in the Design of Transmission Lines: In areas where
galloping is either historically known to occur or is expected, designers should indicate design
measures that will minimize galloping and galloping problems, especially conductor contacts.
The primary tool for assuring absence of conductor contacts is to superimpose Lissajous ellipses
over a scaled diagram of the structure to indicate the theoretical path of a galloping conductor.
See Figures 6-3 and 6-4. To avoid contact between phase conductors or between phase
conductors and overhead ground wires, none of the conductor ellipses should touch one another.
However, if galloping is expected to be infrequent and of minimal severity, there may be
situations where allowing ellipses to overlap may be the favored design choice when economics
are considered.
Bulletin 1724E-200
Page 6-8
FIGURE 6-3: GUIDE FOR PREPARATION
OF LISSAJOUS ELLIPSES
POINT OF SUSPENSION
INSULATOR SUPPORT
POINT OF CONDUCTOR
ATTACHMENT
⎛ pc
⎝ wc
φ = tan −1 ⎜⎜
i
Ø
Si
⎞
⎟⎟
⎠
Eq. 6-6
D
Ø+ Ø
M
2
B
Single Loop
Major Axis
‘M’
M = 1.25 Si + 1.0
Double Loop
Eq. 6-7
2
⎛
⎞
8S i
− 2a ⎟⎟
3a⎜⎜ L +
3L
⎝
⎠
M = 1.0 +
8
Eq. 6-8
2
⎛ L⎞
2
where a = ⎜ ⎟ + Si
⎝2⎠
Distance ‘B’
B = 0.25 Si
Eq. 6-9
Minor Axis
‘D’
D = 0.4M
Eq. 6-11
B = 0.2 M
D = 2 M − 1.0
Eq. 6-10
Eq. 6-12
Where:
pc = wind load per unit length on iced conductor in lbs/ft.
Assume a 2 psf wind.
wc = weight per unit length of conductor plus 1/2 in. of radial ice,
lbs/ft
L = span length in feet.
M = major axis of Lissajous ellipses in feet.
Si = final sag of conductor with 1/2 in. of radial ice,
no wind, at 32°F, in feet.
D = minor axis of Lissajous ellipses in feet.
B,Ø = as defined in figure above
Bulletin 1724E-200
Page 6-9
FIGURE 6-4: SINGLE LOOP GALLOPING ANALYSIS
6.6 Clearance Between Conductors in a Crossarm to Vertical Construction Span:
Conductor contacts in spans changing from crossarm to vertical type construction may be
reduced by proper phase arrangement and by limiting span lengths. Limiting span lengths well
below the average span lengths is particularly important in areas where ice and sleet conditions
can be expected to occur. See Figure 6-5.
1
1
2
2
3
3
1
2
3
1
3
2
FIGURE 6-5: PROPER PHASE ARRANGEMENTS FOR CROSSARM
TO VERTICAL CONSTRUCTION
Bulletin 1724E-200
Page 6-10
Blank Page
Bulletin 1724E-200
Page 7-1
7. INSULATOR SWING AND CLEARANCES OF CONDUCTORS FROM
SUPPORTING STRUCTURES
7.1 Introduction: Suspension insulator strings supporting transmission conductors, either at
tangent or angle structures, are usually free to swing about their points of support. Therefore, it
is necessary to ensure that when the insulators do swing, clearances are maintained to structures
and guy wires. The amount of swing varies with such factors as: conductor tension,
temperature, wind velocity, insulator weight, ratio of weight span to wind span, and line angle.
The force due to line angle will cause suspension strings to swing in the direction of the line
angle of the structure. Wind blowing on the conductor span will exert a force in the direction of
the wind. These two forces may act either in the same direction or in opposite, the algebraic sum
thereby determining the net swing direction. Line angle forces and wind forces also interact with
the vertical forces of the conductor weight and insulator string weight. The vector sum of these
forces determines the net angle from the vertical axis to which the insulator string will swing.
This net insulator swing angle should be calculated for several key weather conditions so that
corresponding phase-to-ground clearances may be checked on a particular pole-top arrangement.
The purpose of this chapter is to explain how insulator swing application guides called swing
charts are prepared. Chapter 10 explains how these charts are used in laying out a line.
7.2 Clearances and Their Application: Table 7-1 provides information on three sets of
clearances that can ensure proper separation between conductors and structures or guys under
various weather conditions. Figure 7-1 illustrates the various situations in which the clearances
are to be applied.
7.2.1 No-Wind Clearance: The no wind clearance provides a balanced insulation system in
which the insulating value of the air gap is approximately the same as that of the insulator string
for a tangent structure. (See Table 8-1 for insulation levels. Note that tangent structures do not
include the extra insulators used with angle structures).
Conditions at which no-wind clearances are to be maintained follow:
•
Wind: Assume no wind.
•
Temperature: Assume a temperature of 60°F. See Figure 7-1 for conductor condition.
The engineer may also want to evaluate clearances at cold conditions (such as -20°F
initial sag) and hot conditions (such as 167°F final sag).
7.2.2 Moderate Wind Clearance: This clearance is the minimum clearance that should be
maintained under conditions that are expected to occur occasionally. A typical condition may be
the wind that reoccurs no less than once every two years (probability of occurrence no more than
50 percent). Clearance values for moderate wind clearance conditions will have a lower
flashover value than clearance values for the no-wind condition. These lower clearance values
are acceptable because under moderate wind conditions, the specified clearance will be sufficient
to withstand most of the severe voltage stress situations for wind conditions that are not expected
to occur often.
There are different clearance requirements to the structure than to anchor guys. See Table 7-1,
moderate wind, for differences. Also, note that Table 7-1 requires that additional clearance must
be provided if the altitude is above 3300 feet.
Conditions at which moderate wind clearances are to be maintained follow:
Bulletin 1724E-200
Page 7-2
•
Wind: Assume a wind of at least 6 psf blowing in the direction shown in Figure 7-1.
Higher wind pressures can be used if judgment and experience deem them to be
necessary. However, the use of excessively high wind values could result in a design that
is overly restrictive and costly. It is recommended that wind pressure values of no higher
than 9 psf (60 mph) be used for the moderate wind clearance design unless special
circumstances exist.
•
Temperature: Temperature conditions under which the clearances are to be maintained
depend upon the type of structure. A temperature of no more than 32°F should be used
for tangent and small angle structures where the insulator string is suspended from a
crossarm. A lower temperature value should be used where such a temperature can be
reasonably expected to occur in conjunction with the wind value assumed. It should be
borne in mind, however, the insulator swing will increase at lower temperatures because
conductor tensions increase. Therefore, in choosing a temperature lower than 32°F, one
should weigh the increase in conservatism of line design against the increase or decrease
in line cost. NESC Rule235 requires a temperature no higher than 60°F final tension.
A temperature of 60°F should be used for angle structures where the force due to change
in direction of the conductor holds the insulator string away from the structure. Even if
the maximum conductor temperature is significantly greater than 60°F, a higher
temperature need not be used as an assumed wind value of 40 mph (6 psf)) has quite a
cooling effect.
Assume final sag conditions for 60°F temperature and initial sag conditions for 32°F.
7.2.3 High Wind Clearance: This is the minimum clearance that should be maintained under
high wind conditions that are expected to occur very rarely. The clearances provide enough of
an air gap to withstand a 60 Hz flashover but not much more. Choice of such values is based on
the philosophy that under very rare high wind conditions, the line should not flashover due to the
60 Hz voltage.
Conditions under which high wind clearances are to be maintained are:
•
Wind: The minimum assumed wind value should be at least the 10-year mean recurrence
interval wind blowing in the direction shown in Figure 7-1. More wind may be assumed
if deemed appropriate.
•
Temperature: The temperature assumed should be that temperature at which the wind is
expected to occur. The conductor should be assumed to be at final tension conditions.
To determine the velocity of the wind for a 10 year return period, the following factors should be
applied to the 50 year peak gust wind speed (See Figures 11-2a, b, c and d in Chapter 11).
V = 85 to100 mph,
Continental U.S.
Alaska
V > 100 mph
(hurricane)
0.84
0.87
0.74
Bulletin 1724E-200
Page 7-3
FIGURE 7-1: ILLUSTRATION OF STRUCTURE INSULATOR SWING ANGLE LIMITS
AND CONDITIONS* UNDER WHICH THEY APPLY (EXCLUDES
BACKSWING)
TANGENT AND
SMALL ANGLE
STRUCTURES
No Wind
Insulator Swing
Moderate Wind
Insulator Swing
High Wind
Insulator Swing
wind
O2
O1
Conditions* at which
clearances are to be
a
maintained
• Line angle
Force due
to line angle (if any)
• Wind force
0
•
Temperature
•
Conductor tension
wind
O3
c
b
Force due
to line angle (if any)
6 psf minimum
60ºF
32ºF or lower
Final tension
Initial tension
MEDIUM AND
LARGE ANGLE
STRUCTURES
Force due
to line angle (if any)
10 year mean wind,
recommended value
Temp. at which wind
value is expected
Final tension
wind
wind
Ø1
a
Conditions* at which
clearances are to be
maintained
• Line angle
Force due
to line angle
• Wind force
0
•
Temperature
•
Conductor tension
b
Ø2
Force due
to line angle
6 psf minimum
60ºF
60ºF or lower
Final tension
Final tension
a = No wind clearance b = Moderate wind clearance
*See text for full explanation of conditions.
c
Ø3
Force due
to line angle
10 year mean wind,
min.recommended
value
Temp. at which wind
value is expected
Final tension
c = High wind clearance
Bulletin 1724E-200
Page 7-4
TABLE 7-1
RECOMMENDED MINIMUM CLEARANCES IN INCHES AT
CONDUCTOR TO SURFACE OF STRUCTURE OR GUY WIRES
Nominal voltage, Phase to Phase,
kV
34.5
46
69
115
138
161
230
Standard Number of 5-3/4”x10”
Insulators on Tangent Structures
3
3
4
7
8
10
12
34.5
46
72.5
120.8
144.9
169.1
241.5
19.9
26.6
41.8
69.7
83.7
97.6
139.4
Max. Operating Voltage, Phase to
Phase, kV
Max. Operating Voltage, Phase to
Ground, kV
Clearance in inches
No Wind Clearance (Not NESC)
Min. clearance to structure or guy at no
wind in inches Notes A, B
19
19
25
42
48
60
71
9
11
16
26
30
35
50
11
13
18
28
32
37
52
13
16
22
34
40
46
64
3
3
5
10
12
14
20
Moderate Wind Clearance
(NESC Table 235-6)
Min. clear. to structure at 6 psf of
wind in inches. Notes C, D
Min. clear. to jointly used structures
and a 6 psf of wind in inches.
Notes C, D
Min. clearance to anchor guys at 6 psf
in inches Notes C, D
High Wind Clearance
(Not NESC)
Min. clearance to structure or guy at
high wind in inches
Notes:
(A) If insulators in excess of the standard number for tangent structures are used, the no wind clearance value
shown should be increased by 6 in. for each additional bell. If the excess insulators are needed for
contamination purposes, this additional clearance is not necessary.
(B) For post insulators, the no wind clearance to structure or guy is the length of the post insulator.
(C) A higher wind may be assumed if deemed necessary.
(D) The following values should be added as appropriate where the altitude exceeds 3300 feet
Additional inches of clearance per 1000 feet of altitude above 3300 feet
Voltage, kV
Clearance to structure
Clearance to anchor guy
34.5
0
0
46
0
0
69
.14
.17
115
.43
.54
138
.57
.72
161
.72
.90
230
1.15
1.44
Bulletin 1724E-200
Page 7-5
7.2.4 Example of Clearance Calculations: The following examples demonstrate the
derivation of the minimum clearance to anchor guys at 6 psf.
To determine the minimum clearance of a 115 kV line to an anchor guy (Table 7-1) at 6 psf, the
clearance is based on NESC Table 235-6 and NESC Rule 235E.
NESC Clear. in any direction.
NESC Clear. in any direction.
= NESC Basic Clearance(Table 235-6) + .25(kVL-L – 50)
= 16 inches + .25(120.8-50) inches
= 16 inches + 17.7 inches
= 33.7 inches ( clearance in Table 7-1is 34 inches)
7.3 Backswing: Insulator swing considerations are illustrated in Figure 7-1. For angle
structures where the insulator string is attached to the crossarm, the most severe condition is
usually where the force of the wind and the force of the line angle are acting in the same
direction. However, for small angle structures, it is possible that the limiting swing condition
may be when the wind force is in a direction opposite of that due to the force of the line angle.
This situation is called backswing, as it is a swing in a direction opposite of that in which the
insulator is pulled by the line angle force. Figure 7-2 illustrates backswing.
When calculating backswing, it is necessary to assume those conditions that would tend to make
the swing worse, which usually is low conductor tension or small line angles. It is recommended
that the temperature conditions for large angle structures in Figure 7-1 be used, as they result in
lower conductor tensions.
direction of line angle
back forward
swing swing
normal position of
insulators (no wind,
no ice)
FIGURE 7-2: FORWARD AND BACKWARD SWING ANGLES
7.4 Structure Insulator Swing Values: Table 7-2 provides the allowable insulator swing angle
values for some of the most often used standard agency tangent structures. These values
represent the maximum angle from the vertical that an insulator string of the indicated number of
standard bells may swing in toward the structure without violating the clearance category
recommendation indicated at the top of each column. For tangent structures, the most restrictive
angle for the particular clearance category for the entire structure is given. Thus, for
an asymmetrical tangent structure (TS-1 for instance) where the allowable swing angle depends
upon whether the insulators are assumed to be displaced to the right or left, the use of the most
restrictive value means that the orientation of the structures with respect to the line angle need
not be considered. For certain angle structures the insulator string has to be swung away from
the structure in order to maintain the necessary clearance. These situations usually occur for
large angle structures where the insulator string is attached directly to the pole or to a bracket on
the pole and where the force due to the change in direction of the conductors is relied upon to
hold the conductors away from the structure.
Bulletin 1724E-200
Page 7-6
Structure and
Voltage
69 kV
TS-1, TS-1X
TSZ-1, TSZ-2
TH-1,TH-1G
115 kV – TH-1A
161 kV – TH-10
230 kV – TH-230
TABLE 7-2
INSULATOR SWING ANGLE VALUES IN DEGREES
(For insulator string with ball hooks)
(For insulator swing of other structures, see Appendix J)
Number of
No Wind
Moderate Wind
Insulators
Swing Angle
Swing Angle
4
4
4
7
10
12
20.0
41.7
35.6
28.3
16.4
16.5
High Wind
Swing Angle
38.5
61.2
61.2
58.7
53.2
47.5
74.0
82.6
85.6
80.8
77.7
74.8
7.5 Line Design and Structure Clearances: Insulator swing has a key effect on acceptable
horizontal to vertical span ratios. Under a given set of wind and temperature conditions, an
insulator string on a structure will swing at an angle toward the structure a given number of
degrees. The angle of this swing is related to a ratio of horizontal to vertical forces on the
insulator string. A relationship between the horizontal span, the vertical span, and if applicable,
the line angle can then be developed for the structure, conductor, and weather. Horizontal and
vertical spans are explained in Figure 7-4.
The acceptable limits of horizontal to vertical span ratios are plotted on a chart called an
insulator swing chart. Such a chart can be easily used for checking or plotting out plan and
profile sheets. Figures 7-3 and 7-5 show simplified insulator swing charts for the moderate wind
condition only. There is one significant difference between the chart for tangent structures, and
the chart for angle (running corner) structures. In Figure 7-3 for a typical tangent structure, the
greater the vertical span for a fixed horizontal span the less swing occurs. The reverse is true for
chart of Figure 7-5 for a typical angle structure. This occurs because the swing chart in Figure 75 is for a large angle structure where the force of the line angle is used to pull the insulator string
away from the structure. As such, the less vertical force there is from the weight span, the
greater the horizontal span can be.
600
32°
TI
I NI
AL
500
400
600
700
E
RV
CU
ING
SW
IOR VE
AT SSI
UL C E
INS EX
VERTICAL SPAN
700
ING
SW
IOR LE
AT AB
UL OW
INS ALL
800
INSULATOR SWING CHART
TH-230 STRUCTURE
9# WIND13 INSULATORS/STRING
800
900
1000
HORIZONTAL SPAN
FIGURE 7-3: TYPICAL INSULATOR SWING CHART FOR A TH-230 TANGENT
Bulletin 1724E-200
Page 7-7
VS
VS 1
VS 2
#2
L1
#1
L2
#3
1/2L1
1/2L2
HS
L = span,
L1 - span from structure 1 to 2
L2 = span from structure 2 to 3
HS = horizontal span
VS = vertical span
Span
Span is the horizontal distance from one structure to an adjacent structure along the line.
Vertical Span
The vertical span (sometimes called the weight span) is the horizontal distance between the
lowest points on the sag curve of two adjacent spans. The maximum sag point of a span may
actually fall outside the span. The vertical span length times the weight of the loaded conductor
per foot will yield the vertical force per conductor bearing down upon the structure and
insulators
Horizontal Span
The horizontal span (sometimes called the wind span) is the horizontal distance between the
mid-span points of adjacent spans. Thus, twice the horizontal span is equal to the sum of the
adjacent spans. The horizontal span length times the wind force per foot on the conductor will
yield the total horizontal force per conductor on the insulators and structure.
FIGURE 7-4: HORIZONTAL AND VERTICAL SPANS
Bulletin 1724E-200
Page 7-8
The ‘no wind’ insulator swing criteria will not be a limiting condition on tangent structures as
long as the line direction does not change and create an angle in the line. If an angle is turned, it
is possible that the ‘no wind’ condition might control. The other two criteria may control under
any circumstance. However, the high wind criteria will be significant in those areas where
unusually high winds can be expected. Thus, all three conditions specified need to be checked.
100
LIN
EA
NG
LE
0°
( 12
300
16°
15°
14°
1 3°
400
18°
17°
VERTICAL SPAN
12°
CU
RV
E)
11°
200
INSULATOR SWING CHART
TH-233 STRUCTURE
9# WIND
16 INSULATORS/STRING
10°
AL SW I
LO NG
WA
BL
E
S
EX WIN
CE G
SS
IVE
500
600
500
600
700
800
HORIZONTAL SPAN
900
1000
FIGURE 7-5: TYPICAL INSULATOR SWING CHART FOR A TH-233 MEDIUM ANGLE
STRUCTURE (Moderate Wind Swing Condition, 9 psf assumed instead of
minimum NESC 6 psf)
7.6 Formulas for Insulator Swing: The formulas in equations 7-1 and 7-2, can be used to
determine the angle of insulator swing that will occur under a given set of conditions for either
tangent or angle structures.
tan φ =
pc =
(2)(T )(sin θ 2) + (HS )( pc )
(VS )(wc ) + (1 / 2)(Wi )
(d c )(F )
12
Eq. 7-1
Eq. 7-2
Bulletin 1724E-200
Page 7-9
where:
Ø = angle with the vertical through which the insulator
θ =
T =
HS =
VS =
pc =
wc =
Wi =
dc =
F =
string swings, in degrees
line angle, in degrees
conductor tension, pounds
horizontal span, feet
vertical span, feet
wind load per unit length of bare conductor in pounds
per foot
weight per unit length of bare conductor in pounds per
foot
weight of insulator string (wind pressure neglected), in
pounds. (See Appendix C for insulator string weights).
conductor diameter2in inches
wind force in lbs/ft
In order for equation 7-1 to be used properly, the following sign conventions are to be followed:
Condition
•
Wind - Blowing insulator toward structure
•
“(2)(T)(sin θ/2)” term (force on insulator due to line angle):
+
Pulling insulator away from structure
+
-
Insulator swing angle
Angle measured from a vertical line through point of insulator
support in toward structure
+
Angle measured from a vertical line through point of insulator
support away from structure
-
Pulling insulator toward structure
•
Sign Assumed
7.7 Insulator Swing Charts: Insulator swing charts similar to those in Figures 7-4 and 7-5 can
be developed by using equation 7-3 and the maximum angle of insulator swing values as limited
by clearance to structure.
VS =
(2)(T )(sin θ 2) + (HS )( pc ) − Wi
(2)(wc )
(wc )(tan φ )
Eq. 7-3
The symbols and sign conditions are the same as those provided for equation 7-1. Equation 7-3
is derived from equation 7-1 and solving for VS.
7.8 Excessive Angles of Insulator Swing: If upon spotting a line, calculations shown a
structure will have excessive insulator swing, one or more of the measures outlined in
Section 10.4 of Chapter 10 of this bulletin may be required to alleviate the problem.
Bulletin 1724E-200
Page 7-10
7.9 Example: For the TH-10 tangent structure, develop the insulator swing chart. Assume that
it is desired to turn slight angles with the tangent structure and the insulator string assembly uses
the ball hook.
7.9.1 Given:
a. Voltage: 161 kV
Structure: TH-10
Conductor: 795 kcmil 26/7 ACSR
Insulation: Standard (10 bells)
b. NESC heavy loading district
High winds: 14 psf
Ruling Span: 800 ft.
c. Conductor Tensions
6 psf wind
0°F
6,244 lbs. initial tension
No wind
60°F
4,633 lbs. final tension
12.5 psf wind
32°F
10,400 lbs. final tension
7.9.2 Solution: Using the information on conductor sizes and weights, allowable swing angles,
insulator string weights from the appendices of this bulletin and using equation 7-3, the
following calculation tables and the swing chart in Figure 7-6 are created.
7.10 Example: On the plan and profile drawings, the engineering is checking insulator swing
for the TH-10 structure in example 7-9. For a certain TH-10 structure with no line angle, the
horizontal span is 800 feet. Determine the minimum vertical span.
7.10.1 Same Information as 7.9.1
7.10.2 Solution: From Figure 7-6, for a horizontal span of 800 feet, the vertical span must be
greater than 241 feet (see also tables for Figure 7-6). Many programs which are used to develop
plan-profile drawings will automatically check insulator swing or will use insulator swing as a
parameter in the spotting of structures.
0
200
400
VERTICAL
SPAN IN
FEET
600
800
1000
0
200
60°F Final
No Wind Insulator
Swing Limit
60°F Final
400
ine
2° L
Moderate Wind
Insulator Swing
Limit
HORIZONTAL SPAN IN FEET
800
1000
Acceptable
Unacceptable
le
Ang
0°F Initial
1200
High Wind Condition Does Not Control
ngle
ngle
i ne A
0° L
ine A
1° L
600
TH-10 161kV 800' Ruling Span
795 Kcmil 26/7 ACSR
6244 lbs. Tension At 0° Initial, 6 psf Wind
4633 lbs. Tension At 60° Final, No Wind
FIGURE 7-6: INSULATOR SWING CHART FOR EXAMPLE 7-9
1400
Bulletin 1724E-200
Page 7-11
Bulletin 1724E-200
Page 7-12
VS =
a)
b)
c)
d)
e)
FIGURE 7-6 INSULATOR SWING CHART FOR EXAMPLE 7-9 (continued)
Note: for the no wind case, vertical span is independent
(2)(T )(sin θ 2) + (HS )( pc ) − Wi
of horizontal span. It is only dependent upon line angle.
(wc )(tan φ )
(2)(wc )
θ
1°
2°
Ø = angle with the vertical through which insulator
string swings.
sin θ/2
.00872
.01745
(2)(T)(sin θ/2)
80.26
161.71
θ = line angle
(HS)(pc)
0
0
T = conductor tension
a+b
80.26
161.71
HS = horizontal span
(wc)(tan Ø)
.32
.32
VS = vertical span
(a + b)/c
251.13
502.25
pc = wind load on conductors
Wi/(2)(wc)
61.70
61.70
wc = weight of conductor/ft.
d – e = VS
189.43
440.55
Wi = weight of insulator string
θ
sin θ/2
a) (2)(T)(sin θ/2)
b) (HS)(pc)
a+b
c) (wc)(tan Ø)
d) (a + b)/c
e) Wi/(2)(wc)
d – e = VS
θ
sin θ/2
a) (2)(T)(sin θ/2)
b) (HS)(pc)
a+b
c) (wc)(tan Ø)
d) (a + b)/c
e) Wi/(2)(wc)
d – e = VS
Ø = 16.4°
Structure: TH-10________
Conductor: 795 26/7 ACSR
Voltage: 161 kV_______
Insulator Swing Condition:
Ø=
pc =
wc=
T=
Wi=
16.4°_______
0 lbs./ft____
1.0940 lbs./ft
4,633 lbs___
135 lbs
Ruling span 800___ft.
Loading district: Heavy
No of Insulators: 10___
No wind____________
(F=0 lbs at 60°F)
Conductor dia: 1.108 __
pc = (d)(F)
12
Bulletin 1724E-200
Page 7-13
FIGURE 7-6: INSULATOR SWING CHART FOR EXAMPLE 7-9 (continued)
(2)(T )(sin θ 2) + (HS )( pc ) − Wi
VS =
(wc )(tan φ )
(2)(wc )
θ = 0°
HS=200 HS=400 HS=800 HS=1000
Ø = angle with the vertical through which
insulator string swings.
0
sin θ/2
0
0
0
0
a) (2)(T)(sin θ/2)
0
0
0
θ = line angle
554.00
b) (HS)(pc)
110.80
221.60
443.20
T = conductor tension
554.00
a+b
110.80
221.60
443.20
HS = horizontal span
c) (wc)(tan Ø)
1.460
1.460
1.460
1.460
VS = vertical span
d) (a + b)/c
75.77
151.53
303.07
378.83
pc = wind load on conductors
e) Wi/(2)(wc)
61.70
61.70
61.70
61.70
wc = weight of conductor/ft.
d – e = VS
14.07
89.83
241.37
317.13
Wi = weight of insulator string
HS=200
HS=400
HS=800
HS=1000
.008727
1.08.98
110.80
219.78
1.460
150.29
61.70
88.59
.008727
108.98
221.60
330.58
1.460
226.05
61.70
164.35
.008727
108.98
443.20
552.18
1.460
377.59
61.70
315.89
.008727
108.98
554.00
662.98
1.460
453.35
61.70
391.65
θ = 2°
HS=200
HS=400
HS=800
HS=1000
Structure: TH-10________
Ruling span 800___ft.
sin θ/2
a) (2)(T)(sin θ/2)
b) (HS)(pc)
a+b
c) (wc)(tan Ø)
d) (a + b)/c
e) Wi/(2)(wc)
d – e = VS
.017452
217.95
110.80
328.75
1.460
224.80
61.70
163.10
.017452
217.95
221.60
439.55
1.460
300.57
61.70
238.87
.017452
217.95
443.20
661.15
1.460
452.10
61.70
390.40
.017452
217.95
554.00
771.95
1.460
527.87
61.70
466.17
Conductor: 795 26/7 ACSR
Voltage: 161 kV_______
Insulator Swing Condition:
Loading district: Heavy
No of Insulators: 10___
θ = 1°
a)
b)
c)
d)
e)
sin θ/2
(2)(T)(sin θ/2)
(HS)(pc)
a+b
(wc)(tan Ø)
(a + b)/c
Wi/(2)(wc)
d – e = VS
Ø = 53.2°
Ø=
pc =
wc=
T=
Wi=
53.2°_______
0.554 lbs./ft____
1.0940 lbs./ft
6,244 lbs___
135 lbs
Moderate wind______
(F=6 psf at 0°F)
Conductor dia: 1.108__
pc = (d)(F)
12
Bulletin 1724E-200
Page 7-14
FIGURE 7-6: INSULATOR SWING CHART FOR EXAMPLE 7-9 (continued)
(2)(T )(sin θ 2) + (HS )( pc ) − Wi
VS =
(wc )(tan φ )
(2)(wc )
θ = 0°
HS=200 HS=400 HS=800 HS=1000
Ø = angle with the vertical through which
insulator string swings.
0
sin θ/2
0
0
0
0
a) (2)(T)(sin θ/2)
0
0
0
θ = line angle
1154.00
b) (HS)(pc)
230.80
461.60
923.20
T = conductor tension
1154.00
a+b
230.80
461.60
923.20
HS = horizontal span
c) (wc)(tan Ø)
5.02
5.02
5.02
5.02
VS = vertical span
d) (a + b)/c
46.00
92.00
183.99
229.99
pc = wind load on conductors
e) Wi/(2)(wc)
61.70
61.70
61.70
61.70
wc = weight of conductor/ft.
d – e = VS
-15.70
30.30
122.29
168.29
Wi = weight of insulator string
θ = 1°
a)
b)
c)
d)
e)
sin θ/2
(2)(T)(sin θ/2)
(HS)(pc)
a+b
(wc)(tan Ø)
(a + b)/c
Wi/(2)(wc)
d – e = VS
θ = 2°
sin θ/2
a) (2)(T)(sin θ/2)
b) (HS)(pc)
a+b
c) (wc)(tan Ø)
d) (a + b)/c
e) Wi/(2)(wc)
d – e = VS
HS=200 HS=400 HS=800 HS=1000
.008727
181.51
230.80
412.31
5.02
82.17
61.70
20.47
.008727
181.51
461.60
643.11
5.02
128.17
61.70
66.47
.008727
181.51
923.20
1104.71
5.02
220.17
61.70
158.47
.008727
181.51
1154.00
1335.51
5.02
266.17
61.70
204.47
Ø = 77.7°
HS=200 HS=400 HS=800 HS=1000
Structure: TH-10________
Ruling span 800___ft.
.017452
363.01
230.80
593.81
5.02
118.35
61.70
56.65
Conductor: 795 26/7 ACSR
Voltage: 161 kV_______
Insulator Swing Condition:
Loading district: Heavy
No of Insulators: 10___
.017452
363.01
461.60
824.61
5.02
164.35
61.70
102.65
.017452
363.01
923.01
1286.21
5.02
256.34
61.70
194.64
.017452
363.01
1154.00
1517.01
5.02
302.34
61.70
240.64
Ø=
pc =
wc=
T=
Wi=
77.7°_______
1.154 lbs./ft____
1.0940 lbs./ft
10,400 lbs___
135 lbs
High wind__________
(F=12.5 psf at 32°F)
Conductor dia: 1.108__
pc = (d)(F)
12
Bulletin 1724E-200
Page 8-1
8. INSULATION AND INSULATORS
8.1 Insulator Types: Insulation is defined as the separation between conducting surfaces by
means of a non-conducting (dielectric) material that would economically offer a high resistance
to current. Insulators may be fabricated from porcelain, toughened glass, fiberglass rods and
sheds of polymer or silicone construction.
The main types of insulators used on transmission lines are suspension insulators using bells or
polymer strings, pin insulators, and vertical and horizontal posts. Several suspension bell units
are connected in a string to achieve the insulation level desired. The polymer suspension is one
unit with an insulation level determined largely by its length. Horizontal post units are made of
porcelain or polymer and are single units with a desired rating. See Figures 8-1 and 8-2.
FIGURE 8-1: A STANDARD PORCELAIN SUSPENSION BELL
FIGURE 8-2: A TYPICAL PORCELAIN HORIZONTAL POST INSULATOR
8.2 Insulator Materials
8.2.1 Porcelain insulators have been the industry standard as specified by ANSI requirements
for electrical and mechanical capacities. Although porcelain insulators have a history of long,
useful lives, the strings are heavy and subject to breakage from gunshots. The connecting
portions of porcelain insulators are metal components which are embedded in high strength
cement as specified by ANSI standards. Strength ratings for porcelain insulators are verified by
proof loading requirements of each manufactured unit, and stamped accordingly.
8.2.2 Toughened glass insulators are similar in construction to the porcelain insulator. They
are heavy, and are also subject to vandalism exposure. ANSI fabrication standards are also
available for toughened glass.
8.2.3 Non-ceramic (polymer) insulators typically consist of a fiberglass rod that is sheathed
with weathershed ‘bells’ made of either rubber-based or silicone-based polymers. The
connecting ends are typically compressed metal fittings. ANSI standards have been developed
for suspension units.
Bulletin 1724E-200
Page 8-2
Non-ceramic assemblies offer varieties of end fittings, lengths and strength capacities. They are
much lighter in weight than their porcelain and glass counterparts. Polymers may be subject to
damage by corona voltage, ultraviolet radiation, or physical deterioration which may not be
apparent. Deterioration of a fiberglass rod may result in a reduction in strength of the unit.
8.3 Insulation Levels Using Suspension Bells: Table 8-1 provides suggested insulation levels.
However, circumstances such as high altitude, contamination, high isokeraunic levels, or high
footing resistance, may warrant additional insulation. If wood structures with steel arms, steel
structures, or concrete pole structures are used in areas where there is a high isokeraunic level,
consideration should be given to using one additional suspension bell beyond the standard
agency recommended insulation levels.
8.3.1 Tangent and Small Angles: Table 8-1 indicates the recommended number of
5-3/4 x 10 in. suspension insulators to be used per phase on wood tangent and small angle
structures. Also given are the electrical characteristics of the insulator strings.
8.3.2 Angles: For angle structures where the conductor tension is depended upon to pull the
insulator string away from the structure, one more insulator bell should be added to the number
of bells recommended for tangent structures. The sole exception to this is 34.5 kV where no
additional bells are needed.
TABLE 8-1
RECOMMENDED ISULATION LEVELS*AT SEA LEVEL
(SUSPENSION AT TANGENT AND SMALL ANGLE STRUCTURES)
Flashover Characteristics in kV
Nominal L-L
Voltage in kV
No. of
5-3/4x10”
Bells
60 Hz
Low Freq
Dry*
60 Hz
Low Freq
Wet
34.5
46
69
115
138
161
230
3
3
4
7
8
10
12
215
215
270
435
485
590
690
130
130
170
295
335
415
490
Impulse
Positive Negative
355
355
440
695
780
945
1105
340
340
415
670
760
930
1105
Total Leakage
Distance
inches
34.5
34.5
46
80.5
92
115
138
*See NESC Rule 273, Table 273-1 for minimum insulation level requirements
8.3.3 Deadends: In situations where the insulator string is in line with the conductor, the
number of bells should be two more than is used for tangent structures. These situations occur at
large angles, and tangent deadends where the conductor is deadended onto an insulator string.
The sole exception to this is 34.5 kV where one additional bell is used.
8.4 Insulation Levels Using Post Insulators: Agency recommended electrical characteristics
for horizontal post insulators are given in Table 8-2.
Bulletin 1724E-200
Page 8-3
TABLE 8-2
RECOMMENDED INSULATION LEVELS AT SEA LEVEL
(POSTS AT TANGENT AND SMALL ANGLE STRUCTURES)
Flashover Characteristics in kV
Nominal L-L
Voltage in kV
60 Hz
Low Freq
Dry
60 Hz
Low Freq
Wet
34.5
46
69
115
138
125
150
200
380
430
115
135
180
330
390
Impulse
Positive Negative
210
255
330
610
690
Total Leakage
Distance
inches
29
40
53
100
110
260
344
425
780
870
8.5 Electrical Characteristics of Insulators: Because low frequency dry flashover ratings can
be tested easily and accurately, these ratings are generally the most common flashover values
referred to when comparing insulators. However, flashover (60 Hz) of an insulator in service
almost never occurs under normal dry operating conditions, so these ratings are probably the
least significant of insulator electrical characteristics. When comparing different types of
insulators (e.g., post vs. suspension) characteristics such as impulse and wet flashover do not
necessarily follow the same pattern as the low frequency dry flashover ratings. For these
reasons, Tables 8-1 and 8-2 are developed and provide both impulse and wet flashover values.
For voltages up to 230 kV the most severe stress on the insulation is usually caused by lightning,
and the most important flashover characteristic is the impulse flashover values.
8.6 High Altitude Considerations
8.6.1 General: As altitude increases, the insulation value of air decreases and an insulator at a
high elevation will flash over at a lower voltage than the same insulator at sea level. Figure 8-3
gives the derating factors for insulator flashover values as a function of altitude. These derating
factors apply to both low frequency flashover values and impulse flashover values.
FIGURE 8-3: INSULATION DERATING FACTOR vs. ALTITUDE
IN 1,000's OF FEET (230 kV and below)
Multiply Derating Factor by Insulator
Flashover Values at Sea Level to Get
Flashover Values at Altitude desired.
Curve is a plot of the equation:
9
8
7
F = (17.93B)/(460+T)
Where T = 60° F
B is standard
atmospheric
pressure at
various altitudes
in inches of Hg.
ALTITUDE IN 1000'S OF FEET
6
5
4
3
2
1
0
0.08
0.72
0.75
0.80
0.84
0.88
INSULATION DERATING FACTOR (F)
0.92
0.96
1.00
Bulletin 1724E-200
Page 8-4
In addition to increasing the number of insulators for high altitude, it is also necessary to
increase the structure air gap clearances. This could result in a decreased allowable insulator
swing angle or a longer crossarm (see Chapter 7 for details).
8.6.2 Example of Insulation Needed at High Altitudes: A line is located at 6000 feet
elevation. The derating factor (from Figure 8-3) is .827. At 138 kV, using the sea-level
requirement for low frequency dry flashover of 435 kV from Table 8-1, the line would require
526 kV (435/.827) at 6000 feet. A 10 bell string should be used instead of 7 bells. The
clearance to structure and clearance to guy wire should be increased (see Table 7-1 for
guidance).
8.6.3 Insulation for Lines with Relatively Small Changes in Altitude: When the insulation
derating factor for the line altitude is at a value less than approximately 90 percent of the
insulation value at sea level (see Figure 8-3), then additional insulation should be added to bring
the insulation level up to at least 90 percent of the sea level value.
8.6.4 Insulation for Lines with Significant Elevation Changes but Less than 5000 Feet: If
the elevation change in a line from its low point to its highest point is less than 5000 feet, it is
recommended that insulation for the entire length of the line be based on the weighted average
altitude of the line. This can be achieved by applying the procedure given in paragraph 8.6.2 to
that weighted average altitude.
8.6.5 Insulation for Line with Elevation Changes Greater than 5000 Feet: Where the
elevation change is greater than 5000 feet, the following two steps should be taken:
a. The entire line insulation should be upgraded for the minimum altitude of the line using
the procedure in paragraph 8.6.2 above.
b. Additional insulation should be added in sections of line where it is needed. This need
arises where the altitude of the line increases to the point where the insulation value is less
than approximately 90 percent of the insulation value at the minimum line altitude. This
means there may be different numbers of insulator bells at different points along the same
line.
8.6.6 Example of Additional Insulation for High Altitudes and Line Elevation Changes
Less than 5000 feet: A 161 kV line is to be built in an area where altitude ranges from 5430 ft.
to 7580 ft. Determine how much additional insulation, if any, is necessary.
Solution: The elevation change for the line from its lowest point to its highest point is less than
5000 ft. Therefore, the insulation should be based on the weighted average altitude. Since we
do not know the distribution of the line at the various altitudes, we will assume a uniform
distribution. Thus:
Average altitude =
5430 + 7580
2
= 6505 ft.
From Figure 8-3 the derating factor for an average altitude of 6505 ft is 0.81. Since paragraph
8.6.2 indicates that additional insulation is needed if the derating factor is less than 0.90,
additional insulation will be needed.
According to paragraph 8.6.5, the insulation value should be brought up to approximately
90 percent of the sea level value, which for 161 kV is:
Bulletin 1724E-200
Page 8-5
(0.9)(590) kV) = 531 kV
(590 kV is the low frequency dry flashover value of 10 bells at sea level).
The 531 kV requirement for low frequency dry flashover at sea level needs to be increased to
account for the higher elevation. Applying the derating factor to the 531 kV, the low frequency
dry flashover value of the string needs to be:
531/.81 = 655 kV
From Appendix C, the low frequency dry flashover of 11 bells is 640 kV. For 12 bells it is
690 kV. Therefore, the addition of one extra bell will not quite bring the insulation level up to
the 90 percent of sea level. The above calculations seem to indicate the need to add two extra
bells. However, some judgment should be exercised as to whether the second additional bell is
used. Even though one bell extra does not quite provide enough additional insulation, it comes
close. If the expected frequency and severity of lightning storms is not particularly high, one
extra bell might be sufficient. Depending on experience and judgement, at least one and
possibly two extra bells should be used.
8.7 Lightning Considerations
8.7.1 General: Transmission lines are subjected to three types of voltage stress that may cause
flashover of the insulation: power frequency voltage, switching surges and lightning surges.
Flashovers due to power frequency voltages are primarily a problem in contaminated conditions
and are discussed in section 8.8. Of the remaining two causes of flashovers, lightning is the
more severe for lines of 230 kV and below.
8.7.2 Lightning Flashover Mechanism: When lightning strikes a transmission line, it may hit
either the overhead ground wire or a phase conductor. If a phase conductor is hit, there will
almost certainly be a flashover of the insulation. To minimize this near certainty of a flashover,
an overhead ground wire is used to intercept the lightning strokes. To reduce the possibility of a
shielding failure, the shielding angle should be kept at 30° or less. (The shielding angle is the
angle measured from the vertical between the OHGW and the phase conductors, as shown in
Figure 8-4). On H-frame structures where two overhead ground wires are used, the center phase
may be considered to be properly shielded even if the shielding angle to it is greater than 30°.
For structures whose height is in excess of 92 feet, shielding angles of less than 30° as indicated
in Table 8-3, should be used. Where there is an unusually high exposure to lightning, such as at
river crossings, an even smaller shielding angle may be warranted.
TABLE 8-3
REDUCED SHIELDING ANGLE VALUES
Structure Height,
feet
Recommended
Shielding Angle,
degrees
92
99
116
30
26
21
Bulletin 1724E-200
Page 8-6
If lightning strikes an overhead ground wire, a traveling current wave will be set up which will
induce a traveling voltage wave. This voltage wave will generally increase in magnitude as it
travels down the wire, until it reaches a structure where the reflection of the traveling wave from
the ground prevents the voltage from further increasing. (The overhead ground wire is grounded
at every structure). If the traveling voltage wave at the structure is sufficiently high, a "back
flashover" across the insulation from the structure ground wire or from the overhead ground wire
to the phase conductor will occur. The factors that determine if a back flashover will occur are:
the amount of insulation, the footing resistance (the higher the footing resistance, the higher the
voltage rise at the structure) and the span length.
Cross
connection
Overhead
ground wire
Shield
angle
Pole
ground
wires
FIGURE 8-4: SHIELDING ANGLE, POLE AND
OVERHEAD GROUND WIRES
8.7.3 Designing for Lightning: An overhead ground wire should be used in all locations where
the isokeraunic level is above 20. The overhead ground wire should be grounded at every
structure by way of a structure ground wire. At H-frame structures, the OHGW's should each be
connected to a structure ground wire and to one another so that if one structure ground wire
breaks, both overhead ground wires will still be grounded.
In areas where the isokeraunic level is 20 or less, an overhead ground wire should still be used
for a distance of 1/2 mile from a substation. A map of isokeraunic levels is given in Appendix E.
8.7.4 Footing Resistance: For satisfactory lightning performance of a line, low footing
resistance is essential. Exactly what value of footing resistance is acceptable or unacceptable is
not a simple matter as it depends upon several variables. Previous successful experience with a
similar line in similar circumstances can be one guide. The following references may be useful
in determining what lightning outage rate a given footing resistance would yield.
(a) “Transmission Line Reference Book, 115 kV and Below,” Palo Alto, Calif., Electric
Power Research Institute, 1975.
(b) “Estimating Lightning Performance of Transmission Lines,” J. M. Clayton and F. S.
Young. IEEE Transactions on Power Apparatus and Systems, November 1964, pp. 11021110.
Bulletin 1724E-200
Page 8-7
A grounded structure has a good chance to withstand a lightning flashover provided that
conductor insulation and ground resistance have been properly analyzed and coordinated.
A lightning outage rate of 1 to 4 per 100 miles per year is acceptable with the lower number
more appropriate for lines in the 161 to 230 kV range.
Generally, experience has shown that the footing resistance of individual structures of the line
especially within 1/2 mile of the substation should be less than 25 ohms in high isokeraunic
areas.
When a line is being built, it is recommended that the footing resistance of the ground
connection be measured and recorded on a spot check basis. If footing resistance problems are
expected, more frequent measurements should be made and recorded. If experience indicates
that the lightning outage rate is not acceptable, these measurements readings can be useful when
taking remedial measures.
Footing resistance should not be measured immediately after a rain when the soil is moist. If the
footing resistance is higher than desired, additional driven rods may be used to reduce it. If the
earth's resistivity is very high, counterpoise rather than driven rods may be required. Reference
(b) this section gives guidance in the selection of counterpoise.
8.7.5 Lightning Arresters: In areas where structure grounding is difficult to achieve, or the
lightning performance of an existing transmission line needs to be improved, Metal Oxide
Varistor (MOV) line arresters can be installed. These arresters should be coordinated with the
substation station class arresters for proper performance. The engineer should determine the size
of the substation arresters and choose a slightly higher Maximum Continuous Over Voltage
(MCOV) rating on the transmission line to prevent the line arresters from taking all of the
flashover duty.
On a triangular three wire designs, adding an arrester to the top phase of every structure will
typically give some shield angle protection to the other phases. For best performance, the
arrester should be tied to a ground system with 10 ohms or less of resistance. If good grounding
is not available, the borrower should consider adding lightning arresters to all three phases.
Lightning arresters can also be installed on shielded lines to minimize back flashover where
good grounding is difficult. The engineer should design for phase-to-phase clearances between
the failed arrester, open position, and other phase wires since the arrester may drop near the other
energized phase position.
8.8 Contamination Considerations: The problem of contamination induced flashovers should
be considered if a line is to be built near a seacoast, an industrial district, or at other locales
where airborne contaminants may accumulate on insulators.
8.8.1 Contamination Flashover Mechanism: When a layer of contaminants on an insulator is
moistened by fog, dew, light rain or snow, it will become more conductive and the leakage
current along the surface of the insulator will greatly increase. Where the current density is the
greatest (for suspension insulators near the pin, and for post insulators at the points of least
diameter), heat caused by the increased leakage current will evaporate the moisture causing the
formation of a dry band. This band usually has an higher resistance than the adjacent moistened
area which means that the band will support almost all the voltage across it. This will result in
the breakdown of the air and the formation of an arc across the dry band. The arc will cause the
moisture film at the dry band edges to dry out, enlarging the dry band, eventually to the point
where the voltage across the band is just below the air breakdown value. If an increase in
precipitation occurs causing a lowering of contaminant resistance, a second breakdown can
occur. If conditions are right, a cycle of repeated and ever-increasing surges will be set up which
Bulletin 1724E-200
Page 8-8
will result in several discharges joining, elongating and bridging the entire insulator and
resulting in a power arc. See Figure 8-5 for a graphic description.
M O IS T U R E L A Y E R
FORM S ON
C O N D U C T IN G
M A T E R IA L
D RY A REA
(A )
(B )
IN IT IA L C O N D U C T IN G S T A T E
L E A K A G E C U R R E N T D R IE S O U T
M O IS T U R E N E A R P IN
ARC
D RY A REA
(C )
(D )
A R C B R ID G E S O V E R D R Y A R E A
H E A T IN G A N D E N L A R G IN G IT
E N L A R G E D D R Y A R E A H O L D S E N T IR E
U N IT V O L T A G E A N D A R C E X T IN G U IS H E S
C O N T A M IN A T IO N
L AYER
ARC
(E )
(F )
A R C R E S T R IK E S A S M O R E M O IS T U R E
A PP EA RS O N DR Y AR EA
A R C B R ID G E S E N T IR E
IN S U L A T O R
FIGURE 8-5: CONTAMINATION BREAKDOWN PROCESS
OF A SINGLE PORCELAIN INSULATOR UNIT
8.8.2 Effect of Insulator Orientation: The orientation of insulators has an effect on
contamination performance. Vertical strings of suspension insulators or vertical post insulators
do not wash well in the rain because of the sheltering effects of the insulator skirts.
Contaminants will tend to remain on the underside of the insulator which is not immune from the
moistening effects of fog or wind blown rain and snow. Horizontally oriented suspension
insulators and post insulators have their undersides more thoroughly washed by the rain and
therefore tend to fare better than vertical insulators in contaminated areas. Another advantage of
insulators in nonvertical positions is that any ionized gases caused by arcing will not contribute
to setting up conditions where an arc could jump from one bell to another or along the skirts of a
vertical post.
Bulletin 1724E-200
Page 8-9
8.8.3 Designing for Adverse Contamination Conditions: There are several means available
for improving line insulation performance in a contaminated atmosphere.
One way to compensate for contaminated conditions is to increase the leakage distance of the
insulation. The leakage distance is the distance along the surface of the insulators from the top
of the string (or post) to the energized hardware, not including any metal such as insulator caps
and pins.
Table 8-4 gives recommended leakage distances for various levels of contamination. The
increased leakage distance can be obtained by adding additional standard insulator bells (using a
longer post insulator) or by using fog insulators, which have more leakage distance for the same
overall insulator length. The additional leakage distance on fog insulators is obtained by having
more and/or deeper skirts on the underside of the insulator bell. In addition to the leakage
distance, the shape of the insulator has an effect on contamination performance, especially when
fog units are being used.
Research into the performance of existing lines with similar contamination should play an
important part in the final determination of insulating for atmospheric contamination.
An alternative to increasing the total leakage distance of the insulator string is to use a resistance
graded insulators. These insulators have a glaze that permits a small but steady leakage current
to flow over their surface. This leakage current gives the insulator much better contamination
performance without having to increase leakage distance. The base of a resistance graded
insulator should be solidly bonded to the structure ground wire to permit the leakage current to
flow easily to the ground. To aid in determining whether to use this type of insulator, its
advantages and disadvantages are listed below.
Advantages and Disadvantages of Resistance Graded Insulators
Advantages
• No extra leakage distance required.
• Longer intervals between insulator
washings.
• No radio noise (due to a more uniform
voltage distribution across string).
Disadvantages
• Higher initial costs.
• Small but continuous power loss.
•
Not entirely successful in very heavily
contaminated areas.
Bulletin 1724E-200
Page 8-10
TABLE 8-4
SUGGESTED LEAKAGE DISTANCES FOR CONTAMINATED AREAS
Contaminate
Level
Environment
Areas without industries and with low
density of houses equipped with
heating plants. Areas with some
density of industries or houses but
subject to frequent winds and/or
rainfall. Areas not exposed to sea
winds.
Light
Areas with industries not producing
particularly polluting smoke and/or
areas with average density of houses
equipped with heating plants. Areas
with high density of houses and/or
rainfall. Areas exposed to winds from
the sea but not less than 10 miles from
the coast
Moderate
Areas with high density of industries
and suburbs of large cities with high
density of heating plants producing
pollution. Areas close to the sea or in
any case exposed to relatively strong
winds from the sea (within 10 miles of
the sea).
Heavy
Areas subjected to industrial smoke
producing particularly thick conductive
deposits. Areas with very strong and
polluting winds from the sea. Desert
areas, characterized by no rain for
long periods, exposed to strong winds
carrying sand and salt, and subjected
to regular condensation
*rms L-G is root mean square line to ground voltage
Equivalent Amount
NaCl
mg/cm2
Suggested Leakage
Distance rms L-G*
in/kV
0-.03
NA-1.0
.03-.06
1.0-1.25
.06-.1
1.5-1.75
.1-.25
2.0-2.5
Very Light
Washing of the insulators should not be used in place of properly designing for contamination
but rather should be used in addition to the other steps where it is felt to be necessary.
Insulator performance in a contaminated environment can be improved by coating the surface
with suitable silicone grease. The grease absorbs the contamination and repels water. It is
necessary, however, to remove and replace the grease at intervals determined by the degree of
contamination. As with washing, the use of grease should only be considered as a remedial step.
Resistance graded insulators should not be greased.
Bulletin 1724E-200
Page 8-11
8.9 Mechanical Considerations (Porcelain and Non-ceramic)
8.9.1 Suspension Insulators: Strength rating methods and nomenclature vary depending on the
insulator material.
For porcelain, ANSI C29.1 specifies Mechanical and Electrical (M&E) procedures. The M&E
value is determined by a combined mechanical and electrical test. The insulator has a voltage
(75 percent of its rated dry flashover) impressed across it while a mechanical load is gradually
applied to the insulator. For non-ceramics, most manufacturers conduct specified mechanical
loading (SML) procedures to determine a polymer insulator’s failure rating. These procedures
are similar to the M&E for porcelain, but no electrical test is applied.
ANSI C 29.2 defines standard mechanical ratings for porcelain as: 15,000 lbs., 25,000 lbs.,
36,000 lbs. and 50,000 lbs. ANSI C29.12 defines standard SML’s for non-ceramic transmission
insulators as: 20,000 lbs., 25,000 lbs., 36,000 lbs. and 40,000 lbs.
For recommended insulator loading limits, refer to Table 8-5. Under NESC district loading
conditions, suspension insulators should not be loaded to more than 40 percent of their standard
ANSI M&E rating for porcelain insulators or 40 percent of their ANSI SML for non-ceramics.
If a heavier loading than the NESC district loading can be expected to occur with reasonable
regularity, then the 40 percent loading limit should be maintained at the higher loading limit.
Under extreme ice or high wind (50-year mean recurrence interval wind conditions) the load on
the insulator should not exceed 65 percent of the M&E strength of the insulator for porcelain and
50 percent of the M&E strength for non-ceramics.
Generally, porcelain insulators with a 15,000 pound M&E rating will be satisfactory for tangent
structures. However, stronger insulators may be needed on long spans with large conductors and
at deadends and angles where the insulators carry the resultant conductor tension.
TABLE 8-5
SUMMARY OF RECOMMENDED INSULATOR LOADING LIMITS
Insulator Type
Suspension
Horizontal Post
Cantilever
Tension, Compression
Vertical Post (Porcelain)
Vertical Pin Insulator
(Porcelain, Mounted on
the Crossarm)
NESC District Loading
Extreme Loading
Non-ceramic
Porcelain
40%
(% of ANSI standard
SML or M&E strength)
50%
(% of ANSI standard
SML strength)
65%
(% of ANSI standard
M&E strength)
40%
50%
(% of appropriate rated
ultimate strength value)
750 lbs.
50%
50%
(% of appropriate rated
ultimate strength value)
65%
65%
(% of appropriate rated
ultimate strength value)
-----
500 lbs.
-----
Bulletin 1724E-200
Page 8-12
When suspension non-ceramic insulators are used, the designer must be aware of the effects on
insulator swing calculations due to increased length and reduced weight. Agency Bulletin
1724E-220, “Procurement and Application Guide for Non-Ceramic Composite Insulators,”
provides additional information on non-ceramic insulators. When used as a jumper, polymer
suspension insulators may be pulled towards the structure because of their lightweight.
8.9.2 Horizontal Post Insulators (Porcelain and Non-ceramic): Under NESC loading district
conditions, horizontal post insulators must not be loaded to more than 40 percent of their
ultimate cantilever strength. As with suspension insulators, if a loading more severe than the
NESC loading can be expected to occur with reasonable regularity, then the limit recommended
for the more severe loading should be used. Under extreme ice conditions, the cantilever load on
horizontal post insulators should not exceed 65 percent of the ultimate strength for porcelain and
50 percent of the ultimate strength for non-ceramics.
When a line angle is turned at a horizontal post structure, some or all of the insulators will be
in tension. Under standard NESC loading conditions, the tension or compression load on the
insulator must not exceed 50 percent of the ultimate tension or compression strength of the
insulator. Under extreme loading conditions, the tension load on the insulator must not exceed
65 percent of the ultimate tension strength for porcelain and 50 percent of the ultimate tension
strength of non-ceramic insulators.
Line post insulators are actually subjected to vertical, transverse and longitudinal loads
simultaneously. These loads represent the actual applied stresses to the line post insulator core
that are experienced in the field. Vertical, transverse and longitudinal loads each contribute to
the total bending moment, or total stress on the rod. Non-ceramic manufacturers provide
combined loading application curves, which represent the mechanical strength limits of a nonceramic line post insulator when subjected to simultaneous loads. These curves are used to
determine how the insulator’s combined loading requirements compare with its cantilever
(bending) strength. The combined loading application curves are used during the engineering
stage to evaluate the mechanical strength of the insulator for specific line loading criteria.
There are three special considerations that must be mentioned in relation to horizontal post
insulators:
Insulator Grounding: Where the structure ground wire passes near horizontal post insulators, it
either should be stood off from the pole by means of a non-conducting strut or must be solidly
bonded to the base of the insulator. This grounding is necessary to avoid radio noise problems.
Mechanical Impact Failures: Porcelain post insulators mounted on steel, concrete, or (in some
cases) on wood structures using H-class poles, have experienced cascading mechanical failures
due to impact loads because of the relative rigidity of the structures. To minimize the affects of
impact loads, it is recommended that on rigid structures, non-ceramic insulators be used, or that
porcelain post insulators be equipped with deformable bases, shear pin devices, or other means
of relieving mechanical overloads.
Live Line Maintenance Issues: Many compact designs restrict the lineman for working on
transmission lines while energized. Rule 441 of the NESC provides Table 441-1 which gives the
recommended AC live work minimum approach distance for various voltages.
8.9.3 Porcelain Vertical Post and Pin Insulators Mounted on Crossarms: The maximum
transverse load should be limited to 500 lbs. for standard single pin type agency standard
structures and 750 lbs for standard vertical post type structures. The 500 lb. limit applies
whether the load is from standard NESC loading district loadings alone or from a combination of
loading district loading
Bulletin 1724E-200
Page 8-13
and the resultant of conductor tension on line angles. These limit will prevent excessive stress
on the insulator, the tie wires (if used), insulator pin (if used), and the wood crossarm. The
transverse load can be doubled by using double pin or post construction. See Table 8-5 for a
summary of recommended insulator loading limits.
8.9.4 Coordination of Insulator Strength with Strength of Associated Hardware: Care
should be taken to coordinate the strength of the hardware associated with the insulator with the
strength of the insulator itself.
8.9.5 Example of Maximum Vertical Span Due to Horizontal Post Insulator Strength:
A 115 kV line is to be built using horizontal post insulators with a cantilever strength of
2,800 lbs. The conductor to be used is 477 kcmil 26/7 ACSR. Determine the maximum vertical
span under:
1. Heavy loading district conditions; and
2. Under an extreme ice load, no wind, and 1.5 in. of radial ice
(See Chapter 11 for definitions of heavy loading and Chapter 9 for information on conductors).
Solution: From Appendix B, Conductors, the weights per unit length for the two conditions of
the conductor are:
Heavy Loading District of 1/2 inch radial ice = 1.5014 lbs./ft.
Extreme radial ice of 1.5 inch
=5.0554 lbs./ft.
Span Limits for Heavy Loading District:
2800 lbs.(0.40) = 746 ft.
1.5014 lbs./ft.
Span Limits for Extreme Ice Condition:
2800 lbs.(0.65) = 360 ft.
5.0554 lbs./ft.
The maximum vertical span is therefore 360 ft.
8.9.6 Example of Determining Minimum Suspension Insulator M&E Rating: A conductor
has a maximum tension under heavy loading district conditions of 10,000 1bs. Under extreme
radial ice of 1.5 in, it has a maximum tension of 16,000 lbs. Determine the minimum M&E
rating of suspension bell insulators to be used in tension strings. (Tension strings are those
insulator strings that are in line with the conductor and bear its full tension).
Solution:
Under NESC loading district conditions, the insulator can be loaded up to 40 percent of its M&E
rating. Therefore:
(M&E rating)(0.4)
M&E rating
M&E rating
= load
= load/(0.4)
= 10000 lbs./(0.4) = 25000 lbs.
Under extreme ice conditions the insulator can be loaded to 50 percent of its M&E rating.
Therefore:
Bulletin 1724E-200
Page 8-14
(M&E rating)(.65) = load
M&E rating
= load/(0.65)
M&E rating
= 16,000 lbs./(0.65) = 24,615 lbs.
c. Based on ANSI standard M&E ratings, the insulators to be used should have a minimum
standard rating of 25,000 lbs.
Bulletin 1724E-200
Page 9-1
9. CONDUCTORS AND OVERHEAD GROUND WIRES
9.1 Introduction: Of all the components that go into making up a transmission system, nothing
is more important than the conductors. There are a surprising number of variables and factors
that are to be considered when dealing with conductors. These include:
•
•
•
•
•
•
•
•
•
Conductor type
Conductor size
Conductor ampacity
Conductor thermal capacity
Conductor tensions
Corrosive atmosphere considerations
Radio noise
Conductor motion considerations
Economic considerations
9.2 Types of Conductors: Of the currently available types of conductors, some are used much
more extensively than others. Sections 9.2.1 through 9.2.11 provide descriptions of many of the
conductor types.
9.2.1 ACSR (Aluminum Conductor Steel-Reinforced): ACSR is the most common type of
conductor used today. It is composed of one or more layers of hard-drawn concentricallystranded 1350 aluminum wire with a high-strength galvanized steel core. The core may be a
single wire or stranded depending on the size. Because numerous stranding combinations of
aluminum and steel wires may be used, it is possible to vary the proportions of aluminum and
steel to obtain a wide range of current carrying capacities and mechanical strength
characteristics.
The steel core may be furnished with three different coating weights of zinc. The "A" coating is
the standard weight zinc coating. To provide better protection where corrosive conditions are
present, heavier class "B" or "C" zinc coatings may be specified where "C" is the heaviest
coating.
6 AL/1 St
12 AL/7 St
18 AL/1 S
26 AL/7 St
54 AL/19 St
36 AL/1 S
45AL/7 St
54AL/7 St
84 AL/19 St
FIGURE 9-1: TYPICAL ACSR STRANDINGS
Bulletin 1724E-200
Page 9-2
Aluminum coating is also available (not to be confused with an aluminum cladding which is
thicker). There is a slight reduction in rated conductor strengths when the heavier zinc or
aluminum coating is used.
9.2.2 ACSR/AW (Aluminum Conductor, Aluminum-Clad Steel Reinforced): ACSR/AW
conductor is similar to conventional ACSR except the core wires are high strength aluminumclad steel instead of galvanized steel. Aluminum-clad core wire has a minimum aluminum
thickness of 20 percent of its nominal wire radius. This cladding provides greater protection
against corrosion than any of the other types of steel core wire, and it is applicable for use where
corrosive conditions are severe. ACSR/AW also has a significantly lower resistivity than
galvanized steel core wire and may provide somewhat lower losses.
9.2.3 AAC (All Aluminum Conductors – 1350 H19): AAC conductor is made up entirely of
hard-drawn 1350 aluminum strands. With a minimum aluminum content of 99.5%, 1350
aluminum is essentially pure aluminum. It is usually less expensive than other conductors, but is
not as strong and tends to sag more. AAC conductors are most useful where electrical loads are
heavy and where spans are short and mechanical loads are low.
7 STRAND
19 STRAND
37 STRAND
37 STRAND
91 STRAND
FIGURE 9-2: 1350 ALUMINUM CONDUCTOR STRANDINGS
9.2.4 AAAC-6201 (All Aluminum Alloy Conductor - 6201 Alloy): AAAC conductor is
composed entirely of 6201-T81 high strength aluminum alloy wires, concentrically stranded and
similar in construction and appearance to 1350 aluminum conductors. Its strength is comparable
with that of ACSR. It was developed to fill the need for a conductor with higher strength than
that obtainable with 1350 aluminum conductors, but without a steel core.
AAAC conductors were designed to have diameters the same as those of standard sizes and
strandings of ACSR. The DC resistance of 6201 conductor is approximately equivalent to that
of standard ACSR conductor with the same diameter. AAAC conductor may be used where
contamination and corrosion of the steel wires is a problem. It has proven to be somewhat more
susceptible to vibration problems than standard ACSR conductor strung at the same tension.
The use of conductor sizes smaller than 3/0 ACSR equivalent on suspension type constructions
should be avoided because the light weight of the conductor may result in inadequate downward
force on the suspension insulators causing radio noise and insulator swing problems.
9.2.5 ACAR (Aluminum Conductor Alloy Reinforced): ACAR conductor consists of 1350
aluminum strands reinforced by a core of higher strength 6201 alloy. These 6201 reinforcement
wires may be used in varying amounts allowing almost any desired property of
strength/conductivity (between conductors using all 1350 wires and those using all 6201 wires)
to be achieved. Strength and conductivity characteristics of ACAR are somewhere between
those of a 1350 aluminum conductor and a 6201 conductor.
Bulletin 1724E-200
Page 9-3
3/4
24/13
33/28
12/7
30/7
48/13
18/19
63/28
54/7
42/19
24/37
72/19
54/37
FIGURE 9-3: TYPICAL ACAR STRANDINGS
9.2.6 AWAC (Aluminum-Clad Steel Conductor): AWAC conductor is made up of
aluminum-clad steel and 1350 aluminum strands. The corrosion resistant aluminum clad wires
of the AWAC conductor act as strength members as well as conductivity members, thereby
reducing the weight of the conductor without reducing strength. For the same designated size
and stranding, the AWAC conductors have a slightly smaller diameter than standard ACSR. For
smaller AWAC sizes, the ratio of aluminum-clad to aluminum strands is varied to provide a wide
range of rated strengths.
9.2.7 ACSR/SD (Aluminum Conductor Steel Reinforced - Self Damping): ACSR/SD
conductor may use either two layers of trapezoidal-shaped aluminum wires or two layers of
trapezoidal-shaped aluminum wires and one layer of stranded round wires of hard-drawn 1350
aluminum. The steel core may be a single wire or stranded depending on the size of the
conductor.
From a performance point of view, ACSR/SD conductor is similar to conventional ACSR except
that it has self damping characteristics. That is, the conductor is designed to reduce aeolian
vibration. The damping occurs because of the interaction between the two trapezoidal layers and
between the trapezoidal layers and the core. Some special considerations associated with this
conductor are that:
•
•
During stringing, special precautions are taken and procedures followed to avoid difficulties.
It may be more expensive than conventional ACSR, but its ability to be strung at higher
tensions to reduce sag, which may result in economic advantages that offset its extra cost.
FIGURE 9-4: TYPICAL ACSR/SD STRANDINGS
Bulletin 1724E-200
Page 9-4
9.2.8 ACSR/TW (Trapezoidal Shaped Strand Concentric - Lay Stranded Aluminum
Conductors, Steel Reinforced): As with ACSR/SD, the conductor layers of ACSR/TW are
trapezoidal-shaped aluminum wires. However, unlike ACSR/SD conductor, no gaps exist
between layers ACSR/TW strands. The compact trapezoidal-shaped wires result in an increased
capacity for an equivalent standard range of ACSR conductor diameters. Also, for a given
aluminum area, a smaller conductor diameter can be designed for ACSR/TW than for equivalent
round-wire ACSR which results in reduced wind-on-wire load on the structure. These are
important advantages when existing transmission lines are considered for uprating or
reconductoring. Other advantages and improvements of ACSR/TW include corrosion resistance
and lower temperature gradient.
Use of ACSR/TW should be based on an economic evaluation to determine whether savings will
be achieved in comparison with the use of conventional ACSR conductor.
9.2.9 AACSR (Aluminum Alloy Conductor, Steel Reinforced): AACSR conductor is the
same as a conventional ACSR conductor except that the 1350 strands are replaced with higher
strength 6201 alloy strands. The resulting greater strength of the conductor allows the sags to be
decreased without exceeding the standard conductor percent tension limits. AACSR type of
conductor is primarily used at river crossings where sag limitations are important. The higher
tensions associated with this type of conductor require that special attention be paid to the
possibility of aeolian vibration.
9.2.10 T2 (Twisted Pair Aluminum Conductor): When designing transmission lines with
twisted pair (T2) type conductor, the designer should be aware of Rule 251 of NESC on
conductor wind loading. The rule states for multiconductor cable an equivalent diameter of two
times the single conductor diameter should be assumed for wind loading unless there is a
qualified engineering study to reduce the overall cable diameter.
9.2.11 High Temperature Conductors: Three types of conductors are considered high
temperature, ACCR (aluminum conductor composite reinforced), ACCCTM (aluminum
conductor composite core) and ACSS (aluminum conductor steel supported). For sizes
equivalent to other types of conductor (i.e., ACSR), higher ampacities can be achieved at similar
overall sag levels while operating the conductors a much higher temperatures. One benefit of
these types of conductors can be the avoided cost of replacing existing structures. The
temperature ratings for these conductors can be limited by hardware, so extreme care should be
used when specifying hardware and establishing operating temperature limits. Also, the unique
natures of these conductors result in the use of special precautins during stringing, such as
special stringing blocks in certain locations and multiple grips when installing conductors with
multi-layer annealed aluminum conductor strands.
ACCR conductors are composed of heat resistant aluminum-zirconium alloy outer strands and
aluminum oxide matrix core strands. . The core of the ACCR is composed of stranded fiber
reinforced metal matrix, an aluminum oxide fiber embedded in high-purity aluminum. The fiber
reinforced metal matrix has strength similar to steel and weight similar to aluminum. The outer
strands may be round or trapezoidal in shape and are similar to 1350 aluminum ultimate strength
but may be heated to high temperatures without softening (annealing) and without losing
strength. Additionally, the thermal expansion of the metal matrix core has less thermal
expansion than steel and retains its strength at high temperatures. ACCR conductors use similar
stranding as ACSR. Because of the lightweight core, heat resistant outer and core strands, higher
electrical conductivity, and lower thermal expansion for less sag, higher operating temperatures
may be used with this conductor which leads to higher ampacities. ACCR conductors and
hardware are usually rated up to 210 C continuous operating temperature with 240 C for short
term maximum operating temperature.
Bulletin 1724E-200
Page 9-5
ACCCTM (Aluminum Conductor, Composite Core) are composed of trapezoidal wire of 1350
aluminum stranded around the composite core. The core of the ACCC conductor is a solid with
no voids and is a carbon/glass fiber polymer matrix core. This solid polymer matrix core is
composed of carbon fibers surrounded by an outer shell of boron-free E-glass fibers that
insulates the carbon from the aluminum conductor. The 1350 aluminum trapezoidal wires are
fully annealed which make them softer compared to the hardened aluminum wires used in some
other conductors. The aluminum strands are tempered because the composite core of the ACCC
is designed to carry the entire load Because the core exhibits a very low coefficient of thermal
expansion, the amount of sag the ACCC will experience when operating at high temperatures is
considerably less than other types of conductor (i.e., ACSR). ACCC TM conductors and hardware
are usually rated up to 180 C continuous operating temperature with 200 C for short term
maximum operating temperature. However, because of the softer temper of the aluminum wires,
the outer wires can be more susceptible to damage from improper installation and handling.
ACSS (Aluminum Conductor, Steel Supported) can be considered as another type of high
temperature conductor which can be supplied with round or trapezoidal aluminum strands.
ACSS conductor is similar to ACSR; however, the aluminum strands in ACSS are fully annealed
and depends on the steel for its strength and sag characteristics. ACSS conductors and hardware
are usually rated up to 250 C or more continuous operating temperature, depending upon the
coating on the steel core, without loss of strength. However, because of the softer temper of the
aluminum wires, the outer wires can be more susceptible to damage from improper installation
and handling.
9.3 Selecting a Conductor Type
9.3.1 Agency Standards: The conductor selected should generally be of a type and stranding
listed as being acceptable for use borrower systems of the Rural Utilities Service. See
Informational Publication 202-1, “List of Materials Acceptable for Use on Systems of USDA
Rural Development Electrification Borrowers”.
9.3.2 Corrosion Considerations: Conductors with galvanized steel cores should not be used in
areas of severe corrosion. Rather, a conductor with other types of core wire, such as mischmetal
or aluminum-clad core wire should be used. A conductor with a steel core wire coated with
aluminum or with a heavier weight zinc may be considered, if such materials have been
successfully (i.e., reliably operated without core deterioration) used in similar locations or
corrosive environments..
9.3.3 Economics: The relative cost of one conductor type versus another is very important.
When comparing costs, one should take overall line costs into consideration. However, a less
expensive conductor with greater sags may not be a more economical selection than a more
expensive conductor with lesser sag. When overall line costs are considered, the conductor that
allows longer spans and shorter structures may prove to be the better choice.
9.3.4 Strength: The strength of the conductor and its ability to sustain mechanical loads
without unreasonable sags must be evaluated.
Bulletin 1724E-200
Page 9-6
9.4 Selection of Conductor Size
9.4.1 Minimum Conductor Size: Table 9-1 provides a list of minimum allowable conductor
sizes for each standard agency transmission voltage. The minimums are based on a combination
of radio noise, corona, and mechanical sag and strength considerations. (See Appendix I for
additional details on radio noise and corona). If a conductor type other than ACSR or 6201
AAAC is used, the conductor diameter should not be less than the diameter of the ACSR
specified for the particular given voltage.
TABLE 9-1
RECOMMENDED MINIMUM CONDUCTOR SIZES
kVLL
ACSR
AAAC - 6201
34.5
46
69
115
138
161
230
1/0
2/0
3/0
266.8 kcmil
336.4 kcmil
397.5 kcmil
795 kcmil
123.3 kcmil
155.4 kcmil
195.7 kcmil
312.8 kcmil
394.5 kcmil
465.4 kcmil
927.2 kcmil
9.4.2 Voltage Drop Considerations: Not only should the conductor be sufficiently large to
meet the requirements of paragraph 9.4.1 of this section, but it should also meet the system
voltage drop requirements. Typically, the conductor impedance would have to be sufficiently
low so that, under a given set of electrical loading conditions, the voltage drop would not exceed
approximately 5 percent. In general, voltage drop becomes a factor for longer lines. Voltage
drop can be evaluated by either running a load flow computer program or by using the estimating
tables in Bulletin 1724E-201, “Electrical Characteristics of Agency Alternating Current
Transmission Line Designs.”
9.4.3 Thermal Capability Considerations: When sizing a phase conductor, the thermal
capability of the conductor (ampacity) should also be considered. The conductor should be able
to carry the maximum expected long-term load current without overheating. Generally, a
conductor is assumed to be able to heat up to 167°F without any long-term decrease in strength.
Above that temperature, there may be a decrease in strength depending on how long the
conductor remains at the elevated temperature. A conductor's ampacity depends not only upon
its assumed maximum temperature, but also on the wind and sun conditions that are assumed.
See Appendix D of this bulletin for ampacity tables.
9.4.4 Economic Considerations: Economics is an important factor in determining conductor
size. The minimum conductor sizes given in Table 9-1 will rarely be the most economical in the
long run. The added cost of a larger conductor may be more than offset by the present worth of
the savings from the lower line losses during the entire life of the conductor. A proper economic
analysis should at a minimum consider the following factors for each of the conductor sizes
considered:
•
•
•
•
The total per mile cost of building the line with the particular conductor being
considered;
The present worth of the energy losses associated with the conductor;
The capital cost per kilowatt of loss of the generation, substation and transmission
facilities necessary to supply the line losses;
Load growth.
Bulletin 1724E-200
Page 9-7
The results of an economic conductor analysis can often be best understood when presented in a
graphical form as shown in Figure 9-5. At an initial load of approximately 200 MW, 1272 kcmil
becomes more economical than 795 kcmil. 954 kcmil is not economical at any load level
included on the graph.
9.4.5 Standardization and Stocking Considerations: In addition to the above factors, the
problem of standardization and stocking should be considered. When a conductor is electrically
and economically optimum, but is not a standard size already in use on the system, the additional
cost and complications of having one more conductor size to stock should be weighed against
the advantages of using the optimum conductor. A proliferation of conductor sizes in use on a
power system is undesirable because of the expense of stocking many sizes. In addition, if a
power system does not standardize on conductors then there may be a need for additional
associated hardware such as end fittings and splices.
20
18
Accumulated
present worth
cost in dollars
x 10,000 per mile
1272
16
954
14
795
12
10
100
140
180
220
260
Assumed Load in MW
FIGURE 9-5: RESULTS OF A TYPICAL ECONOMICAL CONDUCTOR
ANALYSIS – 230 kV, 795 vs. 954 vs. 1272 kcmil ACSR
9.5 Overhead Ground Wires (OHGW)
9.5.1 High Strength or Extra High Strength Galvanized Steel Wires: High strength OHGW
included in Informational Publication 202-1 are 3/8" and 7/16", while extra high strength listed
sizes include 5/16", 3/8", and 7/16". Siemens Martin grade wires of any size and 1/4" steel strand
are not accepted by the agency for use as overhead ground wires. Overhead ground wires are
required to be in full compliance with ASTM A-363, “Standard Specification for Zinc-Coated
(Galvanized) Steel Overhead Ground Wire Strand,” ASTM A-363 does not allow steel wires to
have brazed or welded joints. Steel wires for overhead ground wires are available in three
weights of zinc coating. The standard weight zinc coating is designated as ‘A’. The heavier zinc
coating is designated ‘B’ and ‘C’, with ‘C’ having the heaviest weight of zinc.
Bulletin 1724E-200
Page 9-8
9.5.2 Aluminum-Clad Steel Strand: A thick cladding of aluminum which makes aluminumclad steel strand more resistant to corrosion than strands with a thin coating of zinc. In addition,
the aluminum clad material has greater conductivity.
The sizes of this material that may be used as overhead ground wires are 7 No. 10AWG,
7 No. 9AWG, 7 No. 8AWG, and 7 No. 7AWG. The material is in accordance with ASTM B416,
“Standard Specification for Concentric-Lay-Stranded Aluminum-Clad Steel Conductors.”
9.5.3 Selecting a Size and Type: Selecting an overhead ground wire size and type is dependent
upon only a few factors, the most important of which is how the sag of the OHGW coordinates
with that of the phase conductors. Other factors that may have to be considered are corrosion
resistance and conductivity.
If a line is to be built in a seacoast region or in another location where there is a highly corrosive
atmosphere, aluminum-clad steel wire should be considered. If the OHGW is to be used to carry
any type of communications signal, or if large magnitudes of lightning stroke currents are
expected, a higher conductivity than normal may be desirable.
9.6 Conductor and Overhead Ground Wire Design Tensions
9.6.1 General: Throughout the life of a transmission line, the conductor tensions may vary
between 10 and 60 percent, or more, of rated conductor strength due to change in loading and
temperature. Most of the time, however, the tension will vary within relatively narrow limits,
since ice, high winds, and extreme temperatures are relatively infrequent in many areas. Such
normal tensions may actually be more important in determining the life of the conductor than
higher tensions which are experienced infrequently.
9.6.2 Conductor Design Tensions: In Table 9-3 provides recommended maximum conductor
tension values for ACSR and 6201 AAAC conductors that should be observed for the ruling
span. Note that the values given are maximum design values. If deemed prudent, tensions less
than those specified or loadings greater than the standard loading condition (tension limit for
condition 3 of Table 9-3) may be used. However, it is unwise to base the selection of a
"maximum loading" condition on a single or very infrequent case of excessive loading.
Mountainous areas above 4000 feet in which ice is expected, should be treated as being in heavy
loading district even if they are not.
In open areas where steady winds are encountered, aeolian vibration can be a problem, especially
if conductor tensions are high. Generally, lower tensions at conditions at which aeolian
vibration is likely to occur, can reduce vibration problems (see paragraph 9.9.2 for further
discussion).
Explained below are the several conditions at which maximum conductor tension limits are
specified.
1. Initial Unloaded Tension: Initial unloaded tension refers to the state of the conductor
when it is initially strung and is under no ice or wind load.
2. Final Unloaded Tension: After a conductor has been subjected to the assumed ice and
wind loads, and/or long time creep, it receives a permanent or inelastic stretch. The tension
of the conductor in this state, when it is again unloaded, is called the final unloaded tension.
Bulletin 1724E-200
Page 9-9
3. Standard Loaded Tension: The standard loaded tension refers to the state of a conductor
when it is loaded to the assumed simultaneous ice and wind loading for the NESC loading
district concerned (see Table 11-1, Chapter 11 for the loads associated with each loading
districts). The constants in Table 9-2 are to be added to the vector resultant of the transverse
and vertical loads to get the total load on the conductor:
TABLE 9-2
CONSTANTS TO BE ADDED TO THE TOTAL
LOAD ON A WIRE FOR NESC DISTRICT LOADS
Heavy
Medium
Light
0.30 lbs/ft.
0.20 lbs/ft.
0.05 lbs/ft.
In cases where the standard loaded condition is the maximum mechanical load used in the
calculations, the initial and final sags and tensions for the standard loaded condition will be
the same unless creep is the governing factor. If another condition, such as extreme ice, is
the maximum mechanical load, then the initial and final sags and tensions for the standard
loaded condition can be significantly different from one another. In this case, it is important
that the loaded tension limits be set for initial conditions.
4. Extreme Wind Tension: The extreme wind tension refers to the state of the conductor
when a wind is blowing on it with a value not less than the 50-year mean recurrence interval
(see Figure 11-3 in Chapter 11 of this bulletin). No ice should be assumed to be on the
conductor.
5. Extreme Ice Tension: The tension in a conductor when it is loaded with an extreme
amount of ice for the area concerned is called the extreme ice tension. It should be assumed
that there is no wind blowing when the ice is on the conductor. Values of 1 to 2 in. of radial
ice are commonly used as extreme ice loads.
6. Extreme Ice with Concurrent Wind: The tension in a conductor when it is loaded with an
extreme ice with a concurrent wind (see Figure 11-3 in Chapter 11 of this bulletin).
9.6.3 Controlling Conditions: For a given ruling span, usually only one of the tension limit
conditions will control the design of the line and the others will have relatively little significance
as far as line tensions are concerned.
If the conductor loading under extreme ice or wind loads is greater than under the standard
loaded condition, calculated sag and tension values at other conditions could be somewhat
different from what they would be if the standard loaded condition were the maximum case. In
these situations, stringing sags should be based upon tension limits for tension
conditions 1, 2, and 3 only, as tensions at conditions 4 and 5 are satisfactory.
9.6.4 Overhead Ground Wire (OHGW): To avoid unnecessarily high mechanical stresses in
the OHGW, supporting structures, and guys, the OHGW should not be strung with any more
tension than is necessary to coordinate its sags at different conditions with the phase conductors.
See Chapters 6 and 8.
Bulletin 1724E-200
Page 9-10
TABLE 9-3
RECOMMENDED CONDUCTOR AND OVERHEAD
GROUND WIRE TENSION AND TEMPERATURE LIMITS (Note B)
Temperatures
•
Tension limits for conditions 1, 2 and 3 below are to be met at the following temperatures:
Heavy loading district
0º F
Medium loading district
15º F
Light loading district
30º F
•
Tension limits for condition 4 are to be met at the temperature at which the extreme wind is
expected.
Tension limits for condition 5 & 6 are to be met at 32º F
•
Tension Condition
(See section 9.6.2 for explanation)
Tension Limits
(percentage of rated breaking strength)
OHGW High
OHGW Extra
Conductor
Strength Steel
High Strength
Steel
1. Maximum initial unloaded
33.3 (Note C)
25
20
2. Maximum final unloaded
25 (Note D)
25
20
3. Standard Loaded (usually NESC
district loading)
50
50
50
4. Maximum extreme wind (Note A)
70 (Note E)
80
80
5 . Maximum extreme ice (Note A)
70 (Note E)
80
80
6. Extreme ice with concurrent wind
70 (Note E)
80
80
Notes:
(A) These limits are for tension only. When conductor stringing sags are to be determined, tension limits
1, 2 and 3 should be considered as longs as tensions at conditions 4, 5 and 6 are satisfactory.
(B) Tension limits do not apply for self-damping and other special conductors.
(C) In areas prone to aeolian vibration, a value of approximately 20 percent at the average annual
minimum temperature is recommended, if vibration dampers or other means of controlling vibration are
not used (see section 9.9 for further details).
(D) For 6201 AAAC, a value of 20 percent is recommended.
(E) For ACSR only. For 6201 Aluminum, use 60 percent.
Bulletin 1724E-200
Page 9-11
9.7 Ruling Span
9.7.1 Why a Ruling Span? If all spans in a section of line between deadends are of the same
length, uniform ice and wind loads will result in equal conductor tension in all spans. But span
lengths usually vary in any section of line, with the result that temperature change and ice and
wind loads will cause conductor tensions to become greater in the longer spans and less in the
shorter spans when compared to the tensions of loaded uniform spans. Movement of insulator
strings and/or flexing of the structures will tend to reduce this unequal tension. It is possible,
however, for conductor tension in long spans to reach a value greater than desired unless the line
is spotted and the conductor strung to limit this undesirable condition.
A ruling span is an assumed uniform design span which approximately portrays the mechanical
performance of a section of line between its deadend supports. The ruling span is used in the
design and construction of a line to provide a uniform span length which is representative of the
various lengths of spans between deadends. This uniform span length allows sags and
clearances to be readily calculated for structure spotting and conductor stringing.
Use of a ruling span in the design of a line assumes that flexing of the structure and/or insulator
string deflection at the intermediate supporting structures will allow for the equalization of
tension in the conductor between adjacent spans to the ruling span tension.
9.7.2 Calculations of the Ruling Span: On a line where all spans are equal, the ruling span is
the same length as the line spans. Where spans vary in length, the ruling span is between the
shortest and the longest span lengths on the line, but is mainly determined by the longer spans.
•
Approximate Method. Some judgment should be exercised in using this method since a
large difference between the average and maximum span may cause a substantial error in
the ruling span value.
RS = Lavg + 2 / 3(Lmax − Lavg )
Eq. 9-1
where:
RS = ruling span in feet.
Lavg = average span in a line segment between deadends, in feet.
Lmax = maximum span in a line segment between deadends, in feet.
•
Exact Method. The following is the exact formula for determining the ruling span in a
line segment between deadend structures:
L1 + L2 + L3 + K + Ln
L1 + L2 + L3 + K + Ln
3
RS =
3
3
3
Eq. 9-2
where:
L1, L2, L3, etc. = the different span length in the line segment, in feet
Other symbols are as previously defined.
Bulletin 1724E-200
Page 9-12
9.7.3 Establishing a Ruling Span: As can be seen from Equation 9-2, the exact value of the
ruling span can only be calculated after the structures have been spotted and all the span lengths
determined. However, the ruling span has to be known in advance of structure spotting. Thus
the ruling span needs to be estimated before spotting structures on the plan-profile drawings.
When following any procedure for estimating ruling span, keep in mind that estimation of a
ruling span is an intuitive process based on experience, judgment, and trial and error. A good
starting point for estimating ruling span is the height of the base structure. The base structure is
the structure that is expected to occur most often throughout the line. After assuming a base
structure height, subtract the minimum ground clearance value from the height of the lowest
phase conductor above ground at the structure. The allowable sag as limited by ground
clearance is the result. Using this sag value and tables of sags for various ruling span lengths, a
ruling span length can be chosen whose sag is approximately equal to the allowable sag for the
base structure height. In other words, a ruling span is chosen to be approximately equal to the
level ground span -- the maximum span limited by line-to-ground conductor clearance for a
particular height structure. This method of choosing a ruling span is useful if the terrain is flat or
rolling. However, if it is rough, the ruling span should be somewhat greater than the level
ground span.
The ruling span value initially chosen should be checked to see that it coordinates reasonably
well with the minimum span values as limited by such factors as structure strength, conductor
separation, galloping, etc. Also, Equation 9-1 should be used in conjunction with estimated
maximum and average span values to further check the reasonableness of the estimated ruling
span. If the initial estimate does not check out, the value should be changed and the procedure
repeated.
In cases where the spans in one extended section of line are consistently and considerably longer
or shorter than in another section of line, use of more than one ruling span may be unavoidable.
It is a common practice to permit long spans to double the average span without deadends,
provided conductor tension limits are satisfactory. In addition, short spans should not be less
than approximately one-half of the ruling span. After the plan and profile sheets are plotted, the
validity of the estimated ruling span value should be checked by comparing it to the actual value
obtained. It is not essential that the estimated ruling span value be equal to the actual value,
provided the estimated ruling span results in satisfactory ground clearance and economical
structure spotting without excessive conductor tensions. However, if the difference between the
estimated and actual ruling span is more than approximately 15 percent, the effects resulting
from the difference should be carefully checked.
9.7.4 Effects of the "Wrong" Ruling Span: It is important that the actual ruling span be
reasonably close to the ruling span value that is used to spot the line. If this is not the case, there
may be significant differences between the predicted conductor tensions and clearances and the
actual values. There have been instances where sags were greater than predicted, resulting in
clearance problems, because the wrong ruling span was assumed. Table 9-4 will be of use in
determining how conductor sags differ from the predicted value when there are differences
between actual and assumed ruling span. Note that tension variation is opposite of that of the
sags. Thus, increased sags mean decreased tension and vice versa.
Bulletin 1724E-200
Page 9-13
TABLE 9-4
DIRECTION OF DEVIATION OF SAGS FROM
PREDICTED VALUES WHEN ACTUAL AND ASSUMED (DESIGN)
RULING SPAN VALUES ARE SIGNIFICANTLY DIFFERENT
(Applies to Unloaded Condition)
Conductor temperature is
less than temperature at
which the conductor was
strung
Conductor temperature is
greater than temperature at
which the conductor was
strung
Assumed RS
is greater than
Actual RS
Assumed RS
is less than
Actual RS
Actual sag is less than
predicted-INCREASED
TENSIONS
Actual sag is greater than
predicted-CLEARANCE
PROBLEMS
Actual sag is greater than
predicted-CLEARANCE
PROBLEMS
Actual sag is less than
predicted-INCREASED
TENSIONS
CLEARANCE PROBLEMS – Conductor sags greater than indicated on the plan and
profile sheets may result in clearance problems
INCREASED TENSIONS – Conductor tensions greater than anticipated will result
9.8 Determining Conductor Sags and Tensions: Determination of conductor sags and
tensions, given a set of tension limits as outlined in section 9.6, is a complex and difficult task.
This is true because only one of the tension limits may control, and it is not always predictable
which limit it will be. In addition, it is necessary to work with conductor stress strain curves
which for a compound conductor such as ACSR can be rather complex.
The best method of obtaining conductor sag and tension values is to use one of the numerous
computer programs written for that purpose. When using a computer program, several factors
should be checked:
•
The program should be written so that a check is made of all the limiting conditions
simultaneously and the governing condition noted.
•
The program should take conductor creep into account.
•
The tension values given should be average tension values and not tension at support
or horizontal tension values.
•
The source of the stress stain data used should be indicated.
If computerized sag tension values are not available from the software, values can be generated
using the graphical method given in the publication, "Graphic Method for Sag Tension
Calculations for ACSR and Other Conductors," Publication No. 8, Aluminum Company of
America, 1961.
Bulletin 1724E-200
Page 9-14
9.9 Aeolian Vibration
9.9.1 General: Overhead conductors of transmission lines are subject to aeolian and galloping,
both of which are produced by wind. Galloping is discussed in section 6.3. Aeolian vibration is
a high-frequency low-amplitude oscillation generated by a low velocity, comparatively steady
wind blowing across the conductors. This steady wind will create air vortices or eddies on the
lee side of the conductor. These vortices or eddies will detach at regular intervals from the top
and bottom area of the conductor creating a force on the conductor that is alternately impressed
from above and below. If the frequency of the forces approximately corresponds to a frequency
of a mode of resonant vibration of the span, the conductor will tend to vibrate in many loops in a
vertical plane. The frequency of vibration depends mainly on conductor size and wind velocity
and is generally between 5 and 100 Hz for wind speeds within the range of 0 to 15 miles per
hour. The peak-to-peak amplitudes of vibration will cause alternating bending stresses great
enough to produce fatigue failure in the strands of the conductor or OHGW at the points of
attachment. Highly tensioned conductors in long spans are particularly subject to vibration
fatigue. This vibration is generally more severe in flat open terrain where steady winds are more
often encountered.
The frequency and loop length of the vibration can be determined using equation 9-3.
Frequency of the vibration:
f = 3.26
V
dc
Eq. 9-3
where:
f = frequency of conductor vibration in Hertz
V = transverse wind velocity in miles per hour
dc = conductor diameter in inches
Loop Length (for a conductor that is assumed to have negligible stiffness):
LL =
1
2f
⎛ (Tavg )( g ) ⎞
⎜⎜
⎟⎟
⎝ wc ⎠
Eq. 9-4
where:
LL = loop length in feet
Tavg = average conductor tension in pounds
wc = unit weight of conductor in pounds per foot 2
g = universal gravitational constant, 32.2 ft/sec
Other symbols are as previously defined.
9.9.2 Designing for Vibration Problems: If an area is expected to have aeolian vibration
problems, measures ‘a’ through ‘d’ may be taken to mitigate possible problems with damage to
conductors, shield wire, and hardware. It is also important to note that structures, not just
conductors, shield wires, and hardware, may be adversely affected by vibration. The measures
are not necessarily mutually exclusive; more than one measure may be used simultaneously.
Bulletin 1724E-200
Page 9-15
a. Reduced Tension: The two line design variables that have the greatest effect upon a
line's vibration characteristics are conductor tension and span length. Singly or in
combination, these two variables can be reduced to the point where the level of vibration,
without any vibration damping devices, will not be damaging. For similar sag
characteristics, conductors of different types, with their different characteristics, may
require a different degree of vibration protection.
A rule of thumb that has proved generally successful in eliminating vibration problems is
to keep the conductor tension for short and medium length spans under initial unloaded
conditions at the average annual minimum temperature to approximately 20 percent or
less of the conductor's rated strength. For long spans, a somewhat lower percent tension
limit should be used. Due to their vibration characteristics, 6201 AAAC and 1350
aluminum conductors should be held to tensions somewhat lower than the 20 percent
value, even for relatively short spans.
b. Armor Rods: In addition to reinforcing the conductor at the support points, armor rods
provide a small amount of damping of aeolian vibration. In lines with lower conductor
tension and shorter spans, this damping may provide adequate protection against
conductor strand fatigue.
c. Cushioned Suspensions: Cushioned suspensions combine armor rods with a resilient
cushioning of the conductor. These suspension clamps provide somewhat more damping
than armor rods, but the degree of damping is still relatively small compared to vibration
dampers.
d. Dampers: Stockbridge and other types of dampers are effective devices for controlling
vibration. The selection of damper sizes and the best placement of them in the spans
should be determined by the damper or conductor manufacturer on the basis of the
tension, weight, and diameter of the conductor and the expected range of wind velocities.
The length of the suspension clamp and the effect of the armor rods or cushioned
suspensions should also be considered. With new efficient damper designs and usual
conductor tensions and span lengths, one damper is installed near one span support joint.
For long spans, additional dampers may be required.
9.10 Galloping: See Chapter 6 for details.
9.11 Maximum Possible Single Span: For a given span length, as the sag is increased, the
tension at the support will decrease, until a point is reached where the tension will begin to
increase due to the weight of the conductor. This point occurs when the sag is equal to 0.337
times the span length.
The relationship between span length and tension can be expressed as:
Lmax = 1.33
T
wc
where:
wc = unit weight of conductor in pounds per foot
T = resultant tension at support, pounds
Lmax = maximum span, feet
Eq. 9-5
Bulletin 1724E-200
Page 9-16
The above formula can be used to determine the maximum possible span given a maximum
tension at supports. This is most useful when dealing with river crossings, etc.
9.12 Sag and Tension Relationships: The relationships in paragraphs 9.12.1 through 9.12.3
are useful for understanding the sag-tension relationships for conductors:
9.12.1 Level Span Sags: Equation 9-6, the approximate "parabola method", is helpful in
solving some sag and tension problems in span lengths below 1,000 feet, or where sag is less
than 5 percent of the span length.
wc L2
S=
8Th
Eq. 9-6
where:
S = sag at center of span in feet
L = span length in feet
Th = horizontal tension in pounds
The exact formula for determining sags is:
S=
Th
wc
⎛
wL ⎞
⎜⎜ cosh c − 1⎟⎟
2Th
⎠
⎝
Eq. 9-7
9.12.2 Inclined Span Sags: See Figure 9-6 for method of determining inclined span sags.
9.12.3 Tension: The conductor tension in a level span varies from a maximum value at the
point of support to a minimum value at mid-span point.
The tension at the point of support is:
T = Th + wc S = Th cosh
wc L
2Th
Eq. 9-8
The value that is generally referred to, when the "tension" of a conductor is indicated, is usually
the average of the tension at the support and the tension at mid-span. Thus:
Tavg =
Th + T
wS
= Th + c
2
2
where:
Tavg = average tension in pounds
Eq. 9-9
Bulletin 1724E-200
Page 9-17
4000
3000
2500
L
25
S
B
SAG
3500
20
C
30
35
40
45
50
700
600
500
400
300
200
(Add to horizontal spacing to obtain
equivalent span length)
1000
900
800
EQUIVALENT SPAN CORRECTION
HORIZONTAL SPACING OF
SUPPORTS (L.)
1500
Formula for equivalent span length:
Equiv. deadend span = 2C-A
Equiv. suspension span = √AC
*For spans between a
suspension and deadend
*For spans between a
tower, use suspension
suspension and deadend
correction.
tower, span
use suspension
span
2
3
4
5
2.5
10
15
20
25
30
40
50
60
80
100
150
200
250
300
5
7.5
10
12.5
15
20
25
37.5
50
62.5
75
Example: AssumeEXAMPLE
span with A=1000 ft,
B = 100 ft. if deadend span correction = 10 ft
(see above). If suspension span, correction =2.5
Assume
with L=1000',
B=100'
ft (see
above).span
Equivalent
span = 1000
ft +
correction . Read
sag for
equivalent span
If chart
deadend
span,
length.
VERTICAL SPACING OF SUPPORTS
(B.)
2000
60
70
80
90
100
150
200
250
300
350
400
500
correction = 10' (see above)
100
If parabolic
suspension
span, If sag
Sag is based on
functions.
exceeds 5
% of span, =do25'
not(see
use this
chart.
correction
above)
Equivalent span = 1000' + correction.
Read chart sag for equiv. span length.
FIGURE 9-6: NOMOGRAPH FOR DETERMINING LEVEL SPAN
EQUIVALENTS OF NON-LEVEL SPANS
From IEEE Standard 524-1992, “IEEE Guide to the Installation of Overhead Transmission Line
Conductors,” copyright 1992 IEEE. All rights reserved.
Bulletin 1724E-200
Page 9-18
9.13 Stringing Conductors
9.13.1 Tension Method (Preferred) for Stringing Conductors: Using this method, the
conductor is kept under tension during the stringing process. Normally, the tension method is
used to keep the conductor clear of the ground and of obstacles which might cause conductor
surface damage and clear of energized circuits. The method requires pulling a light pilot line
into the sheaves. The pilot line is then used to pull a heavier line. The heavier pulling line is
used to pull conductors from reel stands using specially designed tensioners and pullers. For
lighter conductors, a lightweight pulling line may be used in place of the pilot line to directly
pull the conductor. A helicopter or ground vehicle can be used to pull or lay out a pilot line or
pulling line. When a helicopter is used to pull a line, synthetic rope is normally used to attach
the line to the helicopter and prevent the ‘pilot line’ or pulling line from flipping into the rotor
blades upon release. With the tension method, the amount of right-of-way travel by heavy
equipment can be minimized. Usually, this tension method provides the most economical means
of stringing conductor. Use of a helicopter is particularly advantageous in rugged or poorly
accessible terrain.
Major equipment required for tension stringing includes reel stands, tensioner, puller, reel
winder, pilot line winder, splicing cart and helicopter or pulling vehicle.
9.13.2 Slack or Layout Method: Using this method, the conductor is dragged along the
ground by means of a pulling vehicle, or the reel is carried along the line on a vehicle and the
conductor is deposited on the ground. Conductor reels are positioned on reel stands or "jacks,"
either placed on the ground or mounted on a transport vehicle. These stands are designed to
support the reel on an arbor, permitting the reel to turn as the conductor is pulled. Usually a
braking device is provided to prevent overrunning and backlash. When the conductor is dragged
past a supporting structure, pulling is stopped and the conductor placed in sheaves attached to
the structure before proceeding to the next structure.
This method is chiefly applicable to the construction of new lines where maintenance of
conductor surface condition is not critical and where terrain is easily accessible to a pulling
vehicle. The method is not usually economically applicable in urban locations where hazards
exist from traffic or where there is danger of contact with energized circuits, nor is it practical in
mountainous regions inaccessible to pulling vehicles.
Major equipment required to perform slack stringing includes reel stands, pulling vehicle(s) and
a splicing cart.
9.13.3 Stringing Conductors During Temperature Changes: An examination of conductor
sag and tension tables will generally indicate the changes that take place in various span lengths
with a change of conditions. For a given set of conditions, spans of various lengths may have a
different rate of tension change with a change of loading or temperature. The ruling span tension
of an unloaded conductor matches the tension of any other span only at one temperature. Large
changes in temperature during stringing require care in matching average tensions in any section.
It is desirable to complete stringing between deadends during periods of minimum temperature
change and at zero wind load. Where spans are supported by suspension insulators, each span
will have an influence on adjacent spans such that no span can be considered independently
of the remainder of spans in the same section between anchor structures. Change in temperature
has a greater effect on short spans than loading does, while long spans are affected more by
loading. In short spans a slight movement of supports results in substantial changes in tension
while in longer spans, relatively greater movement is required. The relation between adjacent
span lengths therefore determines the movement required to equalize tension.
Bulletin 1724E-200
Page 9-19
9.14 The Sagging of Conductors: It is important that the conductors be properly sagged in at
the right stringing tension for the ruling span used. When installing conductors, a series of
several spans is usually sagged in one operation by pulling the conductors to proper tension
while they are supported on free rolling sheaves. To obtain the correct sags and to ensure that
the suspension insulators will hang vertically, the horizontal components of tension must be the
same in all spans for a selected condition. In a series of spans of varying length, greater sag
tends to form in the long spans. On steep inclines the sheaves will deflect in the uphill direction
and there will be a horizontal component of tension in the sheave itself. The horizontal
component of tension in the conductor will therefore increase from one span to the next, as the
elevation increases, by an amount equal to the horizontal component in the sheave. As a result,
sags will proportionally decrease. In order to avoid this effect, it may be necessary to use a
procedure called offset clipping. In this procedure, the point along the conductor at which it is
attached to the insulator string is moved a specific distance down span from the point at which
the conductor sits in the stringing block. See Figure 9-7 for further details on offset clipping.
It is important that the sags of the conductor be properly checked. It is best to do this in a series
of level spans as nearly equal to the ruling span as possible.
For additional information, see:
“A Guide to the Installation of Overhead Transmission Line Conductors,” IEEE
Standard 524-1992, IEEE, 1992.
Bulletin 1724E-200
Page 9-20
∑ CONDUCTOR LENGTH IN TRAVELERS = ∑ CONDUCTOR LENGTH IN SUSPENSION CLAMPS
FIGURE 9-7: ANALYSIS FOR APPLICATION OF CLIPPING OFFSETS
From IEEE Standard 524-1992, “IEEE Guide to the Installation of Overhead Transmission Line
Conductors,” copyright 1992 IEEE. All rights reserved.
Bulletin 1724E-200
Page 9-21
9.15 Example 9-1: Determination of Ruling Span: Determine the ruling span for the line
segment given below using both the exact and approximate method.
925 ft
1380 ft
495 ft
1005 ft
FIGURE 9-8: LINE SECTION FOR EXAMPLE 9-1
Solution, Exact Method:
RS =
L1 + L2 + L3 + K + Ln
L1 + L2 + L3 + K + Ln
RS =
925 3 + 1380 3 + 495 3 + 1005 3
925 + 1380 + 495 + 1005
3
3
3
3
See Eq. 9-2
RS = 1094 ft.
Solution, Approximate Method:
RS = Lavg + 2/3(Lmax - Lavg)
See Eq. 9-1
Lavg = (925 + 1380 + 495 + 1005)/4 = 951 ft.
Lmax = 1380
RS = 951 + 2/3(1380 - 951)
RS = 1237 ft.
As previously mentioned in the text, the error between the exact and approximate methods of
determining ruling span is caused by a rather significant error between the average and
maximum span values.
9.16 Example 9-2, Maximum Span Determination: Determine the maximum span (for river
crossings, etc.) for a 795 kcmil 26/7 ACSR conductor. Assume that under heavy loading district
conditions, the conductor can be loaded up to 40 percent of its rated strength.
Bulletin 1724E-200
Page 9-22
Solution: From the conductor tables in Appendix B, the rated strength of the conductor is
31,500 lbs. and the weight of the conductor with 1/2 in. of radial ice is 2.0930 lbs/ft..
T = 31500(0.4) = 12600 lbs.
Lmax = 1.33
T
wc
See Eq. 9-5
Lmax = 1.33 12600 lbs. = 8007 ft.
2.0930 lbs/ft.
9.17 Example 9-3, Determination of Tensions at the Mid Span Point and at the Point of
Support: A level 800 ft. span of 795 kcmil 26/7 ACSR conductor has a sag of 21.95 ft. The
average tension value is 9,185 lbs. and there is no ice or wind on the conductor. Determine the
actual tension values at the mid span point and at the point of conductor support.
Solution for the Tension at Mid Span Point:
Th + T
wS
= Th + c
2
2
wS
Th = Tavg − c
2
Tavg =
See Eq. 9-9
From the conductor tables in Appendix B, the weight of the conductor without ice is
1.0940 lbs/ft.
Th = 9185 - (1.094)(21.95)
2
Th = 9173 lbs.
Solution for the Tension at Support:
T = Th + wc S = Th cosh
wc L
2Th
T = Th + wcS
T = 9173 + (1.094)(21.95)
T = 9197 lbs.
See Eq. 9-8
Bulletin 1724E-200
Page 10-1
10. PLAN-PROFILE DRAWINGS
10.1 General: Transmission line plan-profile drawings serve an important function in linking
together the various stages involved in the design and construction of the line. Initially, the
drawings are prepared based on a route survey. These drawings show the location and elevation
of all natural and man-made features to be traversed by, or which are adjacent to, the proposed
line which may affect right-of-way, line design and construction. They also indicate ownership
of lands near the line. The drawings are then used to complete line design work such as structure
spotting. During material procurement and construction, the drawings are used to control
purchase of materials and they serve as construction specification drawings. After construction,
the final plan-profile drawings become the permanent record and right-of-way data, useful in line
operation and maintenance or future modifications.
Accuracy, clarity, and completeness of the drawings should be maintained, beginning with initial
preparation, to ensure economical design and correct construction. All revisions made
subsequent to initial preparation and transmittal of drawings should be noted in the revision
block by date and brief description of revision. Originals of the plan-profile drawings, revised
for as-built conditions, should be filed by the borrower for future reference.
10.2 Drawing Preparation: Adequate control of field survey, including ground check of aerial
survey, and proper translation of data to the plan-profile drawings are of utmost importance.
Errors which occur during this initial stage will affect line design because a graphical method is
used to locate the structures and conductor. Normally, plan-profile sheets are prepared using a
scale of 200 feet to the inch horizontally and 20 feet to the inch vertically. On this scale, each
sheet of plan-profile can conveniently accommodate about 1 mile of line with overlap to connect
the end span on adjacent sheets. On lines with abrupt ground terrain changes and on lines where
there is need to minimize breaks in elevation view, plan-profile sheets may use a scale of one
inch equal to 400 feet horizontally and one inch equal to 40 feet vertically may be used.
A sample format for plan-profile drawing, detailing dimensions and stationings in U.S.
customary (English) units, is shown in Figure 10-1. Stationing and structure numbering
increases from left to right and the profile and corresponding plan view are included on the same
sheet. Drawings prepared in ink on Mylar or tracing cloth will provide a better permanent record
than on paper. However, structure spotting initially should be marked in pencil on plan-profile
drawing paper and transferred to the base tracings in ink after the drawings are approved and the
line is released for construction.
Conventional symbols used to denote features on the drawings are shown in Figure 10-2.
Features of existing obstacles, structures, etc. to be crossed by the transmission line, including
the height and position of power and telecommunication lines, should be shown and noted by
station and description in both the plan and profile views. The magnitude and direction of all
deflection angles in the line should be included and referenced by “P.I. Station No. XX” in plan
and elevation views. (P.I. refers to point of intersection). In rough terrain, broken lines
representing side-hill profiles should be accurately plotted to assure final designs will provide for
adequate conductor-to-ground clearances and pole heights. A drawing title block should be
included. The block should identify the line and include the station numbers that are covered on
the drawing sheet. The block should also include space for recording the names of personnel
and the dates involved in various stages of drawing preparation, line design, checking, approval,
and revisions.
Line design computer software may be used to import survey data and develop the land profile
for the transmission line. Developments in surveying technologies have allowed the industry to
go beyond the station-elevation-offset formats that have traditionally been used for transmission
profile
Bulletin 1724E-200
Page 10-2
FIGURE 10-1: SAMPLE OF A PLAN AND PROFILE
Bulletin 1724E-200
Page 10-3
PLAN
CL
Transmission Line
Telephone Lines
Property Lines
R/W Lines
State Lines
County Lines
T
T
T
T
T
Township, Range,
and District Lines
Section Lines
U.S. 40
Highway and Main Roads
8 ft. gravel
Local Roads
Railroads
Fences (all kinds)
O P S 69kV
Existing O.H. Power Line
(Ownership and Voltage)
Smaller Streams
Wooded section
Creeks
Orchard
Rivers
Marsh
Depression
Ponds
Buildings (State Kind)
Barn
PROFILE
Center Line
Sidehill, right
Sidehill, left
P.I.
(Point
Point
of of
Intersection)
Intersection
(P.I.)
FIGURE 10-2: CONVENTIONAL SYMBOLS FOR PLAN-PROFILE
Bulletin 1724E-200
Page 10-4
modeling. Use of three-dimensional Geographical Information System (GIS) modeling is
becoming more common. Total station, geographical positioning system, photogrammetry, and
electronic topographical maps (United States Geological Survey, USGS, maps) have been
employed to collect data in electronic format and to develop quick and accurate terrain plan and
profile for transmission lines.
Design software can use a three-dimensional survey format and develop profile drawings of the
terrain along the centerline of the line. Some software can create interpolated points on profiles
by creating a Triangular Irregular Network (TIN). The TIN can be used to develop a threedimensional rendering of a transmission line.
Once the alignment and profile have been developed, computer programs are then used to spot
structures along the profile. For an established family of structures, the computer can be used to
automatically spot structures for the most economical line cost or the user may manually spot
structures. Programs have been developed to automatically plot the sag curve of the conductor
and to check insulator swing, structure strength, and clearances. A material list is often
developed from computer generated plan-profile drawings.
Computer aided drafting and design software may provide all or part of the following:
•
•
•
•
•
•
•
•
Importing survey data, to model terrain, and to create a profile;
Modeling of structure, including strength, geometry, insulator swing and complete bill of
material;
Calculating conductor sag and tension;
Locating structures (spotting) on the profile drawing;
Calculating conductor stringing and sagging, at almost any temperature, to check design
conditions such as uplift, ground clearance or insulator swing;
Checking the line plan-profile against specific design criteria;
Displaying the plan-profile or structure analysis in three dimensions; and
Preparing reports and construction documents showing all construction material units on the
plan and profile, as well as developing material reports, staking tables, offset clipping
reports, etc.
Some design programs provide more custom drafting capabilities. Some are AutoCAD based;
others are MICRO STATION based. Traditional methods used to spot structures can be as much
as 70-80 percent more conservative than the computer aided design and drafting approach.
10.3 Sag Template: When computers are not used to spot structures and draw the conductor
sag curve, manual techniques are used. Once the profile of the line has been drawn, the next step
is to develop a sag template. The sag template is a scaling device used for structure spotting and
for showing the vertical position of conductor (or ground wire) for specified design conditions .
A sample conductor sag template is shown by Figure 10-3. The template is used on plan-profile
drawings to graphically determine the location and height of supporting structures required to
meet line design criteria for vertical clearances, insulator swing, and span limitations. The sag
template permits alternate layout for portions of the line to be investigated and thereby aids in
optimizing line design for economy.
Generally, the conductor sag curves control the line design. The sag template for the overhead
ground wire is used to show the position of the wire in relationship to the conductors for special
spans or change in conductor configuration. An uplift condition at the overhead ground wire
may be checked by using the template cold curve.
Bulletin 1724E-200
Page 10-5
10.3.1 Sag Template Curves: The sag template should include the following sag curves based
on the design ruling span:
a. Hot (Maximum Sag) Curve: At maximum operating temperature, no ice, no wind, final sag
curve, the hot curve is used to check for minimum vertical clearances. However, if the
maximum sag occurs under an icing condition, this sag curve should be used for the sag
template.
b. Cold Curve: At minimum temperature, no ice, no wind, initial sag curve, the cold curve is
used to check for uplift and insulator swing.
c. Normal Curve: At 60°F, no ice, no wind, final sag curve, the normal curve is used to check
normal clearances and insulator swing.
Sag curves are also used to locate the low point of sags and determine the vertical span lengths
as illustrated by Figure 10-6. The curve intersection with the vertical axis line represents the low
point position of sag.
Conductors of underbuild lines may be of different types or sizes than the transmission
conductor. The hot curve of the lowest distribution conductor should be used for checking
ground clearance. Cold curves may be required for each size of conductor to check for uplift or
insulator swing.
10.3.2 Sag Template Design: Sag templates may be developed from information provided by
the manufacturer of the conductor or from a graphical calculation method. Sag values needed to
construct the template are available from the conductor manufacturer for a given conductor,
ruling span, design condition and temperature. Sag values may also be determined using the
graphic method referred to in Section 9.8 of Chapter 9. The template should be made to include
spans three or four times as long as the normal level ground span to allow for spotting structures
on steep terrain.
The form of the template is based on the fact that, at the time when the conductors are installed,
horizontal tensions have to be equal in all level and inclined spans if the suspension insulators
are plumb in profile. This is also approximately true at maximum temperature. To obtain values
for plotting the sag curves, sag values for the ruling span are extended for spans shorter and
longer than the ruling span. Generally for spans up to 1000 feet, it is sufficiently accurate to
assume that the sag is proportional to the square of the spans (unless more accurate computed
sag values are unavailable). The sag values used for the template may be determined as follows:
a. For the ruling span and its sag under each appropriate design condition and temperature,
calculate other sags by the relationship:
2
⎛ L ⎞
S =⎜
⎟ (S RS )
⎝ RS ⎠
where:
S =
SRS =
L =
RS =
Eq. 10-1
sag of other span in ft.
sag of ruling span in ft.
length of other span in ft.
ruling span sag in ft.
b. Apply catenary sag correction for long spans having large sags.
Bulletin 1724E-200
Page 10-6
The template should be cut to include a minimum of one foot additional clearance than given in
Table 4-1 (Chapter 4), to account for possible minor shifts in structure location and error in the
plotted profile. Where the terrain or the surveying method used in obtaining ground profile is
subject to greater unknowns or tolerances, the one foot additional clearance should be increased.
The vertical offset between the upper two maximum temperature (hot) curves is equal to the total
required clearance, including the specified additional clearance. It is shown as dimension "C" in
Figures 10-3 and 10-4. The minimum temperature and the 60°F curves may be placed in any
convenient location on the template.
A sag template drawing similar to Figure 10-3, made to the same scales as the plan-profile
sheets, should be prepared as a guide for cutting the template. This template is made for a
specified conductor, ruling span, and loading condition. A new template should be prepared for
each line where there is any variation in voltage, conductor size, loading condition, design
tension, or ruling span. A change in any one of these factors may affect the design
characteristics of the template.
CONDUCTOR: 336.4 kcmil ACSR (26/7)
RULING SPAN: 500ft
MAX. DESIGN TENSION : 5786 lb.
DESIGN LOADING: 1/2 in. ice, 4 psf wind @ 0°F
Structure Height
Scale
TS-1
90
85
80
75
70
65
60
55
50
G
Ground
level
SCALE: HORIZONTAL 1" = 200 ft
1" = 20 ft
VERTICAL
0°F Initial
Cold Curve
60°F FINAL
Normal Curve
167°F FINAL
Hot Curve
C
B
FIGURE 10-3: SPECIMEN SAG TEMPLATE FOR CONDUCTOR
(Reduced size, not to scale)
B = Sag for the level ground span, C = Total Ground Clearance,
G = Dimension from ground to point of attachment of lowest conductor
Bulletin 1724E-200
Page 10-7
10.3.3 Sag Template Construction: The sag template should be made of dimensionally-stable
transparent plastic material. A contrasting colored material (for example, red) is very helpful
when the template is used to check plan-profile blueprint drawings.
Curves are first plotted on paper using the correct scales and then reproduced or copied on the
plastic material. To cut a template, the transparent material is fastened securely over the curves
drawn on paper and the centerline and upper curves are etched lightly by a sharp-pointed steel
scriber. The outside edges of the template should be etched deeply so that the template can be
easily broken out and the edges sanded smooth. Structure height scales may also be drawn or
etched on the sag template, or a separate template, for determining the pole height required for
each type of structure used. Etched lines should be filled with ink to make them easier to see
when the template is used.
Conductor size, design tension and loading condition as well as ruling span and descriptive data
for each curve should be shown on the template.
10.4 Structure Spotting
10.4.1 General: Structure spotting is the design process which determines the height, location,
and type of consecutive structures on the plan-profile sheets. Actual economy and safety of the
transmission line depends on how well this final step in the design is performed. Structure
spotting should closely conform to the design criteria established for the line. Constraints on
structure locations and other physical limitations encountered may prevent spotting of structures
at optimum locations. Success of the effort to minimize or overcome these special conditions
can be judged by how closely the final line layout follows the original design parameters.
Desired objectives of a well-designed and economical line layout are:
a. Spans should be approximately uniform in length, equal to or slightly less than the design
ruling span. Generally, differential conductor tensions are minimized and may be ignored if
adjacent span lengths are kept below a ratio of 1.5 to 1.
b. Maximum use should be made of the basic structure of equal height and type. The basic
structure is the pole height and class which has been selected as the most economical structure
for the given design condition.
c. The shape of the running conductor profile, also referred to as the grading of the line, should
be smooth. If the conductor attachment points at the structures lie in a smooth-flowing curve,
the loadings are equalized on successive structures.
For a generally level and straight line, with few constraints on structure locations, there is no
conflict between these objectives. They can be readily achieved. Greater skill and effort are
needed for lines with abrupt or undulating ground profile and for those where constraints on
structure location exist. For example, there may be high or low points in the profile or features
such as line angle points, crossings over highway, railroad, water, power and telecommunication
lines, and ground with poor soil conditions. Structure locations and heights are often controlled
or fixed by these special considerations. Alternative layouts between fixed locations may then
be required to determine the best arrangement based on factors of cost and effective design.
10.4.2 Design Factors for Structure Spotting: The following design factors are involved in
structure spotting and are covered in the identified chapters of this bulletin:
Bulletin 1724E-200
Page 10-8
a. Vertical Clearances (Chapter 4)
• Basic, level ground
• Crossings
• Side hill
• Underbuild
b. Horizontal Clearances
• For insulator side swing condition (Chapter 7)
• To edge of right-of-way, vertical obstructions and steep side hills (Chapter 5)
c. Uplift (Chapter 12)
d. Horizontal or Vertical Span Limitations Due to:
• Vertical sag - clearance requirement (Chapters 4, 6)
• Conductor separation (Chapter 6)
• Galloping (Chapter 6)
• Structure strength (Chapters 13, 14)
• Crossarm strength (Chapter 13)
e. Angle and Deadend (Chapter 14)
• Guying arrangements
• Guy anchors
10.4.3 Preparation: The following are necessary for structure spotting:
•
•
•
•
•
•
Plan-profile drawings of the transmission line,
Sag template of the same scale as the plan-profile prepared for the design temperatures,
loading condition, and ruling span of the specified conductor and overhead ground wire,
Table of minimum conductor clearances over ground features and other overhead lines
(Chapter 4),
Insulator swing charts (Chapter 7),
Horizontal and vertical span limitations due to clearance or strength requirements
(Chapters 8, 9, and 13), and
Guy arrangement and anchor requirements for angle and deadend structures (Chapter 14).
A height scale prepared for each structure type will aid in structure height determination.
Supporting calculations should be summarized in chart or tabular form to facilitate application
during structure spotting. This is especially advisable for the standard suspension structure
which has a greater range of pole height and class, as well as bracing variations for H-frame
structures. Selection of the proper pole may be affected by various criteria, such as spancontrolled-by-clearance or span-limited-by-pole-strength, for a given pole height and class or
bracing.
10.4.4 Process of Spotting: The process of spotting begins at a known or established conductor
attachment point such as a substation take-off structure. For level terrain, the profile is
essentially a straight line. When a sag template is held vertically and the ground clearance curve
is held tangent to the ground profile, the edge of the template will intersect the ground line at
points where structures of the basic height should be set. This relation is illustrated for a level
span in Figure 10-4. Curve 1 (lowest conductor sag position) represents the actual sag of the
conductor. Curve 2 (basic ground clearance curve) represents the actual position of the lowest
conductor plus the required total ground clearance, "C."
Bulletin 1724E-200
Page 10-9
GROUND LINE
D
B
E
C BA
G
32 1
4
5
F
Hot Curves (Maximum Sag)
Curve 1 - Lowest Conductor Sag Position
Curve 2 - Basic Ground Clearance Curve
Curve 3 - Edge of Template or Reference Line
Point 4 - Intersection Locates Pole of Basic
Height
Point 5 - Tangent to Ground Profile
A = Dimension from top of pole to point of
attachment of lowest conductor.B = Sag in level ground span.
C = Total ground clearance.
D = Setting depth of pole
E = Length of pole.
F = Level ground span.
G = Dimension from ground to point of
attachment of lowest conductor
FIGURE 10-4: APPLICATION OF SAG TEMPLATE - LEVEL GROUND SPAN
The point where Curve 3 intersects the ground line determines the location of the next structure.
This new location is found by drawing an arc along the edge of the template from Point 4 to the
next point where Curve 3 intersects the ground line. The template should then be shifted and
adjusted so that with the opposite edge of the template held on the conductor attachment point
previously located with the clearance curve again barely touching the profile. The process is
repeated to establish the location of each succeeding structure. After all structures are located,
the structures and lowest conductor should be drawn in.
The above procedure can be followed only on lines that are approximately straight and which
cross relatively flat terrain with the basic ground clearances. When line angles, broken terrain,
and crossings are encountered, it may be necessary to try several different arrangements of
structure locations and heights at increased clearances to determine the arrangement that is most
satisfactory. Special considerations often fix or limit the structure locations. It is advisable to
examine the profile for several span lengths ahead, take note of these conditions and adjust the
structure spotting accordingly. Sometimes, a more balanced arrangement of span lengths is
achieved by moving ahead to a fixed location and working back.
The relationship between the ground clearance and conductor curves is also used for spans other
than level-ground spans. This is done by shifting the sag template until ground profile touches
or is below the clearance curve with the previously established conductor attachment point is
positioned on the conductor curve. The conductor curve would then indicate the required
conductor height for any selected span. Structure height may be determined by scaling or by use
of the proper structure height template, taking into account the change in the embedded pole
length for poles other than the basic pole. Design limitations due to clearance or structure
strength should be observed.
Bulletin 1724E-200
Page 10-10
10.4.5 Crossings: For spans-crossing features such as highway and power lines, with different
clearance requirements than the normal clearance, the ground clearance curve should be adjusted
accordingly. In California, adequate ground clearance has to be maintained over all railroads,
major highways, major telecommunication and power lines when a broken conductor condition
in either of the spans adjacent to the crossing span. Other states are governed by the NESC,
which does not require the broken conductor condition. The increase in sag due to a broken
conductor in an adjacent span is usually significant only where suspension-type structures are
used at crossings and for voltage at 230 kV or above. For tension structures, and for suspension
structures at lower voltages, the sag increase normally will not seriously affect the clearance.
10.4.6 Insulator Side Swing - Vertical Span: Horizontal conductor clearances to supporting
structures are reduced by insulator side swing under transverse wind pressure. This condition
occurs where the conductor is supported by suspension-type insulators. Conductors supported
by pin-type, post, or tension insulators are not affected and horizontal clearance of the deflected
conductor position within the span becomes the controlling factor (see Chapter 5 of this
bulletin). Suspension insulators also deflect laterally at line angle locations due to the transverse
component of conductor tension.
Chapter 7 covers the preparation of insulator swing charts. At each structure location the charts
are used to determine if insulator swing is within the allowed limit for the vertical and horizontal
spans and line angle conditions. For suspension insulators supported on horizontal crossarms, a
minimum vertical span has to be maintained to avoid excessive side swing. To maintain
adequate clearance for insulators attached directly to the pole, and for some types of angle
structures, the vertical span cannot exceed a maximum value (as indicated by the insulator swing
chart). See Figure 7-5 of this bulletin for an example swing angle chart for the TH-233 large
angle structure.
The vertical span is the distance between the conductor low points in spans adjacent to the
structure. The horizontal span is the average value of the two adjacent spans to a structure.
Where conductor attachments are at different elevations on adjacent structures, the low point is
not at mid-span and will shift its position as the temperature changes. This shift can be readily
seen by comparing the low point for the hot curve with its position for the cold curve. The
vertical span value used to check the insulator swing should be based on the low point position
which yields the most critical condition for the structure type. (See Chapter 7 for details on
insulator swing)
Where minimum vertical span or uplift is the concern, the cold curve should be used. The
normal temperature is more critical and should be used if the vertical span is limited by a
maximum value. Figure 10-6 shows some examples of the relationship of conductor low points
and vertical spans which may occur in a line profile.
If insulator swing is unacceptable, one of the following corrective steps, in order of preference, is
recommended:
a.
b.
c.
d.
Relocate structures to adjust horizontal-vertical span ratio;
Increase structure height or lower adjacent structures;
Use a different structure, one with greater allowable swing angle or a deadend structure; or
Add weight at insulators to provide the needed vertical force.
10.4.7 Uplift: Uplift is defined as negative vertical span and is determined by the same
procedure as vertical span. On steeply inclined spans when the cold sag curve shows the low
point to be above the lower support structure, the conductors in the uphill span exert upward
forces on the lower structure. The amount of this force at each attachment point is related to the
Bulletin 1724E-200
Page 10-11
weight of the loaded conductor from the lower support to the low point of sag. Uplift exists at a
structure (see Structure No. 4 in Figure 10-6) when the total vertical span from the ahead and
back spans is negative. Uplift has to be avoided for suspension, pin-type, and post insulator
construction. For structures with suspension insulators, the check for allowable insulator swing
is usually the controlling criteria on vertical span. A rapid method to check for uplift is shown
by Figure 10-5. There is no danger of uplift if the cold curve passes below the point of
conductor support on a given structure with the curve on the point of conductor support at the
two adjacent structures.
Designing for uplift, or minimizing its effects, is similar to the corrective measures listed for
excessive insulator swing, except that adding of excessive weights should be avoided. Double
deadends and certain angle structures can have uplift as long as the total force of uplift does not
approach the structure weight. If it does, hold-down guys are necessary.
Care should be exercised to avoid locating structures that result in poor line grading (see
Paragraph 10.1.4a of this chapter).
Cold Curve
Cold Curve
Uplift Exists at
Center
Structure
No Uplift at
Center Structure,
Check for Allowable
Insulator Swing
FIGURE 10-5: CHECK FOR UPLIFT
10.4.8 Other Considerations: If maximum conductor tension or other limits are not exceeded,
it may be preferable to use one long span with adequate conductor separation over a depression
in the profile rather than use two short spans with a deadend structure at the bottom of the
depression. A structure at the bottom of the depression may be subjected to considerable uplift
at minimum conductor temperature. Also, poorer soil foundation conditions usually exist in the
depression.
Care has to be exercised at locations where the profile falls sharply away from the structure to
see that the maximum allowable vertical span as limited by the strength of the crossarm or
insulator is not exceeded. Structure No. 2 in Figure 10-6 illustrates this condition. For
maximum accuracy in the heavy or medium loading zone, the vertical span for this purpose
should be determined with a curve made for the sag under ice load, no wind, at 32°F. For most
conductors, however, the maximum temperature final sag curve will closely approximate the
1
Structure No. 1
Vertical Span
FIGURE 10-6: SAG LOW POINT, VERTICAL SPANS AND UPLIFT
3
4
5
Structure No. 5 Vertical Span
Structure No. 4
Uplift
Structure No. 3
Vertical Span
Figure 10-6 Sag Low Point, Vertical Spans and Uplift
2
Structure No. 2 Vertical Span
6
7
Bulletin 1724E-200
Page 10-12
Bulletin 1724E-200
Page 10-13
curve for the ice-loaded conductor, and it may be used when checking for maximum vertical
span. For guyed structures, the maximum vertical loads added to the vertical components from
guy loads should be checked against the buckling strength of the pole
The profile in rough country where side hills are encountered should be prepared so that the
actual clearances under the uphill and downhill conductor may be checked. For some long spans
it may be necessary to check side hill clearance with the conductors in their maximum transverse
swing position. H-frame type structures installed on side hills may require different pole heights
to keep the crossarm level or one pole may be set a greater than normal setting depth.
Structures with adequate longitudinal strength (guyed deadends usually) are required at locations
where longitudinal loading results from unequal line tensions in adjacent spans. For lines
subject to heavy ice and high wind conditions and with long, uninterrupted section of standard
suspension structures, consideration should be given to include some structures with in-line guys
or other means to contain and prevent progressive, cascading-type failure. This is especially
important for H-frame type structures with lower strength in the longitudinal direction when
compared with its transverse strength. Measures to prevent cascading failures are also important
for lines without overhead ground wire which tends to restrain the structure from collapsing
longitudinally. A maximum interval of 5 to 10 miles is suggested between structures with
adequate longitudinal capacity (guyed deadends usually), depending on the importance of the
line and the degree of reliability sought.
10.5 Other Design Data: Conductor and ground wire sizes, design tensions, ruling span, and
the design loading condition should be shown on the first sheet of the plan-profile drawings. For
completeness, it is preferable that these design data be shown on all sheets. A copy of the sag
template reproduced on the first sheet could serve as a record of design in case the template is
misplaced or lost. Design data for underbuild and portions of the line where a change in design
parameters occurs should similarly be indicated. The actual ruling spans between deadends
should be calculated and noted on the sheets. This serves as a check that the actual ruling span
has not deviated greatly from the design ruling span. The significance of this deviation is also
covered in the ruling span section of Chapter 9. Where spans are spotted at lengths less than
one-half or over twice the ruling span, deadending may be required.
As conductor sags and structures are spotted on each profile sheet, the structure locations are
marked on the plan view and examined to insure that the locations are satisfactory and do not
conflict with existing features or obstructions. To facilitate preparation of a structure list and the
tabulation of the number of construction units, the following items, where required, should be
indicated at each structure station in the profile view:
•
•
•
•
•
•
Structure type designation,
Pole height and class,
Pole top, crossarm, and brace assemblies,
Pole grounding units,
Miscellaneous hardware units (vibration dampers at span locations), and
Guying assemblies and anchors.
The required number of units or items required should be shown in parenthesis if greater than
one. Successive plan-profile sheets should overlap. For continuity, and to avoid duplicate count,
the end structure on a sheet should be shown as a broken line on the following sheet. The
number and type of guying assemblies and guy anchors required at angle or deadend locations,
based on guying calculations or application charts, should also be indicated. Design check, line
construction, and inspection are facilitated if an enlarged guying arrangement, showing
attachments and leads in plan and elevation, is added on the plan-profile sheet adjacent to each
Bulletin 1724E-200
Page 10-14
guyed structure. Any special notes or large-scale diagrams necessary to guide the construction
should be inserted on the plan-profile sheet. This is important at locations where changes in line
design or construction occur, such as a slack span adjacent to a substation, line transposition, or
change in transmission and underbuild circuits.
10.6 Drawing Check and Review: The completed plan-profile drawings should be checked to
ensure that:
•
•
•
The line meets the design requirements and criteria originally specified,
Adequate clearances and computed limitations have been maintained, and
Required strength capacities have been satisfied.
The sheets should be checked for accuracy, completeness, and clarity. Figure 10-7 is a Sample
Check List for review of plan and profile sheets.
Bulletin 1724E-200
Page 10-15
Profile: ____________________________
Date: _______________________________
Line: ______________________________
Voltage: ______________
Plan and Profile Drawing Nos.___________
Loadings
NESC District __________________
50 yr extreme wind(psf) ___________
Extreme ice load (radial inches)_____
Checked by: __________________________
Ruling Span: _________________________
Conductor: _________________________
Design Tension: ______________________
OHGW: ___________________________
Design Tension: ______________________
Underbuild: ________________________
Sheet Number
PLAN
Design Tension: ______________________
Property Information
Swamps, Rivers, Lakes, etc.
R/W Data, Boundaries
Location of Buildings, Schools, etc.
Other Utilities
Obstructions, Hazards
Roads
Angles, P.I., Bearing of Centerline
PROFILE
Horizontal Span Length
Vertical Span Length
Type Structure
Pole Strength
Pole Height
Pole Foundation Stability
Crossarm Strength
Conductor Clearance:
To Ground or Side Hill
To Support and Guys
To Buildings
Crossing
Conductor Separation
Conductor Tension Limitations
Climbing or Working Space
Guy Tension
Guy Lead and Height
Anchors
Insulator Swing or Uplift
Tap Off, Switches, Substations
Underbuild
Code Requirements
FIGURE 10-7: SAMPLE CHECK LIST FOR REVIEW OF PLAN AND PROFILE
Bulletin 1724E-200
Page 10-16
Blank Page
Bulletin 1724E-200
Page 11-1
11. LOADINGS AND LOAD FACTORS
11.1 General: The strength to be designed into a transmission line depends to a large extent on
wind and ice loads that may be imposed on the conductor, overhead ground wire and supporting
structure. These loadings are related generally to the geographical location of the line.
When selecting appropriate design loads, the engineer should evaluate climatic conditions,
previous line operation experience and the importance of the line to the system. Conservative
load assumptions should be made for a transmission line which is the only tie to important load
centers.
The 2007 NESC indicates that structure and component strength should take into account
temporary loads. Temporary loads imposed on a structure or component may include lifting of
equipment, stringing operations, or a worker on a structure or component. This design manual
does not address temporary loads.
The alternate method in the 2007 NESC has not been included in this design manual. The
alternate method will not be used after July 31, 2010.
11.2 Loads
11.2.1 NESC Loading Districts: The NESC divides the country into three weather or loading
districts, as shown in Figure 11-1.
FIGURE 11-1: NESC LOADING DISTRICTS
Reproduced from IEEE/ANSI C2, 2007, “National Electrical Safety Code,”Copyright 2001 by the
Institute of Electrical and Electronic Engineers, Inc., with permission of the IEEE.
Bulletin 1724E-200
Page 11-2
The minimum design conditions associated with each loading district are given in Table 11-1.
Constants in this table are to be added to the vector resultant for tension calculations only.
TABLE 11-1
ICE, WIND, TEMPERATURE, AND CONSTANTS
Design
Temp.
(Fº)
Radial Ice
Thickness
(inches)
Wind
Loading
Constants
(lbs/ft)
0°
15°
30°
0.50
0.25
0
0.30
0.20
0.05
Extreme Wind
60°
0
Extreme Ice with Concurrent Wind
15°
See Figure
11-3
4 psf
4 psf
9 psf
See
Figure 11-2
See Figure
11-3
NESC Loading
Loading District
Heavy
Medium
Light
NA
NA
Designing to these minimum requirements may not be sufficient. Extreme winds and special ice
conditions should be investigated. Determination of an appropriate design load to account for
extreme winds is easier than determining a heavy ice design load. Meteorological data may be
available on high winds, but little data is available on extreme ice loads. Heavy ice combined
with a relatively high wind should also be considered.
11.2.2 Extreme Ice: In certain areas of the country heavy ice may be predominant. The
engineer should review the experience of utilities or cooperatives in the area of the line
concerning ice conditions. The number and frequency of outages in the area due to ice storms,
and the design assumptions used for existing lines in the area should be examined. From this
data, the engineer can reasonably decide if a heavy ice condition greater than what is required by
the NESC needs to be included in the design.
If historical data on icing conditions is lacking, the engineer should consider designing the line
for extreme wind conditions without ice, and for loading zone conditions. The engineer would
then calculate the maximum ice load the structure could sustain without wind and evaluate this
specific ice condition.
11.2.3 Extreme Winds: Although the NESC requires that structures over 60 ft. sustain high
winds, Rural Utilities Programs recommends that all transmission lines meet extreme wind
requirements. Required values for temperature and wind are listed in Table 11-1 and Figure 112. The NESC allows linear interpolation when considering locations between isotachs. Local
meteorological data should also be evaluated in determining a design high wind speed. For wind
speeds other than a 50 year recurrence interval, refer to Appendix E.
Equations in Tables 250-2 and 250-3 of the NESC have been incorporated in computer programs
as part of the structure analysis. These equations are included in the definitions for the variables
in Equations 11-1 and 11-2 of this bulletin. Tables 11-2, 11-3, 11-4 and 11-5 provide calculated
values for the parameters in these equations.
Bulletin 1724E-200
Page 11-3
Equation 11-1 should be used to calculate the load in the unit wind load on a circular wire in
pounds per linear foot.
p = 0.00256 * V2 * kz * GRF * d / 12
Eq. 11-1
p = unit load per unit foot, lbs./ft.
V = Basic Wind Speed, 3 –second gust wind speed in miles
per hour at 33 ft. above ground with an annual
probability of .02 (50 year return period), Figure 11-2
kZ = Velocity Pressure Exposure Coefficient, shown in
Table 11-2 or by the equation:
kz = 2.01(h/900)(2/9.5) where h = height of the wire at
the structure and is between 33 feet and 900 feet
GRF = Gust Response Factor, shown in Table 11-3 or by the
equation: GRF = [1+(2.7Ew Bw0.5)]/kv2 where
Ew = 0.346 (33/h)1/7 and
Bw = 1/(1+0.8L/220)
kv = 1.43
h = height of the wire at the structure
L = design wind span (also known as HS)
d = diameter of the conductor in inches
TABLE 11-2
WIRE VELOCITY PRESSURE EXPOSURE COEFFICIENT (kZ)
Height of
Wire( ft)
≤ 33
34 – 50
51 – 80
81 – 115
116 – 165
kZ
1.00
1.10
1.20
1.30
1.40
TABLE 11-3
WIRE GUST RESPONSE FACTOR, GRF
Height of Wire At
the Structure
h (ft.)
≤33
34 – 50
51 – 80
81 – 115
116 – 165
Wire, GRF, for Various Span Lengths in feet
251 - 500
501 - 750
751 - 1000
1001 -1500
0.86
0.82
0.80
0.78
0.77
0.79
0.76
0.75
0.73
0.72
0.75
0.72
0.71
0.70
0.69
0.73
0.70
0.69
0.68
0.67
Bulletin 1724E-200
Page 11-4
TABLE 11-4
COMBINED FACTOR kZ*GRF
FOR COMMON WIRE HEIGHTS
Height of Wire At
the Structure
h (ft.)
34 - 50
51 - 80
81 - 115
Wire, GRF, for Various Span Lengths in feet)
251 – 500
501 - 750
751 - 1000
1001 -1500
0.90
0.96
1.01
0.84
0.90
0.95
0.79
0.85
0.91
0.77
0.83
0.88
For simplicity, the designer may wish to use the height of wire to be the height to the overhead
groundwire at the structure.
To calculate the wind load on a structure in pounds, equation 11-2 should be used.
P = .00256 * V2 * kz * GRF * Cf * A
Eq. 11-2
P = wind load in pounds
V = As defined for Equation 11-1
kZ = Velocity Pressure Exposure Coefficient, shown in
Table 11-5 or by the equation:
kz = 2.01(0.67h/900)(2/9.5) where h = height of the
structure above groundline
GRF = Gust Response Factor, shown in Table 11-5 or by the
equation : GRF = [1+(2.7Es Bs0.5)]/kv2 where
Es = 0.346 (33/(0.67-h)1/7 and
Bs = 1/(1+0.8L/220)
kv = 1.43
h = height of the structure above groundline
L = design wind span (also known as HS)
Cf = drag coefficient
A = projected wind area in square feet
TABLE 11-5
STRUCTURE kZ, GRF , and COMBINED kZ GRF Factor
Height of
Structure, ft
kZ
GRF
Combined
’kZ GRF’
factor
≤ 33
0.92
1.02
0.94
34 – 50
1.00
0.97
0.97
51 – 80
1.10
0.93
1.02
81 – 115
1.20
0.89
1.07
116 – 165
1.30
0.86
1.12
Bulletin 1724E-200
Page 11-5
FIGURE 11-2a: EXTREME WIND SPEED IN MILES PER HOUR AT 33 FT. ABOVE
GROUND (50-year mean recurrence interval)
Reproduced with permission from ASCE 7-05, “Minimum Design Loads for Buildings and Other Structures,”
American Society of Civil Engineers, copyright 2005. For further information, refer to the complete text of the
manual (http://www.pubs.asce.org/ASCE7html?999913330).
Bulletin 1724E-200
Page 11-6
Special Wind
Location
Region
Hawaii
Puerto Rico
Guam
Virgin Islands
American Samoa
V mph
105
145
170
145
125
Notes:
1. Values are nominal design 3-second gust wind speeds in miles per hour at 33 ft.
above gound for Exposure C category.
2. Linear interpolation between wind contours is permitted.
3. Islands and coastal area outside the last contour shall use the last wind speed
contour of the coastal area.
4. Mountainous terrain, gorges, ocean promontories, and special wind regions shall be
examined for unusual wind conditions.
FIGURE 11-2b: EXTREME WIND SPEED IN MILES PER HOUR
AT 33 FT. ABOVE GROUND
(50-year mean recurrence interval)
Reproduced with permission from ASCE 7-05, “Minimum Design Loads for Buildings and Other Structures,”
American Society of Civil Engineers, copyright 2005. For further information, refer to the complete text of the
manual (http://www.pubs.asce.org/ASCE7html?999913330).
Bulletin 1724E-200
Page 11-7
Figure 11-2c
Notes:
1. Values are nominal design 3-second gust wind
speeds in mph at 33 ft above ground for
Exposure C category.
2. Linear interpolation between wind contours is
permitted.
3. Islands and coastal area outside the last contour
shall use the last wind speed contour of the
coastal area.
4. Mountainous terrain, gorges, ocean
promontories, and special wind regions shall be
examined for unusual wind conditions.
Figure 11-2d
FIGURES 11-2c,11-2d: EXTREME WIND SPEED IN MILES PER HOUR AT 33 FT.ABOVE
GROUND FOR THE NORTHEAST AND SOUTHEAST
(50-year mean recurrence interval)
Reproduced with permission from ASCE 7-05, “Minimum Design Loads for Buildings and Other Structures,”
American Society of Civil Engineers, copyright 2005. For further information, refer to the complete text of the
manual (http://www.pubs.asce.org/ASCE7html?999913330).
Bulletin 1724E-200
Page 11-8
Notes:
1. Values are nominal design 3-second gust wind
speeds in mph at 33 ft above ground for
Exposure C category.
2. Linear interpolation between wind contours is
permitted.
3. Islands and coastal area outside the last contour
shall use the last wind speed contour of the
coastal area.
4. Mountainous terrain, gorges, ocean
promontories, and special wind regions shall be
examined for unusual wind conditions.
FIGURES 11-2e: EXTREME WIND SPEED IN MILES PER HOUR AT 33 FT ABOVE
GROUND FOR TEXAS, LOUISIANA AND MISSISSIPPI
(50-year mean recurrence interval)
Reproduced with permission from ASCE 7-05, “Minimum Design Loads for Buildings and Other Structures,”
American Society of Civil Engineers, copyright 2005. For further information, refer to the complete text of the
manual (http://www.pubs.asce.org/ASCE7html?999913330).
11.2.4 Extreme Ice with Concurrent Wind Loads: The NESC requires that structures over 60
ft. be designed to withstand the ice and wind loads associated with the Uniform Ice Thickness
and Concurrent Wind Speed specified in NESC Figure 250-3 and in Figures 11-3a to 11-3d of
this bulletin; however, it is recommended that all transmission lines meet these requirements.
Required values for temperature, ice and wind are listed in Table 11-1.
Bulletin 1724E-200
Page 11-9
Fig 11-3e
Fig 11-3f
FIGURE 11-3a: UNIFORM ICE THICKNESS DUE TO FREEZING RAIN WITH
CONCURRENT 3-SECOND GUST WIND SPEEDS (50 yr. mean recurrence)
Reproduced with permission from ASCE 7-05, “Minimum Design Loads for Buildings and Other Structures,”
American Society of Civil Engineers, copyright 2005. For further information, refer to the complete text of the
manual (http://www.pubs.asce.org/ASCE7html?999913330).
Bulletin 1724E-200
Page 11-10
Figure 11-3d
FIGURE 11-3b: UNIFORM ICE THICKNESS DUE TO FREEZING RAIN WITH
CONCURRENT 3-SECOND GUST WIND SPEEDS (50 yr. mean recurrence)
Reproduced with permission from ASCE 7-05, “Minimum Design Loads for Buildings and Other Structures,”
American Society of Civil Engineers, copyright 2005. For further information, refer to the complete text of the
manual (http://www.pubs.asce.org/ASCE7html?999913330).
Bulletin 1724E-200
Page 11-11
FIGURE 11-3c: UNIFORM ICE THICKNESS DUE TO FREEZING RAIN WITH
CONCURRENT 3-SECOND GUST WIND SPEEDS FOR ALASKA
(50 year mean recurrence interval)
Reproduced with permission from ASCE 7-05, “Minimum Design Loads for Buildings and Other Structures,”
American Society of Civil Engineers, copyright 2005. For further information, refer to the complete text of the
manual (http://www.pubs.asce.org/ASCE7html?999913330).
Bulletin 1724E-200
Page 11-12
FIGURE 11-3d: UNIFORM ICE THICKNESS DUE TO FREEZING RAIN WITH
CONCURRENT 3-SECOND GUST WIND SPEEDS FOR LAKE SUPERIOR
(50 yr. mean recurrence)
FIGURE 11-3e: UNIFORM ICE THICKNESS DUE TO FREEZING RAIN WITH
CONCURRENT 3-SECOND GUST WIND SPEEDS FOR FRASER VALLEY DETAIL
(50 yr. mean recurrence)
Reproduced with permission from ASCE 7-05, “Minimum Design Loads for Buildings and Other Structures,”
American Society of Civil Engineers, copyright 2005. For further information, refer to the complete text of the
manual (http://www.pubs.asce.org/ASCE7html?999913330).
Bulletin 1724E-200
Page 11-13
FIGURE 11-3f: UNIFORM ICE THICKNESS DUE TO FREEZING RAIN WITH
CONCURRENT 3-SECOND GUST WIND SPEEDS FOR COLUMBIA RIVER GOUGE
(50 yr. mean recurrence)
Reproduced with permission from ASCE 7-05, “Minimum Design Loads for Buildings and Other Structures,”
American Society of Civil Engineers, copyright 2005. For further information, refer to the complete text of the
manual (http://www.pubs.asce.org/ASCE7html?999913330).
11.2.5 Longitudinal Loads: Unbalanced longitudinal loads on a line may occur because of:
•
•
Unequal wind load and/or differential ice
conditions on equal or unequal spans
Construction and maintenance activities
•
•
•
A broken wire
Stringing loads
A change in ruling span
Traditionally, standard tangent wood pole structures have not been designed for broken
conductor longitudinal loads and have relied on the restraining capacity of deadends. The 2002
edition of the NESC recommends that structures having a longitudinal strength capability be
provided at reasonable intervals along the line.
Several methods to reduce the risk of cascading transmission line structures due to broken wires
have been recommended in the American Society of Civil Engineers (ASCE) Manual and
Report on Engineering Practice No. 74 “Guidelines for Electrical Transmission Line Structural
Loading,” copyright 1991. They are summarized below.
Method 1, Install “Stop” Structures at Specified Intervals: This method consists of placing
deadend structures, longitudinal guys, or regular tangent structures designed to resist deadend
loads at intervals along the line to limit the number of cascading structures to a manageable
number. This method is most practical for H-frames or narrow-based lattice towers which do
not possess enough inherent longitudinal capacity to resist longitudinal loads. In these cases,
stop structures are used because the cost to strengthen each structure to resist cascading may be
high and the addition of guys at each structure may not be desirable.
Bulletin 1724E-200
Page 11-14
Method 2, Install Release Mechanisms: Slip or release-type suspension clamps may be used as
“fuses” to limit the longitudinal loads applied by broken wires. This is actually very similar to
Method 1. The major difference between Method 1 and this Method is that “fuses” are used to
minimize the unbalanced loads used to design each structure. The structures also have to be
capable of withstanding construction and maintenance loads without endangering line crew
personnel. Where heavy ice buildups are frequent, this could be an insurmountable problem.
As such, this method is not recommended in areas of heavy ice, since unbalanced ice loads
could result in unexpected failures.
Method 3, Design All Structures for Broken Wire Loads: Rigid lattice towers, guyed tangents
(guyed in four directions) and single-shaft pole structures have an inherent longitudinal capacity.
In many instances, such structures can be economically designed to resist longitudinal loads.
The loads are typically based on the “residual static load” (RSL). The RSL is a load at a wire
support after breaking one phase or a ground wire under every day conditions (no ice, no wind,
60ºF). Considerations in determining the RSL include insulator swing, structure deflection and
suspension clamp slippage. Some designers have used 60 percent to 70 percent of the every day
tension for conductors and 100 percent of the every day tension for ground wires. The suggested
longitudinal loading consists of applying RSLs in one direction to a nominal one-third of
conductor support points or to one (or both) ground wire support point(s). The suggested
vertical loading consists of one-half or more of the vertical load(s) imposed by the broken
wire(s) along with all of the vertical loads imposed by the other intact wires. Although every
structure is designed to resist cascading, in the event of the catastrophic loss of a single structure,
localized failures in adjacent structures should be expected.
A blend of Methods 2 and 3 would involve designing the main body of the structure (or pole) for
slightly larger longitudinal loads than those used for the design of the support arms and/or
ground wire peak. The idea is to limit the loads applied to the body of the structure (or pole) by
“sacrificing” the arms or ground wire peak, thereby reducing the number of poles damaged from
a broken wire event and decrease the likelihood of an unmanageable cascade. If such a event
occurred, it could result in damage to several (perhaps numerous) support arms and/or ground
wire peaks.
11.2.6 Example of Extreme Wind Calculations: A proposed 161 kV line using the TH-10
structure is expected to have spans ranging from 501 to 900 feet and to be composed of
structures with wood poles 60 to 90 feet high. The line is expected to be located in northern
Mississippi and will have a 795 26/7 ACSR conductor. Calculate the extreme wind load to be
used in the design.
Extreme wind calculations are made for wind on the wires and wind on the structure. For wind
on the wires, the engineer should calculate the wind on the overhead groundwires and the wind
on the conductors. For wind on the overhead groundwires, a review of Table 11-4 indicates that
0.9 to 0.85 is to be used for the combined factor of kZ*GRF’ for spans 501 to 1000 feet and for
wire heights 52 feet to 79 feet above ground (for structures using 60 to 90 foot poles). The
conductors on the TH-10 are located approximately 13 feet from the top of the pole. The height
from the ground to the conductors at the structure will range from 39 to 63 feet above ground. .
For wind on the conductors, review of Table 11-4 indicates that values of 0.9 to 0.79 may be
used as the combined factor of ‘kZ*GRF’ for spans 501 to 900 and for wire heights 39 to 63.
(Poles are 52 feet to 79 feet above ground).
For wind on the structures, use Table 11-5. For structures of heights 52 to 79 feet above ground,
Table 11-5 indicates that the combined ‘kZ*GRF’ factor for the structure is 1.02.
Wind pressure (psf) on the overhead groundwires:
Bulletin 1724E-200
Page 11-15
p = 0.00256 * V2 * kz * GRF
p = 0.00256 * 902 * 0.9
p = 18.66 psf; use 19 psf in design
Wind pressure (psf) on the conductors:
p = 0.00256 * V2 * kz * GRF
p = 0.00256 * 902 * 0.9
p = 18.66 psf; use 19 psf in design
Wind pressure (psf) on the structure:
p = 0.00256 * V2 * kz * GRF
p = 0.00256 * 902 * 1.02
p = 21.15 psf; use 22 psf in design
For 21 psf, the unit trnasverse load on the conductor pt = 1.9390 lbs/ft (Appendix B)
Therefore, for 19 psf, the unit load will be 1.7543 lbs/ft (or 1.9390x19/21)
11.2.7 Example of Extreme Ice/Wind Calculations:
Using the same example line in the previous paragraph (11.2.6), the line located in northern
Mississppi has a combined ice and wind load of .75inch of ice and a 30 psf wind. Calculate the
transverse and vertical unit loads on the conductor.
For the transverse unit load:
The diameter of the conductor including ice = 1.108 in (Appendix B) + (.75x2) = 2.608 in..
The unit wind load on the conductor pt = 30 lbs/ft2 x 2.608 inches/12in/ft x 1ft = 6.520 lbs/ft
For the vertical unit load:
The vertical unit load, wc, is the dead weight of the conductor plus the ice load per foot of
conductor = 1.0940 lbs/ft + [3.1416((1.108+(2x.75))2 – (1.108) 2)/4/144 x 1 ft] x 57 lbs/ft3 =
2.8269 lbs/ft
11.3 Load Factors for New Construction: Agency transmission lines are to be built to
Grade B construction. In Table 11-6, the columns under the Rural Utilities Service headings
give the recommended minimum load factors to be applied to the light, medium, and heavy
loading districts of the NESC and also the recommended strength factors to be applied in the
design of guys, anchors, crossarms, and structures.
Recommended load factors and strength factors to be applied to extreme wind loadings are in
Table 11-7. The factors are intended to take into account approximations made in the design and
analysis.
Bulletin 1724E-200
Page 11-16
11.4 Application of Load Factors and Strength Factors: In the application of the load factors
and strength factors, the objective is to design a structure with resistance greater than the
maximum load expected during the lifetime of the structure and to design the structure with an
acceptable level of safety and reliability. The use of load factors and strength factors can be
expressed as follow:
ØR > (LF)Q
Eq. 11-3
where:
R
=
Ø
Q
LF
=
=
=
measure of material strength or
resistance
a strength factor, less than 1.0
load
load factor, greater than 1.0
‘Ø’ is a multiplier which limits the resistance, R, and accounts for the variability of the resistance
property. ‘(LF)’ is a multiplier that compensates for uncertainty in the load or assumptions made
in the analysis. ‘Ø’ and ‘(LF)’ may be based on statistics, past engineering judgment, past
practice, or may be legislated.
The traditional view of a safety factor (or load factor) may be expressed as ‘LF’ divided by ‘Ø’.
Tables 11-6 and 11-7 are based on the relationship defined in Equation 11-3. In previous
editions of this bulletin, the method using the load factors was used. That method has been
dropped from this bulletin.
11.4.1 Example Calculation Showing the Use of Strength and Load Factors:
A Douglas fir, 80 ft. tangent pole is to sustain a 750 lbs. transverse load two feet from the top.
Assume this load is based on NESC heavy loading district loads. What class pole should be used
for this construction? The pole is embedded 10 feet. The length of the moment arm used to
calculate the induced moment at groundline is 68 feet.
In this case, R is the moment capacity of the pole at groundline and ‘Q’ is the horizontal load
(750 lbs.). Using the strength factors (Ø) and load factors (LF) from Table 11-6, Equation 11-3
becomes:
ØR > (LF)Q
0.65MMoment capacity at the groundline > 2.50(750 lbs)(68 feet)
MMoment capacity at the groundline > 196,154 ft.-lbs
The pole should have a moment capacity of 196 ft-kips at the groundline. A class 3 Douglas fir
pole would provide this moment capacity at the groundline.
11.4.2 Additional Examples Showing the Application of Loads and the Use of Strength and
Load Factors: Chapters 13 and 14 demonstrate the application of strength and load factors in
the structural analyses examples.
Bulletin 1724E-200
Page 11-17
TABLE 11-6
RECOMMENDED LOAD FACTORS AND STRENGTH FACTORS
TO BE APPLIED TO NESC DISTRICT LOADS
(Grade B New Construction)
(NESC Tables 253-1 and 261-1A) (Note 5)
FACTORS
NESC
RUS
1.50
1.50
2.50
1.65
2.50
1.65
1.10
1.65
1.33
1.65
1.00
1.65
1.33
1.65
1.00
0.65
0.65
0.90
1.00
1.00
1.00
0.65
0.50
0.65 (Note 1)
0.65
0.65 (Note 2)
1.00
1.00
LOAD FACTORS
Vertical Loads
Transverse Loads
Wind
Wire Tension
Longitudinal Loads
At crossings
General
Deadends
Elsewhere
General
Deadends
STRENGTH FACTORS (Note 3)
Steel and Prestressed Concrete Structures
Wood Poles (Note 4)
Wood Crossarms (Note 4)
Guy Wire Assemblies
Guy Anchors and Foundations
Guy Attachment Assemblies (includes guy
hardware)
Conductor Support Hardware (Note 6)
Notes:
1. A value different than 0.65 may be used, but should not exceed 0.9.
2. This strength factor of 0.65 may be increased for steel and prestressed concrete poles.
3. It is recognized that structures will experience some level of deterioration after installation.
These strength factors are for new construction.
4. For wood structures, when the deterioration reduces the structure strength to 2/3 of that
required when installed, the wood structure should be replaced or rehabilitated. If the
structure or structure component is replaced, the structure or structure component needs to
meet the strength for the original grade of construction. The rehabilitated portions of the
structures have to be greater that 2/3 of that required when installed for the life of the line.
5. When calculating the additional moment due to deflection, deflections should be calculated
using loads prior to application of the load factor.
6. Conductor Support Hardware is any hardware not a part of the structure, guy assembly, or
guy attachment. Conductor support hardware may be splices, extension links, insulator
string yokes, y-clevis balls, ball hooks, deadend clamps, etc.
Bulletin 1724E-200
Page 11-18
TABLE 11-7
RECOMMENDED LOAD FACTORS AND STRENGTH FACTORS
TO BE APPLIED TO EXTREME WIND LOADS (Rule 250C of the NESC)
AND TO EXTREME WIND/ICE LOADS (Rule 250D of the NESC)
(Grade B New Construction)
(NESC Tables 253-1 and 261-1A) (Note 5)
FACTORS
NESC
RUS
1.00
1.10
1.00
1.00
1.10
1.00
1.00
1.00
1.00
1.10
1.00
1.00
1.00
1.10
1.00
0.75
0.75
0.90
1.00
Not Specified
1.00
0.75
0.65
0.65 (Note 1)
0.65
0.65 (Note 2)
0.80
0.80
LOAD FACTORS
Vertical Loads
Transverse Loads
Wind
Wire Tension
Longitudinal Loads
At crossings
General
Deadends
Elsewhere
General
Deadends
STRENGTH FACTORS (Note 3)
Steel and Prestressed Concrete Structures
Wood Poles (Note 4)
Wood Crossarms (Note 4)
Guy Wire Assemblies
Guy Anchors and Foundations
Guy Attachment Assemblies (includes guy
hardware, bracket and guy attachment
assemblies)
Conductor Support Hardware (Note 6)
Notes:
1. A value different than 0.65 may be used, but should not exceed 0.90.
2. This strength factor of 0.65 may be increased for steel and prestressed concrete poles.
3. It is recognized that structures will experience some level of deterioration after installation.
These strength factors are for new construction.
4. For wood structures, when the deterioration reduces the structure strength to 2/3 of that
required when installed, the wood structure should be replaced or rehabilitated. If the
structure or structure component is replaced, the structure or structure component needs to
meet the strength for the original grade of construction. The rehabilitated portions of the
structures have to be greater that 2/3 of that required when installed for the life of the line.
5. When calculating the additional moment due to deflection, deflections should be calculated
using loads prior to application of the load factor.
6. Conductor Support Hardware is any hardware not a part of the structure, guy assembly, or
guy attachment. Conductor support hardware may be splices, extension links, insulator
string yokes, y-clevis balls, ball hooks, deadend clamps, etc.
Bulletin 1724E-200
Page 12-1
12. FOUNDATION STABILITY OF DIRECT-EMBEDDED POLES
12.1 General: Every structure standing above ground is subjected to lateral forces. In the case
of direct-embedded wood, steel or prestressed concrete transmission structures, it is desirable to
depend on the earth to resist lateral forces. The embedded portion of a pole provides this
resistance by distributing the lateral load over a sufficient area of soil. A properly selected
embedment depth should prevent poles from kicking out. With time, single poles may not
remain plumb. Leaning of single pole structures is sometimes permitted, provided excessive
angular displacements are avoided, pole strength is adequate considering additional loads from
the pole being out of plum and adequate clearances are maintained.
The lateral forces to which wood transmission structures are subjected are primarily forces due
to wind and wire tension loads due to line angles. Longitudinal loads due to deadending or
uniform ice on unequal spans should be examined to see how they affect embedment depths.
Normally, flexible transmission structures are stabilized longitudinally by the overhead ground
wire and phase conductors.
Bearing and lateral earth capacity of soils depend on soil types and soil characteristics such as
internal friction, cohesion, unit weight, moisture content, gradation of fines, consolidation and
plasticity. Most soils are a combination of a cohesive soil (clay) and cohesionless soil (sand).
12.2 Site Survey
12.2.1 Soil Borings: Depending on the transmission line and knowledge of the soil conditions
along the corridor, soil borings may or may not be taken. If the line is composed of H2 or higher
class wood poles, or equivalent strength steel or concrete poles, the engineer may elect to take
soil borings. The decision to take borings will also depend on existing soil information.
Variation of the soil will determine the frequency of the borings. Borings might also be
considered at unguyed angle structures and deadend structures composed of steel or concrete
poles.
12.2.2 Embedment Depths: In deciding embedment depths for many typical agency borrower
wood pole construction, economics dictate that few, if any, soil borings be taken when data and
experience from previous lines are available. Numerous soil conditions will be encountered in
the field. Although the soil conditions may closely resemble each other, the soils may have a
wide range of strengths. The engineer, therefore, has to identify areas or conditions where pole
embedment depths in soil may have to be greater than the minimum depth of 10 percent, plus 2
feet.
Areas where the designer needs to consider additional embedment depths include (but are not
limited to):
•
Low areas near streams, rivers, or other bodies of water where a high water table or a
fluctuating water table is probable. Poles in a sandy soil with a high water table may
"kick" out. Due to the lubricating action of water, frictional forces along the surface area
of embedded poles are reduced. The legs of H-frames may "walk" out of the ground if
neither sufficient depth nor bog shoes are provided to resist uplift. Guy anchors may fail
if the design capacity does not consider the submerged weight of the soil.
•
Areas where the soil is loose such as soft clay, poorly compacted sand, pliable soil, or
soil which is highly organic in nature.
Bulletin 1724E-200
Page 12-2
•
Locations where higher safety is desired. This may be at locations of unguyed small
angle structures where a portion of the load is relatively permanent in nature, or at river,
line, or road crossings.
•
Locations where poles are set adjacent to or on steep grades.
•
Locations where more heavily loaded poles are used.
•
Locations where underground utilities such as water or sewer will be located next to the
pole.
12.2.3 Field Survey: A field survey is necessary in order to judge whether a soil is "good,"
"average," or "poor." There are several economical methods to make a field survey for wood
transmission lines. The engineer may use a hand auger, light penetrometer, or torque probe. The
meaning of terms such as firm, stiff, soft, dense, and loose may not always be clear. Table 12-1
will help to clarify these terms:
TABLE 12-1
CLASSIFICATION OF SOILS BASED ON FIELD TESTS
Term
Very soft
Soft
Firm
Stiff
Very Stiff
Hard
Field Test
Squeezes between fingers when fist is closed
Easily molded by fingers
Molded by strong pressure of fingers
Dented by strong pressure of fingers
Dented only slightly by finger pressure
Dented only slightly by pencil point
Term
Field Test
Loose
Easily penetrated with a 1/2 in. reinforcing rod pushed by
hand
Easily penetrated with a 1/2 in. reinforcing rod driven with
a 5 lb. hammer
Penetrated 1 ft. with a 1/2 in. reinforcing rod with a 5 lb.
Hammer
Penetrated only a few inches with a 1/2 in. reinforcing rod
driven with a 5 lb. hammer
Firm
Dense
Very dense
12.3 Pole Stability
12.3.1 Wood Poles: In addition to local experience with wood poles, the graphs in Figures 12-1
through 12-3 may be used to approximate embedment depths. To use the charts, good, average,
and poor soils have to be defined. The following are proposed as descriptions of good, average,
and poor soils:
Good: Very dense, well graded sand and gravel, hard clay, dense, well graded, fine and coarse
sand.
Average: Firm clay, firm sand and gravel, compact sandy loam.
Poor: Soft clay, poorly compacted sands (loose, coarse, or fine sand), wet clays and soft clayey
silt
Bulletin 1724E-200
Page 12-3
The graphs in Figures 12-1 through 12-3 are based on Equation 12-1:
3.75
S e De
P=
L − 2. − .662 De
Eq. 12-1
where:
P = horizontal force in pounds 2 feet from the top that will
overturn the pole
Se = Soil constant
140 for good soils
70 for average soils
35 for poor soils
De = embedment depth of pole in feet.
L = total length of pole in feet.
Embedment depth can be determined once an equivalent horizontal load 2 feet from the top is
calculated. This horizontal load is calculated by dividing the total ground line moment by the
lever arm to 2 feet from the top of the pole.
Equation 12-1 is taken from "Effect of Depth of Embedment on Pole Stability," Wood
Preserving News, Vol X, No. 11, November, 1932.
Some general observations can be made concerning wood pole embedment depths:
•
The rule of thumb of "10 percent + 2 ft." is adequate for most wood pole structures in
good soil and not subjected to heavy loadings.
•
For Class 2 and larger class poles and poles of heights less than 60 ft., pole embedment
depths should be increased 2 ft. or more in poor soil (single pole structures).
•
For Class 2 and larger class poles and poles of heights less than 40 ft., pole embedment
depths should be increased 1-2 ft. in average soil (single pole structures).
•
For H-frame wood structures, "10 percent + 2 ft." seems to be adequate for lateral
strengths. Embedment depths are often controlled by pullout resistance.
40'
Load 2' from the top (lbs.)
6,000
POOR SOIL
4,000
60'
90'
2,000
0
5
6
7
8
9
Embedment Depth (ft.)
FIGURE 12-1: EMBEDMENT DEPTHS IN POOR SOIL
10
Bulletin 1724E-200
Page 12-4
10,000
Load 2' from the top (lbs.)
40'
8,000
AVERAGE SOIL
60'
6,000
90'
4,000
2,000
0
5
7
6
8
9
10
Embedment Depth (ft.)
FIGURE 12-2: EMBEDMENT DEPTHS IN AVERAGE SOIL
40'
60'
Load 2' from the top (lbs.)
10,000
90'
GOOD SOIL
8,000
6,000
4,000
2,000
0
5
6
7
8
9
10
Embedment Depth (ft.)
FIGURE 12-3: EMBEDMENT DEPTHS IN GOOD SOIL
Bulletin 1724E-200
Page 12-5
FIGURE 12-4: EMBEDMENT CHART FOR MEDIUM DRY SAND
AGENCY BULLETIN 1724E-205 “EMBEDMENT DEPTHS
FOR CONCRETE AND STEEL POLES”
Bulletin 1724E-200
Page 12-6
12.3.2 Direct Embedded Steel and Concrete Poles: In agency Bulletin 1724E-205,
“Embedment Depths for Concrete and Steel Poles,” embedment charts are provided for concrete
and steel transmission poles sustaining relatively large overturning moments. The information in
Bulletin 1724E-205 may be used to approximate embedment depths for cost estimates, to make
preliminary selection of embedment depths and to verify or check selection of embedment
depths based on other or more exact methods. Sample calculations illustrating the use of the
embedment charts and illustrating the use of design methods for those occasions when the charts
cannot be used, are also provided in Bulletin 1724E-205.
In that bulletin, nine embedment charts have been developed for nine soil types. These charts
show embedment depths for pole diameters ranging from 1.0 to 4.0 feet and ultimate moments at
groundline up to 3500 ft-kips. A sample chart for medium sand is shown in Figure 12-4 of this
bulletin.
Several computer programs exist for determining embedment depths for steel and concrete poles.
Such programs may provide a more efficient selection of embedment depths in preliminary
design and their use should be considered in any final design.
12.3.3 Replumbing: If a search of previous experience in an area indicates that single pole
lines have had to be replumbed, there are several methods which should be considered in order
to reduce the frequency of replumbing of a new line to be located in the same area. These
methods are as follows:
•
•
•
•
•
Use a lower grade species of wood in order to increase embedment diameters. For
instance, embedment diameters for Class 1 Western red cedar poles will be greater than
embedment diameters for Douglas fir.
Use aggregate backfill.
Install a pole key with or without a pole toe of crushed stone, gravel, or concrete.
Embed one foot deeper (or more).
In the case of more heavily loaded steel and prestressed concrete poles, consideration
should be given to the use of concrete backfill.
12.4 Bearing Capacity: To prevent a guyed pole from continually sinking into the ground due
to induced vertical loads, the pole butt should provide sufficient bearing surface area. If little
soil information is available, local building codes (Table 12-2) might be helpful in determining
allowable bearing capacities. These values are usually conservative and reflect the hazards
associated with differential deflection in a building. Fortunately, transmission lines can sustain
deflections on the order of several times that of buildings without detrimentally affecting their
performance. The bearing capacity of guyed poles is not as critical as that for buildings. Good
engineering judgment and local experience should be used in determining if bearing capacities of
a certain soil will be exceeded by guyed poles. Table 12-3 suggests ranges of ultimate bearing
capacities.
Bulletin 1724E-200
Page 12-7
TABLE 12-2
PRESUMPTIVE ALLOWABLE BEARING CAPACITIES, ksf
Soil Description
Clay, very soft
Clay, soft
Clay, ordinary
Clay, medium stiff
Clay, stiff
Clay, hard
Sand, compact and clean
Sand, compact and silty
Inorganic silt, compact
Sand, loose and fine
Sand, loose and coarse, or
sand-gravel mixture, or
compact and fine
Gravel, loose, and compact
coarse sand
Sand-gravel, compact
Hardpan, cemented sand,
cemented gravel
Soft rock
Sedimentary layered rock
(hard shale, sandstone,
siltstone)
Bedrock
Chicago
1966
Atlanta
1950
Uniform Building Code
1964
0.5
1.5
2.5
3.5
4.5
6.0
5.0
3.0
2.5
2.0
2.0
4.0
1.5
1.5
2.5
4.0
8.0
1.5
1.5
2.5
8.0
12.0
12.0
8.0
8.0
20.0
30.0
200.0
200.0
TABLE 12-3
SUGGESTED RANGES OF PRESUMPTIVE
ULTIMATE BEARING CAPACITIES, psf*
Specific Description (Dry)
Clay, soft
Clay, ordinary
Clay, stiff
Clay, hard
Sand, loose
Sand, compact and silty
Sand, compact and clean
Hardpan
psf
2000 - 6000
6000 - 9000
12000
15000
4500
9000
15000
40000
General Description (Dry)
Poor Soil
Average Soil
Good soil
1500 - 4000
5000 – 9000
12000 - 18000
Note:
Ultimate values are based on three times allowable. The
values in the table are considered approximate. For more
accurate bearing capacity values, bearing capacity equations
should be used.
Bulletin 1724E-200
Page 12-8
12.5 Uplift: When H-frame structures with X-braces are subject to overturning forces, one leg
will be in compression and one leg in tension. The skin friction assumed in design should be
based on past experience encountered by the engineer, experience of nearby lines, and the results
of the field survey. The following may be appropriate for average soil:
•
If the soil is wet or subject to frequent wettings, an ultimate skin friction not greater than
100 psf should probably be assumed;
•
If native soil is used as backfill, an ultimate skin friction between 100 and 500 psf should
be assumed, provided the soil is not subject to frequent wettings;
•
If an aggregate backfill is used, an ultimate skin friction between 250 and 1000 psf may
be possible;
•
Pole "bearing" shoes increase uplift capacity of a dry hole with natural backfill on the
order of 2 to 2.5 times. The use of aggregate backfill with bearing shoes is usually not
necessary provided the native backfill material is of relatively good material; and
•
In many cases, double cross-braced H-frame structures may require uplift shoes.
12.6 Construction - Backfill: Lateral and uplift resistance of wood poles will depend not only
on type of soil, moisture content of the soil, depth of setting, but also on how well the backfill
has been tamped.
All water should be removed before backfilling. If native backfill material is to be used, it
should be free of grass, weeds, and other organic materials. If the dirt removed from the hole is
too wet or has frozen, dry, unfrozen material should be obtained for the backfill. Where the
earth removed from the hole is unsuitable as backfill, special backfill should be specified by the
engineer. Drawing TM-101 included in agency Bulletins 1728F-810 and 811 suggests a
gradation of aggregate to be used as backfill material.
When backfilling, the soil should be placed and compacted in shallow layers (approximately 6
inch layers). Each layer should be compacted until the tamp makes a solid sound as the earth is
struck. Power tamping is preferred using two power tampers and one shoveler. The importance
of proper compaction of the backfill cannot be overemphasized. Insufficient tamping is a
common source of trouble and has been the cause of some failures.
Bulletin 1724E-200
Page 13-1
13. STRUCTURES
13.1 Economic Study: During preliminary planning stages of lines above 161 kV, studies
should be made to evaluate the economics of different types of structures as related to conductor
size. In most instances, for lines of 230 kV and below, wood structures have historically been
the economical choice. However, in more heavily loaded situations (larger wires, longer spans)
steel and prestressed concrete structures may be more economical than wood, especially
considering the long-term maintenance costs associated with wood structures. In some instances,
other types of material have been used because of environmental or meteorological constraints.
For voltages 345 kV and above, it may be difficult to obtain long span construction utilizing
wood, due to height or strength reasons.
In most instances, for lines 230 kV and below, an economic study can help to determine
structure configuration, base pole class (wood, steel or prestressed concrete) and height.
Factors which limit structure spans include:
a. Strength: Horizontal spans are limited by crossbrace, poles, etc. Vertical spans are limited by
crossarms, structure strength. For H-frame structures, horizontal and vertical spans are also
limited by pullout resistance for H-frame structures.
b. Conductor Separation: Conductor separation is intended to provide adequate space for line
crew personnel on poles, prevention of contact and flashover between conductors.
c. Clearances-to-Ground: Limits on spans are directly related to height of structures.
d. Insulator Swing: The ratio of horizontal to vertical span will be limited by insulator swing and
clearance to structure.
Historically, preliminary cost estimates have been usually based on level ground spans. With the
advent of computer-automated line design and optimization software, preliminary cost estimates
can now be performed using a preliminary profile digitized from the United States Geological
Survey (USGS) topographic maps or from other sources. An economic study should consider
material costs, cost of foundations and erection, different structure heights, hardware costs, and
right-of-way costs. The estimates are intended to give borrowers an idea as to relative rankings
of various structure types and configurations such as steel lattice, steel pole, prestressed concrete
pole, and wood H-frame or single pole. However, in the decision-making process, the manager
may want to consider as part of the evaluation such intangibles as importance of the line to the
power system, appearance, material availability, and susceptibility to environmental attack. In
some areas, State or local constraints may ignore economics and specify the type of structure to
be used.
The level ground span used to develop preliminary cost estimates in the economic study is
determined from clearance-to-ground and structure strength. Developing a graph, as shown in
Figure 13-1, is one means of determining the level ground span (points A and B). Structure cost
per mile can be related to pole height and class of poles as shown in Figure 13-2. To keep the
cost down, the line design should be based on one tangent structure type and one or two pole
classes for the majority of the line. For H-frame structures, the engineer should consider double
crossbraced structures, as well as single crossbraced structures.
With the help of computer automated line design and optimization software, an economic study
can be accomplished almost concurrently with the line design. If a land profile is available, or
developed from USGS maps, the line designer may want to use optimization software to help
Bulletin 1724E-200
Page 13-2
determine the most economic line design. With such software, different structure types and
materials and different conductor types can be evaluated. An advantage of optimization software
is the use of the actual terrain (rather than level ground span) or a good approximation of the
terrain. Optimization algorithms can fit structure height and type to the terrain, and can make
use of different structure heights and configurations. The major disadvantage of optimization
software is that it requires input and analysis of large amounts of data.
Class 1
Span limit due
to strength
Structure per mile or
span length, feet
Class 2
B
A
Span limit due to
conductor sag
Pole height, feet
FIGURE 13-1: SELECTION OF LEVEL GROUND SPAN
Structure costs per mile
36
Class 2(1x)
34
Class 1(1x)
Class 2(2x)
32
30
28
70
80
90
100
110
Pole height, feet
FIGURE 13-2: STRUCTURE COST PER MILE RELATED TO POLE HEIGHT
13.2 Steel and Concrete Structures - General Design Considerations: Rural Utilities Service
provides several bulletins on design considerations for steel and concrete pole structures.
•
•
•
•
1724E-204, “Guide Specifications for Steel Single Pole and H-Frame Structures,”
1724E-214, “Guide Specification for Standard Class Steel Transmission Poles,”
1724E-206, “Guide Specification for Spun, Prestressed Concrete Poles and Concrete Pole
Structures,”
1724E-216, “Guide Specification for Standard Class Spun, Prestressed Concrete
Transmission Poles.”
The bulletins include sample purchase specifications, design considerations, and suggested
drawings and example design calculations.
Bulletin 1724E-200
Page 13-3
13.3 Wood Structures - General Design Considerations
13.3.1 Stress Limitations: The structural stress limitations set forth in Table 13-1 are
recommended for transmission lines using agency standard wood pole construction. These
values assume that the wood has not deteriorated due to decay occurring in the manufacturing
process.
TABLE 13-1
DESIGNATED STRESSES FOR POLES
Kind of Wood
Modulus of
Elasticity x 1000
(psi)
Designated Ultimate
Bending Stress
(M.O.R.)* (psi)
1710
1800
1920
1340
1220
1800
1260
1120
800
8400
8000
8000
6600
6600
6600
6000
6000
4000
Western larch
Southern yellow pine
Douglas fir
Lodgepole pine
Jack pine
Red (Norway) pine
Ponderosa pine
Western red cedar
Northern white cedar
*M.O.R. = Modulus of Rupture
Douglas fir and Southern yellow pine (SYP) are used for crossarms. Southern yellow pine has
four species which are long leaf (most popular species), loblolly, shortleaf, and slash. The coast
type Douglas fir is the only type which should be used when specifying Douglas fir for
crossarms. Table 13-2 gives strength properties to be used in crossarm design.
TABLE 13-2
DESIGNATED STRESSES FOR CROSSARMS
Kind of
Wood
Modulus of
Elasticity x 1000
(psi)
Douglas fir
1920
SYP
1800
*M.O.R. = Modulus of Rupture
Designated Ult.
Bending Stress
(M.O.R.)* (psi)
End Grain Max
Crushing
Strength (psi)
Across Grain
Stress
(psi)
Shear
Parallel to
Grain (psi)
7400
7400
7420
7070
910
1000
1140
1310
13.3.2 Preservative Treatment: The decay of poles results from fungi and other low forms of
plant life which attack untreated poles or poles with insufficient preservative. Damage by insect
attack (termites, ants, and wood borers) is also associated with decay. When preservative
retention is low, wood cannot resist attacks by fungi and insects. There are two general classes
of preservative treatment.
Oil-Borne Using Creosote, Penta and Copper Naphthenate in Petroleum: Creosote oil was the
predominant preservative for poles on rural systems until about 1947. Post-war shortages
prompted the introduction of pentachlorophenol (penta) and copper naphthenate dissolved in the
fuel oils, and other preservatives.
Waterborne Using Arsenates of Copper: Poles using waterborne arsenates of copper (CCA,
ACA and ACZA) are green in appearance. These preservatives were developed before
World War II and have proven very effective as wood preservatives around the world. For
Bulletin 1724E-200
Page 13-4
species and amounts of treatment, refer to agency Bulletin 1728F-700, “Specification for Wood
Poles, Stubs, and Anchor Logs.”
13.3.3 Structure Designations for Single Wood Pole Structures: Single pole wood structures
are mainly limited in use to 115 kV and below. The six primary standard single pole structures
utilized by Rural Utilities Service borrowers are designated as:
•
•
•
•
•
•
TP - pin or post insulators
TPD - pin or post insulators, double circuit
TS - suspension insulators, crossarm construction
TSD - suspension insulators, crossarms, double circuit
TSZ - suspension insulators, "wishbone" arm construction
TU - suspension insulators, steel upswept arm construction
13.4 Design Calculations for Single Wood Pole Structures
13.4.1 Maximum Horizontal Span Limits of Single Wood Pole Structures: The following
conditions should be taken into account when determining horizontal spans as limited by pole
strength for tangent structures:
•
Wind on the conductors and OHGW is the primary load. 75 to 90 percent of the
horizontal span will be determined by this load.
•
Wind on the structure will affect the horizontal span by 5 to 15 percent.
•
Unbalanced vertical load will increase ground-line moments. For single circuit
structures, one phase is usually left unbalanced. The vertical load from the conductor
will induce moments at the groundline and will affect horizontal span lengths by 2 to
10 percent.
•
P-delta (P-δ) moments will also increase induced ground line moments. As a transverse
load is applied to a structure, the structure will deflect. This deflection will offset the
vertical load an additional amount " δ " causing an additional moment of the vertical
weight times this deflection. This additional moment due to deflection is a secondary
effect. An approximate method for taking into account the p-δ moments is given in
section 13.4.2.
For wood structures, depending on the taper of the pole, the maximum stress may theoretically
occur above the ground level. The general rule of thumb is that if the diameter at ground level is
greater than one and a half times the diameter where the net pull is applied, the maximum stress
occurs above the ground level. Even if the point of maximum stress occurs above the groundline
for single base wood pole structures, one can assume that spans are based on groundline
moments in accordance with Exception 1 in NESC Rule 261A.2. Exception 1 states: “When
installed, naturally grown wood poles acting as single-based structures or unbraced multiple-pole
structures, shall meet the requirements of Rule 261A.2a without exceeding the permitted stress
level at the ground line for unguyed poles or at the points of attachment for guyed poles.”
The strength of the crossarm has to be checked to determine its ability to withstand all expected
vertical and longitudinal loads. When determining bending stress in crossarms, moments are
calculated at the through bolt, without considering the strength of the brace. The vertical force is
determined by the vertical span under those conditions which yield the maximum vertical
weight. The strength of two crossarms will be twice the strength of one crossarm. When
considering the strength of the crossarm to withstand longitudinal loadings, reduction in the
moment capacity due to bolt holes should be taken into account.
Bulletin 1724E-200
Page 13-5
Equation 13-1 is the general equation for determining the moment induced in the pole from the
applied loads represented in Figure 13-3. This equation may be used to determine the maximum
horizontal span as demonstrated in the example in Paragraph 13.4.2.
φM A = M g = (LF )M wp + (LF )M wc + (LF )M vo + (LF )M p −δ
Eq. 13-1
where:
φ = strength factor, see Chapter 11
MA = FbS, the ultimate groundline moment capacity of the
pole, ft-lbs. For moment capacities of wood poles at
the groundline, (see Appendix F);
Fb = designated ultimate bending stress (M.O.R.)
S = section modulus of the pole at the groundline (see
Appendix H).
LF = load factor associated with the particular load
Mg = induced moment at the ground line
Other symbols are defined by Equations 13-2, 13-3, 13-4, 13-5.
When estimating the load carrying capacity of a pole using manual methods, it is difficult to
assess the additional moment due to deflection. Equations 13-5 and 13-6 provide an
approximate way to calculate the additional moment due to defection. Because Mp-δ is a
function of the vertical span (VS), the engineer should make an assumption about the
relationship between the vertical and horizontal span (HS). In Equations 13-4 and 13-5, the
relationship used is: VS = 1.25HS.
Pg
Sg
Sc
Pc
Pt
h
hg
Sa
Sb
hc
hl
FIGURE 13-3: TS TYPE STRUCTURE
h a ,h b
A
Refer to Figure 13-3 when considering the equations and symbols that follow.
a. Mwp = groundline moment due to wind on the pole
2
(
F )(2d t + d a )(h )
M wp =
72
where:
F = wind pressure, psf
dt = diameter of pole at top, inches
da = diameter of pole at groundline, inches
h = height of pole above groundline, feet
Eq. 13-2
Bulletin 1724E-200
Page 13-6
b. Mwc = groundline moment due to wind on the wires
M wc = pt (h1 )HS
where:
Eq. 13-3
HS = horizontal span, feet
h1 = moment arm of pt, feet; in the example,
(h )( p ) + (hb )( pc ) + (hc )( pc ) + (hg )( pg )
h1 = a c
Pt
Eq. 13-3a
pt = sum of transverse unit wire loads, lbs/ft; in example,
pt = 3 pc + pg single circuit, single pole structures
c. Mvo = groundline moment due to unbalanced vertical load
Mvo = 1.25HS(wcst + wgsg) + Wist
Eq. 13-4
where:
sg = Horizontal distance from center of pole to ground wire
(positive value on one side of the pole, negative on the
other), feet
st = sa + sb + sc , where sa , sb ,and sc are horizontal
distances from center of pole to conductors (positive
value on one side of the pole, negative on the other),
feet
wc = weight of the conductor per unit length, lbs./ft.
wg = weight of overhead groundwire per unit length, lbs./ft.
Wi = weight of insulators, lbs.
d. Mp-δ = groundline moment due to pole deflection
Mp -δ = 1.25HS(wt)δimp
where:
wt = total weight per unit length of all wires, lbs./ft.
δimp = improved estimate of deflection of the structure, ft.
δ imp
(
⎛ 6.78( pt )(HS )(hc )3144
= ⎜⎜
3
E (d a ) (d1 )
⎝
)⎞⎟δ
⎟
⎠
mag
Eq. 13-5
Eq. 13-6
E = modulus of elasticity, psi
da = diameter of pole at location "A" (groundline), inches
d1 = diameter of pole at height "h1" inches
δmag = deflection magnifier, no units, (assume 1.15 initially)
hc = effective height to the conductors, feet
HS = horizontal span, feet
pt = total transverse load per unit length of all wires, lbs./ft.
Bulletin 1724E-200
Page 13-7
After substitutions of Mwp, Mwc, Mvo, and Mpδ have been made into Eq.13-1, the equation
can be reduced to a quadratic equation (below) and solved for the horizontal span. (See
Paragraph 13.4.2 for an example of how the calculation of HS is carried out.)
a (HS ) + b(HS ) + c = 0
2
Eq. 13-7
− b ± b 2 − 4ac
2a
Once “HS” has been calculated, check the assumption of δmag = 1.15:
HS =
δ mag
Eq. 13-8
1
=
1.25HS (Wt )
1−
Pcr
51.25'
47.5'
40.5'
h l = 44.6 '
40.5'
60'
7.0'
4.5'
(See Chapter 14 for calculations of Pcr)
13.4.2 Example of Maximum Horizontal Spans: Determine the maximum horizontal span for the 69
kV TSS-1 wood structure (Figure 13-4). Terrain is predominantly level, flat, and open. ("sg" is
negligible; see Equation 13-4). Location and magnitude of resultant loads are indicated in Figure 13-5.
Given:
3.75
NESC Heavy Loading
Extreme wind
19 psf on the wires
22 psf on the structure
Extreme Ice with
4 psf, 1 inch radial ice
5.5'
Concurrent Wind(EI&W)
Pole:
Western red cedar
Conductor:
266.8 kcmil,
26/7 ACSR (Partridge)
Ground wire:
3/8"
H.S.S.
Conductor loads, lbs./ft:
Heavy
High Wind
EI&W
Transverse
0.5473
1.0165
.8808
Vertical
1.0776
0.3673
2.402
Ground wire loads, lbs./ft:
FIGURE 13-4: TSS-1 STRUCTURE
Heavy
High Wind
EI&W
Transverse
0.4533
0.5700
.7868
Vertical
0.8079
0.2730
1.9667
Other information:
Fb(pole)
= 6000 psi
pt = 2.10 lb/ft
Fb (crossarm)
= 7400 psi
S(groundline)
= 458 in3
wt
wt = 4.041 lb/ft
S(crossarm)
= 22.7 in3
Wt. of insulator
= 58 lbs.
Dia. (top)
= 8.59 in.
Dia. (groundline) = 16.72 in.
pt(total unit load) = 3(0.5473)+.4533 = 2.10 lbs./ft.
wt(total unit load) = 3(1.0776)+0.8079 = 4.41 lbs./ft
Pcr(critical
17,900 lbs. (see chapter 14 for fix–free
buckling load) =
condition) , l =44.6 ft., E=1.12 E 06 psi
da = 9.63 in., dg = 16.72 in., Ia=422 in4
FIGURE 13-5:
APPLICATION OF FORCES
(HEAVY LOADING)
Bulletin 1724E-200
Page 13-8
Solution for Maximum Horizontal Span Considering P-δ moments: A comparison of unit loads
with load factors indicates that the Heavy Loading District Loads control design. Therefore, for
Heavy Loading, the moments for Equation 13-1 are calculated.
2
4[(2 )(8.59 + 16 .72 )](52 )
a. M wp =
6(12 )
= 5,100 ft − lbs .
b. M wc = (2 )(0.5473 )(40 .5 )HS + (0.5473 )(47 .5 )HS + (0.4533 )(51 .25 )HS
= 93 .5 HS
c. M vo = [(3.75 )(1.0776 ) − .8075 (.5) ]HS (1.25 ) + Wi s t
= 4.45 HS + 217
d M pδ = (1.25 )(HS )(4.041)δ imp
6.78(2.095 )(HS )(44 .6 ) (144 )
3
δimp =
(1.12 E 06 )(16.72 )3 (9.63)
δ imp = .003558 (1.15 )HS
δ mag
δ imp = .0041 HS
M pδ = (1.25 )(4.041)(HS )(.0041)(HS )
= .0207 (HS )
2
e. φM a = ( LF ) M wp + ( LF ) M wc+ ( LF ) M vo + ( LF ) M pδ
(.65)(229, 000) = ( 2.5)(5,100 ) + ( 2.5)(93 .5) HS + 1.5( 4.45) HS + 1.5( 217 ) + 1.5(.0207 ) HS 2
148,524 = ( 2.5)(5,100 ) + (1.5)(187 ) + ( 2.5)(93 .5) HS + 1.5(5.56 ) HS + 1.5(.0207 ) HS 2
.0311 HS 2 + 241.32 HS − 135,820 = 0
f. a (HS ) + b(HS ) + c = 0
2
.0311(HS ) + 241 .32 (HS ) − 135,775 = 0
2
− 241 .32 + 241 .32 2 − 4(.0311 )(− 135,775 )
2(.0311)
HS = 527 feet
HS =
g. Once the HS has been calculated , the assumption of 1.15 as the magnifier
should be checked. Pcr = 17,900 assuming fixed free conditions (See Chapter 14).
δmag =
1
= 1.15
1 - (W t )1.25 HS
Pcr
δmag =
1
1 - (4.0407 )(1.25 )(525 )
17 ,900
.
= 1.175 Recalculat e assuming 1.17 as the deflection magnifier, HS = 529 feet.
Bulletin 1724E-200
Page 13-9
h. Lateral Stability: The Equivalent load 2 feet from the top is approximately 4400 lbs.
From Figure 12-2 (average soil), the embedment depth for a 4400 lb. load 2 feet from the top
is between 8 and 8.5 feet. Lines nearby have performed well with the standard embedment
depths. Engineering judgment dictates that an 8 foot embedment depth for the 60 foot pole
will be sufficient.
13.4.3 Maximum Vertical Span for TP and TS Pole Top Assemblies: To determine the
vertical span, the moment capacity of the arm at the pole is calculated.
Calculations for these structures are:
VS =
where:
Mx-arm
Fb
S
wc
sc
Wi
VS
φM x −arm − (LF )(Wi )(s c )
=
=
=
=
=
=
=
(LF )(wc )(sc )
Eq. 13-9
FbS, moment capacity of the arm, ft-lbs.
the designated bending stress.
the section modulus of the arm (see Appendix G.)
weight of the conductor per unit length, lbs./ft.
moment arm, meters (feet).
insulator weight, lbs.
vertical span, meters (feet).
Example of Vertical Span Calculations for TS Pole Top Assembly (Heavy Loading):
wc = 1.0776 lbs./ft., see Figure 13-4, S = 22.7 in3, φ = .50 and LF = 1.5 Heavy
Loading District,
0.50M a − (LF )(Wi )(s c )
(LF )(wc )(sc )
VS =
a.
M a = Fb S
M a = 7400(22.7 ) / 12
= 14,000 ft − lbs
b.
VS =
Wi = 50lbs.
(0.50)(14,000) − (1.5)(50 )(5.5)
(1.5)(1.0776)(5.5)
= 741 ft.
Check vertical span for extreme ice with concurrent wind,
wc = 2.4092 lbs./ft., φ = 1.0 and LF = 1.1 for extreme ice with concurrent wind
VS =
(1.0)(14,000) − (1.1)(50 )(5.5)
(1.1)(2.4092 )(5.5)
= 939 ft.
Bulletin 1724E-200
Page 13-10
13.4.4 Span Calculations for TSZ Pole Top Assembly: The TSZ structure is a wishbone-type
crossarm assembly. It is intended for use on transmission lines where conductor jumping due to
ice unloading and/or conductor galloping are problems. The wishbone provides additional
vertical and horizontal offset between phases in order to reduce the possibilities of phase-tophase faulting due to ice unloading or galloping.
"a"
S
FIGURE 13-6: TSZ-1 POLE TOP ASSEMBLY
Since the crossarms of the wishbone are not horizontal, the vertical span is related to the
horizontal span. The maximum vertical load (Wc) the TSZ-1single crossarm assembly can
withstand is 3,400 lbs. at any conductor position. By calculating moments at point "a"
on the assembly, horizontal and vertical spans are related. Span limited by pole strength are
calculated in the same manner as the TP and TS structures.
Example of Span Calculations for Wishbone Pole Top Assemblies: Determine the maximum
horizontal and vertical spans for the pole top assembly of the 69 kV TSZ-1 pole top assembly
(Figure 13-7).
Given:
Loadings:
1.5ft
3.22 ft
Wires
Conductor: 266.8 kcmil, 26/7 ACSR (Partridge)
OHGW:
3/8” H.S.S
Pole:
S.Y.P. (70-1)
VERTICAL SPAN (FT.)
"a"
NESC heavy loading district
1200
1100
1000
900
800
400
600
800
1000
HORIZONTAL SPAN (FT.)
FIGURE 13-7: TSZ-1 EXAMPLE
FIGURE 13-8: HS vs. VS FOR TSZ-1
Bulletin 1724E-200
Page 13-11
Solution:
Moment capacity of crossarm at “a”:
Ma = Wc(s)
Ma = 3,400(3.22)
= 10,950 ft-lbs.
Horizontal and vertical span:
The relationship between the horizontal and vertical spans is obtained by summing moments
about point ‘a’.
2.5(.5473)(1.5)HS+1.5(1.0776)(3.22)VS+1.5(50)(3.22) = (0.50)(10,950) ft-lbs.
2.05HS+5.21VS = 5234 ft-lbs.
For HS = VS, Span = 720 ft. See Figure 13-8 for application chart.
13.4.5 Span Calculations for TU-1 Pole Top Assembly: These assemblies have steel upswept
arms. With these arms, vertical spans are related to horizontal spans and a graph can be made to
relate horizontal and vertical spans. Spans limited by pole strength are calculated in the same
manner as the TP and TS structures.
Example of Span Calculations for Steel Davit Arm Construction: For the 138 kV structure in
Figure 13-9, plot the horizontal versus vertical span for steel davit arms.
Given:
Loadings:
7.0'
14'
14'
14'
8.0'
FIGURE 13-9: TU-1 STRUCTURE
NESC Heavy Loading
High Wind 19 psf on the wires
Wires:
Conductor:
OHGW:
Pole:
477 kcmil, 26/7 ACSR
3/8” H.S.S
S.Y.P. (70-1)
Conductor loads:
Transverse
Vertical
Heavy Ldg
0.6193
1.5014
High wind
1.3585
0.6570
Manufacturers catalog data for crossarms:
Rated Ultimate
s, length
R, rise
Vert. load (Wc)
3000
8.0
2.7
3000
7.0
2.5
Weight of insulators (Wi):
102 lbs.
EI&W
0.8808
2.4092
Bulletin 1724E-200
Page 13-12
s
Solution:
For the 8.0' davit arm, the moment capacity
of the arm at the pole (Figure 13-9a):
Ma =
=
=
R
.5'
Wc
Wc(s)
(3000)(8.0)
24,000 ft-lbs.
FIGURE 13-9a: DAVIT
An equation for the vertical and horizontal spans can be developed. Since the arm is steel, a
strength factor ( φ ) of 1.0 is used.
2.5(0.6193)(2.7)HS+1.5(1.5014)(8.0)VS+1.5(102)(8.0) = (1.0)(24,000) ft-lbs.
4.1803HS+18.017VS = 22,776 ft-lbs.
For the 7.0' davit arm, the moment capacity of the arm at pole:
Ma =
=
=
Wc(s)
(3000)(7.0)
21,000 ft-lbs
An equation for the vertical and horizontal spans can be developed:
2.5(0.6193)(2.5)HS+1.5(1.5014)(7.0)VS+1.5(102)(7.0) = (1.0)(21,000) ft-lbs.
3.87HS+15.77VS = 19,929 ft-lbs.
In this example for the NESC heavy loading district loads, the magnitude of the vertical span is
not sensitive to the horizontal span (as shown in Figure 13-10). For horizontal spans between
400 and 1000 feet, the vertical span for the 8 foot arm as well as the 7 foot arm should be limited
to 1018 feet (for design purposes, use 1000 feet). Spans limited by the extreme winds are not a
factor in this example.
VERTICAL SPAN (FT.)
1200
8.0 ft. arm
1100
7.0 ft. arm
1000
900
800
400
600
800
1000
HORIZONTAL SPAN (FT.)
FIGURE 13-10: VS vs. HS FOR TUS-1 STRUCTURE OF EXAMPLE 13-3
Bulletin 1724E-200
Page 13-13
13.5 Design Calculations for Wood H-Frame Structures
13.5.1 General: There are various techniques available for analysis of H-frame structures:
•
•
•
Classical indeterminate structural analysis.
Matrix methods of structural analysis.
Approximate methods (explained in this section and subsequent sections).
In analyzing a statically indeterminate structure by approximate procedures, one assumption is
made for each degree of indeterminacy. These assumptions are based on logical interpretations
of how the structure will react to a given loading. For the H-frame with knee and V-braces, we
can assume that the structure will behave as shown in Figure 13-11.
Outside
Kneebraces
B
F
E
Crossbraces
D
C
A
FIGURE 13-11: ASSUMED H-FRAME BEHAVIOR
At some point in the poles, there will be an inflection point (a point of zero moment). If the pole
or column is uniform in cross section, it is common to assume that the inflection point is located
midway between points of bracing, shown as a dotted line in Figure 13-11. However, since the
pole is tapered, the following relationship may be used to determine the location of the inflection
point (see Figure 13-12, Equation 13-10 and Appendix H for application chart).
CD
xo
C A (2C A + C D )
=
x 2 C A 2 + C AC D + C D 2
(
X
CA
)
Eq. 13-10
where:
Xo
CA = circumference at base
CD = circumference at top
FIGURE 13-12: LOCATION OF POINT
OF CONTRAFLEXURE
By applying the same reasoning, the inflection point can be located on the other column.
Locating the inflection point on each column, and hence the point of zero moment, entails
two assumptions for the frame. Since the frame is statically indeterminate to the third degree, a
third assumption has to be made. A common third assumption is that the shear in the columns is
Bulletin 1724E-200
Page 13-14
distributed equally at the inflection points. The shear in the columns is equal to the horizontal
force on the structure above the level under consideration.
For a less rigid support, the inflection point moves toward the less rigid support. Two
conclusions can be made:
•
For a pole rotating in the ground, the inflection point "C" below the crossbraces, is
lowered. The lowering of the inflection point inreasing the moment induced in the
pole at the connection of the lower crossbrace. Since the amount of rotation of a base
is difficult to determine, the usual design approach is to always assume a rigid base.
•
For H-frames with outside kneebraces only, the point of inflection ‘F’above the
crossbrace (shown in Figure 13-11) is higher than the point of inflection for four
kneebraces. This higher point of inflection increases the moment in the pole at the
upper crossbrace-pole connection. For the H-frame with outside kneebraces only, the
designer may make one of two assumptions:
(1) When determining induced moments in the poles, the outside kneebraces are
ignored and no point of inflection exists between the crossbrace and the crossarm.
This is a conservative assumption and assumes that the purpose of outside braces
is to increase vertical spans only.
(2) It can be assumed that the point of inflection occurs at the crossarm. This
assumption will be used in the equations and examples which follow.
13.5.2 Crossbraces: The primary purpose of wood X-bracing for H-frame type structures is to
increase horizontal spans by increasing structure strength. Additional benefits achieved by
crossbracing include possible reduction of right-of-way costs by eliminating some guys and
reduction of lateral earth pressures. For an efficient design, several calculations should be made
in order to correctly locate the crossbrace.
The theoretical maximum tensile or compressive load which the wood crossbrace will be able to
sustain will largely be dependent on the capacity of the wood brace to sustain a compressive
load. Drawing TM-110, X-brace Assembly of Bulletins 1728F-810 and 811, is to be used for the
115, 138, 161 kV, and 230 kV tangent structures. The crossbrace dimension is 3-3/8" x 4-3/8"
for the 115 kV structure, 3-3/8" x 5-3/8" for 138 kV and 161 kV structures. The dimensions of
this X-brace for the TH-230 structure are 3-5/8" x 7-1/2" (minimum).
The maximum compressive load which a wood X-brace is able to sustain is determined by:
Aπ2 E
Pcr =
Eq. 13-1145
2
⎛ kl ⎞
⎜ ⎟
⎝ r ⎠
where:
Pcr = maximum compressive load, lbs.
A = area, in2
E = modulus of elasticity, psi.
kℓ = effective unbraced length, in.
r = radius of gyration, in. which will give you the
maximum kℓ/r ratio; kℓ and r must be
compatible for the same axis
FIGURE 13-13: CROSSBRACE
( )
Bulletin 1724E-200
Page 13-15
For an assumed 1 foot diameter pole, the following theoretical values apply:
TABLE 13-3
CROSSBRACE CAPACITIES
Crossbrace
TM-110
3-3/8" x 4-3/8"
3-3/8" x 5-3/8"
TM-110A
3-5/8" x 7-1/2"
A
Area
(in2)
r
Least Radius
of
Gyration (in.)
L
Distance
CL to CL
of Poles (ft.)
0.5L/0.707
less 1’ for
Pole Dia.,
(in.)
kl
r
Pcr for
E = 1.8 x 106
(lbs.)
14.77
18.14
0.9743
0.9743
12.5
15.5
97.6
123.1
100.2
126.3
26,100
20,200
27.19
1.05
19.5
157
149.5
21,600
The calculations included in Table 13-3 do not reflect the capacity of the hardware. RUS
Specifications for Double Armed and Braced Type Crossarm Assemblies (138 kV and 161 kV),
and RUS Specifications for Double Armed and Braced Type Crossarm Assemblies (230 kV)
require X-braces to withstand a tension or compression loading of 20,000 lbs. This ultimate
value correlates with the above theoretical ultimate loads in the table. It is recommended that
20,000 lbs. (ultimate) be used for design purposes, since this value assures one that the
crossbrace will sustain the indicated load.
For the 115 kV structure (TH-1AA) it is recommended that 20,000 lbs. be used as the ultimate
load the crossbrace is able to sustain. The hardware for the crossbrace is the same as
the hardware used with 138 kV and 161 kV structures.
13.5.3 V-Braces: The primary purpose of two V-braces on the outside of the poles is to
increase vertical spans. Two V-braces on the inside will increase horizontal spans. Four Vbraces increase both horizontal and vertical spans. The various bracing arrangements and their
designations for 161 kV structures are shown in Figure 13-14.
TH-10
TH-10X
TH-10VIX
TH-10VOX
TH-10V4X
FIGURE 13-14: POLE TOP BRACING ARRANGEMENTS
(‘X’ added to the pole top assembly nomenclature refers to crossbrace)
RUS Specifications for Double Armed and Braced Type Crossarm Assemblies (138 kV and
161 kV) specifies the following minimum strength requirements for the various pole top
assemblies:
Maximum vertical load (at any conductor position)
TH-10
8,000 lbs.
TH-10VO
14,000 lbs.
TH-10V4
14,000 lbs.
Bulletin 1724E-200
Page 13-16
Maximum transverse conductor load (total)
TH-10VO
15,000 lbs.
TH-10V4
15,000 lbs.
Maximum tension or compression in V-brace
20,000 lbs.
RUS Specifications for Double Armed and Braced Type Crossarm Assemblies (230 kV)
specifies the following minimum strength requirements for the TH-230 pole top assembly:
Maximum vertical load (at any conductor position)
TH-230
10,000 lbs.
Maximum transverse conductor load (total)
TH-230
15,000 lbs.
Maximum tension or compression in V-brace
TH-230
20,000 lbs.
When determining maximum vertical and horizontal spans as limited by H-frame top assemblies,
the above minimum strengths may be used as guidance.
13.5.4 Structure Analysis of H-frames: Equations 13-16 to 13-22 are used for calculating
forces in the various members of H-frame structures. As part of the structural analysis, span
limitations due to strength of the pole top assembly (Equations 13-12 to 13-15) should be
considered and suggested methods follow. Appropriate load factors and strength factors should
be applied in the respective equations.
Outside V-Braces: An H-frame structure with two outside V-braces in figure 13-14 (and shown
in greater detail in Figure 13-19) needs further explanation. A structure with two outside Vbraces has less rigidity above the crossbrace than a structure with than four V-braces. The
location of the point of contraflexure is difficult to determine. Equation 13-10, which calculates
the moment (ME) at the top of the crossbrace assumes that the point of contraflexure exists at the
crossarm. However, when using Equation 13-12 to determining span limitations due to strength
of the pole top assembly, a point of contraflexure is assumed between the top of the crossbrace
and the crossarm.
The maximum vertical span is determined for the maximum horizontal span.
Pt
b
Wt
a
o
FIGURE 13-15: POLE TOP ASSEMBLY WITH TWO OUTSIDE BRACES
Bulletin 1724E-200
Page 13-17
Ultimate force in the brace is:
( LF )Wt ( LF ) Pt (a )
+
≤ (φ )20,000 ⋅ lbs
(b )sin α
sin α
where:
Eq. 13-12
Wt = total vertical load at the phase wire, locations, lbs.,
Wt = VS(wc)+Wi,
VS = vertical span, ft.
wc = weight load per foot of conductor, lbs./ft.
Wi = total weight of the insulators, lbs.
Pt = total transverse load, lbs.
Pt = (HS)(3pc+2pg) where
HS = horizontal span, ft.
pc = wind load per foot of conductor, lbs./ft.
pg= wind load per foot of overhead ground wire, lbs./ft.
a = distance from the point of contraflexure to equivalent force, ft.
b = distance between poles, ft.
LF = load factor
α = angle the brace makes with the crossarm
Two Inside V-Braces: Pole bending moment, uplift, and force in the X-brace may be calculated
in the same manner as when four braces are used. Crossarm strength controls the maximum
vertical span.
Force in the braces is:
( LF )Wt ( LF ) Pt (a )
+
≤ (φ )20,000.lbs
(b )sin α
2 sin α
Eq. 13-13
Crossarm bending moment, (φ ) M o is:
(φ ) M o =
( LF )Wt (b )
2
Eq. 13-14
Pt
a
o
b
Wt
FIGURE 13-16: POLE TOP ASSEMBLY WITH INSIDE BRACES
Bulletin 1724E-200
Page 13-18
Four V-Braces: The following equations can be used to determine the maximum vertical span as
limited by four V-braces, given the maximum horizontal span:
For four V-braces, force in the outside braces is:
( LF )Wt
≤ (φ )20,000 lbs
sin α
Eq. 13-15
Force in the inside braces is:
( LF )Wt ( LF ) Pt (a )
+
≤ (φ )20,000 lbs
(b )sin α
2 sin α
from Eq. 13-13
13.5.5 Abbreviations: In Equations 13-16 to 13-23, all units should be consistent. The
following abbreviations apply:
De
F
Fs
HS
Ma
Mn
=
=
=
=
=
=
LF
Qu
Rn
U
V
Vn
VS
Wc
Wg
Wi
Wl-p
Wp
Wt
=
=
=
=
=
=
=
=
=
=
=
=
=
W1 =
W2
X
Y
a
=
=
=
=
b =
davg =
dbt =
dn =
dt =
embedment depth
wind pressure on a cylindrical surface, psf
presumptive skin friction value, psf
horizontal span, ft.
moment capacity of crossarm
moment capacity at the indicated location ‘n’, ft-lb.
includes moment reduction due to bolt hole,
i.e., Mn = Mcap-Mbh.
load factor (see Chapter 11 of this bulletin)
ultimate bearing resistance of the soil, psf
reaction at the indicated location,"n," lbs.
dummy variable
dummy variable
induced axial force at the indicated location, lbs.
vertical span, ft.
weight of conductors (plus ice, if any),lbs.
weight of OHGW (plus ice, if any),lbs.
total weight of the insulators
weight of a line person
weight of pole, lbs.
total weight equal to weight of conductors (plus ice, if
any, WC) plus weight of insulators,Wi.
total resistance due to skin friction around the
embedded portion of the pole, lbs.
total bearing resistance of the soil, lbs.
dummy variable
dummy variable
distance from Pt to the point of contraflexure above the
crossbrace for an H-frame structure with pole top
bracing. Ft.
spacing of the poles of an H-frame, ft.
average diameter of pole between groundline
and butt, ft.
diameter of pole at butt, ft.
diameter at location "n,” ft.
diameter of pole at top, ft.
Bulletin 1724E-200
Page 13-19
fs = calculated skin friction value, psf
hn = length as indicated, ft.
Pt = total horizontal force per unit length due to wind on the
conductors and overhead ground wire, lbs./ft.
sn = distance as shown, ft.
wc = weight per unit length of the conductors (plus ice, if
any), lbs./ft.
wg = weight per unit length of overhead ground wire (plus
ice, if any), lbs./ft.
φ = strength factor (see Chapter 11 of this bulletin)
13.5.6 Equations for Structure 1 (Figure 13-17): For this structure, the horizontal span is
reduced by 10 % to take into account P-delta (P-δ)moments (i.e. 0.90 in Equation 13-16). For a
more detailed analysis, see Equation 13-1 for single poles.
⎛
(LF )(F )(h )2 (2d t + d a ) ⎞⎟ ⎛ (LF )( pt )(h1 ) ⎞
HS A = ⎜⎜ (φ ) M A −
⎟(0.90)
⎟ / ⎜⎝
6
2
⎠
⎝
⎠
R A = ( LF )(W g + 3 / 2Wt + W p )
VS =
Wt
Eq. 13-17
(φ ) M a − (LF )(Wi )(s )
wc (s )(LF )
B
Eq. 13-18
B
Wt
S
Pt
Wt
h
A
Eq. 13-16
A
b
FIGURE 13-17: STRUCTURE 1
h
l
Bulletin 1724E-200
Page 13-20
13.5.7 Equations for Structure 2 (Figure 13-18):
⎛
(LF )(F )( y1 )2 (2d t + d b ) ⎞⎟
( )
HS B = ⎜⎜ (φ ) M B −
⎟ / (LF ) p g ( y1 )
6
⎝
⎠
2
⎛
(LF )(F )( y ) (2d t + d e ) ⎞⎟ (LF )( pt )( y o )
HS E = ⎜⎜ (φ ) M E −
⎟/
6
2
⎝
⎠
(LF )(F )(h − xo )(x1 )(d t + d c ) ⎞ (LF )( pt )(x1 )
⎛
HS D = ⎜ (φ ) M D −
⎟/
2
2
⎝
⎠
(LF )(F )(h − xo )(xo )(d t + d c ) ⎞ (LF )( pt )(xo )
⎛
HS A = ⎜ (φ ) M A −
⎟/
2
2
⎝
⎠
Eq. 13-19a
Eq. 13-19b
Eq. 13-19c
Eq. 13-19d
For crossbrace:
(
)
HS x = (φ )28,300(b ) − 2(LF )(F )(h − xo ) (2d t + d c ) / 6 / (LF )( pt )(h2 )
Eq. 13-19e
HS ( pt )(h2 ) − VS (wg )(b ) − 1.5VS (wc )(b ) = W1 (b ) + W p (b ) + X − Y
Eq. 13-19f
2
For uplift:
For bearing:
HS ( pt )(h2 ) + VS (wg )(b ) + 1.5VS (wc )(b ) = W2 (b ) − W p (b ) + X − Y + (w1 )(b ) Eq. 13-19g
where:
W1 = Fs (De )(d avg )π / S .F .
(
)
Eq. 13-19h
W2 = π d bt / 4 (Qu ) / S .F .
Eq. 13-19i
X = (F )(h − xo )(d t + d c )( xo )
Eq. 13-19j
Y = 2(F )(h ) (2d t + d a ) / 6
Eq. 13-19k
2
2
y
y 1
B
B
E
E
Pt
yo
h2 h1
h
D
D
C
C
A
A
x1
xo
b
FIGURE 13-18: STRUCTURE 2
Bulletin 1724E-200
Page 13-21
13.5.8 Equations for Structure 3 (Figure 13-19):
(LF )(F )( y1 )(z )(d t + d b ) ⎞ (LF )( pt )(z )
⎛
HS E = ⎜ (φ ) M E −
⎟/
2
2
⎝
⎠
Eq. 13-20
HSD, HSA = same as structure #2.
For crossbrace, uplift and bearing: same as structure #2
y
y
1
z
B
E
y
1
Pt
B
E
y
z1
B
F
B
F
zo
E
E
h2 h1 h
x1
xo
b
A
D
D
C
C
x1
C
C
a
h2 h1 h
D
D
Pt
xo
A
b
A
FIGURE 13-19: STRUCTURE 3
A
FIGURE 13-20: STRUCTURE 4
13.5.9 Equations for Structure 4 (Figure 13-20):
(LF )(F )( y − z o )(d t + d f )(z1 ) ⎞ (LF )( pt )(z1 )
⎛
⎟⎟ /
HS B = ⎜⎜ (φ ) M B −
2
2
⎠
⎝
Eq. 13-21a
(LF )(F )( y − z o )(d t + d f )(z o ) ⎞ (LF )( pt )(z o )
⎛
⎟⎟ /
HS E = ⎜⎜ (φ ) M E −
2
2
⎝
⎠
Eq. 13-21b
HSD, HSA = same as structure #2.
For uplift and bearing: same as structure #2.
For crossbrace:
HS x = ((φ )28,300(b ) − U + V ) /[(LF )( pt )(h2 − a )]
where:
2
U = 2(LF )(F )(h − x o ) (2d t + d c ) / 6
V = 2(LF )(F )( y − z o ) (2d t + d f ) / 6
2
Eq. 13-21c
Eq. 13-21d
Eq. 13-21e
Bulletin 1724E-200
Page 13-22
13.5.10 Equations for Structure 5 (Figure 13-21):
For crossbrace:
(
)
HS x = (φ )56,500(b ) − 2(LF )(F )(h − xo ) (2d t + d c ) / 6 /[(LF )( pt )(h2 )]
2
yo
Pt
Eq. 13-22
a
z1
Pt
z0
h2 h1 h
h2 h1 h
x1
x1
xo
x
0
b
FIGURE 13-21: STRUCTURE 5
b
FIGURE 13-22: STRUCTURE 6
13.5.11 Equations for Structure 6 (Figure 13-22):
For crossbrace:
HS x = ((φ )56,500(b ) − U + V ) /[(LF )( pt )(h2 − a )]
where:
U, V = same as structure #4
Eq. 13-23
Bulletin 1724E-200
Page 13-23
13.6 Example of an H-frame Analysis: For the 161 kV structure shown in Figure 13-23,
determine the horizontal span based on structure strength and uplift and plot the horizontal
versus vertical span for the pole top assembly.
.75"
d t = 7.96"
B
3.52'
7.5'
db= 8.81"
df = 9.19"
5.56'
2.19'
7.0'
F
E
3.98'
70'
15.5'
de = 9.65"
D
15.3'
dd = 11.33"
dc = 13.00"
Pt
C
39.25'
23.95'
15.5'
A
da = 15.64"
FIGURE 13-23: EXAMPLE OF AN H-FRAME
13.6.1 Given:
NESC heavy loading
High winds 19 psf on the wires and
22 psf on the structure
Heavy ice 1" radial ice
Extreme ice with
1” radial ice with 4 psf wind
concurrent wind
Pole:
Conductor:
OHGW:
Ruling Span:
Douglas fir 80-2
ACSR 795 kcmil 26/7
7/16 E.H.S.
800 ft.
Conductor Loads
Transverse Loads
Vertical Loads
Tension
Heavy Ldg District
0.7027 lbs./ft.
2.0938 lbs./ft.
10,400 lbs.
High Wind
1.7543 lbs./ft.
1.0940 lbs./ft.
---
Heavy Ice
0
3.7154 lbs./ft.
14,000 lbs
EI&W
1.0360
3.7154
OHGW Loads
Transverse Loads
Vertical Loads
Tension
Heavy Ldg District
0.4783 lbs./ft.
0.9803 lbs./ft.
5,900 lbs.
High Wind
0.6888 lbs./ft.
0.3990 lbs./ft.
---
Heavy Ice
0
2.1835 lbs./ft.
7,500 lbs.
EI&W
.8116
2.1835
Soil: Average. Presumptive skin friction (ultimate) of 250 psf for predominantly dry soil areas
and using native backfill; 500 psf when aggregate backfill is used.
Bulletin 1724E-200
Page 13-24
13.6.2 Solution for Heavy Loading District Loads: Maximum horizontal span based on structure
strength:
a. Equivalent load pt :
pt = 2 pg + 3 pc
= 2(0.4783) + 3(0.7027)
= 3.065 lbs / ft.
b. Determine location of equivalent load pt :
Distance from top =
2 pg (0.75) + 3 pc (7.75)
pt
= 5.56 ft.
c. Determine location of xo, x1, z0 and z1 for the X - brace location shown.
All diameters, d n , determined by Appendix F, and ratio xo /x1 or zo /z determined by Appendix H.
For xo , x1 :
d d 11.33
=
= 0.72
d a 15.64
xo
= 0.61
x
xo = 0.61(39.25)
∴
xo = 23.9 ft.
x1 = 15.3 ft.
and d c = 13.0 in.
For zo , z1 :
d d 8.81
=
= .91
d e 9.65
zo
= 0.53
z
zo = 0.53(7.5)
∴
zo = 3.98 ft.
z1 = 3.52 ft.
and d f = 9.19 in.
Bulletin 1724E-200
Page 13-25
d. Find the horizontal span limited by pole strength at B (see Figure 13 - 23) using Equation 13 - 21a :
(LF )(F )( y − z o )(d t + d f )(z1 ) (LF )( pt )(z1 )
HS B = (φ ) M B −
/
2
2
a. M B = 44,700 ft − lbs.
2.5(4 )(15.25 − 3.98)(0.663 + 0.766 )(3.52 ) ⎞ ⎛ 2.5(3.065)(3.52 ) ⎞
⎛
b. HS B = ⎜ (0.65)44,700 −
⎟ /⎜
⎟
2
2
⎝
⎠ ⎝
⎠
= 2,133 ft.
e. Horizontal span limited by pole strength at E :
(LF )(F )( y − z o )(d t + d f )(z o ) (LF )( pt )(z o )
HS E = (φ ) M E −
/
2
2
a. M E = M cap − M bh
M E = 58,800 − 8,400 ft. − lbs.
M E = 50,400 ft. − lbs
( M bh from Appendix F)
⎛
2.5(4 )(15.25 − 3.98)(0.663 + 0.766 )(3.98) ⎞ ⎛ 2.5(3.065)(3.98) ⎞
⎟⎟
b. HS E = ⎜⎜ (0.65)(50,400) −
⎟ /⎜
2
2
⎠ ⎝
⎝
⎠
= 2,127 ft.
f. For horizontal span limited by pole strength at locations D and A,
similar calculations can be made. The results are as follows :
HS D = 811 ft.
HS A = 1664 ft.
g. For horizontal span limited by strength of the crossbrace :
HS X = ((φ )28,300(b ) − U + V ) /[(OLF )( pt )(h2 − a )]
where :
U = 2(LF )(F )(h − xo ) (2d t + d c ) / 6
2
V = 2(LF )(F )( y − z o ) (2d t + d f ) / 6
2
U = 2(2.5)(4 )(70 − 23.9 ) (2(0.663) + 1.083) / 6
= 17,065 ft − lbs.
2
V = 2(2.5)(4 )(15.25 − 3.98) (2(0.663) + .766 ) / 6
= 885 ft − lbs.
HS X = [(0.65)28,300(15.5) − 17,065 + 885] /[(2.5)(3.065)(34.78)]
2
= 1009 ft.
Bulletin 1724E-200
Page 13-26
13.6.3 Solution for Heavy Loading District Loads - Maximum span limited by pole top
assembly follows:
a. From Equation 13 - 15.
( LF )Wt (VS )
≤ (φ )20,000.lbs
sin α
10,000 sin 39° − 1.5(135)
VS =
2.0938(1.5)
= 1938 ft.
b. From Equation 13 - 13 :
( LF )Wc (VS ) ( LF ) pt (a )(HS )
+
≤ (φ )20,000 lbs.
2 sin α
b sin α
1.5(2.0938)(VS ) 2.5(3.065)(2.19 + 3.52 )(HS )
+
≤ (0.50)20,000 lbs.
2sin39°
15.5sin39°
2.49VS + 4.48HS ≤ 10,000 lbs.
(For VS equal to the HS, the vertical span is 1,435 ft.)
13.6.4 Solution for Heavy Loading District Loads - Maximum span limited by uplift follows:
Assume dry native backfill, safety factor of 4.
HS ( pt )(h2 ) − VS (wg )(b ) − 1.5VS (wc )(b ) = W1 (b ) + W p (b ) + X − Y
where :
W1 = Fs (D )(d avg )π / SF
= 2649 lbs.
Wp = Wt. of one pole and half the weight of pole top assembly and crossbrace.
= 4200 + 800 / 2 = 4600 lbs.
X = F (h − xo )(d t + d c )( x o )
= 7705 ft − lbs.
( )
Y = 2(F ) h 2 (2d t + d a ) / 6
= 17,182 ft − lbs.
The equation is as follows :
124.13HS − 63.88VS = 102,900
(For VS = 0, maximum HS = 830 ft.)
Bulletin 1724E-200
Page 13-27
13.6.5 Check for extreme ice and concurrent wind: Span limitations based on pole strength and
crossbrace strength is controlled by NESC Heavy Loading conditions. The unit conductor loads when
load factors and strength factors accounted for, are greater for the Heavy Loading District load than for
the EI&W as shown below:
NESC
> EI&W
Transverse load:
7027(2.5)/.65 > 1.0360/.65 lbs/ft
2.7027 > 1.5938 lbs/ft.
Vertical load:
NESC
> EI&W
2.0938(1.5)/.65 > 3.7154 lbs/ft
4.8318 > 3.7154 lbs/ft
13.6.6 Check for Extreme Wind Conditions: Although span limitations based on pole strength and
crossbrace strength is controlled by NESC Heavy Loading conditions, span limitations based on uplift is
controlled by the extreme wind condition.
For Dry Native Backfill: For an assumed safety factor of 1.5, the following equation result:
222.2HS - 25.4VS = 142,862
(For VS=0, maximum HS=640 ft.)
For Aggregate Backfill: For an assumed safety factor of 1.5, the following equation results:
222.2HS - 25.4VS = 252,400
(For VS=0, maximum HS=1,135 ft.)
When considering uplift, it may be prudent to base calculations on the minimum vertical span as
limited by insulator swing.
13.6.7 Summary of Span Limitations:
Horizontal Span limits:
HSA = 1664 ft.
HSD = 811 ft.
HSE = 2127 ft.
HSB = 2133 ft.
HSx = 1009 ft.
Dry native backfill:
For a VS = 0, the HS (limited by uplift) = 640 ft.
Aggregate backfill:
For a VS = 0, the HS (limited by uplift) = 1,135 ft.
Vertical Span limited by Heavy District Loads:
VSpoletop = 1,435 ft., max. (For VS =HS)
A more efficient design could be achieved by moving the crossbrace.
Bulletin 1724E-200
Page 13-28
Blank Page
Bulletin 1724E-200
Page 14-1
14. GUYED STRUCTURES
14.1 Introduction: When a pole structure is guyed, loading on the poles is due to the combined
action of vertical and horizontal forces. Vertical forces on the pole include the vertical
component of the tension on the guy(s) and the weight of the conductors and insulators.
Horizontal forces include transverse due to wire tension at angle structures, horizontal wind
forces, and vertical and longitudinal forces from deadending.
Bisector guys are used on small angle structures, whereas head and back guys are used on large
angle structures and double deadends. Angles between 10 and 45 degrees may be turned on
what is called a “running” angle structure, utilizing bisector guys. Above 45 degrees, unequal
stresses will be set up in the conductor where it attaches to the suspension insulator clamp. The
sharper the angle or bend in the conductor at the clamp, the more unequal the stresses will be.
Any unbalanced longitudinal wire tensions loads on double deadend and large angle structures
can be more effectively carried by head and back guys. For large angle structures, the transverse
load due to wire tension loads will be a heavy and permanent. Therefore, head and back guys
will be more effective in carrying this load.
Figure 14-1 shows a deadend structure in which the conductors are connected to the structure by
strain insulators.
FIGURE 14-1: DEADEND STRUCTURE
(Head and back guys shown)
Deadend structures include:
•
•
Ordinary deadend structures that need only be designed to withstand the load resulting
from the difference in tensions of the conductor for the forward and back spans. This
condition occurs where there is a change in ruling spans.
Full deadend structures in which guys and anchors are designed to withstand the resultant
load when the conductors are assumed to be broken or slack on one side of the structure.
As mentioned in Chapter 10, it is suggested that full deadend structures be located at
intervals of five to ten miles to prevent progressive cascading-type failures.
In general for wood structures, guys and anchors should be installed at deadends, angles, long
spans where pole strength is exceeded, and at points of excess unbalanced conductor tension.
The holding power and condition of the soil (whether wet or dry, packed or loose, disturbed or
undisturbed, etc.) and the ability of the pole to resist buckling and deflection should be
considered. Unguyed steel and concrete pole structures are sometimes used at angles and
deadends to avoid the use of guys. In these cases, careful consideration needs to be made of the
structure and foundation design and deflection.
Bulletin 1724E-200
Page 14-2
14.2 Load Factors: In Chapter 11, Tables 11-6 and 11-7 give recommended minimum load
factors (LF) associated with the design guys and anchors. Table 14-1 summarizes the
application of the load factors and strength factors for guys and anchors.
TABLE 14-1
APPLICATION OF LOAD AND STRENGTH FACTORS FOR GUYED STRUCTURES
(GUYS AND ANCHORS)
Loading Districts:
NESC
(2.50)(a+b)
+ 1.65c
= G cosβ ≤ (0.9)Gu cosβ
Recommended
(2.50)(a+b)
+ 1.65c
= G cosβ ≤ ( φ )Gu cosβ
(See table 11-6 of
this bulletin for φ )
Extreme Winds and Extreme Ice with Concurrent Winds:
NESC
(1.00)(a+b)
+ 1.00c
= G cosβ ≤ (0.9)Gu cosβ
Recommended
(1.10)(a+b)
+ 1.100c
= G cosβ ≤ ( φ )Gu cosβ
Where:
a
b
c
Au
G
Gu
φ
cosβ
=
=
=
=
=
=
=
=
(See table 11-7 of
this bulletin for φ )
Transverse wind load on the conductor
Transverse wind load on the pole
Transverse component of wire tension load.
Rated anchor capacity
The calculated force in the guy, considering guy lead. The rated breaking
strength of the guy wire (Gu) and the anchor capacity (Au) multiplied by
their respective strength factor must equal or exceed this value.
Rated breaking strength of the guy wire
Strength factor; see table 11-7 of this bulletin
Guy slope with horizontal groundline
14.2.1 Longitudinal Strength: Longitudinal strength is applicable to crossings and locations
where unequal spans and unequal vertical loadings may occur. Required longitudinal strength of
wood tangent structures at crossings is defined by NESC Rule 261A2. The rule states that wood
tangent structures which meet transverse strength requirements without guys, shall be considered
as having the required longitudinal strength, provided that the longitudinal strength of the
structure is comparable to the transverse strength of the structure. If there is an angle in the line,
the wood structure will have the required longitudinal strength provided:
•
•
•
The angle is not over 20 degrees,
The angle structure is guyed in the plane of the resultant conductor tensions, and
The angle structure has sufficient strength to withstand, without guys, the transverse
loading which would exist if there were no angle at that structure (with the appropriate
load factors and strength factors applied).
14.2.2 Distribution Underbuild: Guying and anchors for distribution underbuild are to comply
with NESC Grade B provisions. Refer to Chapter 16 for additional information concerning
underbuild.
14.3 Clearances: Recommended clearances to be maintained between any phase conductor and
guy wires are indicated in Table 14-2. Refer to Chapter 7 for further details.
Bulletin 1724E-200
Page 14-3
TABLE 14-2
RECOMMENDED MINIMUM CLEARANCES IN INCHES
FROM CONDUCTOR TO SURFACE OF STRUCTURE OR TO GUY WIRES (Note A)
Nominal Voltage, Phase to Phase,kV
Standard Number of 5-3/4”x10”
Insulators on Tangent Structures
Max. Operating Voltage, Phase to
Phase, kV
Max. Operating Voltage, Phase to
Ground, kV
34.5
46
69
115
138
161
230
3
3
4
7
8
10
12
34.5
46
72.5
120.8
144.9
169.1
241.5
19.9
26.6
41.8
69.7
83.7
97.6
139.4
Wind Condition
NO WIND CLEARANCE
Min. clearance to guy at no wind
(Notes A, B)
Clearance, in.
19
19
25
42
48
60
71
9
11
16
26
30
35
50
MODERATE WIND CLEARANCE
(based on NESC Rule 235E, Table
235-6)
Min. clear. to structure at 6 psf of
wind (Notes C, D)
Min. clear. to jointly used structures
and a 6 psf of wind (Notes C,
D)
Min. clearance to anchor guys at
6 psf (Notes C, D)
11
13
18
28
32
37
52
13
16
22
34
40
46
64
HIGH WIND CLEARANCE
Min. clearance to guys at high wind
3
3
5
10
12
14
20
Notes:
(A) If insulators in excess of the standard number for tangent structures are used, the no-wind
clearance value given should be increased by 6 in. for each additional bell. For instance, extra
insulation in the form of additional insulator bells may be used on steel structures where
grounding is a problem or the structures are located in high isokeraunic areas. In these
instances, the no wind clearances should be increased. If excess insulators are needed for
contamination purposes only, the additional clearance is not necessary
(B) For post insulators, the no-wind clearance to structure or guy is the length of the post
insulator.
(C) A higher wind may be assumed if deemed necessary.
(D) The following values should be added as appropriate where the altitude exceeds 3300 feet
Additional inches of clearance per 1000 feet of altitude above 3300 feet:
Nominal Voltage, KV
Clearance to structure
Clearance to guy
34.5
0
0
46
0
0
69
0.14
017
115
0.43
0.53
138
0.57
0.72
161
0.72
0.90
230
1.15
1.44
Bulletin 1724E-200
Page 14-4
14.4 Design
14.4.1 Bisector Guys: For structures utilizing bisector guys, the guys have to be designed to
sustain the resultant transverse load due to longitudinal wire tension loads in Table 14-1:
c =2 (T) (Sin θ/2)
where:
T = maximum design tension, lbs.
θ = line angle
The transverse load (a) due to wind on the conductors for an angle structure is given as:
a = (p) (HS) (cos θ/2)
where:
p = wind load in lbs./ft.
HS = horizontal span, ft.
θ = line angle; cos θ/2 is usually set equal to one
Wind on the structure may be converted to a horizontal force (b) at the point of guy attachment.
14.4.2 Head and Back Guys: Wood pole deadends, double deadends, and large angle
structures will normally require head and back guys. For tangent deadends and double deadends,
the transverse strength of the structure must be sufficient to carry the appropriate wind load. In
some cases, bisector guys or crossbraces may have to be used to meet transverse strength
requirements. The tension in the guy should take into account the slope of the guy.
14.5 Pole Strength: Once the tension in the guy wire has been calculated, the compressive
strength of the pole should be calculated and checked to see if the pole selected will be adequate
for the intended use.
14.5.1 Stability Concept: The selection of structural members is based on three characteristics:
strength, stiffness, and stability. When considering a guyed wood, steel or concrete pole, it is
important that the designer check the stability of the structure for the expected loadings.
For an example of stability, consider the axial load carrying capabilities of the rods in
Figure 14-2. The rod on the left is unquestionably “more stable” to axial loads than the rod on
the right. Consideration of material strength alone is not sufficient to predict the behavior of a
long slender member. As an example, the rod on the right might be able to sustain 1000 lbs axial
load when considering strength (ultimate compressive stress times area), but could only sustain
750 lbs. when considering stability of the system. The rod on the right is more likely to become
laterally unstable through sidewise buckling.
FIGURE 14-2: COMPARISON OF RODS TO SHOW
STABILITY CONCEPT
a
b
Bulletin 1724E-200
Page 14-5
14.5.2 Critical Column Loads: In transmission structures, the guyed pole acts as a column,
sustaining axial loads induced in the pole from vertical guy components. The taller the pole, the
less load the guyed pole can sustain in compression before the structure becomes “unstable”.
Stability of a column can be thought of in one of two ways:
a. The column is unstable when the axial force would cause large lateral defections even
when the lateral load was very small.
b. When a column subjected to an axial force, a small deflection may be produced. The
column is considered stable if the deflection disappears when the lateral force is removed,
and the bar returns to its straight form. If the axial force (P) is gradually increased, a
condition is reached in which the straight form of equilibrium becomes unstable and a
small lateral force will produce a deflection which does not disappear when the lateral
force is removed. The “critical” load is then the axial force which causes buckling or
collapses due to any bowing or lateral disturbance.
14.5.3 Calculation of Buckling Loads: For long slender columns, the critical buckling load is
determined by the general equation:
π EI
2
Pcr =
where:
Pcr
E
I
kl
(kl) 2
=
=
=
=
(Pcr is independent of the yield
stress of the material).
critical buckling load, lbs. or kips
modulus of elasticity, psi
moment of inertia, in4
the effective unbraced length of the column; kl
depends on restraint end conditions of the
column.
Where for the various end conditions of the column, Pcr is idealized in Figure 14-3 below:
P
P
P
a
b
c
FIGURE 14-3: EFFECTIVE UNBRACED LENGTH FOR VARIOUS END CONDITIONS
Bulletin 1724E-200
Page 14-6
Assumptions made in the above calculations:
•
•
•
•
•
The column is perfectly straight initially.
The axial load is concentrically applied at the end of the column.
The column is assumed to be perfectly elastic.
Stresses do not exceed the proportional limit.
The column is uniform in section properties.
14.5.4 Buckling of Guyed Steel and Concrete Poles: For guyed steel and concrete poles, all
the assumptions in paragraph 14.5.3 are violated. As such, the engineer will often ask the pole
manufacturer to check the axial capacity of the pole. The engineer must give the pole
manufacturer information concerning guy size and strength, yield stress, guy locations, and guy
leads. In the case of steel poles, the pole manufacturer should also check the capacity of the guy
attachments. It is recommended that in the case of concrete poles, the pole manufacturer should
design the guy attachment or at least check the capacity of the pole and attachment when the
owner has selected the hardware.
14.5.5 Buckling of Guyed Wood Poles: For a guyed wood poles, all the assumptions in
paragraph 14.5.3 are also violated. As such, the engineer must apply appropriate safety factors
to account for realistic cases and the variability of wood. Equations for buckling of a wood
column with no taper follow:
Fixed – Free End
Figure 14-3a
Conditions
For a column with no
taper
P cr =
π 2 EI
4l
2
Fixed – Pinned End
Figure 14-3b
Pcr =
2π 2 EI
l2
Pinned – Pinned End
Figure 14-3c
Pcr =
π 2 EI
l2
One method of calculating the buckling capacity of a tapered wood column was developed by
Gere and Carter. This method modifies the critical buckling load as follows:
Pcr = PA P ∗
⎛d
P = ⎜⎜ g
⎝ da
where:
PA
∗
α
⎞
⎟⎟
⎠
E
IA
dg
= Critical load for a uniform column with circular cross
sections having diameter d (at guy attachment), lbs.
= A multiplier dependent on the end conditions of the
column, lbs.
= Modulus of Elasticity, psi
= Moment of Inertia at the guy attachment, in4
= Diameter at the groundline, in.
da
= Diameter at the point of guy attachment, in.
P∗
= Distance from the groundline to the point of guy
attachment, in.
α = An exponent that is a function of shape of the column
l
For tapered round columns, the equations become:
Bulletin 1724E-200
Page 14-7
Conditions
Fixed – Free End
For a tapered column
(circular cross section)
π EI A ⎛ d g
⎜
Pcr =
4 l 2 ⎜⎝ d a
2
⎞
⎟⎟
⎠
2.7
Fixed – Pinned End
2π EI A ⎛ d g
⎜⎜
Pcr =
l2
⎝ da
2
⎞
⎟⎟
⎠
2.0
Pinned – Pinned End
π EI A ⎛ d g
⎜
Pcr =
l 2 ⎜⎝ d a
2
⎞
⎟⎟
⎠
2.0
When using the Gere and Carter method for the NESC district loads with load factors, strength
factors between 0.65 to 0.5 respectively are recommended. The resulting safety factor will be
between 2.5 and 3.0. For extreme wind loads, it is recommended that strength factors between
0.65 and 0.5 be used, resulting in a safety factor between 1.5 and 2.0. For deadends, lower
strength factors (or higher safety factor) should be used.
14.5.6 General Application Notes: For unbraced guyed single poles at small and medium
angles structures using bisector guys, certain assumptions are made as to the end constraints. In
the direction of the bisector guy, the structure appears to be pinned at the point of the guy
attachment and fixed at the base. However, 90° to the bisector guy, the structure appears to be a
cantilevered column. Since the conductors and phase wires offer some constraint, the actual end
conditions may be assumed to be between fixed-free and fixed-pinned (Figure 14-4a). When
checking buckling, it is suggested that the end conditions of pinned-pinned be assumed.
Buckling Mode
Longitudinally
Transversely
End Conditions
Bisector Guyed
In-Line Guyed
pinned-pinned
pinned-fixed
pinned-fixed
pinned-fixed
Bisector Guyed Structure
FIGURE 14-4a
In-line Guyed Structure
FIGURE 14-4b
FIGURE 14-4: END CONDITIONS FOR BISECTOR AND IN-LINE GUYED STRUCTURES
For in-line guyed poles at medium angles and large angle deadends, the structure appears to be
pinned at the point of guyed attachment and fixed at the base in both directions (Figure 14-4b).
For in-line guyed poles at tangent deadends without side guys, it is suggested that fixed-free be
assumed.
In many instances, axial loads are applied intermittently along the pole. In Figure 14-5a, the
static wire and phase wire are guyed at their respective locations. The axial loads acting on the
pole on the left are applied as shown in Figure 14-5b.
Bulletin 1724E-200
Page 14-8
In such instances, the usual engineering practice is to assume an unbraced length from the
groundline to the lowest guy attachment and the induced axial load in the pole equal to the sum
of all axial loads included by the vertical component of the guys.
a
b
FIGURE 14-5: AXIAL LOADS INDUCED IN A POLE
When the structure is considered to be a double deadend or large angle, the poles, guys, and
anchors must sustain the full deadend load with an appropriate load factor. For the tangent
double deadend shown in Figure 14-6, the poles must sustain the maximum axial load which
might occur if all phase conductors on one side of the structure were removed (see Figure 14-6a
and 14-6b). However, to “double account” the loads, as shown in Figure 14-6c would be too
conservative.
a
b
c
FIGURE 14-6: REPRESENTATION OF AXIAL LOADS (a & b)
AND DOUBLE ACCOUNTING LOADS (c)
For wood pole lines, deadends and large angle structures will often require a higher class pole
than that used as the base class pole for the line. Ways to control or reduce the pole class needed
at deadends and large angles include:
•
Relocate and/or increase the height of tangent structures adjacent to guyed angle and
deadends. This would allow the use of shorter poles with guyed structures, and as a
result would allow use a lower class pole with no sacrifice in safety.
•
Decrease the guy slope. This will decrease the vertical load component pole.
Bulletin 1724E-200
Page 14-9
As a note, angle and deadend structures usually comprise about 5 percent of the total structures
of a line. Use of conservative safety factors for these critical structures results in a greater
overload margin without significantly affecting the total cost of the transmission line.
The engineer should consider guying single pole structures used for small angles, even if the
pole has adequate strength to carry the load. Wood poles have a tendency to “creep” with time
when subjected to a sustained load. For steel or concrete poles, the engineer should also
consider the use of guyed poles at angles or deadend structures. Use of guys will prevent
unguyed steel and concrete poles from having large diameters at the groundline and will reduce
the cost of foundations.
14.6 Anchors: The holding power of the anchor will largely depend on whether the soil is wet
or dry, packed or loose, disturbed or undisturbed. Since soils vary considerably between
locations, the holding power of an anchor will also vary considerably.
In areas with a fluctuating water table, the capacity of the anchors should take into account the
submerged unit weight of the soil. If at any time the holding power of an anchor is questionable
due to variable soil conditions, the anchor should be tested. The primary types of anchors
include log anchors, plate anchors, power screw anchors, and rock anchors. The selection of the
appropriate anchor will largely depend on the type of soil condition.
14.6.1 Log Anchor Assemblies: The two log anchors in the construction drawings (agency
Bulletins 1728F-810 and 811, units TA-2L and 4L) are 8″ x 5′ - 0″ and 8″ x 8′ - 0″, and have an
ultimate holding power of 16,000 lbs. and 32,000 lbs. These logs, using one or two anchor rods
may be used in combination to provide sufficient holding power for guys. “Average” soil is
considered to be medium dense, coarse sand and stiff to very stiff silts and clays. Log anchors
should be derated or should not be used in soils of soft clay, organic material, saturated material,
or loose sand or silt.
14.6.2 Plate Anchors: The plate anchor assembly TA-3P in Bulletins 1728F-810 and 811, is
rated at an ultimate holding power of 16,000 lbs and 24,000 lbs. In firm soils, where the
engineer would like to minimize digging, plate anchors may prove economical.
14.6.3 Power Screw Anchors: Screw anchors are being used more often because of their easy
installation. They are most appropriate for locations where firm soils are at large depths. The
screw anchor assembles TA-2H to TA-4H of Bulletins 1728F-810 and 811 should be installed
per manufacturer’s recommendations. In addition to the anchor unit being shown on the plan
and profile, the capacity of the screw anchor should also be shown. Screw anchors have a higher
safety factor than other types of anchors. This higher safety factor is reflected in Information
Bulletin 202-1, “List of Materials Acceptable for Use on Systems of USDA Rural Development
Electrification,” by a reduced designated ultimate holding capacity (70 percent of the
manufacturer’s suggested holding capacity).
14.7 Drawings: A summary drawing should be prepared for each line, showing the
arrangement of guys for each type of structure to be used. The drawing will greatly facilitate the
review of the plan and profile, and simplify the construction of the line.
Guys required for various line angles are based on certain spans. Since actual spans will vary,
the guying requirements shown will not be suitable for all conditions. Sometimes, it is desirable
to make a guying guide for each angle structure which relates horizontal span to the angle of the
line (see the example, paragraph 14.8).
Bulletin 1724E-200
Page 14-10
The Guying Guide drawing also shows (1) points of attachment of the guy to the pole, (2) slope
of the guys, (3) type of structure, and (4) guys and anchors required.
14.8 Example: Develop guying guides for TH-12 161 kV structure.
14.8.1 Design Parameters
General Loading and Structure Information:
NESC Heavy Loading
Extreme Wind:
Heavy Ice:
Extreme Ice with
Concurrent winds
19 psf on wires,
1” radial
1” radial
Pole:
Conductor:
Overhead ground wire:
Ruling Span:
Guy Wire:
Douglas fir 80-2
795 kcmil 26/7 ACSR
7/16” E.H.S.
800 ft.
7/16” E.H.S.
22 psf on the structure
4 psf
Conductor Loads, lbs/ft:
Transverse
Vertical
Conductor
tensions
Heavy
0.7027
2.0938
10,400 lbs.
High Wind
1.7543
1.0940
NA
Heavy Ice
High Wind
0.6888
0.3990
NA
Heavy Ice
0
3.7154
12940 lbs.
EI&W
1.0360
3.7154
13240 lbs.
Overhead Ground Wire loads, lbs/ft:
Transverse
Vertical
OHGW
tensions
Heavy
0.4783
0.9804
5,900 lbs.
0
2.1835
7,500 lbs.
EI&W
.8116
2.1835
7800 lbs.
Guy wire: 7/16” E.H.S.
Ultimate tension (R.B.S.):
Horizontal strength with 1/1 lead:
20,800 lbs.
14,700 lbs.
Anchors: 8,000 lbs. and 16,000 lbs.
Ultimate Capacity:
Horizontal strength with 1/1 lead:
16,000 lbs. and 32,000 lbs.
11,300 lbs. and 22,600 lbs.
Soil: Average, presumptive ultimate bearing capacity approximately equal to 4000 psf.
Bulletin 1724E-200
Page 14-11
14.8.2 Solution for Heavy Loading District:
a. Wind on the wires:
Conductor:
a = .7027 (HS) (cos θ/2)
OHGW:
a = .4783 (HS) (cos θ/2)
b. Wind on the pole:
b = 143 lbs.
Here (b) is based on an 80-2 pole with the guy located 60 ft. from the ground. The
equivalent horizontal load (b), at this location is determined by Mwp/lever arm.
b = 8590 ft.-lbs./60 ft.
c. Wire tension loads:
Conductor:
OHGW:
c = 2(10,400) sin θ/2
c = 2(5,900) sin θ/2
d. Equations from Table 14-1 of this bulletin:
General Equation:
2.50(a+b) +1.65c = Gcosβ ≤ .65Gucosβ or
2.50(a+b) +1.65c = Gcosβ ≤ .65Aucosβ
For one conductor:
2.50 [(.7027) (HS) (cos θ/2) + (143)] + 1.65 [2(10,400) (sin θ/2)] ≤ .65Gu (or Au) cosβ
358 + (1.757) (HS) (cos θ/2) + 34,320 (sin θ/2) ≤ .65Gu cosβ or ≤ .65Aucosβ
550 + (2.703) (HS) (cos θ/2) + 52,800 (sin θ/2) ≤ Gu cosβ or ≤ Aucosβ
For one OHGW:
2.50 [(.4783) (HS) (cos θ/2) + (neg.)] + 1.65 [2(5,900) (sin θ/2)] ≤ .65Gu (or Au) cosβ
(1.196) (HS) (cos θ/2) +(19,470) (sin θ/2) ≤ .65Gu cosβ or ≤ .65Aucosβ
(1.840) (HS) (cos θ/2) +(29,954) (sin θ/2) ≤ Gu cosβ or ≤ Aucosβ
Case 1: Using 1 guy wire and 1 anchor for the three conductors and 1 guy wire and 1 anchor for
both OHGW, the following general equations result (1/1 leads).
For the 3 conductors:
3(550) + 3(2.703)(HS)(cos θ/2) + 3(52800)(sin θ/2) ≤ Gu cosβ or ≤ Aucosβ
1650 + 8.109 (HS)(cos θ/2) + (158,400)(sin θ/2) ≤ 14,700 lbs.(for guy)
1650 + 8.109 (HS)(cos θ/2) + (158,400)(sin θ/2) ≤ 11,300 lbs. (for anchor)
For the 2 OHGW’s:
2(1.840)(HS)(cos θ/2) + 2(29,954)(sin θ/2) ≤ Gu cosβ or ≤ Aucosβ
3.680(HS)(cos θ/2) + (59,908)(sin θ/2) ≤14,700 lbs. (for guy)
3.680(HS)(cos θ/2) + (59,908)(sin θ/2) ≤11,300 lbs. (for anchor)
Case 2: Using 2 guy wires and 2 anchors for the three conductors and 1 guy wire and 1 anchor
for both OHGW, the following general equations result (1/1 leads).
For the 3 conductors:
1650 + (8.109)(HS)(cos θ/2) + (158,400)(sin θ/2) ≤ (2)14,700 lbs. (for guy)
Bulletin 1724E-200
Page 14-12
1650 + (8.109)(HS)(cos θ/2) + (158,400)(sin θ/2) ≤ (2)11,300 lbs. (for anchor)
For the OHGW: (same as above)
See the Guying Guide at the end of this example for plots of controlling equations.
e. Checking for buckling of the poles. Since the outside poles carry the maximum axial load, it
is necessary only to examine this pole. Longitudinal buckling is considered since this condition
is the critical case. Weight of the conductor and OHGW is included in the calculations.
The following example calculations are for Case 1 above.
The maximum axial load which various poles can sustain can be calculated for various heights of
structures. The Gere and Carter method is used to calculate Pcr below:
Pole
Class &
Height
60-1
60-2
60-3
80-1
80-2
80-3
Unbraced Length, ℓ
Ground to Lowest
Guy Attachment,
ft.
42
60
dg
da
in.
in.
15.03
14.09
13.15
16.72
15.64
14.55
9.83
9.14
8.44
9.76
9.05
8.35
IA
At Point da
(πd4/64)
in4
458
343
249
445
329
239
π EI A ⎛ d g
⎜
Pcr =
l 2 ⎜⎝ d a
2
⎞
⎟⎟
⎠
2.0
pinned-pinned assumed
lbs.
79935
60733
45108
47784
35948
26485
Assuming that horizontal spans are equal to the vertical span, the previous equations in item d
above be revised to include the weight of the conductor and OHGW on the outside pole. The
total axial load in the pole is the sum of the axial loads induced in the pole from guying the three
conductors and two OHGW, and the vertical weight of the OHGW and conductor. Half of the
vertical load from the outside phase is carried by the middle pole and other half is carried by the
outside pole. For this example, since the guy leads are 1 to 1, the vertical axial load from the
guy wire will be equal to the horizontal component of the guy wire.
Cond.
OHGW
Total
Wire Weight + Induced Axial Load, Guying 3 conductors and 2 OHGW’s
1.5(.5)(2.0938)HS+
8.109(HS)(cos θ/2)
+1652 +158,400(sinθ/2)
1.5(.9804)HS + 3.680(HS)(cos θ/2)
+ 59,908(sinθ/2)
(3.0401)HS + 11.789(HS)(cos θ/2)
+1652 +218,300(sinθ/2)
≤ .65Pcr
Bulletin 1724E-200
Page 14-13
GUYING GUIDE
Structure:
Conductor Type:
OHGW Type:
Guy Wire Type
TH – 12
795 26/7
7/16 ״E. H. S.
7/16 ״E. H. S
Ruling Span
Max. Tension (L, M, H):
Max. Tension (L, M, H):
Ultimate Strength
Heavy Loading District
pC: 0.7027 lbs./ft.
wC: 2.0938 lbs./ft.
800 ft.
10,400 lbs.
5,900 lbs.
20.800 lbs.
pg: 0.4783 lbs/ft.
wg: 0.9804 lbs/ft.
20°
Line Angle
15°
9ft.
1
1
10°
80
-2
D
80
-3
TG-11A
TG-11C
Case 2
F
60
-2
DF
DF
5°
Case 1
60
-3
0
200
400
600
800
1000
1200
1400
80
-1
D
TA-3P
or
2-TA-3P
F
DF
1600
1800
2000
Horizontal Span
Line Angle chart/drawing
Case 1
For OHGW:
For conductor:
TG - 11A, TA - 3P
TG - 11A, TA - 3P
Case 2
For OHGW:
For conductor:
TG – 11A, TA-3P
TG – 11C, (2)TA - 3P
Total guys and anchors:
(2) TG - 11A
(2) TA - 3P
Total guys and anchors:
1 - TG – 11A
1 - TG – 11C
3 - TA – 3P
Limitation:
Limitation:
TA-3P to conductor
TA - 3P to conductor
TA-3P
8 ft.
Bulletin 1724E-200
Page 14-14
Blank Page
Bulletin 1724E-200
Page 15-1
15. HARDWARE
15.1 General: Hardware for transmission lines can be separated into conductor-related
hardware and structure-related hardware.
Conductor-Related Hardware: For many transmission lines, the conductor may constitute the
most expensive single component of investment. Yet, this is the one component which is most
exposed to danger and most easily damaged. In the design of any line, appropriate emphasis
should be given to mechanical and electrical demands on the design of conductor-related
hardware used to support, join, separate, and reinforce the overhead conductor and overhead
groundwire. Conductor motion hardware is used to diminish damage to the overhead conductors
from vibration. Selection and proper installation of conductor accessories will have considerable
influence on the operation and maintenance of a transmission line. Electrical, mechanical, and
material design considerations are generally involved in the design of conductor support
hardware and conductor motion hardware.
Structure Related Hardware: This includes any hardware necessary to frame a structure, to
accommodate guying and other types of pole attachments to the structure and to provide
necessary conductor-to-structure clearances. As structure–related hardware items are the
connecting pieces for structural members, proper selection of this hardware is necessary to
assure structure strength. At the same time, proper selection of structure-related hardware
includes use of designs that are static proof or incorporate static proof aids to help minimize
possible radio and television interference emanations from the line (see Appendix I).
Selection of conductor-related and structure-related hardware should consider corrosion and the
damage and degradation of strength and visual esthetics that corrosion can cause. In addition to
selecting hardware made of materials that are less likely to corrode, the designer should be
certain that the materials selected are compatible with one another and will not corrode when in
contact with each other.
15.2 Conductor-Related Hardware
15.2.1 Suspension Clamps: Contoured suspension clamps are designed to match the conductor
diameter in order to guard against conductor ovaling and excessively high compressive stresses
on the conductor. Suspension clamps may be made from galvanized malleable iron or forged
steel. Aluminum liners are recommended for aluminum conductors. Copper liners are
recommended for copper conductors only. The connector fitting will usually be either a socket
or clevis (see Figure 15-1). When using clamps with liners on conductors covered by armor
rods, designers should select clamps that have the proper seating diameter for the effective
diameter of the conductor and armor rod. Liners can be expected to add 1/10 inch to the
conductor diameter. There are a few clamps made for large line angles (up to 120o). However,
these clamps are available only for small conductor sizes. When a transmission line with large
conductors has to make a turn along its route, strain clamps should be used. In the case of
medium angles (greater than a 30 degree line angle) double suspension clamps connected to a
yoke plate may be needed to make a gradual turn.
FIGURE 15-1: SUSPENSION CLAMP WITH
CLEVIS OR BALL AND SOCKET
TYPE OF CONNECTION
U bolt
Bulletin 1724E-200
Page 15-2
Cushioned suspension clamps are sometimes used to support the conductor and reduce the static
and bending stresses in the conductor. Cushioned suspension clamps are further explained in the
conductor motion hardware section (Section 15.3).
15.2.2 Clamp Top Clamps: Clamp top clamps for vertical and horizontal post insulators are
popular because of they are simple to install. The clamps, made of malleable iron or aluminum
alloy, are mounted on a metal cap. The clamp itself is composed of a removable trunion cap
screw (keeper piece) and a trunion saddle piece (Figure 15-2).
FIGURE 15-2: POST TYPE INSULATOR WITH STRAIGHT LINE
TRUNION CLAMPS
Straight line clamps are designed to hold conductors without damage on tangent and line angles
of up to approximately 15o. The maximum acceptable vertical angle (each side of clamp) is
considered to be approximately 15o with the horizontal. Since the keeper piece of the clamp is
not designed to provide the support for upward loading, this clamp should not be used where
uplift conditions could occur. Angle clamps are available which are designed to take up to a 60o
line angle. However, when line angles are greater than 15o to 20o, suspension insulators should
be used. The designer should coordinate with the trunion clamp manufacturer concerning the
compatibility of the clamp design for longitudinal loads on the line.
15.2.3 Tied Supports: A large portion of lower voltage construction involves tying conductors
to pin and post insulator supports. Hand ties (Figure 15-3) are occasionally vulnerable to
loosening from various forces and motion from differential ice buildup, ice dropping, galloping,
and vibration. Factory formed ties with secure fit, low stress concentration and uniformity of
installation may eliminate mechanical difficulties and radio interference problems associated
with loose tie wires.
FIGURE 15-3: TOP GROOVE HAND TIE
Bulletin 1724E-200
Page 15-3
15.2.4 Deadend Clamps: Deadending a conductor may be accomplished by using formed type
deadends, automatic deadends, bolted deadends or compression type deadends (See
Figures 15-4a and 15-4b). Because of the strength limitations of formed and automatic
deadends, these types are limited to primarily small conductor sizes and distribution line use.
The two basic methods of deadending a transmission conductor are by use of bolted deadend
clamps and by compression type deadend clamps.
Deadend clamps, or strain clamps as they are sometimes called, are made from three basic types
of material as follows:
Aluminum Alloy Type:
General Notes: This type is corrosion resistant. It minimizes power losses, minimizes
hysteresis and eddy currents, minimizes excessive conductor heating in the conductor
clamping area and is lightweight. This clamp is the most widely used.
Application: No armor rods or tape are required. Clamps are to be used with ACSR or all
aluminum conductors. These clamps are not to be used with copper or copperclad
conductors.
Malleable Iron:
General Notes: This clamp is somewhat lightweight. The range of conductor sizes is limited.
Application: Clamps are to have aluminum or copper liners. Clamps with copper liners are
to be used for copper or copper-clad conductors. Clamps with aluminum liners are used for
ACSR and other aluminum composite type conductors
Forged Steel:
General Notes: Forged steel clamps are heavy in weight.
Application: Clamps may be used with all aluminum, copper or ACSR conductors. Clamps
are to have aluminum or copper liners. Clamps with copper liners are to be used for copper or
copper-clad conductors. Clamps with aluminum liners are used for ACSR and other
aluminum composite type conductors.
FIGURE 15-4a: TYPICAL BOLTED DEADEND CLAMP
30°
30°
FIGURE 15-4b: TYPICAL COMPRESSION DEADEND
Bulletin 1724E-200
Page 15-4
The ultimate strength of the body of the bolted clamps should meet or exceed the ultimate
strength of the conductor the clamp is designed to hold. The holding power of a bolt type or
compression type clamp should meet the following criteria:
•
•
Clamps have to be capable of holding at least 90 percent of the strength of the largest
conductor for which the clamp is designed to hold in a short-time load.
Clamps have to hold a sustained load of 75 percent of the strength of the conductor for 3
days.
For bolted type clamps, the amount of torque to tighten the bolts depends on the size of the bolt.
Torque will range from 300 in-lbs. for 3/8” bolts to 400 in.-lbs. for 5/8” bolts. Clamps should
also meet certain corrosion resistance tests and heat cycling tests.
Suspension and deadend clamps for use on high voltage transmission lines are specially designed
to control corona. Designs usually involve providing smooth and rounded surfaces rather than
sharp edges and by placing all the clamp nuts and studs within the protection of the electrical
shield.
Installation of compression splices, deadend clamps, and bolted deadend clamps should follow
the manufacturer’s recommendations.
15.2.5 Splices: Conductor splices may be automatic compression type splices, formed type
splices, or crimp compression type splices. For most transmission conductors, the crimped
compression type splice is used because of its high strength capabilities. Splices should meet the
same strength, corrosion resistance and heat cycling requirements as the deadend clamps.
15.2.6 Strain Yokes: Two or more insulator strings may be connected in parallel by using
yokes to:
•
•
•
Provide the strength needed to sustain heavy loads at deadend structures;
Increase the safety factor for long-span river crossings; and
Make a gradual turn at large angles.
Usually, it is more economical to supply higher strength rated insulators than to use yokes. One
disadvantage to using higher strength rated insulators (36,000 lbs and higher) is that the ball and
socket size changes for porcelain insulators which will require other related hardware to be
coordinated.
15.2.7 Insulators: Mechanical and electrical requirements of insulators are discussed in
Chapter 8. Where suspension insulators are exposed to salt sprays or corrosive industrial
emissions, insulators using enlarged pin shafts or corrosion intercepting sleeves are
recommended to prolong the life of the insulator pins. Use of corroision intercepting sleeves
provide an air space between the pin and the cement. With this design, corrosion can attack the
expandable long-lived sleeve. Any increase in the volume of the rust line only distorts the
sleeve. However, without the sleeve, bursting stresses would be imposed on the adjacent
porcelain. Other types of insulators have enlarged shafts near the cement lines which provide
additional sacrificial metal for corrosion.
On lower voltage lines, pin and post type insulators are mounted on structure crossarms.
The side and top wire grooves generally limit the size of the conductor with armor rods
that can be installed to a maximum of 4/0 and 336.4 kcmil ACSR.
Bulletin 1724E-200
Page 15-5
FIGURE 15-5: SUSPENSION INSULATORS
(Ball and Socket Type, Left, and Clevis-Eye Type, Right)
15.2.8 Fittings: Fittings used to attach the insulator to the structure may include hooks, “Y”
ball/clevis, ball eyes, ball clevises and chain, anchor or vee shackles. The “C” hooks suggested
on agency standard construction drawings are the self locking hooks. With the insulator cap in
place, the opening of the hook is sufficiently restricted so that accidental disconnection cannot
occur. Fittings should meet or exceed the ANSI M&E ratings of the insulators. Various fitting
types are shown in Figure 15-6, 15-7 and 15-8.
FIGURE 15-6: DIFFERENT TYPES OF HOOKS
(Self Locking “C” Hook, Left; Ball Hook, Middle, Clevis Type Hook, Right)
FIGURE 15-7: VARIOUS TYPES OF BALL AND CLEVIS “Y” CONNECTIONS
FIGURE 15-8: ANCHOR SHACKLE (Left); CHAIN SHAKLE (Right)
Bulletin 1724E-200
Page 15-6
15.3 Conductor Motion Hardware
15.3.1 Aeolian Vibration: All conductors are in some state of vibration, varying from
extremely slight to temporarily severe. Selection of the proper hardware to improve conductor
life will depend on the degree of vibration. Suspension clamps do not restrict vibration, but
these clamps should be designed to keep to a minimum the effect of such vibration on the
conductor. Methods to reduce the effects that aeolian vibration has on lines include the
following:
Armor Rods: Armor rods (Figure 15-9) should be used on lines in areas where mild vibrations
may occur. Armor rods, wrenched or preformed, are helical layers of round rods which are
installed over the conductor at the points of attachment to the supporting structures. The primary
purpose of armor rods is to provide additional rigidity to the conductor at its point of support.
The use of armor rods accomplishes:
•
•
•
Alleviating changes of mechanical stress buildup at the point of support by providing a
gentler slope of curvature for the incoming conductor,
Increasing conductor life from fatigue failure by increasing the flexural rigidity of the
conductor, and reducing bending stresses in the conductor,
Protecting the conductor from flashover damage and mechanical wear at the points of
support.
In laboratory tests, the placement of armor rods on the conductor has allowed the conductor
to withstand considerably more vibration cycles without fatigue failure. Tests such as these
show that there is a significant reduction in stress afforded through the use of armor rods.
Armor Rod
FIGURE 15-9: ARMOR RODS USED WITH SUSPENSION INSULATORS
Cushioned Suspension Units: These units use resilient cushioning in conjunction with armor
rods to further reduce the static and dynamic bending stresses in the conductor (See
Figures 15-10a and 15-10b). With this cushioning, the compressive clamping force is decreased,
thereby reducing stress concentration notches. For line angles greater than 30o, single support
units should be replaced with double units. When considering longitudinal loads for a line using
cushioned suspension units, the designer should consider that the units have a slip load of
approximately 20 percent of the rated breaking strength of the conductor. A disadvantage to
cushioned suspension units is that it is very difficult to remove or install these units with hot line
tools.
FIGURE 15-10a:
CUSHIONED SUSPENSION
UNIT
FIGURE 15-10b:
DOUBLE CUSHIONED SUSPENSION
(For Line Angles Greater Than 30º)
Bulletin 1724E-200
Page 15-7
Dampers: These are used in areas of severe vibration. They act to attenuate aeolian vibration
amplitudes and thereby reduce the dynamic bending stress at hardware locations and extend
conductor life. Suspension dampers (figure 15-11) make use of the connecting cables between
weights to dissipate the energy supplied to the damper. Use of spiral dampers (Figure 15-12) is
limited to small conductor sizes (Figure 15-12).
When a vibration wave passes the damper location, the clamp of a suspension type damper
oscillates up and down, causing flexure of the damper cable and creating relative motion
between the damper clamp and damper weights. Stored energy from the vibration wave is
dissipated to the damper in the form of heat. For a damper to be effective, its response
characteristics should be consistent with the frequencies of the conductor on which it is installed.
Dampers of various designs are available from a number of manufactures. The number of
dampers required, as well as their location in the span should be determined by consultation with
the damper manufacturer.
Damper Clamp
Conductor
Tapered Sleeve
Damper Weight
Damper Cable
Drain Hole
FIGURE 15-11: TYPICAL SUSPENSION DAMPER
FIGURE 15-12: SPIRAL VIBRATION DAMPER FOR SMALL CONDUCTORS
Application of armor rods, cushion suspension or dampers or a combination thereof should be on
a case-by-case basis. A certain item should not be used merely because it has given satisfactory
performance in another location.
If prevailing wind conditions and the terrain are such that vibration will occur most of the time,
some form of vibration protection should be investigated. Dampers should be selected on the
basis of the frequencies one expects to encounter in the terrain that must be traversed. The
engineer should not specify a certain type of damper or armor rod simply because everyone else
is using them. An improperly located damper can affect the amount of protection and ability of
the damper to suppress the damaging effects of aeolian vibration.
Armor rods are meant to be reinforcement items, not dampers. Vibrations are passed on through
the conductor clamp basically without any attenuation, and then dissipated in the supporting
structure. If the structure is made of steel and if fatigue can be a problem then use of dampers
along with armor rods should be investigated. However, care should be exercised in selecting
the distance between the ends of the armor rods and the dampers, if both are to be used.
Bulletin 1724E-200
Page 15-8
15.3.2
•
•
•
Galloping: Hazards associated with galloping conductors include:
Contact between phases or between phase conductors and ground wires,
Racking of the structure,
Possible mechanical damage at supports.
Aerodynamic drag dampers and interphase spacers are used to limit the amplitude of the
conductor during galloping. Historically, effectiveness of anti-galloping devices has been
erratic.
15.3.3 Bundled Conductors: Bundled connectors are not used very often on transmission lines
under 230 kV but are often economically justified above 230 kV. Bundled conductors can
experience aeolian vibration, galloping, corona vibration, and subconductor oscillation. For a
bundled conductor with spacers, aeolian vibration may be reduced by a factor of 10. However,
galloping of ice coated conductors will occur more readily and more severely on bundled lines
than on single conductors in the same environment.
Subconductor oscillation, though, has caused a major share of the problems to date. It is caused
by one conductor lying in the wake of an upstream conductor and thereby being excited to
vibrate in a nearly horizontal ellipse. Damage has consisted of conductor wear as well as spacer
deterioration and breakage. To reduce subconductor oscillation, subspan length or the distance
between spacers should be kept below 250 feet.
The primary purpose of spacers is to reduce the probability of conductor contact and magnitude
of vibration. Spacers may be rigid, articulated or flexible. They may be open-coil and closedcoil springs, and wire rope and steel strand connecting members. Spacers should grip bundled
conductors securely to avoid abrasion of the subconductors and to prevent conductor
entanglement during strong winds.
15.3.4 Insulator Swing: Occasionally, tie-down weights are used to control conductor position
by preventing excessive uplift and swinging. A line should not be designed to use tie-down
weights as a means of preventing the conductor from swinging into the structure. Sometimes
due to a low Vertical/Horizontal span ratio, weights may have to be used on an occasional
structure. Two types of tie down weights are shown in Figure 15-13.
Attach to the suspension
clamps via hold down
shackles
FIGURE 15-13: DISC WEIGHTS (Left), BALL WEIGHTS (Right)
15.4 Structure Related Hardware for Wood Structures
15.4.1 Fasteners: Threaded rods and machine bolts are frequently used on wood transmission
structures (Figure 15-14). A static-proof bolt has a washer securely fixed to the head of the bolt
and is furnished with washer nuts. Variations of the static-proof bolt include shoulder eye bolts
with round or curved washers welded to the eye, forged shoulder eye bolts and forged eye bolts.
MF type locknuts, used in conjunction with a regular nut or washer nut, form a solid unit which
Bulletin 1724E-200
Page 15-9
does not loosen from vibration and helps to maintain a static proof installation. The strengths
and tensile stress areas of bolts conforming to ANSI C135.1 are shown in the Table 15-1.
Machine Bolt
Double Arming Bolt,
Fully Threaded
Static Proof Bolt
With Forged Washer
Nut
StaticProof
ProofDouble
DoubleEnd
End
Static
Bolts Bolts with M/F
Locknuts
Shoulder Eye Bolt
with Curved
Washer
Static Proof
Double Arming Bolts
MF type Locknut
FIGURE 15-14: FASTENERS
TABLE 15-1
STRENGTHS OF ANSI C135.1 MACHINE BOLTS, DOUBLE ARMING
BOLTS, AND DOUBLE END BOLTS
Machine Bolt
Diameter
in.
Tensile
Stress Area
sq. in.
Minimum Tensile
Strength
lbs.
1/2
5/8
3/4
7/8
1
0.142
0.226
0.334
0.462
0.606
7,800
12,400
18,350
25,400
33,500
Lag screws (Figure 13-5) are sometimes used in lieu of bolts when shear loads are small. A lag
screw with fettered edges is driven into the wood and maintains its holding power with cone
shaped threads. When lag screws are used, the moment capacity of the wood pole is reduced in
the same manner as a bolt hole reduces moment capacity.
FIGURE 15-15: LAG SCREW
Anti-split bolts help prevent the propagation of checking and splitting at the end of crossarms. A
three inch edge distance should be provided between the anti-split bolt and the edge of the arm.
Bulletin 1724E-200
Page 15-10
15.4.2 Framing Fittings: The primary purpose for using grid gains is to reduce bolt hole
slotting by distributing the shear load of the bolt over a large wood area. The specially shaped
teeth of the grid gain press into the wood surface and offer maximum resistance to movement
both with and across the grain of the wood. The use of grid gains will strengthen bolt
connections and are recommended anytime a bolt must carry large shear loads. Two applications
of grid gains are shown in Figure 15-16.
Grid Gains
Application of Grid Gains
FIGURE 15-16: GRID GAINS
The gain plate (between a pole and a crossarm) and the reinforcing plate (on the outside of an
arm) provide additional metal bearing surface for transfer of the vertical load from the crossarm
to the crossarm mounting bolt. The gain plate eliminates a potential decay area between two
wood contact areas. A reinforcing plate, also called a ribbed tie plate, will prevent the crossarm
from splitting or checking when the nut is tightened.
When double crossarms are used to allow longer vertical spans or to increase longitudinal
strength capabilities, spacer fittings Figure 15-17 are needed to separate the crossarms and to
provide a point of attachment for suspension insulators. If fixed spacers are used, poles should
be gained. Since the standard fixed spacing sizes are 7-1/2”, 9”, 10-1/2”, and 12”, the crossarm
may be bowed +1/2 inch. The brand on the butt and face of the pole should include proper
designation of the fixed spacer size. Adjustable spacers will fit a range of pole diameters. When
they are used the pole need not be gained.
Spacer Fitting
Reinforcing Plate
and Gain Plate
FIGURE 15-17: SPACER FITTING, REINFORCING PLATE
AND GAIN PLATE
15.4.3 Swing Angle Brackets: Swing angle brackets are used to provide increased clearance
between phase conductors and the structure to which the conductors are attached (Figure 15-18).
These brackets cab be mounted horizontally or vertically. The two primary types of angle
brackets are the rod type for light loads, and angle iron type for heavier loads.
Bulletin 1724E-200
Page 15-11
FIGURE 15-18: SMALL ANGLE
STRUCTURE WITH SWING
ANGLE BRACKETS
15.4.4 Guy Attachments: The primary types of guy attachments used on wood transmission
line structures include the wrap guy, guying plates, pole eye plates, guying tees, and pole bands.
Other types of guy attachments such as formed straps, angle bolt eyes, and goat hooks are used
primarily on distribution lines. Guy attachments are used to attach the insulators to the structure
as well as providing a means of guying the structure.
15.5 Structure Related Hardware for Concrete and Steel Structures: Much of the structure
related hardware used on wood construction may be appropriate to use on steel or concrete
structures. However, hardware items with grid teeth, such as grid gains or guy attachments with
grid teeth, are not appropriate for use on steel or concrete structures. Likewise, lag screws and
gain plates are not used on steel and concrete poles. Since steel and concrete poles do not shrink
and swell with age and weather, spring washers may not be needed to keep the hardware tight
over time.
In many instances, higher strength bolts are used with steel or concrete poles. Bolts such
ASTM A325, Specification for High-Strength Bolts for Structural Steel Joints, may be
specified instead of the ANSI C135 bolts. Table 15-2 gives the strength ratings for bolts
conforming to ASTM Standard A325.
TABLE 15-2
STRENGTHS OF ASTM A325
HEAT TREATED, HIGH STRENGTH BOLTS
Machine Bolt
Diameter
in.
1/2
5/8
3/4
7/8
1
Tensile
Stress Area
sq. in.
0.142
0.226
0.334
0.462
0.606
Minimum Tensile
Strength
lbs.
17,500
27,100
40,100
55,450
72,700
Minimum Yield
Strength
lbs.
13,050
20,800
30,700
42,500
55,570
Proper selection and design of end fittings and guy attachments is necessary to obtain the
necessary capacity. For example, for steel structures, it may be necessary to use reinforcing
washers on the backside of a guy attachment or end fitting to prevent the nut or bolt head from
pulling through the wall of the steel pole. Selection of hardware should be coordinated with the
Bulletin 1724E-200
Page 15-12
steel pole supplier or concrete pole supplier to obtain the capacity and performance desired.
Selection of hardware should also consider proper fit with other hardware.
When using standard class concrete or steel poles, the owner should provide the pole
manufacturer with the load capabilities, attachment method, and attachment location of all
appurtenances. The pole manufacture should verify that the pole will not have a localized
strength problem at the attachment point. Items to consider if standard class steel or
concrete poles are guyed include:
•
•
•
•
Localized buckling at the guy attachment,
Field holes in the wrong locations,
Unexpected torsion on the pole due to the fact that the pole is not round and the correct
guy plate location does not fall on one of the pole’s flat surfaces, and
Sliding of the slip joint under heavy conductor loads.
In the use of concrete and steel structures, a means for climbing the structure should be provided.
The NESC Rule 261N states the requirements for climbing devices and attachments to the
structure. Based on this requirement, it is recommended that step bolts, removable steps,
ladders, and each attachment to the pole be designed to support a minimum of a 300-pound
worker and equipment multiplied by a 2.0 load factor. The load should be applied at the outer
edge of the step or bolt and should be supported without permanent deformation. Refer to agency
Bulletins 1724E-204, -206, -214, and -216, for additional guidelines on the use of concrete and
steel structures.
15.6 Corrosion of Hardware: Corrosion may be defined as the destruction of metal by a
chemical or electro-chemical reaction with its environment. Certain industrial and sea coast
environments accelerate the rate of corrosion. Parameters which stimulate corrosion include air
(oxygen) dissolved in water, airborne acids, sulphur compounds (from cinders, coke, coal dust,)
salt dissolved in water, corona, etc.
Any two dissimilar metals when placed together in the presence of an electrolyte form a simple
battery. One metal becomes an anode, sacrificing itself to the other metal which becomes the
cathode. One method to reduce the rate of corrosion is to select metals which are compatible
with one another. Table 15-3 details the galvanic voltage of various metals commonly used for
transmission line hardware. The greater the algebraic difference between the metals selected, the
more rapid the rate of corrosion will be of the more electronegative metal selected.
TABLE 15-3
GALVANIC TABLE OF VARIOUS METALS
Silver
Copper
Lead
Tin
Iron
Chromium
Zinc
Aluminum
+.79
+.34
-.13
-.15
-.35
-.47
-.77
-1.337
As an example, when malleable iron suspension clamps are used, aluminum liners should be
furnished in order to reduce the rate of corrosion of the aluminum conductor. As another
example, the selection of staples to be used on the pole ground wire must be compatible material
to the ground wire (see Drawing TM-9 in Bulletins 1728F-810 and 1728F-811).
Bulletin 1724E-200
Page 15-13
Other methods of reducing the rate of corrosion are to galvanize tin plate, paint or cover metals
with corrosion inhibitors. The life of used metals can be prolonged by increasing metal
thickness.
Bulletin 1724E-200
Page 15-14
Blank Page
Bulletin 1724E-200
Page 16-1
16. UNDERBUILD
16.1 General: Placing of underbuild distribution or communications circuits on transmission
lines is a practice that is becoming more prevalent as available rights-of-way decrease. Although
underbuild distribution lines increase the initial cost of a transmission line, common sharing of a
right-of-way is sometimes necessary in order to build the line.
The following factors should be considered in designing a common use line: hazards to
personnel and property, costs, difficulties of construction, operation and maintenance. Adequate
structure arrangement and conductor separation should be provided to minimize the possibility
of conductor contacts, and to provide safe working conditions. Adequate electrical protection
involves prompt and positive de-energization of power circuits in the event of conductor contact
or flashover. Obtaining and maintaining a low ground resistance to earth is desirable to limit the
magnitude of voltage rise, duration of hazardous voltage, and lightning damage.
16.2 Addition of Distribution Underbuild to an Existing Transmission Line: Distribution
circuits can be added to existing transmission structures only if the original transmission
structure was designed for the new particular underbuild facilities or the total structure facilities
meets the current edition of the NESC.
16.3 Strength Requirements: Standard distribution construction is required to meet NESC
Grade C construction in accordance with 7 CFR Part 1724. However, underbuild distribution on
transmission circuits, with the exception of the crossarms, are to be built to meet all requirements
of NESC Grade B construction. This means that the loading on the pole due to the distribution
circuits has to be calculated using NESC Grade B overload capacity factor and strength factors,
It also means that all guying for the underbuild must meet the guying requirements for
transmission. Distribution crossarms on transmission structures may be designed for NESC
Grade C construction, except at angles where they have to be designed for NESC Grade B
construction.
16.4 Line-to-Ground Clearances: Since the lowest conductors on a transmission line with
underbuild will usually be those of the distribution circuits, the clearances to ground and
clearances in crossing situations will in most instances be limited by the requirements stipulated
in the NESC for distribution circuits.
The problem of providing satisfactory clearance becomes more involved when multiple
distribution circuits or conductors cross on the same structure. In these instances, very careful
attention need to be given to the allowable clearance in Section 23 of the NESC.
Particular attention should be given to the use of reduced size distribution neutrals since the
clearance to ground for the neutral, by virtue of its increased sag and position on the pole or
crossarm, may be the controlling factor for pole height. In some cases, it may be more
economical to increase the size of the neutral to reduce its sag.
16.5 Separation Between Transmission and Underbuild Distribution Circuits: The
clearances discussed in this section are intended to provide not only operating clearances but
also sufficient working clearances. A distribution line worker has to be able to access and work
on the distribution underbuild without encroaching upon the required safety (zone) clearances of
the transmission conductors.
16.5.1 Horizontal Separation: The horizontal separation at the support between the lowest
transmission conductor(s) and the highest distribution conductor(s) or neutral should be at least
1 foot if possible as illustrated in Figure 16-1.
Bulletin 1724E-200
Page 16-2
1' min. if
possible
FIGURE 16-1: HORIZONTAL
SEPARATION REQUIREMENTS
BETWEEN TRANSMISSION AND
UNDERBUILD
D
v
FIGURE 16-2: VERTICAL
SEPARATION REQUIREMENTS AT
STRUCTURE FOR UNDERBUILD
16.5.2 Vertical Clearance to Underbuild at Supports: Recommended minimum vertical
clearances between the transmission conductors and the underbuild conductors at the support are
shown in Table 16-1. These clearances apply regardless of the amount of horizontal separation
between transmission and underbuild conductors (see Figure 16-2).
16.5.3 Vertical Clearance to Underbuild at any Point in the Span: Recommended minimum
vertical clearances at any point along the span are shown in Table 16.1.
These clearances apply for the condition below which yields the least separation between the
upper and lower conductor.
a. An upper conductor final sag at a temperature of 32°, no wind, with radial thickness of ice
for the applicable loading district;
b. An upper conductor final sag at a temperature of 167ºF;
c. Upper conductor final sag at a maximum design temperature, no wind. For high voltage bulk
transmission lines of major importance to the system, consideration should be given to the
use of 212ºF as the maximum design conductor temperature.
The sag of the underbuild conductor to be used is the final sag, at the same ambient temperature
as the upper conductor without electrical loading and without ice loading.
If the transmission line or portion thereof is at an altitude which is greater than 3300 feet, an
additional clearance (as indicated in Table 16-1) has to be added to both clearances at the
structure (Category 1) and clearances at the midspan point (Category 2).
16.5.4 Additional Clearance Requirements for Communication Underbuild: For
communication underbuild, the low point of the transmission conductors at final sag,
60˚ F, no wind, should not be lower than a straight line joining the points of support of the
highest communication underbuild.
Bulletin 1724E-200
Page 16-3
TABLE 16-1
RECOMMENDED MINIMUM VERTICAL CLEARANCES TO DISTRIBUTION OR
COMMUNICATION UNDERBUILD ON TRANSMISSION LINES IN FEET
(Circuits may be of the same or different utilities)
(Based on NESC Rule 235 and Table 235-5)
Transmission Nominal voltage, Phase
to Phase
Max. Operating Voltage, Phase to Phase
Max. Operating Voltage, Phase to Ground
kVL-L
34.5
46
69
115
138
161
230
kVL-L
kVL-G
36.2
20.2
48.3
27.9
72.5
41.8
120.8
69.7
144.9
83.7
169.1
97.6
241.5
139.4
Vertical Clearances Between Transmission and
Distribution Conductors
1. Clearance at the support from point of
suspension of transmission conductor to
point of suspension of underbuild
distribution or communication conductor.
Nominal underbuild voltage in kV line-toline: (Note A)
a. 25 kV and below (including
communications conductors)
b. 34.5 kV
2. Clearance at any point in span from
transmission conductor to underbuild
conductor. Nominal underbuild voltage in
kV line-to-line (Note A):
a. 25 kV and below (including
communications conductors)
b. 34.5 kV
Clearances in Feet
4.7
5
5.4
6.4
6.8
7.3
8.7
4.9
5.2
5.6
6.5
7.0
7.5
8.9
3.7
3.8
4.2
5.2
5.6
6.1
7.5
3.8
4.0
4.3
5.4
5.8
6.3
7.7
0.08
0.12
Vertical Clearances Between Transmission
Conductors and Distribution Structures
ALTITUDE CORRECTION TO BE ADDED TO VALUES ABOVE
Additional feet of clearance per 1000 feet
0.02
of altitude above 3300 feet
(See Table 4-2)
0.02
0.05
0.06
Note:
(A) An additional .5 feet of clearance is added to the NESC clearance to obtain the recommended design
clearances.
16.5.5 Span Length and Clearance to Underbuild: The conditions of either Paragraph 16.5.2
or Paragraph 16.5.3 above will dictate what the minimum clearance to underbuild at the structure
should be. If the clearance to an underbuild is dictated by Paragraph 16.5.3 of this section, the
clearance at the structure would have to be increased. Vertical separation at the structure may
depend upon the relative sags of transmission and underbuild conductors. Since the span length
has an effect on relative sags, the resulting maximum span as limited by vertical clearance to
underbuild should be calculated to ensure that the vertical separation at the support is correct for
each span.
Bulletin 1724E-200
Page 16-4
The formula for maximum span as limited by clearance to underbuild is:
Lma x = (RS )
A− B
Sl − Su
Eq. 16-1
where:
Lmax
RS
A
B
Sℓ
Su
=
=
=
=
=
maximum span in feet
ruling span in feet
allowable separation at midspan in feet
vertical separation at supports in feet
underbuild sag at the same ambient temperature as the
transmission conductor, final, in feet
= transmission conductor sag at condition resulting in
least separation to underbuild, final sag, in feet
16.6 Climbing Space: Climbing space through the lower circuits should be preserved on one
side of the pole or in one quadrant from the ground to the top of the pole as required by the
NESC. Working space should be provided in the vicinity of crossarms. Jumpers should be kept
short enough to prevent their being displaced into the climbing space.
16.7 Overhead Ground Wires and Distribution Neutrals: Standard distribution underbuild
construction has its own neutral. This neutral may be tied to the transmission pole ground wire
in order to improve its grounding. Depending on the characteristic of the circuits, a common
ground or a separate ground is acceptable. If separate grounds are used, the pole ground wires
should be located on opposite sides of the pole. Similar materials should be used for both the
transmission pole ground wire and for the distribution pole ground wire and ground rod. For
example, if copper is used for the transmission pole ground, then copper and/or copperclad
should be used for the distribution ground rod and pole ground wire. Use of similar materials
will reduce the possibility of galvanic corrosion. Likewise, the distribution anchors and
transmission anchors should be of similar material as the ground rods and wire used for the pole
butt wraps.
For distribution underbuild on concrete transmission poles, the neutral may be tied to the
external pole ground using a compression connector in locations where the neutral is to be
grounded. A lead from the pole ground should then be tied to a separate ground rod via a
compression connector six inches to one foot above the ground level. Similarly, in the case of
steel poles, there may be situations where the neutral of the distribution underbuild is to be
grounded. In these instances, the pole may be used as the ground path but not as a ground
electrode. A grounding connector mounted on the pole needs to be specified just below the
location of the neutral on the pole. The ground pad near the ground line should then be used to
connect a driven ground rod to the pole.
16.8 Addition of Poles for Underbuild: There may be structures where it is either desirable or
necessary to transfer distribution circuits to separate poles. Such situations include:
•
•
•
•
Large Line Angles (Figure 16-3)
Deadends
Tap-offs
Sectionalizing Structures
•
•
•
Substation Approaches
Transformers or Regulators (Figure 16-4)
Capacitors
Bulletin 1724E-200
Page 16-5
Transmission
Distribution
FIGURE 16-3: TRANSFERENCE OF THE DISTRIBUTION CIRCUIT
TO A SEPARATE POLE AT A LARGE ANGLE
Location of transformers on structures carrying both transmission and distribution lines should
be avoided. Not only does the transformer create an unbalanced load on the structure, but the
additional conductors necessary for service drops may make working on the structure hazardous
to personnel. A ground rod should be installed at every pole location with a transformer and the
transformer grounded per NESC requirements.
(See Table 4-2
for Clearance)
Transformer
Pole
FIGURE 16-4: USE OF A SEPARATE POLE TO MOUNT
A DISTRIBUTION TRANSFORMER
16.9 Guying: The need to provide additional guys to compensate for the effect of underbuild
on structures is readily apparent. However, there are locations where special attention has to be
given to the guying being proposed. One example is a common use pole with a line tap.
Tension due to
vertical loading
only
M
x
Transmission Line
N
P
x
Guy
Distribution
Sketch (a)
Sketch (b)
FIGURE 16-5: GUYING DISTRIBUTION UNDERBUILD
Bulletin 1724E-200
Page 16-6
For winds perpendicular to the transmission line, the guying described in Figure 16-5 may be
insufficient. This will be true if consideration has been given only to underbuild deadend tension
shown as forces (x) in the figure. The maximum transverse load acts on half the sum of adjacent
spans, (MN+NP)/2, of the transmission and distribution circuits.
These forces have to be added to the tensions of tap conductors in order to determine the proper
amount of guying required. If winds are parallel to the transmission line, the deadend loading of
the tap is larger and this load should be used. Guying of the distribution underbuild is to meet
Grade B construction.
A general rule is that where the transmission circuit or the distribution circuit requires guys, both
circuits should be guyed. The guys should be designed to carry the entire transverse load on the
structure at maximum loading conditions. All drawings should show location and slope of guys
to assure adequate clearances when guys are required. Positions of guys should be clear from
other hardware or electrical connections, such as connectors between neutral and pole ground
wire. Where guys may pass close to conductors, minimum clearances in accordance with Table
4-2 should be met.
16.10 Example: Maximum Span as Limited by Clearance to Underbuild: A 69 kV single
pole transmission is to be built with a 25 kV underbuild distribution circuit. Determine
maximum span as limited by clearance between transmission conductors and underbuild.
16.10.1 Given:
•
•
•
•
Vertical separation between transmission and distribution conductors at the structure is
11.0 ft.
Ruling span: 300 ft.
NESC Heavy loading district
Conditions for the conductor:
a. Transmission conductor is at 32°F with ½” ice while the distribution conductor is
at an ambient temperature of 0°F during the winter.
b. Transmission conductor is at 212°F maximum design temperature while the
distribution conductor is at an ambient temperature of 0°F during the winter.
c. Transmission conductor is at 212°F maximum design temperature while the
distribution conductor is at an ambient temperature of 90°F during the summer.
Transmission Conductor
477 kcmil 26/7 ACSR
(a)
(b)
(c)
Distribution Conductor
4/0 6/1 ACSR
Loading
Condition
Final sag
(ft.)
Ambient Temp.
Final sag (ft.)
32ºF, 1/2” ice
212ºF
212ºF
4.40
6.73
6.73
0°F
0°F
90°F
1.60
1.60
3.98
16.10.2 Solution:
From Table 16-1 the required vertical clearance at midspan between the transmission and
distribution conductors is 4.2 feet.
Bulletin 1724E-200
Page 16-7
Next, calculate the separation between the upper and lower conductor for each loading condition
given above:
(a) 11’ - 4.40’ + 1.60’ = 8.20’
(b) 11’ - 6.73’ + 1.60’ = 5.87’
(c) 11’ - 6.73’ + 3.98’ = 8.25’
The condition (b) results in the least separation between the transmission and underbuild
conductors; therefore, the condition (b) conductor sag values will be used in the following
equation:
Lma x = (RS )
A− B
Sl − Su
Eq. 16-1
Substituting:
RS
A
B
Sl
=
=
=
=
=
300
4.2
11
1.60
6.73
Lma x = (300 )
4.2 − 11
1.60 − 6.73
Lmax = 345 feet
The maximum span as limited by the separation between the transmission conductors and the
distribution underbuild is 345 feet.
For situations where greater span lengths are necessary, the separation at the structure should be
increased. In addition, consideration should be given for the effects of ice jumping as described
in Section 6.3 of this manual.
Bulletin 1724E-200
Page 16-8
Blank Page
Bulletin 1724E-200
Page A-1
APPENDIX A
TRANSMISSION LINE DESIGN DATA
SUMMARY SHEET AND SUPPORTING INFORMATION
•
Sample Summary Sheet
A-3
•
Instructions
A-5
•
Suggested Outline for Design Data Summary Book
A-10
Bulletin 1724E-200
Page A-2
Blank Page
Bulletin 1724E-200
Page A-3
I. GENERAL INFORMATION
BORROWER:
DATE:
LINE IDENTIFICATION:
VOLTAGE
TRANSMISSION LINE DESIGN
DATA SUMMARY
LENGTH
TRANSMISSION
UNDERBUILD
TRANSMISSION
UNDERBUILD
___________kV
___________kV
___________mi
___________mi.
.
TYPE OF TANGENT STRUCTURE:
BASE POLE:
____________HT. ____________CL
DESIGNED BY:
II. CONDUCTOR DATA
TRANSMISSION
OHGW
UNDERBUILD
COMMON NEUTRAL
TRANSMISSION
(lbs./ft.)
OHGW
(lbs./ft.)
UNDERBUILD
(lbs./ft.)
COMM.NEUTRAL
(lbs./ft.)
SIZE (kcmil or in.)
STRANDING
MATERIAL
DIAMETER (in)
WEIGHT (lbs./ft.)
RATED STRENGTH (lbs.)
III. DESIGN LOADS (Wires)
NESC:__________________LOADING DISTRICT
a. ICE:
_________in.
b. WIND ON ICED COND. ____psf
Vertical.
Transverse
c. CONSTANT K ___________
Resultant + K
HEAVY ICE(NO WIND) ______in.
Vertical.
HIGH WIND(NO ICE) ______psf
Transverse
EXTREME HIGH WIND/ICE
ICE:
_________in.
WIND ON ICED COND. ____psf
Vertical.
Transverse
IV. SAG & TENSION DATA
SPANS
AVERAGE(EST)
___________ft
MAXIMUM(EST)
SOURCE OF SAG-TENSION DATA:
TRANSMISSION
TENSIONS (% RATED STRENGTH)
INITIAL
NESC
a. UNLOADED (0˚ 15˚ 30˚)
NESC
b. LOADED (0˚ 15˚ 30˚)
FINAL
___________ft..
OHGW
INITIAL
FINAL
RULING(EST)
UNDERBUILD
INITIAL
FINAL
____________ft.
COMM.NEUTRAL
INITIAL
FINAL
_____˚F
_____˚F
MAXIMUM ICE
32 ˚F
HIGH WIND (NO ICE)
_____˚F
UNLOADED LOW TEMPERATURE _____˚F
SAGS (FT)
NESC DISTRICT LOADED
_____˚F
UNLOADED HIGH TEMP(120˚FOR OHGW &U.B.)___˚F
MAXIMUM ICE
32˚F
LOADED 1/2” ICE, NO WIND
32˚F
V. CLEARANCES
MINIMUM CLEARANCES TO BE MAINTAINED AT:_____________________________________________________________________
CLEARANCES
IN FEET
RAILROADS
HIGHWAY
CULTIVATED
FIELDS
ADDITIONAL .
ALLOWANCE
TRANSMISSION
UNDERBUILD
VI. RIGHT OF WAY
WIDTH
_____________
FT. (MIN.)
_____________
FT. (MAX.)
Bulletin 1724E-200
Page A-4
VII. CONDUCTOR MOTION DATA
HISTORY OF CONDUCTOR GALLOPING:
HISTORY OF AEOLIAN VIBRATION:
a. TYPE OF VIBRATION DAMPERS USED (IF ANY)
b. TYPE OF ARMOR RODS USED (IF ANY)
VIII. INSULATION
NO. OF THUNDERSTORM DAYS/YR______________ELEV.ABOVE SEA LEVEL (MIN, MAX, ft.)____________________
CONTAMINATION EXPECTED?_____________MAX EST. FOOTING RESISTANCE___________Ω
SHIELD ANGLE __________˚
STRUCTURE
STRUCTURE
NO. OF BELLS /
60 HZ DRY
INSULATOR SIZE
SML / M & E
TYPE
DESIGNATION
POLYMER /
FLASHOVER
(DIAMETER &
RATING / POST
LENGTH)
STRENGTH
PIN OR POST
OTHER
TANGENT
ANGLE
STRAIN STRUC
IX. INSULATOR SWING
CRITERIA: (1)_________PSF ON BARE CONDUCTOR AT __________(6 psf MIN) FOR ___________________in. CLEARANCE
(2)_________PSF HIGH WIND ON BARE CONDUCTOR AT ___________˚ F FOR _______________in. CLEARANCE
ALLOWABLE SWING ANGLE:
ANGLE IN DEGREES
STRUCTURE.
NO. OF
6 psf MIN.
TYPE
INSULATORS.
WIND(1)
HIGH WIND (2)
NO WIND
OTHER
X. ENVIRONMENTAL AND METEORLOGICAL DATA
TEMPERATURE: MIN__________˚ MAX.__________˚
AVERAGE YEARL LOW
_____________˚
MAXIMUM HEIGHT OF SNOW ON THE GROUND
EXTREME 10 SEC. WIND GUSTS (mph):
10 YR. ___________ 50 YR.__________ 100 YR___________
DESCRIBE TERRAIN AND CHARACTERISTICS OF SOIL
UNDER THE CONDUCTOR(ft.):
CORROSIVENESS OF ATMOSPHERE:
XI. STRUCTURE DATA (FOR SINGLE POLES AND H-FRAMES)
POLE MATERIAL:_____________________________
TYPE OF FOUNDATION: TANGENT:____________ANGLE:____________
ARM MATERIAL: Trans_________________________
DEADEND_________________GUYED STRUCTURES____________
Underbuild_________________________
TANGENT STRUCTURE TYPE___________________
BASE POLE
SUMMARY OF SPANS (ft.) FOR TANGENT STRUCT.
_____FT.____CL
OTHER HEIGHTS/CLASSES AND BRACING
LEVEL GROUND SPAN
MAX. HORIZON. SPAN LIMITED BY STRUCTURE STRENGTH
MAX. VERTICAL SPAN LIMITED BY STRUCTURE STRENGTH
MAX. HORIZONTAL SPAN LIMITED BY COND. SEPARATION
MAX. SPAN LIMITED BY UNDERBUILD
MAX. SPAN LIMITED BY GALLOPING
EMBEDMENT DEPTH
PRESERVATIVE OF WOOD POLE (TYPE &RETENT.)_______________________
FOR BASE POLE:_____________________________
CORROSION PROTECTION FOR STEEL POLES ___________________________
GUYING: TYPE OF ANCHORS: ____________________________ GUY SIZE AND R.B.S.:___________________________________
XII. LINE DESCRIPTION
TANGENTS__________________%
MEDIUM ANGLES____________%
LIGHT ANGLES ______________%
DEADEND &
HEAVY ANGLES______________%
AVERAGE NUMBER OF
LINE ANGLES PER mi. ______________________
MAXIMUM DISTANCE BETWEEN
FULL DEADENDS (mi.)___________________
Bulletin 1724E-200
Page A-5
INSTRUCTIONS FOR FILLING OUT SAMPLE SUMMARY SHEET
I.
GENERAL INFORMATION
BORROWER – Agency borrower designation.
DATE – Date when design data was completed.
LINE IDENTIFICATION – The name of the line, usually expressed in terms of the line’s
endpoints. If the line design is “project design data” that is to be used for several line
designs, the term “project design data” should be entered.
VOLTAGE – Nominal line-to-line voltage of both transmission and underbuild
distribution circuit in kV. If there is no underbuild, fill in N. A. (not appropriate)
LENGTH – Self-explanatory.
TYPE OF TANGENT STRUCTURE – Give agency designation for tangent structure
type used (for example, “TH-10”). If the structure is not a standard agency structure, the
word “special” should be filled in.
BASE POLE – The height and class of pole used most widely in line.
DESIGNED BY – Individual and/or firm doing the designing.
II.
CONDUCTOR DATA
SIZE – For conductors, size in AWG numbers or kcmil. For steel wire, diameter in
inches.
STRANDING – Number of strands. For ACSR conductor, give aluminum first, steel
second. For example: 26/7.
MATERIAL – Indicate conductor or wire type. For example, ACSR, 6201;or EHS (extra
high strength steel).
DIAMETER – Diameter of conductor, in.
WEIGHT – Weight per foot of bare conductor, lbs/ft.
RATED STRENGTH – Standard rated strength of conductor.
III.
DESIGN LOADS
NESC LOADING DISTRICT – Indicate the National Electrical Safety Code loading
district on which design is based. Use “H” for heavy, “M” for medium, and “L” for light
loading district.
Bulletin 1724E-200
Page A-6
a. Ice – Radial in. of ice on conductor for loading district specified.
b. Wind – Wind force in lbs. for loading district specified.
c. Constant “K” – Constant from NESC to be added to resultant of horizontal and
vertical load (at standard loading district condition) for determining conductor sags
and tensions.
HEAVY ICE – (no–wind, in.) – Radial thickness (in.) of ice conductor for the heavy
icing condition for which line is designed (if any).
HIGH WIND – (no ice – psf) – The high wind value in lbs/sq. ft. for which the line is
designed.
COMBINED EXTREME ICE/WIND – The loadings associated with the 50 yr extreme
ice/wind from the figures in 11.3 of this bulletin. The radial thickness of ice and the unit
loads should be given for the vertical loads. The high wind associated with the radial
thickness of ice should be given for the tansverse loads as well as the unit loads.
LOADING TABLE - Conductor or wire loads in lbs. per linear ft. for conditions
indicated at left.
IV.
SAG & TENSION DATA
SPANS – AVG., MAX., and RULING – Self-explanatory.
SOURCE OF SAG-TENSION DATA – Self-explanatory.
TENSION TABLE – Initial and final tension values in percent of rated strength at
loading conditions indicated on the left should be given. In those boxes where there is a
dotted line in the center, the specified tension limiting values (in percent) should be given
above the line. The actual resulting tension value (in percent) should be given below the
line. For all other boxes the tension value should be the actual resulting value (in
percent). The details of loading condition should be filled in on the left as follows:
a. Unloaded (0º, 15º, 30º) – Indicate appropriate temperature. Heavy loading district
will be 0ºF, medium will be 15ºF, light will be, 30ºF.
b. NESC Loaded (0º, 15º, 30º) – Specify appropriate temperature.
c. Maximum Ice – Use the same maximum radial ice as indicated in the
DESIGN LOADS section.
d. High Wind – Use the same value as in the DESIGN LOAD section.
e. Unloaded Low Temperature – Specify lowest temperature that can be expected to
occur every winter.
SAG TABLE – Specify initial and/or final sags in ft. for conditions indicated. Specify
maximum conductor operation temperature in the appropriate box on the left. Sags for
the overhead ground wire and underbuild conductors are for a temperature of 120ºF.
Note: When sag and tension calculations are done, tension limits are usually specified at
several conditions. However, only one of the conditions will usually control, resulting in
tensions, at the other conditions, that are lower than the limit.
V.
CLEARANCES
MINIMUM CLEARANCES TO BE MAINTAINED AT – Specify maximum sag
condition at which minimum clearances are to be maintained. Generally, it will be at the
high temperature condition but it may be possible for the sag at NESC loading (H, M, L)
to be the controlling case.
Bulletin 1724E-200
Page A-7
CLEARANCE TABLE – Indicate clearance which will be used for plan and profile and
design. Extra boxes are for special situations.
VI.
RIGHT-OF-WAY WIDTH
Indicate width value used. If more than one value is used, give largest and smallest
value.
VII.
CONDUCTOR MOTION DATA
HISTORY OF CONDUCTOR GALLOPING – Indicate if conductor galloping has ever
occurred in the area and how often it can be expected.
HISTORY OF AEOLIAN VIBRATION – Indicate whether or not the line is in an area
prone to aeolian vibration.
a. Type of Vibration Dampers Used (if any) – Self-explanatory.
b. Type of Armor Rods Used (if any) – Indicate whether standard armor rods, cushioned
suspension units or nothing is used.
VIII. INSULATION
NUMBER OF THUNDERSTORM DAYS/YEAR – Self -explanatory.
ELEVATION ABOVE SEA LEVEL (min., max., ft.) – Give the altitude in ft. above sea
level of the minimum and maximum elevation points of the line
CONTAMINATION EXPECTED? – Indicate contamination problems which may affect
the performance of the insulation. The following are recommended terms: None, Light,
Medium, Heavy, Sea Coast Area.
MAXIMUM ESTIMATED FOOTING RESISTANCE. – Give the estimated maximum
electrical footing resistance (in ohms) expected to be encountered along the length of the
line. Where the footing resistance is high, the value to which the footing resistance will
be reduced, by using special measures, should be indicated by putting this value in
parentheses. For example, 70(20).
SHIELD ANGLE – If the basic tangent structure being used is not a standard structure,
its shield angle should be given.
INSULATION TABLE – For the structure type indicated, the structure numerical
designation and the number of suspension bells should be given. If post insulators are
used instead of suspension, the word “post” or “pin” should be put in the second column.
If nonceramic insulators are used, indicate ‘susp-nci’ or ‘post-nci’. The 60 Hz dry
flashover value for the entire string of insulators (or post) should be given. The column
“insulator size” should contain the diameter and length of the insulator. For suspension
bell, the M&E strength should be given. For post insulator, the ultimate cantilever
strength should be entered. For nonceramic insulators suspension or posts, give the SML
ratings.
Bulletin 1724E-200
Page A-8
IX.
INSULATOR SWING
CRITERIA – Self-explanatory
INSULATOR SWING TABLE – For the primary structures used in the line and the
number of insulators used, the insulator swing angles under the 6 lb. minimum condition,
the high wind condition and under the no wind condition should be given.. Angles
measured from a vertical through the point of insulator string suspension away from
structure should be indicated by following them with an asterisk (*).
X.
ENVIRONMENTAL & METEORLOGICAL DATA
TEMPERATURE – The minimum, maximum, and average yearly low temperature
recorded in the area of the line should be given.
MAXIMUM HEIGHT OF SNOW ON GROUND UNDER CONDUCTOR
(ft.) – Self-explanatory.
CORROSIVENESS OF ATMOSPHERE – Indicate corrosiveness of the atmosphere by
severe, moderate, or light.
EXTREME 10 SEC WIND GUSTS – Give the annual extreme wind with mean
recurrence intervals of 10, 50, and 100 years. For 50 year, see Figures 11-2a to 11-2d of
Chapter 11. For 10 year, see paragraph 7.2.3 of Chapter 7.
DESCRIBE TERRAIN & CHARACTER OF SOIL – A brief description should be given
as to whether the terrain is flat, hilly, rolling piedmont, or mountainous. Indicate whether
the soil firmness is good, average, or poor. Give approximate depth of ground water
table. Describe corrosiveness of soil.
XI.
STRUCTURE DATA (For single poles and H-frames)
POLE MATERIAL – Indicate wood, steel, or concrete. If wood, indicate species.
ARM MATERIAL – If a crossarm is used, indicate wood, steel or fiberglass..
TYPE OF FOUNDATION – For tangent, angle, or deadend structures, indicate direct
embedded or caisson for the majority of the structures within each type. For example, if
most of the angle and deadends are unguyed, indicate the predominant foundation for
each type.
STRUCTURE TABLE The various maximum span values should be given for the base
pole and structure configuration. Values should also be given for other pole heights,
wood classes or standard steel/concrete pole classes, bracing and configurations that are
expected to be commonly used.
a. Level Ground Span – Give the maximum span for height of pole, limited by
clearance to ground only.
b. Maximum Horizontal Span Limited by Structure Strength – For single pole
structures, give the maximum span as limited by pole strength. For H-frame
structures, the effect of the bracing must be included. If vertical post insulators are
used, their maximum horizontal span value should be included if it is less than that of
the rest of the structure, and should be indicated as such by placing the term “ins”
after the value. If underbuild is to be used on the line, its effect should be included.
c.
d.
e.
f.
Bulletin 1724E-200
Page A-9
Maximum Vertical Span Limited by Structure Strength – Give the maximum
vertical span limited by either crossarm strength, crossarm brace strength, or
horizontal post insulator strength. If horizontal post insulators are the limiting factor,
the term “ins” should be placed after the span value. If the structure is such that the
maximum horizontal span affects the maximum vertical span, the assumed maximum
horizontal span should be the value shown in the “maximum horizontal span” box.
Maximum Horizontal Span Limited by Conductor Separation – Give the
maximum span value from Equation 6-1 or 6-2 in Chapter 6 of this bulletin.
Maximum Span Limited by Underbuild – Give the maximum span limited by
separation between underbuild conductors, or between underbuild and transmission
conductors, whichever is more limited.
Maximum Span Limited by Galloping – Give the maximum span that can be
allowed before galloping ellipses touch.
EMBEDMENT DEPTH – Indicate the pole embedment depth used. If the standard
values are used, indicate “standard”. If other values are use, indicate by how much they
differ from the standard value. For example, std. + 2 ft.
PRESERVATIVE FOR WOOD POLES – Type and retention level of preservative.
CORROSION PROTECTION FOR STEEL POLES – Indicate weathering steel,
galvanized steel, or painted.
GUYING – Indicate whether log, screw or other anchors are used and the predominant
anchor capacity. For example: Log, 8,000/16,000 lbs. The diameter, type and rated
breaking strength (rbs) of the guy strand should be given.
XII.
LINE DESCRIPTION
For the respective structures types, indicate the percentage of the total number of structures used.
Calculate the average number of line angles per mile and give the maximum distance in miles
between full deadends: (“Full” deadends refer to strain type structures that are designed to
remain standing if all conductors and overhead ground wires are cut on either side of the
structure.)
Bulletin 1724E-200
Page A-10
SUGGESTED OUTLINE FOR
DESIGN DATA SUMMARY BOOK
Given below is a suggested outline for a Design Data Summary Book. The outline is primarily
intended for lines of 230 kV Generally, a well prepared design data book should include all the
material indicated below. However, some judgment should be used in submitting more or less
information as deemed appropriate.
I.
Transmission Line Design Data Summary
II.
General Information
A.
Line identification, description and role in system
B.
Description of terrain and weather
C.
Design criteria and applicable codes and standards
D.
Selection of conductor and OHGW
Selection of conductor and OHGW type
2.
Selection of conductor and OHGW size/
Economic conductor analysis
E.
Determination of maximum conductor temperature
F.
Selection of structure type and average height
G.
III.
1.
1.
Economic evaluation of alternate structures
2.
Selection of optimum structure height
Construction cost estimate
Supporting Calculations to Part I
A.
Conductor sag and tension tables (computer printout and source)
B.
OHGW sag and tension values (computer printout and source)
C.
Vertical and horizontal clearances and ROW width
D.
Insulation considerations
E.
Level ground span
Bulletin 1724E-200
Page A-11
F.
Maximum span limited by conductor separation
1.
Horizontal separation
2.
Vertical and diagonal separation
G.
Maximum span limited by underbuild (if applicable)
H.
Galloping analysis
I.
Unguyed structure strength calculations
J.
1.
Maximum horizontal span limited by pole strength, ‘X’ bracing, poles
(including post insulators; if applicable)
2.
Maximum vertical span limited by structure strength
3.
Loading trees for steel or concrete structures; selection method for
standard class poles
4.
Hardware limitations
5.
Insulator strength requirements
6.
Foundation type; embedment depths; selection method; soil information
Guyed structure calculations
1.
Minimum spacing of anchors
2.
Guy and anchor calculations and application charts
3.
Maximum axial loads for guyed pole
4.
Guy attachments and their strengths
5.
Arrangement of guys and anchors and application guides
K.
Sample insulator swing calculations and application charts for all structures
L.
Diagrams for all non-standard structures or assemblies anticipated for use on the
line
M.
Sag-clearance template if a CADD program is not used for the plan-profile
Bulletin 1724E-200
Page A-12
Blank Page
Bulletin 1724E-200
Page B-1
APPENDIX B
CONDUCTOR TABLES
•
Conductor Mechanical Loading Tables
B-2
•
Overhead Ground Wire Loading Tables
B-7
Bulletin 1724E-200
Page B-2
CONDUCTOR MECHANICAL
LOADING TABLES
The tables that follow give horizontal, vertical, and resultant vector loads on conductors and
overhead ground wires under standard NESC loading district conditions, high wind conditions,
and heavy ice conditions.
Bulletin 1724E-200
Page B-3
ACSR CONDUCTORS
NESC DISTRICT LOADINGS
LIGHT
.00" ICE, 9 LB., K=.05
VERT.
TRANS RESULTANT
STRAND LB/FT.
LB/FT.
LB/FT.
6/1
0.1452
0.2985
0.3819
6/1
0.1831
0.3353
0.4320
6/1
0.2309
0.3765
0.4917
6/1
0.2911
0.4223
0.5629
18/1
0.2894
0.4568
0.5907
26/7
0.3673
0.4815
0.6556
18/1
0.3653
0.5130
0.6798
26/7
0.4630
0.5408
0.7619
30/7
0.5271
0.5558
0.8160
18/1
0.4316
0.5573
0.7548
MEDIUM
.25" ICE, 4 LB. WIND, K=.20
VERT.
TRANS RESULTANT
LB/FT.
LB/FT.
LB/FT.
0.3467
0.2993
0.6580
0.3998
0.3157
0.7094
0.4647
0.3340
0.7723
0.5439
0.3543
0.8491
0.5565
0.3697
0.8681
0.6446
0.3807
0.9486
0.6557
0.3947
0.9653
0.7649
0.4070
1.0664
0.8352
0.4137
1.1320
0.7403
0.4143
1.0484
HEAVY
.5" ICE, 4 LB. WIND, K=.30
VERT.
TRANS RESULTANT
LB/FT.
LB/FT.
LB/FT.
0.7036
0.4660
1.1439
0.7719
0.4823
1.2102
0.8539
0.5007
1.2899
0.9520
0.5210
1.3853
0.9789
0.5363
1.4162
1.0774
0.5473
1.5084
1.1015
0.5613
1.5363
1.2222
0.5737
1.6501
1.2987
0.5803
1.7225
1.2045
0.5810
1.6373
ULTIMATE
STRENGTH DIAM. WT./FT.
LBS.
IN.
LBS.
4380
0.398
0.1452
5310
0.447
0.1831
6620
0.502
0.2309
8350
0.563
0.2911
6880
0.609
0.2894
11300
0.642
0.3673
8680
0.684
0.3653
14100
0.721
0.4630
17300
0.741
0.5271
9940
0.743
0.4316
NAME
RAVEN
QUAIL
PIGEON
PENGUIN
WAXWING
PARTRIDGE
MERLIN
LINNET
ORIOLE
CHICKADEE
SIZE
1/0
2/0
4/0
266.8
266.8
336.4
336.4
336.4
397.5
397.5
IBIS
LARK
PELICAN
FLICKER
HAWK
HEN
OSPREY
PARAKEET
DOVE
EAGLE
397.5
397.5
477.
477.
477.
477.
556.5
556.5
556.5
556.5
26/7
30/7
18/1
24/7
26/7
30/7
18/1
24/7
26/7
30/7
0.5469
0.6228
0.5180
0.6145
0.6570
0.7470
0.6040
0.7170
0.7660
0.8720
0.5873
0.6045
0.6105
0.6345
0.6435
0.6623
0.6593
0.6855
0.6953
0.7148
0.8525
0.9179
0.8506
0.9333
0.9696
1.0483
0.9441
1.0420
1.0845
1.1775
0.8680
0.9511
0.8488
0.9552
1.0015
1.0992
0.9550
1.0789
1.1319
1.2460
0.4277
0.4353
0.4380
0.4487
0.4527
0.4610
0.4597
0.4713
0.4757
0.4843
1.1677
1.2460
1.1551
1.2554
1.2990
1.3920
1.2599
1.3773
1.4278
1.5368
1.3446
1.4348
1.3350
1.4514
1.5014
1.6069
1.4614
1.5962
1.6533
1.7754
0.5943
0.6020
0.6047
0.6153
0.6193
0.6277
0.6263
0.6380
0.6423
0.6510
1.7701
1.8560
1.7656
1.8765
1.9241
2.0251
1.8900
2.0190
2.0737
2.1910
16300
20300
11800
17200
19500
23800
13700
19800
22600
27800
0.783
0.806
0.814
0.846
0.858
0.883
0.879
0.914
0.927
0.953
0.5469
0.6228
0.5180
0.6145
0.6570
0.7470
0.6040
0.7170
0.7660
0.8720
KINGBIRD
ROOK
GOSBEAK
EGRET
CUCKOO
DRAKE
MALLARD
TERN
CONDOR
RAIL
636.
636.
636.
636.
795.
795.
795.
795.
795.
954.
18/1
24/7
26/7
30/19
24/7
26/7
30/19
45/7
54/7
45/7
0.6910
0.8190
0.8750
0.9880
1.0240
1.0940
1.2350
0.8960
1.0240
1.0750
0.7050
0.7478
0.7425
0.7643
0.8190
0.8310
0.8550
0.7973
0.8198
0.8738
1.0372
1.1590
1.1976
1.2991
1.3612
1.4238
1.5521
1.2493
1.3617
1.4353
1.0610
1.2067
1.2605
1.3825
1.4412
1.5162
1.6671
1.3042
1.4415
1.5149
0.4800
0.4990
0.4967
0.5063
0.5307
0.5360
0.5467
0.5210
0.5310
0.5550
1.3645
1.5058
1.5548
1.6723
1.7358
1.8081
1.9545
1.6044
1.7362
1.8134
1.5864
1.7498
1.8014
1.9325
2.0139
2.0938
2.2547
1.8678
2.0145
2.1103
0.6467
0.6657
0.6633
0.6730
0.6973
0.7027
0.7133
0.6877
0.6977
0.7217
2.0131
2.1721
2.2197
2.3463
2.4312
2.5086
2.6649
2.2904
2.4319
2.5302
15700
22000
25200
31500
27900
31500
38400
22100
28200
25900
0.940
0.997
0.990
1.019
1.092
1.108
1.140
1.063
1.093
1.165
0.6910
0.8190
0.8750
0.9880
1.0240
1.0940
1.2350
0.8960
1.0240
1.0750
CARDINAL
BUNTING
GRACKLE
BITTERN
PHEASANT
LAPWING
FALCON
CHUKAR
BLUEBIRD
954.
1192.5
1192.5
1272.
1272.
1590.
1590.
1780.
2156.
54/7
45/7
54/19
45/7
54/19
45/7
54/19
84/19
84/19
1.2290
1.3440
1.5330
1.4340
1.6350
1.7920
2.0440
2.0740
2.5110
0.8970
0.9765
1.0035
1.0088
1.0365
1.1265
1.1588
1.2015
1.3215
1.5715
1.7113
1.8822
1.8033
1.9859
2.1667
2.3996
2.4469
2.8875
1.6785
1.8265
2.0267
1.9299
2.1424
2.3367
2.6020
2.6498
3.1365
0.5653
0.6007
0.6127
0.6150
0.6273
0.6673
0.6817
0.7007
0.7540
1.9712
2.1227
2.3173
2.2255
2.4323
2.6301
2.8898
2.9408
3.4259
2.2835
2.4644
2.6758
2.5812
2.8052
3.0368
3.3155
3.3810
3.9175
0.7320
0.7673
0.7793
0.7817
0.7940
0.8340
0.8483
0.8673
0.9207
2.6980
2.8811
3.0870
2.9969
3.2154
3.4492
3.7223
3.7904
4.3242
33800
3200
41900
34100
43600
42200
54500
51000
60300
1.196
1.302
1.338
1.345
1.382
1.502
1.545
1.602
1.762
1.2290
1.3440
1.5330
1.4340
1.6350
1.7920
2.0440
2.0740
2.5110
Bulletin 1724E-200
Page B-4
ACSR CONDUCTORS
HIGH WIND LOADINGS
WT./FT
LBS.
0.1452
0.1831
0.2309
0.2911
0.2894
0.3673
0.3653
0.4630
0.5271
0.4316
13 psf
16 psf
21 psf
26 psf
31 psf
6 psf
TRANS RESULTANT TRANS RESULTANT TRANS RESULTANT TRANS RESULTANT TRANS RESULTANT TRANS
SWING
LB/FT
LB/FT
LB/FT
LB/FT
LB/FT
LB/FT
LB/FT
LB/FT
LB/FT
LB/FT
LB/FT
ANGLE
0.4312
0.4550
0.5307
0.5502
0.6965
0.7115
0.8623
0.8745
1.0282
1.0384
0.1990
53.88
0.4843
0.5177
0.5960
0.6235
0.7823
0.8034
0.9685
0.9857
1.1548
1.1692
0.2235
50.67
0.5438
0.5908
0.6693
0.7080
0.8785
0.9083
1.0877
1.1119
1.2968
1.3172
0.2510
47.39
0.6099
0.6758
0.7507
0.8051
0.9853
1.0274
1.2198
1.2541
1.4544
1.4833
0.2815
44.04
0.6598
0.7204
0.8120
0.8620
1.0658
1.1043
1.3195
1.3509
1.5733
1.5996
0.3045
46.46
0.6955
0.7865
0.8560
0.9315
1.1235
1.1820
1.3910
1.4387
1.6585
1.6987
0.3210
41.15
0.7410
0.8262
0.9120
0.9824
1.1970
1.2515
1.4820
1.5264
1.7670
1.8044
0.3420
43.11
0.7811
0.9080
0.9613
1.0670
1.2618
1.3440
1.5622
1.6293
1.8626
1.9193
0.3605
37.90
0.8028
0.9603
0.9880
1.1198
1.2968
1.3998
1.6055
1.6898
1.9143
1.9855
0.3705
35.10
0.8049
0.9133
0.9907
1.0806
1.3003
1.3700
1.6098
1.6667
1.9194
1.9673
0.3715
40.72
NAME
RAVEN
QUAIL
PIGEON
PENGUIN
WAXWING
PARTRIDGE
MERLIN
LINNET
ORIOLE
CHICKADEE
SIZE
1/0
2/0
4/0
266.8
266.8
336.4
336.4
336.4
397.5
397.5
STRAND
6/1
6/1
6/1
6/1
18/1
26/7
18/1
26/7
30/7
18/1
IBIS
LARK
PELICAN
FLICKER
HAWK
HEN
OSPREY
PARAKEET
DOVE
EAGLE
397.5
397.5
477.
477.
477.
477.
556.5
556.5
556.5
556.5
26/7
30/7
18/1
24/7
26/7
30/7
18/1
24/7
26/7
30/7
0.5469
0.6228
0.5180
0.6145
0.6570
0.7470
0.6040
0.7170
0.7660
0.8720
0.8483
0.8732
0.8818
0.9165
0.9295
0.9566
0.9523
0.9902
1.0043
1.0324
1.0093
1.0725
1.0227
1.1034
1.1383
1.2137
1.1277
1.2225
1.2630
1.3514
1.0440
1.0747
1.0853
1.1280
1.1440
1.1773
1.1720
1.2187
1.2360
1.2707
1.1786
1.2421
1.2026
1.2845
1.3192
1.3943
1.3185
1.4139
1.4541
1.5411
1.3703
1.4105
1.4245
1.4805
1.5015
1.5453
1.5383
1.5995
1.6223
1.6678
1.4754
1.5419
1.5158
1.6030
1.6389
1.7163
1.6526
1.7529
1.7940
1.8820
1.6965
1.7463
1.7637
1.8330
1.8590
1.9132
1.9045
1.9803
2.0085
2.0648
1.7825
1.8541
1.8382
1.9333
1.9717
2.0538
1.9980
2.1061
2.1496
2.2414
2.0228
2.0822
2.1028
2.1855
2.2165
2.2811
2.2708
2.3612
2.3948
2.4619
2.0954
2.1733
2.1657
2.2702
2.3118
2.4003
2.3497
2.4676
2.5143
2.6118
0.3915
0.4030
0.4070
0.4230
0.4290
0.4415
0.4395
0.4570
0.4635
0.4765
35.60
32.91
38.16
34.54
33.14
30.58
36.04
32.51
31.18
28.65
KINGBIRD
ROOK
GOSBEAK
EGRET
CUCKOO
DRAKE
MALLARD
TERN
CONDOR
RAIL
636.
636.
636.
636.
795.
795.
795.
795.
795.
954.
18/1
24/7
26/7
30/19
24/7
26/7
30/19
45/7
54/7
45/7
0.6910
0.8190
0.8750
0.9880
1.0240
1.0940
1.2350
0.8960
1.0240
1.0750
1.0183
1.0801
1.0725
1.1039
1.1830
1.2003
1.2350
1.1516
1.1841
1.2621
1.2306
1.3555
1.3842
1.4815
1.5646
1.6241
1.7466
1.4591
1.5654
1.6579
1.2533
1.3293
1.3200
1.3587
1.4560
1.4773
1.5200
1.4173
1.4573
1.5533
1.4312
1.5614
1.5837
1.6799
1.7800
1.8383
1.9585
1.6768
1.7811
1.8890
1.6450
1.7448
1.7325
1.7833
1.9110
1.9390
1.9950
1.8603
1.9128
2.0388
1.7842
1.9274
1.9409
2.0387
2.1681
2.2263
2.3463
2.0648
2.1696
2.3048
2.0367
2.1602
2.1450
2.2078
2.3660
2.4007
2.4700
2.3032
2.3682
2.5242
2.1507
2.3102
2.3166
2.4188
2.5781
2.6382
2.7615
2.4713
2.5801
2.7435
2.4283
2.5756
2.5575
2.6324
2.8210
2.8623
2.9450
2.7461
2.8236
3.0096
2.5247
2.7027
2.7030
2.8117
3.0011
3.0643
3.1935
2.8886
3.0035
3.1958
0.4700
0.4985
0.4950
0.5095
0.5460
0.5540
0.5700
0.5315
0.5465
0.5825
34.22
31.33
29.50
27.28
28.07
26.86
24.78
30.68
28.09
28.45
CARDINAL
BUNTING
GRACKLE
BITTERN
PHEASANT
LAPWING
FALCON
CHUKAR
BLUEBIRD
954.
1192.5
1192.5
1272.
1272.
1590.
1590.
1780.
2156.
54/7
45/7
54/19
45/7
54/19
45/7
54/19
84/19
84/19
1.2290
1.3440
1.5330
1.4340
1.6350
1.7920
2.0440
2.0740
2.5110
1.2957
1.4105
1.4495
1.4571
1.4972
1.6272
1.6738
1.7355
1.9088
1.7858
1.9483
2.1098
2.0444
2.2169
2.4205
2.6419
2.7043
3.1542
1.5947
1.7360
1.7840
1.7933
1.8427
2.0027
2.0600
2.1360
2.3493
2.0133
2.1955
2.3522
2.2962
2.4635
2.6874
2.9020
2.9772
3.4387
2.0930
2.2785
2.3415
2.3538
2.4185
2.6285
2.7038
2.8035
3.0835
2.4272
2.6454
2.7987
2.7562
2.9193
3.1812
3.3894
3.4873
3.9766
2.5913
2.8210
2.8990
2.9142
2.9943
3.2543
3.3475
3.4710
3.8177
2.8680
3.1248
3.2794
3.2479
3.4116
3.7151
3.9222
4.0434
4.5694
3.0897
3.3635
3.4565
3.4746
3.5702
3.8802
3.9913
4.1385
4.5518
3.3251
3.6221
3.7812
3.7589
3.9267
4.2740
4.4842
4.6291
5.1985
0.5980
0.6510
0.6690
0.6725
0.6910
0.7510
0.7725
0.8010
0.8810
25.95
25.84
23.58
25.13
22.91
22.74
20.70
21.12
19.33
Bulletin 1724E-200
Page B-5
ACSR CONDUCTORS
MISCELLANEOUS LOADINGS
DIAM. WT./FT
NAME
SIZE STRAND IN.
LBS.
RAVEN
1/0
6/1
0.398 0.1452
QUAIL
2/0
6/1
0.447 0.1831
PIGEON
4/0
6/1
0.502 0.2309
PENGUIN 266.8
6/1
0.563 0.2911
WAXWING 266.8
18/1
0.609 0.2894
PARTRIDG 336.4
26/7
0.642 0.3673
MERLIN
336.4
18/1
0.684 0.3653
LINNET
336.4
26/7
0.721 0.4630
ORIOLE
397.5
30/7
0.741 0.5271
18/1
0.743 0.4316
CHICKADE 397.5
0.75 INCH ICE 1PSF
1 INCH ICE
1PSF
1.25 INCH ICE
1PSF
WT./FT
TRANS
WT./FT
TRANS
WT./FT
TRANS
LBS.
LB/FT
LBS.
LB/FT
LBS.
LB/FT
1.2159
0.1582
1.8837
0.1998
2.7069
0.2415
1.2995
0.1623
1.9825
0.2039
2.8210
0.2456
1.3986
0.1668
2.0987
0.2085
2.9543
0.2502
1.5157
0.1719
2.2348
0.2136
3.1093
0.2553
1.5569
0.1758
2.2903
0.2174
3.1791
0.2591
1.6656
0.1785
2.4092
0.2202
3.3083
0.2618
1.7027
0.1820
2.4594
0.2237
3.3716
0.2653
1.8349
0.1851
2.6031
0.2268
3.5268
0.2684
1.9177
0.1868
2.6921
0.2284
3.6220
0.2701
1.8241
0.1869
2.5991
0.2286
3.5296
0.2703
IBIS
LARK
PELICAN
FLICKER
HAWK
HEN
OSPREY
PARAKEE
DOVE
EAGLE
397.5
397.5
477.
477.
477.
477.
556.5
556.5
556.5
556.5
26/7
30/7
18/1
24/7
26/7
30/7
18/1
24/7
26/7
30/7
0.783
0.806
0.814
0.846
0.858
0.883
0.879
0.914
0.927
0.953
0.5469
0.6228
0.5180
0.6145
0.6570
0.7470
0.6040
0.7170
0.7660
0.8720
1.9767
2.0740
1.9767
2.1030
2.1567
2.2700
2.1233
2.2689
2.3301
2.4603
0.1903
0.1922
0.1928
0.1955
0.1965
0.1986
0.1983
0.2012
0.2023
0.2044
2.7641
2.8686
2.7738
2.9101
2.9675
3.0886
2.9406
3.0971
3.1623
3.3006
0.2319
0.2338
0.2345
0.2372
0.2382
0.2403
0.2399
0.2428
0.2439
0.2461
3.7071
3.8187
3.7264
3.8726
3.9337
4.0626
3.9134
4.0808
4.1500
4.2964
0.2736
0.2755
0.2762
0.2788
0.2798
0.2819
0.2816
0.2845
0.2856
0.2878
KINGBIRD
ROOK
GOSBEAK
EGRET
CUCKOO
DRAKE
MALLARD
TERN
CONDOR
RAIL
636.
636.
636.
636.
795.
795.
795.
795.
795.
954.
18/1
24/7
26/7
30/19
24/7
26/7
30/19
45/7
54/7
45/7
0.940
0.997
0.990
1.019
1.092
1.108
1.140
1.063
1.093
1.165
0.6910
0.8190
0.8750
0.9880
1.0240
1.0940
1.2350
0.8960
1.0240
1.0750
2.2672
2.4484
2.4978
2.6379
2.7420
2.8269
2.9977
2.5869
2.7429
2.8610
0.2033
0.2081
0.2075
0.2099
0.2160
0.2173
0.2200
0.2136
0.2161
0.2221
3.1035
3.3024
3.3497
3.4987
3.6255
3.7154
3.8962
3.4614
3.6267
3.7673
0.2450
0.2498
0.2492
0.2516
0.2577
0.2590
0.2617
0.2553
0.2578
0.2638
4.0952
4.3118
4.3569
4.5150
4.6645
4.7594
4.9501
4.4914
4.6660
4.8290
0.2867
0.2914
0.2908
0.2933
0.2993
0.3007
0.3033
0.2969
0.2994
0.3054
CARDINAL
BUNTING
GRACKLE
BITTERN
PHEASAN
LAPWING
FALCON
CHUKAR
BLUEBIRD
954.
1192.5
1192.5
1272.
1272.
1590.
1590.
1780.
2156.
54/7
45/7
54/19
45/7
54/19
45/7
54/19
84/19
84/19
1.196
1.302
1.338
1.345
1.382
1.502
1.545
1.602
1.762
1.2290
1.3440
1.5330
1.4340
1.6350
1.7920
2.0440
2.0740
2.5110
3.0440
3.2578
3.4804
3.3879
3.6234
3.8924
4.1845
4.2676
4.8538
0.2247
0.2335
0.2365
0.2371
0.2402
0.2502
0.2538
0.2585
0.2718
3.9598
4.2066
4.4404
4.3501
4.5971
4.9034
5.2088
5.3097
5.9457
0.2663
0.2752
0.2782
0.2788
0.2818
0.2918
0.2954
0.3002
0.3135
5.0311
5.3109
5.5559
5.4678
5.7263
6.0698
6.3886
6.5072
7.1930
0.3080
0.3168
0.3198
0.3204
0.3235
0.3335
0.3371
0.3418
0.3552
Transverse loadings are based on 1 psf on
the indicated ice condition. Transverse
loadings other than 1psf can be obtained by
multiplying the transverse loading value in the
table by the amount of the expected wind load
For example, the transverse load caused by a
6 psf wind on a 477 kcmil 26/7 conductor
covered by 1 inch of radial ice is:
.2382(6) = 1.4292 lb/ft.
Bulletin 1724E-200
Page B-6
6201 A LUM INUM A LLO Y CO NDUCTO RS
NE S C DIS TRICT LO A DING S
NA M E
A ZUS A
A NA HE IM
A M HE RS T
A LLIA NCE
B UTTE
CA NTO N
CA IRO
DA RIE N
E LO IN
F LINT
G RE E LE Y
S IZE
123.3
155.4
195.7
246.9
312.8
394.5
465.4
559.5
652.4
740.8
927.2
LIG HT
.00" ICE , 9 LB ., K = .05
V E RT.
TRA NS RE S ULTA NT
LB /FT
LB /FT
LB /FT
0.1157
0.2985
0.3701
0.1459
0.3353
0.4156
0.1837
0.3765
0.4689
0.2318
0.4223
0.5317
0.2936
0.4815
0.6140
0.3703
0.5408
0.7054
0.4369
0.5873
0.7819
0.5252
0.6435
0.8806
0.6124
0.6953
0.9765
0.6954
0.7433
1.0678
0.8704
0.8310
1.2534
S TRA ND
7
7
7
7
19
19
19
19
19
37
37
M E DIUM
.25" ICE , 4 LB W IND, K = .20
V E RT.
TRA NS RE S ULTA NT
LB /FT
LB /F T
LB /F T
0.3172
0.2993
0.6361
0.3626
0.3157
0.6807
0.4175
0.3340
0.7347
0.4846
0.3543
0.8003
0.5709
0.3807
0.8862
0.6722
0.4070
0.9858
0.7580
0.4277
1.0704
0.8697
0.4527
1.1804
0.9783
0.4757
1.2878
1.0812
0.4970
1.3900
1.2926
0.5360
1.5993
HE A V Y
.5" ICE , 4 LB W IND, K = .30
V E RT.
TRA NS RE S ULTA NT
LB /F T
LB /FT
LB /FT
0.6741
0.4660
1.1195
0.7347
0.4823
1.1789
0.8067
0.5007
1.2495
0.8927
0.5210
1.3337
1.0037
0.5473
1.4432
1.1295
0.5737
1.5668
1.2346
0.5943
1.6702
1.3696
0.6193
1.8031
1.4997
0.6423
1.9314
1.6225
0.6637
2.0530
1.8702
0.7027
2.2979
6201 A LUM INUM A LLO Y CO NDUCTO RS
HIG H W IND LO A DING S
NA M E
A ZUS A
A NA HE IM
A M HE RS T
A LLIA NCE
B UTTE
CA NTO N
CA IRO
DA RIE N
E LO IN
F LINT
G RE E LE Y
S IZE
123.3
155.4
195.7
246.9
312.8
394.5
465.4
559.5
652.4
740.8
927.2
W T./F T
LB S .
0.1157
0.1459
0.1837
0.2318
0.2936
0.3703
0.4369
0.5252
0.6124
0.6954
0.8704
S TRA ND
7
7
7
7
19
19
19
19
19
37
37
13 ps f
16 ps f
21 ps f
26 ps f
31 ps f
TRA NS RE S ULTA NT TRA NS RE S ULTA NT TRA NS RE S ULTA NT TRA NS RE S ULTA NT TRA NS RE S ULTA NT
LB /FT
LB /FT
LB /FT
LB /FT
LB /F T
LB /F T
LB /F T
LB /F T
LB /FT
LB /FT
0.4312
0.4464
0.5307
0.5431
0.6965
0.7060
0.8623
0.8701
1.0282
1.0347
0.4843
0.5058
0.5960
0.6136
0.7823
0.7957
0.9685
0.9794
1.1548
1.1639
0.5438
0.5740
0.6693
0.6941
0.8785
0.8975
1.0877
1.1031
1.2968
1.3098
0.6099
0.6525
0.7507
0.7856
0.9853
1.0122
1.2198
1.2417
1.4544
1.4728
0.6955
0.7549
0.8560
0.9050
1.1235
1.1612
1.3910
1.4216
1.6585
1.6843
0.7811
0.8644
0.9613
1.0302
1.2618
1.3150
1.5622
1.6055
1.8626
1.8990
0.8483
0.9542
1.0440
1.1317
1.3703
1.4382
1.6965
1.7519
2.0228
2.0694
0.9295
1.0676
1.1440
1.2588
1.5015
1.5907
1.8590
1.9318
2.2165
2.2779
1.0043
1.1762
1.2360
1.3794
1.6223
1.7340
2.0085
2.0998
2.3948
2.4718
1.0736
1.2791
1.3213
1.4932
1.7343
1.8685
2.1472
2.2570
2.5601
2.6528
1.2003
1.4827
1.4773
1.7147
1.9390
2.1254
2.4007
2.5536
2.8623
2.9917
6201 A LUM INUM A LLO Y CO NDUCTO RS - M IS CE LLA NE O US LO A DING S
NA M E
S IZE
S TRA ND
A ZUS A
A NA HE IM
A M HE RS T
A LLIA NCE
B UTTE
CA NTO N
CA IRO
DA RIE N
E LO IN
F LINT
G RE E LE Y
123.3
155.4
195.7
246.9
312.8
394.5
465.4
559.5
652.4
740.8
927.2
7
7
7
7
19
19
19
19
19
37
37
0.75 " ICE
W T./F T
TRA NS
LB S .
for 1ps f
LB /FT
1.1864
0.1582
1.2623
0.1623
1.3514
0.1668
1.4564
0.1719
1.5919
0.1785
1.7422
0.1851
1.8667
0.1903
2.0249
0.1965
2.1765
0.2023
2.3192
0.2076
2.6033
0.2173
1.0 " ICE
W T./F T
TRA NS
LB S .
for 1ps f
LB /FT
1.8542
0.1998
1.9453
0.2039
2.0515
0.2085
2.1755
0.2136
2.3355
0.2202
2.5104
0.2268
2.6541
0.2319
2.8357
0.2382
3.0087
0.2439
3.1713
0.2493
3.4918
0.2590
1.25 " ICE
W T./FT
TRA NS
LB S .
for 1ps f
LB /FT
2.6774
0.2415
2.7838
0.2456
2.9071
0.2502
3.0500
0.2553
3.2346
0.2618
3.4341
0.2684
3.5971
0.2736
3.8020
0.2798
3.9964
0.2856
4.1789
0.2909
4.5358
0.3007
Trans vers e Loadings other than 1 ps f on the indic ated ic e
c ondition c an be obtained by m ultiply ing the trans vers e l
value in the table by the am ount of the ex pec ted wind loa
per foot.
For ex am ple, the trans vers e load c aus ed by a 6 ps f wind
wind on a 559.5 k c m il c onduc tor c overed by 1 inc h of rad
.2382(6) = 1.4292 lb/ft.
Bulletin 1724E-200
Page B-7
1350 ALUMINUM ALLOY CONDUCTORS
NESC DISTRICT LOADINGS
NAME
POPPY
ASTRE
PHLOX
OXLIP
VALERIAN
DAISY
LAUREL
TULIP
CANNA
GOLDENTUFT
COSMOS
SYRINGA
DAHLIA
MISTLETOE
ORCHID
ARBUTUS
LILAC
ANEMONE
CROCUS
MAGNOLIA
GOLDENROD
HAWTHORN
NARCESSUS
COREOPSIS
SIZE
1/0
2/0
3/0
4/0
250.
266.8
266.8
336.4
397.5
450.
477.
477.
556.5
556.5
636.
795.
795.
874.5
874.5
954.
954.
1192.5
1272.
1590
STRAND
7
7
7
7
19
7
19
19
19
19
19
37
19
37
37
37
61
37
61
37
61
61
61
61
LIGHT
.00" ICE, 9 LB., K=.05
VERT.
TRANS RESULTANT
LB/FT
LB/FT
LB/FT
0.0991
0.2760
0.3433
0.1249
0.3105
0.3847
0.1575
0.3480
0.4320
0.1986
0.3915
0.4890
0.2347
0.4305
0.5403
0.2505
0.4395
0.5559
0.2505
0.4448
0.5604
0.3128
0.4995
0.6394
0.3731
0.5430
0.7088
0.4224
0.5775
0.7655
0.4478
0.5948
0.7945
0.4478
0.5963
0.7957
0.5220
0.6420
0.8774
0.5220
0.6435
0.8786
0.5970
0.6885
0.9613
0.7460
0.7695
1.1217
0.7460
0.7710
1.1228
0.8210
0.8078
1.2017
0.8210
0.8085
1.2023
0.8960
0.8430
1.2802
0.8960
0.8445
1.2813
1.1190
0.9435
1.5137
1.1920
0.9750
1.5900
1.4900
1.0898
1.8960
MEDIUM
.25" ICE, 4 LB WIND, K=.20
VERT.
TRANS RESULTANT
LB/FT
LB/FT
LB/FT
0.2912
0.2893
0.6105
0.3313
0.3047
0.6501
0.3795
0.3213
0.6972
0.4386
0.3407
0.7554
0.4909
0.3580
0.8076
0.5104
0.3620
0.8257
0.5126
0.3643
0.8289
0.5976
0.3887
0.9128
0.6759
0.4080
0.9895
0.7395
0.4233
1.0521
0.7721
0.4310
1.0842
0.7727
0.4317
1.0851
0.8658
0.4520
1.1767
0.8665
0.4527
1.1776
0.9601
0.4727
1.2702
1.1427
0.5087
1.4508
1.1433
0.5093
1.4516
1.2335
0.5257
1.5409
1.2339
0.5260
1.5413
1.3232
0.5413
1.6296
1.3238
0.5420
1.6304
1.5878
0.5860
1.8925
1.6739
0.6000
1.9782
2.0194
0.6510
2.3218
HEAVY
.5" ICE, 4 LB WIND, K=.30
VERT.
TRANS RESULTANT
LB/FT
LB/FT
LB/FT
0.6388
0.4560
1.0849
0.6932
0.4713
1.1383
0.7569
0.4880
1.2006
0.8341
0.5073
1.2762
0.9025
0.5247
1.3439
0.9257
0.5287
1.3661
0.9301
0.5310
1.3710
1.0378
0.5553
1.4770
1.1342
0.5747
1.5714
1.2121
0.5900
1.6480
1.2518
0.5977
1.6871
1.2530
0.5983
1.6885
1.3651
0.6187
1.7988
1.3664
0.6193
1.8002
1.4787
0.6393
1.9110
1.6948
0.6753
2.1244
1.6961
0.6760
2.1258
1.8015
0.6923
2.2300
1.8022
0.6927
2.2307
1.9058
0.7080
2.3330
1.9070
0.7087
2.3344
2.2121
0.7527
2.6366
2.3112
0.7667
2.7350
2.7043
0.8177
3.1252
ULTIMATE
STRENGTH
LBS.
1990
2510
3040
3830
4660
4830
4970
6150
7110
7890
8360
8690
9750
9940
11400
13900
14300
15000
15800
16400
16900
21100
22000
27000
1350 ALUMINUM ALLOY CONDUCTORS
HIGH WIND LOADINGS
NAME
POPPY
ASTER
PHLOX
OXLIP
DAISY
LAUREL
TULIP
CANNA
GOLDENTUFT
COSMOS
SYRINGA
DAHLIA
MISTLETOE
ORCHID
ARBUTUS
LILAC
ANEMONE
CROCUS
MAGNOLIA
GOLDENROD
HAWTHORN
NARCESSUS
COREOPSIS
SIZE
1/0
2/0
3/0
4/0
266.8
266.8
336.4
397.5
450.
477.
477.
556.5
556.5
636.
795.
795.
874.5
874.5
954.
954.
1192.5
1272.
1590
STRAND
7
7
7
7
7
19
19
19
19
19
37
19
37
37
37
61
37
61
37
61
61
61
61
WT./FT
LBS.
0.0991
0.1249
0.1575
0.1986
0.2505
0.2505
0.3128
0.3731
0.4224
0.4478
0.4478
0.5220
0.5220
0.5970
0.7460
0.7460
0.8210
0.8210
0.8960
0.8960
1.1190
1.1920
1.1940
13 psf
TRANS RESULTANT
LB/FT
LB/FT
0.3987
0.4108
0.4485
0.4656
0.5027
0.5268
0.5655
0.5994
0.6348
0.6825
0.6424
0.6895
0.7215
0.7864
0.7843
0.8686
0.8342
0.9350
0.8591
0.9688
0.8613
0.9707
0.9273
1.0642
0.9295
1.0660
0.9945
1.1599
1.1115
1.3386
1.1137
1.3404
1.1668
1.4267
1.1678
1.4275
1.2177
1.5118
1.2198
1.5135
1.3628
1.7634
1.4083
1.8451
1.5741
1.9757
16 psf
TRANS RESULTANT
LB/FT
LB/FT
0.4907
0.5006
0.5520
0.5660
0.6187
0.6384
0.6960
0.7238
0.7813
0.8205
0.7907
0.8294
0.8880
0.9415
0.9653
1.0349
1.0267
1.1102
1.0573
1.1483
1.0600
1.1507
1.1413
1.2550
1.1440
1.2575
1.2240
1.3618
1.3680
1.5582
1.3707
1.5605
1.4360
1.6541
1.4373
1.6553
1.4987
1.7461
1.5013
1.7484
1.6773
2.0163
1.7333
2.1036
1.9373
2.2757
21 psf
TRANS RESULTANT
LB/FT
LB/FT
0.6440
0.6516
0.7245
0.7352
0.8120
0.8271
0.9135
0.9348
1.0255
1.0557
1.0378
1.0676
1.1655
1.2067
1.2670
1.3208
1.3475
1.4122
1.3878
1.4582
1.3913
1.4615
1.4980
1.5863
1.5015
1.5896
1.6065
1.7138
1.7955
1.9443
1.7990
1.9475
1.8848
2.0558
1.8865
2.0574
1.9670
2.1615
1.9705
2.1646
2.2015
2.4696
2.2750
2.5684
2.5428
2.8091
26 psf
TRANS RESULTANT
LB/FT
LB/FT
0.7973
0.8035
0.8970
0.9057
1.0053
1.0176
1.1310
1.1483
1.2697
1.2941
1.2848
1.3090
1.4430
1.4765
1.5687
1.6124
1.6683
1.7210
1.7182
1.7756
1.7225
1.7798
1.8547
1.9267
1.8590
1.9309
1.9890
2.0767
2.2230
2.3448
2.2273
2.3489
2.3335
2.4737
2.3357
2.4758
2.4353
2.5949
2.4397
2.5990
2.7257
2.9464
2.8167
3.0585
3.1482
3.3670
31 psf
TRANS RESULTANT
LB/FT
LB/FT
0.9507
0.9558
1.0695
1.0768
1.1987
1.2090
1.3485
1.3630
1.5138
1.5344
1.5319
1.5523
1.7205
1.7487
1.8703
1.9072
1.9892
2.0335
2.0486
2.0970
2.0538
2.1020
2.2113
2.2721
2.2165
2.2771
2.3715
2.4455
2.6505
2.7535
2.6557
2.7585
2.7823
2.9009
2.7848
2.9033
2.9037
3.0388
2.9088
3.0437
3.2498
3.4371
3.3583
3.5636
3.7536
3.9389
6 psf
TRANS
SWING
LB/FT
ANGLE
0.1840
61.7
0.2070
58.9
0.2320
55.8
0.2610
52.7
0.2930
49.5
0.2965
49.8
0.3330
46.8
0.3620
44.1
0.3850
42.3
0.3965
41.5
0.3975
41.6
0.4280
39.3
0.4290
39.4
0.4590
37.6
0.5130
34.5
0.5140
34.6
0.5385
33.3
0.5390
33.3
0.5620
32.1
0.5630
32.1
0.6290
29.3
0.6500
28.6
0.7265
31.3
DIAM.
WT./FT
IN.
LBS.
0.368
0.0991
0.414
0.1249
0.464
0.1575
0.522
0.1986
0.574
0.2347
0.586
0.2505
0.593
0.2505
0.666
0.3128
0.724
0.3731
0.770
0.4224
0.793
0.4478
0.795
0.4478
0.856
0.5220
0.858
0.5220
0.918
0.5970
1.026
0.7460
1.028
0.7460
1.077
0.8210
1.078
0.8210
1.124
0.8960
1.126
0.8960
1.258
1.1190
1.300
1.1920
1.453
1.4900
Bulletin 1724E-200
Page B-8
1350 ALUMINUM ALLOY CONDUCTORS
MISCELLANEOUS LOADINGS
NAME
POPPY
ASTRE
PHLOX
OXLIP
VALERIAN
DAISY
LAUREL
TULIP
CANNA
GOLDENTUFT
COSMOS
SYRINGA
DAHLIA
MISTLETOE
ORCHID
ARBUTUS
LILAC
ANEMONE
CROCUS
MAGNOLIA
GOLDENROD
HAWTHORN
SIZE
STRAND
1/0
2/0
3/0
4/0
250.
266.8
266.8
336.4
397.5
450.
477.
477.
556.5
556.5
636.
795.
795.
874.5
874.5
954.
954.
1192.5
7
7
7
7
19
7
19
19
19
19
19
37
19
37
37
37
61
37
61
37
61
61
DIAM.
WT./FT
IN.
LBS.
0.368 0.0991
0.414 0.1249
0.464 0.1575
0.522 0.1986
0.574 0.2347
0.586 0.2505
0.593 0.2505
0.666 0.3128
0.724 0.3731
0.770 0.4224
0.793 0.4478
0.795 0.4478
0.856 0.5220
0.858 0.5220
0.918 0.5970
1.026 0.7460
1.028 0.7460
1.077 0.8210
1.078 0.8210
1.124 0.8960
1.126 0.8960
1.258 1.1190
.75 " ICE
1.0 " ICE
1.25 " ICE
WT./FT
TRANS WT./FT
TRANS WT./FT
TRANS
LBS.
for 1psf
LBS.
for 1psf
LBS.
for 1psf
LB/FT
LB/FT
LB/FT
1.1418
0.1557
1.8003
0.1973
2.6142
0.2390
1.2105
0.1595
1.8833
0.2012
2.7115
0.2428
1.2898
0.1637
1.9781
0.2053
2.8218
0.2470
1.3849
0.1685
2.0913
0.2102
2.9531
0.2518
1.4695
0.1728
2.1920
0.2145
3.0700
0.2562
1.4965
0.1738
2.2228
0.2155
3.1044
0.2572
1.5031
0.1744
2.2315
0.2161
3.1153
0.2578
1.6335
0.1805
2.3846
0.2222
3.2911
0.2638
1.7478
0.1853
2.5170
0.2270
3.4416
0.2687
1.8400
0.1892
2.6235
0.2308
3.5624
0.2725
1.8869
0.1911
2.6775
0.2328
3.6235
0.2744
1.8888
0.1913
2.6800
0.2329
3.6266
0.2746
2.0199
0.1963
2.8300
0.2380
3.7956
0.2797
2.0217
0.1965
2.8325
0.2382
3.7988
0.2798
2.1527
0.2015
2.9821
0.2432
3.9670
0.2848
2.4024
0.2105
3.2654
0.2522
4.2839
0.2938
2.4043
0.2107
3.2679
0.2523
4.2870
0.2940
2.5250
0.2148
3.4039
0.2564
4.4382
0.2981
2.5259
0.2148
3.4051
0.2565
4.4397
0.2982
2.6438
0.2187
3.5373
0.2603
4.5862
0.3020
2.6457
0.2188
3.5398
0.2605
4.5893
0.3022
2.9918
0.2298
3.9269
0.2715
5.0175
0.3132
Bulletin 1724E-200
Page B-9
SIZE
3/8
7/16
3/8
7/16
7 NO. 9
7 NO. 8
7 NO. 7
STRAND
7
7
7
7
LIGHT
.00" ICE, 9 LB., K=.05
VERT.
TRANS RESULTANT
LB/FT
LB/FT
LB/FT
0.2730
0.2700
0.4340
0.3990
0.3263
0.5654
0.2730
0.2700
0.4340
0.3990
0.3263
0.5654
0.2076
0.2573
0.3806
0.2618
0.2888
0.4398
0.3300
0.3248
0.5130
MEDIUM
.25" ICE, 4 LB WIND, K=.20
VERT.
TRANS RESULTANT
LB/FT
LB/FT
LB/FT
0.4626
0.2867
0.7443
0.6120
0.3117
0.8868
0.4626
0.2867
0.7443
0.6120
0.3117
0.8868
0.3920
0.2810
0.6823
0.4592
0.2950
0.7458
0.5423
0.3110
0.8252
HEAVY
.5" ICE, 4 LB WIND, K=.30
VERT.
TRANS RESULTANT
LB/FT
LB/FT
LB/FT
0.8077
0.4533
1.2262
0.9804
0.4783
1.3908
0.8077
0.4533
1.2262
0.9804
0.4783
1.3908
0.7318
0.4477
1.1578
0.8121
0.4617
1.2341
0.9101
0.4777
1.3278
ULTIMATE
STRENGTH
LBS.
10800
14500
15400
20800
12630
15930
19060
OVERHEAD GROUND WIRES
HIGH WIND LOADINGS
SIZE
3/8
7/16
3/8
7/16
7 NO. 9
7 NO. 8
7 NO. 7
STRAND
7
7
7
7
13 psf
16 psf
21 psf
26 psf
31 psf
6 psf
WT./FT
TRANS RESULTANT TRANS RESULTANT TRANS RESULTANT TRANS RESULTANT TRANS RESULTANT TRANS
SWING
LBS.
LB/FT
LB/FT
LB/FT
LB/FT
LB/FT
LB/FT
LB/FT
LB/FT
LB/FT
LB/FT
LB/FT
ANGLE
0.2730
0.3900
0.4761
0.4800
0.5522
0.6300
0.6866
0.7800
0.8264
0.9300
0.9692
0.1800
33.4
0.3990
0.4713
0.6175
0.5800
0.7040
0.7613
0.8595
0.9425
1.0235
1.1238
1.1925
0.2175
28.6
0.2730
0.3900
0.4761
0.4800
0.5522
0.6300
0.6866
0.7800
0.8264
0.9300
0.9692
0.1800
33.4
0.3990
0.4713
0.6175
0.5800
0.7040
0.7613
0.8595
0.9425
1.0235
1.1238
1.1925
0.2175
28.6
0.2076
0.3716
0.4256
0.4573
0.5022
0.6003
0.6351
0.7432
0.7716
0.8861
0.9101
0.1715
39.6
0.2618
0.4171
0.4924
0.5133
0.5762
0.6738
0.7228
0.8342
0.8743
0.9946
1.0285
0.1925
36.3
0.3300
0.4691
0.5735
0.5773
0.6650
0.7578
0.8265
0.9382
0.9945
1.1186
1.1662
0.2165
33.3
OVERHEAD GROUND WIRES - MISCELLANEOUS LOADINGS
SIZE
STRAND
3/8
7/16
3/8
7/16
7 NO. 9
7 NO. 8
7 NO. 7
7
7
7
7
0.75 " ICE
1.0 " ICE
WT./FT
TRANS WT./FT
TRANS
LBS.
for 1psf
LBS.
for 1psf
LB/FT
LB/FT
1.3083
0.1550
1.9642
0.1967
1.5042
0.1613
2.1835
0.2029
1.3083
0.1550
1.9642
0.1967
1.5042
0.1613
2.1835
0.2029
1.2270
0.1536
1.8777
0.1953
1.3204
0.1571
1.9841
0.1988
1.4333
0.1611
2.1120
0.2028
1.25 " ICE
WT./FT
TRANS
LBS.
for 1psf
LB/FT
2.7756
0.2383
3.0182
0.2446
2.7756
0.2383
3.0182
0.2446
2.6838
0.2369
2.8033
0.2404
2.9461
0.2444
Transverse Loadings other than 1 psf on the indicated ice
condition can be obtained by multiplying the transverse loading
value in the table by the amount of the expected wind load
per foot.
For example, the transverse load caused by a 6 psf wind on
3/8" HIGH STRENGTH STEEL OHGW covered by 1 inch of radial ice is:
.1967(6) = 1.1802 lb/ft.
Bulletin 1724E-200
Page B-10
Blank Page
Bulletin 1724E-200
Page C-1
APPENDIX C
INSULATION TABLES
•
Flashover Data For Porcelain String
5-3/4”X 10” Standard Suspension Insulators
C-2
•
Flashover Data For Suspension Polymers
ANSI C29.12-1997
C-3
•
Approximate Weights and Length of Insulator Strings Using
Standard 5-3/4 in. x 10 in. Suspension Bells
C-4
Bulletin 1724E-200
Page C-2
TABLE C-1
FLASHOVER DATA FOR PORCELAIN STRING
5-3/4”X 10” STANDARD SUSPENSION INSULATORS
60Hz
Flashover-kV
Units in
string
Impulse Flashover, kV
1.5 X 50
Dry
Wet
Positive
Negative
2
3
4
5
155
215
270
325
90
130
170
215
250
355
440
525
250
340
415
495
6
7
8
9
10
380
435
485
540
590
255
295
335
375
415
610
695
780
860
945
585
670
760
845
930
11
12
13
14
15
640
690
735
785
830
455
490
525
565
600
1025
1105
1185
1265
1345
1015
1105
1190
1275
1360
16
17
18
19
20
875
920
965
1010
1055
630
660
690
720
750
1425
1505
1585
1665
1745
1440
1530
1615
1700
1785
21
22
23
24
25
1095
1135
1175
1215
1255
775
800
825
850
875
1820
1895
1970
2045
2120
1865
1945
2025
2105
2185
Bulletin 1724E-200
Page C-3
TABLE C-2
FLASHOVER DATA FOR SUSPENSION POLYMERS
(ANSI C29.12-1997)
Electrical Values
Low Frequency flashover
Critical Impulse Flashover
ANSI
Class
Dry
(kV)
Wet
(kV)
Positive
(kV)
Negative
(kV)
60-1
60-2
60-3
60-4
60-5
60-6
60-7
60-8
60-9
60-10
60-11
60-12
60-13
60-14
365
410
470
485
560
620
670
720
810
900
925
980
1060
1345
310
350
415
455
490
545
580
620
690
755
795
830
890
1290
610
675
780
860
925
1025
1105
1185
1345
1490
1575
1665
1825
2530
585
670
760
845
930
1015
1105
1190
1360
1530
1600
1700
1870
2630
Bulletin 1724E-200
Page C-4
TABLE C-3
APPROXIMATE WEIGHTS AND LENGTHS OF
INSULATOR STRINGS USING STANDARD
5-3/4” x 10” SUSPENSION BELLS WITH A BALL HOOK*
Number of
Insulators
Length of String
(Includes Suspension
Hardware), Ft.
Weight of String
(Includes Suspension
Hardware), Lbs.
Max. Voltage- for the
Number of Insulators
(Tangent)
3
4
5
6
7
8
9
10
11
12
13
14
15
16
2.00
2.50
3.00
3.50
3.92
4.42
4.92
5.33
5.83
6.33
6.83
7.25
7.75
8.25
45
58
71
84
96
109
122
135
147
160
173
186
198
211
34.5 kV, 46 kV
69 kV
*Exact length and weight will vary slightly depending upon conductor
suspension hardware used.
115 kV
161 kV
230 kV
Bulletin 1724E-200
Page D-1
APPENDIX D
AMPACITY, MVA, SURFACE GRADIENT TABLES
•
Ampacity Of ACSR Conductors
D-2
•
MVA Limits
D-3
Bulletin 1724E-200
Page D-2
TABLE D-1
AMPACITY OF ACSR CONDUCTORS
Conductor Temperature
Summer ambient
Winter ambient
Wind (ft./sec.)
NAME
RAVEN
QUAIL
PIGEON
PENGUIN
WAXWING
PARTRIDGE
MERLIN
LINNET
ORIOLE
CHICKADEE
IBIS
LARK
PELICAN
FLICKER
HAWK
HEN
OSPREY
PARAKEET
DOVE
EAGLE
KINGBIRD
ROOK
GOSBEAK
EGRET
CUCKOO
DRAKE
MALLARD
TERN
CONDOR
RAIL
CARDINAL
BUNTING
GRACKLE
BITTERN
PHEASANT
LAPWING
FALCON
CHUKAR
BLUEBIRD
SIZE
1/0
2/0
3/0
4/0
266.8
266.8
336.4
336.4
397.5
397.5
397.5
397.5
477.
477.
477.
477.
556.5
556.5
556.5
556.5
636.
636.
636.
636.
795.
795.
795.
795.
795.
954.
954.
1192.5
1192.5
1272.
1272.
1590.
1590.
1780.
2156
120ºF
104ºF
32ºF
2
STRAND
6/1
6/1
6/1
6/1
18/1
26/7
18/1
26/7
30/7
18/1
26/7
30/7
18/1
24/7
26/7
30/7
18/1
24/7
26/7
30/7
18/1
24/7
26/7
30/19
24/7
26/7
30/19
45/7
54/7
45/7
54/7
45/7
54/19
45/7
54/19
45/7
54/19
84/19
84/19
167ºF
212ºF
104ºF
104ºF
32ºF
32ºF
2
2
Ampacity
Summer Rating
120
167
212
Deg F
Deg F
Deg F
70
195
257
77
223
294
85
255
338
92
291
386
110
359
478
108
364
484
119
416
554
117
420
561
115
423
565
120
461
616
122
466
624
120
469
629
131
516
692
128
521
699
127
522
701
124
526
706
135
568
763
130
573
771
129
575
774
126
579
779
136
617
815
131
623
839
129
625
843
125
629
849
126
715
967
123
718
972
116
723
979
131
709
959
126
715
967
120
793
1076
112
800
1086
84
908
1238
65
927
1264
61
944
1289
21
964
1317
1079
1480
1103
1514
1168
1608
1304
1803
ft./sec.
Ampacity
Winter Rating
120
167
212
Deg F
Deg F
Deg F
240
292
330
275
335
379
315
384
435
357
439
497
442
543
616
447
550
624
511
630
715
517
637
724
520
642
729
544
700
795
574
708
806
578
714
812
636
786
894
641
793
902
644
796
906
648
801
913
700
866
986
706
874
996
709
878
1000
713
884
1007
761
943
1053
768
952
1085
770
955
1089
776
962
1097
882
1096
1251
886
1101
1257
892
1110
1267
874
1086
1240
882
1096
1251
978
1218
1393
987
1229
1406
1121
1400
1604
1144
1429
1637
1165
1457
1670
1190
1489
1706
1330
1670
1919
1361
1709
1963
1440
1813
2085
1606
2030
2340
Bulletin 1724E-200
Page D-3
TABLE D-2: MVA LIMITS
MVA LIMIT FOR 212 DEGREE F OPERATION AT THE INDICATED VOLTAGE
(S = Summer; W = Winter)
CONDUCTOR
SIZE &
NAME
STRAND
RAVEN
QUAIL
PIGEON
PENGUIN
WAXWING
PARTRIDGE
MERLIN
LINNET
ORIOLE
CHICKADEE
IBIS
LARK
PELICAN
FLICKER
HAWK
HEN
OSPREY
PARAKEET
DOVE
EAGLE
KINGBIRD
ROOK
GOSBEAK
EGRET
CUCKOO
DRAKE
MALLARD
TERN
CONDOR
RAIL
CARDINAL
BUNTING
GRACKLE
BITTERN
PHEASANT
LAPWING
FALCON
CHUKAR
BLUEBIRD
1/0
2/0
3/0
4/0
266.8
266.8
336.4
336.4
397.5
397.5
397.5
397.5
477.
477.
477.
477.
556.5
556.5
556.5
556.5
636.
636.
636.
636.
795.
795.
795.
795.
795.
954.
954.
1192.5
1192.5
1272.
1272.
1590.
1590.
1780.
2156
6/1
6/1
6/1
6/1
18/1
26/7
18/1
26/7
30/7
18/1
26/7
30/7
18/1
24/7
26/7
30/7
18/1
24/7
26/7
30/7
18/1
24/7
26/7
30/19
24/7
26/7
30/19
45/7
54/7
45/7
54/7
45/7
54/19
45/7
54/19
45/7
54/19
84/19
84/19
34.5 kV
46 kV
69 kV
115 kV
138 kV
161 kV
230 KV
S
W
S
W
S
W
S
W
S
W
S
W
S
W
15
18
20
23
29
29
33
34
34
37
37
38
41
42
42
42
46
46
46
47
49
50
50
51
58
58
59
57
58
64
65
74
76
77
79
88
90
96
108
20
23
26
30
37
37
43
43
44
48
48
48
53
54
54
55
59
60
60
60
63
65
65
66
75
75
76
74
75
83
84
96
98
100
102
115
117
125
140
20
23
27
31
38
39
44
45
45
37
37
38
41
42
42
42
46
46
46
47
49
50
50
51
58
58
59
57
58
64
65
74
76
77
79
88
90
96
108
26
30
35
40
49
50
57
58
58
48
48
48
53
54
54
55
59
60
60
60
63
65
65
66
75
75
76
74
75
83
84
96
98
100
102
115
117
125
140
31
35
40
46
57
58
66
67
68
74
75
75
83
83
84
84
91
92
93
93
97
100
101
101
116
116
117
115
116
129
130
148
151
154
157
177
181
192
215
39
45
52
59
74
75
85
87
87
95
96
97
107
108
108
109
118
119
120
120
126
130
130
131
150
150
151
148
150
166
168
192
196
200
204
229
235
249
280
51
59
67
77
95
96
110
112
113
123
124
125
138
139
140
141
152
154
154
155
162
167
168
169
193
194
195
191
193
214
216
247
252
257
262
295
302
320
359
66
75
87
99
123
124
142
144
145
158
160
162
178
180
180
182
196
198
199
201
210
216
217
219
249
250
252
247
249
277
280
319
326
333
340
382
391
415
466
61
70
81
92
114
116
132
134
135
147
149
150
165
167
168
169
182
184
185
186
195
201
201
203
231
232
234
229
231
257
260
296
302
308
315
354
362
384
431
79
91
104
119
147
149
171
173
174
190
193
194
214
216
216
218
236
238
239
241
252
259
260
262
299
301
303
296
299
333
336
383
391
399
408
459
469
498
559
72
82
94
108
133
135
155
156
158
172
174
175
193
195
196
197
213
215
216
217
227
234
235
237
270
271
273
267
270
300
303
345
352
359
367
413
422
448
503
92
106
121
139
172
174
199
202
203
222
225
226
249
252
253
254
275
278
279
281
294
303
304
306
349
351
353
346
349
388
392
447
457
466
476
535
548
581
653
102
117
134
154
190
193
221
224
225
246
249
250
276
278
279
281
304
307
308
310
324
334
336
338
385
387
390
382
385
429
433
493
504
514
525
590
603
640
718
132
151
173
198
245
249
285
288
290
317
321
323
356
359
361
364
393
397
398
401
419
432
434
437
498
501
505
494
498
555
560
639
652
665
680
764
782
831
932
Bulletin 1724E-200
Page D-4
Blank Page
Bulletin 1724E-200
Page E-1
APPENDIX E
WEATHER DATA
•
Wind Velocities and Pressures
E-2
•
Conversion Factors for Other Mean Recurrence Intervals
E-3
•
Map of Isokeraunic Levels for the United States
E-4
Bulletin 1724E-200
Page E-2
TABLE E-1
WIND VELOCITIES AND PRESSURES
Actual Wind Velocity,
mi/hr.
psf on a Cylindrical
Surface
psf on a Flat
Surface
35
40
45
49
50
55
60
65
70
75
80
85
90
95
100
105
110
115
120
3.1
4.0
5.2
6.0
6.4
7.7
9.0
10.8
12.5
14.4
16.4
18.5
20.7
23.1
25.6
28.2
31.0
33.9
36.9
4.8
6.3
8.1
9.6
10.0
12.0
14.1
16.9
19.5
22.5
28.9
32.3
36.1
40.0
44.1
48.4
53.0
57.7
63.1
*Based on:
F = .00256V2 (for cylindrical surfaces)
Where:
F= wind force in pounds per square foot.
V= wind velocity in miles per hour.
Bulletin 1724E-200
Page E-3
TABLE E-2
CONVERSION FACTORS FOR OTHER
MEAN RECURRENCE INTERVALS
Peak gust wind speed, V (mph)
Continental U.S.
MRI
(years
)
V=85-100
V>100 (hurricane)
Alaska
500
200
100
50
25
10
1.23
1.14
1.07
1.00
0.93
0.84
1/18
1.12
1.06
1.00
0.94
0.87
5
0.78
1.23
1.14
1.07
1.00
0.88
0.74(76 mph
min.)
0.66(60 mph
min.)
0.81
Note:
Conversion factors for the column “V>100 (hurricane)” are
approximate. For the MRI (mean recurrence interval) = 50 as
shown, the actual return period, as represented by the design
wind speed map in Figures 11-2a to 11-2d, varies from 50 to
approximately 90 years. For an MRI = 500, the conversion
factor is theoretically “exact” as shown.
TABLE E-3
PROBABLILITY OF EXCEEDING DESIGN WIND SPEEDS
DURING REFERENCE PERIOD
Annual
Probablility
Pa
.04(1/25)
.02(1/50)
.01(1/100)
.005(1/200
)
Reference (Exposure) Period, n (years)
1
5
10
25
50
100
0.04
0.02
0.01
0.005
0.18
0.10
0.05
0.02
0.34
0.18
0.10
0.05
0.64
0.40
0.22
0.10
0.87
0.64
0.40
0.22
0.98
0.87
0.64
0.39
FIGURE E-1: ISOKERAUNIC LEVELS FOR THE UNITED STATES
Bulletin 1724E-200
Page E-4
Bulletin 1724E-200
Page F-1
APPENDIX F
POLE DATA
•
Moments (ft-k) at Groundline Due to a 1 psf Wind on the Pole
F-2
•
Moment Capacities for Wood Poles at Groundline
F-3
•
Pole Classes
F-4
•
Moment Capacities for D.F. and SYP Along the Pole
F-5
•
Moment Reduction due to a Bolt Hole in the Pole
F-20
•
Weight and Volume of D.F. and SYP Poles
F-22
Bulletin 1724E-200
Page F-2
TABLE F-1
MOMENTS (FT-K) AT GROUNDLINE
DUE TO A 1 PSF WIND ON THE POLE
6000 psi
Western Red Cedar
6600 psi
Lodgepole Pine
Ht.
Cl-H1
Cl-1
Cl-2
Cl-3
50
55
60
0.9
1.1
0.9
1.0
0.8
1.0
1.4
1.6
1.9
2.2
1.3
1.5
1.8
2.1
2.6
3.0
3.4
3.9
4.4
65
70
75
80
85
90
95
100
Cl-H1
Cl-1
Cl-2
Cl-3
0.7
0.9
0.8
1.0
0.8
1.0
0.7
0.9
1.2
1.4
1.7
2.0
1.1
1.3
1.6
1.8
1.3
1.5
1.8
2.1
1.2
1.4
1.7
1.9
1.1
1.3
1.5
1.8
2.4
2.8
3.2
2.3
2.6
3.0
2.1
2.4
2.7
2.4
2.7
3.1
2.2
2.5
2.9
2.1
2.4
2.7
3.6
4.1
3.4
3.8
3.6
4.0
3.3
3.7
8000 psi
Douglas Fir and
Southern Yellow Pine
8400 psi
Western Larch
Ht.
Cl-H1
Cl-1
Cl-2
Cl-3
Cl-H1
Cl-1
Cl-2
Cl-3
50
55
60
65
0.9
1.1
1.3
0.8
1.0
1.2
0.8
0.9
1.1
0.7
0.9
1.1
0.9
1.1
1.3
0.8
1.0
1.2
0.8
0.9
1.1
0.7
0.9
1.0
1.6
1.8
2.1
2.5
1.5
1.7
2.0
2.3
1.4
1.6
1.9
2.2
1.3
1.5
1.7
2.0
1.6
1.8
2.1
2.5
1.4
1.7
2.0
2.3
1.4
1.6
1.8
2.1
1.2
1.5
1.7
2.0
2.8
3.2
3.7
2.6
3.0
3.4
2.5
2.8
3.2
2.3
2.6
2.8
3.2
3.6
2.6
3.0
3.4
2.4
2.8
3.2
2.3
2.6
4.2
3.9
3.6
4.1
3.9
3.6
70
75
80
85
90
95
100
Bulletin 1724E-200
Page F-3
TABLE F-2
MOMENT CAPACITIES (FT-K) AT GROUNDLINE
For Western Red Cedar (6000 psi), Lodgepole Pine (6600 psi),
Douglas Fir and Southern Yellow Pine (8000 psi) and Western Larch (8400 psi)
6000 psi
Western Red Cedar
6600 psi
Lodgepole Pine
Ht.
ClassH1
Class 1
Class 2
Class 3
Class 1
Class 2
Class 3
Ht.
50
222.2
186.1
154.2
126.2
186.9
153.9
125.1
50
55
245.4
206.9
172.7
137.9
202.5
167.8
137.2
55
60
270.4
229.3
192.7
150.4
225.5
182.5
150.2
60
65
297.1
246.7
202.4
163.7
243.4
198.2
159.0
65
70
317.7
265.1
218.6
177.9
262.4
214.8
173.4
70
75
339.4
284.4
235.7
192.9
282.4
232.4
188.8
75
80
362.2
304.8
253.8
203.1
303.4
251.0
205.1
80
85
386.1
326.2
266.0
219.6
317.5
263.6
216.1
85
90
411.1
348.6
285.6
230.7
340.4
283.8
227.5
90
95
441.6
367.3
301.9
368.0
300.5
95
100
473.4
395.5
326.6
387.8
317.7
100
8000 psi
Douglas Fir & Southern Yellow Pine
8400 psi
Western Larch
Ht.
ClassH1
Class 1
Class 2
Class 3
ClassH1
Class 1
Class 2
Class 3
Ht.
50
220.3
187.2
152.1
121.7
222.4
183.9
148.7
123.0
50
55
246.4
204.2
167.1
134.7
243.6
201.1
163.8
136.4
55
60
266.8
222.3
183.0
148.7
264.3
219.4
179.9
145.4
60
65
288.4
241.5
200.0
163.5
294.4
238.9
203.5
160.4
65
70
311.2
261.9
218.1
179.4
318.0
259.5
215.3
176.4
70
75
335.3
283.4
230.3
190.2
333.8
281.3
227.7
187.3
75
80
360.6
306.2
250.2
201.5
359.6
296.1
247.8
198.7
80
85
387.2
321.5
263.7
213.3
386.7
320.0
261.5
210.6
85
90
405.2
337.5
285.5
225.5
405.0
336.2
275.8
229.9
90
95
438.0
357.3
303.2
438.3
365.6
301.5
95
100
461.5
387.3
321.5
462.1
386.7
319.9
100
Bulletin 1724E-200
Page F-4
TABLE F-3
POLE CLASSES
Wood poles are separated into 15 classes based on the minimum circumference of the pole 6 feet
from the butt. The minimum circumferences have been calculated in order for each species (in a
given class) to develop stresses approximately equal to those shown in the table. These stresses
are developed at the groundline, when a horizontal load is applied 2 feet from the top of the pole.
The horizontal loads used in these calculations are as follows:
Class
Horizontal Load (lbs.)
H6
H5
H4
H3
H2
H1
1
2
3
4
5
6
7
9
10
11,400
10,000
8,700
7,500
6,400
5,400
4,500
3,700
3,000
2,400
1,900
1,500
1,200
740
370
Bulletin 1724E-200
Page F-5
DOUGLAS FIR AND SOUTHERN YELLOW PINE
Ultimate Bending Stress – 8000 psi
55 ft.
Dist.
(ft.)
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
Dia.
(in.)
9.23
9.36
9.50
9.63
9.76
9.90
10.03
10.16
10.30
10.43
10.56
10.70
10.83
10.96
11.10
11.23
11.36
11.49
11.63
11.76
11.89
12.03
12.16
12.29
12.43
12.56
12.69
12.83
12.96
13.09
13.23
13.36
13.49
13.63
13.76
13.89
14.03
14.16
14.29
14.42
14.56
14.69
14.82
14.96
15.09
15.22
15.36
15.49
15.62
15.76
15.82
15.89
15.96
16.02
16.09
16.16
55 ft.
Class H1
Area
Moment
(sq. in.)
(ft-k)
66.92
51.5
68.87
53.7
70.84
56.1
72.84
58.5
74.87
60.9
76.93
63.4
79.01
66.0
81.12
68.7
83.26
71.4
85.43
74.3
87.63
77.1
89.85
80.1
92.10
83.1
94.38
86.2
96.69
89.4
99.02
92.7
101.39
96.0
103.78
99.4
106.19
102.9
108.64
106.5
111.12
110.1
113.62
113.9
116.15
117.7
118.71
121.6
121.29
125.6
123.90
129.7
126.55
133.9
129.21
138.1
131.91
142.5
134.64
146.9
137.39
151.4
140.17
156.0
142.98
160.8
145.81
165.6
148.68
170.5
151.57
175.5
154.49
180.6
157.44
185.8
160.41
191.0
163.42
196.4
166.45
201.9
169.51
207.5
172.60
213.2
175.71
219.0
178.85
224.9
182.02
230.9
185.22
237.0
188.45
243.3
191.70
249.6
194.98
256.0
196.64
259.3
198.31
262.6
199.98
265.9
201.66
269.3
203.34
272.7
205.04
276.1
Dia.
(in.)
8.59
8.72
8.85
8.97
9.10
9.23
9.35
9.48
9.61
9.73
9.86
9.99
10.11
10.24
10.37
10.49
10.62
10.75
10.87
11.00
11.13
11.25
11.38
11.51
11.63
11.76
11.89
12.01
12.14
12.27
12.39
12.52
12.65
12.77
12.90
13.03
13.15
13.28
13.41
13.53
13.66
13.79
13.91
14.04
14.17
14.29
14.42
14.55
14.67
14.80
14.87
14.94
15.00
15.07
15.14
15.20
Class 1
Area
(sq. in.)
58.01
59.73
61.48
63.26
65.05
66.88
68.73
70.60
72.5
74.42
76.37
78.35
80.35
82.37
84.42
86.50
88.60
90.73
92.88
95.05
92.26
99.48
101.73
104.01
106.31
108.64
110.99
113.37
115.78
118.20
120.66
123.14
125.64
128.17
130.72
133.30
135.91
138.54
141.19
143.87
146.58
149.31
152.07
154.85
157.66
160.49
163.34
166.23
169.13
172.07
173.62
175.19
176.76
178.34
179.92
181.52
Moment
(ft-k)
41.5
43.4
45.3
47.3
49.3
51.4
53.6
55.8
58.0
60.4
62.8
65.2
67.7
70.3
72.9
75.6
78.4
81.3
84.2
87.1
90.2
93.3
96.5
99.7
103.1
106.5
110.0
113.5
117.1
120.8
124.6
128.5
132.4
136.4
140.5
144.7
149.0
153.3
157.8
162.3
166.9
171.6
176.3
181.2
186.1
191.2
196.3
201.5
206.8
212.2
215.1
218.0
221.0
223.9
226.9
230.0
Dist.
(ft.)
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
Dia.
(in.)
7.96
8.08
8.20
8.32
8.44
8.56
8.68
8.80
8.92
9.04
9.16
9.28
9.40
9.52
9.64
9.76
9.88
10.00
10.12
10.24
10.36
10.48
10.60
10.72
10.84
10.96
11.08
11.20
11.32
11.44
11.56
11.68
11.80
11.92
12.04
12.16
12.28
12.40
12.52
12.64
12.76
12.89
13.01
13.13
13.25
13.37
13.49
13.61
13.73
13.85
13.91
13.98
14.05
14.11
14.18
14.25
Class 2
Area
(sq. in.)
49.74
51.25
52.79
54.34
55.93
57.53
59.16
60.81
62.48
64.17
65.89
67.63
69.40
71.18
72.99
74.82
76.68
78.55
80.45
82.37
84.32
86.29
88.28
90.29
92.32
94.38
96.46
98.57
100.69
102.84
105.01
107.21
109.42
111.66
113.92
116.21
118.52
120.85
123.20
125.58
127.97
130.40
132.84
135.31
137.79
140.31
142.84
145.40
147.98
150.58
152.04
153.50
154.97
156.45
157.94
159.43
Moment
(ft-k)
33.0
34.5
36.1
37.7
39.3
41.0
42.8
44.6
46.4
48.3
50.3
52.5
54.4
56.5
58.6
60.9
63.1
65.5
67.9
70.3
72.8
75.4
78.0
80.7
83.4
86.2
89.1
92.0
95.0
98.1
101.2
104.4
107.6
111.0
114.3
117.8
121.3
124.9
128.6
132.3
136.1
140.0
144.0
148.0
152.1
156.3
160.5
164.9
169.3
173.8
176.3
178.8
181.4
184.0
186.6
189.3
Dia.
(in.)
7.32
7.43
7.55
7.66
7.78
7.89
8.00
8.12
8.23
8.34
8.46
8.57
8.69
8.80
8.91
9.03
9.14
9.25
9.37
9.48
9.59
9.71
9.82
9.94
10.05
10.16
10.28
10.39
10.50
10.62
10.73
10.85
10.96
11.07
11.19
11.30
11.41
11.53
11.64
11.75
11.87
11.98
12.10
12.21
12.32
12.44
12.55
12.66
12.78
12.89
12.96
13.03
13.09
13.16
13.23
13.29
Class 3
Area
(sq. in.)
42.10
43.41
44.75
46.11
47.49
48.89
50.31
51.75
53.20
54.68
56.18
57.71
59.25
60.81
62.39
63.99
65.61
67.25
68.92
70.60
72.30
74.03
75.77
77.53
79.32
81.12
82.95
84.79
86.66
88.55
90.45
92.38
94.33
96.29
98.28
100.29
102.32
104.36
106.43
108.52
110.63
112.76
114.91
117.08
119.27
121.48
123.71
125.96
128.24
130.53
131.88
133.25
134.62
136.00
137.38
138.77
Moment
(ft-k)
25.7
26.9
28.2
29.4
30.8
32.1
33.6
35.0
36.5
38.0
39.6
41.2
42.9
44.6
46.3
48.1
50.0
51.9
53.8
55.8
57.8
59.9
62.0
64.2
66.4
68.7
71.0
73.4
75.9
78.3
80.9
83.5
86.1
88.9
91.6
94.4
97.3
100.3
103.2
106.3
109.4
112.6
115.8
119.1
122.5
125.9
129.4
132.9
136.5
140.2
142.4
144.6
146.9
149.1
151.4
153.7
Dist.
(ft.)
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
Bulletin 1724E-200
Page F-6
DOUGLAS FIR AND SOUTHERN YELLOW PINE
Ultimate Bending Stress – 8000 psi
60 ft.
Dist.
(ft.)
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
Dia.
(in.)
9.231
9.361
9.49
9.62
9.75
9.879
10.01
10.14
10.27
10.4
10.53
10.66
10.79
10.92
11.05
11.18
11.31
11.44
11.57
11.69
11.82
11.95
12.08
12.21
12.34
12.47
12.6
12.73
12.86
12.99
13.12
13.25
13.38
13.51
13.64
13.77
13.9
14.03
14.16
14.29
14.42
14.55
14.68
14.81
14.94
15.07
15.2
15.33
15.46
15.59
15.72
15.84
15.97
16.1
16.23
16.3
60 ft.
Class H1
Area
Moment
(sq. in.)
(ft-k)
66.92
51.5
68.82
53.7
70.74
55.9
72.68
58.3
74.66
60.7
76.66
63.1
78.68
65.6
80.73
68.2
82.81
70.9
84.92
73.6
87.05
76.4
89.21
79.2
91.39
82.2
93.60
85.2
95.84
88.2
98.10
91.4
100.39
94.6
102.71
97.9
105.05
101.2
107.42
104.7
109.82
108.2
112.24
111.8
114.69
115.5
117.16
119.2
119.66
123.1
122.19
127.0
124.74
131.0
127.32
135.1
129.93
139.3
132.56
143.5
135.22
147.9
137.91
152.3
140.62
156.8
143.36
161.4
146.13
166.1
148.92
170.9
151.74
175.8
154.58
180.7
157.45
185.8
160.35
190.9
163.27
196.2
166.22
201.5
169.20
207.0
172.20
212.5
175.23
218.1
178.29
223.9
181.37
229.7
184.48
235.6
187.62
241.6
190.78
247.8
193.96
254.0
197.18
260.4
200.42
266.8
203.69
273.4
206.98
280.0
208.69
283.5
Dia.
(in.)
8.594
8.718
8.842
8.966
9.09
9.213
9.337
9.461
9.585
9.708
9.832
9.956
10.08
10.2
10.33
10.45
10.57
10.7
10.82
10.95
11.07
11.19
11.32
11.44
11.57
11.69
11.81
11.94
12.06
12.18
12.31
12.43
12.56
12.68
12.8
12.93
13.05
13.17
13.3
13.42
13.55
13.67
13.79
13.92
14.04
14.16
14.29
14.41
14.54
14.66
14.78
14.91
15.03
15.16
15.28
15.35
Class 1
Area
(sq. in.)
58.01
59.70
61.40
63.13
64.89
66.67
68.47
70.30
72.15
74.03
75.93
77.85
79.80
81.77
83.77
85.79
87.83
89.90
91.99
94.11
96.25
98.41
100.60
102.81
105.05
107.31
109.60
111.91
114.24
116.60
118.98
121.38
123.81
126.27
128.74
131.24
133.77
136.32
138.89
141.49
144.11
146.76
149.43
152.12
154.84
157.58
160.35
163.14
165.95
168.79
171.66
174.54
177.45
180.39
183.35
184.95
Moment
(ft-k)
41.5
43.4
45.2
47.2
49.2
51.2
53.3
55.4
57.6
59.9
62.2
64.6
67.0
69.5
72.1
74.7
77.4
80.2
83.0
85.8
88.8
91.8
94.9
98.0
101.2
104.5
107.9
111.3
114.8
118.4
122.0
125.7
129.5
133.4
137.4
141.4
145.5
149.7
153.9
158.3
162.7
167.2
171.8
176.4
181.2
186.0
190.9
195.9
201.0
206.2
211.5
216.8
222.3
227.8
233.4
236.5
Dist.
(ft.)
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
Dia.
(in.)
7.958
8.076
8.194
8.311
8.429
8.547
8.665
8.783
8.901
9.019
9.137
9.255
9.372
9.49
9.608
9.726
9.844
9.962
10.08
10.2
10.32
10.43
10.55
10.67
10.79
10.91
11.02
11.14
11.26
11.38
11.49
11.61
11.73
11.85
11.97
12.08
12.2
12.32
12.44
12.56
12.67
12.79
12.91
13.03
13.15
13.26
13.38
13.5
13.62
13.73
13.85
13.97
14.09
14.21
14.32
14.39
Class 2
Area
(sq. in.)
49.74
51.22
52.73
54.26
55.81
57.38
58.97
60.59
60.22
63.88
65.56
67.27
68.99
70.74
72.51
74.30
76.11
77.94
79.80
81.68
83.58
85.50
87.44
89.40
91.39
93.40
95.43
97.48
99.56
101.65
103.77
105.91
108.07
110.25
112.46
114.69
116.93
119.21
121.50
123.81
126.15
126.51
130.89
133.29
135.71
138.16
140.62
143.11
145.62
148.15
150.71
153.28
155.88
158.50
161.14
162.65
Moment
(ft-k)
33.0
34.5
36.0
37.6
39.2
40.9
42.6
44.3
46.2
48.0
49.9
51.9
53.9
55.9
58.1
60.2
62.4
64.7
67.0
69.4
71.8
74.3
76.9
79.5
82.2
84.9
87.7
90.5
93.4
96.4
99.4
102.5
105.6
108.9
112.1
115.5
118.9
122.4
125.9
129.5
133.2
137.0
140.8
144.7
148.7
152.7
156.8
161.0
165.2
169.6
174.0
178.5
183.0
187.6
192.4
195.1
Dia.
(in.)
7.32
7.43
7.55
7.66
7.77
7.88
7.99
8.11
8.22
8.33
8.44
8.55
8.67
8.78
8.89
9.00
9.11
9.23
9.34
9.45
9.56
9.67
9.79
9.90
10.01
10.12
10.23
10.35
10.46
10.57
10.68
10.79
10.91
11.02
11.13
11.24
11.35
11.47
11.58
11.69
11.80
11.91
12.03
12.14
12.25
12.36
12.47
12.59
12.70
12.81
12.92
13.03
13.15
13.26
13.37
13.44
Class 3
Area
(sq. in.)
42.10
43.39
44.71
46.05
47.41
48.78
50.18
51.60
53.03
54.49
55.96
57.46
58.97
60.51
62.06
63.63
65.23
66.84
68.47
70.12
71.80
73.49
75.20
76.93
78.68
80.45
82.24
84.05
85.88
87.73
89.60
91.49
93.40
95.33
97.28
99.24
101.23
103.24
105.27
107.31
109.38
111.46
113.57
115.70
117.84
120.01
122.19
124.39
126.62
128.86
131.12
133.41
135.71
138.03
140.37
141.78
Moment
(ft-k)
25.7
26.9
28.1
29.4
30.7
32.0
33.4
34.8
36.3
37.8
39.4
41.0
42.6
44.3
46.0
47.7
49.5
51.4
53.3
55.2
57.2
59.2
61.3
63.4
65.6
67.9
70.1
72.5
74.8
77.3
79.8
82.3
84.9
87.5
90.2
93.0
95.8
98.6
101.6
104.5
107.6
110.7
113.8
117.0
120.3
123.6
127.0
130.5
134.0
137.5
141.2
144.9
148.7
152.5
156.4
158.7
Dist.
(ft.)
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
Bulletin 1724E-200
Page F-7
DOUGLAS FIR AND SOUTHERN YELLOW PINE
Ultimate Bending Stress – 8000 psi
60 ft.
Dist.
(ft.)
56
57
58
59
60
Dia.
(in.)
16.37
16.43
16.5
16.57
16.63
60 ft.
Class H1
Area
Moment
(sq. in.)
(ft-k)
210.40
287.0
212.13
290.5
213.86
294.1
215.59
297.7
217.33
301.3
Dia.
(in.)
15.41
15.48
15.55
15.61
15.68
Class 1
Area
(sq. in.)
186.57
188.19
189.82
191.46
193.10
Moment
(ft-k)
239.6
242.8
245.9
249.1
252.3
Dist.
(ft.)
56
57
58
59
60
Dia.
(in.)
14.46
14.52
14.59
14.66
14.73
Class 2
Area
(sq. in.)
164.17
165.69
167.22
168.75
170.29
Moment
(ft-k)
197.8
200.5
203.3
206.1
209.0
Dia.
(in.)
13.50
13.57
13.64
13.70
13.77
Class 3
Area
(sq. in.)
143.20
144.62
146.05
147.48
148.92
Moment
(ft-k)
161.1
163.5
166.0
168.4
170.9
Dist.
(ft.)
56
57
58
59
60
Bulletin 1724E-200
Page F-8
DOUGLAS FIR AND SOUTHERN YELLOW PINE
Ultimate Bending Stress – 8000 psi
65 ft.
Dist.
(ft.)
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
Dia.
(in.)
9.23
9.36
9.48
9.61
9.74
9.86
9.99
10.12
10.25
10.37
10.50
10.63
10.75
10.88
11.01
11.13
11.26
11.39
11.51
11.64
11.77
11.89
12.02
12.15
12.27
12.40
12.53
12.65
12.78
12.91
13.03
13.16
13.29
13.41
13.54
13.67
13.80
13.92
14.05
14.18
14.30
14.43
14.56
14.68
14.81
14.94
15.06
15.19
15.32
15.44
15.57
15.70
15.82
15.95
16.08
16.20
65 ft.
Class H1
Area
Moment
(sq. in.)
(ft-k)
66.9
51.5
68.8
53.6
70.7
55.8
72.6
58.1
74.5
60.4
76.4
62.8
78.4
65.3
80.4
67.8
82.4
70.4
84.5
73.0
86.6
75.7
88.7
78.5
90.8
81.4
93.0
84.3
95.1
87.3
97.3
90.3
99.6
93.4
101.8
96.6
104.1
99.9
106.4
103.2
108.7
106.6
111.1
110.1
113.5
113.7
115.9
117.3
118.3
121.0
120.8
124.8
123.3
128.7
125.8
132.6
128.3
136.6
130.9
140.8
133.4
144.9
136.0
149.2
138.7
153.6
141.3
158.0
144.0
162.5
146.7
167.1
149.5
171.8
152.2
176.6
155.0
181.5
157.8
186.4
160.7
191.5
163.5
196.6
166.4
201.9
169.3
207.2
172.3
212.6
175.2
218.1
178.2
223.7
181.2
229.4
184.3
235.2
187.3
241.1
190.4
247.1
193.5
253.1
196.7
259.3
199.8
265.6
203.0
272.0
206.2
278.5
Dia.
(in.)
8.59
8.72
8.84
8.96
9.08
9.20
9.32
9.44
9.57
9.69
9.81
9.93
10.05
10.17
10.29
10.42
10.54
10.66
10.78
10.90
11.02
11.14
11.26
11.39
11.51
11.63
11.75
11.87
11.99
12.11
12.24
12.36
12.48
12.60
12.72
12.84
12.96
13.09
13.21
13.33
13.45
13.57
13.69
13.81
13.94
14.06
14.18
14.30
14.42
14.54
14.66
14.79
14.91
15.03
15.15
15.27
Class 1
Area
(sq. in.)
58.0
59.7
61.3
63.0
64.8
66.5
68.3
70.1
71.9
73.7
75.6
77.4
79.3
81.3
83.2
85.2
87.2
89.2
91.3
93.3
95.4
97.5
99.7
101.8
104.0
106.2
108.4
110.7
113.0
115.3
117.6
119.9
122.3
124.7
127.1
129.5
132.0
134.5
137.0
139.5
142.1
144.7
147.3
149.9
152.5
155.2
157.9
160.6
163.3
166.1
168.9
171.7
174.5
177.4
180.3
183.2
Moment
(ft-k)
41.5
43.3
45.2
47.1
49.0
51.0
53.0
55.1
57.3
59.5
61.8
64.1
66.5
68.9
71.4
73.9
76.6
79.2
82.0
84.8
87.6
90.6
93.6
96.6
99.7
102.9
106.2
109.5
112.9
116.4
119.9
123.5
127.2
130.9
134.8
138.6
142.6
146.7
150.8
155.0
159.2
163.6
168.0
172.5
177.1
181.8
186.5
191.4
196.3
201.3
206.4
211.5
216.8
222.1
227.6
233.1
Dist.
(ft.)
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
Dia.
(in.)
7.96
8.07
8.19
8.31
8.42
8.54
8.65
8.77
8.89
9.00
9.12
9.23
9.35
9.47
9.58
9.70
9.81
9.93
10.05
10.16
10.28
10.39
10.51
10.63
10.74
10.86
10.97
11.09
11.21
11.32
11.44
11.55
11.67
11.79
11.90
12.02
12.13
12.25
12.37
12.48
12.60
12.71
12.83
12.95
13.06
13.18
13.29
13.41
13.53
13.64
13.76
13.87
13.99
14.11
14.22
14.34
Class 2
Area
(sq. in.)
49.7
51.2
52.7
54.2
55.7
57.2
58.8
60.4
62.0
63.6
65.3
67.0
68.7
70.4
72.1
73.9
75.6
77.4
79.3
81.1
83.0
84.8
86.7
88.7
90.6
92.6
94.6
96.6
98.6
100.7
102.7
104.8
107.0
109.1
111.2
113.4
115.6
117.8
120.1
122.4
124.6
126.9
129.3
131.6
134.0
136.4
138.8
141.2
143.7
146.2
148.7
151.2
153.7
156.3
158.8
161.4
Moment
(ft-k)
33.0
34.4
36.0
37.5
39.1
40.7
42.4
44.1
45.9
47.7
49.6
51.5
53.5
55.5
57.6
59.7
61.9
64.1
66.4
68.7
71.1
73.5
76.0
78.5
81.1
83.5
86.5
89.3
92.1
95.0
97.9
100.9
104.0
107.1
110.3
113.6
116.9
120.3
123.8
127.3
130.8
134.5
138.2
142.0
145.8
149.8
153.8
157.8
161.9
166.1
170.4
174.8
179.2
183.7
188.3
192.9
Dia.
(in.)
7.32
7.43
7.54
7.65
7.76
7.87
7.98
8.10
8.21
8.32
8.43
8.54
8.65
8.76
8.87
8.98
9.09
9.20
9.31
9.42
9.53
9.64
9.75
9.86
9.98
10.09
10.20
10.31
10.42
10.53
10.64
10.75
10.86
10.97
11.08
11.19
11.30
11.41
11.52
11.63
11.75
11.86
11.97
12.08
12.19
12.30
12.41
12.52
12.63
12.74
12.85
12.96
13.07
13.18
13.29
13.40
Class 3
Area
(sq. in.)
42.1
43.4
44.7
46.0
47.3
48.7
50.1
51.5
52.9
54.3
55.8
57.2
58.7
60.3
61.8
63.3
64.9
66.5
68.1
69.7
71.4
73.0
74.7
76.4
78.2
79.9
81.7
83.4
85.2
87.1
88.9
90.8
92.6
94.5
96.4
98.4
100.3
102.3
104.3
106.3
108.3
110.4
112.5
114.6
116.7
118.8
120.9
123.1
125.3
127.5
129.7
132.0
134.2
136.5
138.8
141.1
Moment
(ft-k)
25.7
26.9
28.1
29.3
30.6
32.0
33.3
34.7
36.2
37.6
39.2
40.7
42.3
44.0
45.7
47.4
49.2
51.0
52.8
54.8
56.7
58.7
60.7
62.8
65.0
67.2
69.4
71.7
74.0
76.4
78.8
81.3
83.8
86.4
89.1
91.8
94.5
97.3
100.2
103.1
106.0
109.1
112.1
115.3
118.5
121.7
125.1
128.4
131.9
135.4
138.9
142.5
146.2
149.9
153.8
157.6
Dist.
(ft.)
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
Bulletin 1724E-200
Page F-9
DOUGLAS FIR AND SOUTHERN YELLOW PINE
Ultimate Bending Stress – 8000 psi
65 ft.
Dist.
(ft.)
56
57
58
59
60
61
62
63
64
65
Dia.
(in.)
16.33
16.46
16.58
16.71
16.78
16.84
16.91
16.98
17.05
17.11
65 ft.
Class H1
Area
Moment
(sq. in.)
(ft-k)
209.5
285.1
212.7
291.8
216.0
298.5
219.3
305.4
221.1
309.1
222.9
312.8
224.6
316.6
226.4
320.3
228.2
324.1
230.0
328.0
Dia.
(in.)
15.39
15.51
15.63
15.76
15.82
15.89
15.96
16.02
16.09
16.16
Class 1
Area
(sq. in.)
186.1
189.0
192.0
195.0
196.6
198.3
200.0
201.7
203.3
205.0
Moment
(ft-k)
238.7
244.4
250.1
256.0
259.3
262.6
265.9
269.3
272.7
276.1
Dist.
(ft.)
56
57
58
59
60
61
62
63
64
65
Dia.
(in.)
14.45
14.57
14.69
14.80
14.87
14.94
15.00
15.07
15.14
15.20
Class 2
Area
(sq. in.)
164.1
166.7
169.4
172.1
173.6
175.2
176.8
178.3
179.9
181.5
Moment
(ft-k)
197.6
202.4
207.3
212.2
215.1
218.0
221.0
223.9
226.9
230.0
Dia.
(in.)
13.51
13.63
13.74
13.85
13.91
13.98
14.05
14.11
14.18
14.25
Class 3
Area
(sq. in.)
143.5
145.8
148.2
150.6
152.0
153.5
155.0
156.5
157.9
159.4
Moment
(ft-k)
161.6
165.6
169.6
173.8
176.3
178.8
181.4
184.0
186.6
189.3
Dist.
(ft.)
56
57
58
59
60
61
62
63
64
65
Bulletin 1724E-200
Page F-10
DOUGLAS FIR AND SOUTHERN YELLOW PINE
Ultimate Bending Stress – 8000 psi
70 ft.
Dist.
(ft.)
Dia.
(in.)
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
9.23
9.36
9.48
9.60
9.73
9.85
9.98
10.10
10.23
10.35
10.47
10.60
10.72
10.85
10.97
11.10
11.22
11.34
11.47
11.59
11.72
11.84
11.97
12.09
12.22
12.34
12.46
12.59
12.71
12.84
12.96
13.09
13.21
13.33
13.46
13.58
13.71
13.83
13.96
14.08
14.20
14.33
14.45
14.58
14.70
14.83
14.95
15.07
15.20
15.32
15.45
15.57
15.70
15.82
15.95
16.07
70 ft.
Class H1
Area
Moment
(sq.
(ft-k)
in.)
66.9
51.5
68.7
53.6
70.6
55.8
72.4
58.0
74.3
60.3
76.2
62.6
78.2
65.0
80.1
67.5
82.1
70.0
84.1
72.6
86.2
75.2
88.2
77.9
90.3
80.7
92.4
83.5
94.5
86.4
96.7
89.4
98.9
92.5
101.1
95.6
103.3
98.7
105.6
102.0
107.8
105.3
110.1
108.7
112.5
112.2
114.8
115.7
117.2
119.3
119.6
123.0
122.0
126.7
124.5
130.6
126.9
134.5
129.4
138.4
131.9
142.5
134.5
146.6
137.1
150.9
139.6
155.2
142.3
159.6
144.9
164.0
147.6
168.6
150.3
173.2
153.0
177.9
155.7
182.7
158.5
187.6
161.3
192.6
164.1
197.6
166.9
202.8
169.8
208.0
172.6
213.3
175.6
218.7
178.5
224.2
181.4
229.8
184.4
235.5
187.4
241.3
190.5
247.2
193.5
253.1
196.6
259.2
199.7
265.3
202.8
271.6
Dia.
(in.)
8.59
8.71
8.83
8.95
9.07
9.19
9.31
9.43
9.55
9.67
9.79
9.91
10.03
10.15
10.27
10.38
10.50
10.62
10.74
10.86
10.98
11.10
11.22
11.34
11.46
11.58
11.70
11.82
11.94
12.06
12.18
12.29
12.41
12.53
12.65
12.77
12.89
13.01
13.13
13.25
13.37
13.49
13.61
13.73
13.85
13.97
14.09
14.20
14.32
14.44
14.56
14.68
14.80
14.92
15.04
15.16
Class 1
Area
(sq.
in.)
58.0
59.6
61.3
62.8
64.6
66.3
68.1
69.8
71.6
73.4
75.2
77.1
79.0
80.9
82.8
84.7
86.7
88.6
90.6
92.7
94.7
96.8
98.9
101.0
103.1
105.3
107.5
109.7
111.9
114.2
116.4
118.7
121.0
123.4
125.7
128.1
130.5
133.0
135.4
137.9
140.4
142.9
145.4
148.0
150.6
153.2
155.8
158.5
161.1
163.5
166.6
169.3
172.1
174.9
177.7
180.5
Moment
(ft-k)
41.5
43.3
45.1
47.0
48.9
50.8
52.8
54.9
57.0
59.2
61.4
63.6
66.0
68.4
70.8
73.3
75.9
78.5
81.1
83.9
86.7
89.5
92.5
94.5
98.5
101.6
104.8
108.8
111.3
114.7
118.1
121.6
125.2
128.9
132.6
136.4
140.2
144.2
148.2
152.2
156.4
160.6
164.9
169.3
173.8
178.3
182.9
187.6
192.4
197.2
202.1
207.1
212.2
217.4
222.7
228.0
Dist.
(ft.)
Dia.
(in.)
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
7.96
8.07
8.19
8.30
8.42
8.53
8.64
8.76
8.87
8.99
9.10
9.22
9.33
9.44
9.56
9.67
9.79
9.90
10.02
10.13
10.25
10.36
10.47
10.59
10.70
10.82
10.93
11.05
11.16
11.28
11.39
11.50
11.62
11.73
11.85
11.96
12.08
12.19
12.30
12.42
12.53
12.65
12.76
12.88
12.99
13.11
13.22
13.33
13.45
13.56
13.68
13.79
13.91
14.02
14.13
14.25
Class 2
Area
(sq.
in.)
49.7
51.2
52.6
54.1
55.6
57.1
58.7
60.2
61.8
63.4
65.1
66.7
68.4
70.1
71.8
73.5
75.2
77.0
78.8
80.6
82.4
84.3
86.2
88.1
90.0
91.9
93.9
95.8
97.8
99.8
101.9
103.9
106.9
108.1
110.2
112.4
114.5
116.7
118.9
121.1
123.4
125.6
127.9
130.2
132.5
134.9
137.3
139.6
142.1
144.5
146.9
149.4
151.9
154.4
156.9
159.5
Moment
(ft-k)
Dia.
(in.)
33.0
34.4
35.9
37.4
39.0
40.6
42.3
44.0
45.7
47.5
49.3
51.2
53.2
55.1
57.2
59.2
61.4
63.6
65.8
68.1
70.4
72.8
75.2
77.7
80.3
82.9
85.5
88.2
91.0
93.8
96.7
99.6
102.6
105.7
108.8
112.0
115.3
118.6
121.9
125.4
128.9
132.4
126.0
139.7
143.5
147.3
151.2
155.2
159.2
163.3
167.5
171.7
176.0
180.4
184.8
189.4
7.32
7.43
7.54
7.65
7.76
7.87
7.98
8.09
8.20
8.31
8.42
8.52
8.63
8.74
8.85
8.96
9.07
9.18
9.29
9.40
9.51
9.62
9.73
9.84
9.95
10.06
10.17
10.28
10.38
10.49
10.60
10.71
10.82
10.93
11.04
11.15
11.26
11.37
11.48
11.59
11.70
11.81
11.92
12.03
12.14
12.24
12.35
12.46
12.57
12.68
12.79
12.90
13.01
13.12
13.23
13.34
Class 3
Area
(sq.
in.)
42.1
43.4
44.7
46.0
47.3
48.6
50.0
51.4
52.8
54.2
55.6
57.1
58.6
60.0
61.6
63.1
64.2
66.2
67.8
69.4
71.0
72.7
74.3
76.0
77.7
79.4
81.2
82.9
84.7
86.5
88.3
90.1
92.0
93.9
95.7
97.7
99.6
101.5
103.5
105.5
107.5
109.5
111.5
113.6
115.7
117.8
119.9
122.0
124.2
126.3
128.5
130.7
133.0
135.2
137.5
139.7
Moment
(ft-k)
25.7
26.9
28.1
29.3
30.6
31.9
33.2
34.6
36.0
37.2
39.0
40.5
42.1
43.7
45.4
47.1
48.9
50.7
52.5
54.4
56.3
58.2
60.3
62.3
64.4
66.6
68.8
71.0
73.3
75.6
78.0
80.5
83.0
85.5
88.1
90.7
93.4
96.2
99.0
101.9
104.8
107.7
110.8
113.8
117.0
120.2
123.4
126.7
130.1
133.5
137.0
140.5
144.2
147.8
151.6
155.3
Dist.
(ft.)
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
Bulletin 1724E-200
Page F-11
DOUGLAS FIR AND SOUTHERN YELLOW PINE
Ultimate Bending Stress – 8000 psi
70 ft.
Dist.
(ft.)
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
Dia.
(in.)
16.19
16.32
16.44
16.57
16.69
16.82
16.94
17.06
17.19
17.26
17.32
17.39
17.46
17.52
17.59
70 ft.
Class H1
Area
Moment
(sq. in.)
(ft-k)
206.0
278.0
209.1
284.4
212.3
291.0
215.6
297.6
218.8
304.4
222.1
311.2
225.4
318.2
228.7
325.2
232.0
332.4
233.9
336.3
235.7
340.2
237.5
344.2
239.3
348.1
241.2
352.2
243.0
356.2
Dia.
(in.)
15.28
15.40
15.52
15.64
15.76
15.88
16.00
16.11
16.23
16.30
16.37
16.43
16.50
16.57
16.63
Class 1
Area
(sq. in.)
183.3
186.2
189.1
192.0
195.0
198.0
200.9
203.9
207.9
208.9
210.4
212.1
213.9
215.6
217.3
Moment
(ft-k)
233.4
239.0
244.6
250.2
256.0
261.9
267.8
273.9
280.0
283.5
287.0
290.5
294.1
297.7
301.3
Dist.
(ft.)
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
Dia.
(in.)
14.36
14.48
14.59
14.71
14.82
14.94
15.05
15.16
15.28
15.35
15.41
15.48
15.55
15.61
15.68
Class 2
Area
(sq. in.)
162.0
164.6
167.2
169.9
172.5
175.2
177.9
180.6
183.3
185.0
186.6
188.2
189.8
191.5
193.1
Moment
(ft-k)
194.0
198.6
203.4
208.2
213.1
218.1
223.1
228.2
233.4
236.5
239.6
242.8
245.9
249.1
252.3
Dia.
(in.)
13.45
13.56
13.67
13.78
13.89
14.00
14.11
14.21
14.32
14.39
14.46
14.52
14.59
14.66
14.73
Class 3
Area
(sq. in.)
142.1
144.4
146.7
149.1
151.4
153.8
156.3
158.7
161.1
162.7
164.2
165.7
167.2
168.8
170.3
Moment
(ft-k)
159.2
163.1
167.1
171.1
175.3
179.4
183.7
188.0
192.4
195.1
197.8
200.5
203.3
206.1
209.0
Dist.
(ft.)
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
Bulletin 1724E-200
Page F-12
DOUGLAS FIR AND SOUTHERN YELLOW PINE
Ultimate Bending Stress – 8000 psi
75 ft.
Dist.
(ft.)
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
Dia.
(in.)
9.23
9.35
9.48
9.60
9.72
9.84
9.96
10.09
10.21
10.33
10.45
10.58
10.70
10.82
10.94
11.06
11.19
11.31
11.43
11.55
11.68
11.80
11.92
12.04
12.16
12.29
12.41
12.53
12.65
12.78
12.90
13.02
13.14
13.27
13.39
13.51
13.63
13.75
13.88
14.00
14.12
14.24
14.37
14.49
14.61
14.73
14.85
14.98
15.10
15.22
15.34
15.47
15.59
15.71
15.83
15.95
75 ft.
Class H1
Area
Moment
(sq. in.)
(ft-k)
66.9
51.3
68.7
53.6
70.5
55.7
72.3
57.9
74.2
60.1
76.1
62.4
78.0
64.8
79.9
67.2
81.9
69.6
83.8
72.2
85.8
74.8
87.8
77.4
89.9
80.1
92.0
82.9
94.0
85.8
96.2
88.7
98.3
91.6
100.5
94.7
102.6
97.8
104.8
100.9
107.1
104.2
109.3
107.5
111.6
110.9
113.9
114.3
116.2
117.8
118.6
121.4
120.9
125.1
123.3
128.8
125.8
132.6
128.2
136.5
130.7
140.5
133.2
144.5
135.7
148.6
138.2
152.8
140.8
157.0
143.3
161.4
146.0
165.8
148.6
170.3
151.2
174.9
153.9
179.5
156.6
184.3
159.3
189.1
162.1
194.0
164.9
199.0
167.6
204.1
170.5
209.3
173.3
214.5
176.2
219.9
179.1
225.3
182.0
230.8
184.9
236.4
187.9
242.1
190.8
247.9
193.8
253.8
196.9
259.7
199.9
265.8
Dia.
(in.)
8.59
8.71
8.83
8.95
9.06
9.18
9.30
9.42
9.54
9.65
9.77
9.89
10.01
10.12
10.24
10.36
10.48
10.59
10.71
10.83
10.95
11.06
11.18
11.30
11.42
11.54
11.65
11.77
11.89
12.01
12.12
12.24
12.36
12.48
12.59
12.71
12.83
12.95
13.06
13.18
13.30
13.42
13.54
13.65
13.77
13.89
14.01
14.12
14.24
14.36
14.48
14.59
14.71
14.83
14.95
15.06
Class 1
Area
(sq. in.)
58.0
59.6
61.2
62.9
64.5
66.2
67.9
69.7
71.4
73.2
75.0
76.8
78.6
80.5
82.4
84.3
86.2
88.2
90.1
92.1
94.1
96.2
98.2
100.3
102.4
104.5
106.6
108.8
111.0
113.2
115.4
117.7
120.0
122.3
124.6
126.9
129.3
131.7
134.1
136.5
138.9
141.4
143.9
146.4
148.9
151.5
154.1
156.7
159.3
161.9
164.6
167.3
170.0
172.7
175.5
178.2
Moment
(ft-k)
41.5
43.3
45.1
46.9
48.8
50.7
52.6
54.7
56.7
58.9
61.1
63.3
65.6
67.9
70.3
72.8
73.5
77.8
80.4
83.1
85.9
88.7
91.5
94.4
97.4
100.5
103.6
106.7
110.0
113.3
116.6
120.1
123.5
127.1
130.7
134.4
138.2
142.0
145.9
149.9
154.0
158.1
162.3
166.6
170.9
175.3
179.8
184.4
189.0
193.7
198.6
203.4
208.4
213.4
218.5
223.7
Dist.
(ft.)
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
Dia.
(in.)
7.96
8.07
8.18
8.29
8.40
8.51
8.62
8.73
8.84
8.95
9.06
9.18
9.29
9.40
9.51
9.62
9.73
9.84
9.95
10.06
10.17
10.28
10.39
10.50
10.61
10.73
10.84
10.95
11.06
11.17
11.28
11.39
11.50
11.61
11.72
11.83
11.94
12.05
12.16
12.28
12.39
12.50
12.61
12.72
12.83
12.94
13.05
13.16
13.27
13.38
13.49
13.60
13.72
13.83
13.94
14.05
Class 2
Area
(sq. in.)
49.7
51.1
52.5
54.0
55.4
56.9
58.4
59.9
61.4
63.0
64.5
66.1
67.7
69.4
71.0
72.7
74.3
76.0
77.8
79.5
81.3
83.0
84.8
86.7
88.5
90.4
92.2
94.1
96.0
98.0
99.9
101.9
103.9
105.9
107.9
110.0
112.0
114.1
116.2
118.4
120.5
122.7
124.8
127.0
129.3
131.5
133.8
136.0
138.3
140.7
143.0
145.4
147.7
150.1
152.5
155.0
Moment
(ft-k)
33.0
34.4
35.8
37.3
38.8
40.4
42.0
43.6
45.3
47.0
48.8
50.6
52.4
54.3
56.3
58.2
60.3
62.4
64.5
66.7
68.9
71.2
73.8
75.9
78.3
80.8
83.3
85.9
88.5
91.2
93.9
96.7
99.6
102.5
105.4
108.4
111.5
114.6
117.8
121.1
124.4
127.7
131.2
134.7
138.2
141.8
145.5
149.2
153.0
156.9
160.8
164.8
168.8
173.0
177.2
181.4
Dia.
(in.)
7.32
7.43
7.53
7.64
7.75
7.85
7.96
8.06
8.17
8.28
8.38
8.49
8.59
8.70
8.81
8.91
9.02
9.12
9.23
9.34
9.44
9.55
9.66
9.76
9.87
9.97
10.08
10.19
10.29
10.40
10.50
10.61
10.72
10.82
10.93
11.03
11.14
11.25
11.35
11.46
11.57
11.67
11.78
11.88
11.99
12.10
12.20
12.31
12.41
12.52
12.62
12.73
12.84
12.94
13.05
13.16
Class 3
Area
(sq. in.)
42.1
43.3
44.6
45.8
47.1
48.4
49.7
51.1
52.4
53.8
55.2
56.6
58.0
59.5
60.9
62.4
63.9
65.4
66.9
68.5
70.0
71.6
73.2
74.8
76.5
78.1
79.8
81.5
83.2
84.9
86.7
88.4
90.2
92.0
93.8
95.6
97.5
99.3
101.2
103.1
105.1
107.0
108.9
110.9
112.9
114.9
116.9
119.0
121.0
123.1
125.2
127.3
129.5
131.6
133.8
136.0
Moment
(ft-k)
25.7
26.8
28.0
29.2
30.4
31.7
33.0
34.3
35.7
37.1
38.5
40.0
41.5
43.1
44.7
46.3
48.0
49.7
51.5
53.3
55.1
57.0
58.9
60.9
62.9
64.9
67.0
69.2
71.4
73.6
75.9
78.2
80.5
83.0
85.4
87.9
90.5
93.1
95.8
98.5
101.2
104.1
106.9
109.8
112.8
115.8
118.9
122.0
125.2
128.5
131.7
135.1
138.5
142.0
145.5
149.1
Dist.
(ft.)
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
Bulletin 1724E-200
Page F-13
DOUGLAS FIR AND SOUTHERN YELLOW PINE
Ultimate Bending Stress – 8000 psi
75 ft.
Dist.
(ft.)
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
Dia.
(in.)
16.08
16.20
16.32
16.44
16.57
16.69
16.81
16.93
17.05
17.18
17.30
17.42
17.54
17.67
17.73
17.80
17.87
17.93
18.00
18.07
75ft.
Class H1
Area
Moment
(sq. in.)
(ft-k)
203.0
272.0
206.1
278.2
209.2
284.6
212.4
291.0
215.5
297.5
218.7
304.2
221.9
310.9
225.2
317.8
228.4
324.7
231.7
331.17
235.0
338.8
238.4
346.1
241.7
353.4
245.1
360.9
247.0
365.0
248.8
369.1
250.7
373.3
252.6
377.5
254.5
381.7
256.4
386.0
Dia.
(in.)
15.18
15.30
15.42
15.53
15.65
15.77
15.89
16.01
16.12
16.24
16.36
16.48
16.59
16.71
16.78
16.84
16.91
16.98
17.05
17.11
Class 1
Area
(sq. in.)
181.0
183.8
186.7
189.5
192.4
195.3
198.3
201.2
204.2
207.2
210.2
213.2
216.3
219.3
221.1
222.9
224.6
226.4
228.2
230.0
Moment
(ft-k)
229.0
234.4
239.8
245.4
251.0
256.7
262.5
268.4
274.3
280.4
286.5
292.7
299.0
305.4
309.1
312.8
316.6
320.3
324.1
328.0
Dist.
(ft.)
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
Dia.
(in.)
14.16
14.27
14.38
14.49
14.60
14.71
14.82
14.93
15.04
15.15
15.27
15.38
15.49
15.60
15.66
15.73
15.80
15.86
15.93
16.00
Class 2
Area
(sq. in.)
157.4
159.9
162.4
164.9
167.4
170.0
172.5
175.1
177.7
180.4
183.0
185.7
188.4
191.1
192.7
194.4
196.0
197.7
199.3
201.0
Moment
(ft-k)
185.7
190.1
194.6
199.1
203.7
208.4
213.1
217.9
222.8
227.8
232.8
237.9
243.1
248.3
251.5
254.8
258.0
261.3
264.6
268.0
Dia.
(in.)
13.26
13.37
13.48
13.58
13.69
13.79
13.90
14.01
14.11
14.22
14.32
14.43
14.54
14.64
14.71
14.78
14.84
14.91
14.98
15.04
Class 3
Area
(sq. in.)
138.2
140.4
142.6
144.9
147.1
149.4
151.7
154.1
156.4
158.8
161.1
163.5
166.0
168.4
169.9
171.5
173.0
174.6
176.2
177.7
Moment
(ft-k)
152.7
156.4
160.1
164.0
167.8
171.8
175.8
179.8
183.9
188.1
192.4
196.7
201.0
205.5
208.3
211.1
214.0
216.9
219.9
222.8
Dist.
(ft.)
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
Bulletin 1724E-200
Page F-14
DOUGLAS FIR AND SOUTHERN YELLOW PINE
Ultimate Bending Stress – 8000 psi
80 ft.
Dist.
(ft.)
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
Dia.
(in.)
9.231
9.351
9.472
9.592
9.713
9.833
9.954
10.07
10.19
10.31
10.44
10.56
10.68
10.8
10.92
11.04
11.16
11.28
11.4
11.52
11.64
11.76
11.88
12
12.12
12.24
12.36
12.48
12.6
12.72
12.84
12.96
13.09
13.21
13.33
13.45
13.57
13.69
13.81
13.93
14.05
14.17
14.29
14.41
14.53
14.65
14.77
14.89
15.01
15.13
15.25
15.37
15.49
15.61
15.73
15.86
80 ft.
Class H1
Area
Moment
(sq. in.)
(ft-k)
66.92
51.5
66.68
53.5
70.46
55.6
72.27
57.8
74.09
60.0
75.94
62.2
77.81
64.5
79.71
66.9
81.63
69.3
83.57
71.8
85.53
74.4
87.51
77.0
89.52
79.6
91.55
82.4
93.61
85.2
95.68
88.0
97.78
90.9
99.91
93.9
102.05
96.9
104.22
100.0
106.41
103.2
108.62
106.5
110.86
109.8
113.12
113.1
115.40
116.6
117.71
120.1
120.03
123.7
122.38
127.3
124.76
131.0
127.15
134.8
129.57
138.7
132.01
142.6
134.48
146.6
136.96
150.7
139.47
154.9
142.01
159.1
144.56
163.4
147.14
167.8
149.74
172.3
152.36
176.8
155.01
181.5
157.68
186.2
160.37
191.0
163.09
195.8
165.82
200.8
168.58
205.8
171.37
210.9
174.17
216.1
177.00
221.4
179.85
226.8
182.73
232.3
185.62
237.8
188.54
243.4
191.49
249.2
194.45
255.0
197.44
260.9
Dia.
(in.)
8.594
8.711
8.827
8.943
9.059
9.175
9.291
9.407
9.523
9.64
9.756
9.872
9.988
10.1
10.22
10.34
10.45
10.57
10.68
10.8
10.92
11.03
11.15
11.27
11.38
11.5
11.61
11.73
11.85
11.96
12.08
12.19
12.31
12.43
12.54
12.66
12.78
12.89
13.01
13.12
13.24
13.36
13.47
13.59
13.7
13.82
13.94
14.05
14.17
14.29
14.4
14.52
14.63
14.75
14.87
14.98
Class 1
Area
(sq. in.)
58.01
59.59
61.19
62.81
64.45
66.12
67.80
69.51
71.23
72.98
74.75
76.54
78.35
80.18
82.04
83.91
85.81
87.73
89.67
91.63
93.61
95.61
97.63
99.68
101.74
103.83
105.94
108.07
110.22
112.39
114.58
116.80
119.03
121.29
123.57
125.87
128.19
130.53
132.89
135.27
137.68
140.10
142.55
145.02
147.51
150.02
152.55
155.10
157.68
160.27
162.89
165.53
168.19
170.87
173.57
176.29
Moment
(ft-k)
41.5
43.3
45.0
46.8
48.7
50.6
52.5
54.5
56.5
58.6
60.8
63.0
65.2
67.5
69.9
72.3
74.7
77.3
79.8
82.5
85.2
87.9
90.7
93.6
96.5
99.5
102.5
105.6
108.8
112.0
115.3
118.7
122.1
125.6
129.2
132.8
136.5
140.2
144.0
147.9
151.9
155.9
160.0
164.2
168.5
172.8
177.2
181.6
186.2
190.8
195.5
200.3
205.1
210.0
215.0
220.1
Dist.
(ft.)
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
Dia.
(in.)
7.958
8.067
8.177
8.287
8.396
8.506
8.616
8.726
8.835
8.945
9.055
9.164
9.274
9.384
9.493
9.603
9.713
9.822
9.932
10.04
10.15
10.26
10.37
10.48
10.59
10.7
10.81
Class 2
Area
(sq. in.)
49.74
51.12
52.52
53.93
55.37
56.83
58.30
59.80
61.31
62.84
64.39
65.96
67.55
69.16
70.78
72.43
74.09
75.78
77.48
79.20
80.94
82.70
84.47
86.27
88.09
89.92
91.77
93.64
95.54
97.44
99.37
101.32
103.29
105.27
107.28
109.30
111.34
113.40
115.48
117.58
119.70
121.84
123.99
126.17
128.36
130.57
132.80
135.05
137.32
139.61
141.91
144.24
146.58
148.95
151.33
153.73
Moment
(ft-k)
33.0
34.4
35.8
37.2
38.7
40.3
41.9
43.5
45.1
46.8
48.6
50.46
52.2
54.1
56.0
58.0
60.0
62.0
64.1
66.3
68.5
70.7
73.0
75.3
77.7
80.2
82.7
85.2
87.8
90.5
93.1
95.9
98.7
101.6
104.5
107.4
110.5
113.6
116.7
119.9
123.1
126.5
129.8
133.3
136.7
140.3
143.9
147.6
151.3
155.1
159.0
162.9
166.9
170.9
175.0
179.2
Dia.
(in.)
7.321
7.424
7.528
7.631
7.734
7.837
7.941
8.044
8.147
8.25
8.353
8.457
8.56
8.663
8.766
8.87
8.973
9.076
9.179
9.283
9.386
9.489
9.592
9.696
9.799
9.902
10.01
10.11
10.21
10.31
10.42
10.52
10.62
10.73
10.83
10.93
11.04
11.14
11.24
11.35
11.45
11.55
11.66
11.76
11.86
11.97
12.07
12.17
12.28
12.38
12.48
12.59
12.69
12.79
12.9
13
Class 3
Area
(sq. in.)
42.10
43.29
44.50
45.73
46.98
48.24
49.52
50.82
52.13
53.46
54.81
56.17
57.55
58.94
60.36
61.79
63.23
64.70
66.18
67.68
69.19
70.72
72.27
73.83
75.41
77.01
78.62
80.25
81.90
83.57
85.25
86.94
88.66
90.39
92.14
93.90
95.68
97.48
99.30
101.13
102.98
104.84
106.72
108.62
110.54
112.47
114.42
116.39
118.37
120.37
122.38
124.42
126.47
128.53
130.61
132.71
Moment
(ft-k)
25.7
26.8
27.9
29.1
30.3
31.5
32.8
34.1
35.4
36.8
38.2
39.6
41.1
42.6
44.1
45.7
47.3
48.9
50.6
52.4
54.1
55.9
57.8
59.7
61.6
63.5
65.6
67.6
69.7
71.8
74.0
76.2
78.5
80.8
83.2
85.6
88.0
90.5
93.0
95.6
98.3
100.9
103.7
106.5
109.3
112.2
115.1
118.1
121.1
124.2
127.3
130.5
133.7
137.0
140.4
143.8
Dist.
(ft.)
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
Bulletin 1724E-200
Page F-15
DOUGLAS FIR AND SOUTHERN YELLOW PINE
Ultimate Bending Stress – 8000 psi
80 ft.
Dist.
(ft.)
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
Dia.
(in.)
15.98
16.1
16.22
16.34
16.46
16.58
16.7
16.82
16.94
17.06
17.18
17.3
17.42
17.54
17.66
17.78
17.9
18.02
18.14
18.21
18.28
18.34
18.41
18.48
18.54
80 ft.
Class H1
Area
Moment
(sq. in.)
(ft-k)
200.45
266.9
203.49
272.9
206.54
279.1
209.62
285.4
212.72
291.7
215.85
298.2
219.00
304.7
222.17
311.4
225.36
318.1
228.58
325.0
231.82
331.9
235.08
338.9
238.36
346.0
241.67
353.3
245.00
360.6
248.35
368.0
251.73
375.6
255.13
383.2
258.55
390.9
260.46
395.3
262.37
399.6
264.29
404.0
266.22
408.5
268.16
412.9
270.10
417.4
Dia.
(in.)
15.1
15.21
15.33
15.45
15.56
15.68
15.8
15.91
16.03
16.14
16.26
16.38
16.49
16.61
16.72
16.84
16.96
17.07
17.19
17.26
17.32
17.39
17.46
17.52
17.59
Class 1
Area
(sq. in.)
179.04
181.80
184.59
187.39
190.22
193.07
195.94
198.84
201.75
204.68
207.64
201.62
213.61
216.63
219.67
222.74
225.82
228.92
232.05
233.86
235.67
237.49
239.32
241.16
243.00
Moment
(ft-k)
225.3
230.5
235.8
241.2
246.7
252.3
257.9
263.6
269.5
275.4
281.3
287.4
293.6
299.8
306.2
312.6
319.1
325.7
332.4
336.3
340.2
344.2
348.1
352.2
356.2
Dist.
(ft.)
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
Dia.
(in.)
14.1
14.21
14.32
14.43
14.54
14.65
14.76
14.87
14.98
15.09
15.2
15.31
15.42
15.53
15.64
15.75
15.86
15.96
16.07
16.14
16.21
16.28
16.34
16.41
16.48
Class 2
Area
(sq. in.)
156.15
158.59
161.05
163.52
166.02
168.53
171.07
173.62
176.19
178.78
181.39
184.02
186.66
189.33
192.02
194.72
197.44
200.18
202.94
204.63
206.33
208.04
209.75
211.47
213.20
Moment
(ft-k)
183.5
187.8
192.2
196.6
201.1
205.7
210.4
215.1
219.9
224.8
229.7
234.7
239.8
245.0
250.2
255.5
260.9
266.3
271.9
275.3
278.7
282.2
285.6
289.2
292.7
Dia.
(in.)
13.1
13.21
13.31
13.41
13.52
13.62
13.72
13.82
13.93
14.03
14.13
14.24
14.34
14.44
14.55
14.65
14.75
14.86
14.96
15.03
15.09
15.16
15.23
15.29
15.36
Class 3
Area
(sq. in.)
134.83
136.96
139.11
141.28
143.46
145.66
147.88
150.11
152.36
154.63
156.91
159.21
161.53
163.87
166.22
168.58
170.97
173.37
175.79
177.36
178.94
180.53
182.13
183.73
185.34
Moment
(ft-k)
147.2
150.7
154.3
157.9
161.6
165.3
169.1
172.9
176.8
180.8
184.8
188.9
193.0
197.2
201.5
205.8
210.2
214.6
219.2
222.1
225.1
228.1
231.1
234.2
237.3
Dist.
(ft.)
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
Bulletin 1724E-200
Page F-16
DOUGLAS FIR AND SOUTHERN YELLOW PINE
Ultimate Bending Stress – 8000 psi
85 ft.
Dist.
(ft.)
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
Dia.
(in.)
9.23
9.35
9.47
9.59
9.71
9.83
9.94
10.06
10.18
10.30
10.42
10.54
10.66
10.78
10.90
11.01
11.13
11.25
11.37
11.49
11.61
11.73
11.85
11.96
12.08
12.20
12.32
12.44
12.56
12.68
12.80
12.92
13.03
13.15
13.27
13.39
13.51
13.63
13.75
13.87
13.99
14.10
14.22
14.34
14.46
14.58
14.70
14.82
14.94
15.06
15.17
15.29
15.41
15.53
15.65
15.77
85 ft.
Class H1
Area
Moment
(sq. in.)
(ft-k)
66.92
51.5
68.66
53.5
70.42
55.6
72.20
57.7
74.00
59.9
75.82
62.1
77.67
64.4
79.53
66.7
81.42
69.1
83.34
71.5
85.27
74.0
87.23
76.6
89.20
79.2
91.21
81.9
93.23
84.6
95.27
87.4
97.34
90.3
99.43
93.2
101.54
96.2
103.68
99.3
105.83
102.4
108.01
105.6
110.21
108.8
112.44
112.1
114.68
115.5
116.95
118.9
119.24
122.4
121.55
126.0
123.88
129.7
126.24
133.4
128.62
137.2
131.02
141.0
133.44
144.9
135.88
148.9
138.35
153.0
140.84
157.2
143.35
161.4
145.89
165.7
148.44
170.1
151.02
174.5
153.62
179.0
156.24
183.6
158.89
188.3
161.55
193.1
164.24
197.9
166.95
202.8
169.69
207.8
172.44
212.9
175.22
218.1
178.02
223.3
180.04
228.7
183.69
234.1
186.55
239.6
189.44
245.2
192.35
250.9
195.28
256.6
Dia.
(in.)
8.59
8.71
8.82
8.93
9.05
9.16
9.27
9.38
9.50
9.61
9.72
9.84
9.95
10.06
10.17
10.29
10.40
10.51
10.63
10.74
10.85
10.96
11.08
11.19
11.30
11.41
11.53
11.64
11.75
11.87
11.98
12.09
12.20
12.32
12.43
12.54
12.66
12.77
12.88
12.99
13.11
13.22
13.33
13.45
13.56
13.67
13.78
13.90
14.01
14.12
14.24
14.35
14.46
14.57
14.69
14.80
Class 1
Area
(sq. in.)
58.01
59.55
61.10
62.67
64.26
65.88
67.51
69.16
70.84
72.53
74.24
75.98
77.73
79.50
81.29
83.11
84.94
86.79
88.67
90.56
92.47
94.40
96.36
98.33
100.32
102.34
104.37
106.42
108.49
110.59
112.70
114.83
116.99
119.16
121.35
123.56
125.80
128.05
130.32
132.62
134.93
137.26
139.61
141.99
144.38
146.79
149.23
151.68
154.15
156.64
159.16
161.69
164.24
166.81
169.41
172.02
Moment
(ft-k)
41.5
43.2
44.9
46.7
48.4
50.3
52.2
54.1
56.1
58.1
60.2
62.3
64.4
66.7
68.9
71.2
73.6
76.0
78.5
81.0
83.6
86.3
88.9
91.7
94.5
97.3
100.3
103.2
106.3
109.4
112.5
115.7
119.0
122.3
125.7
129.2
132.7
136.3
139.9
143.6
147.4
151.2
155.1
159.1
163.1
167.2
171.4
175.7
180.0
184.3
188.8
193.3
197.9
202.6
207.3
212.1
Dist.
(ft.)
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
Dia.
(in.)
7.96
8.06
8.17
8.28
8.38
8.49
8.60
8.71
8.81
8.92
9.03
9.13
9.24
9.35
9.45
9.56
9.67
9.77
9.88
9.99
10.09
10.20
10.31
10.41
10.52
10.63
10.73
10.84
10.95
11.05
11.16
11.27
11.37
11.48
11.59
11.69
11.80
11.91
12.02
12.12
12.23
12.34
12.44
12.55
12.66
12.76
12.87
12.98
13.08
13.19
13.30
13.40
13.51
13.62
13.72
13.83
Class 2
Area
(sq. in.)
49.74
51.08
52.44
53.82
55.22
56.63
58.07
59.52
60.99
62.47
63.98
65.50
67.04
68.60
70.18
71.77
73.38
75.01
76.66
78.33
80.01
81.71
83.43
85.17
86.93
88.70
90.49
92.30
94.13
95.97
97.84
99.72
101.61
103.53
105.47
107.42
109.39
111.38
113.38
115.41
117.45
119.51
121.59
123.68
125.80
127.93
130.08
132.25
134.43
136.63
138.86
141.09
143.35
145.63
147.92
150.23
Moment
(ft-k)
33.0
34.3
35.7
37.1
38.6
40.1
41.6
43.2
44.8
46.4
48.1
49.8
51.6
53.4
55.3
57.2
59.1
61.1
63.1
65.2
67.3
69.5
71.7
73.9
76.2
78.6
80.9
83.4
85.9
88.4
91.0
93.6
96.3
99.1
101.8
104.7
107.6
110.5
113.5
116.6
119.7
122.9
126.1
129.3
132.7
136.1
139.5
143.0
146.6
150.2
153.9
157.6
161.4
165.2
169.2
173.1
Dia.
(in.)
7.32
7.42
7.52
7.62
7.72
7.82
7.93
8.03
8.13
8.23
8.33
8.43
8.53
8.63
8.73
8.83
8.93
9.03
9.13
9.24
9.34
9.44
9.54
9.64
9.74
9.84
9.94
10.04
10.14
10.24
10.34
10.44
10.54
10.65
10.75
10.85
10.95
11.05
11.15
11.25
11.35
11.45
11.55
11.65
11.75
11.85
11.95
12.06
12.16
12.26
12.36
12.46
12.56
12.66
12.76
12.86
Class 3
Area
(sq. in.)
42.10
43.26
44.45
45.64
46.86
48.09
49.33
50.60
51.87
53.17
54.48
55.80
57.14
58.50
59.88
61.27
62.67
64.09
65.53
66.98
68.45
69.94
71.44
72.96
74.49
76.04
77.60
79.18
80.78
82.39
84.02
85.67
87.33
89.00
90.69
92.40
94.13
95.87
97.62
99.40
101.18
102.99
104.81
106.64
108.49
110.36
112.25
114.15
116.06
117.99
119.94
121.90
123.88
125.88
127.89
129.92
Moment
(ft-k)
25.7
26.8
27.9
29.0
30.2
31.4
32.6
33.8
35.1
36.5
37.8
39.2
40.6
42.1
43.6
45.1
46.7
48.2
49.9
51.5
53.3
55.0
56.8
58.6
60.5
62.3
64.3
66.3
68.3
70.3
72.4
74.6
76.7
79.0
81.2
83.5
85.9
88.3
90.7
93.2
95.7
98.3
100.9
103.6
106.3
109.0
111.8
114.7
117.6
120.5
123.5
126.6
129.7
132.8
136.0
139.2
Dist.
(ft.)
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
Bulletin 1724E-200
Page F-17
DOUGLAS FIR AND SOUTHERN YELLOW PINE
Ultimate Bending Stress – 8000 psi
85 ft.
Dist.
(ft.)
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
81
82
83
84
85
Dia.
(in.)
15.89
16.01
16.13
16.24
16.36
16.48
16.60
16.72
16.84
16.96
17.08
17.19
17.31
17.43
17.55
17.67
17.79
17.91
18.03
18.15
18.26
18.38
18.50
18.62
18.69
18.75
18.82
18.89
18.96
19.02
85 ft.
Class H1
Area
Moment
(sq. in.)
(ft-k)
198.24
262.5
201.22
268.4
204.22
274.4
207.24
280.5
210.28
286.7
213.35
293.0
216.44
299.4
219.55
305.9
222.68
312.5
225.83
319.1
229.01
325.9
232.21
332.7
235.43
339.7
238.68
346.7
241.94
353.9
245.23
361.1
248.54
368.4
251.87
375.9
255.23
383.4
258.60
391.0
262.00
398.8
265.42
406.6
268.87
414.6
272.33
422.6
274.29
427.2
276.26
431.8
278.23
436.4
280.21
441.1
282.20
445.8
284.19
450.5
Dia.
(in.)
14.91
15.03
15.14
15.25
15.36
15.48
15.59
15.70
15.81
15.93
16.04
16.15
16.27
16.38
16.49
16.60
16.72
16.83
16.94
17.06
17.17
17.28
17.39
17.51
17.57
17.64
17.71
17.77
17.84
17.91
Class 1
Area
(sq. in.)
174.65
177.30
179.98
182.67
185.38
188.12
190.87
193.64
196.43
199.25
202.08
204.93
207.80
210.70
213.61
216.54
219.49
222.47
225.46
228.47
231.50
234.56
237.63
240.72
242.56
244.41
246.27
248.13
250.00
251.88
Moment
(ft-k)
217.0
222.0
227.0
232.2
237.3
242.6
248.0
253.4
258.9
264.5
270.1
275.9
281.7
287.6
293.6
299.6
305.8
312.0
318.3
324.7
331.2
337.8
344.4
351.2
355.2
359.3
363.4
367.5
371.7
375.9
Dist.
(ft.)
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
81
82
83
84
85
Dia.
(in.)
13.94
14.04
14.15
14.26
14.36
14.47
14.58
14.68
14.79
14.90
15.00
15.11
15.22
15.33
15.43
15.54
15.65
15.75
15.86
15.97
16.07
16.18
16.29
16.39
16.46
16.53
16.59
16.66
16.73
16.79
Class 2
Area
(sq. in.)
152.56
154.91
157.27
159.65
162.05
164.47
166.91
169.36
171.83
174.32
176.83
179.36
181.90
184.46
187.04
189.64
192.25
194.88
197.54
200.20
202.89
205.60
208.32
211.06
212.78
214.52
216.25
218.00
219.75
221.51
Moment
(ft-k)
177.2
181.3
185.5
189.7
194.0
198.3
202.8
207.2
211.8
216.4
221.1
225.9
230.7
235.6
240.5
245.6
250.7
255.8
261.1
266.4
271.8
277.2
282.7
288.3
291.9
295.4
299.0
302.7
306.3
310.0
Dia.
(in.)
12.96
13.06
13.16
13.26
13.36
13.47
13.57
13.67
13.77
13.87
13.97
14.07
14.17
14.27
14.37
14.47
14.57
14.67
14.78
14.88
14.98
15.08
15.18
15.28
15.35
15.41
15.48
15.55
15.61
15.68
Class 3
Area
(sq. in.)
131.96
134.02
136.09
138.18
140.29
142.41
144.55
146.71
148.88
151.06
153.27
155.48
157.72
159.97
162.23
164.52
166.81
169.13
171.46
173.80
176.17
178.54
180.94
183.35
184.95
186.57
188.19
189.82
191.46
193.10
Moment
(ft-k)
142.5
145.9
149.3
152.7
156.2
159.8
163.4
167.1
170.8
174.6
178.4
182.3
186.2
190.2
194.3
198.4
202.6
206.8
211.1
215.5
219.9
224.3
228.9
233.4
236.5
239.6
242.8
245.9
249.1
252.3
Dist.
(ft.)
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
81
82
83
84
85
Bulletin 1724E-200
Page F-18
DOUGLAS FIR AND SOUTHERN YELLOW PINE
Ultimate Bending Stress – 8000 psi
90 ft.
Dist.
(ft.)
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
Dia.
(in.)
9.23
9.35
9.46
9.58
9.69
9.81
9.92
10.04
10.16
10.27
10.39
10.50
10.62
10.73
10.85
10.96
11.08
11.20
11.31
11.43
11.54
11.66
11.77
11.89
12.00
12.12
12.24
12.35
12.47
12.58
12.70
12.81
12.93
13.05
13.16
13.28
13.39
13.51
13.62
13.74
13.85
13.97
14.09
14.20
14.32
14.43
14.55
14.66
14.78
14.89
15.01
15.13
15.24
15.36
15.47
15.59
90 ft.
Class H1
Area
Moment
(sq. in.)
(ft-k)
66.92
51.5
68.61
53.4
70.32
55.4
72.05
57.5
73.80
59.6
75.57
61.8
77.36
64.0
79.17
66.2
81.00
68.6
82.86
70.9
84.73
73.3
86.63
75.8
88.55
78.3
90.48
80.9
92.44
83.6
94.42
86.3
96.42
89.0
98.45
91.8
100.49
94.7
102.55
97.7
104.64
100.6
106.74
103.7
108.87
106.8
111.02
110.0
113.19
113.2
115.38
116.5
117.59
119.9
119.82
123.3
122.07
126.8
124.35
130.4
126.64
134.0
128.96
137.7
131.30
141.5
133.65
145.3
136.03
149.2
138.43
153.2
140.85
157.2
143.29
161.3
145.76
165.5
148.24
169.7
150.75
174.0
153.27
178.4
155.82
182.9
158.39
187.4
160.97
192.0
163.58
196.7
166.21
210.5
168.87
206.3
171.54
211.3
174.23
216.3
176.95
221.3
179.68
226.5
182.44
231.7
185.22
237.0
188.01
242.4
190.83
247.9
Dia.
(in.)
8.59
8.70
8.81
8.92
9.03
9.14
9.25
9.36
9.47
9.58
9.69
9.80
9.91
10.02
10.13
10.24
10.35
10.46
10.57
10.68
10.79
10.90
11.01
11.12
11.23
11.34
11.45
11.56
11.67
11.78
11.89
12.00
12.11
12.22
12.33
12.44
12.55
12.66
12.77
12.88
12.99
13.10
13.21
13.32
13.43
13.54
13.65
13.76
13.87
13.98
14.09
14.20
14.31
14.42
14.53
14.64
Class 1
Area
(sq. in.)
58.01
59.51
61.02
62.55
64.10
65.67
67.25
68.86
70.49
72.13
73.80
75.48
77.18
78.90
80.64
82.40
84.14
85.97
87.79
89.62
91.48
93.35
95.24
97.15
99.08
101.03
103.00
104.98
106.99
109.01
111.05
113.12
115.20
117.30
119.42
121.56
123.71
125.89
128.08
130.30
132.53
134.78
137.05
139.34
141.65
143.98
146.33
148.69
151.08
153.48
155.90
158.34
160.80
163.28
165.78
168.30
Moment
(ft-k)
41.5
43.2
44.8
46.5
48.3
50.0
51.9
53.7
55.6
57.6
59.6
61.7
63.8
65.9
68.1
70.3
72.6
75.0
77.3
79.8
82.3
84.8
87.4
90.0
92.7
95.5
98.3
101.1
104.1
107.0
110.0
113.1
116.3
119.5
122.7
126.0
129.4
132.8
136.3
139.9
143.5
147.1
150.9
154.7
158.5
162.5
166.4
170.5
174.6
178.8
183.0
187.4
191.7
196.2
200.7
205.3
Dist.
(ft.)
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
Dia.
(in.)
7.96
8.06
8.17
8.28
8.38
8.49
8.59
8.70
8.81
8.91
9.02
9.12
9.23
9.34
9.44
9.55
9.66
9.76
9.87
9.97
10.08
10.19
10.29
10.40
10.50
10.61
10.72
10.82
10.93
11.03
11.14
11.25
11.35
11.46
11.57
11.67
11.78
11.88
11.99
12.10
12.20
12.31
12.41
12.52
12.63
12.73
12.84
12.94
13.05
13.16
13.26
13.37
13.48
13.58
13.69
13.79
Class 2
Area
(sq. in.)
49.74
51.07
52.42
53.79
55.18
56.59
58.01
59.45
60.91
62.39
63.88
65.39
66.92
68.47
70.04
71.62
73.22
74.84
76.47
78.13
79.80
81.49
83.19
84.92
86.66
88.42
90.20
91.99
93.80
95.63
97.48
99.35
101.23
103.13
105.05
106.99
108.94
110.91
112.90
114.91
116.93
118.98
121.04
123.12
125.21
127.32
129.45
131.60
133.77
135.95
138.16
140.37
142.61
144.87
147.14
149.43
Moment
(ft-k)
33.0
34.3
35.7
37.1
38.5
40.0
41.5
43.1
44.7
46.3
48.1
49.7
51.5
53.3
55.1
57.0
58.9
60.9
62.9
64.9
67.0
69.2
71.5
73.6
75.9
78.2
80.5
83.0
85.4
87.9
90.5
93.1
95.8
98.5
101.2
104.1
106.9
109.8
112.8
115.8
118.9
122.0
125.2
128.5
131.7
135.1
138.5
142.0
145.5
149.1
152.7
156.4
160.1
164.0
167.8
171.8
Dia.
(in.)
7.32
7.42
7.52
7.62
7.72
7.81
7.91
8.01
8.11
8.21
8.31
8.40
8.50
8.60
8.70
8.80
8.90
9.00
9.09
9.19
9.29
9.39
9.49
9.59
9.69
9.78
9.88
9.98
10.08
10.18
10.28
10.38
10.47
10.57
10.67
10.77
10.87
10.97
11.07
11.16
11.26
11.36
11.46
11.56
11.66
11.75
11.85
11.95
12.05
12.15
12.25
12.35
12.44
12.54
12.64
12.74
Class 3
Area
(sq. in.)
42.10
43.24
44.39
45.56
46.75
47.95
49.17
50.40
51.65
52.91
54.19
55.48
56.79
58.11
59.45
60.81
62.18
63.56
64.96
66.38
67.81
69.25
70.71
72.19
73.68
75.19
76.71
78.25
79.80
81.37
82.95
84.55
86.16
87.79
89.43
91.09
92.77
94.46
96.16
97.88
99.62
101.37
103.13
104.91
106.71
108.52
110.35
112.19
114.05
115.92
117.81
119.71
121.63
123.56
125.51
127.48
Moment
(ft-k)
25.7
26.7
27.8
28.9
30.1
31.2
32.4
33.6
34.9
36.2
37.5
38.9
40.2
41.7
43.1
44.6
46.1
47.7
49.2
50.9
52.5
54.2
55.9
57.7
59.5
61.3
63.2
65.1
67.0
69.0
71.0
73.1
75.2
77.3
79.5
81.8
84.0
86.3
88.7
91.1
93.5
96.0
98.5
101.0
103.7
106.3
109.0
111.7
114.5
117.4
120.2
123.2
126.1
129.2
132.2
135.3
Dist.
(ft.)
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
Bulletin 1724E-200
Page F-19
DOUGLAS FIR AND SOUTHERN YELLOW PINE
Ultimate Bending Stress – 8000 psi
90 ft.
Dist.
(ft.)
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
81
82
83
84
85
86
87
88
89
90
Dia.
(in.)
15.70
15.82
15.93
16.05
16.17
16.28
16.40
16.51
16.63
16.74
16.86
16.97
17.09
17.21
17.32
17.44
17.55
17.67
17.78
17.90
18.01
18.13
18.25
18.36
18.48
18.59
18.71
18.82
18.94
19.01
19.07
19.14
19.21
19.27
19.34
90 ft.
Class H1
Area
Moment
(sq. in.)
(ft-k)
193.67
253.4
196.54
259.1
199.42
264.8
202.32
270.6
205.25
276.5
208.19
282.5
211.16
288.5
214.14
294.7
217.15
300.9
220.18
307.2
223.23
313.6
226.30
320.1
229.40
326.7
232.51
333.4
235.64
340.1
238.80
347.0
241.97
353.9
245.17
361.0
248.39
368.1
251.63
375.3
254.89
382.6
258.17
390.1
261.47
397.6
264.79
405.2
268.14
412.9
271.50
420.7
274.89
428.6
278.30
436.6
281.72
444.6
283.72
449.4
285.72
454.1
287.72
458.9
289.73
463.7
291.76
468.6
293.78
473.5
Dia.
(in.)
14.75
14.86
14.97
15.08
15.19
15.30
15.41
15.52
15.63
15.74
15.85
15.96
16.07
16.18
16.29
16.40
16.51
16.62
16.73
16.84
16.95
17.06
17.17
17.28
17.39
17.50
17.61
17.72
17.83
17.89
17.96
18.03
18.09
18.16
18.23
Class 1
Area
(sq. in.)
170.84
173.39
175.96
178.56
181.17
183.80
186.45
189.12
191.81
194.52
197.24
199.99
202.75
205.53
208.34
211.16
214.00
216.86
219.73
222.63
225.55
228.48
231.43
234.41
237.40
240.41
243.44
246.49
249.55
451.43
253.31
255.20
257.10
259.00
260.91
Moment
(ft-k)
210.0
214.7
219.5
224.4
229.3
234.3
239.4
244.6
249.8
255.1
260.5
265.9
271.5
277.1
282.8
288.5
294.4
300.3
306.3
312.4
218.5
324.7
331.1
337.5
343.9
350.5
357.2
363.9
370.7
374.9
379.1
383.4
387.6
391.9
396.3
Dist.
(ft.)
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
81
82
83
84
85
86
87
88
89
90
Dia.
(in.)
13.90
14.01
14.11
14.22
14.32
14.43
14.54
14.64
14.75
14.85
14.96
15.07
15.17
15.28
15.38
15.49
15.60
15.70
15.81
15.92
16.02
16.13
16.23
16.34
16.45
16.55
16.66
16.76
16.87
16.94
17.00
17.07
17.14
17.20
17.27
Class 2
Area
(sq. in.)
151.74
154.06
156.41
158.77
161.14
163.54
165.95
168.39
170.84
173.30
175.79
178.29
180.81
183.35
185.90
188.47
191.07
193.67
196.30
198.94
201.61
204.28
206.98
209.70
212.43
215.18
217.95
220.73
223.53
225.31
227.09
228.88
230.67
232.48
234.29
Moment
(ft-k)
175.8
179.8
183.9
188.1
192.4
196.7
201.0
205.5
210.0
214.5
219.2
223.9
228.6
233.4
238.3
243.3
248.3
253.4
258.6
263.9
269.2
274.6
280.0
285.5
291.1
296.8
302.5
308.4
314.3
318.0
321.8
325.6
329.4
333.3
337.2
Dia.
(in.)
12.84
12.94
13.04
13.13
13.23
13.33
13.43
13.53
13.63
13.73
13.82
13.92
14.02
14.12
14.22
14.32
14.41
14.51
14.61
14.71
14.81
14.91
15.01
15.10
15.20
15.30
15.40
15.50
15.60
15.66
15.73
15.80
15.86
15.93
16.00
Class 3
Area
(sq. in.)
129.45
131.45
133.46
135.48
137.52
139.58
141.65
143.74
145.84
147.95
150.09
152.23
154.40
156.57
158.77
160.97
163.20
165.44
167.69
169.96
172.24
174.54
176.86
179.19
181.53
183.89
186.27
188.66
191.07
192.71
194.35
196.01
197.67
199.34
201.02
Moment
(ft-k)
138.5
141.7
145.0
148.3
151.7
155.1
158.5
162.0
165.6
169.2
172.9
176.6
180.4
184.2
188.1
192.0
196.0
200.1
204.2
208.3
212.6
216.8
221.2
225.5
230.0
234.5
239.0
243.7
248.3
251.5
254.8
258.0
261.3
264.6
268.0
Dist.
(ft.)
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
81
82
83
84
85
86
87
88
89
90
Bulletin 1724E-200
Page F-20
MOMENT REDUCTION DUE TO A
BOLT HOLE IN A POLE
The reduction in moment capacity of a pole caused by a bolt hole is calculated by the equation:
( Fb (b)(b 2 sin 2θ + d n cos 2 θ )
72(1000)
2
M bh =
where:
Fb = Ultimate fiber stress of the wood (psi)
dn = Pole diameter at location ‘n’ (inches)
b = Width of hole, taken as bolt diameter
plus 1/16 inch (inches)
Mbh = Reduction in strength (ft-kips)
The drawings below explain the Pole Moment Reduction table which follows:
0 = 0°
Neutral Axis
-1
0 = sin (3.5/d n )
Neutral Axis
The Pole Moment Reduction table which follows is based on 1000 psi for the fiber stress. For
any species of wood, this number should be multiplied by the fiber stress of the wood divided by
1000.
Bulletin 1724E-200
Page F-21
TABLE F-4
POLE MOMENT (ft-k) REDUCTION
DUE TO BOLT HOLES FOR 1000 psi FIBER STRESS
POLE
3/4 in. *
DIAM 0 DEGREES
THETA
9
0.914
0.78
9.1
0.934
0.93
9.2
0.955
0.96
9.3
0.976
0.98
9.4
0.997
1.00
9.5
1.018
1.02
9.6
1.040
1.04
9.7
1.062
1.06
9.8
1.084
1.08
9.9
1.106
1.11
10
1.128
1.13
10.1
1.151
1.15
10.2
1.174
1.17
10.3
1.197
1.20
10.4
1.221
1.22
10.5
1.244
1.24
10.6
1.268
1.27
10.7
1.292
1.29
10.8
1.316
1.32
10.9
1.341
1.34
11
1.365
1.37
11.1
1.390
1.39
11.2
1.416
1.42
11.3
1.441
1.44
11.4
1.467
1.47
11.5
1.492
1.49
11.6
1.518
1.52
11.7
1.545
1.54
11.8
1.571
1.57
11.9
1.598
1.60
12
1.625
1.63
12.1
1.652
1.65
12.2
1.680
1.68
12.3
1.707
1.71
12.4
1.735
1.74
12.5
1.763
1.76
12.6
1.792
1.79
12.7
1.820
1.82
12.8
1.849
1.85
12.9
1.878
1.88
13
1.907
1.91
13.1
1.937
1.94
13.2
1.966
1.97
13.3
1.996
2.00
13.4
2.026
2.03
13.5
2.057
2.06
13.6
2.087
2.09
13.7
2.118
2.12
13.8
2.149
2.15
13.9
2.180
2.18
14
2.212
2.21
14.1
2.244
2.24
14.2
2.275
2.28
14.3
2.308
2.31
14.4
2.340
2.34
14.5
2.373
2.37
14.6
2.405
2.41
14.7
2.439
2.44
14.8
2.472
2.47
14.9
2.505
2.51
15
2.539
2.54
7/8 in. *
0 DEGREES
THETA
1.055
0.897
1.078
1.078
1.102
1.102
1.126
1.126
1.151
1.151
1.175
1.175
1.200
1.200
1.225
1.225
1.251
1.251
1.276
1.276
1.302
1.302
1.328
1.328
1.355
1.355
1.381
1.381
1.408
1.408
1.436
1.436
1.463
1.463
1.491
1.491
1.519
1.519
1.547
1.547
1.576
1.576
1.604
1.604
1.633
1.633
1.663
1.663
1.692
1.692
1.722
1.722
1.752
1.752
1.782
1.782
1.813
1.813
1.844
1.844
1.875
1.875
1.906
1.906
1.938
1.938
1.970
1.970
2.002
2.002
2.035
2.035
2.067
2.067
2.100
2.100
2.133
2.133
2.167
2.167
2.201
2.201
2.235
2.235
2.269
2.269
2.303
2.303
2.338
2.338
2.373
2.373
2.408
2.408
2.444
2.444
2.480
2.480
2.516
2.516
2.552
2.552
2.589
2.589
2.626
2.626
2.663
2.663
2.700
2.700
2.738
2.738
2.776
2.776
2.814
2.814
2.852
2.852
2.891
2.891
2.930
2.930
*BOLT HOLE = BOLT DIAMETER + 1/16 in.
1
in. *
0 DEGREES
THETA
1.195
1.017
1.222
1.222
1.249
1.249
1.276
1.276
1.304
1.304
1.332
1.332
1.360
1.360
1.388
1.388
1.417
1.417
1.446
1.446
1.476
1.476
1.505
1.505
1.535
1.535
1.566
1.566
1.596
1.596
1.627
1.627
1.658
1.658
1.690
1.690
1.721
1.721
1.753
1.753
1.786
1.786
1.818
1.818
1.851
1.851
1.884
1.884
1.918
1.918
1.952
1.952
1.986
1.986
2.020
2.020
2.055
2.055
2.090
2.090
2.125
2.125
2.161
2.161
2.196
2.196
2.233
2.233
2.269
2.269
2.306
2.306
2.343
2.343
2.380
2.380
2.418
2.418
2.456
2.456
2.494
2.494
2.532
2.532
2.571
2.571
2.610
2.610
2.650
2.650
2.689
2.689
2.729
2.729
2.770
2.770
2.810
2.810
2.851
2.851
2.892
2.892
2.934
2.934
2.976
2.976
3.018
3.018
3.060
3.060
3.103
3.103
3.146
3.146
3.189
3.189
3.232
3.232
3.276
3.276
3.320
3.320
Bulletin 1724E-200
Page F-22
TABLE F-5
VOLUMES FOR DOUGLAS FIR AND
SOUTHERN YELLOW PINE POLES, (cu. ft.)
Height
Pole Classes
ft.
H1
1
2
3
50
55
60
65
70
75
80
85
90
44.1
51.2
58.0
65.2
72.8
80.9
89.5
98.5
106.6
39.3
45.0
51.1
57.2
64.5
71.8
79.6
86.6
93.9
34.1
39.2
44.6
50.5
56.7
62.3
69.3
75.6
83.3
24.4
33.7
38.6
43.8
49.3
54.4
59.7
65.2
71.1
TALBE F-6
POLE WEIGHTS FOR DOUGLAS FIR (TREATED)
(50 pcf assumed) (lbs.)
Height
Pole Classes
ft.
H1
1
2
3
50
55
60
65
70
75
80
85
90
2200
2560
2900
3260
3640
4050
4480
4930
5330
1970
2250
2560
2860
3225
3590
3980
4330
4700
1700
1960
2230
2530
2840
3120
3470
3780
4170
1220
1690
1930
2190
2470
2720
2990
3260
3560
TABLE F-7
POLE WEIGHTS FOR SOUTHERN YELLOW PINE (TREATED)
(60 pcf assumed) (lbs.)
Height
Pole Classes
ft.
H1
1
2
3
50
55
60
65
70
75
80
85
90
2650
3070
3480
3900
4370
4850
5380
5910
6400
2360
2700
3070
3430
3870
4300
4780
5200
5630
2050
2350
2680
3030
3400
3740
4160
4540
5000
1470
2020
2320
2630
2960
3260
3580
3910
4270
Bulletin 1724E-200
Page G-1
APPENDIX G
CROSSARM DATA
•
•
Moment Capacities of
Standard Crossarms
G-2
Crossarm Loading Chart
G-3
Bulletin 1724E-200
Page G-2
MOMENT CAPACITIES OF
STANDARD CROSSARM SIZES
The following table gives moment capacities (MXX, MYY ) of standard size crossarms for
transmission structures in RUS Form 805. The moment capacities are based on the dressed size
of the arms and a modulus of rupture of 7400 psi. MXX is the moment resistance for vertical and
MYY is the moment resistance for longitudinal loads. Section moduli are also given for the
respective axis.
TABLE G-1
CROSSARM SIZES AND MOMENT CAPACITIES
Crossarm Size
SXX(in3)
MXX(ft-k)
SYY(in3)
MYY (ft-k)
3-5/8 x 9-3/8
(2) 3-5/8 x 9-3/8
3-5/8 x 5-5/8
(2) 3-5/8 x 5-5/8
4-1/8 x 5-1/8
(2) 4-1/8 x 5-1/8
4-5/8 x 5-5/8
(2) 5/8 x 5-5/8
5-3.8 x 7-5/8
5-5/8 x 7-3/8
49.9
99.8
17.7
35.3
16.7
33.3
22.7
45.4
49.2
48.2
30.8
61.6
10.9
21.8
10.3
20.6
14.0
28.0
30.4
29.7
18.9
37.8
11.2
22.5
13.3
26.7
18.6
37.1
34.5
36.6
11.7
23.3
6.9
13.9
16.5
16.5
11.5
22.9
21.2
22.5
Example:
Given:
Determine the maximum vertical span for a TSS-1L (69 kV)
Conductor: 266.8 26/7 ACSR
Ldg. Dist:
Heavy
Cond. Wt. (wc):
1.0776 lbs./ft.
51 lbs.
Insulator wt. (Wi):
Moment arm(s):
5.5 ft.
Procedure:
Moment capacity of TSS-1L arm (4-5/8” x 5-5/8”) is 14.0 ft-k.
V .S . =
φMa −(OLF ) (Wi ) ( s)
(OLF ) (Wc ) (s )
= (0.50)(14,000 ) −1.5 (51) (5.5)
(1.5) (1.0776) (5.5)
= 740 ft.
Bulletin 1724E-200
Page G-3
FIGURE G-1
Crossarm Loading Chart - Maximum Permitted Vertical Loads
of Various Sizes of Douglas Fir Crossarms
(A fiber stress of 7400 x 0.5 or 3700 psi is assumed)
8,000
7,000
6,000
Load in Pounds
5,000
4,000
3-5/8 x 9-3/8
3,000
5-5/8 x7-3/8
4-5/8 x 5-5/8
2,000
3-5/8 x 5-5/8
1,000
4-1/8 x 5-
0
2
3
4
5
6
7
Moment Arm in Feet
8
9
10
Bulletin 1724E-200
Page G-4
Blank Page
Bulletin 1724E-200
Page H-1
APPENDIX H
MISCELLANEOUS STRUCTURAL DATA
• Properties of Common Sections
H-2
• Curve for Locating Plane of Contra-flexure
for Braced H-frame structures
H-3
• Tensile Strength of Bolts
H-4
• Rated Breaking Strength of Guy Wire
H-4
Bulletin 1724E-200
Page H-2
TABLE H-1
PROPERTIES OF COMMON SECTIONS
FIGURE H-1
CURVE FOR LOCATING PLANE OF CONTRAFLEXURE
IN X-BRACED H-FRAME STRUCTURES
Bulletin 1724E-200
Page H-3
Bulletin 1724E-200
Page H-4
TABLE H-2
STRENGTHS FOR MACHINE BOLTS
DOUBLE ARMING BOLTS, DOUBLE END BOLTS
(Conforming to ANSI C135.1)
Machine Bolt
Diameter (in.)
1/2”
5/8”
3/4”
7/8”
1”
Tension Stress
Area (in.2)
0.142
0.226
0.334
0.462
0.606
Min. Tensile
Strength (lbs.)
7,800
12, 400
18,350
25,400
33,500
TABLE H-3
STRENGTHS OF ASTM A325
HEAT TREATED, HIGH STRENGTH BOLTS
Machine Bolt
Diameter
(in.)
1/2
5/8
3/4
7/8
1
Tensile
Stress Area
(sq. in.)
0.142
0.226
0.334
0.462
0.606
Minimum Tensile
Strength
(lbs.)
17,500
27,100
40,100
55,450
72,700
Minimum Yield
Strength
(lbs.)
13,050
20,800
30,700
42,500
55,570
TABLE H-4
STRENGTH OF GUY STRANDS
Strand Size
Description
3/8 in.
7 No. 9 AWG
3/8 in.
7/16 in.
7 No. 8 AWG
7 No. 7 AWG
7/16 in.
H.S.
A.C.S
E.H.S
H.S.
A.C.S
A.C.S
E.H.S
Minimum Breaking
Strength (lbs)
10,800
12,600
14,400
14,500
15,930
19,060
20,080
H.S.= high strength, E.H.S. = extra high strength, A.C.S.= aluminum clad steel
Bulletin 1724E-200
Page I-1
APPENDIX I
RI AND TVI
•
Insulator and Hardware RIV
Performance Values
I-2
•
Some Possible Sources of RI
or RVI on Transmission Lines
I-2
•
Formulae for Calculating Surface
Gradients of Conductors
I-3
•
Surface Gradient for Typical Designs
I-5
Bulletin 1724E-200
Page I-2
INSULATOR AND HARDWARE RIV PERFORMANCE VALUES
The values below give recommended maximum RIV levels for insulators plus hardware
assemblies for various voltages. The RIV values are measured using the procedure outlined in
NEMA publication 107, Methods of Measuring Radio Noise – 1964.
TABLE I-1
RIV LEVELS
kVLL
34.5
46
69
115
138
161
230
RIV Level in Microvolts at 1000
kHZ*
100
200
200
200
200
500
500
Note:
The values in Table I-1 are from Figure 3 of “Transmission System Radio
Influence”-IEEE Committee Report – Power Apparatus and System, August
1965. (This publication is the major work on the subject.)
SOME POSSIBLE SOURCES OF RI OR TVI
ON TRANSMISSION LINES
1. Poor contact between metal parts of suspension insulators; an insufficient vertical span or an
uplift condition can cause this.
2. Poor contact between clamps and clamp support brackets on clamp-top insulators;
3. Loose conductor clamps;
4. Loose hardware which can result from wood shrinkage, structure vibration or wind
movement;
5. Loose crossarm braces or bolts;
6. Loose insulator mounting brackets;
7. Loose staples, bonding wire or ground wire;
8. Staples, bonding wire or ground wire too near ungrounded hardware;
9. Bond or ground wire clamped against wood under washer;
10. Unbonded guy wires too close to each other or to pole hardware;
11. Slack guy wire causing poor contact at pole attachments or at anchor eye;
12. Metal-to-metal clearance insufficient on pole hardware;
13. “Trash” on conductors (bits of wire, metal kite strings, tree limb, etc.).
Bulletin 1724E-200
Page I-3
FORMULAE FOR CALCULATING SURFACE
GRADIENTS OF CONDUCTORS
Excessively high conductor surface gradients can result in radio noise, television interference,
and corona. The equations below can be used to check the surface gradient. They are
approximate but yield reasonably accurate results. They assume phase conductors that are far
apart compared to their diameter.
Equation for Single Conductor per Phase:
g=
kV LL
3 r ln
Eq. I-1
D
r
where:
kVLL = line-to-line voltage, kV
r = conductor radius, cm.
D = geometric mean distance (GMD) of the
phase conductors, cm.
g = conductor surface gradient, kV/cm
Equation for Two Conductor Bundle per Phase:
g=
kV LL (1 + 2 r / s )
2 3 r ln
D
rs
Eq. I-2
where:
All the symbols are the same as those above with the addition
that:
s = the separation between subconductors, cm.
Application of Formulae:
It is recommended that transmission line designs that have unusually close phase spacing have
the conductor surface gradient checked. A maximum conductor gradient of 16 kV/cm should be
used.
Bulletin 1724E-200
Page I-4
Example
Determine the conductor gradient for a 230 kV line with (1) a 556.5 kcmil (dove) ACSR
conductor and (2) a 1272 kcmil (pheasant) conductor. GMD for TH-230 is 24.57 feet or 784.90
cm.
556.5 kcmil conductor:
r=
.927
2
(2.54) = 1.18
230 (1.05)
g=
3 (1.18)1n
748.90
1.18
g = 18.3 kV/cm.
The 556.5 kcmil conductor should not be used for 230 kV lines.
1272 kcmil Conductor (1 Conductor):
r=
g=
1.382
2
g=
(2.54) = 1.755
230 (1.05)
3 (1.755) 1n
g = 13.12 kV/cm.
748.90
1.755
Bulletin 1724E-200
Page I-5
TABLE I-2
SURFACE GRADIENT FOR TYPICAL DESIGNS
16 kV/cm recommended to minimize
radio noise
Conductor
Diameter
Radius
(inches)
RAVEN
QUAIL
PIGEON
PENGUIN
WAXWING
PARTRIDGE
MERLIN
LINNET
ORIOLE
CHICKADEE
IBIS
LARK
PELICAN
FLICKER
HAWK
HEN
OSPREY
PARAKEET
DOVE
EAGLE
KINGBIRD
ROOK
GROSBEAK
EGRET
0.398
0.447
0.502
0.563
0.609
0.642
0.684
0.721
0.741
0.743
0.783
0.806
0.814
0.846
0.858
0.883
0.879
0.914
0.927
0.953
0.94
0.977
0.99
1.019
0.199
0.224
0.251
0.282
0.305
0.321
0.342
0.361
0.371
0.372
0.392
0.403
0.407
0.423
0.429
0.442
0.440
0.457
0.464
0.477
0.470
0.489
0.495
0.510
TP-3
TP-3
TS-1 TU-1AA
GMD
GMD
GMD
GMD
2.53
2.53
3.00
3.59
(feet)
77.15
77.15
91.33 109.35
(cm)
Gradien Gradien Gradien Gradien
t
t
t
t
Radiu
s
(kV/cm) (kV/cm) (kV/cm) (kV/cm)
(cm)
34.5
46
69
161
0.505
0.568
0.638
0.715
0.773
0.815
0.869
0.916
0.941
0.944
0.994
1.024
1.034
1.074
1.090
1.121
1.116
1.161
1.177
1.210
1.194
1.241
1.257
1.294
8.23
7.50
6.84
6.25
5.88
5.64
5.37
5.15
5.04
5.03
4.83
4.73
4.69
4.55
4.51
4.41
4.42
4.29
4.25
4.16
4.20
4.08
4.04
3.95
10.97
10.00
9.12
8.33
7.83
7.52
7.16
6.87
6.72
6.71
6.44
6.30
6.25
6.07
6.01
5.88
5.90
5.72
5.66
5.55
5.60
5.44
5.39
5.27
15.92
14.50
13.22
12.06
11.33
10.87
10.34
9.93
9.72
9.69
9.31
9.10
9.03
8.76
8.67
8.48
8.51
8.25
8.17
7.99
8.08
7.84
7.76
7.59
35.91
32.68
29.76
27.14
25.49
24.44
23.24
22.29
21.81
21.76
20.88
20.41
20.25
19.65
19.44
19.00
19.07
18.50
18.30
17.91
18.10
17.56
17.38
17.00
TH-230
GMD
24.57
748.85
Gradien
t
(kV/cm)
230
37.78
34.19
30.94
28.04
26.22
25.06
23.75
22.70
22.18
22.13
21.17
20.65
20.48
19.82
19.59
19.12
19.19
18.57
18.35
17.92
18.13
17.55
17.36
16.94
Bulletin 1724E-200
Page I-6
TABLE I-2 (Continued)
SURFACE GRADIENT FOR TYPICAL DESIGNS
16 kV/cm recommended to minimize
radio noise
Conductor
CUCKOO
DRAKE
MALLARD
TERN
CONDOR
RAIL
CARDINAL
BUNTING
GRACKLE
BITTERN
PHEASANT
LAPWING
FALCON
CHUKAR
BLUEBIRD
Diameter
Radius
(inches)
1.092
1.108
1.14
1.063
1.093
1.165
1.196
1.302
1.338
1.345
1.382
1.502
1.545
1.602
1.762
0.546
0.554
0.570
0.532
0.547
0.583
0.598
0.651
0.669
0.673
0.691
0.751
0.773
0.801
0.881
TP-3
TP-3
TS-1 TU-1AA
GMD
GMD
GMD
GMD
2.53
2.53
3.00
3.59
(feet)
77.15
77.15
91.33 109.35
(cm)
Gradien Gradien Gradien Gradien
t
t
t
t
Radiu
s
(kV/cm) (kV/cm) (kV/cm) (kV/cm)
(cm)
34.5
46
69
161
1.387
1.407
1.448
1.350
1.388
1.480
1.519
1.654
1.699
1.708
1.755
1.908
1.962
2.035
2.238
3.75
3.71
3.63
3.83
3.75
3.57
3.51
3.29
3.23
3.21
3.15
2.96
2.90
2.83
2.64
5.00
4.95
4.84
5.11
5.00
4.77
4.67
4.39
4.30
4.28
4.20
3.95
3.87
3.77
3.52
7.20
7.12
6.97
7.35
7.20
6.86
6.72
6.31
6.18
6.15
6.03
5.67
5.55
5.40
5.04
16.11
15.93
15.59
16.45
16.10
15.33
15.03
14.08
13.79
13.74
13.46
12.64
12.37
12.04
11.21
TH-230
GMD
24.57
748.85
Gradien
t
(kV/cm)
230
15.98
15.79
15.41
16.35
15.97
15.13
14.80
13.79
13.48
13.42
13.12
12.24
11.95
11.60
10.72
Bulletin 1724E-200
Page J-1
APPENDIX J
INSULATOR SWING TABLES
Bulletin 1724E-200
Page J-2
TABLE J-1
INSULATOR SWING VALUES FOR STANDARD TANGENT STRUCTURES
(Porcelain Insulators with Ball Hook and Suspension Clamp
per Drawing TM-1A. Insulator String Lengths per TABLE C-3)
Number of
Insulators
Insulator Swing
Angle In
Degrees
(no wind
clearance,
note 1)
Insulator Swing
Angle In
Degrees
(moderate wind
clearance,
note 2)
Insulator Swing
Angle In
Degrees
(high wind
clearance,
note 3)
3
3
3
40.2
40.8
40.2
69.8
69.8
70.5
82.0
82.0
82.3
3
25.3
52.3
68.0
3
3
3
3
3
3
3
3
25.3
67.9
40.8
40.8
77.0
52.6
41.3
77.0
52.9
92.9
72.5
70.1
101.9
77.1
72.9
101.9
68.0
108.6
89.5
89.1
115.1
90.5
89.8
115.1
46 kV
TS-1, TS-1X
TS-1L, TS-1LX
TS-2, TS-2X
TSD-1, TSD-1X
TSD-2, TSD-2X
TS-9
TSS-1, TSS-2
TSS-1L
TSS-9
TSZ-1, TSZ-2
TH-1, TH-1G
TH-9, TH-9G
3
3
3
3
3
3
3
3
3
3
3
3
40.2
40.8
40.2
25.3
25.3
67.9
40.8
40.8
77.0
52.6
41.3
77.0
64.5
64.5
65.0
47.7
48.0
86.9
64.9
64.9
97.2
72.3
67.8
97.2
82.0
82.0
82.3
68.0
68.0
108.6
89.5
89.5
115.1
90.5
89.8
115.1
69 kV
TS-1, TS-1X
TS-1L, TS-1LX
TS-2, TS-2X
TSD-1, TSD-1X
TSD-2, TSD-2X
TS-9
TSS-1, TSS-2
TSS-1L
TSS-9
4
4
4
4
4
4
4
4
4
20.0
33.5
20.0
17.8
17.8
45.8
25.9
35.1
45.8
38.5
53.5
38.5
38.5
38.5
71.7
45.8
60.9
79.2
74.0
74.0
74.2
62.8
62.8
93.2
85.4
85.4
106.6
Sturcture and
Voltage
34.5 kV
TS-1, TS-1X
TS-1L, TS-1LX
TS-2, TS-2X
TSD-1, TSD1X,
TSD-2, TSD-2X
TS-9
TSS-1, TSS-2
TSS-1L
TSS-9
TSZ-1, TSZ-2
TH-1, TH-1G
TH-9, TH-9G
Bulletin 1724E-200
Page J-3
TABLE J-1 (Continued)
INSULATOR SWING VALUES FOR STANDARD TANGENT STRUCTURES
(Porcelain Insulators with Ball Hook and Suspension Clamp
per Drawing TM-1A. Insulator String Lengths per TABLE C-3)
Number of
Insulators
Insulator Swing
Angle In
Degrees
(no wind
clearance)
Insulator Swing
Angle In
Degrees
(moderate wind
clearance)
Insulator Swing
Angle In
Degrees
(high wind
clearance)
4
4
41.7
35.6
61.2
61.2
81.4
85.6
4
66.5
86.2
106.6
4
35.6
61.2
85.6
4
27.2
56.1
81.3
4
33.7
60.0.
84.6
7
7
26.9
28.3
54.2
58.7
80.2
80.8
7
22.1
55.5
78.1
7
22.1
55.5
78.1
138 kV
TH-10 SERIES
8
19.9
54.5
77.2
161 kV
TH-10 SERIES
10
16.4
50.5
77.7
230 kV
TH-230
TH-230
12
13
16.5
15.2
47.8
43.9
74.8
76.0
Sturcture and
Voltage
69 kV (continued)
TSZ-1, TSZ-2
TH-1, TH-1G
TH-1B,
TH-1BG
TH-1A,
TH-1AA,
TH-1AAX
TS-115
115 Kv
TS-115
TH-1A
TH-1AA,TH1AAX
TH-10 SERIES
Notes:
1. Conditions at which insulator swing no wind clearances are to be maintained follow (See Chapter 7 of this
bulletin):
• Wind: Assume no wind.
• Temperature: Assume a temperature of 60°F.
2. Conditions at which insulator swing moderate wind clearances are to be maintained follow (See Chapter 7
of this bulletin):
• Wind: Assume a wind of at least 6 psf blowing. A wind pressure values of no higher than 9 psf
(60 mph) should be used for the moderate wind clearance design
• Temperature: A temperature of no more than 32°F should be used for tangent and small angle
structures where the insulator string is suspended from a crossarm. A lower temperature value should
be used where such a temperature can be reasonably expected to occur in conjunction with the wind
value assumed.
3. Conditions at which insulator swing high wind clearances are to be maintained follow (See Chapter 7 of
this bulletin):
• Wind: The minimum assumed wind value should be at least the 10-year mean recurrence interval.
More wind may be assumed if deemed appropriate.
• Temperature: The temperature assumed should be that temperature at which the wind is expected to
occur. The conductor should be assumed to be at initial tension conditions.
Bulletin 1724E-200
Page J-4
Blank Page
Bulletin 1724E-200
Page K-1
APPENDIX K
SYMBOLS AND ABBREVIATIONS
A = Cross sectional area
ft2, in2
A = Separation between points of insulator string for two phases
ft2
A = Allowable separation at midspan
ft
AU = Designated ultimate anchor capacity
lbs
B = Vertical separation at supports
ft
C = Clearance between a supply conductor and an object or
ground. May be specified as C1 C2, C3, etc.
C = Circumference of pole. Depending on the location, the
circumference may be indicated as CA, CB CC .
in
ft, in
De = Embedment depth
ft
Dv = Vertical separation between conductors
ft
EC = Experience factor for horizontal separation requirements
E = Experience factor for horizontal separation requirements. It
is generally recommended that E be greater then 1.25.
E = Modulus of elasticity of wood
psi
EI&W = Extreme Ice and Concurrent Wind
F = Wind pressure on a cylindrical surface
Fb = Designated ultimate bending stress for either the pole or the
crossarm
Fc = Experience factor to be used in horizontal separation
requirements (Fc = 1.15 for light loading district, 1.2 for
medium loading district, and 1.25 for heavy loading
district).
Fs
= Designated ultimate skin friction of soil
G, GN = Calculated force in the guy, considering guy lead
GU = Rated breaking strength of guy.
H = Horizontal separation between the phase conductors at the
structure.
HS = Horizontal span. For any structure the HS = (L1 + L2)/2 and
is the horizontal distance between the midspan points of
adjacent spans. The horizontal span times the wind force
per foot on the conductor (pc) will yield the total horizontal
force per conductor on the structure.
HSN = For an H-frame structure, HSA, HSB, etc., are the horizontal
spans limited by pole strength at locations on the pole.
HSR = Horizontal span limited by bearing
psf
psi
psf
lbs
lbs
ft
ft
ft
ft
Bulletin 1724E-200
Page K-2
APPENDIX K
SYMBOLS AND ABBREVIATIONS
HSx = Horizontal span as limited by crossbrace strength
Of an H-frame structure
ft
I = Moment of inertia of a structural member
in4
L
ft
=
Span length or the horizontal distance from one structure to
an adjacent structure. L1, L2, L3, etc., are designations for
difference spans.
Lavg
= Average span length
ft
Lmax
= Maximum span length
ft
LF = Load Factor
LL = Loop length of conductor when vibrating
ft
M = Major axis of Lissagous ellipses
ft
Ma
= Moment capacity of crossarms
ft.-lbs
Mg
= Moment capacity of a pole at groundline
ft.-lbs
MN = Moment capacity at the indicated location.
ft-lbs
Mbh
= Moment capacity at the indicated location.
ft-lbs
Mwp
= Moment due to wind on the pole.
ft-lbs
P = Horizontal force.
PC
lbs
= Force due to wind on conductors (plus ice, if any)
lbs
Pg
= Force due to wind on OHGW (plus ice, if any)
lbs
Pt
= Force due to wind on conductors and OHGW (plus ice)
lbs
= Critical buckling load for a member in compression
lbs
Pcr
P-δ = P-delta moment, additional moment due to deflection
ft-lbs
R = Rise of a davit arm
ft
R
lbs
Rg
Total transverse load due to wind on the conductors and
OHGW and wire tension load for conductors and OHGW
Total transverse load due to wind on the OHGW (Pg) and
=
wire tension load for OHGW (Tg)
=
RS = Ruling Span
S = Section modulus of a structural member equal I/c
lbs
ft
in3
Bulletin 1724E-200
Page K-3
APPENDIX K
SYMBOLS AND ABBREVIATIONS
S = Sag of conductor
ft
Se = Soil constant
Sf
= Final Sag of a bare conductor at condition specified
ft
Si = Sag of an iced conductor
ft
Sℓ
= Sag of the lower bare conductor
ft
Siℓ
= Sag of an iced lower conductor
ft
SRS
= Sag at midspan for a span equal to the ruling span
ft
= Sag of an upper conductor
ft
Siu = Sag of an iced upper conductor
ft
SP = Diagonal distance between phase conductors at structure
ft
T =
Tc
=
Tg
=
Th
=
Resultant tension at support
lbs
Average conductor tension
lbs
Average OHGW tension
lbs
Su
Tavg
Horizontal component of tension
T
Average conductor tension in a span, (Tavg= h +T )
2
=
lbs
lbs
V = Wind velocity
miles/hr
V = Vertical separation between phase conductors at a structure
ft
VS = Vertical span, the horizontal distance between the maximum ft
sag points of two adjacent spans. The vertical span times the
weight of the loaded conductor per foot (Wc) will yield the
vertical force per conductor.
W = Weight
W =
Wc
=
Wg
=
Wp
=
lbs
Right-of-way width
ft
Weight of conductors (plus ice, if any)
lbs
Weight of OHGW (plus ice, if any)
lbs
Weight of pole
lbs
Wi = Weight of insulators
lbs
V = Wind velocity
miles/hr
V = Vertical separation between phase conductors at a structure
ft
Bulletin 1724E-200
Page K-4
APPENDIX K
SYMBOLS AND ABBREVIATIONS
a = Length as indicated
ft
a = Insulator swing clearance for normal condition
in
b = Distance between two poles for an H-frame
ft
b = Bolt hole diameter; width of a section
in
b = Insulator swing clearance for 6 psf wind condition
in
c = Insulator swing clearance for high wind condition
in
c = Distance from the neutral axis to the extreme fiber
in
dc = Diameter of conductor
in
dg = Diameter of overhead ground wire
in
dg = Diameter at the groundline of a pole
in
dn = Diameter of a pole. Depending on the location the diameter
may be indicated as da, db, dc, dd, , etc.
in
dt = Diameter at the top of a pole
in
f = Frequency of conductor vibration
Hz
fb = Computed bending stress
psi
a = Length as indicated
ft
a = Insulator swing clearance for normal condition
in
b = Distance between two poles for an H-frame
ft
b = Bolt hole diameter; width of a section
in
b = Insulator swing clearance for 6 psf wind condition
in
c = Insulator swing clearance for high wind condition
in
c = Distance from the neutral axis to the extreme fiber.
in
dc = Diameter of conductor
in
dg = Diameter of overhead ground wire
in
dg = Diameter at the groundline of a pole.
in
Bulletin 1724E-200
Page K-5
APPENDIX K
SYMBOLS AND ABBREVIATIONS
dn = Diameter of a pole. Depending on the location the diameter
may be indicated as da, db, dc, dd, , etc.
in
dt = Diameter at the top of a pole
in
f = Frequency of conductor vibration
Hz
fb = Computed bending stress
psi
fs = Computed skin friction of soil
psf
g = Acceleration due to gravity 9.81 (32.2)
ft/sec2
g = Conductor surface gradient
hn = Length, may be indicated as h1, h2, h3, or ha, hb hc, etc.
ft.
kVL-G = Line to ground voltage
kV
kVL-L = Line to line voltage
kV
ℓ = Unbraced length used in buckling calculations
ft.
ℓi = Insulator string length
in. ft.
mc = Mass per unit length of the conductor
lbm/ft.
mg = Mass for unit length of the overhead ground wire
lbs./ft.
pc = Horizontal force per unit length due to wind on the
conductors (plus ice, if any)
lbs/ft.
pg = Horizontal force per unit length due to wind on the overhead
ground wire (plus ice, if any)
lbs/ft
pt = Total horizontal force per unit length due to wind on the
conductors and overhead ground wire
lbs/ft
qa = Calculated allowable soil bearing capacity
psf
qu = Calculated ultimate soil bearing capacity.
psf
r = Radius of gyration. a property of a cross section equal to
I/A.
lbs/ft
r = Radius of conductor
in.
rc = Resultant load per unit length on conductor including ice
and wind and K factor
lbs/ft
Bulletin 1724E-200
Page K-6
APPENDIX K
SYMBOLS AND ABBREVIATIONS
s = Maximum moment arm for a crossarm
ft.
wc = Weight per unit length of the conductors (plus ice, if any)
lbs/ft.
wg = Weight per unit length of the overhead ground wire (plus
ice, if any)
lbs/ft.
xn, yn, = Length. May be indicated as x0, x1, z0, x1, etc.
zn
ft.
Bulletin 1724E-200
Page L-1
APPENDIX L
SELECTED SI-METRIC CONVERSIONS
AREA
To Convert From
circular mil (cmil)
square centimeter (cm2)
square foot (ft2)
square inch (in2)
square kilometer (km2)
square mile (mi2)
To
Multiply by
2
square meter (m )
square meter (m2)
square meter (m2)
square meter (m2)
square meter (m2)
square meter (m2)
5.067075
*1.000
*9.290304
*6.451600
*1.000
2.589988
E – 10
E – 04
E – 02
E – 04
E + 06
E + 06
FORCE
To Convert From
To
Multiply by
kilogram force (kgf)
Kip
pound force (lbf)
newton (N)
newton (N)
newton (N)
*9.806650
4.448222 E + 03
4.448222
FORCE PER LENGTH
To Convert From
To
Multiply by
kilogram force per
meter (kgf/m)
pound per foot (lb/ft)
newton per meter (N/m)
newton per meter (N/m)
*9.806650
1.459390 E + 01
DENSITY
To Convert From
pound per cubic inch
(lb/in3)
pound per cubic foot
(lb/ft3)
To
kilogram per cubic
meter (kg/m3)
kilogram per cubic
meter (kg/m3)
Multiply by
2.767990 E + 04
1.601846 E + 01
LENGTH
To Convert From
foot (ft)
inch (in)
kilometer (km)
mile (mi)
*Exact Conversion.
To
meter (m)
meter (m)
meter (m)
meter (m)
Multiply by
3.048
*2.540
*1.000
*1.609344
E – 01
E – 02
E + 03
E + 03
BULLETIN 1724E-200
Page L-2
SELECTED SI-METRIC CONVERSIONS (Continued)
LINEAR DENSITY
To Convert From
pound per foot (lb/ft)
pound per inch (lb/in)
To
kilogram per meter (kg/m)
kilogram per meter (kg/m)
Multiply by
1.488164
1.785797 E + 01
LOAD CONCENTRATION
To Convert From
pound per square
inch (lb/in2)
pound per square
foot (lb/ft2)
ton per square
foot (ton/ft2)
To
kilogram per square
meter (kg/m2)
kilogram per square
meter (kg/m2)
kilogram per square
meter (kg/m2)
Multiply by
7.03069 E + 02
4.882428
9.071847 E + 02
MASS
To Convert From
pound (avoirdupois) (lb)
To
kilogram (kg)
Multiply by
4.535924 E - 01
PRESSURE
To Convert From
kip per square inch
(kip/in2)
kip per square foot
(kip/ft2)
newton per square
meter (N/m2)
pound per square
foot (lb/ft2)
pound per square
inch (lb/in2)
To
Multiply by
pascal (Pa)
6.894757 E + 06
pascal (Pa)
4.788026 E + 04
pascal (Pa)
*1.000
pascal (Pa)
4.788026 E + 04
pascal (Pa)
6.894757 E + 03
BENDING MOMENT
To Convert From
kilogram force
meter (kgf-m)
kip-foot (kip-ft)
pound-foot (lb-ft)
*Exact Conversion.
To
Multiply by
newton meter (N-m)
newton meter (N-m)
newton meter (N-m)
*9.806650
1.355818
1.355818
Bulletin 1724E-200
Page L-3
SELECTED SI-METRIC CONVERSIONS, (Continued)
VELOCITY
To Convert From
foot per second (ft/s)
kilometer per hour (km/h)
mile per hour (mi/h or mph)
meter per hour (m/h)
To
Multiply by
meter per second (m/s)
meter per second (m/s)
meter per second (m/s)
meter per second (m/s)
*3.048
2.777778
4.470400
2.777778
E - 01
E - 01
E - 01
E - 04
VOLUME
To Convert From
3
cubic foot (ft )
cubic inch (in3)
cubic kilometer (km3)
cubic millimeter (mm3)
To
Multiply by
3
cubic meter (m )
cubic meter (m3)
cubic meter (m3)
cubic meter (m3)
2.831685
1.638706
*1.000
*1.000
E - 02.
E - 05
E + 09
E - 09
TEMPERATURE
To Convert From
Degrees
Fahrenheit
ºF
Degrees
Celsius
ºC
XºC =
9/5 X + 32
--------------
XºF =
---------------
5/9(X – 32)
BULLETIN 1724E-200
Page L-4
Blank page
Bulletin 1724E-200
Page M-1
Subject
INDEX
Page Numbers
A
AAC Aluminum conductor (1350 H-19)
AAAC (6201 conductor)
AACSR conductor
ACAR conductor
ACCC conductor
ACCR conductor
ACSR conductor
ACSR/AW conductor
ACSR/SD conductor
ACSR/TW
ACSS
AWAC conductor
Aeolian vibration
Ampacity, conductor
Anchors
logs
plate
power screw
Armor rods
Authorizations
AWAC conductor
Axial loading, for guyed structures
4-2, 9-2
4-2, 9-2, 9-6, 9-8, 9-15
9-4
9-2, 9-3
9-4, 9-5
9-4
4-2, 9-1, 9-2, 9-6, 9-8
9-2
9-3
9-4
9-4, 9-5
9-3
9-3, 9-4, 9-8, 9-13, 9-14, 9-15, 15-6
to 15-7
9-6, D-2
11-17, 11-18, 14-2, 14-9
14-9
14-9
14-9
15-1, 15-3, 15-4, 15-6, 15-7
3-5
9-3
14-2, 14-4 to 14-8
B
Backfill
Backswing
Bearing capacity
Bisector guys
Bolt hole, moment reduction due to
Buckling
Buckling, calculation of buckling loads
Building, clearance over
Building, horizontal clearance to
Bundled conductors
12-8
7-5
12-6, 12-7
14-1, 14-4, 14-7
13-4, F-20, F-21
10-13, 14-4 to 14-7, 15-12
14-5 to 14-7, 14-12
4-4, 4-6 to 4-8
5-1, 5-2, 5-3, 5-9
15-8
C
Calculation of a ruling span
Checklist, review of plan and profile
Clamp top clamps
9-11, 9-12, 9-21
10-15
15-2
Bulletin 1724E-200
Page M-2
Subject
INDEX
Clearance
at crossings
between transmission and underbuild
distribution conductors
examples of, calculations
for lines along roads in rural districts
for lines over buildings
for lines over railroads
for lines over swimming pools
for sag template
horizontal
horizontal to vegetation
insulator swing
minimum horizontal clearance of conductors to
objects
over water
radial and horizontal, to vegetation
side hill
to grain bins
to guys
to objects under line
to rail cars
to swimming pools
to tall vehicles
to vegetation
under differential ice loading
vertical, between conductors of different lines at
noncrossing situations
vertical, between conductors where one line crosses
over another
vertical, conductors to ground
vertical, conductors to ground (underbuild
distribution),
vertical clearance to underbuild
Climbing space
Communication underbuild
Conductor
AAC (1350 H-19 aluminum)
AAAC-6201
AACSR
ACAR
ACCC
ACCR
Page Numbers
10-10, 4-9 to 4-13
16-1, 16-2, 16-3, 16-4
4-9, 4-10, 4-11, 5-9, 6-5, 6-6, 7-5
4-3
4-4, 4-8
4-4, 4-5, 4-6, 4-7
4-5, 4-8, 5-3
4-4
5-1 to 5-3, Chapter 5
5-4, 5-5
Chapter 13
Chapter 5
4-4, 4-6, 4-7
5-4, 5-5
10-8, 10-13
4-8, 5-3 to 5-7
14-3, 7-4
4-6, 4-7, 4-8, Chapter 4
4-4, 4-5, 5-3
4-5, 4-6, 4-7, 4-8, 5-3
4-3
5-4, 5-5
6-6, 6-7
4-10
4-9 to 4-13
4-1, 4-2, 4-6, 4-7
16-1, 16-2
16-2, 16-3, 16-4, 16-6
16-4
16-2, 16-3
4-2, 9-2
4-2, 9-2
9-4
9-2, 9-3
9-4, 9-5
9-4
Bulletin 1724E-200
Page M-3
Subject
INDEX
ACSR
ACSR/AW
ACSR/SD (self-damping)
ACSR/TW
ACSS
ampacity tables
AWAC
bundled
corrosion considerations
design for vibration
design tensions
determination of conductor sags and tensions
economic considerations
extreme ice tension
extreme ice and concurrent wind tension
extreme wind tension
final unloaded tension
high temperature
initial unloaded tension
mechanical loading tables
minimum size
motion hardware
ruling span of
related hardware
sagging of
selection of size
selection of type
standard loaded tension
stringing of
swing angle
temperature
thermal consideration
twisted pair (T-2)
vibration
voltage drop considerations of
Considerations in establishing radial and horizontal
clearances to vegetation
Contamination, insulation
Contraflexure for H-frames
Corrosion of hardware
Corrosion considerations, conductor
Crossarm braces
Page Numbers
4-2, 9-1, 9-2, 9-6, 9-8
9-2
9-3
9-4
9-4, 9-5
9-6, D-2
9-3
15-8
9-5
9-3, 9-8, 9-10, 9-14
9-8, 9-9
9-13, 9-16, 9-17
9-1, 9-6
9-9, 9-10, 11-2
9-9, 9-10, 11-2
9-9, 9-10, 11-2
9-8, 9-10
9-4, 9-5
9-7, 9-9, 9-15
B-2 to B-9
9-6
15-1, 15-6 to 15-8
9-11 to 9-13, 9-21
15-1 to 15-8
9-19
9-6
9-5
9-9
9-18
5-8, Chapter 7, 7-3, 7-5, 7-6, 7-9
4-2, 4-9, 4-10, 5-1, 7-1, 7-2, 7-3,
9-6, 9-10, 9-13, 9-15, 11-2, 16-2
9-5
9-4
9-8, 9-10, 9-14, 9-15, 15-6, 15-7,
15-8
9-6
5-4, 5-5
8-7 to 8-10
13-13, 13-14, H-3
15-12
9-5
13-15, 13-16, 13-17
Bulletin 1724E-200
Page M-4
Subject
INDEX
Crossarm data
moment capacities
crossarm loading chart
Crossarm fittings
Crossarm, wood, designated stresses
Crossbraces
Cushioned suspension unit
Page Numbers
G-2
G-3
15-8, 15-9, 15-10, 15-17
13-3
13-15, 13-8
9-15, 15-2, 15-6
D
Dampers
Deadend clamps
Deflection, structure
Design data summary
Design data summary book, suggested outline
Design data summary form
Design data summary form, instructions for filling out
Determining conductor sags and tensions
9-15, 15-7, 15-8
15-3, 15-4
4-12, 5-1, 5-5, 5-8 to 5-12
13-4 to 13-8
2-1, Appendix A
A-10, A-11
A-3, A-4
A-5 to A-9
9-13 to 9-17
E
Easements
Electrical characteristics of insulators
Embedment depths
Embedment depths of wood poles
Embedment depths of steel/concrete poles
Environmental criteria
Establishing a ruling span
Excessive insulator swing
Extreme ice
Extreme ice with concurrent wind
Extreme ice, conductor tension
Extreme winds,
conductor tension
gust response factors for
velocity pressure exposure coefficients
3-3, 3-4, 3-5 to 3-8
8-2, 8-3
12-1, 12-2 to 12-6
12-2 to 12-4
12-5, 12-6
3-1, 3-5 to 3-8
9-11 to 9-13
7-9, 10-10, 10-11
11-2
11-2, 11-8 to 11-13
9-9, 9-10
11-2 to 11-8, 11-14
9-9, 9-10
11-3, 11-4
11-3
F
Fasteners
Fault clearing
Fault clearing and switching surges
15-8, 15-9, 15-11
4-1
4-1
Bulletin 1724E-200
Page M-5
Subject
Field survey, soil
Final unloaded conductor tension
Fittings
Footing resistance
Foundation stability
INDEX
Page Numbers
12-2
9-8, 9-10
15-5, 15-10, 15-11
8-6, 8-7
Chapter 12, 12-3 to 12-7
G
Gain plate
Galloping
Grid gains
Gust response factor
wire
structure
Guy attachments
Guy strands, strength
Guyed structures
Guys
bisector
clearance to
for steel and concrete poles
for wood poles
force in
head and back
hold-down (uplift)
in-line
rated breaking strength of
strength factors
15-10
6-7, 6-8, 6-9, 15-8
15-10
11-3, 11-4
11-4
15-11
H-4
10-14, Chapter 14, 16-5, 16-6
14-1, 14-4, 14-7
14-3, 7-4
14-6
14-6, 14-7
14-2
14-1, 14-4
10-11
14-7, 10-13
H-4
11-16 to 11-18, 14-2
H
Hardware
armor rods
bolts
clamp top clamps
conductor motion
conductor-related hardware
corrosion of
crossarm fittings
cushioned suspension units
dampers
deadend clamps
fasteners
9-15, 15-1, 15-3, 15-6, 15-7
15-8, 15-9, 15-11, 15-12, H-4
15-2
9-14, 9-15, 15-6 to 15-8
15-1 to 15-8
15-12
15-10
9-15, 15-2, 15-6
9-10, 9-15, 15-7
15-3, 15-4
15-8, 15-9
Bulletin 1724E-200
Page M-6
Subject
INDEX
fittings
gain plate
grid gains
guy attachment
reinforcing plate
spacer fitting
splices
stepbolts
strain yokes
structure-related
suspension clamps
swing angle brackets
tied supports
Head and back guys
High temperature conductors
High wind (insulator swing) clearance
Hold down guys (uplift)
Horizontal clearance recommendations
Horizontal separation
Horizontal separation recommendations
Horizontal span, definition
Horizontal span, max. as limited by structure strength
single pole structures
H-frames
Page Numbers
15-5, 15-8, 15-9, 15-11
15-10
15-10
15-11
15-10
15-10
15-4
15-12
15-4
15-8 to 15-12
15-1, 15-2, 15-6
15-10, 15-11
15-2
14-1, 14-4
9-4, 9-5
7-2, 7-3, 7-4
10-11
Chapter 5, 5-1 to 5-7
6-1
6-1, 6-2
7-7
13-4 to 13-9
13-16 to 13-27
I
IEEE 516
Ice loading
Ice loading, differential
Initial unloaded conductor tension
In-line guys
Insulation
footing resistance
high altitude considerations
recommended agency levels
tables for
Insulation contamination
Insulator greasing
Insulator washing
Insulator lengths
Insulator load limits
porcelain and non-ceramic
5-4
11-2
6-6, 6-7, 11-13
9-8, 9-10, 9-15
10-13, 14-7
Chapter 8
8-2, 8-6, 8-7
8-3, 8-4, 8-5
8-2, 8-3
C-2, C-3
8-7 to 8-10
8-10
8-10
C-4
8-11 to 8-14
Bulletin 1724E-200
Page M-7
Subject
INDEX
post, pin, suspension
Insulator orientation
Insulator swing,
charts
effect on design
excessive
formulae for
Insulator string flashover data
Insulator swing clearance
Insulator swing tables, structure
Insulator swing values
Insulator weights, suspension
Insulators,
corrosion of
electrical characteristics of
horizontal post (porcelain and non-ceramic)
horizontal post (special considerations)
lengths, suspension
load limits of
mechanical considerations of post and pin
mechanical considerations of suspension
porcelain vertical post and pin mounted on
crossarms
post
suspension
types
weights, suspension
Page Numbers
8-11 to 8-14
8-8
Chapter 7, 10-10, 10-11, 13-1, 15-8
7-6, 7-8, 7-9, 7-11 to 7-14
7-6
7-9
7-8, 7-9
8-2, 8-3, C-2, C-3
7-1 to 7-5
Appendix J, 7-6
7-5, 7-6, J-2 to J-3
C-4
15-12
8-2, 8-3
8-1, 8-3, 8-11, 8-12
8-12
C-4
8-11
8-11, 8-12, 8-13
8-11 to 8-14
8-11, 8-12, 8-13
8-1 to 8-3, 8-9, 8-12, 8-13
8-1 to 8-3, 8-9, 8-11, 8-12, 8-13
8-1
C-4
L
Licenses
Lightning
Lightning arresters
Lightning flashover mechanism
Line routing considerations
Line survey
Load factors
Loading, axial (for guyed structures)
Loads
extreme wind
combined ice and wind (NESC)
extreme ice
extreme ice with concurrent wind (50 yr)
3-5 to 3-8
8-5 to 8-7
8-7
8-5
3-1, 3-2
3-3, 3-4
Chapters 11 and 13, 14-2
14-4 to 14-9
11-2 to 11-8, 11-14
11-1, 11-2
11-2
11-2, 11-8 to 11-13
Bulletin 1724E-200
Page M-8
Subject
INDEX
ice
NESC district loads
longitudinal loads
Longitudinal loads
Longitudinal structure strength
Page Numbers
11-2
11-1, 11-2
11-13
11-13
10-13, 11-13, 11-14
M
Meteorological data
wind velocities and pressures
annual extreme winds
annual extreme ice with concurrent wind maps
thunderstorm days per year
Moderate wind (insulator swing) clearance
Moment capacities for wood poles
Moment reduction due to bolt hole
E-2
11-2 to 11-8
11-8 to 11-13
E-4
7-1 to 7-4
F-3, F-5 to F-19
F-20, F-21
N
NERC FAC 003
NESC loading districts
No wind (insulator swing) clearance
5-4, 5-5
11-1, 11-2
7-1, 7-3, 7-4
O
Offset clipping
Overhead ground wire
sags and clearances
selection of size and type
tension limits
9-19, 9-20
8-5, 8-6, 9-7 to 9-10, 10-4,
6-3, 6-7
9-8
9-9, 9-10
P
Permits
Percy Thomas formula
Photogrammetry
Plan-profile drawings,
preparation of
Pole, moment capacities
Pole classes
Pole embedment depth
Pole stability
3-5 to 3-8
6-4
3-3, 3-4
3-4, Chapter 10
10-1 to 10-4
F-5 to F-19
F-4
12-1 to 12-6
Bulletin 1724E-200
Page M-9
Subject
INDEX
direct embedded, wood
direct embedded, steel and concrete
Pole top assembly, TP and TS
Pole top assembly, wishbone
Pole top assembly, H-frame
Pole, weight
Poles, wood, designated stresses
Post insulator
Preservative treatment
Page Numbers
12-2, 12-3, 12-4
12-5 to 12-6
13-4 to 13-9
13-10
13-15 to 13-18
F-22
13-3
8-1 to 8-3, 8-11, 8-12, 8-13
13-3
R
Rail cars, clearance to
Reconnaissance and preliminary survey
Reference component and tall Vehicles/boats
Rerouting
RI and TVI
Right-of-way
calculated width
clearing
typical width
width
width for a line directly next to a road
width for two or more structures on a single
right-of-way
Roads, clearances for lines along roads in rural districts
Route selection
Route survey
Ruling span
calculation of
effects of a wrong
establishment of
4-4, 4-5, 4-6, 4-7
3-3
4-3
3-4, 3-5
I-2 to I-6
3-3, 3-5
5-8 to 5-13
3-5
5-9
5-9
5-10
5-11
4-3
3-1, 3-2, 3-3
3-3, 3-4, 10-1
9-11, 9-13, 10-5, 10-6
9-10
9-12, 9-13
9-11
S
Sag, overhead ground wire
Sag and tension relationships
Sag template,
curves
Sagging of conductors
Section properties, (structural)
Selection of conductor size
Selection of conductor type
6-7
9-16
10-4 to 10-7
10-5 to 10-7
9-19, 9-20
H-2
9-6, 9-7
9-5
Bulletin 1724E-200
Page M-10
Subject
INDEX
Self-damping conductor
Separation, horizontal
between transmission and underbuild
distribution conductors
Separation, minimum vertical
Separation between lines as dictated by minimum
clearance between conductors carried on different
lines
Separation between lines as dictated by minimum
clearance of conductors from one line to the
supporting structure of another
Shielding angle
Side hill clearance
Single pole structures, a method of structural analysis
of
Site survey
Soil,
bearing capacity
construction backfill
Soils, description of types
Spaces and ways accessible to pedestrians only
Span,
definition of
horizontal, definition
maximum, as limited by structure strength for
single pole structures
maximum, as limited by structure strength for
H-frame structures
maximum, as limited by clearance to underbuild
maximum, as limited by conductor separation
maximum, as limited by conductor separation under
differential ice loading
maximum, as limited by galloping
maximum possible
vertical
Splices
Standard loaded conductor tension
Stepbolts
Strain yokes
Strength factors
Strength of pole top assembly, H-frames
Stringing of conductors
Structure, designated stresses, wood
Structure deflection
Page Numbers
9-3
6-1, 6-2
16-1, 16-2, 16-3, 16-4
6-1 to 6-3
5-10
5-11
8-5, 8-6
10-13
13-4 to 13-8
12-1
12-7, 12-8
12-6, 12-7
12-8
12-2
4-3, 4-6, 4-7
7-7, 10-10, 10-11, 10-12
7-7
13-4 to 13-8
13-12 to 13-27
16-3, 16-4
6-1, 6-2, 6-4, 6-5
6-6, 6-7
6-7, 6-8, 6-9
9-15, 9-16
10-8, 10-10, 10-11, 10-12
15-4
9-9
15-12
15-4
11-16 to 11-18
13-15 to 13-18
9-18
13-3
5-1, 5-4, 5-8 to 5-12, 13-4 to 13-7
Bulletin 1724E-200
Page M-11
Subject
INDEX
Structure related hardware
Structure spotting
Structure strength, longitudinal
Structure uplift (H-frame)
Structures,
general design considerations for steel/concrete
general design considerations for wood
guyed
H-frames, a method of analysis of
single pole, a method of analysis of
Suspension clamps
Suspension insulators
Swimming pools, lines over
Swing angle bracket
Page Numbers
15-8 to 15-12
10-7 to 10-14
10-13, 11-13, 11-14
12-8
Chapter 13
13-2
13-3
Chapter 14, 10-13
13-13 to 13-27
13-4 to 13-12
15-1, 15-2, 15-6
8-1, 8-2, 8-11, 8-12, 8-13
4-5, 4-8
15-10, 15-11
T
T2 Conductor
Temperature, conductor
Thermal considerations, conductor
Thunderstorm days, map
Tied Supports
TVI and RI
9-4
4-2, 4-9, 4-10, 5-1, 9-6, 16-2
9-6
E-4
15-2
I-2 to I-6
U
Underbuild,
addition to existing transmission line
clearance between transmission and underbuild
distribution conductor
distribution neutrals
horizontal separation from transmission conductor
sag template curves
strength requirements
vertical clearance to ground
Uplift
V
Chapter 16
16-1
16-1, 16-2, 16-3
16-4
16-1, 16-2
4-4, 10-4 to 10-8
Chapter 11, 16-1
16-1, 16-2, 16-3
10-10 to 10-13, 12-8, 13-20, 13-21
Bulletin 1724E-200
Page M-12
Subject
INDEX
V-braces
Vegetation, clearance to
Vehicles, tall, clearance to
Velocity pressure exposure coefficient
structure
wire
Vertical separation
minimum
Vertical span,
definition
maximum vertical span limited by structure
strength for single pole structures
maximum limited vertical span limited by structure
strength for H-frames
Voltage, maximum operating
Page Numbers
13-15 to 13-18
5-4, 5-5
4-3
11-4
11-3,11-4
6-1, 6-2, 6-3, 6-4, 6-5, 16-3
6-3
10-8, 10-10
7-7, 10-10, 10-11, 10-12
13-9 to 13-12
13-15 to 13-19
4-1
W
Wind, annual extreme winds
Wind, annual extreme ice with concurrent wind
Wind, velocities and pressures
Wood, preservative treatment
Wood, designated stresses for
Wood, stress limitations
11-2 to 11-8, 11-14
11-8 to 11-13
11-3, 11-4, E-2
13-3
13-3
13-3
DESIGN MANUAL FOR
HIGH VOLTAGE TRANSMISSION LINES
U.S. DEPARTMENT OF AGRICULTURE
RURAL UTILITIES SERVICE
ELECTRIC STAFF DIVISION
Revised May 2009
Bulletin 1724E-200
Page-ii
Blank Page
Bulletin 1724E-200
Page-iv
Blank Page
Bulletin 1724E-200
Page-v
TABLE OF CONTENTS
CHAPTER 1 - GENERAL
CHAPTER 2 - TRANSMISSION LINE DOCUMENTATION
CHAPTER 3 - TRANSMISSION LINE LOCATION, ENGINEERING SURVEY AND
RIGHT-OF-WAY ACTIVITIES
CHAPTER 4 - CLEARANCES TO GROUND, TO OBJECTS UNDER THE LINE AND
AT CROSSINGS
CHAPTER 5 - HORIZONTAL CLEARANCES FROM LINE CONDUCTORS
TO OBJECTS AND RIGHT-OF-WAY WIDTH
CHAPTER 6 - CLEARANCES BETWEEN CONDUCTORS AND BETWEEN
CONDUCTORS AND OVERHEAD GROUND WIRES
CHAPTER 7 - INSULATOR SWING AND CLEARANCES OF CONDUCTORS
FROM SUPPORTING STRUCTURES
CHAPTER 8 - INSULATION AND INSULATORS
CHAPTER 9 - CONDUCTORS AND OVERHEAD GROUND WIRES
CHAPTER 10 - PLAN-PROFILE DRAWINGS
CHAPTER 11 - LOADINGS AND LOAD FACTORS
CHAPTER 12 - FOUNDATION STABILITY OF DIRECT-EMBEDDED POLES
CHAPTER 13 - STRUCTURES
CHAPTER 14 - GUYED STRUCTURES
CHAPTER 15 - HARDWARE
CHAPTER 16 - UNDERBUILD
APPENDIX A - TRANSMISSION LINE DESIGN DATA SUMMARY SHEET
AND SUPPORTING INFORMATION
APPENDIX B - CONDUCTOR TABLES
APPENDIX C - INSULATION TABLES
APPENDIX D - AMPACITY, MVA, SURFACE GRADIENT TABLES
APPENDIX E - WEATHER DATA
Bulletin 1724E-200
Page-vi
TABLE OF CONTENTS (CONT)
APPENDIX F - POLE DATA
APPENDIX G - CROSSARM DATA
APPENDIX H - MISCELLANEOUS STRUCTURAL DATA
APPENDIX I - RI AND TVI
APPENDIX J - INSULATOR SWING TABLES
APPENDIX K - SYMBOLS AND ABBREVIATIONS
APPENDIX L - SELECTED SI-METRIC CONVERSIONS
APPENDIX M- INDEX
INDEX OF BULLETINS:
Design, System
Transmission Facilities, Line Manual
ABBREVIATIONS
(See Appendix L for Engineering Symbols and Abbreviations)
AAAC
AAC
AACSR
AC
ACCR
ACAR
ACCC/TW
ACSR
ACSS
ACSR/AW
ACSR/SD
ACSR/TW
ANSI
ASCE
ASTM
AWAC
AWG
BIA
BLM
CADD
CEQ
CFR
COE
DOE
EPA
EHV
EIS
EI&W
EPRI
All Aluminum Alloy Conductor
All Aluminum Conductor
Aluminum Alloy Conductor Steel Reinforced
Alternating Current
Aluminum Conductor Composite Reinforced
Aluminum Conductor Alloy Reinforced
Aluminum Conductor, Composite Core, Trapezoidal Wire
Aluminum Conductor Steel Reinforced
Steel Supported Aluminum Conductor
Aluminum Conductor Steel Reinforced/Aluminum Clad Steel Reinforced
Aluminum Conductor Steel Reinforced/Self Damping
Aluminum Conductor Steel Reinforced/Trapezoidal Wire
American National Standards Institute
American Society of Civil Engineers
American Society for Testing and Materials
Aluminum Clad Steel, Aluminum Conductor
American Wire Guage
Bureau of Indian Affairs
Bureau of Land Management
Computer-Aided Design and Drafting
Council on Environmental Quality
Code of Federal Regulations
Corps of Engineers
Department of Energy
Environmental Protection Agency
Extra High Voltage
Environmental Impact Statement
Extreme Ice & Concurrent Wind
Electric Power Research Institute
Bulletin 1724E-200
Page-vii
ABBREVIATIONS
(continued from previous page)
(See Appendix L for Engineering Symbols and Abbreviations)
Eq.
FAA
FEMA
FERC
FHA
FLPMA
FS
FWS
GIS
GPS
IEEE
LF
LWCF
M&E
MCOV
MOR
MOV
NEPA
NESC
NPDES
NPS
NRCS
OHGW
PL
Psf
RI
RSL
REA
ROW
RTK-GPS
RUS
SHPO
SML
SPCC
SYP
T2
T&D
TIN
TVI
TW
USC
USDA
USDI
USGS
Equation
Federal Aviation Agency
Federal Emergency Management Agency
Federal Energy Regulatory Commission
Federal Highway Administration
Federal Land Policy and Management Act
Forest Service
Fish and Wildlife Service
Geographic Information System
Global Positioning System
Institute of Electrical and Electronics Engineers, Inc.
Load Factor
Land and Water Conservation Fund Act
Mechanical and Electrical
Maximum Continuous Over Voltage
Modulus of Rupture
Metal Oxide Varistor
National Environmental Protection Act
National Electrical Safety Code
National Pollutant Discharge Elimination System
National Park Service
Natural Resource Conservation Service
Overhead Ground Wire
Public Law
Pounds per square foot
Radio Interference
Residual Static Load
Rural Electrification Administration
Right-of-Way
Real Time Kinematic-Global Positioning System
Rural Utilities Service
State Historical Preservation Officers
Specified Mechanical Load
Spill Prevention Control and Countermeasure
Southern Yellow Pine
Twisted Pair Aluminum Conductor
Transmission and Distribution
Triangular Irregular Network
Television Interference
Trapezoidal Wire
United States Code
United States Department of Agriculture
United States Department of the Interior
United States Geological Survey
Bulletin 1724E-200
Page-viii
FOREWORD
Numerous references are made to tables, figures, charts, paragraphs, sections, and chapters.
Unless stated otherwise, the tables, figures, charts, etc. referred to are found in this bulletin.
When the reference is not in this bulletin, the document is identified by title and source. Any
reference to agency means Rural Utilities Service.
ACKNOWLEDGEMENTS
Figures 9-6 and 9-7 of this bulletin are reprinted from IEEE Std 524-1992, “IEEE Guide to the
Installation of Overhead Transmission Line Conductors, Copyright 1992 by IEEE. The IEEE
disclaims any responsibility or liability resulting from the placement and use in the described
manner.
Figures 4-2, 4-4, 5-2, 5-5 and 11-1 and the table on reference heights (page 4-3) of this bulletin
are reprinted from IEEE/ANSI C2-2007, National Electrical Safety Code, Copyright 2007 by
IEEE. The IEEE disclaims any responsibility or liability resulting from the placement and use in
the described manner.
Figures 11-2a to 11-2e, 11-3a to 11-3f, and Tables E-2 and E-3 of this bulletin are reprinted from
ASCE7-05, “Minimum Design Loads for Buildings and Other Structures,” American Society of
Civil Engineers, Copyright 2005. For further information, refer to the complete rest of the
manual (http://www.pubs.asce.org/ASCE7.html?99991330).
Bulletin 1724E-200
Page-ix
LIST OF TABLES
Table
Number
Table Name
Brief Comment
Page
Routing
3-2
3-1
Line Routing Considerations
3-2
Summary of Potential Major Federal Permits Federal permits
or Licenses That May Be Required
3-6
4-1
Recommended Design Vertical Clearances
of Conductors Above Ground, Roadways,
Rails, or Water Surface
Vertical clearance
4-6
4-2
Recommended Design Vertical Clearances
from Other Supporting Structures, Buildings
and Other Installations
Vertical clearance
4-8
4-3
Recommended Design Vertical Clearances
in Feet Between Conductors Where the
Conductors of One Line Cross Over the
Conductors of Another and Where the
Upper and Lower Conductor Have Ground
Fault Relaying
Vertical clearance
4-12
5-1
Recommended Design Horizontal
Clearances (In Feet) From Conductors At
Rest And Displaced By 6 Psf Wind To
Other Supporting Structures, Buildings And
Other Installations
Horizontal clearanceno wind and 6psf wind
5-2
5-2
Recommended Design Horizontal
Clearances (In Feet) From Conductors
Displaced By Extreme Winds To Other
Supporting Structures, Buildings And Other
Installations Or Vegetation
Horizontal clearanceextreme wind
5-5
5-3
Typical Right-of-Way Widths
Right-of-way
5-9
6-1
Recommended Vertical Separation in Feet
Between Phases of the Same or Different
Circuits Attached to the Same Structure
Vertical separation of
conductors
6-3
7-1
Recommended Minimum Clearances in
Inches at Conductor to Surface of Structure
or Guy Wires
Clearances for insulator 7-4
swing
Bulletin 1724E-200
Page-x
LIST OF TABLES
(Continued from previous page)
Table
Number
Table Name
Brief Comment
Page
7-2
Insulator Swing Angle Values in Degrees
Angles of swing
7-6
8-1
Recommended Insulation Levels at Sea
Level (Suspension at Tangent and Small
Angle Structures)
Insulation
8-2
8-2
Recommended Insulation Levels at Sea
Level (Posts at Tangent and Small Angle
Structures)
Insulation
8-3
8-3
Reduced Shielding Angle Values
Shield angles
8-5
8-4
Suggested Leakage Distances for
Contaminated Areas
Leakage distances
8-10
8-5
Summary of Recommended Insulator
Loading Limits
Insulator load limits
8-11
9-1
Recommended Minimum Conductor Sizes
Min. conductor sizes
9-6
9-2
Constants to be Added to the Total
Load on a Wire for NESC District Loads
Constants
9-9
9-3
Recommended Conductor and
Overhead Ground Wire Tension and
Temperature Limits
Tension and temp.
limits
9-10
9-4
Direction of Deviation of Sags from
Predicted Values when Actual and Assumed
(Design) Ruling Span Values are
Significantly Different
Ruling span and sags
9-13
11-1
Ice, Wind, Temperature,and Constants
Loading Districts
11-2
11-2
Wire Velocity Pressure Exposure
Coefficient (kZ)
Wire kZ
11-3
11-3
Wire Gust Response Factor, GRF
Wire GRF
11-3
11-4
Combined Factor kZ*GRF for Common Wire
Heights
Wire kZ*GRF
11-4
11-5
Structure kZ, GRF , and Combined kZ GRF
Factor
kZ, and GRF for
structures
11-4
11-6
Recommended Load Factors and Strength
Factors to be Applied to NESC District
Loads
Load factors and
strength factors
11-17
Bulletin 1724E-200
Page-xi
LIST OF TABLES
(Continued from previous page)
Table
Number
Table Name
Brief Comment
Page
11-7
Recommended Load Factors and Strength
Factors to be Applied to Extreme Wind
Loads and Extreme Ice with Concurrent
Wind
Load factors and
strength factors
11-18
12-1
Classification of Soils Based
on Field Tests
Soil description
12-2
12-2
Presumptive Allowable Bearing
Capacities, ksf
Bearing capacity
12-7
12-3
Suggested Ranges of Presumptive
Ultimate Bearing Capacities, psf
Bearing capacity
12-7
13-1
Designated Stresses for Poles
Wood characteristics
13-3
13-2
Designated Stresses for Crossarms
Wood characteristics
13-3
13-3
Crossbrace Capacities
X-brace
13-15
14-1
Application of Load and Strength Factors
for Guyed Structures (Guys and Anchors)
Load factors
14-2
14-2
Recommended Minimum Clearances in
Inches from Conductor to Surface of
Structure or to Guy Wires
Clearance to guys
14-3
15-1
Strengths for ANSI C135.1 Machine Bolts,
Double Arming Bolts and Double End Bolts
Bolt strengths
15-9
15-2
Strengths of ASTM A325 Heat Treated,
High Strength Bolts
Bolt strengths
15-11
15-3
Galvanic Table of Various Metals
Galvanic table
15-12
16-1
Recommended Minimum Vertical
Clearances to Distribution or
Communication Underbuild on
Transmission Lines in Feet
Clearance to
underbuild
16-3
C-1
Flashover Data for Porcelain String
5-3/4” x 10” Standard Suspension Insulators
C-2
C-2
Flashover Data For Suspension Polymers
(ANSI C29.12-1997)
C-3
C-3
Approximate Weights and Lengths of
Insulator Strings Using Standard 5-3/4” x 10”
Suspension Bells with a Ball Hook
C-4
Bulletin 1724E-200
Page-xii
LIST OF TABLES
(Continued from previous page)
Table
Number
Table Name
Brief Comment
Page
D-1
Ampacity of ACSR Conductors
D-2
D-2
MVA Limits
D-3
E-1
Wind Velocities and Pressures
E-2
E-2
Conversion Factors for Other Mean
Recurrence Intervals
E-3
E-3
Probability of Exceeding Design Wind
Speeds During Reference Period
E-3
F-1
Moments (ft-k) at Groundline Due to a 1 psf
Wind on the Pole
F-2
F-2
Moment Capacities (ft-k) at Groundline
F-3
F-3
Pole Classes
F-4
F-4
Pole Moment (ft-k) Reduction to Bolt Holes
for 1000 psi Fiber Stress
F-21
F-5
Volumes for Douglas Fir and Southern
Yellow Pine Poles, (cu. ft.)
F-22
F-6
Pole Weights for Douglas Fir (Treated)
F-22
F-7
Pole Weights for Southern Yellow Pine
(Treated)
F-22
G-1
Crossarm Sizes and Moment Capacities
G-2
H-1
Properties of Common Sections
H-2
H-2
Strengths for Machine Bolts, Double
Arming Bolts, Double End Bolts
H-4
H-3
Strengths of ASTM A325 Heat Treated,
High Strength Bolts
H-4
H-4
Strength of Guy Strands
H-4
I-1
RIV Levels
I-2
I-2
Surface Gradient for Typical Designs
I-5
J-1
Insulator Swing Values for Standard RDUP
Tangent Structures
J-2
Bulletin 1724E-200
Page-xiii
LIST OF FIGURES
Figure
Number
Figure Name
Brief Comment
Page
4-1
Clearance Situations Covered in This
Chapter
Vertical clearances
4-1
4-2
NESC Figure 234-5
Clearance to rail cars
4-4
4-3
Simplified Clearance Envelope
Clearance to rail cars
4-5
4-4
Swimming Pool Clearances
Vertical clearances for
swimming pools
4-5
5-1
Horizontal Clearance Requirement
Horizontal clearances
5-1
5-2
Radial Clearance Requirements to
Vegetation
Clearance to vegetation
5-4
5-3
Clearance to Grain Bins, NESC
Figure 234-4a
Clearance to grain bins
5-6
5-4
Horizontal Clearance to Grain Bins,
Conductors at Rest
Clearance to grain bins
5-6
5-5
Horizontal Clearance To Grain Bins,
Conductors Displaced by 6 psf or Extreme
Wind
Clearance to grain bins
5-6
5-6
NESC Clearance to Grain Bins with
Portable Loading Equipment
Clearance to grain bins
5-7
5-7
Simplified Recommendations for Clearances Clearance to grain bins
to Grain Bins with Portable Loading
Equipment
5-7
5-8
A Top View of a Line Showing Total
Horizontal Clearance Requirements
Horizontal clearance
5-8
5-9
ROW Width for Single Line of Structures
(First Method)
ROW width
5-10
5-10
Clearance Between Conductors of One Line
to Conductor of Another Line
Clearance between
lines
5-11
5-11
Clearance Between Conductors of One Line
and Structure of Another
Clearance between
lines
5-12
6-1
Example of Vertical and Horizontal
Separation Values
Separation of
conductors
6-1
Bulletin 1724E-200
Page-xiv
LIST OF FIGURES
(Continued from previous page)
Figure
Number
Figure Name
Brief Comment
Page
6-2
Minimum Distance Between Conductors
Distance Between
Conductors
6-6
6-3
Guide for Preparation of Lissajous Ellipses
Galloping ellipses
6-8
6-4
Single Loop Galloping Analysis
Galloping
6-9
6-5
Proper Phase Arrangements for Crossarm to
Vertical Construction
Vertical transition of
conductors
6-9
7-1
Illustration of Structure Insulator Swing
Angle Limits and Conditions Under Which
They Apply (Excludes Backswing)
Insulator swing
7-3
7-2
Forward and Backward Swing Angles
Insulator swing
7-5
7-3
Typical Insulator Swing Chart for a TH-230
Tangent Structure
Example swing chart
7-6
7-4
Horizontal and Vertical Spans
Span definitions
7-7
7-5
Typical Insulator Swing Chart for a
TH-233 Medium Angle Structure
Example swing chart
7-8
7-6
Insulator Swing Chart for Example 7-9
Example swing chart
7-11
8-1
A Standard Porcelain Suspension Bell
Suspension bell
8-1
8-2
A Typical Porcelain Horizontal Post
Insulator
Horizontal post
8-1
8-3
Insulation Derating Factor vs. Altitude in
1,000's of Feet
Derating factor
8-3
8-4
Shielding Angle, Pole and Overhead Ground
Wires
Shielding angle
8-6
8-5
Contamination Breakdown Process of a
Single Porcelain Insulator Unit
Insulator contamination 8-8
9-1
Typical ACSR Strandings
ACSR conductor
9-1
9-2
1350 Aluminum Conductor Strandings
1350 conductor
9-2
9-3
Typical ACAR Strandings
ACAR conductor
9-3
9-4
Typical ACSR/SD Strandings
ACSR/SD conductor
9-3
Bulletin 1724E-200
Page-xv
LIST OF FIGURES
(Continued from previous page)
Figure
Number
Figure Name
Brief Comment
Page
9-5
Results of a Typical Economical Conductor
Analysis - 230 kV, 795 vs. 954 vs. 1272
kcmil ACSR
Economic conductor
analysis
9-7
9-6
Nomograph for Determining Level Span
Equivalents of Non-Level Spans
Level span equivalents
9-17
9-7
Analysis for Application of Clipping Offsets
Offset clipping
9-20
9-8
Line Section for Example 9-1
Example of ruling span
9-21
10-1
Sample of a Plan and Profile
P&P sample
10-2
10-2
Conventional Symbols for Plan-Profile
Symbols
10-3
10-3
Specimen Sag Template for Conductor
Sag template
10-6
10-4
Application of Sag Template - Level Ground Level ground span
Span.
10-9
10-5
Check for Uplift
Uplift
10-11
10-6
Sag Low Point, Vertical Spans and Uplift
Vertical spans and uplift
10-12
10-7
Sample Check List for Review of Plan and
Profile
Checklist
10-15
11-1
NESC Loading Districts
NESC districts
11-1
11-2a
Extreme Wind Speed in Miles per Hour at
33 Ft. Above Ground (50-Year Mean
Recurrence Interval)
Western states extreme
wind loads
11-5
11-2b
Extreme Wind Speed in Miles per Hour At
33 Ft. Above Ground (50-Year Mean
Recurrence Interval)
Midwest and Eastern
states extreme wind
loads
11-6
11-2c,
11-2d
Extreme Wind Speed in Miles per Hour at
33 Ft. Above Ground for the Northeast and
Southeast (50-Year Mean Recurrence Int)
Northeast and
Southeast extreme
wind loads
11-7
11-2e
Extreme Wind Speed in Miles per Hour at
33 Ft. Above Ground for the Texas,
Louisiana, and Mississippi (50-Year Mean
Recurrence Interval)
Texas, Louisiana, and
Mississippi extreme
wind loads
11-8
11-3a
Uniform Ice Thickness Due To Freezing
Rain With Concurrent 3-Second Gust Wind
Speeds (50 Yr. Mean Recurrence)
Extreme ice with
concurrent wind loads
for Western US
11-9
Bulletin 1724E-200
Page-xvi
LIST OF FIGURES
(Continued from previous page)
Figure
Number
Figure Name
Brief Comment
Page
11-3b
Uniform Ice Thickness Due To Freezing
Rain With Concurrent 3-Second Gust Wind
Speeds (50 Yr. Mean Recurrence)
Extreme ice with
concurrent wind loads
for Central and eastern
11-10
11-3c
Uniform Ice Thickness Due To Freezing
Rain With Concurrent 3-Second Gust Wind
Speeds For Alaska (50 Year Mean
Recurrence Interval)
Extreme ice with
concurrent wind loads
for Alaska
11-11
11-3d
Uniform Ice Thickness Due To Freezing
Rain With Concurrent 3-Second Gust Wind
Speeds For Lake Superior (50 Yr. Mean
Recurrence)
Extreme ice with
concurrent wind loads
for Lake Superior
11-12
11-3e
Uniform Ice Thickness Due To Freezing
Rain With Concurrent 3-Second Gust Wind
Speeds For Fraser Valley Detail (50 Yr.
Mean Recurrence)
Fraser Valley extreme
ice with concurrent
wind loads
11-12
11-3f
Uniform Ice Thickness Due To Freezing
Rain With Concurrent 3-Second Gust Wind
Speeds For Columbia River Gouge (50 Yr.
Mean Recurrence)
Extreme ice with
concurrent wind loads
for Columbia River
Gouge
11-13
12-1
Embedment Depths in Poor Soil
Embedment depths
12-3
12-2
Embedment Depths in Average Soil
Embedment depths
12-4
12-3
Embedment Depths in Good Soil
Embedment depths
12-4
12-4
Embedment Chart for Medium Dry Sand
Bulletin 1724e-205 “Embedment Depths for
Concrete and Steel Poles”
Embedment depths
12-5
13-1
Selection of Level Ground Span
Level ground span
13-2
13-2
Structure Cost per Mile Related to Pole Height
Economic pole height
13-2
13-3
TS Type Structure
13-5
13-4
TSS-1 Structure
13-7
13-5
Application of Forces (Heavy Loading)
13-7
13-6
TSZ-1 Pole Top Assembly
13-10
13-7
TSZ-1 Example
13-10
Bulletin 1724E-200
Page-xvii
LIST OF FIGURES
(Continued from previous page)
Figure
Number
Figure Name
Brief Comment
Page
13-8
HS vs. VS for TSZ-1
13-10
13-9
TU-1 Structure
13-11
13-9a
Davit Arm
13-12
13-10
VS vs. HS for TUS-1 Structure of Ex.13-3
13-12
13-11
Assumed H-Frame Behavior
H-frame behavior
13-13
13-12
Location of Point of Contraflexure
Pt. of contraflexure
13-13
13-13
Crossbrace
X-brace
13-14
13-14
Pole Top Bracing Arrangements
Pole top for H-frames
13-15
13-15
Pole Top Assembly with Two Outside Braces
Two outside braces
13-16
13-16
13-17
Pole Top Assembly with Inside Braces
Structure 1
Inside braces
13-17
13-19
13-18
Structure 2
13-20
13-19
Structure 3
13-21
13-20
Structure 4
13-21
13-21
Structure 5
13-22
13-22
Structure 6
13-22
13-23
Example of an H-Frame
13-23
14-1
Deadend Structure
14-1
14-2
Comparison of Rods to Show Stability Concept
Stability concept
14-4
14-3
Effective Unbraced Length for Various End
Conditions
Unbraced lengths
14-5
14-4a,
14-4b
End Conditions for Bisector and In-Line
Guyed Structures
End conditions for
guyed poles
14-7
14-5
Axial Loads Induced in a Pole
14-8
14-6
Representation of Axial Loads and Double
Accounting Loads
14-8
Bulletin 1724E-200
Page-xviii
LIST OF FIGURES
(Continued from previous page)
Figure
Number
Figure Name
Brief Comment
Page
15-1
Suspension Clamp with Clevis or Ball and
Socket Type of Connection
15-1
15-2
15-2
15-3
Post Type Insulator with Straight Line
Trunion Clamps
Top Groove Hand Tie
15-4a
Typical Bolted Deadend Clamp
15-3
15-4b
Typical Compression Deadend
15-3
15-5
Suspension Insulators
15-5
15-6
Different Types of Hooks
15-5
15-7
Various Types of Ball and Clevis “Y”
Connections
15-5
15-8
Anchor Shackle; Chain Shackle
15-5
15-9
Armor Rods Used with Suspension
Insulators
15-6
15-10a
Cushioned Suspension Unit
15-6
15-10b
Double Cushioned Suspension (for Line
Angles Greater than 30o)
15-6
15-11
Typical Suspension Damper
15-7
15-12
Spiral Vibration Damper for Small
Conductors
15-7
15-13
Disc Weights, Ball Weights
15-8
15-14
Fasteners
15-9
15-15
Lag Screw
15-9
15-16
Grid Gains
15-10
15-17
Spacer Fitting, Reinforcing Plate
and Gain Plate
15-10
15-18
Small Angle Structure with Swing Angle
Brackets
15-11
16-1
Horizontal Separation Requirements
Between Transmission and Underbuild
16-2
15-2
Bulletin 1724E-200
Page-xix
LIST OF FIGURES
(Continued from previous page)
Figure
Number
Figure Name
Brief Comment
Page
16-2
Vertical Separation Requirements at
Structure for Underbuild
16-2
16-3
16-5
16-4
Transference of the Distribution Circuit to a
Separate Pole at a Large Angle
Use of a Separate Pole to Mount a
Distribution Transformer
16-5
Guying Distribution Underbuild
16-5
E-1
Isokeraunic Levels for the United States
E-4
G-1
Crossarm Loading Chart-Maximum
Permitted Vertical Loads of Various Sizes of
Douglas Fir Crossarms
G-3
H-1
Curve for Locating Plane of Contraflexure in
X-Braced H-Frame Structures
H-3
16-5
Bulletin 1724E-200
Page-xx
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Bulletin 1724E-200
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1. GENERAL
1.1 Purpose: The primary purpose of this bulletin is to furnish engineering information for use
in designing transmission lines. Good line design should result in high continuity of service,
long life of physical equipment, low maintenance costs, and safe operation.
1.2 Scope: The engineering information in this bulletin is for use in design of transmission lines
for voltages 230 kV and below. Much of this document makes use of standard Rural Utilities
Service (referred to as the agency) structures and assemblies in conjunction with data provided in
this bulletin. Where nonstandard construction is used, factors not covered in this bulletin may
have to be considered and modification to the design criteria given in this bulletin may be
appropriate.
Since the agency program is national in scope, it is necessary that designs be adaptable to various
conditions and local requirements. Engineers should investigate local weather information, soil
conditions, operation of existing lines, local regulations, and environmental requirements and
evaluate known pertinent factors in arriving at design recommendations.
1.3 National Electrical Safety Code (NESC): This bulletin is based on the requirements of the
2007 edition of the National Electrical Safety Code. In accordance with the Code of Federal
Regulations 7 CFR Part 1724, agency financed lines are to be a minimum of Grade B
construction as defined in the NESC. However, since the NESC is a safety code and not a design
guide, additional information and design criteria are provided in this bulletin as guidance to the
engineer.
The NESC may be purchased from the Institute of Electrical and Electronics Engineers (IEEE)
Operations Center, 445 Hoes Lane, P.O. Box 1331, Piscataway, NJ 08855-1331 or at the
following website:
http://standards.ieee.org/nesc
1.4 Responsibility: The borrower is to provide or obtain all engineering services necessary for
sound and economical design. Due concern for the environment in all phases of construction and
cleanup should be exercised.
1.5 Environmental Regulations: Agency environmental regulations are codified in
7 CFR Part 1794, "Environmental Policies and Procedures." These regulations reference
additional laws, regulations and Executive Orders relative to the protection of the environment.
The Code of Federal Regulations may be purchased from the Superintendent of Documents, U.S.
Government Printing Office, Washington, DC 20402.
Agency environmental regulations may be found on the following website:
http://www.usda.gov/rus/electric/regs/index.htm
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Bulletin 1724E-200
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2. TRANSMISSION LINE DOCUMENTATION
2.1 Purpose: The purpose of this chapter is to provide information regarding design
documentation for transmission lines financed by the Rural Utilities Service.
2.2 General: Policy and procedures pertaining to construction of transmission lines by agency
electric borrowers are codified in 7 CFR 1724, “Electric Engineering, Architectural Services and
Design Policies and Procedures” and 7 CFR 1726, "Electric System Construction Policies and
Procedures" (http://www.usda.gov/rus/electric/regs/index.htm). The requirements of
7 CFR 1726 apply to the procurement of materials and equipment for use by electric borrowers
and to construction of the electric system if the material, equipment, and construction are
financed, in whole or in part, with loans made or guaranteed by the Rural Utilities Service.
2.3 Design Data Summary: When design data is required by the agency, a design data
summary (or its equivalent) should be submitted. Engineering design information includes
design data, sample calculations, and plan-profile drawings. A ‘Transmission Line Design Data
Summary Form’, which is included in Appendix A of this bulletin, has been prepared to aid in
the presentation of the design data summary. A suggested outline in Appendix A indicates
information that should be considered when preparing a design data summary. Appendix A also
highlights information which should be included in the design data submitted to the agency when
computer software has been used in the design.
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Bulletin 1724E-200
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3. TRANSMISSION LINE LOCATION, ENGINEERING SURVEY AND RIGHT-OFWAY ACTIVITIES
3.1 Route Selection: Transmission line routing requires a thorough investigation and study of
several different alternate routes to assure that the most practical route is selected, taking into
consideration the environmental criteria, cost of construction, land use, impact to public,
maintenance and engineering considerations.
To select and identify environmentally acceptable transmission line routes, it is necessary to
identify all requirements imposed by State and Federal legislation. Environmental
considerations are generally outlined in agency Bulletin 1794A-601, “Guide for Preparing
Environmental Reports for Electric Projects That Require Environmental Assessments.” State
public utility commissions and departments of natural resources may also designate avoidance
and exclusion areas which have to be considered in the routing process.
Maps are developed in order to identify avoidance and exclusion areas and other requirements
which might impinge on the line route. Ideally, all physical and environmental considerations
should be plotted on one map so this information can be used for route evaluation. However,
when there are a large number of areas to be identified or many relevant environmental concerns,
more than one map may have to be prepared for clarity. The number of maps engineers need to
refer to in order to analyze routing alternatives should be kept to a minimum.
Typical physical, biological and human environmental routing considerations are listed in
Table 3-1. The order in which considerations are listed is not intended to imply any priority. In
specific situations, environmental concerns other than those listed may be relevant. Suggested
sources for such information are also included in the table. Sources of information include the
United States Geological Service (USGS), Federal Emergency Management Agency (FEMA),
United States Department of the Interior (USDI), United States Department of Agriculture
(USDA), Natural Resource Conservation Service (NRCS) and numerous local and state
agencies.
For large projects, photogrammetry is contributing substantially to route selection and design of
lines. Preliminary corridor location is improved when high altitude aerial photographs or
satellite imagery are used to rapidly and accurately inventory existing land use. Once the
preferred and alternative corridors have been identified, the engineer should consult USGS maps,
county soil maps, and plat and road maps in order to produce small scale maps to be used to
identify additional obstructions and considerations for the preferred transmission line.
On smaller projects, the line lengths are often short and high altitude photograph and satellite
imagery offer fewer benefits. For such projects, engineers should seek existing aerial
photographs. Sources for such photographs include county planning agencies, pipeline
companies, county highway departments, and land development corporations. A preliminary
field survey should also be made to locate possible new features which do not appear on USGS
maps or aerial photographs.
As computer information systems become less expensive and easier to use, electric transmission
utilities are using Geographic Information Systems(GIS) to automate the route identification
process. GIS technology enables users to easily consolidate maps and attribute information from
various sources and to efficiently analyze what has been collected. When used by routing
experts, automated computer processes help standardize the route evaluation and selection
process, promote objective quantitative analysis and help users select defendable routes. GIS
tools have proven very beneficial to utilities whose goals are to minimize impact on people and
the natural environment while selecting a constructible, maintainable and cost effective route.
Bulletin 1724E-200
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Final route selection, whether for a large or small project, is a matter of judgment and requires
sound evaluation of divergent requirements, including costs of easements, cost of clearing, and
ease of maintenance as well as the effect a line may have on the environment. Public relations
and public input are necessary in the corridor selection and preliminary survey stages.
Physical
•
•
•
•
•
•
•
•
TABLE 3-1
LINE ROUTING CONSIDERATIONS
Sources
Highways
Streams, rivers, lakes
Railroads
Airstrips
Topography (major ridge lines,
floodplains, etc.)
Transmission lines & distribution lines
Pipelines,(water, gas, sewer),
underground Electric
Occupied buildings
Biological
•
•
Woodlands
Wetlands
•
Waterfowl, wildlife refuge areas,
endangered species & critical
Habitat Areas
Human Environmental
•
Rangeland
•
Cropland
•
Urban development
•
•
•
•
Industrial development
Mining areas
Recreation or aesthetic areas,
national parks, state and local parks
Prime or unique farmland
•
Irrigation (existing & potential)
•
Historic and archeological sites
•
Wild and scenic rivers
Other
•
Federal, state and county controlled
lands
USGS, state & county highway department maps
USGS, Army Corps of Engineers, flood insurance maps
USGS, railroad
USGS, Federal Aviation Administration (FAA)
USGS, flood insurance maps (FEMA), Army Corps of
Engineers
USGS, local utility system maps
USGS, local utility system maps
Local tax maps, land use maps, local GIS maps
Sources
USGS, USDA - Forest Service,
USGS, Army Corps of Engineers, USDA National Conservation
Resource Service, USDI Fish and Wildlife Service
USDI - Fish and Wildlife Service, State Fish and Game Office
Sources
USGS aerial survey, satellite mapping, county planning
agencies, state planning agencies, state soil conservation
service, mining bureau, U.S. Bureau of Land Management,
NRCS
USGS, soil surveys, USDA - NRCS, state department of
agriculture, county extension agent
Irrigation district maps, applications for electrical service, aerial
survey, state departments of agriculture and natural
resources, water management districts
National Register of Historic Sites (existing), state historic
preservation officer , state historic and archeological
societies
USGS maps, state maps, state department of natural resources,
Department of Interior
Sources
USGS, state maps, USDI Park Service, Bureau of Land
Management, state department of natural resources, county
maps, etc.
Bulletin 1724E-200
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3.2 Reconnaissance and Preliminary Survey: Once the best route has been selected and a
field examination made, aerial photos of the corridor should be reexamined to determine what
corrections will be necessary for practical line location. Certain carefully located control points
should then be established from an aerial reconnaissance. Once these control points have been
made, a transit line using stakes with tack points should be laid in order to fix the alignment of
the line. A considerable portion of this preliminary survey usually turns out to be the final
location of the line.
In many instances, after route has been selected and a field examination made, digital design data
on a known coordinate system like State Plane is used for centerline alignment and profile. This
alignment is provided to surveyors in a universal drawing file format. The surveyors then
convert it to a format used by their field recording equipment. Once the project location is
known, base control monuments are established along the route at 2 to 5 mile intervals,
depending on topography, with static Global Positioning System (GPS) sessions from known
horizontal and vertical control monuments. GPS equipment and radio transmitter equipment
occupying the base monuments broadcast a corrected signal to roving GPS unit(s). These GPS
units, with the use of an on-board field computer, allow any point or any line segment along the
route to be reproduced in the field. The roving unit can be used to locate and verify wire heights
at crossings, unmarked property lines or any routing concerns that may come up locally. The
equipment can also be used to establish centerline points in open areas so that conventional
survey equipment can be used to mark the line in wooded areas for clearing purposes. Once the
right-of-way (ROW) has been cleared, all structures can be staked with the Real Time
Kinematic-Global Positioning System (RTK-GPS) equipment. Since this entire process uses
data of a known mapping plane, any position along the route can be converted to various formats
and used within databases.
3.3 Right-of-Way: A right-of-way agent (or borrower's representative) should precede the
preliminary survey party in order to acquaint property owners with the purpose of the project, the
survey, and to secure permission to run the survey line. The agent or surveyor should also be
responsible for determining property boundaries crossed and for maintaining good public
relations. The agent should avoid making any commitments for individual pole locations before
structures are spotted on the plan and profile sheets. However, if the landowner feels particularly
sensitive about placing a pole in a particular location along the alignment, then the agent should
deliver that information to the engineer, and every reasonable effort should be made by the
engineer to accommodate the landowner.
As the survey proceeds, a right-of-way agent should begin a check of the records (for faulty
titles, transfers, joint owners, foreclosed mortgages, etc.) against the ownership information
ascertained from the residents. This phase of the work requires close coordination between the
engineer and the right-of-way agent. At this time, the right-of-way agent also has to consider
any access easements necessary to construct or maintain the line.
Permission may also have to be obtained to cut danger trees located outside inside the
right-of-way. Costly details, misuse of survey time and effort, and misunderstanding on the part
of the landowners should be avoided.
3.4 Line Survey: Immediately after the alignment of a line has been finalized to the satisfaction
of both the engineer and the borrower, a survey should be made to map the route of the line.
Based on this survey, plan-profile drawings will be produced and used to spot structures.
Long corridors can usually be mapped by photogrammetry at less cost than equivalent ground
surveys. The photographs will also contain information and details which could not otherwise be
discovered or recorded. Aerial survey of the corridor can be accomplished rapidly, but proper
conditions for photography occur only on a comparatively few days during the year. In certain
Bulletin 1724E-200
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areas, photogrammetry is impossible. It cannot be used where high conifers conceal the ground
or in areas such as grass-covered plains that contain no discernible objects. Necessary delays
and overhead costs inherent in air mapping usually prevent their use for short lines.
When using photogrammetry to develop plan-profile drawings, proper horizontal and vertical
controls should first be established in accordance with accepted surveying methods. From a
series of overlapping aerial photographs, a plan of the transmission line route can be made. The
plan may be in the form of an orthophoto or it may be a planimetric map (see Chapter 10). The
overlapping photos also enable the development of profile drawings. The tolerance of plotted
ground elevations to the actual ground profile will depend on photogrammetric equipment, flying
height, and accuracy of control points.
Survey data can be gathered using a helicopter-mounted laser to scan existing lines and/or
topography. Three dimensional coordinates of millions of points can be gathered while also
taking forward and downward looking videos. These points can be classified into ground points,
structure points and wire points.
If use of photogrammetry or laser-derived survey information for topographic mapping is not
applicable for a particular line, then transit and tape or various electronic instruments for
measuring distance should be used to make the route survey. This survey will generally consist
of placing stakes at 100 foot intervals with the station measurement suitably marked on the
stakes. It will also include the placement of intermediate stakes to note the station at property
lines and reference points as required. The stakes should be aligned by transit between the hub
stakes set on the preliminary survey. The survey party needs to keep notes showing property
lines and topographic features of obstructions that would influence structure spotting. To
facilitate the location of the route by others, colored ribbon or strips of cloth should be attached
at all fence crossings and to trees at regular intervals along the route (wherever possible).
As soon as the horizontal control survey is sufficiently advanced, a level party should start taking
ground elevations along the center line of the survey. Levels should be taken at every 100 foot
stations and at all intermediate points where breaks in the ground contour appear. Wherever the
ground slopes more than 10 percent across the line of survey, side shots should be taken for a
distance of at least 10 feet beyond the outside conductor's normal position. These elevations to
the right and left of the center line should be plotted as broken lines. The broken lines represent
side hill profiles and are needed, when spotting structures, to assure proper ground clearance
under all conductors, and proper pole lengths and setting depths for multiple-pole structures.
3.5 Drawings: As soon as the route survey has been obtained, the plan and profile should be
prepared. Information on the plan and profile should include alignment, stationing, calculated
courses, fences, trees, roads, ditches, streams, and swamps. The vertical and plan location of
telecommunications, transmission and other electric lines should be included since they affect
the proposed line. The drawings should also show railroads and river crossings, property lines,
with the names of the property owners, along with any other features which may be of value in
the right-of-way acquisition, design, construction, and operation of the line. Chapter 10
discusses structure spotting on the plan-profile drawings.
Structure spotting should begin after all of the topographic and level notes are plotted on the plan
and profile sheets. Prints of the drawings should be furnished to the right-of-way agent for
checking property lines and for recording easements. One set of prints certified as to the extent
of permits, easements, etc. that has been secured by the borrower should be returned to the
engineer.
3.6 Rerouting: During the final survey, it may be necessary to consider routing small segments
of the line due to the inability of the right-of-way agent to satisfy the demands of property
Bulletin 1724E-200
Page 3-5
owners. In such instances, the engineer should ascertain the costs and public attitudes towards
all reasonable alternatives. The engineer should then decide to either satisfy the property owner's
demands, relocate the line, initiate condemnation proceedings, or take other action as
appropriate. Additional environmental review may also be required.
3.7 Clearing Right-of-Way: The first actual work to be done on a transmission line is usually
clearing the right-of-way. When clearing, it is important that the environment be considered.
Environmental commitments/mitigations should be included in the construction contracts. It is
also important that the clearing be done in such a manner that will not interfere with the
construction, operation or maintenance of the line. In terrain having heavy timber, prior partial
clearing may be desirable to facilitate surveying. All right-of-way for a given line should be
secured before starting construction. See Chapter 5 for a discussion of right-of-way width.
3.8 Permits, Easements, Licenses, Franchises, and Authorizations: The following list of
permits, easements, licenses, franchises, and authorizations that commonly need to be obtained is
not meant to be exhaustive.
Private property
Railroad
Highway
Other public bodies
City, county or state
Joint and common use pole
Wire crossing
Easement from owner and permission
to cut danger trees
Permit or agreement
Permit from state/county/city
Authorization
Permit
Permit or agreement
Permission of utility
Table 3-2 list required federal permits or licenses required and other environmental review
requirements. The following abbreviations pertain to Table 3-2:
BIA
BLM
CEQ
CFR
COE
DOE
EIS
EPA
FAA
FERC
FHA
FLPMA
FS
FWS
LWCF
NEPA
NPDES
NPS
PL
SHPO
SPCC
USC
Bureau of Indian Affairs
Bureau of Land Management
Council on Environmental Quality
Code of Federal Regulations
Corps of Engineers
Department of Energy
Environmental Impact Statement
Environmental Protection Agency
Federal Aviation Agency
Federal Energy Regulatory Commission
Federal Highway Administration
Federal Land Policy and Management Act
Forest Service
Fish and Wildlife Service
Land and Water Conservation Fund Act
National Environmental Protection Act
National Pollutant Discharge Elimination System
National Park Service
Public Law
State Historical Preservation Officer
Spill Prevention Control and Countermeasure
United States Code
Bulletin 1724E-200
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TABLE 3-2
SUMMARY OF POTENTIAL MAJOR FEDERAL PERMITS OR LICENSES
THAT MAY BE REQUIRED
And other environmental review requirements for transmission line construction and operation
Issue
NEPA (National
Environmental
Protection Act)
Compliance
Right-of-Way
Across Land
Under Federal
Management
Action Requiring
Permit, Approval,
or Review
Agency
Federal; Action to
grant right-of-way
across land under
Federal jurisdiction
Lead Agency –
EIS and Record of
Decision
Preconstruction
surveys; construction,
operation,
maintenance, and
abandonment
Bureau of Land
Management (BLM)
Right-of-way grant and
special use permit
Bureau of Indian
Affairs (BIA), tribe
Right-of-way grant
across American
Indian lands
Special use
authorization permit or
easement
Authorization to cross
National Park Service
lands
Special use permit for
crossing a national
wildlife refuge
Forest Service (FS)
National Park
Service (NPS)
Fish and Wildlife
Service (FWS)
Biological
Resources
Paleontological
Resources
Permit, License,
Compliance or
Review
Relevant Laws and
Regulations
NEPA (42 USC 4321),
CEQ (40 CFR 1500-1508).
DOE NEPA implementing
Regulations (10 CFR to
1021)
Federal Land Policy and
Management Act (FLPMA)
of 1976 (PL 94-579)
43 USC 1761-1771
43 CFR 2800
25 CFR 169
36 CFR 251
18 USC, 36 CFR 14
50 CFR 25
“Conversion of use” for
a use other than
recreation on lands
reserved with Land
and Water
Conservation Fund Act
(LWCF) monies
NPS
Review of
transmission line
corridor to identify
conflicts with
recreational areas
Land and Water
Conservation Fund Act
PL 88-578, Section 6(f)(3)
Construction,
operation,
maintenance, and
abandonment of
transmission line
across or within
highway rights-of-way
Federal Highway
Administration (FHA)
Permits to cross
Federal Aid Highway;
4 (f) compliance
Department of
Transportation Act
23 CFR 1.23 and 1.27
23 USC 116, 123, and 315
23 CFR 645
23 CFR 771
Grant right-of-way by
federal land-managing
agency
FWS
Endangered Species
Act compliance by
federal land-managing
agency and lead
agency
Endangered Species Act
of 1973 as amended (16
USC 1531 et seq)
Protection of migratory
birds
FWS
Compliance
Protection of bald and
golden eagles
FWS
Compliance
Migratory Bird Treaty Act
of 1918
16 USC 703-712
50 CFR Ch 1
Bald and Golden Eagle
Protection Act of 1972
(16 USC 668)
Ground disturbance on
federal land or federal
aid project
BLM
Compliance with BLM
mitigation and
planning standards for
paleontological
resources of public
lands
FLPMA of 1976
(43 USC 1701-1771)
Antiquities Act of 1906
(16 USC 431-433)
Bulletin 1724E-200
Page 3-7
TABLE 3-2 (Continued)
SUMMARY OF POTENTIAL MAJOR FEDERAL PERMITS OR LICENSES
THAT MAY BE REQUIRED
And other environmental review requirements for transmission line construction and operation
Issue
Ground
Disturbance
and Water
Quality
Degradation
Air Traffic
Action Requiring
Permit, Approval,
or Review
Agency
Permit, License,
Compliance or
Review
Relevant Laws and
Regulations
Clean Water Act
(33 USC 1342)
Section 402 National
Pollutant Discharge
Elimination System
(NPDES) General
Permit for Storm Water
Discharges from
Construction Activities
General easement
10 USC 2668 to 2669
COE
Floodplain use permits
40 USC 961
Construction in or
modification of
floodplain
Federal lead agency
Compliance
Executive Order 11988
Floodplains
Construction or
modification of
wetlands
Federal lead agency
Compliance
Executive Order 11990
Wetlands
Potential discharge
into water of the state
(including wetlands
and washes)
COE (and states);
EPA on tribal lands
Section 401 permit
Clean Water Act
(33 USC 1344)
Discharge of dredge or
fill material to
watercourse
COE; EPA on tribal
lands
404 Permit (individual
or nationwide)
Clean Water Act
(33 USC 1344)
Placement of
structures and
construction work in
navigable waters of the
U.S
COE
Section 10 permit
Rivers and Harbors Act of
1899 (33 USC 403)
Protection of all rivers
included in the
National Wild and
Scenic Rivers System
Affected landmanaging agencies
Review by permitting
agencies
Wild and Scenic Rivers Act
(PL 90- 542)
(43 CFR 83.50)
Potential pollutant
discharge during
construction,
operation, and
maintenance
EPA
Spill Prevention
Control and
Countermeasure
(SPCC) plan for
substations
Oil Pollution Act of 1990
(40 CFR 112)
Location of towers in
regards to airport
facilities and airspace
Federal Aviation
Administration (FAA)
A “No-hazard
Declaration” required if
structure is more than
200 feet in height
Section 1101 Air
Space Permit for air
space construction
clearance
FAA Act of 1958
(49 USC 1501)
(14 CFR 77)
Construction sites with
greater than five acres
of land disturbance
Environmental
Protection Agency
(EPA)
Construction across
water resources
Army Corps of
Engineers (COE)
Crossing 100-year
floodplain, streams,
and rivers
FAA Act of 1958
(49 USC 1501)
(14 CFR 77)
Bulletin 1724E-200
Page 3-8
TABLE 3-2 (Continued)
SUMMARY OF POTENTIAL MAJOR FEDERAL PERMITS OR LICENSES
THAT MAY BE REQUIRED
And other environmental review requirements for transmission line construction and operation
Issue
Cultural
Resources
Rate regulation
Action Requiring
Permit, Approval,
or Review
Agency
Permit, License,
Compliance or
Review
Relevant Laws and
Regulations
Disturbance of historic
properties
Federal lead agency,
State Historical
Preservation Officers
(SHPO), Advisory
Council on Historic
Preservation
Section 106
consultation
National Historic
Preservation Act of 1966
(16 USC 470)
(36 CFR Part 800)
Excavation of
archaeological
resources
Federal landmanaging agency
Permits to excavate
Archaeological Resources
Protection Act of 1979
(16 USC 470aa to 470ee)
Potential conflicts with
freedom to practice
traditional American
Indian religions
Federal lead agency,
Federal landmanaging agency
Consultation with
affected American
Indians
American Indian Religious
Freedom Act
(42 USC 1996)
Disturbance of graves,
associated funerary
objects, sacred
objects, and items of
cultural patrimony
Federal landmanaging agency
Consultation with
affected Native
American group
regarding treatment of
remains and objects
Native American Graves
Protection and
Repatriation Act of 1990
(25 USC 3001)
Investigation of cultural
and paleontological
resources
Affected landmanaging agencies
Antiquities Act of 1906
(16 USC 432-433)
Investigation of cultural
resources
Affected landmanaging agencies
Protection of
segments, sites, and
features related to
national trails
Sales for resale and
transmission services
Affected landmanaging agencies
Permit for study of
historical,
archaeological, and
paleontological
resources
Permits to excavate
and remove
archaeological
resources on Federal
lands; American Indian
tribes with interests in
resources must be
consulted prior to
issuance of permits
National Trails
Systems Act
compliance
Federal Power Act
compliance by power
seller
Federal Power Act
(16 USC 792)
Federal Energy
Regulatory
Commission (FERC)
Archaeological Resources
Protection Act of 1979
(16 USC 470aa to 470ee)
(43 CFR 7)
National Trails System Act
(PL 90-543)
(16 USC 1241 to 1249)
In cases where structures or conductors will exceed a height of 200 feet, or are within
20,000 feet of an airport, the nearest regional or area office of the FAA must be
contacted. In addition, if required, FAA Form 7460-1, "Notice of Proposed Construction
or Alteration," is to be filed. Care must also be given when locating lines near hospital
landing pads, crop duster operations, and military bases.
Bulletin 1724E-200
Page 4-1
4. CLEARANCES TO GROUND, TO OBJECTS UNDER THE LINE AND AT
CROSSINGS
4.1 General: Recommended design vertical clearances for agency financed transmission lines
of 230 kV and below are listed in the Tables 4-1 through 4-3. These clearances exceed the
minimum clearances calculated in accordance with the 2007 edition of the NESC. If the 2007
edition has not been adopted in a particular locale, clearances and the conditions found in this
chapter should be reviewed to ensure that they meet the more stringent of the applicable
requirements.
Clearance values provided in the following tables are recommended design values. In order to
provide an additional cushion of safety, recommended design values exceed the minimum
clearances in the 2007 NESC.
4.2 Assumptions
4.2.1 Fault Clearing and Switching Surges: Clearances in tables 4-1, 4-2, 4-3, and 5-1 are
recommended for transmission lines capable of clearing line-to-ground faults and voltages up to
230 kV. For 230 kV, the tables apply for switching surges less than or equal to 2.0; for higher
switching surges on 230 kV transmission lines see the alternate clearance recommendations in
the NESC.
4.2.2 Voltage: Listed in the chart that follows are nominal transmission line voltages and the
assumed maximum allowable operating voltage for these nominal voltages. If the expected
operating voltage is greater than the value given below, the clearances in this bulletin may be
inadequate. Refer to the 2007 edition of the NESC for guidance.
Nominal Line-to-Line
Voltage (kV)
Maximum Line-to Line
Operating Voltage (kV)
34.5
46
69
115
138
161
230
*
*
72.5
121
145
169
242
*Maximum operating voltage has no effect on clearance
requirements for these nominal voltages.
Table 4-2
Table 4-3
Table 4-3
Table 4-2
Table 4-1
FIGURE 4-1: CLEARANCE SITUATIONS COVERED IN THIS CHAPTER
Bulletin 1724E-200
Page 4-2
4.3 Design Vertical Clearance of Conductors: The recommended design vertical clearances
under various conditions are provided in Table 4-1.
4.3.1 Conditions Under Which Clearances Apply: The clearances apply to a conductor at
final sag for the conditions ‘a’ through ‘c’ listed below. The condition that produces the greatest
sag for the line is the one that applies.
a. Conductor temperature of 32°F, no wind, with the radial thickness of ice for the applicable
NESC loading district.
b. Conductor temperature of 167°F. A lower temperature may be considered where justified by
a qualified engineering study. Under no circumstances should a design temperature be less
than 120°F.
c. Maximum design conductor temperature, no wind. For high voltage bulk transmission lines
of major importance to the system, consideration should be given to the use of 212°F as the
maximum design conductor temperature.
According to the National Electric Reliability Council Criteria, emergency loading for lines of a
system would be the line loads sustained when the worst combination of one line and one
generator outage occurs. The loads used for condition "c" should be based on long range load
forecasts.
Sags of overhead transmission conductors are predicted fairly accurately for normal operating
temperatures. However, it has consistently been observed that sags for ACSR (Aluminum
Conductor Steel Reinforced) conductors can be greater than predicted at elevated temperatures.
If conductors are to be regularly operated at elevated temperatures, it is important that sag
behavior be well understood. Current knowledge of the effects of high temperature operation on
the long term behavior of conductors and associated hardware (splices, etc.) is probably limited;
however, and a clear understanding of the issues involved is essential. The Electric Power
Research Institute (EPRI) has prepared a report on the effects of high temperature conductor and
associated hardware. 1
The traditional approach in predicting ACSR conductor sag has been to assume that the
aluminum and steel share only tension loads. But as conductor temperature rises, aluminum
expands more rapidly than steel. Eventually the aluminum tension will reduce to zero and then
go into compression. Beyond this point the steel carries the total conductor tension. These
compressive stresses generally occur when conductors are operated above 176 °F to 200 °F.
Greater sags than predicted at these elevated temperatures may be attributed to aluminum being
in compression which is normally neglected by traditional sag and tension methods. AAC (All
Aluminum Conductors) and AAAC (All Aluminum Alloy Conductor) or ACSR conductors
having only one layer of aluminum or ACSR with less than 7 percent steel should not have
significantly larger sags than predicted by these traditional methods at higher operating
temperatures. 2
1
Conductor and Associated Hardware Impacts During High Temperature Operations – Issues and Problems, L.
Shan and D. Douglass, Final Report, EPRI TR-109044, Electric Power Research Institute, Palo Alto, California,
December, 1997.
2
Conductor Sag and Tension Characteristics at High Temperatures, Tapani O. Seppa and Timo Seppa, The Valley
Group, Inc., presented at the Southeastern Exchange Annual E/O Meeting, May 22, 1996, in Atlanta, GA.
Bulletin 1724E-200
Page 4-3
4.3.2 Altitude Greater than 3300 Feet: If the altitude of a transmission line (or a portion
thereof) is greater than 3300 feet, an additional clearance as indicated in Table 4-1 must be
added to the base clearances given.
4.3.3 Spaces and Ways Accessible to Pedestrians Only: Pedestrian-only clearances should be
applied carefully. If it is possible for anything other than a person on foot to get under the line,
such as a person riding a horse, the line should not be considered to be accessible to pedestriansonly and another clearance category should be used. It is expected that this type of clearance
will be used rarely and only in the most unusual circumstances.
4.3.4 Clearance for Lines Along Roads in Rural Districts: If a line along a road in a rural
district is adjacent to a cultivated field or other land falling into Category 3 of Table 4-1, the
clearance-to-ground should be based on the clearance requirements of Category 3 unless the line
is located entirely within the road right-of-way and is inaccessible to vehicular traffic, including
highway right-of-way maintenance equipment. If a line meets these two requirements, its
clearance may be based on the "along road in rural district" requirement. To avoid the need for
future line changes, it is strongly recommended that the ground clearance for the line should be
based on clearance over driveways. This should be done whenever it is considered likely a
driveway will be built somewhere under the line. Heavily traveled rural roads should be
considered as being in urban areas.
4.3.5 Reference Component and Tall Vehicles/Boats: There may be areas where it can be
normally expected that tall vehicles/boats will pass under the line. In such areas, it is
recommended that consideration be given to increasing the clearances given in Table 4-1 by the
amount by which the operating height of the vehicle/boat exceeds the reference component. The
reference component is that part of the clearance component which covers the activity in the area
which the overhead line crosses.
For example, truck height is limited to 14 feet by state regulation, thus the reference component
for roads is 14 feet. However, in northern climates sanding trucks typically operate with their
box in an elevated position to distribute the sand and salt to icy roadways. The clearances in
Table 4-1 are to be increased by the amount the sanding truck operating height exceeds 14 feet.
In another example, the height of farm equipment may be 14 feet or more. In these cases, these
clearances should be increased by the difference between the known height of the oversized
vehicle and the reference height of 14 feet.
Reference heights for Table 4-1 are given below:
Item
1.0
2.0
3.0
4.0
5.0
6.0
7.0
Description
Reference height
(feet)
22.0
14.0
14.0
14.0
8.0/10.0
12.5
Track rails
Roads, streets, alleys, etc
Residential driveways
Other lands traversed by vehicles
Spaces and ways--pedestrians only
Water areas--no sail boating
Water areas—sail boating
Less than 20 acres
16.0
20 to 200 acres
30.0
200 to 2000 acres
30.0
Over 2000 acres
36.0
8.0
Areas posted for rigging or launching
See item 7.0
sailboats
From IEEE/ANSI C2-2007, National Electrical Safety Code, Copyright 2006. All rights reserved.
Bulletin 1724E-200
Page 4-4
For reference components to Table 4-2, see Appendix A, Table A-2b of the NESC.
4.3.6 Clearances Over Water: Clearances over navigable waterways are governed by the
U.S. Army Corps of Engineers and therefore the clearances over water provided in Table 4-1
apply only where the Corps does not have jurisdiction.
4.3.7 Clearances for Sag Templates: Sag templates used for spotting structures on a plan and
profile sheet should be cut to allow at least one foot extra clearance than given in Table 4-1, in
order to compensate for minor errors and to provide flexibility for minor shifts in structure
location.
Where the terrain or survey method used in obtaining the ground profile for the plan and profile
sheets is subject to greater unknowns or tolerances than the one foot allowed, appropriate
additional clearance should be provided.
4.4 Design Vertical Clearance of Conductors to Objects Under the Line (not including
conductors of other lines): The recommended design vertical clearances to various objects
under a transmission line are given in Table 4-2.
4.4.1 Conditions Under Which Clearances Apply: The clearances in Table 4-2 apply under
the same loading and temperature conditions as outlined in section 4.3.1 of this chapter. See
NESC Figures 234-1(a) and 234-1(b) and 234-1(c) for transition zones between horizontal and
vertical clearance planes. See Chapter 5 for horizontal clearances.
4.4.2 Lines Over Buildings: Although clearances for lines passing over buildings are shown in
Table 4-2, it is recommended that lines not pass directly over a building if it can be avoided.
4.4.3 Clearances to Rail Cars: The NESC has defined the clearance envelope around rail cars
as shown in Figure 4-2 (NESC Figure 234-5):
V=(item 1.0, Table 4-1) - 20 ft.
V
10'-8"
22'
20'
CLEARANCE
REQUIRED BY
RULE 232
V
3'
Item 9.0
Table 5-1
FIGURE 4-2: NESC FIGURE 234-5
From IEEE/ANSI C2-2007, National Electrical Safety Code, Copyright 2006. All rights reserved.
Bulletin 1724E-200
Page 4-5
To simplify the design process, Figure 4-3, which defines the recommended clearances, may be
used:
10'-8"
Item 1.0
Table 4-1
3'
Item 9.0
Table 5-1
FIGURE 4-3: SIMPLIFIED CLEARANCE ENVELOPE
In cases where the base of the transmission line is below that of the railroad bed, the designer
may be required to install taller poles or to offset further from the track (using the agency
suggested approach) than is indicated by the NESC clearance envelope.
4.4.4 Lines Over Swimming Pools: Clearances over swimming pools are for reference
purposes only. Lines should not pass over or within clearance ‘A’ of the edge of a swimming
pool or the base of the diving platform. Clearance ‘B’ should be maintained in any direction to
the diving platform or tower.
FIGURE 4-4: SWIMMING POOL CLEARANCES (See TABLE 4-2)
From IEEE/ANSI C2-2007, National Electrical Safety Code, Copyright 2006. All rights reserved.
B
C
RADIUS A
POINT
A
A
B
A
C
" C " is the vertical
clearance over adjacent
land.
Bulletin 1724E-200
Page 4-6
TABLE 4-1
RECOMMENDED DESIGN VERTICAL CLEARANCES OF CONDUCTORS ABOVE
GROUND, ROADWAYS, RAILS, OR WATER SURFACE (in feet) (See Notes A, F & G)
(Applicable NESC Rules 232A, 232B, and Table 232-1)
Line conditions under which the NESC states vertical clearances shall be met (Calculations are
based on Maximum Operating Voltage):
- 32°F, no wind, with radial thickness of ice, if any, specified in Rule 250B of the NESC for the
loading district concerned.
- Maximum conductor temperature for which the line is designed to operate, with no horizontal
displacement
Nominal Voltage, Phase to Phase (kVLL)
34.5
69
115
138
161
230
& 46
Max. Operating Voltage, Phase to Phase
(kVLL)
---72.5
120.8 144.9
169.1 241.5
Max. Operating Voltage, Phase to Ground
(kVLG)
---41.8
69.7
83.7
97.6
139.4
NESC Basic
Clear.(Note F)
Clearances in feet
1.0 Track rails
26.5
29.2
29.7
30.6
31.1
31.5
32.9
2.0 Roads, streets, etc., subject to truck traffic
18.5
21.2
21.7
22.6
23.1
23.5
24.9
3.0 Driveways, parking lots,
and alleys
18.5
21.2
21.7
22.6
23.1
23.5
24.9
4.0 Other lands cultivated etc., traversed
by vehicles (Note B)
18.5
21.2
21.7
22.6
23.1
23.5
24.9
5.0 Spaces and ways accessible to
pedestrians only (Note C)
14.5
17.2
17.7
18.6
19.1
19.5
20.9
6.0 Water areas – no sail boating
17.0
19.7
20.2
21.1
21.6
22.0
23.4
7.0 Water areas – sail boating suitable
(Notes D & E)
Less than 20 acres
20 to 200 acres
200 to 2000 acres
Over 2000 acres
20.5
28.5
34.5
40.5
23.2
31.2
37.2
43.2
23.7
31.7
37.7
43.7
24.6
32.6
38.6
44.6
25.1
33.1
39.1
45.1
25.5
33.5
39.5
45.5
26.9
34.9
40.9
46.9
8.0 Public or private land and water areas
posted for rigging or launching sailboats
(Note E)
Less than 20 acres
20 to 200 acres
200 to 2000 acres
Over 2000 acres
25.5
33.5
39.5
45.5
28.2
36.2
42.2
48.2
28.7
36.7
42.7
48.7
29.6
37.6
43.6
49.6
30.1
38.1
44.1
50.1
30.5
38.5
44.5
50.5
31.9
39.9
45.9
51.9
.02
.05
.07
.08
.12
ALTITUDE CORRECTION TO BE ADDED TO VALUES ABOVE:
Additional feet of clearance per 1000 feet of
.00
altitude above 3300 feet
Bulletin 1724E-200
Page 4-7
TABLE 4-1
(continued from previous page)
RECOMMENDED DESIGN VERTICAL CLEARANCE OF CONDUCTORS ABOVE
GROUND, ROADWAYS, RAILS, OR WATER SURFACE (in feet) (See Notes A, F & G)
(Applicable NESC Rules 232A, 232B, and Table 232-1
Notes:
(A) For voltages exceeding 98 kV alternating current to ground, or 139 kV direct current to ground, the NESC states
that either the clearance shall be increased or the electric field, or the effects thereof, shall be reduced by other
means, as required, to limit the current due to electrostatic effects to 5.0 milliampere (mA), rms, if the largest
anticipated truck, vehicle or equipment under the line were short circuited to ground. The size of the anticipated
truck, vehicle, or equipment used to determine these clearances may be less than but need not be greater than that
limited by Federal, State, or local regulations governing the area under the line. For this determination, the
conductors shall be at final unloaded sag at 120° F.
Fences and large permanent metallic structures in the vicinity of the line will be grounded in accordance with the
owner’s grounding units for the structure concerned to meet the 5.0 milliampere requirement. There should be
adequate ground clearance at crossings and along the right-of-way to meet the minimum requirement of 5 mA due to
the electrostatic field effects on the anticipated vehicles under the transmission line.
Consideration should be given to using the 5.0 mA rule to the conductor under maximum sag condition of the
conductor.
(B) These clearances are for land traversed by vehicles and equipment whose overall operating height is less than
14 feet.
(C) Areas accessible to pedestrians only are areas where riders on horses or other large animals, vehicles or other
mobile units exceeding 8 feet in height are prohibited by regulation or permanent terrain configurations or are not
normally encountered nor reasonably anticipated. Land subject to highway right-of-way maintenance equipment is
not to be considered as being accessible to pedestrians only.
(D) The NESC states that “for uncontrolled water flow areas, the surface area shall be that enclosed by its annual
high-water mark. Clearances shall be based on the normal flood level; if available, the 10 year flood level may be
assumed as the normal flood level. The clearance over rivers, streams, and canals shall be based upon the largest
surface area of any one mile-long segment which includes the crossing. The clearance over a canal, river, or stream
normally used to provide access for sailboats to a larger body of water shall be the same as that required for the
larger body of water.”
(E) Where the U.S. Army Corps of Engineers or the state, has issued a crossing permit, the clearances of that permit
shall govern.
(F) The NESC basic clearance is defined as the reference height plus the electrical component for open supply
conductors up to 22 kVL-G.
(G) An additional 2.5 feet of clearance is added to the NESC clearance to obtain the recommended design
clearances. Greater values should be used where survey methods to develop the ground profile are subject to
greater unknowns. See Chapter 10, paragraph 10.3 of this bulletin.
Bulletin 1724E-200
Page 4-8
TABLE 4-2
RECOMMENDED DESIGN VERTICAL CLEARANCES FROM OTHER SUPPORTING
STRUCTURES (See Note B), BUILDINGS AND OTHER INSTALLATIONS (in feet)
(Applicable NESC Rules: 234A, 234B, 234C, 234D, 234E, 234F, 234I, Tables 234-1, 234-2, 234-3)
Line conditions under which the NESC vertical clearances shall be met (Calculations are based on
Maximum Operating Voltage.):
•
•
32°F, no wind, with radial thickness of ice, if any, specified in Rule 250B of the NESC for the loading
district concerned.
Maximum conductor temperature for which the line is designed to operate, with no horizontal displacement
Nominal Voltage, Phase to Phase (kVLL)
Max. Operating Voltage, Phase to Phase
Max. Operating Voltage, Phase to Ground
(kVLL)
(kVLG)
34.5
& 46
-------
69
115
138
161
72.5
41.8
120.8
69.7
144.9
83.7
169.1
97.6
NESC Basic
Clear.(Note D)
230
(E)
241.5
139.4
Clearances in feet
1.0 From a lighting support, traffic signal support,
or supporting structure of a second line
5.5
7.5
7.5
8.2
8.6
9.1
10.8
2.0 From buildings not accessible to pedestrians
12.5
14.7
15.2
16.1
16.6
17.0
18.4
3.0 From buildings – accessible to pedestrians and
vehicles but not truck traffic
13.5
15.7
16.2
17.1
17.6
18.0
19.4
4.0 From buildings – over roofs accessible to truck
traffic
18.5
20.7
21.2
22.1
22.6
23.0
24.4
5.0 From signs, chimneys, billboards, radio & TV
antennas, tanks & other installations
not accessible to personnel.
8.0
10.2
10.7
11.6
12.1
12.5
13.9
6.0 From bridges – not attached (Note C )
12.5
14.7
15.2
16.1
16.6
17.0
18.4
7.0 From grain bins probe ports
18.0
20.2
20.7
21.6
22.1
22.5
23.9
27.2
27.7
28.6
29.1
29.5
30.9
19.2
19.7
20.6
21.1
21.5
22.9
.00
.02
.05
.07
.08
.12
25.0
8.0 Clearance in any direction from swimming pool
edge and diving platform base
(Clearance A, Figure 4-4)
Clearance in any direction from diving structures
17.0
(Clearance B, Figure 4-4)
ALTITUDE CORRECTION TO BE ADDED TO VALUES ABOVE
Additional feet of clearance per 1000 feet of altitude
above 3300 feet
Notes:
(A) An additional 2.0 feet of clearance is added to NESC clearance to obtain the recommended design clearances.
Greater values should be used where the survey method used to develop the ground profile is subject to greater
unknowns.
(B) Other supporting structures include lighting supports, traffic signal supports, or a supporting structure of another
line.
(C) If the line crosses a roadway, then Table 4-1, line 2.0 clearances are required.
(D) The NESC basic clearance is defined as the reference height plus the electrical component for open supply
conductors up to 22 kVLG except row ‘1.0’ where voltage referenc is 50 kVLG
(E) For 230 kV, clearances may be required to be higher if switching surges are greater than 2.0 per unit. See NESC
Tables 234-4 and 234-5.
Bulletin 1724E-200
Page 4-9
4.4.5 Examples of Clearance Calculations: The following examples demonstrate the
derivation of the vertical clearances shown in Tables 4-1 and 4-2.
To determine the vertical clearance of a 161 kV line crossing a road (category 2.0 of Table 4-1),
the clearance is based on NESC Table 232-1 and NESC Rule 232.
NESC Vertical Clearance = NESC Basic Clearance(Table 232-1) + .4(kVL-G – 22)/12
= 18.5 feet + .4(97.6-22)/12 feet
= 18.5 feet + 2.52 feet
NESC Vertical Clearance = 21.02 feet
Recommended Clearance
= NESC Vertical Clearance + Agency Adder
= 21.02 feet + 2.5 feet
= 23.52 feet (23.5 feet in Table 4-1)
To determine the vertical clearance of a 230 kV line over a building roof not accessible to
pedestrians (category 2.0 of Table 4-2), the clearance is based on NESC Table 234-1 and NESC
Rule 234.
NESC Vertical Clearance = NESC Basic Clearance(Table 234-1) + .4(kVL-G – 22)/12
= 12.5 feet + .4(139-22)/12 feet
= 12.5 feet + 3.9 feet
NESC Vertical Clearance = 16.4 feet
Recommended Clearance = NESC Vertical Clearance + Agency Adder
= 16.4 feet + 2.0 feet
= 18.4 feet (18.4 feet in Table 4-2)
4.5 Design Vertical Clearance Between Conductors Where One Line Crosses Over or
Under Another: Recommended design vertical clearances between conductors when one line
crosses another are provided in Table 4-3. The clearance values in Table 4-3 are for
transmission lines which are known to have ground fault relaying. The clearances should be
maintained at the point where the conductors cross, regardless of where the point of crossing is
located on the span.
4.5.1 Conditions Under Which Clearances Apply: The clearances apply for an upper
conductor at final sag for the conditions ‘a’ through ‘c’. The condition that produces the greatest
sag for the line is the one that applies.
a. A conductor temperature of 32°F, no wind, with a radial thickness of ice for the loading
district concerned.
b. A conductor temperature of 167°F. A lower temperature may be considered where justified
by a qualified engineering study. Under no circumstances should a design temperature be less
than 120°F.
c. Maximum conductor temperature, no wind. See paragraph 4.3.1. The same maximum
temperature used for vertical clearance to ground should be used.
Bulletin 1724E-200
Page 4-10
At a minimum the NESC requires that (1) the upper and lower conductors are simultaneously
subjected to the same ambient air temperature and wind loading conditions and (2) each is
subjected individually to the full range of its icing conditions and applicable design electrical
loading.
4.5.2 Altitude Greater than 3300 Feet: If the altitude of the crossing point of the two lines is
greater than 3300 feet, additional clearance as indicated in Table 4-3 is added to the base
clearance given.
4.5.3 Differences in Sag Conditions Between Lower and Upper Conductors: The reason for
the differences in sag conditions between the upper and lower conductor at which the clearances
apply is to cover situations where the lower conductor has lost its ice while the upper conductor
has not, or where the upper conductor is loaded to its thermal limit while the lower conductor is
only lightly loaded.
4.5.4 Examples of Clearance Calculations: The following example demonstrates the
derivation of the vertical clearance of a category in Tables 4-3 of this bulletin.
To determine the vertical clearance of a 161 kV line crossing a distribution conductor (item 3 of
Table 4-3), the clearance is based on NESC Table 233-1 and NESC Rule 233.
NESC Vertical Clearance= NESC Basic Clearance(Table 233-1) + .4(kVL-G – 22)/12
= 2.0 feet + .4(97.6-22)/12 feet
= 2.0 feet + 2.5 feet
NESC Vertical Clearance = 4.5 feet
Recommended Clearance
= NESC Vertical Clearance + Agency Adder
= 4.5 feet + 1.5 feet
= 6.0 feet (6.0 feet in Table 4-3)
4.6 Design Vertical Clearance Between Conductors of Different Lines at Noncrossing
Situations: If the horizontal separation between conductors as set forth in Chapter 5 cannot be
achieved, then the clearance requirements in section 4.5 should be attained.
4.7 Example of Line-to-Ground Clearance: A portion of a 161 kV line is to be built over a
field of oats that is at an elevation of 7200 feet. Determine the design line-to-ground clearance.
4.7.1 Solution of the Additional Clearance for Altitude: Because the altitude of the 161 kV
line is greater than 3300 feet, the basic clearance is to be increased by the amount indicated in
Table 4-1. The calculation follows:
(7200-3300)(.08)/1000 = 0.32 feet
Bulletin 1724E-200
Page 4-11
4.7.2 Total Clearance: Assuming the line meets the assumptions given in section 4.2 and
Table 4-1, the recommended design clearance over cultivated fields for a 161 kV line is
23.5 feet. Therefore, the recommended clearance, taking altitude into account, is 23.8 feet.
0.32 feet + 23.5 feet = 23.8 feet
An additional one foot of clearance should be added for survey, construction and design
tolerance.
4.8 Example of Conductor Crossing Clearances: A 230 kV line crosses over a 115 kV line in
two locations. At one location the 115 kV line has an overhead ground wire which, at the point
of crossing, is 10 feet above its phase conductors. At the other location the lower voltage line
does not have an overhead ground wire. Determine the required clearance between the 230 kV
conductors and the 115 kV conductors at both crossing locations. Assume that the altitude of the
line is below 3300 feet. Also assume that the sag of the overhead ground wire is the same as or
less than the sag of the 115 kV phase conductors. The 230 kV line has ground fault relaying.
Solution: The first step in the solution is to determine if the line being crossed over has
automatic ground fault relaying. We are able to determine that the lower line has automatic
ground fault relaying.
From Table 4-3, (item 4), the required clearance from a 230 kV conductor to a 115 kV conductor
is 9.0 feet. From Table 4-3, (item 2), the required clearance from the 230 kV conductor to the
overhead ground wire is 7.4 feet; adding 10 feet for the distance between the overhead ground
wire (OHGW) and the 115 kV phase conductors, the total required clearance is 17.4 feet.
When the lower circuit has an overhead ground wire, clearance requirements to the overhead
ground wire govern and the required clearance between the upper and lower phase conductor is
17.4 feet.
Where there is no overhead ground wire for the 115 kV circuit, the required clearance between
the phase conductors is 9.0 feet.
It is important to note that the above clearances are to be maintained where the upper conductor
is at its maximum sag condition, as defined in section 4.5.1b or 4.5.1c above, and the lower
conductor is at 60°F initial sag.
4.9 Vertical Clearances to Vegetation: The best practice is usually to remove all substantive
vegetation (such as trees and vines) under and adjacent to the line. In certain areas, such as
canyons, river crossings, or endangered species habitat, vegetation can be spanned. For vertical
clearances (intended to meet NERC FAC 003), refer to radial clearances discussed in Section
5.2.2 of this bulletin.
Bulletin 1724E-200
Page 4-12
TABLE 4-3
RECOMMENDED DESIGN VERTICAL CLEARANCES IN FEET
BETWEEN CONDUCTORS WHERE THE CONDUCTORS OF ONE LINE
CROSS OVER THE CONDUCTORS OF ANOTHER AND WHERE THE UPPER AND
LOWER CONDUCTORS HAVE GROUND FAULT RELAYING
Voltage between circuits = Voltage line to ground Top Circuit + Voltage line to ground Bottom Circuit (Calculations are
based on the maximum operating voltage.)
The NESC requires that clearances not be less than that required by application of a clearance envelope developed
under NESC Rules 233A1 & 233A2. Structure deflection shall also be taken into account. Agency recommended
values in this table are to be adders applied for the movement of the conductor and deflection of structures, if any.
UPPER LEVEL CONDUCTOR (Note F)
34.5
Nominal Voltage, Phase to Phase kV L-L
69
115
138
161
230
& 46
Max. Operating Voltage, Phase to Phase
(kVLL)
---72.5 120.8 144.9 169.1 241.5
Max. Operating Voltage, Phase to Ground
(kVLG)
---41.8
69.7
83.7
97.6
139.4
NESC
Basic
(kVLG)
Clearances in feet
Clear.
(Note H)
LOWER LEVEL CONDUCTOR
1. Communication
5.0
6.7
7.2
8.1
8.6
9.0
10.4
2. OHGW (Note G)
2.0
3.7
4.2
5.1
5.6
6.0
7.4
3. Distribution conductors
2.0
3.7
4.2
5.1
5.6
6.0
7.4
4. Transmission conductors of lines that
have ground fault relaying. Nominal
line – to – line voltage in kV. (Note F)
230 kV
161 kV
138 kV
115 kV
69 kV
46 kV and below
2.0
2.0
2.0
2.0
2.0
2.0
7.6
7.1
6.2
5.7
8.5
8.1
7.6
6.7
6.2
11.3
9.9
9.5
9.0
8.1
7.6
139.4
97.6
83.7
69.7
41.8
26.4
3.8
4.8
4.3
6.7
5.6
5.2
Notes:
(A) The conductors on other supports are assumed to be from different circuits
(B) This table applies to lines with ground fault relaying.
(C) The NESC requires that the clearance shall be not less than that required by application of a clearance envelope
developed under NESC Rule 233A2 to the positions on or within conductor movement envelopes developed under
Rule 233A1 at which the two wires, conductors or cables would be closest together. For purposes of this
determination, the relevant positions of the wires, conductors, or cables on or within their respective conductor
movement envelopes are those which can occur when (1) both are simultaneously subjected to the same ambient air
temperature and wind loading conditions and (2) each is subjected individually to the full range of its icing conditions
and applicable design electrical loading.
Bulletin 1724E-200
Page 4-13
TABLE 4-3 (continued)
RECOMMENDED DESIGN VERTICAL CLEARANCES IN FEET
BETWEEN CONDUCTORS WHERE THE CONDUCTORS OF ONE LINE
CROSS OVER THE CONDUCTORS OF ANOTHER AND WHERE THE UPPER AND
LOWER CONDUCTORS HAVE GROUND FAULT RELAYING
(D) An additional 1.5 feet of clearance is added to NESC clearance to obtain the recommended design clearances.
Greater values should be used where the survey method used to develop the ground profile is subject to greater
unknowns.
(E) ALTITUDE CORRECTION TO BE ADDED TO VALUES ABOVE
Total altitude
=
Correction for
+
correction factor
upper conductors
Correction for
lower conductors
For upper conductors use correction factor from Table 4-1 of this bulletin.
For lower conductors:
Categories 1, 2, 3 above use no correction factors
Category 4 uses correction factors from Table 4-1 of this bulletin
(F) The higher voltage line should cross over the lower voltage line
(G) If the line on the lower level has overhead ground wire(s), this clearance will usually be the limiting factor at
crossings.
(H) The NESC basic clearance is defined as the reference height plus the electrical component for open supply
conductors up to 22 kVL-G.
Bulletin 1724E-200
Page 4-14
Blank Page
Bulletin 1724E-200
Page 5-1
5. HORIZONTAL CLEARANCES FROM LINE CONDUCTORS TO OBJECTS AND
RIGHT-OF-WAY WIDTH
5.1 General: The preliminary comments and assumptions in Chapter 4 of this bulletin also
apply to this chapter.
5.2 Minimum Horizontal Clearance of Conductor to Objects: Recommended design
horizontal clearances of conductors to various objects are provided in Table 5-1 and minimum
radial operating clearances of conductors to vegetation in Table 5-2. The clearances apply only
for lines that are capable of automatically clearing line-to-ground faults.
Clearance values provided in Table 5-1are recommended design values. In order to provide an
additional margin of safety, the recommended design values exceed the minimum clearances in
the 2007 NESC. Clearance values provided in Table 5-2 are minimum operating clearances to be
used by the designer to determine appropriate design clearances for vegetation maintenance
management.
5.2.1 Conditions Under Which Horizontal Clearances to Other Supporting Structures,
Buildings and Other Installations Apply:
Conductors at Rest (No Wind Displacement): When conductors are at rest the clearances apply
for the following conditions: (a) 167°F but not less than 120°F, final sag, (b) the maximum
operating temperature the line is designed to operate, final sag, (c) 32°F, final sag with radial
thickness of ice for the loading district (0 in., ¼ in., or ½ in.).
Conductors Displaced by 6 psf Wind: The clearances apply when the conductor is displaced by
6 lbs. per sq. ft. at final sag at 60°F. See Figure 5-1.
δ
li
Sf
∅
x
y
FIGURE 5-1: HORIZONTAL CLEARANCE REQUIREMENT TO BUILDINGS
where:
φ =
Sf =
x =
ℓi =
y =
δ =
conductor swing out angle in degrees under 6 psf. of wind
conductor final sag at 60°F with 6 psf. of wind
horizontal clearance required per Tables 5-1 for conductors
displaced by 6 psf wind (include altitude correction if necessary)
insulator string length (ℓi = 0 for post insulators or restrained
suspension insulators).
total horizontal distance from insulator suspension point
(conductor attachment point for post insulators) to structure with
conductors at rest
structure deflection with a 6 psf. Wind
Bulletin 1724E-200
Page 5-2
TABLE 5-1
RECOMMENDED DESIGN HORIZONTAL CLEARANCES (in feet) FROM CONDUCTORS
AT REST AND DISPLACED BY 6 PSF WIND TO OTHER SUPPORTING STRUCTURES,
BUILDINGS AND OTHER INSTALLATIONS
(NESC Rules 234B, 234C, 234D, 234E, 234F, 234I, Tables 234-1, 234-2, 234-3)
Conditions under which clearances apply:
No wind: When the conductor is at rest the clearances apply at the following conditions: (a) 120°F, final sag, (b) the maximum
operating temperature the line is designed to operate, final sag, (c) 32°F, final sag with radial thickness of ice for the loading
district (1/4 in. for Medium or 1/2 in. Heavy).
Displaced by Wind: Horizontal clearances are to be applied with the conductor displaced from rest by a 6 psf wind at final sag at
60°F. The displacement of the conductor is to include deflection of suspension insulators and deflection of flexible structures.
The clearances shown are for the displaced conductors and do not provide for the horizontal distance required to account for blowout of
the conductor and the insulator string. This distance is to be added to the required clearance. See Equation 5-1.
Clearances are based on the Maximum Operating Voltage
Nominal voltage, Phase to Phase, kVL-L
34.5
& 46
-------
Max. Operating Voltage, Phase to Phase, kVL-L
Max. Operating Voltage, Phase to Ground, kVL-G
Horizontal Clearances - (Notes 1,2,3)
1.0 From a lighting support, traffic signal support
or supporting structure of another line
At rest
(NESC Rule 234B1a)
Displaced by wind (NESC Rule 234B1b)
2.0 From buildings, walls, projections, guarded
windows, windows not designed to open,
balconies, and areas accessible to pedestrians
At rest
(NESC Rule 234C1a)
Displaced by wind (NESC Rule 234C1b)
3.0 From signs, chimneys, billboards, radio, & TV
antennas, tanks & other installations not
classified as buildings
At rest
(NESC Rule 234C1a)
Displaced by wind (NESC Rule 234C1b)
4.0 From portions of bridges which are readily
accessible and supporting structures are not
attached
At rest
(NESC Rule 234D1a)
Displaced by wind
(NESC Rule 234D1b)
5.0 From portions of bridges which are ordinarily
inaccessible and supporting structures are not
attached
At rest
(NESC Rule 234D1a)
Displaced by wind (NESC Rule 234D1b)
69
115
138
161
230
72.5
41.8
120.8
69.7
144.9
83.7
169.1
97.6
241.5
139.4
NESC
Basic
Clear
Clearances in feet
5.0
4.5
6.5
6.2
6.5
6.7
7.2
7.6
7.6
8.1
8.1
8.5
9.5
9.9
7.5
4.5
9.2
6.2
9.7
6.7
10.6
7.6
11.1
8.1
11.5
8.5
12.9
9.9
7.5
4.5
9.2
6.2
9.7
6.7
10.6
7.6
11.1
8.1
11.5
8.5
12.9
9.9
7.5
4.5
9.2
6.2
9.7
6.7
10.6
7.6
11.1
8.1
11.5
8.5
12.9
9.9
6.5
4.5
8.2
6.2
8.7
6.7
9.6
7.6
10.1
8.1
10.5
8.5
11.9
9.9
Bulletin 1724E-200
Page 5-3
TABLE 5-1 (continued)
RECOMMENDED DESIGN HORIZONTAL CLEARANCES (in feet) FROM CONDUCTORS
AT REST AND DISPLACED BY 6 PSF WIND TO OTHER SUPPORTING STRUCTURES,
BUILDINGS AND OTHER INSTALLATIONS
(NESC Rules 234B, 234C, 234D, 234E, 234F, 234I, Tables 234-1, 234-2, 234-3)
Conditions under which clearances apply:
No wind: When the conductor is at rest the clearances apply at the following conditions: (a) 120°F, final sag, (b) the
maximum operating temperature the line is designed to operate, final sag, (c) 32°F, final sag with radial thickness of ice
for the loading district (1/4 in. for Medium or 1/2 in. Heavy).
Displaced by Wind: Horizontal clearances are to be applied with the conductor displaced from rest by a 6 psf wind at final sag
at 60°Funder extreme wind conditions (such as the 50 or 100-year mean wind) at final sag at 60°F. The displacement of the
conductor is to include deflection of suspension insulators and deflection of flexible structures.
The clearances shown are for the displaced conductors and do not provide for the horizontal distance required to account for
blowout of the conductor and the insulator string. This distance is to be added to the required clearance. See Equation 5-1.
Clearances are based on the Maximum Operating Voltage
Nominal voltage, Phase to Phase, kVL-L
Max. Operating Voltage, Phase to Phase, kVL-L
Max. Operating Voltage, Phase to Ground, kVL-G
Horizontal Clearances - (Notes 1,2,3)
34.5
& 46
-------
69
115
138
161
230
72.5
41.8
120.8
69.7
144.9
83.7
169.1
97.6
241.5
139.4
NESC
Basic
Clear
6.0 Swimming pools – see section 4.4.3 of
Chapter 4 and item 9 of Table 4–2.
(NESC Rule 234E)
Clearance in any direction from swimming
25.0
pool edge (Clearance A, Figure 4-2 of this bulletin)
Clearance in any direction from diving
17.0
structures (Clearance B, Figure 4-2 of this bulletin)
7.0 From grain bins loaded with permanently
attached conveyor
At rest
(NESC Rule 234F1b)
15.0
Displaced by wind (NESC Rule 234C1b)
4.5
8.0 From grain bins loaded with a portable conveyor.
Height ‘V’ of highest filling or probing port on bin
must be added to clearance shown. Clearances for ‘at
rest’ and not displaced by the wind. See NESC
Figure 234-4 for other requirements.
Horizontal clearance envelope (includes area of
sloped clearance per NESC Figure 234-4b)
9.0 From rail cars (Applies only to lines parallel to
tracks) See Figure 234-5 and section 234I (Eye) of
the NESC
Clearance measured to the nearest rail
ALTITUDE CORRECTION TO BE ADDED TO VALUES ABOVE
Additional feet of clearance per 1000 feet of altitude above
3300 feet
Clearances in feet
27.2
27.7
28.6
29.1
29.5
30.9
19.2
19.7
20.6
21.1
21.5
22.9
17.2
6.7
17.7
7.2
18.6
8.1
19.1
8.6
19.5
9.0
20.9
10.4
(24+V) + 1.5V (Note 3)
14.1
.02
14.1
15.1
15.6
16.0
17.5
.02
.05
.07
.08
.12
Notes:
1. Clearances for categories 1-5 in the table are approximately 1.5 feet greater than NESC clearances.
2. Clearances for categories 6 to 9 in the table are approximately 2.0 feet greater than NESC clearances.
3. “V” is the height of the highest filling or probing port on a grain bin. Clearance is for the highest voltage of 230 kV.
Bulletin 1724E-200
Page 5-4
5.2.2 Considerations in Establishing Radial and Horizontal Clearances to Vegetation:
The designer should identify and document clearances between vegetation and any overhead,
ungrounded supply conductors, taking into consideration transmission line voltage, the effects of
ambient temperature on conductor sag under maximum design loading, and the effects of wind
velocities on conductor sway. Specifically, the designer should establish clearances to be
achieved at the time of vegetation management work and should also establish and maintain a set
of clearances to prevent flashover between vegetation and overhead ungrounded supply
conductors. As a mimimum, these clearances should apply to all transmission lines operated at
200 kV phase-to-phase and above and to any lower voltage lines designated as critical (refer to
NERC FAC 003).
The designer should determine and document appropriate clearance distances to be achieved at
the time of transmission vegetation management work based upon local conditions and the
expected time frame in which the Transmission Owner plans to return for future vegetation
management work. Local conditions may include, but are not limited to: operating voltage,
appropriate vegetation management techniques, fire risk, reasonably anticipated tree and
conductor movement, species types and growth rates, species failure characteristics, local
climate and rainfall patterns, line terrain and elevation, location of the vegetation within the
span, and worker approach distance requirements.
The designer should determine and document specific radial clearances to be maintained
between vegetation and conductors under all rated electrical operating conditions. These
minimum clearance distances are necessary to prevent flashover between vegetation and
conductors and will vary due to such factors as altitude and operating voltage. These specific
minimum clearance distances should be no less than those set forth in the Institute of Electrical
and Electronics Engineers (IEEE) Standard 516-2003 (Guide for Maintenance Methods on
Energized Power Lines) and as specified in its Section 4.2.2.3, Minimum Air Insulation
Distances without Tools in the Air Gap. Where transmission system transient overvoltage factors
are not known, clearances shall be derived from Table 5, IEEE 516-2003, phase-to-ground
distances, with appropriate altitude correction factors applied.Where transmission system
transient overvoltage factors are known, clearances shall be derived from Table 7, IEEE 5162003, phase-to-phase voltages, with appropriate altitude correction factors applied. Table 5-2
contains radial clearances determined from Table 5, IEEE 516-2003, where transmission system
transient overvoltage factors are not known.
i
Sf
Ø
xv
yv
FIGURE 5-2: RADIAL CLEARANCE REQUIREMENT TO VEGETATION
Bulletin 1724E-200
Page 5-5
where:
φ
=
Sf =
xv =
ℓi =
y
=
δ =
conductor swing out angle in degrees under all rated operating
conditions
conductor final sag at all rated operating conditions
radial clearance (include altitude correction if necessary)
insulator string length (ℓi = 0 for post insulators or restrained
suspension insulators).
horizontal clearance at the time of vegetation management work
structure deflection at all rated operating conditions
TABLE 5-2
RADIAL OPERATING CLEARANCES (in feet) FROM IEEE 516 FOR USE IN
DETERMINING CLEARANCES TO VEGETATION FROM CONDUCTORS
(NERC Standard FAC-003.1 Transmission Vegetation Management Program, IEEE 516,
Guideline For Maintenance Methods Of Energized Power Lines)
Conditions under which clearances apply:
Displaced by Wind: Radial operating clearances are to be applied at all rated operating conditions.The designer should
determine applicable conductor temperature and wind conditions for all rated operating conditions. The displacement of the
conductor is to include deflection of suspension insulators and deflection of flexible structures.
The operating clearances shown are for the displaced conductors and do not provide for the horizontal distance required to
account for blowout of the conductor and the insulator string. This distance is to be added to the required clearance. See
Equation 5-1.
Clearances are based on the Maximum Operating Voltage.
Nominal voltage, Phase to Phase, kVL-L
Max. Operating Voltage, Phase to Phase, kVL-L
Max. Operating Voltage, Phase to Ground, kVL-G
Radial Table 5 IEEE Standard 516 Operating
Clearances
34.5
& 461
-------
691
1151
1381
1611
2301,2
72.5
41.8
120.8
69.7
144.9
83.7
169.1
97.6
241.5
139.4
Clearances in feet
Operating clearance at all rated operating
conditions
1.8
1.8
1.9
2.3
2.5
2.7
Design adder for survey and installation tolerance
1.5 feet for all voltages
Design adder for vegetation
Determined by designer (see Note 3 below)
ALTITUDE CORRECTION TO BE ADDED TO VALUES ABOVE
Additional feet of clearance per 1000 feet of altitude above
.02
.02
.05
.07
.08
.12
3300 feet
Notes:
1.
2.
3.
These clearances apply to all transmission lines operated at 200 kV phase-to-phase and above and to any lower
voltage lines designated as critical (refer to NERC FAC 003).
The 230 kV clearance is based on 3.0 Per Unit switching surge.
The design adder for vegetation, applied to conductors displaced by wind, should account for reasonably anticipated
tree movement, species types and growth rates, species failure characteristics, and local climate and rainfall patterns.
The design adder for vegetation, applied to conductors at rest, should account for worker approach distances in
addition to the aforementioned factors.
Bulletin 1724E-200
Page 5-6
5.2.3 Clearances to Grain Bins: The NESC has defined clearances from grain bins based on
grain bins that are loaded by permanent or by portable augers, conveyers, or elevator systems.
In NESC Figure 234-4(a), the horizontal clearance envelope for permanent loading equipment is
graphically displayed and shown Figure 5-2.
P = probe clearance, item 7, Table 4-2
H = horizontal clearance, item 7, Table 5-1
T = transition clearance
V1 = vertical clearance, item 2&3,
Table 4-2
V2 = vertical clearance, Table 4-1
FIGURE 5-3: CLEARANCE TO
GRAIN BINS
NESC FIGURE 234-4a
V1
P
T
V2
H
Permanent
Elevator
V1
V1
P
Probe
Ports
V1
P
T
Grain Bin
Grain Bin
H
V2
From IEEE/ANSI C2-2007, National Electrical Safety Code, Copyright 2006. All rights reserved.
Because the vertical distance from the probe in Table 4-2, item 7.0, is greater than the horizontal
distance, (see Table 5-1, item 7.0), the user may want to simplify design and use this distance as
the horizontal clearance distance as shown below:
No overhead lines
FIGURE 5-4: HORIZONTAL
CLEARANCE TO GRAIN
BINS, CONDUCTORS AT REST
P = clearance from item 7, Table 4-2
P
Permanent
Elevator
Grain Bin
FIGURE 5-5: HORIZONTAL
CLEARANCE TO GRAIN BINS,
CONDUCTORS DISPLACED
BY 6 PSF WIND
P
Probe
Ports
Grain Bin
No Overhead Lines
Item 7.0
Table 5-1
Permanent
Elevator
Grain Bin
or Table 5-2
Probe
Ports
Grain Bin
Bulletin 1724E-200
Page 5-7
The clearance envelope for portable loading equipment from NESC Figure 234(b), is shown in
1.5
Figure 5-6.
1
1.5
18'
1
15'
H
V
See NESC Rule 232
See NESC Rule 232
V=Height of highest filling or probing port on grain bin
H=V- 18'
1.5:1
slope
1.5:1
slope
Flat top of
clearance
envelope
1.5:1
slope
LOADING
SIDE
15'
H
NON-LOADING
SIDE
1.5:1
slope
NESC
RULE 232
AREA
AREA OF SLOPED
CLEARANCE
1.5:1
slope
FIGURE 5-6: NESC CLEARANCE TO GRAIN BINS WITH
PORTABLE LOADING EQUIPMENT
From IEEE/ANSI C2-2007, National Electrical Safety Code, Copyright 2006. All rights reserved.
In order to simplify the clearance envelope, the horizontal clearances in category 8 of Table 5-1
is shown as ‘H’ in the drawing below:
LOADING SIDE
No Overhead
Lines
NON-LOADING
15'
H
FIGURE 5-7: SIMPLIFIED RECOMMENDATIONS FOR CLEARANCES
TO GRAIN BINS WITH PORTABLE LOADING EQUIPMENT
5.2.4 Altitude Greater Than 3300 Feet: If the altitude of the transmission line or portion
thereof is greater than 3300 feet, an additional clearance as indicated in Table 5-1 and 5-2 has to
be added to the base clearance given.
Bulletin 1724E-200
Page 5-8
5.2.5 Total Horizontal Clearance to Point of Insulator Suspension to Object: As can be
seen from Figure 5-1, the total horizontal clearance (y) is:
y = (l i + S f )sin φ + x + δ
Eq. 5-1
Symbols are defined in Section 5.2.1 and figure 5-1. The factor "δ" indicates that structure
deflection should be taken into account.
For the sake of simplicity when determining horizontal clearances, the insulator string should be
assumed to have the same swing angle as the conductor. This assumption should be made only
in this chapter as its use in calculations elsewhere may not be appropriate.
The conductor swing angle ( φ ) under wind can be determined from the formula.
φ = tan
where:
−1
⎛ (d c )(F ) ⎞
⎟⎟
⎜⎜
⎝ 12 w c ⎠
Eq. 5-2
dc = conductor diameter in inches
wc = weight of conductor in lbs./ft.
F = wind force;
The total horizontal distance (y) at a particular point in the span depends upon the conductor sag
at that point. The value of (y) for a structure adjacent to the maximum sag point will be greater
than the value of (y) for a structure placed elsewhere along the span. See Figure 5-7.
Conductor
position with no
wind blowing.
Conductor in blown
out position.
Top view of line
y
x
x = clearance from wind-displaced conductor, y= total horizontal clearance from conductor at
rest
FIGURE 5-8: A TOP VIEW OF A LINE SHOWING TOTAL
HORIZONTAL CLEARANCE REQUIREMENTS
Bulletin 1724E-200
Page 5-9
5.2.6 Examples of Horizontal Clearance Calculations: The following examples demonstrate
the derivation of the horizontal clearance in Table 5-1 of this bulletin.
To determine the horizontal clearance of a 115 kV line to a building (category 2.0 of Table 5-1),
the clearance is based on NESC Table 234-1 and NESC Rule 234.
At rest:
NESC Horizontal Clear.
NESC Horizontal Clear.
= NESC Basic Clearance(Table 234-1) + .4(kVL-G – 22)/12
= 7.5 feet + .4(69.7-22)/12 feet
= 7.5 feet + 1.59 feet
= 9.09 feet
Recommended Clearance = NESC Horizontal Clearance + Adder
= 9.09 feet + 1.5 feet
y = 10.59 feet (10.60 feet in Table 5-1)
Conductors displaced by 6 psf wind:
NESC Horizontal Clear. = NESC Basic Clearance (Table 234-1) + .4(kVL-G – 22)/12
= 4.5 feet + .4(69.7-22)/12 feet
= 4.5 feet + 1.59 feet
NESC Horizontal Clear. = 6.09 feet
Recommended Clearance = NESC Horizontal Clearance + Adder
= 6.09 feet + 1.5 feet
x = 7.59 feet (7.6 feet in Table 5-1)
5.3 Right-of-Way (ROW) Width: For transmission lines, a right-of-way provides an
environment allows the line to be operated and maintained safely and reliably. Determination of
the right-of-way width is a task that requires the consideration of a variety of judgmental,
technical, and economic factors.
Typical right-of-way widths (predominantly H-frames) that have been used by agency borrowers
in the past are shown in Table 5-2. In many cases a range of widths is provided. The actual
width used will depend upon the particulars of the line design.
TABLE 5-3
TYPICAL RIGHT-OF-WAY WIDTHS
Nominal Line-to-Line Voltage in kV
ROW Width, ft.
69
115
138
161
230
75-100
100
100-150
100-150
125-200
5.4 Calculation of Right-of-Way Width for a Single Line of Structures on a Right-of-Way:
Right-of-way widths can be calculated using the method described below. The calculated values
for right-of-way widths are directly related to the particular parameters of the line design. This
method provides sufficient width to meet clearance requirements to buildings of undetermined
height or vegetation located directly on the edge of the right-of-way. See Figures 5-8 and 5-9.
Bulletin 1724E-200
Page 5-10
i
Sf
Ø
x
y
A
W
FIGURE 5-9: ROW WIDTH FOR SINGLE LINE OF STRUCTURES
(
)
W = A + 2 l i + S f sin φ + 2δ + 2 x
Eq. 5-3
where:
W = total right-of-way width required
A = separation between points of suspension of insulator
strings for outer two phases
x = clearance required per Table 5-1 and appropriate
clearance derived from Table 5-2 of this bulletin
(include altitude correction if necessary)
y = clearance required per Section 5.2.1 and Table 5-1 and
appropriate clearance derived from Section 5.2.2. and
Table 5-2 of this bulletin (include altitude correction if
necessary)
Other symbols are as previously defined. In some instances, clearance “x”
may control. In other instances, clearance “y” may control.
There are two ways of choosing the length (and thus the sag) on which the right-of-way width is
based. One is to use a width based on the maximum span length in the line. The other way is to
base the width on a relatively long span, (the ruling span, for instance), but not the longest span.
For those spans that exceed this base span, additional width is added as appropriate.
5.5 Right-of-Way Width for a Line Directly Next to a Road: The right-of-way width for a
line next to a road can be calculated based on the two previous sections with one exception. No
ROW is needed on the road side of the line as long as the appropriate clearances to existing or
possible future structures on the road side of the line are met.
If a line is to be placed next to a roadway, consideration should be given to the possibility that
the road may be widened. If the line is on the road right-of-way, the borrower would generally
be expected to pay for moving the line. If the right-of-way is on private land, the highway
Bulletin 1724E-200
Page 5-11
department should pay. Considerations involved in placing a line on a road right-of-way should
also include evaluation of local ordinances and requirements.
5.6 Right-of-Way Width for Two or More Lines of Structures on a Single Right-of-Way:
To determine the right-of-way width when the right ROW contains two parallel lines, start by
calculating the distance from the outside phases of the lines to the ROW edge (see Section 5.4).
The distance between the two lines is governed by the two criteria provided in section 5.6.1. If
one of the lines involved is an extra high voltage (EHV) line (345 kV and above), the NESC
should be referred to for additional applicable clearance rules not covered in this bulletin.
5.6.1 Separation Between Lines as Dictated by Minimum Clearance Between Conductors
Carried on Different Supports: The horizontal clearance between a phase conductor of one
line to a phase conductor of another line shall meet the larger of C1, or C2 below, under the
following conditions: (a) both phase conductors displaced by a 6 psf wind at 60°F, final sag; (b)
if insulators are free to swing, one should be assumed to be displaced by a 6 lbs/sq. ft. wind
while the other should be assumed to be unaffected by the wind (see Figure 5-10). The assumed
wind direction should be that which results in the greatest separation requirement. It should be
noted that in the Equations 5-5, and 5-6, the ‘δ1-δ2’ term, (the differential structure deflection
between the two lines of structures involved), is to be taken into account. An additional 1.5 feet
have been added to the NESC clearance to obtain design clearances ‘C1’and ‘C2’. Note Equation
5-6 has been revised from previous versions due to the voltage adder change in the 2007 NESC
edition.
C1 = 6.5 + (δ 1 − δ 2 ) (NESC Rule 233B1)
C 2 = 6.5 +
.4
[(kVLG1 + kVLG 2 ) − 22] + (δ 1 − δ 2 ) (NESC Rule 233B1)
12
where:
C1,C2 = clearance requirements between conductors on
different lines in feet (largest value governs)
kVLG1 = maximum line-to-ground voltage in kV of line 1
kVLG2 = maximum line-to-ground voltage in kV of line 2
δ1 = deflection of the upwind structure in feet
δ2 = deflection of the downwind structure in feet
δ1
δ2
C1 ,C 2
FIGURE 5-10: CLEARANCE BETWEEN CONDUCTORS OF ONE LINE
TO CONDUCTOR OF ANOTHER LINE
Eq. 5-5
Eq. 5-6
Bulletin 1724E-200
Page 5-12
5.6.2 Separation Between Lines as Dictated by Minimum Clearance of Conductors From
One Line to the Supporting Structure of Another: The horizontal clearance of a phase
conductor of one line to the supporting structure of another when the conductor and insulator are
displaced by a 6 psf wind at 60°F final sag should meet Equation 5-7.
C3 = 6'+
where:
.4
(kVLG − 22) + (δ1 − δ 2 )
12
Eq. 5-7
kVLG = the maximum line-to-ground voltage in kV
C3 = the clearance of conductors of one line to structure of
another in feet
Other symbols are defined in Figure 5-1.
Additional 1.5 feet have been added to the NESC clearance and included in equation 5-7 to
obtain the design clearance ‘C3’.
.
δ1
δ2
C3
FIGURE 5-11: CLEARANCE BETWEEN CONDUCTORS OF ONE LINE
AND STRUCTURE OF ANOTHER
The separation between lines will depend upon the spans and sags of the lines as well as how
structures of one line match up with structures of another. In order to avoid the unreasonable
task of determining separation of structures span-by-span, a standard separation value should be
used, based on a worst case analysis. Thus if structures of one line do not always line up with
those of the other, the separation determined in section 5.6.2 should be based on the assumption
that the structure of one line is located next to the mid-span point of the line that has the most
sag.
5.6.3 Other Factors: Galloping should be taken into account in determining line separation. In
fact, it may be the determining factor in line separation. See Chapter 6 for a discussion of
galloping.
Bulletin 1724E-200
Page 5-13
Standard phase spacing should also be taken into account. For example, if two lines of the same
voltage using the same type structures and phase conductors are on a single ROW, a logical
separation of the two closest phases of the two lines should be at least the standard phase
separation of the structure.
5.6.4 Altitude Greater than 3300 Feet: If the altitude at which the lines included in the design
are installed greater than 3300 feet, NESC Section 23 rules provide additional separation
requirements.
Bulletin 1724E-200
Page 5-14
BLANK PAGE
Bulletin 1724E-200
Page 6-1
6. CLEARANCES BETWEEN CONDUCTORS AND BETWEEN CONDUCTORS AND
OVERHEAD GROUND WIRES
6.1 General: The preliminary comments and assumptions of Chapter 4, section 4.2, also apply
to this chapter.
This chapter considers design limits related to conductor separation. It is assumed that only
standard agency structures will be used, thus making it unnecessary to check conductor
separation at structures. Therefore, the only separation values left to consider are those related to
span length and conductor sags.
Maximum span lengths may be controlled by conductor separation. Other factors which may
limit span length, but are not covered in this chapter, are structure strength, insulator strength,
and ground clearance.
6.2 Maximum Span as Limited by Horizontal Conductor Separation: Sufficient horizontal
separation between phases is necessary to prevent swinging contacts and flashovers between
conductors where there is insufficient vertical separation.
6.2.1 Situations Under Which Maximum Span as Limited by Horizontal Separation are to
be Met:
If the vertical separation
(regardless of horizontal
displacement) of phase
conductors of the same or
different circuit(s) at the
structure is less than the
appropriate values provided in
Table 6-1,then the
recommendations in sections
6.2.2, 6.2.3, and 6.2.4 of this
section should be met.
H
V
FIGURE 6-1: EXAMPLE OF VERTICAL AND HORIZONTAL
SEPARATION VALUES
6.2.2 Horizontal Separation Recommendations: Equation 6-1 gives an horizontal phase
spacing (relative to conductor sag, and thus indirectly to span length) that should be sufficient to
prevent swinging contacts or flashovers between phases of the same or different circuits.
H = (0.025)kV + Fc S f + l i (sin φmax )
Eq. 6-1
Bulletin 1724E-200
Page 6-2
where:
H = horizontal separation between the phase conductors at the
structure in feet.
kV = (phases of the same circuit) the nominal line-to-line voltage
in 1000's of volts for 34.5 and 46 kV and 1.05 times the
nominal voltage in 1000's of volts for higher voltages
kV = (phases of different circuits) 1.05 times the magnitude of the
voltage vector between the phases in 1000's of volts. kV
should never be less than 1.05 times the nominal line-toground voltage in 1000's of volts of the higher voltage circuit
involved regardless of how the voltage vectors add up. The
voltage between the phases should be taken as the sum of the
two line-to-ground voltages, based on 1.05 times nominal
voltage.
Fc = experience factor
Ømax = maximum 6 psf insulator swing angle for the structure in
question. See Chapter 7 of this bulletin.
Sf = final sag of the conductor at 60°F, no load, in feet
l i = length of the insulator string in feet, l i = 0 for post or
restrained suspension insulators
V = vertical separation between phase conductors
at the structure in feet
The experience factor (Fc) may vary from a minimum of 0.67 to a maximum of 1.4, depending
upon how severe the wind and ice conditions are judged to be. The following are values of Fc
that have proved to be satisfactory in the past.
Fc = 1.15 for the light loading zone
Fc = 1.2 for the medium loading zone
Fc = 1.25 for the heavy loading zone
Any value of Fc in the 0.67 to 1.4 range may be used if it is thought to be reasonable and
prudent. There has been significant favorable experience with larger conductor sizes that have
horizontal spacing based on an Fc factor of 0.67. Therefore, Fc factor values significantly less
than the values listed above may be appropriate. If Fc values less than those given above are
used, careful attention should be paid to galloping as a possible limiting condition on the
maximum span length.
Bulletin 1724E-200
Page 6-3
TABLE 6-1
RECOMMENDED VERTICAL SEPARATION IN FEET BETWEEN PHASES
OF THE SAME OR DIFFERENT CIRCUITS ATTACHED TO THE SAME STRUCTURE
(For separations less than those shown, Equation 6-1 applies) (See Notes E & F)
Nominal voltage, Line-to-Line Voltage in kV
Max. Operating Voltage, Phase to Phase, kV
Max. Operating Voltage, Phase to Ground, kV
34.5 &
46
-------
69
115
138
161
230
72.5
41.8
120.8
69.7
144.9
83.7
169.1
97.6
241.5
139.4
Vertical Separation
Separation in feet
Minimum Vertical Separation at Support
1. Phases of the same circuit (Note A)
(Based on NESC Table 235-5)
3.2
4.0
5.6
6.4
7.2
9.6
2. Phases of different circuits (Notes B & D)
(Based on NESC Table 235-5,footnote 7
criteria for different utilities)
5.4
6.3
8.2
9.1
10.1
12.8
3. Phase conductors and overhead ground
wires (Based on NESC 235C and 233C3)
Minimum Vertical Separation in Span
2.5
2.9
3.9
4.3
4.8
6.4
4. Phases of the same circuit (Notes A & G)
(Based on NESC Table 235-5), H ≥ 1.0 ft.,
Figure 6-4
2.5
3.3
4.9
5.7
6.5
9.0
5. Phases of different circuits (Notes C, D & G)
(Based on NESC Table 235-5, footnote
7 criteria for different utilities NESC Rule
235C2b.), H ≥ 1.0 ft.,
Figure 6-4
4.2
5.2
7.0
7.9
8.9
11.7
6. Phase conductors and overhead ground
1.5
2.1
3.0
3.6
4.0
wires (H ≥ 1.0 ft., Figure 6-4), Notes D & G
ALTITUDE CORRECTION TO BE ADDED TO VALUES IN CATEGORY ‘2’ ABOVE (NONE
REQUIRED FOR CATEGORY ‘1’):
5.4
Additional feet of clearance per 1000 feet of
altitude above 3300 feet
.12
.02
.02
.05
.07
.08
Notes:
(A) There are no NESC values specified for vertical separation of conductors of the same circuit for
voltages above 50 kV line-to-line.
(B) Assumes both circuits have the same nominal voltage. If they do not, the vertical separation can be
determined using Equation 6-2 below.
V=
40 .4
6
+ (kVLG1 + kVLG 2 − 8.7 ) + ( NoteD )
12 12
12
where:
kVLG1
kVLG 2
=
=
Line to ground voltage circuit one, kilovolts.
Line to ground voltage circuit two, kilovolts.
Eq. 6-2
Bulletin 1724E-200
Page 6-4
TABLE 6-1 (continued)
RECOMMENDED VERTICAL SEPARATION IN FEET BETWEEN PHASES
OF THE SAME OR DIFFERENT CIRCUITS ATTACHED TO THE SAME STRUCTURE
(For separations less than those shown, Equation 6-1 applies) (See Notes E & F)
(C) Assumes both circuits have the same nominal voltage. If they do not, the vertical separation can be
determined using Equation 6-2a below.
6
⎡ 40 .4
⎤ .4
V = .75⎢ + (50 − 8.7)⎥ + (kVLG1 + kVLG 2 − 50) + ( NoteD ) Eq. 6-2a
12
⎣ 12 12
⎦ 12
(D) An additional 0.5 feet of clearance is added to the NESC clearance to obtain the recommended
design clearances.
(E) The values in this table are not recommended as minimum vertical separations at the structure for
non-standard agency structures. They are intended only to be used on standard agency structures to
determine whether or not horizontal separation calculations are required.
(F) The upper conductor is at final sag at the maximum operating temperature and the lower conductor
is at final sag at the same ambient conditions as the upper conductor without electrical loading and
without ice loading; or, the upper conductor is at final sag at 32º with radial ice from either the medium
loading district or the heavy loading district and the lower conductor is at final sag at 32ºF.
(G) In areas subjected to icing, an additional 2.0 feet of clearance should be added to the above
clearances when conductors or wires are directly over one another or have less than a one foot
horizontal offset. See section 6.3 of this bulletin.
6.2.3 Additional Horizontal Separation Equation: Equation 6-3 below, commonly known as
the Percy Thomas formula, may be used in addition to (but not instead of) equation 6-1 for
determining the horizontal separation between the phases at the structure. Equation 6-3 takes
into account the weight, diameter, sag, and span length of the conductor.
H = (.025)kV +
(Ec )(d c )(S p )
wc
+
li
2
Eq. 6-3
where:
dc = conductor diameter in inches
wc = weight of conductor in lbs/ft.
Ec = an experience factor. It is generally recommended that (Ec)
be larger than 1.25.
Sp = sag of conductor at 60°F, expressed as a percent of span
length
All other symbols are as previously defined.
By using the Thomas formula to determine values of Ec, the spacing of conductors on lines
which have operated successfully in a locality can be examined. These values of Ec may be
helpful in determining other safe spacings.
6.2.4 Maximum Span Based on Horizontal Separation at the Structure: Equation 6-1 can
be rewritten and combined with Equation 10-1 (Chapter 10) to yield the maximum allowable
Bulletin 1724E-200
Page 6-5
span, given the horizontal separation at the structure and the sag and length of the ruling span.
See Chapter 9 for a discussion of ruling span.
⎛ H − (.025)kV − l i sin φmax ⎞
⎟
Eq. 6-4
Lmax = (RS )⎜
⎜
⎟
F
S
c
RS
⎝
⎠
where:
Lmax = maximum span as limited by conductor separation in feet
RS = length of ruling span in feet
SRS = sag of the ruling span at 60°F final sag in feet
Other symbols are as previously defined for Eq. 6-1.
6.2.5 Maximum Span Based on Vertical Separation: Since vertical separation is related to
the relative sags of the phase conductors involved, and since sags are related to span length, a
maximum span as limited by vertical separation can be determined. The formula for the
maximum span as limited by vertical separation is:
Lmax = (RS )
where:
Lmax
Dv
B
Sl
Su
RS
=
=
=
=
=
=
Dv − B
Sl − Su
Eq. 6-5
maximum allowable span in feet
required vertical separation at mid-span in feet
vertical separation at supports in feet
sag of lower conductor in feet without ice
sag of upper conductor wire in feet with ice
ruling span in feet
6.2.6 Example of Clearance Calculations: The following example demonstrates the derivation
of the vertical separation at a support for phases of different circuits in Tables 6-1 of this bulletin.
To determine the vertical separation of a 115 kV line to another 115 kV circuit, the clearance is
based on NESC Table 235-5 and NESC Rule 235.
At the support, phases of different circuits:
NESC Vertical Separation = 40 inches/12 in./ft + .4(kVL-G + kVL-G – 8.7)/12 ft.
= 3.333 ft. + .4(69.7+69.7-8.7)/12 ft.
= 3.33 ft.+ 4.36 ft.
NESC Vertical Separation = 7.69 feet
Recommended
Vertical Separation
= NESC Vertical Separation + suggested Adder
= 7.69 feet + 0.5 feet
= 8.19 feet (8.2 feet in Table 6-1)
Bulletin 1724E-200
Page 6-6
In the span, phases of different circuits:
NESC Vertical Separation
⎡ 40 .4
⎤ .4
= 0.75⎢ + (50 − 8.7)⎥ + (kVLG1 + kVLG 2 − 50)
⎣ 12 12
⎦ 12
= 0.75(3.33+1.37) ft + (.4/12)(69.7+69.7-50) feet
= 3.53 ft. + 2.98 feet
NESC Vertical
Separation in the Span = 6.51 feet
Recommended
Clearance
= NESC Vertical Separation + suggested Adder
= 6.51 feet + .5 feet
= 7.01 feet (7.0 feet in Table 6-1)
6.3 Maximum Span as Limited by Conductor Separation Under Differential Ice Loading
Conditions
6.3.1 General: There is a tendency among conductors covered with ice, for the conductor
closest to the ground to drop its ice first. Upon unloading its ice the lower conductor may jump
up toward the upper conductor, possibly resulting in a temporary short circuit. After the lower
conductor recovers from its initial ice-jump it may settle into a position with less sag than before,
which may persist for long periods of time. If the upper conductor has not dropped its ice, the
reduced separation may result in a flashover between phases.
The clearance recommendations provided in paragraph 6.3.2 of this section are intended to
insure that sufficient separation will be maintained during differential ice loading conditions with
an approach towards providing clearance for the ice-jump.
6.3.2 Clearance Recommendations: The minimum vertical distance (Dv) in span between
phase conductors, and between phase conductors and overhead ground wires under differential
ice loading conditions, are provided in Table 6-1. These vertical separations in span are
recommended in cases where the horizontal separation between conductors (H) is greater than
one foot (H ≥1.0 ft). When conductors or wires are directly over one another or have less than a
1 foot horizontal offset, it is recommended that an additional 2 feet of clearance be added to the
values given in Table 6-1. The purpose of this requirement is to improve the performance of the
line under ice-jump conditions. It has been found that a horizontal offset of as little as 1 foot
significantly lessens the ice-jump problem. Figure 6-4 indicates the horizontal and vertical
components of clearance and their relationship.
Upper
Upperconductor
conductoratat32ºF,
32° Ffinal sag,
ice
for
medium
or
heavy
final sag, maximum ice loading district.
Dv
H
Lower conductor at 32° F,
final sag, no ice.
FIGURE 6-2: MINIMUM DISTANCE BETWEEN CONDUCTORS
Bulletin 1724E-200
Page 6-7
6.3.3 Conditions Under Which Clearances Apply: Lines should be designed so that
clearances are considered with the upper conductor at 32°F, final sag, and a radial thickness of
ice equal to the ice thickness from either the medium loading district or the heavy loading
district. The lower conductor should be at 32°F, final sag, no ice. The designer is reminded to
check clearances for the upper conductor at the maximum operating temperature (no wind) and
the lower conductor at ambient temperature (see Note F of Table 6-1).
6.4 Overhead Ground Wire Sags and Clearances: In addition to checking clearances
between the overhead ground wire (OHGW) and phase conductors under differential ice loading
conditions, it is also important that the relative sags of the phase conductors and the OHGW be
coordinated so that under more commonly occurring conditions, there will be a reasonably low
chance of a mid-span flashover. Adequate midspan separation is usually assured for standard
agency structures by keeping the sag of the OHGW at 60°F initial sag, no load conditions to
80 percent of the phase conductors under the same conditions.
6.5 Maximum Span as Limited by Galloping
6.5.1 The Galloping Phenomenon: Galloping, sometimes called dancing, is a phenomenon
where the transmission line conductors vibrate with very large amplitudes. This movement of
conductors may result in: (1) contact between phase conductors or between phase conductors
and overhead ground wires, resulting in electrical outages and conductor burning, (2) conductor
failure at support point due to the violent stress caused by galloping, (3) possible structure
damage, and (4) excessive conductor sag due to the overstressing of conductors.
Galloping usually occurs only when a steady, moderate wind blows over a conductor covered by
a layer of ice deposited by freezing rain, mist or sleet. The coating may vary from a very thin
glaze on one side to a solid three-inch cover and may give the conductor a slightly out-of-round,
elliptical, or quasi-airfoil shape. The wind blowing over this irregular shape results in
aerodynamic lift which causes the conductor to gallop. The driving wind can be anything
between 5 to 45 miles per hour at an angle to the line of 10 to 90 degrees and may be unsteady in
velocity or direction.
During galloping, the conductors oscillate elliptically at frequencies on the order of 1-Hz or less
with vertical amplitudes of several feet. Sometimes two loops appear, superimposed on one
basic loop. Single-loop galloping rarely occurs in spans over 600 to 700 feet. This is fortunate
since it would be impractical to provide clearances large enough in long spans to prevent the
possibility of contact between phases. In double-loop galloping, the maximum amplitude usually
occurs at the quarter span points and is smaller than that resulting from single-loop galloping.
There are several measures that can be incorporated at the design stage of a line to reduce
potential conductor contacts caused by galloping, such as designing the line to have shorter
spans, or increased phase separation. The H-frame structures provide very good phase spacing
for reducing galloping contacts.
6.5.2 Galloping Considerations in the Design of Transmission Lines: In areas where
galloping is either historically known to occur or is expected, designers should indicate design
measures that will minimize galloping and galloping problems, especially conductor contacts.
The primary tool for assuring absence of conductor contacts is to superimpose Lissajous ellipses
over a scaled diagram of the structure to indicate the theoretical path of a galloping conductor.
See Figures 6-3 and 6-4. To avoid contact between phase conductors or between phase
conductors and overhead ground wires, none of the conductor ellipses should touch one another.
However, if galloping is expected to be infrequent and of minimal severity, there may be
situations where allowing ellipses to overlap may be the favored design choice when economics
are considered.
Bulletin 1724E-200
Page 6-8
FIGURE 6-3: GUIDE FOR PREPARATION
OF LISSAJOUS ELLIPSES
POINT OF SUSPENSION
INSULATOR SUPPORT
POINT OF CONDUCTOR
ATTACHMENT
⎛ pc
⎝ wc
φ = tan −1 ⎜⎜
i
Ø
Si
⎞
⎟⎟
⎠
Eq. 6-6
D
Ø+ Ø
M
2
B
Single Loop
Major Axis
‘M’
M = 1.25 Si + 1.0
Double Loop
Eq. 6-7
2
⎛
⎞
8S i
− 2a ⎟⎟
3a⎜⎜ L +
3L
⎝
⎠
M = 1.0 +
8
Eq. 6-8
2
⎛ L⎞
2
where a = ⎜ ⎟ + Si
⎝2⎠
Distance ‘B’
B = 0.25 Si
Eq. 6-9
Minor Axis
‘D’
D = 0.4M
Eq. 6-11
B = 0.2 M
D = 2 M − 1.0
Eq. 6-10
Eq. 6-12
Where:
pc = wind load per unit length on iced conductor in lbs/ft.
Assume a 2 psf wind.
wc = weight per unit length of conductor plus 1/2 in. of radial ice,
lbs/ft
L = span length in feet.
M = major axis of Lissajous ellipses in feet.
Si = final sag of conductor with 1/2 in. of radial ice,
no wind, at 32°F, in feet.
D = minor axis of Lissajous ellipses in feet.
B,Ø = as defined in figure above
Bulletin 1724E-200
Page 6-9
FIGURE 6-4: SINGLE LOOP GALLOPING ANALYSIS
6.6 Clearance Between Conductors in a Crossarm to Vertical Construction Span:
Conductor contacts in spans changing from crossarm to vertical type construction may be
reduced by proper phase arrangement and by limiting span lengths. Limiting span lengths well
below the average span lengths is particularly important in areas where ice and sleet conditions
can be expected to occur. See Figure 6-5.
1
1
2
2
3
3
1
2
3
1
3
2
FIGURE 6-5: PROPER PHASE ARRANGEMENTS FOR CROSSARM
TO VERTICAL CONSTRUCTION
Bulletin 1724E-200
Page 6-10
Blank Page
Bulletin 1724E-200
Page 7-1
7. INSULATOR SWING AND CLEARANCES OF CONDUCTORS FROM
SUPPORTING STRUCTURES
7.1 Introduction: Suspension insulator strings supporting transmission conductors, either at
tangent or angle structures, are usually free to swing about their points of support. Therefore, it
is necessary to ensure that when the insulators do swing, clearances are maintained to structures
and guy wires. The amount of swing varies with such factors as: conductor tension,
temperature, wind velocity, insulator weight, ratio of weight span to wind span, and line angle.
The force due to line angle will cause suspension strings to swing in the direction of the line
angle of the structure. Wind blowing on the conductor span will exert a force in the direction of
the wind. These two forces may act either in the same direction or in opposite, the algebraic sum
thereby determining the net swing direction. Line angle forces and wind forces also interact with
the vertical forces of the conductor weight and insulator string weight. The vector sum of these
forces determines the net angle from the vertical axis to which the insulator string will swing.
This net insulator swing angle should be calculated for several key weather conditions so that
corresponding phase-to-ground clearances may be checked on a particular pole-top arrangement.
The purpose of this chapter is to explain how insulator swing application guides called swing
charts are prepared. Chapter 10 explains how these charts are used in laying out a line.
7.2 Clearances and Their Application: Table 7-1 provides information on three sets of
clearances that can ensure proper separation between conductors and structures or guys under
various weather conditions. Figure 7-1 illustrates the various situations in which the clearances
are to be applied.
7.2.1 No-Wind Clearance: The no wind clearance provides a balanced insulation system in
which the insulating value of the air gap is approximately the same as that of the insulator string
for a tangent structure. (See Table 8-1 for insulation levels. Note that tangent structures do not
include the extra insulators used with angle structures).
Conditions at which no-wind clearances are to be maintained follow:
•
Wind: Assume no wind.
•
Temperature: Assume a temperature of 60°F. See Figure 7-1 for conductor condition.
The engineer may also want to evaluate clearances at cold conditions (such as -20°F
initial sag) and hot conditions (such as 167°F final sag).
7.2.2 Moderate Wind Clearance: This clearance is the minimum clearance that should be
maintained under conditions that are expected to occur occasionally. A typical condition may be
the wind that reoccurs no less than once every two years (probability of occurrence no more than
50 percent). Clearance values for moderate wind clearance conditions will have a lower
flashover value than clearance values for the no-wind condition. These lower clearance values
are acceptable because under moderate wind conditions, the specified clearance will be sufficient
to withstand most of the severe voltage stress situations for wind conditions that are not expected
to occur often.
There are different clearance requirements to the structure than to anchor guys. See Table 7-1,
moderate wind, for differences. Also, note that Table 7-1 requires that additional clearance must
be provided if the altitude is above 3300 feet.
Conditions at which moderate wind clearances are to be maintained follow:
Bulletin 1724E-200
Page 7-2
•
Wind: Assume a wind of at least 6 psf blowing in the direction shown in Figure 7-1.
Higher wind pressures can be used if judgment and experience deem them to be
necessary. However, the use of excessively high wind values could result in a design that
is overly restrictive and costly. It is recommended that wind pressure values of no higher
than 9 psf (60 mph) be used for the moderate wind clearance design unless special
circumstances exist.
•
Temperature: Temperature conditions under which the clearances are to be maintained
depend upon the type of structure. A temperature of no more than 32°F should be used
for tangent and small angle structures where the insulator string is suspended from a
crossarm. A lower temperature value should be used where such a temperature can be
reasonably expected to occur in conjunction with the wind value assumed. It should be
borne in mind, however, the insulator swing will increase at lower temperatures because
conductor tensions increase. Therefore, in choosing a temperature lower than 32°F, one
should weigh the increase in conservatism of line design against the increase or decrease
in line cost. NESC Rule235 requires a temperature no higher than 60°F final tension.
A temperature of 60°F should be used for angle structures where the force due to change
in direction of the conductor holds the insulator string away from the structure. Even if
the maximum conductor temperature is significantly greater than 60°F, a higher
temperature need not be used as an assumed wind value of 40 mph (6 psf)) has quite a
cooling effect.
Assume final sag conditions for 60°F temperature and initial sag conditions for 32°F.
7.2.3 High Wind Clearance: This is the minimum clearance that should be maintained under
high wind conditions that are expected to occur very rarely. The clearances provide enough of
an air gap to withstand a 60 Hz flashover but not much more. Choice of such values is based on
the philosophy that under very rare high wind conditions, the line should not flashover due to the
60 Hz voltage.
Conditions under which high wind clearances are to be maintained are:
•
Wind: The minimum assumed wind value should be at least the 10-year mean recurrence
interval wind blowing in the direction shown in Figure 7-1. More wind may be assumed
if deemed appropriate.
•
Temperature: The temperature assumed should be that temperature at which the wind is
expected to occur. The conductor should be assumed to be at final tension conditions.
To determine the velocity of the wind for a 10 year return period, the following factors should be
applied to the 50 year peak gust wind speed (See Figures 11-2a, b, c and d in Chapter 11).
V = 85 to100 mph,
Continental U.S.
Alaska
V > 100 mph
(hurricane)
0.84
0.87
0.74
Bulletin 1724E-200
Page 7-3
FIGURE 7-1: ILLUSTRATION OF STRUCTURE INSULATOR SWING ANGLE LIMITS
AND CONDITIONS* UNDER WHICH THEY APPLY (EXCLUDES
BACKSWING)
TANGENT AND
SMALL ANGLE
STRUCTURES
No Wind
Insulator Swing
Moderate Wind
Insulator Swing
High Wind
Insulator Swing
wind
O2
O1
Conditions* at which
clearances are to be
a
maintained
• Line angle
Force due
to line angle (if any)
• Wind force
0
•
Temperature
•
Conductor tension
wind
O3
c
b
Force due
to line angle (if any)
6 psf minimum
60ºF
32ºF or lower
Final tension
Initial tension
MEDIUM AND
LARGE ANGLE
STRUCTURES
Force due
to line angle (if any)
10 year mean wind,
recommended value
Temp. at which wind
value is expected
Final tension
wind
wind
Ø1
a
Conditions* at which
clearances are to be
maintained
• Line angle
Force due
to line angle
• Wind force
0
•
Temperature
•
Conductor tension
b
Ø2
Force due
to line angle
6 psf minimum
60ºF
60ºF or lower
Final tension
Final tension
a = No wind clearance b = Moderate wind clearance
*See text for full explanation of conditions.
c
Ø3
Force due
to line angle
10 year mean wind,
min.recommended
value
Temp. at which wind
value is expected
Final tension
c = High wind clearance
Bulletin 1724E-200
Page 7-4
TABLE 7-1
RECOMMENDED MINIMUM CLEARANCES IN INCHES AT
CONDUCTOR TO SURFACE OF STRUCTURE OR GUY WIRES
Nominal voltage, Phase to Phase,
kV
34.5
46
69
115
138
161
230
Standard Number of 5-3/4”x10”
Insulators on Tangent Structures
3
3
4
7
8
10
12
34.5
46
72.5
120.8
144.9
169.1
241.5
19.9
26.6
41.8
69.7
83.7
97.6
139.4
Max. Operating Voltage, Phase to
Phase, kV
Max. Operating Voltage, Phase to
Ground, kV
Clearance in inches
No Wind Clearance (Not NESC)
Min. clearance to structure or guy at no
wind in inches Notes A, B
19
19
25
42
48
60
71
9
11
16
26
30
35
50
11
13
18
28
32
37
52
13
16
22
34
40
46
64
3
3
5
10
12
14
20
Moderate Wind Clearance
(NESC Table 235-6)
Min. clear. to structure at 6 psf of
wind in inches. Notes C, D
Min. clear. to jointly used structures
and a 6 psf of wind in inches.
Notes C, D
Min. clearance to anchor guys at 6 psf
in inches Notes C, D
High Wind Clearance
(Not NESC)
Min. clearance to structure or guy at
high wind in inches
Notes:
(A) If insulators in excess of the standard number for tangent structures are used, the no wind clearance value
shown should be increased by 6 in. for each additional bell. If the excess insulators are needed for
contamination purposes, this additional clearance is not necessary.
(B) For post insulators, the no wind clearance to structure or guy is the length of the post insulator.
(C) A higher wind may be assumed if deemed necessary.
(D) The following values should be added as appropriate where the altitude exceeds 3300 feet
Additional inches of clearance per 1000 feet of altitude above 3300 feet
Voltage, kV
Clearance to structure
Clearance to anchor guy
34.5
0
0
46
0
0
69
.14
.17
115
.43
.54
138
.57
.72
161
.72
.90
230
1.15
1.44
Bulletin 1724E-200
Page 7-5
7.2.4 Example of Clearance Calculations: The following examples demonstrate the
derivation of the minimum clearance to anchor guys at 6 psf.
To determine the minimum clearance of a 115 kV line to an anchor guy (Table 7-1) at 6 psf, the
clearance is based on NESC Table 235-6 and NESC Rule 235E.
NESC Clear. in any direction.
NESC Clear. in any direction.
= NESC Basic Clearance(Table 235-6) + .25(kVL-L – 50)
= 16 inches + .25(120.8-50) inches
= 16 inches + 17.7 inches
= 33.7 inches ( clearance in Table 7-1is 34 inches)
7.3 Backswing: Insulator swing considerations are illustrated in Figure 7-1. For angle
structures where the insulator string is attached to the crossarm, the most severe condition is
usually where the force of the wind and the force of the line angle are acting in the same
direction. However, for small angle structures, it is possible that the limiting swing condition
may be when the wind force is in a direction opposite of that due to the force of the line angle.
This situation is called backswing, as it is a swing in a direction opposite of that in which the
insulator is pulled by the line angle force. Figure 7-2 illustrates backswing.
When calculating backswing, it is necessary to assume those conditions that would tend to make
the swing worse, which usually is low conductor tension or small line angles. It is recommended
that the temperature conditions for large angle structures in Figure 7-1 be used, as they result in
lower conductor tensions.
direction of line angle
back forward
swing swing
normal position of
insulators (no wind,
no ice)
FIGURE 7-2: FORWARD AND BACKWARD SWING ANGLES
7.4 Structure Insulator Swing Values: Table 7-2 provides the allowable insulator swing angle
values for some of the most often used standard agency tangent structures. These values
represent the maximum angle from the vertical that an insulator string of the indicated number of
standard bells may swing in toward the structure without violating the clearance category
recommendation indicated at the top of each column. For tangent structures, the most restrictive
angle for the particular clearance category for the entire structure is given. Thus, for
an asymmetrical tangent structure (TS-1 for instance) where the allowable swing angle depends
upon whether the insulators are assumed to be displaced to the right or left, the use of the most
restrictive value means that the orientation of the structures with respect to the line angle need
not be considered. For certain angle structures the insulator string has to be swung away from
the structure in order to maintain the necessary clearance. These situations usually occur for
large angle structures where the insulator string is attached directly to the pole or to a bracket on
the pole and where the force due to the change in direction of the conductors is relied upon to
hold the conductors away from the structure.
Bulletin 1724E-200
Page 7-6
Structure and
Voltage
69 kV
TS-1, TS-1X
TSZ-1, TSZ-2
TH-1,TH-1G
115 kV – TH-1A
161 kV – TH-10
230 kV – TH-230
TABLE 7-2
INSULATOR SWING ANGLE VALUES IN DEGREES
(For insulator string with ball hooks)
(For insulator swing of other structures, see Appendix J)
Number of
No Wind
Moderate Wind
Insulators
Swing Angle
Swing Angle
4
4
4
7
10
12
20.0
41.7
35.6
28.3
16.4
16.5
High Wind
Swing Angle
38.5
61.2
61.2
58.7
53.2
47.5
74.0
82.6
85.6
80.8
77.7
74.8
7.5 Line Design and Structure Clearances: Insulator swing has a key effect on acceptable
horizontal to vertical span ratios. Under a given set of wind and temperature conditions, an
insulator string on a structure will swing at an angle toward the structure a given number of
degrees. The angle of this swing is related to a ratio of horizontal to vertical forces on the
insulator string. A relationship between the horizontal span, the vertical span, and if applicable,
the line angle can then be developed for the structure, conductor, and weather. Horizontal and
vertical spans are explained in Figure 7-4.
The acceptable limits of horizontal to vertical span ratios are plotted on a chart called an
insulator swing chart. Such a chart can be easily used for checking or plotting out plan and
profile sheets. Figures 7-3 and 7-5 show simplified insulator swing charts for the moderate wind
condition only. There is one significant difference between the chart for tangent structures, and
the chart for angle (running corner) structures. In Figure 7-3 for a typical tangent structure, the
greater the vertical span for a fixed horizontal span the less swing occurs. The reverse is true for
chart of Figure 7-5 for a typical angle structure. This occurs because the swing chart in Figure 75 is for a large angle structure where the force of the line angle is used to pull the insulator string
away from the structure. As such, the less vertical force there is from the weight span, the
greater the horizontal span can be.
600
32°
TI
I NI
AL
500
400
600
700
E
RV
CU
ING
SW
IOR VE
AT SSI
UL C E
INS EX
VERTICAL SPAN
700
ING
SW
IOR LE
AT AB
UL OW
INS ALL
800
INSULATOR SWING CHART
TH-230 STRUCTURE
9# WIND13 INSULATORS/STRING
800
900
1000
HORIZONTAL SPAN
FIGURE 7-3: TYPICAL INSULATOR SWING CHART FOR A TH-230 TANGENT
Bulletin 1724E-200
Page 7-7
VS
VS 1
VS 2
#2
L1
#1
L2
#3
1/2L1
1/2L2
HS
L = span,
L1 - span from structure 1 to 2
L2 = span from structure 2 to 3
HS = horizontal span
VS = vertical span
Span
Span is the horizontal distance from one structure to an adjacent structure along the line.
Vertical Span
The vertical span (sometimes called the weight span) is the horizontal distance between the
lowest points on the sag curve of two adjacent spans. The maximum sag point of a span may
actually fall outside the span. The vertical span length times the weight of the loaded conductor
per foot will yield the vertical force per conductor bearing down upon the structure and
insulators
Horizontal Span
The horizontal span (sometimes called the wind span) is the horizontal distance between the
mid-span points of adjacent spans. Thus, twice the horizontal span is equal to the sum of the
adjacent spans. The horizontal span length times the wind force per foot on the conductor will
yield the total horizontal force per conductor on the insulators and structure.
FIGURE 7-4: HORIZONTAL AND VERTICAL SPANS
Bulletin 1724E-200
Page 7-8
The ‘no wind’ insulator swing criteria will not be a limiting condition on tangent structures as
long as the line direction does not change and create an angle in the line. If an angle is turned, it
is possible that the ‘no wind’ condition might control. The other two criteria may control under
any circumstance. However, the high wind criteria will be significant in those areas where
unusually high winds can be expected. Thus, all three conditions specified need to be checked.
100
LIN
EA
NG
LE
0°
( 12
300
16°
15°
14°
1 3°
400
18°
17°
VERTICAL SPAN
12°
CU
RV
E)
11°
200
INSULATOR SWING CHART
TH-233 STRUCTURE
9# WIND
16 INSULATORS/STRING
10°
AL SW I
LO NG
WA
BL
E
S
EX WIN
CE G
SS
IVE
500
600
500
600
700
800
HORIZONTAL SPAN
900
1000
FIGURE 7-5: TYPICAL INSULATOR SWING CHART FOR A TH-233 MEDIUM ANGLE
STRUCTURE (Moderate Wind Swing Condition, 9 psf assumed instead of
minimum NESC 6 psf)
7.6 Formulas for Insulator Swing: The formulas in equations 7-1 and 7-2, can be used to
determine the angle of insulator swing that will occur under a given set of conditions for either
tangent or angle structures.
tan φ =
pc =
(2)(T )(sin θ 2) + (HS )( pc )
(VS )(wc ) + (1 / 2)(Wi )
(d c )(F )
12
Eq. 7-1
Eq. 7-2
Bulletin 1724E-200
Page 7-9
where:
Ø = angle with the vertical through which the insulator
θ =
T =
HS =
VS =
pc =
wc =
Wi =
dc =
F =
string swings, in degrees
line angle, in degrees
conductor tension, pounds
horizontal span, feet
vertical span, feet
wind load per unit length of bare conductor in pounds
per foot
weight per unit length of bare conductor in pounds per
foot
weight of insulator string (wind pressure neglected), in
pounds. (See Appendix C for insulator string weights).
conductor diameter2in inches
wind force in lbs/ft
In order for equation 7-1 to be used properly, the following sign conventions are to be followed:
Condition
•
Wind - Blowing insulator toward structure
•
“(2)(T)(sin θ/2)” term (force on insulator due to line angle):
+
Pulling insulator away from structure
+
-
Insulator swing angle
Angle measured from a vertical line through point of insulator
support in toward structure
+
Angle measured from a vertical line through point of insulator
support away from structure
-
Pulling insulator toward structure
•
Sign Assumed
7.7 Insulator Swing Charts: Insulator swing charts similar to those in Figures 7-4 and 7-5 can
be developed by using equation 7-3 and the maximum angle of insulator swing values as limited
by clearance to structure.
VS =
(2)(T )(sin θ 2) + (HS )( pc ) − Wi
(2)(wc )
(wc )(tan φ )
Eq. 7-3
The symbols and sign conditions are the same as those provided for equation 7-1. Equation 7-3
is derived from equation 7-1 and solving for VS.
7.8 Excessive Angles of Insulator Swing: If upon spotting a line, calculations shown a
structure will have excessive insulator swing, one or more of the measures outlined in
Section 10.4 of Chapter 10 of this bulletin may be required to alleviate the problem.
Bulletin 1724E-200
Page 7-10
7.9 Example: For the TH-10 tangent structure, develop the insulator swing chart. Assume that
it is desired to turn slight angles with the tangent structure and the insulator string assembly uses
the ball hook.
7.9.1 Given:
a. Voltage: 161 kV
Structure: TH-10
Conductor: 795 kcmil 26/7 ACSR
Insulation: Standard (10 bells)
b. NESC heavy loading district
High winds: 14 psf
Ruling Span: 800 ft.
c. Conductor Tensions
6 psf wind
0°F
6,244 lbs. initial tension
No wind
60°F
4,633 lbs. final tension
12.5 psf wind
32°F
10,400 lbs. final tension
7.9.2 Solution: Using the information on conductor sizes and weights, allowable swing angles,
insulator string weights from the appendices of this bulletin and using equation 7-3, the
following calculation tables and the swing chart in Figure 7-6 are created.
7.10 Example: On the plan and profile drawings, the engineering is checking insulator swing
for the TH-10 structure in example 7-9. For a certain TH-10 structure with no line angle, the
horizontal span is 800 feet. Determine the minimum vertical span.
7.10.1 Same Information as 7.9.1
7.10.2 Solution: From Figure 7-6, for a horizontal span of 800 feet, the vertical span must be
greater than 241 feet (see also tables for Figure 7-6). Many programs which are used to develop
plan-profile drawings will automatically check insulator swing or will use insulator swing as a
parameter in the spotting of structures.
0
200
400
VERTICAL
SPAN IN
FEET
600
800
1000
0
200
60°F Final
No Wind Insulator
Swing Limit
60°F Final
400
ine
2° L
Moderate Wind
Insulator Swing
Limit
HORIZONTAL SPAN IN FEET
800
1000
Acceptable
Unacceptable
le
Ang
0°F Initial
1200
High Wind Condition Does Not Control
ngle
ngle
i ne A
0° L
ine A
1° L
600
TH-10 161kV 800' Ruling Span
795 Kcmil 26/7 ACSR
6244 lbs. Tension At 0° Initial, 6 psf Wind
4633 lbs. Tension At 60° Final, No Wind
FIGURE 7-6: INSULATOR SWING CHART FOR EXAMPLE 7-9
1400
Bulletin 1724E-200
Page 7-11
Bulletin 1724E-200
Page 7-12
VS =
a)
b)
c)
d)
e)
FIGURE 7-6 INSULATOR SWING CHART FOR EXAMPLE 7-9 (continued)
Note: for the no wind case, vertical span is independent
(2)(T )(sin θ 2) + (HS )( pc ) − Wi
of horizontal span. It is only dependent upon line angle.
(wc )(tan φ )
(2)(wc )
θ
1°
2°
Ø = angle with the vertical through which insulator
string swings.
sin θ/2
.00872
.01745
(2)(T)(sin θ/2)
80.26
161.71
θ = line angle
(HS)(pc)
0
0
T = conductor tension
a+b
80.26
161.71
HS = horizontal span
(wc)(tan Ø)
.32
.32
VS = vertical span
(a + b)/c
251.13
502.25
pc = wind load on conductors
Wi/(2)(wc)
61.70
61.70
wc = weight of conductor/ft.
d – e = VS
189.43
440.55
Wi = weight of insulator string
θ
sin θ/2
a) (2)(T)(sin θ/2)
b) (HS)(pc)
a+b
c) (wc)(tan Ø)
d) (a + b)/c
e) Wi/(2)(wc)
d – e = VS
θ
sin θ/2
a) (2)(T)(sin θ/2)
b) (HS)(pc)
a+b
c) (wc)(tan Ø)
d) (a + b)/c
e) Wi/(2)(wc)
d – e = VS
Ø = 16.4°
Structure: TH-10________
Conductor: 795 26/7 ACSR
Voltage: 161 kV_______
Insulator Swing Condition:
Ø=
pc =
wc=
T=
Wi=
16.4°_______
0 lbs./ft____
1.0940 lbs./ft
4,633 lbs___
135 lbs
Ruling span 800___ft.
Loading district: Heavy
No of Insulators: 10___
No wind____________
(F=0 lbs at 60°F)
Conductor dia: 1.108 __
pc = (d)(F)
12
Bulletin 1724E-200
Page 7-13
FIGURE 7-6: INSULATOR SWING CHART FOR EXAMPLE 7-9 (continued)
(2)(T )(sin θ 2) + (HS )( pc ) − Wi
VS =
(wc )(tan φ )
(2)(wc )
θ = 0°
HS=200 HS=400 HS=800 HS=1000
Ø = angle with the vertical through which
insulator string swings.
0
sin θ/2
0
0
0
0
a) (2)(T)(sin θ/2)
0
0
0
θ = line angle
554.00
b) (HS)(pc)
110.80
221.60
443.20
T = conductor tension
554.00
a+b
110.80
221.60
443.20
HS = horizontal span
c) (wc)(tan Ø)
1.460
1.460
1.460
1.460
VS = vertical span
d) (a + b)/c
75.77
151.53
303.07
378.83
pc = wind load on conductors
e) Wi/(2)(wc)
61.70
61.70
61.70
61.70
wc = weight of conductor/ft.
d – e = VS
14.07
89.83
241.37
317.13
Wi = weight of insulator string
HS=200
HS=400
HS=800
HS=1000
.008727
1.08.98
110.80
219.78
1.460
150.29
61.70
88.59
.008727
108.98
221.60
330.58
1.460
226.05
61.70
164.35
.008727
108.98
443.20
552.18
1.460
377.59
61.70
315.89
.008727
108.98
554.00
662.98
1.460
453.35
61.70
391.65
θ = 2°
HS=200
HS=400
HS=800
HS=1000
Structure: TH-10________
Ruling span 800___ft.
sin θ/2
a) (2)(T)(sin θ/2)
b) (HS)(pc)
a+b
c) (wc)(tan Ø)
d) (a + b)/c
e) Wi/(2)(wc)
d – e = VS
.017452
217.95
110.80
328.75
1.460
224.80
61.70
163.10
.017452
217.95
221.60
439.55
1.460
300.57
61.70
238.87
.017452
217.95
443.20
661.15
1.460
452.10
61.70
390.40
.017452
217.95
554.00
771.95
1.460
527.87
61.70
466.17
Conductor: 795 26/7 ACSR
Voltage: 161 kV_______
Insulator Swing Condition:
Loading district: Heavy
No of Insulators: 10___
θ = 1°
a)
b)
c)
d)
e)
sin θ/2
(2)(T)(sin θ/2)
(HS)(pc)
a+b
(wc)(tan Ø)
(a + b)/c
Wi/(2)(wc)
d – e = VS
Ø = 53.2°
Ø=
pc =
wc=
T=
Wi=
53.2°_______
0.554 lbs./ft____
1.0940 lbs./ft
6,244 lbs___
135 lbs
Moderate wind______
(F=6 psf at 0°F)
Conductor dia: 1.108__
pc = (d)(F)
12
Bulletin 1724E-200
Page 7-14
FIGURE 7-6: INSULATOR SWING CHART FOR EXAMPLE 7-9 (continued)
(2)(T )(sin θ 2) + (HS )( pc ) − Wi
VS =
(wc )(tan φ )
(2)(wc )
θ = 0°
HS=200 HS=400 HS=800 HS=1000
Ø = angle with the vertical through which
insulator string swings.
0
sin θ/2
0
0
0
0
a) (2)(T)(sin θ/2)
0
0
0
θ = line angle
1154.00
b) (HS)(pc)
230.80
461.60
923.20
T = conductor tension
1154.00
a+b
230.80
461.60
923.20
HS = horizontal span
c) (wc)(tan Ø)
5.02
5.02
5.02
5.02
VS = vertical span
d) (a + b)/c
46.00
92.00
183.99
229.99
pc = wind load on conductors
e) Wi/(2)(wc)
61.70
61.70
61.70
61.70
wc = weight of conductor/ft.
d – e = VS
-15.70
30.30
122.29
168.29
Wi = weight of insulator string
θ = 1°
a)
b)
c)
d)
e)
sin θ/2
(2)(T)(sin θ/2)
(HS)(pc)
a+b
(wc)(tan Ø)
(a + b)/c
Wi/(2)(wc)
d – e = VS
θ = 2°
sin θ/2
a) (2)(T)(sin θ/2)
b) (HS)(pc)
a+b
c) (wc)(tan Ø)
d) (a + b)/c
e) Wi/(2)(wc)
d – e = VS
HS=200 HS=400 HS=800 HS=1000
.008727
181.51
230.80
412.31
5.02
82.17
61.70
20.47
.008727
181.51
461.60
643.11
5.02
128.17
61.70
66.47
.008727
181.51
923.20
1104.71
5.02
220.17
61.70
158.47
.008727
181.51
1154.00
1335.51
5.02
266.17
61.70
204.47
Ø = 77.7°
HS=200 HS=400 HS=800 HS=1000
Structure: TH-10________
Ruling span 800___ft.
.017452
363.01
230.80
593.81
5.02
118.35
61.70
56.65
Conductor: 795 26/7 ACSR
Voltage: 161 kV_______
Insulator Swing Condition:
Loading district: Heavy
No of Insulators: 10___
.017452
363.01
461.60
824.61
5.02
164.35
61.70
102.65
.017452
363.01
923.01
1286.21
5.02
256.34
61.70
194.64
.017452
363.01
1154.00
1517.01
5.02
302.34
61.70
240.64
Ø=
pc =
wc=
T=
Wi=
77.7°_______
1.154 lbs./ft____
1.0940 lbs./ft
10,400 lbs___
135 lbs
High wind__________
(F=12.5 psf at 32°F)
Conductor dia: 1.108__
pc = (d)(F)
12
Bulletin 1724E-200
Page 8-1
8. INSULATION AND INSULATORS
8.1 Insulator Types: Insulation is defined as the separation between conducting surfaces by
means of a non-conducting (dielectric) material that would economically offer a high resistance
to current. Insulators may be fabricated from porcelain, toughened glass, fiberglass rods and
sheds of polymer or silicone construction.
The main types of insulators used on transmission lines are suspension insulators using bells or
polymer strings, pin insulators, and vertical and horizontal posts. Several suspension bell units
are connected in a string to achieve the insulation level desired. The polymer suspension is one
unit with an insulation level determined largely by its length. Horizontal post units are made of
porcelain or polymer and are single units with a desired rating. See Figures 8-1 and 8-2.
FIGURE 8-1: A STANDARD PORCELAIN SUSPENSION BELL
FIGURE 8-2: A TYPICAL PORCELAIN HORIZONTAL POST INSULATOR
8.2 Insulator Materials
8.2.1 Porcelain insulators have been the industry standard as specified by ANSI requirements
for electrical and mechanical capacities. Although porcelain insulators have a history of long,
useful lives, the strings are heavy and subject to breakage from gunshots. The connecting
portions of porcelain insulators are metal components which are embedded in high strength
cement as specified by ANSI standards. Strength ratings for porcelain insulators are verified by
proof loading requirements of each manufactured unit, and stamped accordingly.
8.2.2 Toughened glass insulators are similar in construction to the porcelain insulator. They
are heavy, and are also subject to vandalism exposure. ANSI fabrication standards are also
available for toughened glass.
8.2.3 Non-ceramic (polymer) insulators typically consist of a fiberglass rod that is sheathed
with weathershed ‘bells’ made of either rubber-based or silicone-based polymers. The
connecting ends are typically compressed metal fittings. ANSI standards have been developed
for suspension units.
Bulletin 1724E-200
Page 8-2
Non-ceramic assemblies offer varieties of end fittings, lengths and strength capacities. They are
much lighter in weight than their porcelain and glass counterparts. Polymers may be subject to
damage by corona voltage, ultraviolet radiation, or physical deterioration which may not be
apparent. Deterioration of a fiberglass rod may result in a reduction in strength of the unit.
8.3 Insulation Levels Using Suspension Bells: Table 8-1 provides suggested insulation levels.
However, circumstances such as high altitude, contamination, high isokeraunic levels, or high
footing resistance, may warrant additional insulation. If wood structures with steel arms, steel
structures, or concrete pole structures are used in areas where there is a high isokeraunic level,
consideration should be given to using one additional suspension bell beyond the standard
agency recommended insulation levels.
8.3.1 Tangent and Small Angles: Table 8-1 indicates the recommended number of
5-3/4 x 10 in. suspension insulators to be used per phase on wood tangent and small angle
structures. Also given are the electrical characteristics of the insulator strings.
8.3.2 Angles: For angle structures where the conductor tension is depended upon to pull the
insulator string away from the structure, one more insulator bell should be added to the number
of bells recommended for tangent structures. The sole exception to this is 34.5 kV where no
additional bells are needed.
TABLE 8-1
RECOMMENDED ISULATION LEVELS*AT SEA LEVEL
(SUSPENSION AT TANGENT AND SMALL ANGLE STRUCTURES)
Flashover Characteristics in kV
Nominal L-L
Voltage in kV
No. of
5-3/4x10”
Bells
60 Hz
Low Freq
Dry*
60 Hz
Low Freq
Wet
34.5
46
69
115
138
161
230
3
3
4
7
8
10
12
215
215
270
435
485
590
690
130
130
170
295
335
415
490
Impulse
Positive Negative
355
355
440
695
780
945
1105
340
340
415
670
760
930
1105
Total Leakage
Distance
inches
34.5
34.5
46
80.5
92
115
138
*See NESC Rule 273, Table 273-1 for minimum insulation level requirements
8.3.3 Deadends: In situations where the insulator string is in line with the conductor, the
number of bells should be two more than is used for tangent structures. These situations occur at
large angles, and tangent deadends where the conductor is deadended onto an insulator string.
The sole exception to this is 34.5 kV where one additional bell is used.
8.4 Insulation Levels Using Post Insulators: Agency recommended electrical characteristics
for horizontal post insulators are given in Table 8-2.
Bulletin 1724E-200
Page 8-3
TABLE 8-2
RECOMMENDED INSULATION LEVELS AT SEA LEVEL
(POSTS AT TANGENT AND SMALL ANGLE STRUCTURES)
Flashover Characteristics in kV
Nominal L-L
Voltage in kV
60 Hz
Low Freq
Dry
60 Hz
Low Freq
Wet
34.5
46
69
115
138
125
150
200
380
430
115
135
180
330
390
Impulse
Positive Negative
210
255
330
610
690
Total Leakage
Distance
inches
29
40
53
100
110
260
344
425
780
870
8.5 Electrical Characteristics of Insulators: Because low frequency dry flashover ratings can
be tested easily and accurately, these ratings are generally the most common flashover values
referred to when comparing insulators. However, flashover (60 Hz) of an insulator in service
almost never occurs under normal dry operating conditions, so these ratings are probably the
least significant of insulator electrical characteristics. When comparing different types of
insulators (e.g., post vs. suspension) characteristics such as impulse and wet flashover do not
necessarily follow the same pattern as the low frequency dry flashover ratings. For these
reasons, Tables 8-1 and 8-2 are developed and provide both impulse and wet flashover values.
For voltages up to 230 kV the most severe stress on the insulation is usually caused by lightning,
and the most important flashover characteristic is the impulse flashover values.
8.6 High Altitude Considerations
8.6.1 General: As altitude increases, the insulation value of air decreases and an insulator at a
high elevation will flash over at a lower voltage than the same insulator at sea level. Figure 8-3
gives the derating factors for insulator flashover values as a function of altitude. These derating
factors apply to both low frequency flashover values and impulse flashover values.
FIGURE 8-3: INSULATION DERATING FACTOR vs. ALTITUDE
IN 1,000's OF FEET (230 kV and below)
Multiply Derating Factor by Insulator
Flashover Values at Sea Level to Get
Flashover Values at Altitude desired.
Curve is a plot of the equation:
9
8
7
F = (17.93B)/(460+T)
Where T = 60° F
B is standard
atmospheric
pressure at
various altitudes
in inches of Hg.
ALTITUDE IN 1000'S OF FEET
6
5
4
3
2
1
0
0.08
0.72
0.75
0.80
0.84
0.88
INSULATION DERATING FACTOR (F)
0.92
0.96
1.00
Bulletin 1724E-200
Page 8-4
In addition to increasing the number of insulators for high altitude, it is also necessary to
increase the structure air gap clearances. This could result in a decreased allowable insulator
swing angle or a longer crossarm (see Chapter 7 for details).
8.6.2 Example of Insulation Needed at High Altitudes: A line is located at 6000 feet
elevation. The derating factor (from Figure 8-3) is .827. At 138 kV, using the sea-level
requirement for low frequency dry flashover of 435 kV from Table 8-1, the line would require
526 kV (435/.827) at 6000 feet. A 10 bell string should be used instead of 7 bells. The
clearance to structure and clearance to guy wire should be increased (see Table 7-1 for
guidance).
8.6.3 Insulation for Lines with Relatively Small Changes in Altitude: When the insulation
derating factor for the line altitude is at a value less than approximately 90 percent of the
insulation value at sea level (see Figure 8-3), then additional insulation should be added to bring
the insulation level up to at least 90 percent of the sea level value.
8.6.4 Insulation for Lines with Significant Elevation Changes but Less than 5000 Feet: If
the elevation change in a line from its low point to its highest point is less than 5000 feet, it is
recommended that insulation for the entire length of the line be based on the weighted average
altitude of the line. This can be achieved by applying the procedure given in paragraph 8.6.2 to
that weighted average altitude.
8.6.5 Insulation for Line with Elevation Changes Greater than 5000 Feet: Where the
elevation change is greater than 5000 feet, the following two steps should be taken:
a. The entire line insulation should be upgraded for the minimum altitude of the line using
the procedure in paragraph 8.6.2 above.
b. Additional insulation should be added in sections of line where it is needed. This need
arises where the altitude of the line increases to the point where the insulation value is less
than approximately 90 percent of the insulation value at the minimum line altitude. This
means there may be different numbers of insulator bells at different points along the same
line.
8.6.6 Example of Additional Insulation for High Altitudes and Line Elevation Changes
Less than 5000 feet: A 161 kV line is to be built in an area where altitude ranges from 5430 ft.
to 7580 ft. Determine how much additional insulation, if any, is necessary.
Solution: The elevation change for the line from its lowest point to its highest point is less than
5000 ft. Therefore, the insulation should be based on the weighted average altitude. Since we
do not know the distribution of the line at the various altitudes, we will assume a uniform
distribution. Thus:
Average altitude =
5430 + 7580
2
= 6505 ft.
From Figure 8-3 the derating factor for an average altitude of 6505 ft is 0.81. Since paragraph
8.6.2 indicates that additional insulation is needed if the derating factor is less than 0.90,
additional insulation will be needed.
According to paragraph 8.6.5, the insulation value should be brought up to approximately
90 percent of the sea level value, which for 161 kV is:
Bulletin 1724E-200
Page 8-5
(0.9)(590) kV) = 531 kV
(590 kV is the low frequency dry flashover value of 10 bells at sea level).
The 531 kV requirement for low frequency dry flashover at sea level needs to be increased to
account for the higher elevation. Applying the derating factor to the 531 kV, the low frequency
dry flashover value of the string needs to be:
531/.81 = 655 kV
From Appendix C, the low frequency dry flashover of 11 bells is 640 kV. For 12 bells it is
690 kV. Therefore, the addition of one extra bell will not quite bring the insulation level up to
the 90 percent of sea level. The above calculations seem to indicate the need to add two extra
bells. However, some judgment should be exercised as to whether the second additional bell is
used. Even though one bell extra does not quite provide enough additional insulation, it comes
close. If the expected frequency and severity of lightning storms is not particularly high, one
extra bell might be sufficient. Depending on experience and judgement, at least one and
possibly two extra bells should be used.
8.7 Lightning Considerations
8.7.1 General: Transmission lines are subjected to three types of voltage stress that may cause
flashover of the insulation: power frequency voltage, switching surges and lightning surges.
Flashovers due to power frequency voltages are primarily a problem in contaminated conditions
and are discussed in section 8.8. Of the remaining two causes of flashovers, lightning is the
more severe for lines of 230 kV and below.
8.7.2 Lightning Flashover Mechanism: When lightning strikes a transmission line, it may hit
either the overhead ground wire or a phase conductor. If a phase conductor is hit, there will
almost certainly be a flashover of the insulation. To minimize this near certainty of a flashover,
an overhead ground wire is used to intercept the lightning strokes. To reduce the possibility of a
shielding failure, the shielding angle should be kept at 30° or less. (The shielding angle is the
angle measured from the vertical between the OHGW and the phase conductors, as shown in
Figure 8-4). On H-frame structures where two overhead ground wires are used, the center phase
may be considered to be properly shielded even if the shielding angle to it is greater than 30°.
For structures whose height is in excess of 92 feet, shielding angles of less than 30° as indicated
in Table 8-3, should be used. Where there is an unusually high exposure to lightning, such as at
river crossings, an even smaller shielding angle may be warranted.
TABLE 8-3
REDUCED SHIELDING ANGLE VALUES
Structure Height,
feet
Recommended
Shielding Angle,
degrees
92
99
116
30
26
21
Bulletin 1724E-200
Page 8-6
If lightning strikes an overhead ground wire, a traveling current wave will be set up which will
induce a traveling voltage wave. This voltage wave will generally increase in magnitude as it
travels down the wire, until it reaches a structure where the reflection of the traveling wave from
the ground prevents the voltage from further increasing. (The overhead ground wire is grounded
at every structure). If the traveling voltage wave at the structure is sufficiently high, a "back
flashover" across the insulation from the structure ground wire or from the overhead ground wire
to the phase conductor will occur. The factors that determine if a back flashover will occur are:
the amount of insulation, the footing resistance (the higher the footing resistance, the higher the
voltage rise at the structure) and the span length.
Cross
connection
Overhead
ground wire
Shield
angle
Pole
ground
wires
FIGURE 8-4: SHIELDING ANGLE, POLE AND
OVERHEAD GROUND WIRES
8.7.3 Designing for Lightning: An overhead ground wire should be used in all locations where
the isokeraunic level is above 20. The overhead ground wire should be grounded at every
structure by way of a structure ground wire. At H-frame structures, the OHGW's should each be
connected to a structure ground wire and to one another so that if one structure ground wire
breaks, both overhead ground wires will still be grounded.
In areas where the isokeraunic level is 20 or less, an overhead ground wire should still be used
for a distance of 1/2 mile from a substation. A map of isokeraunic levels is given in Appendix E.
8.7.4 Footing Resistance: For satisfactory lightning performance of a line, low footing
resistance is essential. Exactly what value of footing resistance is acceptable or unacceptable is
not a simple matter as it depends upon several variables. Previous successful experience with a
similar line in similar circumstances can be one guide. The following references may be useful
in determining what lightning outage rate a given footing resistance would yield.
(a) “Transmission Line Reference Book, 115 kV and Below,” Palo Alto, Calif., Electric
Power Research Institute, 1975.
(b) “Estimating Lightning Performance of Transmission Lines,” J. M. Clayton and F. S.
Young. IEEE Transactions on Power Apparatus and Systems, November 1964, pp. 11021110.
Bulletin 1724E-200
Page 8-7
A grounded structure has a good chance to withstand a lightning flashover provided that
conductor insulation and ground resistance have been properly analyzed and coordinated.
A lightning outage rate of 1 to 4 per 100 miles per year is acceptable with the lower number
more appropriate for lines in the 161 to 230 kV range.
Generally, experience has shown that the footing resistance of individual structures of the line
especially within 1/2 mile of the substation should be less than 25 ohms in high isokeraunic
areas.
When a line is being built, it is recommended that the footing resistance of the ground
connection be measured and recorded on a spot check basis. If footing resistance problems are
expected, more frequent measurements should be made and recorded. If experience indicates
that the lightning outage rate is not acceptable, these measurements readings can be useful when
taking remedial measures.
Footing resistance should not be measured immediately after a rain when the soil is moist. If the
footing resistance is higher than desired, additional driven rods may be used to reduce it. If the
earth's resistivity is very high, counterpoise rather than driven rods may be required. Reference
(b) this section gives guidance in the selection of counterpoise.
8.7.5 Lightning Arresters: In areas where structure grounding is difficult to achieve, or the
lightning performance of an existing transmission line needs to be improved, Metal Oxide
Varistor (MOV) line arresters can be installed. These arresters should be coordinated with the
substation station class arresters for proper performance. The engineer should determine the size
of the substation arresters and choose a slightly higher Maximum Continuous Over Voltage
(MCOV) rating on the transmission line to prevent the line arresters from taking all of the
flashover duty.
On a triangular three wire designs, adding an arrester to the top phase of every structure will
typically give some shield angle protection to the other phases. For best performance, the
arrester should be tied to a ground system with 10 ohms or less of resistance. If good grounding
is not available, the borrower should consider adding lightning arresters to all three phases.
Lightning arresters can also be installed on shielded lines to minimize back flashover where
good grounding is difficult. The engineer should design for phase-to-phase clearances between
the failed arrester, open position, and other phase wires since the arrester may drop near the other
energized phase position.
8.8 Contamination Considerations: The problem of contamination induced flashovers should
be considered if a line is to be built near a seacoast, an industrial district, or at other locales
where airborne contaminants may accumulate on insulators.
8.8.1 Contamination Flashover Mechanism: When a layer of contaminants on an insulator is
moistened by fog, dew, light rain or snow, it will become more conductive and the leakage
current along the surface of the insulator will greatly increase. Where the current density is the
greatest (for suspension insulators near the pin, and for post insulators at the points of least
diameter), heat caused by the increased leakage current will evaporate the moisture causing the
formation of a dry band. This band usually has an higher resistance than the adjacent moistened
area which means that the band will support almost all the voltage across it. This will result in
the breakdown of the air and the formation of an arc across the dry band. The arc will cause the
moisture film at the dry band edges to dry out, enlarging the dry band, eventually to the point
where the voltage across the band is just below the air breakdown value. If an increase in
precipitation occurs causing a lowering of contaminant resistance, a second breakdown can
occur. If conditions are right, a cycle of repeated and ever-increasing surges will be set up which
Bulletin 1724E-200
Page 8-8
will result in several discharges joining, elongating and bridging the entire insulator and
resulting in a power arc. See Figure 8-5 for a graphic description.
M O IS T U R E L A Y E R
FORM S ON
C O N D U C T IN G
M A T E R IA L
D RY A REA
(A )
(B )
IN IT IA L C O N D U C T IN G S T A T E
L E A K A G E C U R R E N T D R IE S O U T
M O IS T U R E N E A R P IN
ARC
D RY A REA
(C )
(D )
A R C B R ID G E S O V E R D R Y A R E A
H E A T IN G A N D E N L A R G IN G IT
E N L A R G E D D R Y A R E A H O L D S E N T IR E
U N IT V O L T A G E A N D A R C E X T IN G U IS H E S
C O N T A M IN A T IO N
L AYER
ARC
(E )
(F )
A R C R E S T R IK E S A S M O R E M O IS T U R E
A PP EA RS O N DR Y AR EA
A R C B R ID G E S E N T IR E
IN S U L A T O R
FIGURE 8-5: CONTAMINATION BREAKDOWN PROCESS
OF A SINGLE PORCELAIN INSULATOR UNIT
8.8.2 Effect of Insulator Orientation: The orientation of insulators has an effect on
contamination performance. Vertical strings of suspension insulators or vertical post insulators
do not wash well in the rain because of the sheltering effects of the insulator skirts.
Contaminants will tend to remain on the underside of the insulator which is not immune from the
moistening effects of fog or wind blown rain and snow. Horizontally oriented suspension
insulators and post insulators have their undersides more thoroughly washed by the rain and
therefore tend to fare better than vertical insulators in contaminated areas. Another advantage of
insulators in nonvertical positions is that any ionized gases caused by arcing will not contribute
to setting up conditions where an arc could jump from one bell to another or along the skirts of a
vertical post.
Bulletin 1724E-200
Page 8-9
8.8.3 Designing for Adverse Contamination Conditions: There are several means available
for improving line insulation performance in a contaminated atmosphere.
One way to compensate for contaminated conditions is to increase the leakage distance of the
insulation. The leakage distance is the distance along the surface of the insulators from the top
of the string (or post) to the energized hardware, not including any metal such as insulator caps
and pins.
Table 8-4 gives recommended leakage distances for various levels of contamination. The
increased leakage distance can be obtained by adding additional standard insulator bells (using a
longer post insulator) or by using fog insulators, which have more leakage distance for the same
overall insulator length. The additional leakage distance on fog insulators is obtained by having
more and/or deeper skirts on the underside of the insulator bell. In addition to the leakage
distance, the shape of the insulator has an effect on contamination performance, especially when
fog units are being used.
Research into the performance of existing lines with similar contamination should play an
important part in the final determination of insulating for atmospheric contamination.
An alternative to increasing the total leakage distance of the insulator string is to use a resistance
graded insulators. These insulators have a glaze that permits a small but steady leakage current
to flow over their surface. This leakage current gives the insulator much better contamination
performance without having to increase leakage distance. The base of a resistance graded
insulator should be solidly bonded to the structure ground wire to permit the leakage current to
flow easily to the ground. To aid in determining whether to use this type of insulator, its
advantages and disadvantages are listed below.
Advantages and Disadvantages of Resistance Graded Insulators
Advantages
• No extra leakage distance required.
• Longer intervals between insulator
washings.
• No radio noise (due to a more uniform
voltage distribution across string).
Disadvantages
• Higher initial costs.
• Small but continuous power loss.
•
Not entirely successful in very heavily
contaminated areas.
Bulletin 1724E-200
Page 8-10
TABLE 8-4
SUGGESTED LEAKAGE DISTANCES FOR CONTAMINATED AREAS
Contaminate
Level
Environment
Areas without industries and with low
density of houses equipped with
heating plants. Areas with some
density of industries or houses but
subject to frequent winds and/or
rainfall. Areas not exposed to sea
winds.
Light
Areas with industries not producing
particularly polluting smoke and/or
areas with average density of houses
equipped with heating plants. Areas
with high density of houses and/or
rainfall. Areas exposed to winds from
the sea but not less than 10 miles from
the coast
Moderate
Areas with high density of industries
and suburbs of large cities with high
density of heating plants producing
pollution. Areas close to the sea or in
any case exposed to relatively strong
winds from the sea (within 10 miles of
the sea).
Heavy
Areas subjected to industrial smoke
producing particularly thick conductive
deposits. Areas with very strong and
polluting winds from the sea. Desert
areas, characterized by no rain for
long periods, exposed to strong winds
carrying sand and salt, and subjected
to regular condensation
*rms L-G is root mean square line to ground voltage
Equivalent Amount
NaCl
mg/cm2
Suggested Leakage
Distance rms L-G*
in/kV
0-.03
NA-1.0
.03-.06
1.0-1.25
.06-.1
1.5-1.75
.1-.25
2.0-2.5
Very Light
Washing of the insulators should not be used in place of properly designing for contamination
but rather should be used in addition to the other steps where it is felt to be necessary.
Insulator performance in a contaminated environment can be improved by coating the surface
with suitable silicone grease. The grease absorbs the contamination and repels water. It is
necessary, however, to remove and replace the grease at intervals determined by the degree of
contamination. As with washing, the use of grease should only be considered as a remedial step.
Resistance graded insulators should not be greased.
Bulletin 1724E-200
Page 8-11
8.9 Mechanical Considerations (Porcelain and Non-ceramic)
8.9.1 Suspension Insulators: Strength rating methods and nomenclature vary depending on the
insulator material.
For porcelain, ANSI C29.1 specifies Mechanical and Electrical (M&E) procedures. The M&E
value is determined by a combined mechanical and electrical test. The insulator has a voltage
(75 percent of its rated dry flashover) impressed across it while a mechanical load is gradually
applied to the insulator. For non-ceramics, most manufacturers conduct specified mechanical
loading (SML) procedures to determine a polymer insulator’s failure rating. These procedures
are similar to the M&E for porcelain, but no electrical test is applied.
ANSI C 29.2 defines standard mechanical ratings for porcelain as: 15,000 lbs., 25,000 lbs.,
36,000 lbs. and 50,000 lbs. ANSI C29.12 defines standard SML’s for non-ceramic transmission
insulators as: 20,000 lbs., 25,000 lbs., 36,000 lbs. and 40,000 lbs.
For recommended insulator loading limits, refer to Table 8-5. Under NESC district loading
conditions, suspension insulators should not be loaded to more than 40 percent of their standard
ANSI M&E rating for porcelain insulators or 40 percent of their ANSI SML for non-ceramics.
If a heavier loading than the NESC district loading can be expected to occur with reasonable
regularity, then the 40 percent loading limit should be maintained at the higher loading limit.
Under extreme ice or high wind (50-year mean recurrence interval wind conditions) the load on
the insulator should not exceed 65 percent of the M&E strength of the insulator for porcelain and
50 percent of the M&E strength for non-ceramics.
Generally, porcelain insulators with a 15,000 pound M&E rating will be satisfactory for tangent
structures. However, stronger insulators may be needed on long spans with large conductors and
at deadends and angles where the insulators carry the resultant conductor tension.
TABLE 8-5
SUMMARY OF RECOMMENDED INSULATOR LOADING LIMITS
Insulator Type
Suspension
Horizontal Post
Cantilever
Tension, Compression
Vertical Post (Porcelain)
Vertical Pin Insulator
(Porcelain, Mounted on
the Crossarm)
NESC District Loading
Extreme Loading
Non-ceramic
Porcelain
40%
(% of ANSI standard
SML or M&E strength)
50%
(% of ANSI standard
SML strength)
65%
(% of ANSI standard
M&E strength)
40%
50%
(% of appropriate rated
ultimate strength value)
750 lbs.
50%
50%
(% of appropriate rated
ultimate strength value)
65%
65%
(% of appropriate rated
ultimate strength value)
-----
500 lbs.
-----
Bulletin 1724E-200
Page 8-12
When suspension non-ceramic insulators are used, the designer must be aware of the effects on
insulator swing calculations due to increased length and reduced weight. Agency Bulletin
1724E-220, “Procurement and Application Guide for Non-Ceramic Composite Insulators,”
provides additional information on non-ceramic insulators. When used as a jumper, polymer
suspension insulators may be pulled towards the structure because of their lightweight.
8.9.2 Horizontal Post Insulators (Porcelain and Non-ceramic): Under NESC loading district
conditions, horizontal post insulators must not be loaded to more than 40 percent of their
ultimate cantilever strength. As with suspension insulators, if a loading more severe than the
NESC loading can be expected to occur with reasonable regularity, then the limit recommended
for the more severe loading should be used. Under extreme ice conditions, the cantilever load on
horizontal post insulators should not exceed 65 percent of the ultimate strength for porcelain and
50 percent of the ultimate strength for non-ceramics.
When a line angle is turned at a horizontal post structure, some or all of the insulators will be
in tension. Under standard NESC loading conditions, the tension or compression load on the
insulator must not exceed 50 percent of the ultimate tension or compression strength of the
insulator. Under extreme loading conditions, the tension load on the insulator must not exceed
65 percent of the ultimate tension strength for porcelain and 50 percent of the ultimate tension
strength of non-ceramic insulators.
Line post insulators are actually subjected to vertical, transverse and longitudinal loads
simultaneously. These loads represent the actual applied stresses to the line post insulator core
that are experienced in the field. Vertical, transverse and longitudinal loads each contribute to
the total bending moment, or total stress on the rod. Non-ceramic manufacturers provide
combined loading application curves, which represent the mechanical strength limits of a nonceramic line post insulator when subjected to simultaneous loads. These curves are used to
determine how the insulator’s combined loading requirements compare with its cantilever
(bending) strength. The combined loading application curves are used during the engineering
stage to evaluate the mechanical strength of the insulator for specific line loading criteria.
There are three special considerations that must be mentioned in relation to horizontal post
insulators:
Insulator Grounding: Where the structure ground wire passes near horizontal post insulators, it
either should be stood off from the pole by means of a non-conducting strut or must be solidly
bonded to the base of the insulator. This grounding is necessary to avoid radio noise problems.
Mechanical Impact Failures: Porcelain post insulators mounted on steel, concrete, or (in some
cases) on wood structures using H-class poles, have experienced cascading mechanical failures
due to impact loads because of the relative rigidity of the structures. To minimize the affects of
impact loads, it is recommended that on rigid structures, non-ceramic insulators be used, or that
porcelain post insulators be equipped with deformable bases, shear pin devices, or other means
of relieving mechanical overloads.
Live Line Maintenance Issues: Many compact designs restrict the lineman for working on
transmission lines while energized. Rule 441 of the NESC provides Table 441-1 which gives the
recommended AC live work minimum approach distance for various voltages.
8.9.3 Porcelain Vertical Post and Pin Insulators Mounted on Crossarms: The maximum
transverse load should be limited to 500 lbs. for standard single pin type agency standard
structures and 750 lbs for standard vertical post type structures. The 500 lb. limit applies
whether the load is from standard NESC loading district loadings alone or from a combination of
loading district loading
Bulletin 1724E-200
Page 8-13
and the resultant of conductor tension on line angles. These limit will prevent excessive stress
on the insulator, the tie wires (if used), insulator pin (if used), and the wood crossarm. The
transverse load can be doubled by using double pin or post construction. See Table 8-5 for a
summary of recommended insulator loading limits.
8.9.4 Coordination of Insulator Strength with Strength of Associated Hardware: Care
should be taken to coordinate the strength of the hardware associated with the insulator with the
strength of the insulator itself.
8.9.5 Example of Maximum Vertical Span Due to Horizontal Post Insulator Strength:
A 115 kV line is to be built using horizontal post insulators with a cantilever strength of
2,800 lbs. The conductor to be used is 477 kcmil 26/7 ACSR. Determine the maximum vertical
span under:
1. Heavy loading district conditions; and
2. Under an extreme ice load, no wind, and 1.5 in. of radial ice
(See Chapter 11 for definitions of heavy loading and Chapter 9 for information on conductors).
Solution: From Appendix B, Conductors, the weights per unit length for the two conditions of
the conductor are:
Heavy Loading District of 1/2 inch radial ice = 1.5014 lbs./ft.
Extreme radial ice of 1.5 inch
=5.0554 lbs./ft.
Span Limits for Heavy Loading District:
2800 lbs.(0.40) = 746 ft.
1.5014 lbs./ft.
Span Limits for Extreme Ice Condition:
2800 lbs.(0.65) = 360 ft.
5.0554 lbs./ft.
The maximum vertical span is therefore 360 ft.
8.9.6 Example of Determining Minimum Suspension Insulator M&E Rating: A conductor
has a maximum tension under heavy loading district conditions of 10,000 1bs. Under extreme
radial ice of 1.5 in, it has a maximum tension of 16,000 lbs. Determine the minimum M&E
rating of suspension bell insulators to be used in tension strings. (Tension strings are those
insulator strings that are in line with the conductor and bear its full tension).
Solution:
Under NESC loading district conditions, the insulator can be loaded up to 40 percent of its M&E
rating. Therefore:
(M&E rating)(0.4)
M&E rating
M&E rating
= load
= load/(0.4)
= 10000 lbs./(0.4) = 25000 lbs.
Under extreme ice conditions the insulator can be loaded to 50 percent of its M&E rating.
Therefore:
Bulletin 1724E-200
Page 8-14
(M&E rating)(.65) = load
M&E rating
= load/(0.65)
M&E rating
= 16,000 lbs./(0.65) = 24,615 lbs.
c. Based on ANSI standard M&E ratings, the insulators to be used should have a minimum
standard rating of 25,000 lbs.
Bulletin 1724E-200
Page 9-1
9. CONDUCTORS AND OVERHEAD GROUND WIRES
9.1 Introduction: Of all the components that go into making up a transmission system, nothing
is more important than the conductors. There are a surprising number of variables and factors
that are to be considered when dealing with conductors. These include:
•
•
•
•
•
•
•
•
•
Conductor type
Conductor size
Conductor ampacity
Conductor thermal capacity
Conductor tensions
Corrosive atmosphere considerations
Radio noise
Conductor motion considerations
Economic considerations
9.2 Types of Conductors: Of the currently available types of conductors, some are used much
more extensively than others. Sections 9.2.1 through 9.2.11 provide descriptions of many of the
conductor types.
9.2.1 ACSR (Aluminum Conductor Steel-Reinforced): ACSR is the most common type of
conductor used today. It is composed of one or more layers of hard-drawn concentricallystranded 1350 aluminum wire with a high-strength galvanized steel core. The core may be a
single wire or stranded depending on the size. Because numerous stranding combinations of
aluminum and steel wires may be used, it is possible to vary the proportions of aluminum and
steel to obtain a wide range of current carrying capacities and mechanical strength
characteristics.
The steel core may be furnished with three different coating weights of zinc. The "A" coating is
the standard weight zinc coating. To provide better protection where corrosive conditions are
present, heavier class "B" or "C" zinc coatings may be specified where "C" is the heaviest
coating.
6 AL/1 St
12 AL/7 St
18 AL/1 S
26 AL/7 St
54 AL/19 St
36 AL/1 S
45AL/7 St
54AL/7 St
84 AL/19 St
FIGURE 9-1: TYPICAL ACSR STRANDINGS
Bulletin 1724E-200
Page 9-2
Aluminum coating is also available (not to be confused with an aluminum cladding which is
thicker). There is a slight reduction in rated conductor strengths when the heavier zinc or
aluminum coating is used.
9.2.2 ACSR/AW (Aluminum Conductor, Aluminum-Clad Steel Reinforced): ACSR/AW
conductor is similar to conventional ACSR except the core wires are high strength aluminumclad steel instead of galvanized steel. Aluminum-clad core wire has a minimum aluminum
thickness of 20 percent of its nominal wire radius. This cladding provides greater protection
against corrosion than any of the other types of steel core wire, and it is applicable for use where
corrosive conditions are severe. ACSR/AW also has a significantly lower resistivity than
galvanized steel core wire and may provide somewhat lower losses.
9.2.3 AAC (All Aluminum Conductors – 1350 H19): AAC conductor is made up entirely of
hard-drawn 1350 aluminum strands. With a minimum aluminum content of 99.5%, 1350
aluminum is essentially pure aluminum. It is usually less expensive than other conductors, but is
not as strong and tends to sag more. AAC conductors are most useful where electrical loads are
heavy and where spans are short and mechanical loads are low.
7 STRAND
19 STRAND
37 STRAND
37 STRAND
91 STRAND
FIGURE 9-2: 1350 ALUMINUM CONDUCTOR STRANDINGS
9.2.4 AAAC-6201 (All Aluminum Alloy Conductor - 6201 Alloy): AAAC conductor is
composed entirely of 6201-T81 high strength aluminum alloy wires, concentrically stranded and
similar in construction and appearance to 1350 aluminum conductors. Its strength is comparable
with that of ACSR. It was developed to fill the need for a conductor with higher strength than
that obtainable with 1350 aluminum conductors, but without a steel core.
AAAC conductors were designed to have diameters the same as those of standard sizes and
strandings of ACSR. The DC resistance of 6201 conductor is approximately equivalent to that
of standard ACSR conductor with the same diameter. AAAC conductor may be used where
contamination and corrosion of the steel wires is a problem. It has proven to be somewhat more
susceptible to vibration problems than standard ACSR conductor strung at the same tension.
The use of conductor sizes smaller than 3/0 ACSR equivalent on suspension type constructions
should be avoided because the light weight of the conductor may result in inadequate downward
force on the suspension insulators causing radio noise and insulator swing problems.
9.2.5 ACAR (Aluminum Conductor Alloy Reinforced): ACAR conductor consists of 1350
aluminum strands reinforced by a core of higher strength 6201 alloy. These 6201 reinforcement
wires may be used in varying amounts allowing almost any desired property of
strength/conductivity (between conductors using all 1350 wires and those using all 6201 wires)
to be achieved. Strength and conductivity characteristics of ACAR are somewhere between
those of a 1350 aluminum conductor and a 6201 conductor.
Bulletin 1724E-200
Page 9-3
3/4
24/13
33/28
12/7
30/7
48/13
18/19
63/28
54/7
42/19
24/37
72/19
54/37
FIGURE 9-3: TYPICAL ACAR STRANDINGS
9.2.6 AWAC (Aluminum-Clad Steel Conductor): AWAC conductor is made up of
aluminum-clad steel and 1350 aluminum strands. The corrosion resistant aluminum clad wires
of the AWAC conductor act as strength members as well as conductivity members, thereby
reducing the weight of the conductor without reducing strength. For the same designated size
and stranding, the AWAC conductors have a slightly smaller diameter than standard ACSR. For
smaller AWAC sizes, the ratio of aluminum-clad to aluminum strands is varied to provide a wide
range of rated strengths.
9.2.7 ACSR/SD (Aluminum Conductor Steel Reinforced - Self Damping): ACSR/SD
conductor may use either two layers of trapezoidal-shaped aluminum wires or two layers of
trapezoidal-shaped aluminum wires and one layer of stranded round wires of hard-drawn 1350
aluminum. The steel core may be a single wire or stranded depending on the size of the
conductor.
From a performance point of view, ACSR/SD conductor is similar to conventional ACSR except
that it has self damping characteristics. That is, the conductor is designed to reduce aeolian
vibration. The damping occurs because of the interaction between the two trapezoidal layers and
between the trapezoidal layers and the core. Some special considerations associated with this
conductor are that:
•
•
During stringing, special precautions are taken and procedures followed to avoid difficulties.
It may be more expensive than conventional ACSR, but its ability to be strung at higher
tensions to reduce sag, which may result in economic advantages that offset its extra cost.
FIGURE 9-4: TYPICAL ACSR/SD STRANDINGS
Bulletin 1724E-200
Page 9-4
9.2.8 ACSR/TW (Trapezoidal Shaped Strand Concentric - Lay Stranded Aluminum
Conductors, Steel Reinforced): As with ACSR/SD, the conductor layers of ACSR/TW are
trapezoidal-shaped aluminum wires. However, unlike ACSR/SD conductor, no gaps exist
between layers ACSR/TW strands. The compact trapezoidal-shaped wires result in an increased
capacity for an equivalent standard range of ACSR conductor diameters. Also, for a given
aluminum area, a smaller conductor diameter can be designed for ACSR/TW than for equivalent
round-wire ACSR which results in reduced wind-on-wire load on the structure. These are
important advantages when existing transmission lines are considered for uprating or
reconductoring. Other advantages and improvements of ACSR/TW include corrosion resistance
and lower temperature gradient.
Use of ACSR/TW should be based on an economic evaluation to determine whether savings will
be achieved in comparison with the use of conventional ACSR conductor.
9.2.9 AACSR (Aluminum Alloy Conductor, Steel Reinforced): AACSR conductor is the
same as a conventional ACSR conductor except that the 1350 strands are replaced with higher
strength 6201 alloy strands. The resulting greater strength of the conductor allows the sags to be
decreased without exceeding the standard conductor percent tension limits. AACSR type of
conductor is primarily used at river crossings where sag limitations are important. The higher
tensions associated with this type of conductor require that special attention be paid to the
possibility of aeolian vibration.
9.2.10 T2 (Twisted Pair Aluminum Conductor): When designing transmission lines with
twisted pair (T2) type conductor, the designer should be aware of Rule 251 of NESC on
conductor wind loading. The rule states for multiconductor cable an equivalent diameter of two
times the single conductor diameter should be assumed for wind loading unless there is a
qualified engineering study to reduce the overall cable diameter.
9.2.11 High Temperature Conductors: Three types of conductors are considered high
temperature, ACCR (aluminum conductor composite reinforced), ACCCTM (aluminum
conductor composite core) and ACSS (aluminum conductor steel supported). For sizes
equivalent to other types of conductor (i.e., ACSR), higher ampacities can be achieved at similar
overall sag levels while operating the conductors a much higher temperatures. One benefit of
these types of conductors can be the avoided cost of replacing existing structures. The
temperature ratings for these conductors can be limited by hardware, so extreme care should be
used when specifying hardware and establishing operating temperature limits. Also, the unique
natures of these conductors result in the use of special precautins during stringing, such as
special stringing blocks in certain locations and multiple grips when installing conductors with
multi-layer annealed aluminum conductor strands.
ACCR conductors are composed of heat resistant aluminum-zirconium alloy outer strands and
aluminum oxide matrix core strands. . The core of the ACCR is composed of stranded fiber
reinforced metal matrix, an aluminum oxide fiber embedded in high-purity aluminum. The fiber
reinforced metal matrix has strength similar to steel and weight similar to aluminum. The outer
strands may be round or trapezoidal in shape and are similar to 1350 aluminum ultimate strength
but may be heated to high temperatures without softening (annealing) and without losing
strength. Additionally, the thermal expansion of the metal matrix core has less thermal
expansion than steel and retains its strength at high temperatures. ACCR conductors use similar
stranding as ACSR. Because of the lightweight core, heat resistant outer and core strands, higher
electrical conductivity, and lower thermal expansion for less sag, higher operating temperatures
may be used with this conductor which leads to higher ampacities. ACCR conductors and
hardware are usually rated up to 210 C continuous operating temperature with 240 C for short
term maximum operating temperature.
Bulletin 1724E-200
Page 9-5
ACCCTM (Aluminum Conductor, Composite Core) are composed of trapezoidal wire of 1350
aluminum stranded around the composite core. The core of the ACCC conductor is a solid with
no voids and is a carbon/glass fiber polymer matrix core. This solid polymer matrix core is
composed of carbon fibers surrounded by an outer shell of boron-free E-glass fibers that
insulates the carbon from the aluminum conductor. The 1350 aluminum trapezoidal wires are
fully annealed which make them softer compared to the hardened aluminum wires used in some
other conductors. The aluminum strands are tempered because the composite core of the ACCC
is designed to carry the entire load Because the core exhibits a very low coefficient of thermal
expansion, the amount of sag the ACCC will experience when operating at high temperatures is
considerably less than other types of conductor (i.e., ACSR). ACCC TM conductors and hardware
are usually rated up to 180 C continuous operating temperature with 200 C for short term
maximum operating temperature. However, because of the softer temper of the aluminum wires,
the outer wires can be more susceptible to damage from improper installation and handling.
ACSS (Aluminum Conductor, Steel Supported) can be considered as another type of high
temperature conductor which can be supplied with round or trapezoidal aluminum strands.
ACSS conductor is similar to ACSR; however, the aluminum strands in ACSS are fully annealed
and depends on the steel for its strength and sag characteristics. ACSS conductors and hardware
are usually rated up to 250 C or more continuous operating temperature, depending upon the
coating on the steel core, without loss of strength. However, because of the softer temper of the
aluminum wires, the outer wires can be more susceptible to damage from improper installation
and handling.
9.3 Selecting a Conductor Type
9.3.1 Agency Standards: The conductor selected should generally be of a type and stranding
listed as being acceptable for use borrower systems of the Rural Utilities Service. See
Informational Publication 202-1, “List of Materials Acceptable for Use on Systems of USDA
Rural Development Electrification Borrowers”.
9.3.2 Corrosion Considerations: Conductors with galvanized steel cores should not be used in
areas of severe corrosion. Rather, a conductor with other types of core wire, such as mischmetal
or aluminum-clad core wire should be used. A conductor with a steel core wire coated with
aluminum or with a heavier weight zinc may be considered, if such materials have been
successfully (i.e., reliably operated without core deterioration) used in similar locations or
corrosive environments..
9.3.3 Economics: The relative cost of one conductor type versus another is very important.
When comparing costs, one should take overall line costs into consideration. However, a less
expensive conductor with greater sags may not be a more economical selection than a more
expensive conductor with lesser sag. When overall line costs are considered, the conductor that
allows longer spans and shorter structures may prove to be the better choice.
9.3.4 Strength: The strength of the conductor and its ability to sustain mechanical loads
without unreasonable sags must be evaluated.
Bulletin 1724E-200
Page 9-6
9.4 Selection of Conductor Size
9.4.1 Minimum Conductor Size: Table 9-1 provides a list of minimum allowable conductor
sizes for each standard agency transmission voltage. The minimums are based on a combination
of radio noise, corona, and mechanical sag and strength considerations. (See Appendix I for
additional details on radio noise and corona). If a conductor type other than ACSR or 6201
AAAC is used, the conductor diameter should not be less than the diameter of the ACSR
specified for the particular given voltage.
TABLE 9-1
RECOMMENDED MINIMUM CONDUCTOR SIZES
kVLL
ACSR
AAAC - 6201
34.5
46
69
115
138
161
230
1/0
2/0
3/0
266.8 kcmil
336.4 kcmil
397.5 kcmil
795 kcmil
123.3 kcmil
155.4 kcmil
195.7 kcmil
312.8 kcmil
394.5 kcmil
465.4 kcmil
927.2 kcmil
9.4.2 Voltage Drop Considerations: Not only should the conductor be sufficiently large to
meet the requirements of paragraph 9.4.1 of this section, but it should also meet the system
voltage drop requirements. Typically, the conductor impedance would have to be sufficiently
low so that, under a given set of electrical loading conditions, the voltage drop would not exceed
approximately 5 percent. In general, voltage drop becomes a factor for longer lines. Voltage
drop can be evaluated by either running a load flow computer program or by using the estimating
tables in Bulletin 1724E-201, “Electrical Characteristics of Agency Alternating Current
Transmission Line Designs.”
9.4.3 Thermal Capability Considerations: When sizing a phase conductor, the thermal
capability of the conductor (ampacity) should also be considered. The conductor should be able
to carry the maximum expected long-term load current without overheating. Generally, a
conductor is assumed to be able to heat up to 167°F without any long-term decrease in strength.
Above that temperature, there may be a decrease in strength depending on how long the
conductor remains at the elevated temperature. A conductor's ampacity depends not only upon
its assumed maximum temperature, but also on the wind and sun conditions that are assumed.
See Appendix D of this bulletin for ampacity tables.
9.4.4 Economic Considerations: Economics is an important factor in determining conductor
size. The minimum conductor sizes given in Table 9-1 will rarely be the most economical in the
long run. The added cost of a larger conductor may be more than offset by the present worth of
the savings from the lower line losses during the entire life of the conductor. A proper economic
analysis should at a minimum consider the following factors for each of the conductor sizes
considered:
•
•
•
•
The total per mile cost of building the line with the particular conductor being
considered;
The present worth of the energy losses associated with the conductor;
The capital cost per kilowatt of loss of the generation, substation and transmission
facilities necessary to supply the line losses;
Load growth.
Bulletin 1724E-200
Page 9-7
The results of an economic conductor analysis can often be best understood when presented in a
graphical form as shown in Figure 9-5. At an initial load of approximately 200 MW, 1272 kcmil
becomes more economical than 795 kcmil. 954 kcmil is not economical at any load level
included on the graph.
9.4.5 Standardization and Stocking Considerations: In addition to the above factors, the
problem of standardization and stocking should be considered. When a conductor is electrically
and economically optimum, but is not a standard size already in use on the system, the additional
cost and complications of having one more conductor size to stock should be weighed against
the advantages of using the optimum conductor. A proliferation of conductor sizes in use on a
power system is undesirable because of the expense of stocking many sizes. In addition, if a
power system does not standardize on conductors then there may be a need for additional
associated hardware such as end fittings and splices.
20
18
Accumulated
present worth
cost in dollars
x 10,000 per mile
1272
16
954
14
795
12
10
100
140
180
220
260
Assumed Load in MW
FIGURE 9-5: RESULTS OF A TYPICAL ECONOMICAL CONDUCTOR
ANALYSIS – 230 kV, 795 vs. 954 vs. 1272 kcmil ACSR
9.5 Overhead Ground Wires (OHGW)
9.5.1 High Strength or Extra High Strength Galvanized Steel Wires: High strength OHGW
included in Informational Publication 202-1 are 3/8" and 7/16", while extra high strength listed
sizes include 5/16", 3/8", and 7/16". Siemens Martin grade wires of any size and 1/4" steel strand
are not accepted by the agency for use as overhead ground wires. Overhead ground wires are
required to be in full compliance with ASTM A-363, “Standard Specification for Zinc-Coated
(Galvanized) Steel Overhead Ground Wire Strand,” ASTM A-363 does not allow steel wires to
have brazed or welded joints. Steel wires for overhead ground wires are available in three
weights of zinc coating. The standard weight zinc coating is designated as ‘A’. The heavier zinc
coating is designated ‘B’ and ‘C’, with ‘C’ having the heaviest weight of zinc.
Bulletin 1724E-200
Page 9-8
9.5.2 Aluminum-Clad Steel Strand: A thick cladding of aluminum which makes aluminumclad steel strand more resistant to corrosion than strands with a thin coating of zinc. In addition,
the aluminum clad material has greater conductivity.
The sizes of this material that may be used as overhead ground wires are 7 No. 10AWG,
7 No. 9AWG, 7 No. 8AWG, and 7 No. 7AWG. The material is in accordance with ASTM B416,
“Standard Specification for Concentric-Lay-Stranded Aluminum-Clad Steel Conductors.”
9.5.3 Selecting a Size and Type: Selecting an overhead ground wire size and type is dependent
upon only a few factors, the most important of which is how the sag of the OHGW coordinates
with that of the phase conductors. Other factors that may have to be considered are corrosion
resistance and conductivity.
If a line is to be built in a seacoast region or in another location where there is a highly corrosive
atmosphere, aluminum-clad steel wire should be considered. If the OHGW is to be used to carry
any type of communications signal, or if large magnitudes of lightning stroke currents are
expected, a higher conductivity than normal may be desirable.
9.6 Conductor and Overhead Ground Wire Design Tensions
9.6.1 General: Throughout the life of a transmission line, the conductor tensions may vary
between 10 and 60 percent, or more, of rated conductor strength due to change in loading and
temperature. Most of the time, however, the tension will vary within relatively narrow limits,
since ice, high winds, and extreme temperatures are relatively infrequent in many areas. Such
normal tensions may actually be more important in determining the life of the conductor than
higher tensions which are experienced infrequently.
9.6.2 Conductor Design Tensions: In Table 9-3 provides recommended maximum conductor
tension values for ACSR and 6201 AAAC conductors that should be observed for the ruling
span. Note that the values given are maximum design values. If deemed prudent, tensions less
than those specified or loadings greater than the standard loading condition (tension limit for
condition 3 of Table 9-3) may be used. However, it is unwise to base the selection of a
"maximum loading" condition on a single or very infrequent case of excessive loading.
Mountainous areas above 4000 feet in which ice is expected, should be treated as being in heavy
loading district even if they are not.
In open areas where steady winds are encountered, aeolian vibration can be a problem, especially
if conductor tensions are high. Generally, lower tensions at conditions at which aeolian
vibration is likely to occur, can reduce vibration problems (see paragraph 9.9.2 for further
discussion).
Explained below are the several conditions at which maximum conductor tension limits are
specified.
1. Initial Unloaded Tension: Initial unloaded tension refers to the state of the conductor
when it is initially strung and is under no ice or wind load.
2. Final Unloaded Tension: After a conductor has been subjected to the assumed ice and
wind loads, and/or long time creep, it receives a permanent or inelastic stretch. The tension
of the conductor in this state, when it is again unloaded, is called the final unloaded tension.
Bulletin 1724E-200
Page 9-9
3. Standard Loaded Tension: The standard loaded tension refers to the state of a conductor
when it is loaded to the assumed simultaneous ice and wind loading for the NESC loading
district concerned (see Table 11-1, Chapter 11 for the loads associated with each loading
districts). The constants in Table 9-2 are to be added to the vector resultant of the transverse
and vertical loads to get the total load on the conductor:
TABLE 9-2
CONSTANTS TO BE ADDED TO THE TOTAL
LOAD ON A WIRE FOR NESC DISTRICT LOADS
Heavy
Medium
Light
0.30 lbs/ft.
0.20 lbs/ft.
0.05 lbs/ft.
In cases where the standard loaded condition is the maximum mechanical load used in the
calculations, the initial and final sags and tensions for the standard loaded condition will be
the same unless creep is the governing factor. If another condition, such as extreme ice, is
the maximum mechanical load, then the initial and final sags and tensions for the standard
loaded condition can be significantly different from one another. In this case, it is important
that the loaded tension limits be set for initial conditions.
4. Extreme Wind Tension: The extreme wind tension refers to the state of the conductor
when a wind is blowing on it with a value not less than the 50-year mean recurrence interval
(see Figure 11-3 in Chapter 11 of this bulletin). No ice should be assumed to be on the
conductor.
5. Extreme Ice Tension: The tension in a conductor when it is loaded with an extreme
amount of ice for the area concerned is called the extreme ice tension. It should be assumed
that there is no wind blowing when the ice is on the conductor. Values of 1 to 2 in. of radial
ice are commonly used as extreme ice loads.
6. Extreme Ice with Concurrent Wind: The tension in a conductor when it is loaded with an
extreme ice with a concurrent wind (see Figure 11-3 in Chapter 11 of this bulletin).
9.6.3 Controlling Conditions: For a given ruling span, usually only one of the tension limit
conditions will control the design of the line and the others will have relatively little significance
as far as line tensions are concerned.
If the conductor loading under extreme ice or wind loads is greater than under the standard
loaded condition, calculated sag and tension values at other conditions could be somewhat
different from what they would be if the standard loaded condition were the maximum case. In
these situations, stringing sags should be based upon tension limits for tension
conditions 1, 2, and 3 only, as tensions at conditions 4 and 5 are satisfactory.
9.6.4 Overhead Ground Wire (OHGW): To avoid unnecessarily high mechanical stresses in
the OHGW, supporting structures, and guys, the OHGW should not be strung with any more
tension than is necessary to coordinate its sags at different conditions with the phase conductors.
See Chapters 6 and 8.
Bulletin 1724E-200
Page 9-10
TABLE 9-3
RECOMMENDED CONDUCTOR AND OVERHEAD
GROUND WIRE TENSION AND TEMPERATURE LIMITS (Note B)
Temperatures
•
Tension limits for conditions 1, 2 and 3 below are to be met at the following temperatures:
Heavy loading district
0º F
Medium loading district
15º F
Light loading district
30º F
•
Tension limits for condition 4 are to be met at the temperature at which the extreme wind is
expected.
Tension limits for condition 5 & 6 are to be met at 32º F
•
Tension Condition
(See section 9.6.2 for explanation)
Tension Limits
(percentage of rated breaking strength)
OHGW High
OHGW Extra
Conductor
Strength Steel
High Strength
Steel
1. Maximum initial unloaded
33.3 (Note C)
25
20
2. Maximum final unloaded
25 (Note D)
25
20
3. Standard Loaded (usually NESC
district loading)
50
50
50
4. Maximum extreme wind (Note A)
70 (Note E)
80
80
5 . Maximum extreme ice (Note A)
70 (Note E)
80
80
6. Extreme ice with concurrent wind
70 (Note E)
80
80
Notes:
(A) These limits are for tension only. When conductor stringing sags are to be determined, tension limits
1, 2 and 3 should be considered as longs as tensions at conditions 4, 5 and 6 are satisfactory.
(B) Tension limits do not apply for self-damping and other special conductors.
(C) In areas prone to aeolian vibration, a value of approximately 20 percent at the average annual
minimum temperature is recommended, if vibration dampers or other means of controlling vibration are
not used (see section 9.9 for further details).
(D) For 6201 AAAC, a value of 20 percent is recommended.
(E) For ACSR only. For 6201 Aluminum, use 60 percent.
Bulletin 1724E-200
Page 9-11
9.7 Ruling Span
9.7.1 Why a Ruling Span? If all spans in a section of line between deadends are of the same
length, uniform ice and wind loads will result in equal conductor tension in all spans. But span
lengths usually vary in any section of line, with the result that temperature change and ice and
wind loads will cause conductor tensions to become greater in the longer spans and less in the
shorter spans when compared to the tensions of loaded uniform spans. Movement of insulator
strings and/or flexing of the structures will tend to reduce this unequal tension. It is possible,
however, for conductor tension in long spans to reach a value greater than desired unless the line
is spotted and the conductor strung to limit this undesirable condition.
A ruling span is an assumed uniform design span which approximately portrays the mechanical
performance of a section of line between its deadend supports. The ruling span is used in the
design and construction of a line to provide a uniform span length which is representative of the
various lengths of spans between deadends. This uniform span length allows sags and
clearances to be readily calculated for structure spotting and conductor stringing.
Use of a ruling span in the design of a line assumes that flexing of the structure and/or insulator
string deflection at the intermediate supporting structures will allow for the equalization of
tension in the conductor between adjacent spans to the ruling span tension.
9.7.2 Calculations of the Ruling Span: On a line where all spans are equal, the ruling span is
the same length as the line spans. Where spans vary in length, the ruling span is between the
shortest and the longest span lengths on the line, but is mainly determined by the longer spans.
•
Approximate Method. Some judgment should be exercised in using this method since a
large difference between the average and maximum span may cause a substantial error in
the ruling span value.
RS = Lavg + 2 / 3(Lmax − Lavg )
Eq. 9-1
where:
RS = ruling span in feet.
Lavg = average span in a line segment between deadends, in feet.
Lmax = maximum span in a line segment between deadends, in feet.
•
Exact Method. The following is the exact formula for determining the ruling span in a
line segment between deadend structures:
L1 + L2 + L3 + K + Ln
L1 + L2 + L3 + K + Ln
3
RS =
3
3
3
Eq. 9-2
where:
L1, L2, L3, etc. = the different span length in the line segment, in feet
Other symbols are as previously defined.
Bulletin 1724E-200
Page 9-12
9.7.3 Establishing a Ruling Span: As can be seen from Equation 9-2, the exact value of the
ruling span can only be calculated after the structures have been spotted and all the span lengths
determined. However, the ruling span has to be known in advance of structure spotting. Thus
the ruling span needs to be estimated before spotting structures on the plan-profile drawings.
When following any procedure for estimating ruling span, keep in mind that estimation of a
ruling span is an intuitive process based on experience, judgment, and trial and error. A good
starting point for estimating ruling span is the height of the base structure. The base structure is
the structure that is expected to occur most often throughout the line. After assuming a base
structure height, subtract the minimum ground clearance value from the height of the lowest
phase conductor above ground at the structure. The allowable sag as limited by ground
clearance is the result. Using this sag value and tables of sags for various ruling span lengths, a
ruling span length can be chosen whose sag is approximately equal to the allowable sag for the
base structure height. In other words, a ruling span is chosen to be approximately equal to the
level ground span -- the maximum span limited by line-to-ground conductor clearance for a
particular height structure. This method of choosing a ruling span is useful if the terrain is flat or
rolling. However, if it is rough, the ruling span should be somewhat greater than the level
ground span.
The ruling span value initially chosen should be checked to see that it coordinates reasonably
well with the minimum span values as limited by such factors as structure strength, conductor
separation, galloping, etc. Also, Equation 9-1 should be used in conjunction with estimated
maximum and average span values to further check the reasonableness of the estimated ruling
span. If the initial estimate does not check out, the value should be changed and the procedure
repeated.
In cases where the spans in one extended section of line are consistently and considerably longer
or shorter than in another section of line, use of more than one ruling span may be unavoidable.
It is a common practice to permit long spans to double the average span without deadends,
provided conductor tension limits are satisfactory. In addition, short spans should not be less
than approximately one-half of the ruling span. After the plan and profile sheets are plotted, the
validity of the estimated ruling span value should be checked by comparing it to the actual value
obtained. It is not essential that the estimated ruling span value be equal to the actual value,
provided the estimated ruling span results in satisfactory ground clearance and economical
structure spotting without excessive conductor tensions. However, if the difference between the
estimated and actual ruling span is more than approximately 15 percent, the effects resulting
from the difference should be carefully checked.
9.7.4 Effects of the "Wrong" Ruling Span: It is important that the actual ruling span be
reasonably close to the ruling span value that is used to spot the line. If this is not the case, there
may be significant differences between the predicted conductor tensions and clearances and the
actual values. There have been instances where sags were greater than predicted, resulting in
clearance problems, because the wrong ruling span was assumed. Table 9-4 will be of use in
determining how conductor sags differ from the predicted value when there are differences
between actual and assumed ruling span. Note that tension variation is opposite of that of the
sags. Thus, increased sags mean decreased tension and vice versa.
Bulletin 1724E-200
Page 9-13
TABLE 9-4
DIRECTION OF DEVIATION OF SAGS FROM
PREDICTED VALUES WHEN ACTUAL AND ASSUMED (DESIGN)
RULING SPAN VALUES ARE SIGNIFICANTLY DIFFERENT
(Applies to Unloaded Condition)
Conductor temperature is
less than temperature at
which the conductor was
strung
Conductor temperature is
greater than temperature at
which the conductor was
strung
Assumed RS
is greater than
Actual RS
Assumed RS
is less than
Actual RS
Actual sag is less than
predicted-INCREASED
TENSIONS
Actual sag is greater than
predicted-CLEARANCE
PROBLEMS
Actual sag is greater than
predicted-CLEARANCE
PROBLEMS
Actual sag is less than
predicted-INCREASED
TENSIONS
CLEARANCE PROBLEMS – Conductor sags greater than indicated on the plan and
profile sheets may result in clearance problems
INCREASED TENSIONS – Conductor tensions greater than anticipated will result
9.8 Determining Conductor Sags and Tensions: Determination of conductor sags and
tensions, given a set of tension limits as outlined in section 9.6, is a complex and difficult task.
This is true because only one of the tension limits may control, and it is not always predictable
which limit it will be. In addition, it is necessary to work with conductor stress strain curves
which for a compound conductor such as ACSR can be rather complex.
The best method of obtaining conductor sag and tension values is to use one of the numerous
computer programs written for that purpose. When using a computer program, several factors
should be checked:
•
The program should be written so that a check is made of all the limiting conditions
simultaneously and the governing condition noted.
•
The program should take conductor creep into account.
•
The tension values given should be average tension values and not tension at support
or horizontal tension values.
•
The source of the stress stain data used should be indicated.
If computerized sag tension values are not available from the software, values can be generated
using the graphical method given in the publication, "Graphic Method for Sag Tension
Calculations for ACSR and Other Conductors," Publication No. 8, Aluminum Company of
America, 1961.
Bulletin 1724E-200
Page 9-14
9.9 Aeolian Vibration
9.9.1 General: Overhead conductors of transmission lines are subject to aeolian and galloping,
both of which are produced by wind. Galloping is discussed in section 6.3. Aeolian vibration is
a high-frequency low-amplitude oscillation generated by a low velocity, comparatively steady
wind blowing across the conductors. This steady wind will create air vortices or eddies on the
lee side of the conductor. These vortices or eddies will detach at regular intervals from the top
and bottom area of the conductor creating a force on the conductor that is alternately impressed
from above and below. If the frequency of the forces approximately corresponds to a frequency
of a mode of resonant vibration of the span, the conductor will tend to vibrate in many loops in a
vertical plane. The frequency of vibration depends mainly on conductor size and wind velocity
and is generally between 5 and 100 Hz for wind speeds within the range of 0 to 15 miles per
hour. The peak-to-peak amplitudes of vibration will cause alternating bending stresses great
enough to produce fatigue failure in the strands of the conductor or OHGW at the points of
attachment. Highly tensioned conductors in long spans are particularly subject to vibration
fatigue. This vibration is generally more severe in flat open terrain where steady winds are more
often encountered.
The frequency and loop length of the vibration can be determined using equation 9-3.
Frequency of the vibration:
f = 3.26
V
dc
Eq. 9-3
where:
f = frequency of conductor vibration in Hertz
V = transverse wind velocity in miles per hour
dc = conductor diameter in inches
Loop Length (for a conductor that is assumed to have negligible stiffness):
LL =
1
2f
⎛ (Tavg )( g ) ⎞
⎜⎜
⎟⎟
⎝ wc ⎠
Eq. 9-4
where:
LL = loop length in feet
Tavg = average conductor tension in pounds
wc = unit weight of conductor in pounds per foot 2
g = universal gravitational constant, 32.2 ft/sec
Other symbols are as previously defined.
9.9.2 Designing for Vibration Problems: If an area is expected to have aeolian vibration
problems, measures ‘a’ through ‘d’ may be taken to mitigate possible problems with damage to
conductors, shield wire, and hardware. It is also important to note that structures, not just
conductors, shield wires, and hardware, may be adversely affected by vibration. The measures
are not necessarily mutually exclusive; more than one measure may be used simultaneously.
Bulletin 1724E-200
Page 9-15
a. Reduced Tension: The two line design variables that have the greatest effect upon a
line's vibration characteristics are conductor tension and span length. Singly or in
combination, these two variables can be reduced to the point where the level of vibration,
without any vibration damping devices, will not be damaging. For similar sag
characteristics, conductors of different types, with their different characteristics, may
require a different degree of vibration protection.
A rule of thumb that has proved generally successful in eliminating vibration problems is
to keep the conductor tension for short and medium length spans under initial unloaded
conditions at the average annual minimum temperature to approximately 20 percent or
less of the conductor's rated strength. For long spans, a somewhat lower percent tension
limit should be used. Due to their vibration characteristics, 6201 AAAC and 1350
aluminum conductors should be held to tensions somewhat lower than the 20 percent
value, even for relatively short spans.
b. Armor Rods: In addition to reinforcing the conductor at the support points, armor rods
provide a small amount of damping of aeolian vibration. In lines with lower conductor
tension and shorter spans, this damping may provide adequate protection against
conductor strand fatigue.
c. Cushioned Suspensions: Cushioned suspensions combine armor rods with a resilient
cushioning of the conductor. These suspension clamps provide somewhat more damping
than armor rods, but the degree of damping is still relatively small compared to vibration
dampers.
d. Dampers: Stockbridge and other types of dampers are effective devices for controlling
vibration. The selection of damper sizes and the best placement of them in the spans
should be determined by the damper or conductor manufacturer on the basis of the
tension, weight, and diameter of the conductor and the expected range of wind velocities.
The length of the suspension clamp and the effect of the armor rods or cushioned
suspensions should also be considered. With new efficient damper designs and usual
conductor tensions and span lengths, one damper is installed near one span support joint.
For long spans, additional dampers may be required.
9.10 Galloping: See Chapter 6 for details.
9.11 Maximum Possible Single Span: For a given span length, as the sag is increased, the
tension at the support will decrease, until a point is reached where the tension will begin to
increase due to the weight of the conductor. This point occurs when the sag is equal to 0.337
times the span length.
The relationship between span length and tension can be expressed as:
Lmax = 1.33
T
wc
where:
wc = unit weight of conductor in pounds per foot
T = resultant tension at support, pounds
Lmax = maximum span, feet
Eq. 9-5
Bulletin 1724E-200
Page 9-16
The above formula can be used to determine the maximum possible span given a maximum
tension at supports. This is most useful when dealing with river crossings, etc.
9.12 Sag and Tension Relationships: The relationships in paragraphs 9.12.1 through 9.12.3
are useful for understanding the sag-tension relationships for conductors:
9.12.1 Level Span Sags: Equation 9-6, the approximate "parabola method", is helpful in
solving some sag and tension problems in span lengths below 1,000 feet, or where sag is less
than 5 percent of the span length.
wc L2
S=
8Th
Eq. 9-6
where:
S = sag at center of span in feet
L = span length in feet
Th = horizontal tension in pounds
The exact formula for determining sags is:
S=
Th
wc
⎛
wL ⎞
⎜⎜ cosh c − 1⎟⎟
2Th
⎠
⎝
Eq. 9-7
9.12.2 Inclined Span Sags: See Figure 9-6 for method of determining inclined span sags.
9.12.3 Tension: The conductor tension in a level span varies from a maximum value at the
point of support to a minimum value at mid-span point.
The tension at the point of support is:
T = Th + wc S = Th cosh
wc L
2Th
Eq. 9-8
The value that is generally referred to, when the "tension" of a conductor is indicated, is usually
the average of the tension at the support and the tension at mid-span. Thus:
Tavg =
Th + T
wS
= Th + c
2
2
where:
Tavg = average tension in pounds
Eq. 9-9
Bulletin 1724E-200
Page 9-17
4000
3000
2500
L
25
S
B
SAG
3500
20
C
30
35
40
45
50
700
600
500
400
300
200
(Add to horizontal spacing to obtain
equivalent span length)
1000
900
800
EQUIVALENT SPAN CORRECTION
HORIZONTAL SPACING OF
SUPPORTS (L.)
1500
Formula for equivalent span length:
Equiv. deadend span = 2C-A
Equiv. suspension span = √AC
*For spans between a
suspension and deadend
*For spans between a
tower, use suspension
suspension and deadend
correction.
tower, span
use suspension
span
2
3
4
5
2.5
10
15
20
25
30
40
50
60
80
100
150
200
250
300
5
7.5
10
12.5
15
20
25
37.5
50
62.5
75
Example: AssumeEXAMPLE
span with A=1000 ft,
B = 100 ft. if deadend span correction = 10 ft
(see above). If suspension span, correction =2.5
Assume
with L=1000',
B=100'
ft (see
above).span
Equivalent
span = 1000
ft +
correction . Read
sag for
equivalent span
If chart
deadend
span,
length.
VERTICAL SPACING OF SUPPORTS
(B.)
2000
60
70
80
90
100
150
200
250
300
350
400
500
correction = 10' (see above)
100
If parabolic
suspension
span, If sag
Sag is based on
functions.
exceeds 5
% of span, =do25'
not(see
use this
chart.
correction
above)
Equivalent span = 1000' + correction.
Read chart sag for equiv. span length.
FIGURE 9-6: NOMOGRAPH FOR DETERMINING LEVEL SPAN
EQUIVALENTS OF NON-LEVEL SPANS
From IEEE Standard 524-1992, “IEEE Guide to the Installation of Overhead Transmission Line
Conductors,” copyright 1992 IEEE. All rights reserved.
Bulletin 1724E-200
Page 9-18
9.13 Stringing Conductors
9.13.1 Tension Method (Preferred) for Stringing Conductors: Using this method, the
conductor is kept under tension during the stringing process. Normally, the tension method is
used to keep the conductor clear of the ground and of obstacles which might cause conductor
surface damage and clear of energized circuits. The method requires pulling a light pilot line
into the sheaves. The pilot line is then used to pull a heavier line. The heavier pulling line is
used to pull conductors from reel stands using specially designed tensioners and pullers. For
lighter conductors, a lightweight pulling line may be used in place of the pilot line to directly
pull the conductor. A helicopter or ground vehicle can be used to pull or lay out a pilot line or
pulling line. When a helicopter is used to pull a line, synthetic rope is normally used to attach
the line to the helicopter and prevent the ‘pilot line’ or pulling line from flipping into the rotor
blades upon release. With the tension method, the amount of right-of-way travel by heavy
equipment can be minimized. Usually, this tension method provides the most economical means
of stringing conductor. Use of a helicopter is particularly advantageous in rugged or poorly
accessible terrain.
Major equipment required for tension stringing includes reel stands, tensioner, puller, reel
winder, pilot line winder, splicing cart and helicopter or pulling vehicle.
9.13.2 Slack or Layout Method: Using this method, the conductor is dragged along the
ground by means of a pulling vehicle, or the reel is carried along the line on a vehicle and the
conductor is deposited on the ground. Conductor reels are positioned on reel stands or "jacks,"
either placed on the ground or mounted on a transport vehicle. These stands are designed to
support the reel on an arbor, permitting the reel to turn as the conductor is pulled. Usually a
braking device is provided to prevent overrunning and backlash. When the conductor is dragged
past a supporting structure, pulling is stopped and the conductor placed in sheaves attached to
the structure before proceeding to the next structure.
This method is chiefly applicable to the construction of new lines where maintenance of
conductor surface condition is not critical and where terrain is easily accessible to a pulling
vehicle. The method is not usually economically applicable in urban locations where hazards
exist from traffic or where there is danger of contact with energized circuits, nor is it practical in
mountainous regions inaccessible to pulling vehicles.
Major equipment required to perform slack stringing includes reel stands, pulling vehicle(s) and
a splicing cart.
9.13.3 Stringing Conductors During Temperature Changes: An examination of conductor
sag and tension tables will generally indicate the changes that take place in various span lengths
with a change of conditions. For a given set of conditions, spans of various lengths may have a
different rate of tension change with a change of loading or temperature. The ruling span tension
of an unloaded conductor matches the tension of any other span only at one temperature. Large
changes in temperature during stringing require care in matching average tensions in any section.
It is desirable to complete stringing between deadends during periods of minimum temperature
change and at zero wind load. Where spans are supported by suspension insulators, each span
will have an influence on adjacent spans such that no span can be considered independently
of the remainder of spans in the same section between anchor structures. Change in temperature
has a greater effect on short spans than loading does, while long spans are affected more by
loading. In short spans a slight movement of supports results in substantial changes in tension
while in longer spans, relatively greater movement is required. The relation between adjacent
span lengths therefore determines the movement required to equalize tension.
Bulletin 1724E-200
Page 9-19
9.14 The Sagging of Conductors: It is important that the conductors be properly sagged in at
the right stringing tension for the ruling span used. When installing conductors, a series of
several spans is usually sagged in one operation by pulling the conductors to proper tension
while they are supported on free rolling sheaves. To obtain the correct sags and to ensure that
the suspension insulators will hang vertically, the horizontal components of tension must be the
same in all spans for a selected condition. In a series of spans of varying length, greater sag
tends to form in the long spans. On steep inclines the sheaves will deflect in the uphill direction
and there will be a horizontal component of tension in the sheave itself. The horizontal
component of tension in the conductor will therefore increase from one span to the next, as the
elevation increases, by an amount equal to the horizontal component in the sheave. As a result,
sags will proportionally decrease. In order to avoid this effect, it may be necessary to use a
procedure called offset clipping. In this procedure, the point along the conductor at which it is
attached to the insulator string is moved a specific distance down span from the point at which
the conductor sits in the stringing block. See Figure 9-7 for further details on offset clipping.
It is important that the sags of the conductor be properly checked. It is best to do this in a series
of level spans as nearly equal to the ruling span as possible.
For additional information, see:
“A Guide to the Installation of Overhead Transmission Line Conductors,” IEEE
Standard 524-1992, IEEE, 1992.
Bulletin 1724E-200
Page 9-20
∑ CONDUCTOR LENGTH IN TRAVELERS = ∑ CONDUCTOR LENGTH IN SUSPENSION CLAMPS
FIGURE 9-7: ANALYSIS FOR APPLICATION OF CLIPPING OFFSETS
From IEEE Standard 524-1992, “IEEE Guide to the Installation of Overhead Transmission Line
Conductors,” copyright 1992 IEEE. All rights reserved.
Bulletin 1724E-200
Page 9-21
9.15 Example 9-1: Determination of Ruling Span: Determine the ruling span for the line
segment given below using both the exact and approximate method.
925 ft
1380 ft
495 ft
1005 ft
FIGURE 9-8: LINE SECTION FOR EXAMPLE 9-1
Solution, Exact Method:
RS =
L1 + L2 + L3 + K + Ln
L1 + L2 + L3 + K + Ln
RS =
925 3 + 1380 3 + 495 3 + 1005 3
925 + 1380 + 495 + 1005
3
3
3
3
See Eq. 9-2
RS = 1094 ft.
Solution, Approximate Method:
RS = Lavg + 2/3(Lmax - Lavg)
See Eq. 9-1
Lavg = (925 + 1380 + 495 + 1005)/4 = 951 ft.
Lmax = 1380
RS = 951 + 2/3(1380 - 951)
RS = 1237 ft.
As previously mentioned in the text, the error between the exact and approximate methods of
determining ruling span is caused by a rather significant error between the average and
maximum span values.
9.16 Example 9-2, Maximum Span Determination: Determine the maximum span (for river
crossings, etc.) for a 795 kcmil 26/7 ACSR conductor. Assume that under heavy loading district
conditions, the conductor can be loaded up to 40 percent of its rated strength.
Bulletin 1724E-200
Page 9-22
Solution: From the conductor tables in Appendix B, the rated strength of the conductor is
31,500 lbs. and the weight of the conductor with 1/2 in. of radial ice is 2.0930 lbs/ft..
T = 31500(0.4) = 12600 lbs.
Lmax = 1.33
T
wc
See Eq. 9-5
Lmax = 1.33 12600 lbs. = 8007 ft.
2.0930 lbs/ft.
9.17 Example 9-3, Determination of Tensions at the Mid Span Point and at the Point of
Support: A level 800 ft. span of 795 kcmil 26/7 ACSR conductor has a sag of 21.95 ft. The
average tension value is 9,185 lbs. and there is no ice or wind on the conductor. Determine the
actual tension values at the mid span point and at the point of conductor support.
Solution for the Tension at Mid Span Point:
Th + T
wS
= Th + c
2
2
wS
Th = Tavg − c
2
Tavg =
See Eq. 9-9
From the conductor tables in Appendix B, the weight of the conductor without ice is
1.0940 lbs/ft.
Th = 9185 - (1.094)(21.95)
2
Th = 9173 lbs.
Solution for the Tension at Support:
T = Th + wc S = Th cosh
wc L
2Th
T = Th + wcS
T = 9173 + (1.094)(21.95)
T = 9197 lbs.
See Eq. 9-8
Bulletin 1724E-200
Page 10-1
10. PLAN-PROFILE DRAWINGS
10.1 General: Transmission line plan-profile drawings serve an important function in linking
together the various stages involved in the design and construction of the line. Initially, the
drawings are prepared based on a route survey. These drawings show the location and elevation
of all natural and man-made features to be traversed by, or which are adjacent to, the proposed
line which may affect right-of-way, line design and construction. They also indicate ownership
of lands near the line. The drawings are then used to complete line design work such as structure
spotting. During material procurement and construction, the drawings are used to control
purchase of materials and they serve as construction specification drawings. After construction,
the final plan-profile drawings become the permanent record and right-of-way data, useful in line
operation and maintenance or future modifications.
Accuracy, clarity, and completeness of the drawings should be maintained, beginning with initial
preparation, to ensure economical design and correct construction. All revisions made
subsequent to initial preparation and transmittal of drawings should be noted in the revision
block by date and brief description of revision. Originals of the plan-profile drawings, revised
for as-built conditions, should be filed by the borrower for future reference.
10.2 Drawing Preparation: Adequate control of field survey, including ground check of aerial
survey, and proper translation of data to the plan-profile drawings are of utmost importance.
Errors which occur during this initial stage will affect line design because a graphical method is
used to locate the structures and conductor. Normally, plan-profile sheets are prepared using a
scale of 200 feet to the inch horizontally and 20 feet to the inch vertically. On this scale, each
sheet of plan-profile can conveniently accommodate about 1 mile of line with overlap to connect
the end span on adjacent sheets. On lines with abrupt ground terrain changes and on lines where
there is need to minimize breaks in elevation view, plan-profile sheets may use a scale of one
inch equal to 400 feet horizontally and one inch equal to 40 feet vertically may be used.
A sample format for plan-profile drawing, detailing dimensions and stationings in U.S.
customary (English) units, is shown in Figure 10-1. Stationing and structure numbering
increases from left to right and the profile and corresponding plan view are included on the same
sheet. Drawings prepared in ink on Mylar or tracing cloth will provide a better permanent record
than on paper. However, structure spotting initially should be marked in pencil on plan-profile
drawing paper and transferred to the base tracings in ink after the drawings are approved and the
line is released for construction.
Conventional symbols used to denote features on the drawings are shown in Figure 10-2.
Features of existing obstacles, structures, etc. to be crossed by the transmission line, including
the height and position of power and telecommunication lines, should be shown and noted by
station and description in both the plan and profile views. The magnitude and direction of all
deflection angles in the line should be included and referenced by “P.I. Station No. XX” in plan
and elevation views. (P.I. refers to point of intersection). In rough terrain, broken lines
representing side-hill profiles should be accurately plotted to assure final designs will provide for
adequate conductor-to-ground clearances and pole heights. A drawing title block should be
included. The block should identify the line and include the station numbers that are covered on
the drawing sheet. The block should also include space for recording the names of personnel
and the dates involved in various stages of drawing preparation, line design, checking, approval,
and revisions.
Line design computer software may be used to import survey data and develop the land profile
for the transmission line. Developments in surveying technologies have allowed the industry to
go beyond the station-elevation-offset formats that have traditionally been used for transmission
profile
Bulletin 1724E-200
Page 10-2
FIGURE 10-1: SAMPLE OF A PLAN AND PROFILE
Bulletin 1724E-200
Page 10-3
PLAN
CL
Transmission Line
Telephone Lines
Property Lines
R/W Lines
State Lines
County Lines
T
T
T
T
T
Township, Range,
and District Lines
Section Lines
U.S. 40
Highway and Main Roads
8 ft. gravel
Local Roads
Railroads
Fences (all kinds)
O P S 69kV
Existing O.H. Power Line
(Ownership and Voltage)
Smaller Streams
Wooded section
Creeks
Orchard
Rivers
Marsh
Depression
Ponds
Buildings (State Kind)
Barn
PROFILE
Center Line
Sidehill, right
Sidehill, left
P.I.
(Point
Point
of of
Intersection)
Intersection
(P.I.)
FIGURE 10-2: CONVENTIONAL SYMBOLS FOR PLAN-PROFILE
Bulletin 1724E-200
Page 10-4
modeling. Use of three-dimensional Geographical Information System (GIS) modeling is
becoming more common. Total station, geographical positioning system, photogrammetry, and
electronic topographical maps (United States Geological Survey, USGS, maps) have been
employed to collect data in electronic format and to develop quick and accurate terrain plan and
profile for transmission lines.
Design software can use a three-dimensional survey format and develop profile drawings of the
terrain along the centerline of the line. Some software can create interpolated points on profiles
by creating a Triangular Irregular Network (TIN). The TIN can be used to develop a threedimensional rendering of a transmission line.
Once the alignment and profile have been developed, computer programs are then used to spot
structures along the profile. For an established family of structures, the computer can be used to
automatically spot structures for the most economical line cost or the user may manually spot
structures. Programs have been developed to automatically plot the sag curve of the conductor
and to check insulator swing, structure strength, and clearances. A material list is often
developed from computer generated plan-profile drawings.
Computer aided drafting and design software may provide all or part of the following:
•
•
•
•
•
•
•
•
Importing survey data, to model terrain, and to create a profile;
Modeling of structure, including strength, geometry, insulator swing and complete bill of
material;
Calculating conductor sag and tension;
Locating structures (spotting) on the profile drawing;
Calculating conductor stringing and sagging, at almost any temperature, to check design
conditions such as uplift, ground clearance or insulator swing;
Checking the line plan-profile against specific design criteria;
Displaying the plan-profile or structure analysis in three dimensions; and
Preparing reports and construction documents showing all construction material units on the
plan and profile, as well as developing material reports, staking tables, offset clipping
reports, etc.
Some design programs provide more custom drafting capabilities. Some are AutoCAD based;
others are MICRO STATION based. Traditional methods used to spot structures can be as much
as 70-80 percent more conservative than the computer aided design and drafting approach.
10.3 Sag Template: When computers are not used to spot structures and draw the conductor
sag curve, manual techniques are used. Once the profile of the line has been drawn, the next step
is to develop a sag template. The sag template is a scaling device used for structure spotting and
for showing the vertical position of conductor (or ground wire) for specified design conditions .
A sample conductor sag template is shown by Figure 10-3. The template is used on plan-profile
drawings to graphically determine the location and height of supporting structures required to
meet line design criteria for vertical clearances, insulator swing, and span limitations. The sag
template permits alternate layout for portions of the line to be investigated and thereby aids in
optimizing line design for economy.
Generally, the conductor sag curves control the line design. The sag template for the overhead
ground wire is used to show the position of the wire in relationship to the conductors for special
spans or change in conductor configuration. An uplift condition at the overhead ground wire
may be checked by using the template cold curve.
Bulletin 1724E-200
Page 10-5
10.3.1 Sag Template Curves: The sag template should include the following sag curves based
on the design ruling span:
a. Hot (Maximum Sag) Curve: At maximum operating temperature, no ice, no wind, final sag
curve, the hot curve is used to check for minimum vertical clearances. However, if the
maximum sag occurs under an icing condition, this sag curve should be used for the sag
template.
b. Cold Curve: At minimum temperature, no ice, no wind, initial sag curve, the cold curve is
used to check for uplift and insulator swing.
c. Normal Curve: At 60°F, no ice, no wind, final sag curve, the normal curve is used to check
normal clearances and insulator swing.
Sag curves are also used to locate the low point of sags and determine the vertical span lengths
as illustrated by Figure 10-6. The curve intersection with the vertical axis line represents the low
point position of sag.
Conductors of underbuild lines may be of different types or sizes than the transmission
conductor. The hot curve of the lowest distribution conductor should be used for checking
ground clearance. Cold curves may be required for each size of conductor to check for uplift or
insulator swing.
10.3.2 Sag Template Design: Sag templates may be developed from information provided by
the manufacturer of the conductor or from a graphical calculation method. Sag values needed to
construct the template are available from the conductor manufacturer for a given conductor,
ruling span, design condition and temperature. Sag values may also be determined using the
graphic method referred to in Section 9.8 of Chapter 9. The template should be made to include
spans three or four times as long as the normal level ground span to allow for spotting structures
on steep terrain.
The form of the template is based on the fact that, at the time when the conductors are installed,
horizontal tensions have to be equal in all level and inclined spans if the suspension insulators
are plumb in profile. This is also approximately true at maximum temperature. To obtain values
for plotting the sag curves, sag values for the ruling span are extended for spans shorter and
longer than the ruling span. Generally for spans up to 1000 feet, it is sufficiently accurate to
assume that the sag is proportional to the square of the spans (unless more accurate computed
sag values are unavailable). The sag values used for the template may be determined as follows:
a. For the ruling span and its sag under each appropriate design condition and temperature,
calculate other sags by the relationship:
2
⎛ L ⎞
S =⎜
⎟ (S RS )
⎝ RS ⎠
where:
S =
SRS =
L =
RS =
Eq. 10-1
sag of other span in ft.
sag of ruling span in ft.
length of other span in ft.
ruling span sag in ft.
b. Apply catenary sag correction for long spans having large sags.
Bulletin 1724E-200
Page 10-6
The template should be cut to include a minimum of one foot additional clearance than given in
Table 4-1 (Chapter 4), to account for possible minor shifts in structure location and error in the
plotted profile. Where the terrain or the surveying method used in obtaining ground profile is
subject to greater unknowns or tolerances, the one foot additional clearance should be increased.
The vertical offset between the upper two maximum temperature (hot) curves is equal to the total
required clearance, including the specified additional clearance. It is shown as dimension "C" in
Figures 10-3 and 10-4. The minimum temperature and the 60°F curves may be placed in any
convenient location on the template.
A sag template drawing similar to Figure 10-3, made to the same scales as the plan-profile
sheets, should be prepared as a guide for cutting the template. This template is made for a
specified conductor, ruling span, and loading condition. A new template should be prepared for
each line where there is any variation in voltage, conductor size, loading condition, design
tension, or ruling span. A change in any one of these factors may affect the design
characteristics of the template.
CONDUCTOR: 336.4 kcmil ACSR (26/7)
RULING SPAN: 500ft
MAX. DESIGN TENSION : 5786 lb.
DESIGN LOADING: 1/2 in. ice, 4 psf wind @ 0°F
Structure Height
Scale
TS-1
90
85
80
75
70
65
60
55
50
G
Ground
level
SCALE: HORIZONTAL 1" = 200 ft
1" = 20 ft
VERTICAL
0°F Initial
Cold Curve
60°F FINAL
Normal Curve
167°F FINAL
Hot Curve
C
B
FIGURE 10-3: SPECIMEN SAG TEMPLATE FOR CONDUCTOR
(Reduced size, not to scale)
B = Sag for the level ground span, C = Total Ground Clearance,
G = Dimension from ground to point of attachment of lowest conductor
Bulletin 1724E-200
Page 10-7
10.3.3 Sag Template Construction: The sag template should be made of dimensionally-stable
transparent plastic material. A contrasting colored material (for example, red) is very helpful
when the template is used to check plan-profile blueprint drawings.
Curves are first plotted on paper using the correct scales and then reproduced or copied on the
plastic material. To cut a template, the transparent material is fastened securely over the curves
drawn on paper and the centerline and upper curves are etched lightly by a sharp-pointed steel
scriber. The outside edges of the template should be etched deeply so that the template can be
easily broken out and the edges sanded smooth. Structure height scales may also be drawn or
etched on the sag template, or a separate template, for determining the pole height required for
each type of structure used. Etched lines should be filled with ink to make them easier to see
when the template is used.
Conductor size, design tension and loading condition as well as ruling span and descriptive data
for each curve should be shown on the template.
10.4 Structure Spotting
10.4.1 General: Structure spotting is the design process which determines the height, location,
and type of consecutive structures on the plan-profile sheets. Actual economy and safety of the
transmission line depends on how well this final step in the design is performed. Structure
spotting should closely conform to the design criteria established for the line. Constraints on
structure locations and other physical limitations encountered may prevent spotting of structures
at optimum locations. Success of the effort to minimize or overcome these special conditions
can be judged by how closely the final line layout follows the original design parameters.
Desired objectives of a well-designed and economical line layout are:
a. Spans should be approximately uniform in length, equal to or slightly less than the design
ruling span. Generally, differential conductor tensions are minimized and may be ignored if
adjacent span lengths are kept below a ratio of 1.5 to 1.
b. Maximum use should be made of the basic structure of equal height and type. The basic
structure is the pole height and class which has been selected as the most economical structure
for the given design condition.
c. The shape of the running conductor profile, also referred to as the grading of the line, should
be smooth. If the conductor attachment points at the structures lie in a smooth-flowing curve,
the loadings are equalized on successive structures.
For a generally level and straight line, with few constraints on structure locations, there is no
conflict between these objectives. They can be readily achieved. Greater skill and effort are
needed for lines with abrupt or undulating ground profile and for those where constraints on
structure location exist. For example, there may be high or low points in the profile or features
such as line angle points, crossings over highway, railroad, water, power and telecommunication
lines, and ground with poor soil conditions. Structure locations and heights are often controlled
or fixed by these special considerations. Alternative layouts between fixed locations may then
be required to determine the best arrangement based on factors of cost and effective design.
10.4.2 Design Factors for Structure Spotting: The following design factors are involved in
structure spotting and are covered in the identified chapters of this bulletin:
Bulletin 1724E-200
Page 10-8
a. Vertical Clearances (Chapter 4)
• Basic, level ground
• Crossings
• Side hill
• Underbuild
b. Horizontal Clearances
• For insulator side swing condition (Chapter 7)
• To edge of right-of-way, vertical obstructions and steep side hills (Chapter 5)
c. Uplift (Chapter 12)
d. Horizontal or Vertical Span Limitations Due to:
• Vertical sag - clearance requirement (Chapters 4, 6)
• Conductor separation (Chapter 6)
• Galloping (Chapter 6)
• Structure strength (Chapters 13, 14)
• Crossarm strength (Chapter 13)
e. Angle and Deadend (Chapter 14)
• Guying arrangements
• Guy anchors
10.4.3 Preparation: The following are necessary for structure spotting:
•
•
•
•
•
•
Plan-profile drawings of the transmission line,
Sag template of the same scale as the plan-profile prepared for the design temperatures,
loading condition, and ruling span of the specified conductor and overhead ground wire,
Table of minimum conductor clearances over ground features and other overhead lines
(Chapter 4),
Insulator swing charts (Chapter 7),
Horizontal and vertical span limitations due to clearance or strength requirements
(Chapters 8, 9, and 13), and
Guy arrangement and anchor requirements for angle and deadend structures (Chapter 14).
A height scale prepared for each structure type will aid in structure height determination.
Supporting calculations should be summarized in chart or tabular form to facilitate application
during structure spotting. This is especially advisable for the standard suspension structure
which has a greater range of pole height and class, as well as bracing variations for H-frame
structures. Selection of the proper pole may be affected by various criteria, such as spancontrolled-by-clearance or span-limited-by-pole-strength, for a given pole height and class or
bracing.
10.4.4 Process of Spotting: The process of spotting begins at a known or established conductor
attachment point such as a substation take-off structure. For level terrain, the profile is
essentially a straight line. When a sag template is held vertically and the ground clearance curve
is held tangent to the ground profile, the edge of the template will intersect the ground line at
points where structures of the basic height should be set. This relation is illustrated for a level
span in Figure 10-4. Curve 1 (lowest conductor sag position) represents the actual sag of the
conductor. Curve 2 (basic ground clearance curve) represents the actual position of the lowest
conductor plus the required total ground clearance, "C."
Bulletin 1724E-200
Page 10-9
GROUND LINE
D
B
E
C BA
G
32 1
4
5
F
Hot Curves (Maximum Sag)
Curve 1 - Lowest Conductor Sag Position
Curve 2 - Basic Ground Clearance Curve
Curve 3 - Edge of Template or Reference Line
Point 4 - Intersection Locates Pole of Basic
Height
Point 5 - Tangent to Ground Profile
A = Dimension from top of pole to point of
attachment of lowest conductor.B = Sag in level ground span.
C = Total ground clearance.
D = Setting depth of pole
E = Length of pole.
F = Level ground span.
G = Dimension from ground to point of
attachment of lowest conductor
FIGURE 10-4: APPLICATION OF SAG TEMPLATE - LEVEL GROUND SPAN
The point where Curve 3 intersects the ground line determines the location of the next structure.
This new location is found by drawing an arc along the edge of the template from Point 4 to the
next point where Curve 3 intersects the ground line. The template should then be shifted and
adjusted so that with the opposite edge of the template held on the conductor attachment point
previously located with the clearance curve again barely touching the profile. The process is
repeated to establish the location of each succeeding structure. After all structures are located,
the structures and lowest conductor should be drawn in.
The above procedure can be followed only on lines that are approximately straight and which
cross relatively flat terrain with the basic ground clearances. When line angles, broken terrain,
and crossings are encountered, it may be necessary to try several different arrangements of
structure locations and heights at increased clearances to determine the arrangement that is most
satisfactory. Special considerations often fix or limit the structure locations. It is advisable to
examine the profile for several span lengths ahead, take note of these conditions and adjust the
structure spotting accordingly. Sometimes, a more balanced arrangement of span lengths is
achieved by moving ahead to a fixed location and working back.
The relationship between the ground clearance and conductor curves is also used for spans other
than level-ground spans. This is done by shifting the sag template until ground profile touches
or is below the clearance curve with the previously established conductor attachment point is
positioned on the conductor curve. The conductor curve would then indicate the required
conductor height for any selected span. Structure height may be determined by scaling or by use
of the proper structure height template, taking into account the change in the embedded pole
length for poles other than the basic pole. Design limitations due to clearance or structure
strength should be observed.
Bulletin 1724E-200
Page 10-10
10.4.5 Crossings: For spans-crossing features such as highway and power lines, with different
clearance requirements than the normal clearance, the ground clearance curve should be adjusted
accordingly. In California, adequate ground clearance has to be maintained over all railroads,
major highways, major telecommunication and power lines when a broken conductor condition
in either of the spans adjacent to the crossing span. Other states are governed by the NESC,
which does not require the broken conductor condition. The increase in sag due to a broken
conductor in an adjacent span is usually significant only where suspension-type structures are
used at crossings and for voltage at 230 kV or above. For tension structures, and for suspension
structures at lower voltages, the sag increase normally will not seriously affect the clearance.
10.4.6 Insulator Side Swing - Vertical Span: Horizontal conductor clearances to supporting
structures are reduced by insulator side swing under transverse wind pressure. This condition
occurs where the conductor is supported by suspension-type insulators. Conductors supported
by pin-type, post, or tension insulators are not affected and horizontal clearance of the deflected
conductor position within the span becomes the controlling factor (see Chapter 5 of this
bulletin). Suspension insulators also deflect laterally at line angle locations due to the transverse
component of conductor tension.
Chapter 7 covers the preparation of insulator swing charts. At each structure location the charts
are used to determine if insulator swing is within the allowed limit for the vertical and horizontal
spans and line angle conditions. For suspension insulators supported on horizontal crossarms, a
minimum vertical span has to be maintained to avoid excessive side swing. To maintain
adequate clearance for insulators attached directly to the pole, and for some types of angle
structures, the vertical span cannot exceed a maximum value (as indicated by the insulator swing
chart). See Figure 7-5 of this bulletin for an example swing angle chart for the TH-233 large
angle structure.
The vertical span is the distance between the conductor low points in spans adjacent to the
structure. The horizontal span is the average value of the two adjacent spans to a structure.
Where conductor attachments are at different elevations on adjacent structures, the low point is
not at mid-span and will shift its position as the temperature changes. This shift can be readily
seen by comparing the low point for the hot curve with its position for the cold curve. The
vertical span value used to check the insulator swing should be based on the low point position
which yields the most critical condition for the structure type. (See Chapter 7 for details on
insulator swing)
Where minimum vertical span or uplift is the concern, the cold curve should be used. The
normal temperature is more critical and should be used if the vertical span is limited by a
maximum value. Figure 10-6 shows some examples of the relationship of conductor low points
and vertical spans which may occur in a line profile.
If insulator swing is unacceptable, one of the following corrective steps, in order of preference, is
recommended:
a.
b.
c.
d.
Relocate structures to adjust horizontal-vertical span ratio;
Increase structure height or lower adjacent structures;
Use a different structure, one with greater allowable swing angle or a deadend structure; or
Add weight at insulators to provide the needed vertical force.
10.4.7 Uplift: Uplift is defined as negative vertical span and is determined by the same
procedure as vertical span. On steeply inclined spans when the cold sag curve shows the low
point to be above the lower support structure, the conductors in the uphill span exert upward
forces on the lower structure. The amount of this force at each attachment point is related to the
Bulletin 1724E-200
Page 10-11
weight of the loaded conductor from the lower support to the low point of sag. Uplift exists at a
structure (see Structure No. 4 in Figure 10-6) when the total vertical span from the ahead and
back spans is negative. Uplift has to be avoided for suspension, pin-type, and post insulator
construction. For structures with suspension insulators, the check for allowable insulator swing
is usually the controlling criteria on vertical span. A rapid method to check for uplift is shown
by Figure 10-5. There is no danger of uplift if the cold curve passes below the point of
conductor support on a given structure with the curve on the point of conductor support at the
two adjacent structures.
Designing for uplift, or minimizing its effects, is similar to the corrective measures listed for
excessive insulator swing, except that adding of excessive weights should be avoided. Double
deadends and certain angle structures can have uplift as long as the total force of uplift does not
approach the structure weight. If it does, hold-down guys are necessary.
Care should be exercised to avoid locating structures that result in poor line grading (see
Paragraph 10.1.4a of this chapter).
Cold Curve
Cold Curve
Uplift Exists at
Center
Structure
No Uplift at
Center Structure,
Check for Allowable
Insulator Swing
FIGURE 10-5: CHECK FOR UPLIFT
10.4.8 Other Considerations: If maximum conductor tension or other limits are not exceeded,
it may be preferable to use one long span with adequate conductor separation over a depression
in the profile rather than use two short spans with a deadend structure at the bottom of the
depression. A structure at the bottom of the depression may be subjected to considerable uplift
at minimum conductor temperature. Also, poorer soil foundation conditions usually exist in the
depression.
Care has to be exercised at locations where the profile falls sharply away from the structure to
see that the maximum allowable vertical span as limited by the strength of the crossarm or
insulator is not exceeded. Structure No. 2 in Figure 10-6 illustrates this condition. For
maximum accuracy in the heavy or medium loading zone, the vertical span for this purpose
should be determined with a curve made for the sag under ice load, no wind, at 32°F. For most
conductors, however, the maximum temperature final sag curve will closely approximate the
1
Structure No. 1
Vertical Span
FIGURE 10-6: SAG LOW POINT, VERTICAL SPANS AND UPLIFT
3
4
5
Structure No. 5 Vertical Span
Structure No. 4
Uplift
Structure No. 3
Vertical Span
Figure 10-6 Sag Low Point, Vertical Spans and Uplift
2
Structure No. 2 Vertical Span
6
7
Bulletin 1724E-200
Page 10-12
Bulletin 1724E-200
Page 10-13
curve for the ice-loaded conductor, and it may be used when checking for maximum vertical
span. For guyed structures, the maximum vertical loads added to the vertical components from
guy loads should be checked against the buckling strength of the pole
The profile in rough country where side hills are encountered should be prepared so that the
actual clearances under the uphill and downhill conductor may be checked. For some long spans
it may be necessary to check side hill clearance with the conductors in their maximum transverse
swing position. H-frame type structures installed on side hills may require different pole heights
to keep the crossarm level or one pole may be set a greater than normal setting depth.
Structures with adequate longitudinal strength (guyed deadends usually) are required at locations
where longitudinal loading results from unequal line tensions in adjacent spans. For lines
subject to heavy ice and high wind conditions and with long, uninterrupted section of standard
suspension structures, consideration should be given to include some structures with in-line guys
or other means to contain and prevent progressive, cascading-type failure. This is especially
important for H-frame type structures with lower strength in the longitudinal direction when
compared with its transverse strength. Measures to prevent cascading failures are also important
for lines without overhead ground wire which tends to restrain the structure from collapsing
longitudinally. A maximum interval of 5 to 10 miles is suggested between structures with
adequate longitudinal capacity (guyed deadends usually), depending on the importance of the
line and the degree of reliability sought.
10.5 Other Design Data: Conductor and ground wire sizes, design tensions, ruling span, and
the design loading condition should be shown on the first sheet of the plan-profile drawings. For
completeness, it is preferable that these design data be shown on all sheets. A copy of the sag
template reproduced on the first sheet could serve as a record of design in case the template is
misplaced or lost. Design data for underbuild and portions of the line where a change in design
parameters occurs should similarly be indicated. The actual ruling spans between deadends
should be calculated and noted on the sheets. This serves as a check that the actual ruling span
has not deviated greatly from the design ruling span. The significance of this deviation is also
covered in the ruling span section of Chapter 9. Where spans are spotted at lengths less than
one-half or over twice the ruling span, deadending may be required.
As conductor sags and structures are spotted on each profile sheet, the structure locations are
marked on the plan view and examined to insure that the locations are satisfactory and do not
conflict with existing features or obstructions. To facilitate preparation of a structure list and the
tabulation of the number of construction units, the following items, where required, should be
indicated at each structure station in the profile view:
•
•
•
•
•
•
Structure type designation,
Pole height and class,
Pole top, crossarm, and brace assemblies,
Pole grounding units,
Miscellaneous hardware units (vibration dampers at span locations), and
Guying assemblies and anchors.
The required number of units or items required should be shown in parenthesis if greater than
one. Successive plan-profile sheets should overlap. For continuity, and to avoid duplicate count,
the end structure on a sheet should be shown as a broken line on the following sheet. The
number and type of guying assemblies and guy anchors required at angle or deadend locations,
based on guying calculations or application charts, should also be indicated. Design check, line
construction, and inspection are facilitated if an enlarged guying arrangement, showing
attachments and leads in plan and elevation, is added on the plan-profile sheet adjacent to each
Bulletin 1724E-200
Page 10-14
guyed structure. Any special notes or large-scale diagrams necessary to guide the construction
should be inserted on the plan-profile sheet. This is important at locations where changes in line
design or construction occur, such as a slack span adjacent to a substation, line transposition, or
change in transmission and underbuild circuits.
10.6 Drawing Check and Review: The completed plan-profile drawings should be checked to
ensure that:
•
•
•
The line meets the design requirements and criteria originally specified,
Adequate clearances and computed limitations have been maintained, and
Required strength capacities have been satisfied.
The sheets should be checked for accuracy, completeness, and clarity. Figure 10-7 is a Sample
Check List for review of plan and profile sheets.
Bulletin 1724E-200
Page 10-15
Profile: ____________________________
Date: _______________________________
Line: ______________________________
Voltage: ______________
Plan and Profile Drawing Nos.___________
Loadings
NESC District __________________
50 yr extreme wind(psf) ___________
Extreme ice load (radial inches)_____
Checked by: __________________________
Ruling Span: _________________________
Conductor: _________________________
Design Tension: ______________________
OHGW: ___________________________
Design Tension: ______________________
Underbuild: ________________________
Sheet Number
PLAN
Design Tension: ______________________
Property Information
Swamps, Rivers, Lakes, etc.
R/W Data, Boundaries
Location of Buildings, Schools, etc.
Other Utilities
Obstructions, Hazards
Roads
Angles, P.I., Bearing of Centerline
PROFILE
Horizontal Span Length
Vertical Span Length
Type Structure
Pole Strength
Pole Height
Pole Foundation Stability
Crossarm Strength
Conductor Clearance:
To Ground or Side Hill
To Support and Guys
To Buildings
Crossing
Conductor Separation
Conductor Tension Limitations
Climbing or Working Space
Guy Tension
Guy Lead and Height
Anchors
Insulator Swing or Uplift
Tap Off, Switches, Substations
Underbuild
Code Requirements
FIGURE 10-7: SAMPLE CHECK LIST FOR REVIEW OF PLAN AND PROFILE
Bulletin 1724E-200
Page 10-16
Blank Page
Bulletin 1724E-200
Page 11-1
11. LOADINGS AND LOAD FACTORS
11.1 General: The strength to be designed into a transmission line depends to a large extent on
wind and ice loads that may be imposed on the conductor, overhead ground wire and supporting
structure. These loadings are related generally to the geographical location of the line.
When selecting appropriate design loads, the engineer should evaluate climatic conditions,
previous line operation experience and the importance of the line to the system. Conservative
load assumptions should be made for a transmission line which is the only tie to important load
centers.
The 2007 NESC indicates that structure and component strength should take into account
temporary loads. Temporary loads imposed on a structure or component may include lifting of
equipment, stringing operations, or a worker on a structure or component. This design manual
does not address temporary loads.
The alternate method in the 2007 NESC has not been included in this design manual. The
alternate method will not be used after July 31, 2010.
11.2 Loads
11.2.1 NESC Loading Districts: The NESC divides the country into three weather or loading
districts, as shown in Figure 11-1.
FIGURE 11-1: NESC LOADING DISTRICTS
Reproduced from IEEE/ANSI C2, 2007, “National Electrical Safety Code,”Copyright 2001 by the
Institute of Electrical and Electronic Engineers, Inc., with permission of the IEEE.
Bulletin 1724E-200
Page 11-2
The minimum design conditions associated with each loading district are given in Table 11-1.
Constants in this table are to be added to the vector resultant for tension calculations only.
TABLE 11-1
ICE, WIND, TEMPERATURE, AND CONSTANTS
Design
Temp.
(Fº)
Radial Ice
Thickness
(inches)
Wind
Loading
Constants
(lbs/ft)
0°
15°
30°
0.50
0.25
0
0.30
0.20
0.05
Extreme Wind
60°
0
Extreme Ice with Concurrent Wind
15°
See Figure
11-3
4 psf
4 psf
9 psf
See
Figure 11-2
See Figure
11-3
NESC Loading
Loading District
Heavy
Medium
Light
NA
NA
Designing to these minimum requirements may not be sufficient. Extreme winds and special ice
conditions should be investigated. Determination of an appropriate design load to account for
extreme winds is easier than determining a heavy ice design load. Meteorological data may be
available on high winds, but little data is available on extreme ice loads. Heavy ice combined
with a relatively high wind should also be considered.
11.2.2 Extreme Ice: In certain areas of the country heavy ice may be predominant. The
engineer should review the experience of utilities or cooperatives in the area of the line
concerning ice conditions. The number and frequency of outages in the area due to ice storms,
and the design assumptions used for existing lines in the area should be examined. From this
data, the engineer can reasonably decide if a heavy ice condition greater than what is required by
the NESC needs to be included in the design.
If historical data on icing conditions is lacking, the engineer should consider designing the line
for extreme wind conditions without ice, and for loading zone conditions. The engineer would
then calculate the maximum ice load the structure could sustain without wind and evaluate this
specific ice condition.
11.2.3 Extreme Winds: Although the NESC requires that structures over 60 ft. sustain high
winds, Rural Utilities Programs recommends that all transmission lines meet extreme wind
requirements. Required values for temperature and wind are listed in Table 11-1 and Figure 112. The NESC allows linear interpolation when considering locations between isotachs. Local
meteorological data should also be evaluated in determining a design high wind speed. For wind
speeds other than a 50 year recurrence interval, refer to Appendix E.
Equations in Tables 250-2 and 250-3 of the NESC have been incorporated in computer programs
as part of the structure analysis. These equations are included in the definitions for the variables
in Equations 11-1 and 11-2 of this bulletin. Tables 11-2, 11-3, 11-4 and 11-5 provide calculated
values for the parameters in these equations.
Bulletin 1724E-200
Page 11-3
Equation 11-1 should be used to calculate the load in the unit wind load on a circular wire in
pounds per linear foot.
p = 0.00256 * V2 * kz * GRF * d / 12
Eq. 11-1
p = unit load per unit foot, lbs./ft.
V = Basic Wind Speed, 3 –second gust wind speed in miles
per hour at 33 ft. above ground with an annual
probability of .02 (50 year return period), Figure 11-2
kZ = Velocity Pressure Exposure Coefficient, shown in
Table 11-2 or by the equation:
kz = 2.01(h/900)(2/9.5) where h = height of the wire at
the structure and is between 33 feet and 900 feet
GRF = Gust Response Factor, shown in Table 11-3 or by the
equation: GRF = [1+(2.7Ew Bw0.5)]/kv2 where
Ew = 0.346 (33/h)1/7 and
Bw = 1/(1+0.8L/220)
kv = 1.43
h = height of the wire at the structure
L = design wind span (also known as HS)
d = diameter of the conductor in inches
TABLE 11-2
WIRE VELOCITY PRESSURE EXPOSURE COEFFICIENT (kZ)
Height of
Wire( ft)
≤ 33
34 – 50
51 – 80
81 – 115
116 – 165
kZ
1.00
1.10
1.20
1.30
1.40
TABLE 11-3
WIRE GUST RESPONSE FACTOR, GRF
Height of Wire At
the Structure
h (ft.)
≤33
34 – 50
51 – 80
81 – 115
116 – 165
Wire, GRF, for Various Span Lengths in feet
251 - 500
501 - 750
751 - 1000
1001 -1500
0.86
0.82
0.80
0.78
0.77
0.79
0.76
0.75
0.73
0.72
0.75
0.72
0.71
0.70
0.69
0.73
0.70
0.69
0.68
0.67
Bulletin 1724E-200
Page 11-4
TABLE 11-4
COMBINED FACTOR kZ*GRF
FOR COMMON WIRE HEIGHTS
Height of Wire At
the Structure
h (ft.)
34 - 50
51 - 80
81 - 115
Wire, GRF, for Various Span Lengths in feet)
251 – 500
501 - 750
751 - 1000
1001 -1500
0.90
0.96
1.01
0.84
0.90
0.95
0.79
0.85
0.91
0.77
0.83
0.88
For simplicity, the designer may wish to use the height of wire to be the height to the overhead
groundwire at the structure.
To calculate the wind load on a structure in pounds, equation 11-2 should be used.
P = .00256 * V2 * kz * GRF * Cf * A
Eq. 11-2
P = wind load in pounds
V = As defined for Equation 11-1
kZ = Velocity Pressure Exposure Coefficient, shown in
Table 11-5 or by the equation:
kz = 2.01(0.67h/900)(2/9.5) where h = height of the
structure above groundline
GRF = Gust Response Factor, shown in Table 11-5 or by the
equation : GRF = [1+(2.7Es Bs0.5)]/kv2 where
Es = 0.346 (33/(0.67-h)1/7 and
Bs = 1/(1+0.8L/220)
kv = 1.43
h = height of the structure above groundline
L = design wind span (also known as HS)
Cf = drag coefficient
A = projected wind area in square feet
TABLE 11-5
STRUCTURE kZ, GRF , and COMBINED kZ GRF Factor
Height of
Structure, ft
kZ
GRF
Combined
’kZ GRF’
factor
≤ 33
0.92
1.02
0.94
34 – 50
1.00
0.97
0.97
51 – 80
1.10
0.93
1.02
81 – 115
1.20
0.89
1.07
116 – 165
1.30
0.86
1.12
Bulletin 1724E-200
Page 11-5
FIGURE 11-2a: EXTREME WIND SPEED IN MILES PER HOUR AT 33 FT. ABOVE
GROUND (50-year mean recurrence interval)
Reproduced with permission from ASCE 7-05, “Minimum Design Loads for Buildings and Other Structures,”
American Society of Civil Engineers, copyright 2005. For further information, refer to the complete text of the
manual (http://www.pubs.asce.org/ASCE7html?999913330).
Bulletin 1724E-200
Page 11-6
Special Wind
Location
Region
Hawaii
Puerto Rico
Guam
Virgin Islands
American Samoa
V mph
105
145
170
145
125
Notes:
1. Values are nominal design 3-second gust wind speeds in miles per hour at 33 ft.
above gound for Exposure C category.
2. Linear interpolation between wind contours is permitted.
3. Islands and coastal area outside the last contour shall use the last wind speed
contour of the coastal area.
4. Mountainous terrain, gorges, ocean promontories, and special wind regions shall be
examined for unusual wind conditions.
FIGURE 11-2b: EXTREME WIND SPEED IN MILES PER HOUR
AT 33 FT. ABOVE GROUND
(50-year mean recurrence interval)
Reproduced with permission from ASCE 7-05, “Minimum Design Loads for Buildings and Other Structures,”
American Society of Civil Engineers, copyright 2005. For further information, refer to the complete text of the
manual (http://www.pubs.asce.org/ASCE7html?999913330).
Bulletin 1724E-200
Page 11-7
Figure 11-2c
Notes:
1. Values are nominal design 3-second gust wind
speeds in mph at 33 ft above ground for
Exposure C category.
2. Linear interpolation between wind contours is
permitted.
3. Islands and coastal area outside the last contour
shall use the last wind speed contour of the
coastal area.
4. Mountainous terrain, gorges, ocean
promontories, and special wind regions shall be
examined for unusual wind conditions.
Figure 11-2d
FIGURES 11-2c,11-2d: EXTREME WIND SPEED IN MILES PER HOUR AT 33 FT.ABOVE
GROUND FOR THE NORTHEAST AND SOUTHEAST
(50-year mean recurrence interval)
Reproduced with permission from ASCE 7-05, “Minimum Design Loads for Buildings and Other Structures,”
American Society of Civil Engineers, copyright 2005. For further information, refer to the complete text of the
manual (http://www.pubs.asce.org/ASCE7html?999913330).
Bulletin 1724E-200
Page 11-8
Notes:
1. Values are nominal design 3-second gust wind
speeds in mph at 33 ft above ground for
Exposure C category.
2. Linear interpolation between wind contours is
permitted.
3. Islands and coastal area outside the last contour
shall use the last wind speed contour of the
coastal area.
4. Mountainous terrain, gorges, ocean
promontories, and special wind regions shall be
examined for unusual wind conditions.
FIGURES 11-2e: EXTREME WIND SPEED IN MILES PER HOUR AT 33 FT ABOVE
GROUND FOR TEXAS, LOUISIANA AND MISSISSIPPI
(50-year mean recurrence interval)
Reproduced with permission from ASCE 7-05, “Minimum Design Loads for Buildings and Other Structures,”
American Society of Civil Engineers, copyright 2005. For further information, refer to the complete text of the
manual (http://www.pubs.asce.org/ASCE7html?999913330).
11.2.4 Extreme Ice with Concurrent Wind Loads: The NESC requires that structures over 60
ft. be designed to withstand the ice and wind loads associated with the Uniform Ice Thickness
and Concurrent Wind Speed specified in NESC Figure 250-3 and in Figures 11-3a to 11-3d of
this bulletin; however, it is recommended that all transmission lines meet these requirements.
Required values for temperature, ice and wind are listed in Table 11-1.
Bulletin 1724E-200
Page 11-9
Fig 11-3e
Fig 11-3f
FIGURE 11-3a: UNIFORM ICE THICKNESS DUE TO FREEZING RAIN WITH
CONCURRENT 3-SECOND GUST WIND SPEEDS (50 yr. mean recurrence)
Reproduced with permission from ASCE 7-05, “Minimum Design Loads for Buildings and Other Structures,”
American Society of Civil Engineers, copyright 2005. For further information, refer to the complete text of the
manual (http://www.pubs.asce.org/ASCE7html?999913330).
Bulletin 1724E-200
Page 11-10
Figure 11-3d
FIGURE 11-3b: UNIFORM ICE THICKNESS DUE TO FREEZING RAIN WITH
CONCURRENT 3-SECOND GUST WIND SPEEDS (50 yr. mean recurrence)
Reproduced with permission from ASCE 7-05, “Minimum Design Loads for Buildings and Other Structures,”
American Society of Civil Engineers, copyright 2005. For further information, refer to the complete text of the
manual (http://www.pubs.asce.org/ASCE7html?999913330).
Bulletin 1724E-200
Page 11-11
FIGURE 11-3c: UNIFORM ICE THICKNESS DUE TO FREEZING RAIN WITH
CONCURRENT 3-SECOND GUST WIND SPEEDS FOR ALASKA
(50 year mean recurrence interval)
Reproduced with permission from ASCE 7-05, “Minimum Design Loads for Buildings and Other Structures,”
American Society of Civil Engineers, copyright 2005. For further information, refer to the complete text of the
manual (http://www.pubs.asce.org/ASCE7html?999913330).
Bulletin 1724E-200
Page 11-12
FIGURE 11-3d: UNIFORM ICE THICKNESS DUE TO FREEZING RAIN WITH
CONCURRENT 3-SECOND GUST WIND SPEEDS FOR LAKE SUPERIOR
(50 yr. mean recurrence)
FIGURE 11-3e: UNIFORM ICE THICKNESS DUE TO FREEZING RAIN WITH
CONCURRENT 3-SECOND GUST WIND SPEEDS FOR FRASER VALLEY DETAIL
(50 yr. mean recurrence)
Reproduced with permission from ASCE 7-05, “Minimum Design Loads for Buildings and Other Structures,”
American Society of Civil Engineers, copyright 2005. For further information, refer to the complete text of the
manual (http://www.pubs.asce.org/ASCE7html?999913330).
Bulletin 1724E-200
Page 11-13
FIGURE 11-3f: UNIFORM ICE THICKNESS DUE TO FREEZING RAIN WITH
CONCURRENT 3-SECOND GUST WIND SPEEDS FOR COLUMBIA RIVER GOUGE
(50 yr. mean recurrence)
Reproduced with permission from ASCE 7-05, “Minimum Design Loads for Buildings and Other Structures,”
American Society of Civil Engineers, copyright 2005. For further information, refer to the complete text of the
manual (http://www.pubs.asce.org/ASCE7html?999913330).
11.2.5 Longitudinal Loads: Unbalanced longitudinal loads on a line may occur because of:
•
•
Unequal wind load and/or differential ice
conditions on equal or unequal spans
Construction and maintenance activities
•
•
•
A broken wire
Stringing loads
A change in ruling span
Traditionally, standard tangent wood pole structures have not been designed for broken
conductor longitudinal loads and have relied on the restraining capacity of deadends. The 2002
edition of the NESC recommends that structures having a longitudinal strength capability be
provided at reasonable intervals along the line.
Several methods to reduce the risk of cascading transmission line structures due to broken wires
have been recommended in the American Society of Civil Engineers (ASCE) Manual and
Report on Engineering Practice No. 74 “Guidelines for Electrical Transmission Line Structural
Loading,” copyright 1991. They are summarized below.
Method 1, Install “Stop” Structures at Specified Intervals: This method consists of placing
deadend structures, longitudinal guys, or regular tangent structures designed to resist deadend
loads at intervals along the line to limit the number of cascading structures to a manageable
number. This method is most practical for H-frames or narrow-based lattice towers which do
not possess enough inherent longitudinal capacity to resist longitudinal loads. In these cases,
stop structures are used because the cost to strengthen each structure to resist cascading may be
high and the addition of guys at each structure may not be desirable.
Bulletin 1724E-200
Page 11-14
Method 2, Install Release Mechanisms: Slip or release-type suspension clamps may be used as
“fuses” to limit the longitudinal loads applied by broken wires. This is actually very similar to
Method 1. The major difference between Method 1 and this Method is that “fuses” are used to
minimize the unbalanced loads used to design each structure. The structures also have to be
capable of withstanding construction and maintenance loads without endangering line crew
personnel. Where heavy ice buildups are frequent, this could be an insurmountable problem.
As such, this method is not recommended in areas of heavy ice, since unbalanced ice loads
could result in unexpected failures.
Method 3, Design All Structures for Broken Wire Loads: Rigid lattice towers, guyed tangents
(guyed in four directions) and single-shaft pole structures have an inherent longitudinal capacity.
In many instances, such structures can be economically designed to resist longitudinal loads.
The loads are typically based on the “residual static load” (RSL). The RSL is a load at a wire
support after breaking one phase or a ground wire under every day conditions (no ice, no wind,
60ºF). Considerations in determining the RSL include insulator swing, structure deflection and
suspension clamp slippage. Some designers have used 60 percent to 70 percent of the every day
tension for conductors and 100 percent of the every day tension for ground wires. The suggested
longitudinal loading consists of applying RSLs in one direction to a nominal one-third of
conductor support points or to one (or both) ground wire support point(s). The suggested
vertical loading consists of one-half or more of the vertical load(s) imposed by the broken
wire(s) along with all of the vertical loads imposed by the other intact wires. Although every
structure is designed to resist cascading, in the event of the catastrophic loss of a single structure,
localized failures in adjacent structures should be expected.
A blend of Methods 2 and 3 would involve designing the main body of the structure (or pole) for
slightly larger longitudinal loads than those used for the design of the support arms and/or
ground wire peak. The idea is to limit the loads applied to the body of the structure (or pole) by
“sacrificing” the arms or ground wire peak, thereby reducing the number of poles damaged from
a broken wire event and decrease the likelihood of an unmanageable cascade. If such a event
occurred, it could result in damage to several (perhaps numerous) support arms and/or ground
wire peaks.
11.2.6 Example of Extreme Wind Calculations: A proposed 161 kV line using the TH-10
structure is expected to have spans ranging from 501 to 900 feet and to be composed of
structures with wood poles 60 to 90 feet high. The line is expected to be located in northern
Mississippi and will have a 795 26/7 ACSR conductor. Calculate the extreme wind load to be
used in the design.
Extreme wind calculations are made for wind on the wires and wind on the structure. For wind
on the wires, the engineer should calculate the wind on the overhead groundwires and the wind
on the conductors. For wind on the overhead groundwires, a review of Table 11-4 indicates that
0.9 to 0.85 is to be used for the combined factor of kZ*GRF’ for spans 501 to 1000 feet and for
wire heights 52 feet to 79 feet above ground (for structures using 60 to 90 foot poles). The
conductors on the TH-10 are located approximately 13 feet from the top of the pole. The height
from the ground to the conductors at the structure will range from 39 to 63 feet above ground. .
For wind on the conductors, review of Table 11-4 indicates that values of 0.9 to 0.79 may be
used as the combined factor of ‘kZ*GRF’ for spans 501 to 900 and for wire heights 39 to 63.
(Poles are 52 feet to 79 feet above ground).
For wind on the structures, use Table 11-5. For structures of heights 52 to 79 feet above ground,
Table 11-5 indicates that the combined ‘kZ*GRF’ factor for the structure is 1.02.
Wind pressure (psf) on the overhead groundwires:
Bulletin 1724E-200
Page 11-15
p = 0.00256 * V2 * kz * GRF
p = 0.00256 * 902 * 0.9
p = 18.66 psf; use 19 psf in design
Wind pressure (psf) on the conductors:
p = 0.00256 * V2 * kz * GRF
p = 0.00256 * 902 * 0.9
p = 18.66 psf; use 19 psf in design
Wind pressure (psf) on the structure:
p = 0.00256 * V2 * kz * GRF
p = 0.00256 * 902 * 1.02
p = 21.15 psf; use 22 psf in design
For 21 psf, the unit trnasverse load on the conductor pt = 1.9390 lbs/ft (Appendix B)
Therefore, for 19 psf, the unit load will be 1.7543 lbs/ft (or 1.9390x19/21)
11.2.7 Example of Extreme Ice/Wind Calculations:
Using the same example line in the previous paragraph (11.2.6), the line located in northern
Mississppi has a combined ice and wind load of .75inch of ice and a 30 psf wind. Calculate the
transverse and vertical unit loads on the conductor.
For the transverse unit load:
The diameter of the conductor including ice = 1.108 in (Appendix B) + (.75x2) = 2.608 in..
The unit wind load on the conductor pt = 30 lbs/ft2 x 2.608 inches/12in/ft x 1ft = 6.520 lbs/ft
For the vertical unit load:
The vertical unit load, wc, is the dead weight of the conductor plus the ice load per foot of
conductor = 1.0940 lbs/ft + [3.1416((1.108+(2x.75))2 – (1.108) 2)/4/144 x 1 ft] x 57 lbs/ft3 =
2.8269 lbs/ft
11.3 Load Factors for New Construction: Agency transmission lines are to be built to
Grade B construction. In Table 11-6, the columns under the Rural Utilities Service headings
give the recommended minimum load factors to be applied to the light, medium, and heavy
loading districts of the NESC and also the recommended strength factors to be applied in the
design of guys, anchors, crossarms, and structures.
Recommended load factors and strength factors to be applied to extreme wind loadings are in
Table 11-7. The factors are intended to take into account approximations made in the design and
analysis.
Bulletin 1724E-200
Page 11-16
11.4 Application of Load Factors and Strength Factors: In the application of the load factors
and strength factors, the objective is to design a structure with resistance greater than the
maximum load expected during the lifetime of the structure and to design the structure with an
acceptable level of safety and reliability. The use of load factors and strength factors can be
expressed as follow:
ØR > (LF)Q
Eq. 11-3
where:
R
=
Ø
Q
LF
=
=
=
measure of material strength or
resistance
a strength factor, less than 1.0
load
load factor, greater than 1.0
‘Ø’ is a multiplier which limits the resistance, R, and accounts for the variability of the resistance
property. ‘(LF)’ is a multiplier that compensates for uncertainty in the load or assumptions made
in the analysis. ‘Ø’ and ‘(LF)’ may be based on statistics, past engineering judgment, past
practice, or may be legislated.
The traditional view of a safety factor (or load factor) may be expressed as ‘LF’ divided by ‘Ø’.
Tables 11-6 and 11-7 are based on the relationship defined in Equation 11-3. In previous
editions of this bulletin, the method using the load factors was used. That method has been
dropped from this bulletin.
11.4.1 Example Calculation Showing the Use of Strength and Load Factors:
A Douglas fir, 80 ft. tangent pole is to sustain a 750 lbs. transverse load two feet from the top.
Assume this load is based on NESC heavy loading district loads. What class pole should be used
for this construction? The pole is embedded 10 feet. The length of the moment arm used to
calculate the induced moment at groundline is 68 feet.
In this case, R is the moment capacity of the pole at groundline and ‘Q’ is the horizontal load
(750 lbs.). Using the strength factors (Ø) and load factors (LF) from Table 11-6, Equation 11-3
becomes:
ØR > (LF)Q
0.65MMoment capacity at the groundline > 2.50(750 lbs)(68 feet)
MMoment capacity at the groundline > 196,154 ft.-lbs
The pole should have a moment capacity of 196 ft-kips at the groundline. A class 3 Douglas fir
pole would provide this moment capacity at the groundline.
11.4.2 Additional Examples Showing the Application of Loads and the Use of Strength and
Load Factors: Chapters 13 and 14 demonstrate the application of strength and load factors in
the structural analyses examples.
Bulletin 1724E-200
Page 11-17
TABLE 11-6
RECOMMENDED LOAD FACTORS AND STRENGTH FACTORS
TO BE APPLIED TO NESC DISTRICT LOADS
(Grade B New Construction)
(NESC Tables 253-1 and 261-1A) (Note 5)
FACTORS
NESC
RUS
1.50
1.50
2.50
1.65
2.50
1.65
1.10
1.65
1.33
1.65
1.00
1.65
1.33
1.65
1.00
0.65
0.65
0.90
1.00
1.00
1.00
0.65
0.50
0.65 (Note 1)
0.65
0.65 (Note 2)
1.00
1.00
LOAD FACTORS
Vertical Loads
Transverse Loads
Wind
Wire Tension
Longitudinal Loads
At crossings
General
Deadends
Elsewhere
General
Deadends
STRENGTH FACTORS (Note 3)
Steel and Prestressed Concrete Structures
Wood Poles (Note 4)
Wood Crossarms (Note 4)
Guy Wire Assemblies
Guy Anchors and Foundations
Guy Attachment Assemblies (includes guy
hardware)
Conductor Support Hardware (Note 6)
Notes:
1. A value different than 0.65 may be used, but should not exceed 0.9.
2. This strength factor of 0.65 may be increased for steel and prestressed concrete poles.
3. It is recognized that structures will experience some level of deterioration after installation.
These strength factors are for new construction.
4. For wood structures, when the deterioration reduces the structure strength to 2/3 of that
required when installed, the wood structure should be replaced or rehabilitated. If the
structure or structure component is replaced, the structure or structure component needs to
meet the strength for the original grade of construction. The rehabilitated portions of the
structures have to be greater that 2/3 of that required when installed for the life of the line.
5. When calculating the additional moment due to deflection, deflections should be calculated
using loads prior to application of the load factor.
6. Conductor Support Hardware is any hardware not a part of the structure, guy assembly, or
guy attachment. Conductor support hardware may be splices, extension links, insulator
string yokes, y-clevis balls, ball hooks, deadend clamps, etc.
Bulletin 1724E-200
Page 11-18
TABLE 11-7
RECOMMENDED LOAD FACTORS AND STRENGTH FACTORS
TO BE APPLIED TO EXTREME WIND LOADS (Rule 250C of the NESC)
AND TO EXTREME WIND/ICE LOADS (Rule 250D of the NESC)
(Grade B New Construction)
(NESC Tables 253-1 and 261-1A) (Note 5)
FACTORS
NESC
RUS
1.00
1.10
1.00
1.00
1.10
1.00
1.00
1.00
1.00
1.10
1.00
1.00
1.00
1.10
1.00
0.75
0.75
0.90
1.00
Not Specified
1.00
0.75
0.65
0.65 (Note 1)
0.65
0.65 (Note 2)
0.80
0.80
LOAD FACTORS
Vertical Loads
Transverse Loads
Wind
Wire Tension
Longitudinal Loads
At crossings
General
Deadends
Elsewhere
General
Deadends
STRENGTH FACTORS (Note 3)
Steel and Prestressed Concrete Structures
Wood Poles (Note 4)
Wood Crossarms (Note 4)
Guy Wire Assemblies
Guy Anchors and Foundations
Guy Attachment Assemblies (includes guy
hardware, bracket and guy attachment
assemblies)
Conductor Support Hardware (Note 6)
Notes:
1. A value different than 0.65 may be used, but should not exceed 0.90.
2. This strength factor of 0.65 may be increased for steel and prestressed concrete poles.
3. It is recognized that structures will experience some level of deterioration after installation.
These strength factors are for new construction.
4. For wood structures, when the deterioration reduces the structure strength to 2/3 of that
required when installed, the wood structure should be replaced or rehabilitated. If the
structure or structure component is replaced, the structure or structure component needs to
meet the strength for the original grade of construction. The rehabilitated portions of the
structures have to be greater that 2/3 of that required when installed for the life of the line.
5. When calculating the additional moment due to deflection, deflections should be calculated
using loads prior to application of the load factor.
6. Conductor Support Hardware is any hardware not a part of the structure, guy assembly, or
guy attachment. Conductor support hardware may be splices, extension links, insulator
string yokes, y-clevis balls, ball hooks, deadend clamps, etc.
Bulletin 1724E-200
Page 12-1
12. FOUNDATION STABILITY OF DIRECT-EMBEDDED POLES
12.1 General: Every structure standing above ground is subjected to lateral forces. In the case
of direct-embedded wood, steel or prestressed concrete transmission structures, it is desirable to
depend on the earth to resist lateral forces. The embedded portion of a pole provides this
resistance by distributing the lateral load over a sufficient area of soil. A properly selected
embedment depth should prevent poles from kicking out. With time, single poles may not
remain plumb. Leaning of single pole structures is sometimes permitted, provided excessive
angular displacements are avoided, pole strength is adequate considering additional loads from
the pole being out of plum and adequate clearances are maintained.
The lateral forces to which wood transmission structures are subjected are primarily forces due
to wind and wire tension loads due to line angles. Longitudinal loads due to deadending or
uniform ice on unequal spans should be examined to see how they affect embedment depths.
Normally, flexible transmission structures are stabilized longitudinally by the overhead ground
wire and phase conductors.
Bearing and lateral earth capacity of soils depend on soil types and soil characteristics such as
internal friction, cohesion, unit weight, moisture content, gradation of fines, consolidation and
plasticity. Most soils are a combination of a cohesive soil (clay) and cohesionless soil (sand).
12.2 Site Survey
12.2.1 Soil Borings: Depending on the transmission line and knowledge of the soil conditions
along the corridor, soil borings may or may not be taken. If the line is composed of H2 or higher
class wood poles, or equivalent strength steel or concrete poles, the engineer may elect to take
soil borings. The decision to take borings will also depend on existing soil information.
Variation of the soil will determine the frequency of the borings. Borings might also be
considered at unguyed angle structures and deadend structures composed of steel or concrete
poles.
12.2.2 Embedment Depths: In deciding embedment depths for many typical agency borrower
wood pole construction, economics dictate that few, if any, soil borings be taken when data and
experience from previous lines are available. Numerous soil conditions will be encountered in
the field. Although the soil conditions may closely resemble each other, the soils may have a
wide range of strengths. The engineer, therefore, has to identify areas or conditions where pole
embedment depths in soil may have to be greater than the minimum depth of 10 percent, plus 2
feet.
Areas where the designer needs to consider additional embedment depths include (but are not
limited to):
•
Low areas near streams, rivers, or other bodies of water where a high water table or a
fluctuating water table is probable. Poles in a sandy soil with a high water table may
"kick" out. Due to the lubricating action of water, frictional forces along the surface area
of embedded poles are reduced. The legs of H-frames may "walk" out of the ground if
neither sufficient depth nor bog shoes are provided to resist uplift. Guy anchors may fail
if the design capacity does not consider the submerged weight of the soil.
•
Areas where the soil is loose such as soft clay, poorly compacted sand, pliable soil, or
soil which is highly organic in nature.
Bulletin 1724E-200
Page 12-2
•
Locations where higher safety is desired. This may be at locations of unguyed small
angle structures where a portion of the load is relatively permanent in nature, or at river,
line, or road crossings.
•
Locations where poles are set adjacent to or on steep grades.
•
Locations where more heavily loaded poles are used.
•
Locations where underground utilities such as water or sewer will be located next to the
pole.
12.2.3 Field Survey: A field survey is necessary in order to judge whether a soil is "good,"
"average," or "poor." There are several economical methods to make a field survey for wood
transmission lines. The engineer may use a hand auger, light penetrometer, or torque probe. The
meaning of terms such as firm, stiff, soft, dense, and loose may not always be clear. Table 12-1
will help to clarify these terms:
TABLE 12-1
CLASSIFICATION OF SOILS BASED ON FIELD TESTS
Term
Very soft
Soft
Firm
Stiff
Very Stiff
Hard
Field Test
Squeezes between fingers when fist is closed
Easily molded by fingers
Molded by strong pressure of fingers
Dented by strong pressure of fingers
Dented only slightly by finger pressure
Dented only slightly by pencil point
Term
Field Test
Loose
Easily penetrated with a 1/2 in. reinforcing rod pushed by
hand
Easily penetrated with a 1/2 in. reinforcing rod driven with
a 5 lb. hammer
Penetrated 1 ft. with a 1/2 in. reinforcing rod with a 5 lb.
Hammer
Penetrated only a few inches with a 1/2 in. reinforcing rod
driven with a 5 lb. hammer
Firm
Dense
Very dense
12.3 Pole Stability
12.3.1 Wood Poles: In addition to local experience with wood poles, the graphs in Figures 12-1
through 12-3 may be used to approximate embedment depths. To use the charts, good, average,
and poor soils have to be defined. The following are proposed as descriptions of good, average,
and poor soils:
Good: Very dense, well graded sand and gravel, hard clay, dense, well graded, fine and coarse
sand.
Average: Firm clay, firm sand and gravel, compact sandy loam.
Poor: Soft clay, poorly compacted sands (loose, coarse, or fine sand), wet clays and soft clayey
silt
Bulletin 1724E-200
Page 12-3
The graphs in Figures 12-1 through 12-3 are based on Equation 12-1:
3.75
S e De
P=
L − 2. − .662 De
Eq. 12-1
where:
P = horizontal force in pounds 2 feet from the top that will
overturn the pole
Se = Soil constant
140 for good soils
70 for average soils
35 for poor soils
De = embedment depth of pole in feet.
L = total length of pole in feet.
Embedment depth can be determined once an equivalent horizontal load 2 feet from the top is
calculated. This horizontal load is calculated by dividing the total ground line moment by the
lever arm to 2 feet from the top of the pole.
Equation 12-1 is taken from "Effect of Depth of Embedment on Pole Stability," Wood
Preserving News, Vol X, No. 11, November, 1932.
Some general observations can be made concerning wood pole embedment depths:
•
The rule of thumb of "10 percent + 2 ft." is adequate for most wood pole structures in
good soil and not subjected to heavy loadings.
•
For Class 2 and larger class poles and poles of heights less than 60 ft., pole embedment
depths should be increased 2 ft. or more in poor soil (single pole structures).
•
For Class 2 and larger class poles and poles of heights less than 40 ft., pole embedment
depths should be increased 1-2 ft. in average soil (single pole structures).
•
For H-frame wood structures, "10 percent + 2 ft." seems to be adequate for lateral
strengths. Embedment depths are often controlled by pullout resistance.
40'
Load 2' from the top (lbs.)
6,000
POOR SOIL
4,000
60'
90'
2,000
0
5
6
7
8
9
Embedment Depth (ft.)
FIGURE 12-1: EMBEDMENT DEPTHS IN POOR SOIL
10
Bulletin 1724E-200
Page 12-4
10,000
Load 2' from the top (lbs.)
40'
8,000
AVERAGE SOIL
60'
6,000
90'
4,000
2,000
0
5
7
6
8
9
10
Embedment Depth (ft.)
FIGURE 12-2: EMBEDMENT DEPTHS IN AVERAGE SOIL
40'
60'
Load 2' from the top (lbs.)
10,000
90'
GOOD SOIL
8,000
6,000
4,000
2,000
0
5
6
7
8
9
10
Embedment Depth (ft.)
FIGURE 12-3: EMBEDMENT DEPTHS IN GOOD SOIL
Bulletin 1724E-200
Page 12-5
FIGURE 12-4: EMBEDMENT CHART FOR MEDIUM DRY SAND
AGENCY BULLETIN 1724E-205 “EMBEDMENT DEPTHS
FOR CONCRETE AND STEEL POLES”
Bulletin 1724E-200
Page 12-6
12.3.2 Direct Embedded Steel and Concrete Poles: In agency Bulletin 1724E-205,
“Embedment Depths for Concrete and Steel Poles,” embedment charts are provided for concrete
and steel transmission poles sustaining relatively large overturning moments. The information in
Bulletin 1724E-205 may be used to approximate embedment depths for cost estimates, to make
preliminary selection of embedment depths and to verify or check selection of embedment
depths based on other or more exact methods. Sample calculations illustrating the use of the
embedment charts and illustrating the use of design methods for those occasions when the charts
cannot be used, are also provided in Bulletin 1724E-205.
In that bulletin, nine embedment charts have been developed for nine soil types. These charts
show embedment depths for pole diameters ranging from 1.0 to 4.0 feet and ultimate moments at
groundline up to 3500 ft-kips. A sample chart for medium sand is shown in Figure 12-4 of this
bulletin.
Several computer programs exist for determining embedment depths for steel and concrete poles.
Such programs may provide a more efficient selection of embedment depths in preliminary
design and their use should be considered in any final design.
12.3.3 Replumbing: If a search of previous experience in an area indicates that single pole
lines have had to be replumbed, there are several methods which should be considered in order
to reduce the frequency of replumbing of a new line to be located in the same area. These
methods are as follows:
•
•
•
•
•
Use a lower grade species of wood in order to increase embedment diameters. For
instance, embedment diameters for Class 1 Western red cedar poles will be greater than
embedment diameters for Douglas fir.
Use aggregate backfill.
Install a pole key with or without a pole toe of crushed stone, gravel, or concrete.
Embed one foot deeper (or more).
In the case of more heavily loaded steel and prestressed concrete poles, consideration
should be given to the use of concrete backfill.
12.4 Bearing Capacity: To prevent a guyed pole from continually sinking into the ground due
to induced vertical loads, the pole butt should provide sufficient bearing surface area. If little
soil information is available, local building codes (Table 12-2) might be helpful in determining
allowable bearing capacities. These values are usually conservative and reflect the hazards
associated with differential deflection in a building. Fortunately, transmission lines can sustain
deflections on the order of several times that of buildings without detrimentally affecting their
performance. The bearing capacity of guyed poles is not as critical as that for buildings. Good
engineering judgment and local experience should be used in determining if bearing capacities of
a certain soil will be exceeded by guyed poles. Table 12-3 suggests ranges of ultimate bearing
capacities.
Bulletin 1724E-200
Page 12-7
TABLE 12-2
PRESUMPTIVE ALLOWABLE BEARING CAPACITIES, ksf
Soil Description
Clay, very soft
Clay, soft
Clay, ordinary
Clay, medium stiff
Clay, stiff
Clay, hard
Sand, compact and clean
Sand, compact and silty
Inorganic silt, compact
Sand, loose and fine
Sand, loose and coarse, or
sand-gravel mixture, or
compact and fine
Gravel, loose, and compact
coarse sand
Sand-gravel, compact
Hardpan, cemented sand,
cemented gravel
Soft rock
Sedimentary layered rock
(hard shale, sandstone,
siltstone)
Bedrock
Chicago
1966
Atlanta
1950
Uniform Building Code
1964
0.5
1.5
2.5
3.5
4.5
6.0
5.0
3.0
2.5
2.0
2.0
4.0
1.5
1.5
2.5
4.0
8.0
1.5
1.5
2.5
8.0
12.0
12.0
8.0
8.0
20.0
30.0
200.0
200.0
TABLE 12-3
SUGGESTED RANGES OF PRESUMPTIVE
ULTIMATE BEARING CAPACITIES, psf*
Specific Description (Dry)
Clay, soft
Clay, ordinary
Clay, stiff
Clay, hard
Sand, loose
Sand, compact and silty
Sand, compact and clean
Hardpan
psf
2000 - 6000
6000 - 9000
12000
15000
4500
9000
15000
40000
General Description (Dry)
Poor Soil
Average Soil
Good soil
1500 - 4000
5000 – 9000
12000 - 18000
Note:
Ultimate values are based on three times allowable. The
values in the table are considered approximate. For more
accurate bearing capacity values, bearing capacity equations
should be used.
Bulletin 1724E-200
Page 12-8
12.5 Uplift: When H-frame structures with X-braces are subject to overturning forces, one leg
will be in compression and one leg in tension. The skin friction assumed in design should be
based on past experience encountered by the engineer, experience of nearby lines, and the results
of the field survey. The following may be appropriate for average soil:
•
If the soil is wet or subject to frequent wettings, an ultimate skin friction not greater than
100 psf should probably be assumed;
•
If native soil is used as backfill, an ultimate skin friction between 100 and 500 psf should
be assumed, provided the soil is not subject to frequent wettings;
•
If an aggregate backfill is used, an ultimate skin friction between 250 and 1000 psf may
be possible;
•
Pole "bearing" shoes increase uplift capacity of a dry hole with natural backfill on the
order of 2 to 2.5 times. The use of aggregate backfill with bearing shoes is usually not
necessary provided the native backfill material is of relatively good material; and
•
In many cases, double cross-braced H-frame structures may require uplift shoes.
12.6 Construction - Backfill: Lateral and uplift resistance of wood poles will depend not only
on type of soil, moisture content of the soil, depth of setting, but also on how well the backfill
has been tamped.
All water should be removed before backfilling. If native backfill material is to be used, it
should be free of grass, weeds, and other organic materials. If the dirt removed from the hole is
too wet or has frozen, dry, unfrozen material should be obtained for the backfill. Where the
earth removed from the hole is unsuitable as backfill, special backfill should be specified by the
engineer. Drawing TM-101 included in agency Bulletins 1728F-810 and 811 suggests a
gradation of aggregate to be used as backfill material.
When backfilling, the soil should be placed and compacted in shallow layers (approximately 6
inch layers). Each layer should be compacted until the tamp makes a solid sound as the earth is
struck. Power tamping is preferred using two power tampers and one shoveler. The importance
of proper compaction of the backfill cannot be overemphasized. Insufficient tamping is a
common source of trouble and has been the cause of some failures.
Bulletin 1724E-200
Page 13-1
13. STRUCTURES
13.1 Economic Study: During preliminary planning stages of lines above 161 kV, studies
should be made to evaluate the economics of different types of structures as related to conductor
size. In most instances, for lines of 230 kV and below, wood structures have historically been
the economical choice. However, in more heavily loaded situations (larger wires, longer spans)
steel and prestressed concrete structures may be more economical than wood, especially
considering the long-term maintenance costs associated with wood structures. In some instances,
other types of material have been used because of environmental or meteorological constraints.
For voltages 345 kV and above, it may be difficult to obtain long span construction utilizing
wood, due to height or strength reasons.
In most instances, for lines 230 kV and below, an economic study can help to determine
structure configuration, base pole class (wood, steel or prestressed concrete) and height.
Factors which limit structure spans include:
a. Strength: Horizontal spans are limited by crossbrace, poles, etc. Vertical spans are limited by
crossarms, structure strength. For H-frame structures, horizontal and vertical spans are also
limited by pullout resistance for H-frame structures.
b. Conductor Separation: Conductor separation is intended to provide adequate space for line
crew personnel on poles, prevention of contact and flashover between conductors.
c. Clearances-to-Ground: Limits on spans are directly related to height of structures.
d. Insulator Swing: The ratio of horizontal to vertical span will be limited by insulator swing and
clearance to structure.
Historically, preliminary cost estimates have been usually based on level ground spans. With the
advent of computer-automated line design and optimization software, preliminary cost estimates
can now be performed using a preliminary profile digitized from the United States Geological
Survey (USGS) topographic maps or from other sources. An economic study should consider
material costs, cost of foundations and erection, different structure heights, hardware costs, and
right-of-way costs. The estimates are intended to give borrowers an idea as to relative rankings
of various structure types and configurations such as steel lattice, steel pole, prestressed concrete
pole, and wood H-frame or single pole. However, in the decision-making process, the manager
may want to consider as part of the evaluation such intangibles as importance of the line to the
power system, appearance, material availability, and susceptibility to environmental attack. In
some areas, State or local constraints may ignore economics and specify the type of structure to
be used.
The level ground span used to develop preliminary cost estimates in the economic study is
determined from clearance-to-ground and structure strength. Developing a graph, as shown in
Figure 13-1, is one means of determining the level ground span (points A and B). Structure cost
per mile can be related to pole height and class of poles as shown in Figure 13-2. To keep the
cost down, the line design should be based on one tangent structure type and one or two pole
classes for the majority of the line. For H-frame structures, the engineer should consider double
crossbraced structures, as well as single crossbraced structures.
With the help of computer automated line design and optimization software, an economic study
can be accomplished almost concurrently with the line design. If a land profile is available, or
developed from USGS maps, the line designer may want to use optimization software to help
Bulletin 1724E-200
Page 13-2
determine the most economic line design. With such software, different structure types and
materials and different conductor types can be evaluated. An advantage of optimization software
is the use of the actual terrain (rather than level ground span) or a good approximation of the
terrain. Optimization algorithms can fit structure height and type to the terrain, and can make
use of different structure heights and configurations. The major disadvantage of optimization
software is that it requires input and analysis of large amounts of data.
Class 1
Span limit due
to strength
Structure per mile or
span length, feet
Class 2
B
A
Span limit due to
conductor sag
Pole height, feet
FIGURE 13-1: SELECTION OF LEVEL GROUND SPAN
Structure costs per mile
36
Class 2(1x)
34
Class 1(1x)
Class 2(2x)
32
30
28
70
80
90
100
110
Pole height, feet
FIGURE 13-2: STRUCTURE COST PER MILE RELATED TO POLE HEIGHT
13.2 Steel and Concrete Structures - General Design Considerations: Rural Utilities Service
provides several bulletins on design considerations for steel and concrete pole structures.
•
•
•
•
1724E-204, “Guide Specifications for Steel Single Pole and H-Frame Structures,”
1724E-214, “Guide Specification for Standard Class Steel Transmission Poles,”
1724E-206, “Guide Specification for Spun, Prestressed Concrete Poles and Concrete Pole
Structures,”
1724E-216, “Guide Specification for Standard Class Spun, Prestressed Concrete
Transmission Poles.”
The bulletins include sample purchase specifications, design considerations, and suggested
drawings and example design calculations.
Bulletin 1724E-200
Page 13-3
13.3 Wood Structures - General Design Considerations
13.3.1 Stress Limitations: The structural stress limitations set forth in Table 13-1 are
recommended for transmission lines using agency standard wood pole construction. These
values assume that the wood has not deteriorated due to decay occurring in the manufacturing
process.
TABLE 13-1
DESIGNATED STRESSES FOR POLES
Kind of Wood
Modulus of
Elasticity x 1000
(psi)
Designated Ultimate
Bending Stress
(M.O.R.)* (psi)
1710
1800
1920
1340
1220
1800
1260
1120
800
8400
8000
8000
6600
6600
6600
6000
6000
4000
Western larch
Southern yellow pine
Douglas fir
Lodgepole pine
Jack pine
Red (Norway) pine
Ponderosa pine
Western red cedar
Northern white cedar
*M.O.R. = Modulus of Rupture
Douglas fir and Southern yellow pine (SYP) are used for crossarms. Southern yellow pine has
four species which are long leaf (most popular species), loblolly, shortleaf, and slash. The coast
type Douglas fir is the only type which should be used when specifying Douglas fir for
crossarms. Table 13-2 gives strength properties to be used in crossarm design.
TABLE 13-2
DESIGNATED STRESSES FOR CROSSARMS
Kind of
Wood
Modulus of
Elasticity x 1000
(psi)
Douglas fir
1920
SYP
1800
*M.O.R. = Modulus of Rupture
Designated Ult.
Bending Stress
(M.O.R.)* (psi)
End Grain Max
Crushing
Strength (psi)
Across Grain
Stress
(psi)
Shear
Parallel to
Grain (psi)
7400
7400
7420
7070
910
1000
1140
1310
13.3.2 Preservative Treatment: The decay of poles results from fungi and other low forms of
plant life which attack untreated poles or poles with insufficient preservative. Damage by insect
attack (termites, ants, and wood borers) is also associated with decay. When preservative
retention is low, wood cannot resist attacks by fungi and insects. There are two general classes
of preservative treatment.
Oil-Borne Using Creosote, Penta and Copper Naphthenate in Petroleum: Creosote oil was the
predominant preservative for poles on rural systems until about 1947. Post-war shortages
prompted the introduction of pentachlorophenol (penta) and copper naphthenate dissolved in the
fuel oils, and other preservatives.
Waterborne Using Arsenates of Copper: Poles using waterborne arsenates of copper (CCA,
ACA and ACZA) are green in appearance. These preservatives were developed before
World War II and have proven very effective as wood preservatives around the world. For
Bulletin 1724E-200
Page 13-4
species and amounts of treatment, refer to agency Bulletin 1728F-700, “Specification for Wood
Poles, Stubs, and Anchor Logs.”
13.3.3 Structure Designations for Single Wood Pole Structures: Single pole wood structures
are mainly limited in use to 115 kV and below. The six primary standard single pole structures
utilized by Rural Utilities Service borrowers are designated as:
•
•
•
•
•
•
TP - pin or post insulators
TPD - pin or post insulators, double circuit
TS - suspension insulators, crossarm construction
TSD - suspension insulators, crossarms, double circuit
TSZ - suspension insulators, "wishbone" arm construction
TU - suspension insulators, steel upswept arm construction
13.4 Design Calculations for Single Wood Pole Structures
13.4.1 Maximum Horizontal Span Limits of Single Wood Pole Structures: The following
conditions should be taken into account when determining horizontal spans as limited by pole
strength for tangent structures:
•
Wind on the conductors and OHGW is the primary load. 75 to 90 percent of the
horizontal span will be determined by this load.
•
Wind on the structure will affect the horizontal span by 5 to 15 percent.
•
Unbalanced vertical load will increase ground-line moments. For single circuit
structures, one phase is usually left unbalanced. The vertical load from the conductor
will induce moments at the groundline and will affect horizontal span lengths by 2 to
10 percent.
•
P-delta (P-δ) moments will also increase induced ground line moments. As a transverse
load is applied to a structure, the structure will deflect. This deflection will offset the
vertical load an additional amount " δ " causing an additional moment of the vertical
weight times this deflection. This additional moment due to deflection is a secondary
effect. An approximate method for taking into account the p-δ moments is given in
section 13.4.2.
For wood structures, depending on the taper of the pole, the maximum stress may theoretically
occur above the ground level. The general rule of thumb is that if the diameter at ground level is
greater than one and a half times the diameter where the net pull is applied, the maximum stress
occurs above the ground level. Even if the point of maximum stress occurs above the groundline
for single base wood pole structures, one can assume that spans are based on groundline
moments in accordance with Exception 1 in NESC Rule 261A.2. Exception 1 states: “When
installed, naturally grown wood poles acting as single-based structures or unbraced multiple-pole
structures, shall meet the requirements of Rule 261A.2a without exceeding the permitted stress
level at the ground line for unguyed poles or at the points of attachment for guyed poles.”
The strength of the crossarm has to be checked to determine its ability to withstand all expected
vertical and longitudinal loads. When determining bending stress in crossarms, moments are
calculated at the through bolt, without considering the strength of the brace. The vertical force is
determined by the vertical span under those conditions which yield the maximum vertical
weight. The strength of two crossarms will be twice the strength of one crossarm. When
considering the strength of the crossarm to withstand longitudinal loadings, reduction in the
moment capacity due to bolt holes should be taken into account.
Bulletin 1724E-200
Page 13-5
Equation 13-1 is the general equation for determining the moment induced in the pole from the
applied loads represented in Figure 13-3. This equation may be used to determine the maximum
horizontal span as demonstrated in the example in Paragraph 13.4.2.
φM A = M g = (LF )M wp + (LF )M wc + (LF )M vo + (LF )M p −δ
Eq. 13-1
where:
φ = strength factor, see Chapter 11
MA = FbS, the ultimate groundline moment capacity of the
pole, ft-lbs. For moment capacities of wood poles at
the groundline, (see Appendix F);
Fb = designated ultimate bending stress (M.O.R.)
S = section modulus of the pole at the groundline (see
Appendix H).
LF = load factor associated with the particular load
Mg = induced moment at the ground line
Other symbols are defined by Equations 13-2, 13-3, 13-4, 13-5.
When estimating the load carrying capacity of a pole using manual methods, it is difficult to
assess the additional moment due to deflection. Equations 13-5 and 13-6 provide an
approximate way to calculate the additional moment due to defection. Because Mp-δ is a
function of the vertical span (VS), the engineer should make an assumption about the
relationship between the vertical and horizontal span (HS). In Equations 13-4 and 13-5, the
relationship used is: VS = 1.25HS.
Pg
Sg
Sc
Pc
Pt
h
hg
Sa
Sb
hc
hl
FIGURE 13-3: TS TYPE STRUCTURE
h a ,h b
A
Refer to Figure 13-3 when considering the equations and symbols that follow.
a. Mwp = groundline moment due to wind on the pole
2
(
F )(2d t + d a )(h )
M wp =
72
where:
F = wind pressure, psf
dt = diameter of pole at top, inches
da = diameter of pole at groundline, inches
h = height of pole above groundline, feet
Eq. 13-2
Bulletin 1724E-200
Page 13-6
b. Mwc = groundline moment due to wind on the wires
M wc = pt (h1 )HS
where:
Eq. 13-3
HS = horizontal span, feet
h1 = moment arm of pt, feet; in the example,
(h )( p ) + (hb )( pc ) + (hc )( pc ) + (hg )( pg )
h1 = a c
Pt
Eq. 13-3a
pt = sum of transverse unit wire loads, lbs/ft; in example,
pt = 3 pc + pg single circuit, single pole structures
c. Mvo = groundline moment due to unbalanced vertical load
Mvo = 1.25HS(wcst + wgsg) + Wist
Eq. 13-4
where:
sg = Horizontal distance from center of pole to ground wire
(positive value on one side of the pole, negative on the
other), feet
st = sa + sb + sc , where sa , sb ,and sc are horizontal
distances from center of pole to conductors (positive
value on one side of the pole, negative on the other),
feet
wc = weight of the conductor per unit length, lbs./ft.
wg = weight of overhead groundwire per unit length, lbs./ft.
Wi = weight of insulators, lbs.
d. Mp-δ = groundline moment due to pole deflection
Mp -δ = 1.25HS(wt)δimp
where:
wt = total weight per unit length of all wires, lbs./ft.
δimp = improved estimate of deflection of the structure, ft.
δ imp
(
⎛ 6.78( pt )(HS )(hc )3144
= ⎜⎜
3
E (d a ) (d1 )
⎝
)⎞⎟δ
⎟
⎠
mag
Eq. 13-5
Eq. 13-6
E = modulus of elasticity, psi
da = diameter of pole at location "A" (groundline), inches
d1 = diameter of pole at height "h1" inches
δmag = deflection magnifier, no units, (assume 1.15 initially)
hc = effective height to the conductors, feet
HS = horizontal span, feet
pt = total transverse load per unit length of all wires, lbs./ft.
Bulletin 1724E-200
Page 13-7
After substitutions of Mwp, Mwc, Mvo, and Mpδ have been made into Eq.13-1, the equation
can be reduced to a quadratic equation (below) and solved for the horizontal span. (See
Paragraph 13.4.2 for an example of how the calculation of HS is carried out.)
a (HS ) + b(HS ) + c = 0
2
Eq. 13-7
− b ± b 2 − 4ac
2a
Once “HS” has been calculated, check the assumption of δmag = 1.15:
HS =
δ mag
Eq. 13-8
1
=
1.25HS (Wt )
1−
Pcr
51.25'
47.5'
40.5'
h l = 44.6 '
40.5'
60'
7.0'
4.5'
(See Chapter 14 for calculations of Pcr)
13.4.2 Example of Maximum Horizontal Spans: Determine the maximum horizontal span for the 69
kV TSS-1 wood structure (Figure 13-4). Terrain is predominantly level, flat, and open. ("sg" is
negligible; see Equation 13-4). Location and magnitude of resultant loads are indicated in Figure 13-5.
Given:
3.75
NESC Heavy Loading
Extreme wind
19 psf on the wires
22 psf on the structure
Extreme Ice with
4 psf, 1 inch radial ice
5.5'
Concurrent Wind(EI&W)
Pole:
Western red cedar
Conductor:
266.8 kcmil,
26/7 ACSR (Partridge)
Ground wire:
3/8"
H.S.S.
Conductor loads, lbs./ft:
Heavy
High Wind
EI&W
Transverse
0.5473
1.0165
.8808
Vertical
1.0776
0.3673
2.402
Ground wire loads, lbs./ft:
FIGURE 13-4: TSS-1 STRUCTURE
Heavy
High Wind
EI&W
Transverse
0.4533
0.5700
.7868
Vertical
0.8079
0.2730
1.9667
Other information:
Fb(pole)
= 6000 psi
pt = 2.10 lb/ft
Fb (crossarm)
= 7400 psi
S(groundline)
= 458 in3
wt
wt = 4.041 lb/ft
S(crossarm)
= 22.7 in3
Wt. of insulator
= 58 lbs.
Dia. (top)
= 8.59 in.
Dia. (groundline) = 16.72 in.
pt(total unit load) = 3(0.5473)+.4533 = 2.10 lbs./ft.
wt(total unit load) = 3(1.0776)+0.8079 = 4.41 lbs./ft
Pcr(critical
17,900 lbs. (see chapter 14 for fix–free
buckling load) =
condition) , l =44.6 ft., E=1.12 E 06 psi
da = 9.63 in., dg = 16.72 in., Ia=422 in4
FIGURE 13-5:
APPLICATION OF FORCES
(HEAVY LOADING)
Bulletin 1724E-200
Page 13-8
Solution for Maximum Horizontal Span Considering P-δ moments: A comparison of unit loads
with load factors indicates that the Heavy Loading District Loads control design. Therefore, for
Heavy Loading, the moments for Equation 13-1 are calculated.
2
4[(2 )(8.59 + 16 .72 )](52 )
a. M wp =
6(12 )
= 5,100 ft − lbs .
b. M wc = (2 )(0.5473 )(40 .5 )HS + (0.5473 )(47 .5 )HS + (0.4533 )(51 .25 )HS
= 93 .5 HS
c. M vo = [(3.75 )(1.0776 ) − .8075 (.5) ]HS (1.25 ) + Wi s t
= 4.45 HS + 217
d M pδ = (1.25 )(HS )(4.041)δ imp
6.78(2.095 )(HS )(44 .6 ) (144 )
3
δimp =
(1.12 E 06 )(16.72 )3 (9.63)
δ imp = .003558 (1.15 )HS
δ mag
δ imp = .0041 HS
M pδ = (1.25 )(4.041)(HS )(.0041)(HS )
= .0207 (HS )
2
e. φM a = ( LF ) M wp + ( LF ) M wc+ ( LF ) M vo + ( LF ) M pδ
(.65)(229, 000) = ( 2.5)(5,100 ) + ( 2.5)(93 .5) HS + 1.5( 4.45) HS + 1.5( 217 ) + 1.5(.0207 ) HS 2
148,524 = ( 2.5)(5,100 ) + (1.5)(187 ) + ( 2.5)(93 .5) HS + 1.5(5.56 ) HS + 1.5(.0207 ) HS 2
.0311 HS 2 + 241.32 HS − 135,820 = 0
f. a (HS ) + b(HS ) + c = 0
2
.0311(HS ) + 241 .32 (HS ) − 135,775 = 0
2
− 241 .32 + 241 .32 2 − 4(.0311 )(− 135,775 )
2(.0311)
HS = 527 feet
HS =
g. Once the HS has been calculated , the assumption of 1.15 as the magnifier
should be checked. Pcr = 17,900 assuming fixed free conditions (See Chapter 14).
δmag =
1
= 1.15
1 - (W t )1.25 HS
Pcr
δmag =
1
1 - (4.0407 )(1.25 )(525 )
17 ,900
.
= 1.175 Recalculat e assuming 1.17 as the deflection magnifier, HS = 529 feet.
Bulletin 1724E-200
Page 13-9
h. Lateral Stability: The Equivalent load 2 feet from the top is approximately 4400 lbs.
From Figure 12-2 (average soil), the embedment depth for a 4400 lb. load 2 feet from the top
is between 8 and 8.5 feet. Lines nearby have performed well with the standard embedment
depths. Engineering judgment dictates that an 8 foot embedment depth for the 60 foot pole
will be sufficient.
13.4.3 Maximum Vertical Span for TP and TS Pole Top Assemblies: To determine the
vertical span, the moment capacity of the arm at the pole is calculated.
Calculations for these structures are:
VS =
where:
Mx-arm
Fb
S
wc
sc
Wi
VS
φM x −arm − (LF )(Wi )(s c )
=
=
=
=
=
=
=
(LF )(wc )(sc )
Eq. 13-9
FbS, moment capacity of the arm, ft-lbs.
the designated bending stress.
the section modulus of the arm (see Appendix G.)
weight of the conductor per unit length, lbs./ft.
moment arm, meters (feet).
insulator weight, lbs.
vertical span, meters (feet).
Example of Vertical Span Calculations for TS Pole Top Assembly (Heavy Loading):
wc = 1.0776 lbs./ft., see Figure 13-4, S = 22.7 in3, φ = .50 and LF = 1.5 Heavy
Loading District,
0.50M a − (LF )(Wi )(s c )
(LF )(wc )(sc )
VS =
a.
M a = Fb S
M a = 7400(22.7 ) / 12
= 14,000 ft − lbs
b.
VS =
Wi = 50lbs.
(0.50)(14,000) − (1.5)(50 )(5.5)
(1.5)(1.0776)(5.5)
= 741 ft.
Check vertical span for extreme ice with concurrent wind,
wc = 2.4092 lbs./ft., φ = 1.0 and LF = 1.1 for extreme ice with concurrent wind
VS =
(1.0)(14,000) − (1.1)(50 )(5.5)
(1.1)(2.4092 )(5.5)
= 939 ft.
Bulletin 1724E-200
Page 13-10
13.4.4 Span Calculations for TSZ Pole Top Assembly: The TSZ structure is a wishbone-type
crossarm assembly. It is intended for use on transmission lines where conductor jumping due to
ice unloading and/or conductor galloping are problems. The wishbone provides additional
vertical and horizontal offset between phases in order to reduce the possibilities of phase-tophase faulting due to ice unloading or galloping.
"a"
S
FIGURE 13-6: TSZ-1 POLE TOP ASSEMBLY
Since the crossarms of the wishbone are not horizontal, the vertical span is related to the
horizontal span. The maximum vertical load (Wc) the TSZ-1single crossarm assembly can
withstand is 3,400 lbs. at any conductor position. By calculating moments at point "a"
on the assembly, horizontal and vertical spans are related. Span limited by pole strength are
calculated in the same manner as the TP and TS structures.
Example of Span Calculations for Wishbone Pole Top Assemblies: Determine the maximum
horizontal and vertical spans for the pole top assembly of the 69 kV TSZ-1 pole top assembly
(Figure 13-7).
Given:
Loadings:
1.5ft
3.22 ft
Wires
Conductor: 266.8 kcmil, 26/7 ACSR (Partridge)
OHGW:
3/8” H.S.S
Pole:
S.Y.P. (70-1)
VERTICAL SPAN (FT.)
"a"
NESC heavy loading district
1200
1100
1000
900
800
400
600
800
1000
HORIZONTAL SPAN (FT.)
FIGURE 13-7: TSZ-1 EXAMPLE
FIGURE 13-8: HS vs. VS FOR TSZ-1
Bulletin 1724E-200
Page 13-11
Solution:
Moment capacity of crossarm at “a”:
Ma = Wc(s)
Ma = 3,400(3.22)
= 10,950 ft-lbs.
Horizontal and vertical span:
The relationship between the horizontal and vertical spans is obtained by summing moments
about point ‘a’.
2.5(.5473)(1.5)HS+1.5(1.0776)(3.22)VS+1.5(50)(3.22) = (0.50)(10,950) ft-lbs.
2.05HS+5.21VS = 5234 ft-lbs.
For HS = VS, Span = 720 ft. See Figure 13-8 for application chart.
13.4.5 Span Calculations for TU-1 Pole Top Assembly: These assemblies have steel upswept
arms. With these arms, vertical spans are related to horizontal spans and a graph can be made to
relate horizontal and vertical spans. Spans limited by pole strength are calculated in the same
manner as the TP and TS structures.
Example of Span Calculations for Steel Davit Arm Construction: For the 138 kV structure in
Figure 13-9, plot the horizontal versus vertical span for steel davit arms.
Given:
Loadings:
7.0'
14'
14'
14'
8.0'
FIGURE 13-9: TU-1 STRUCTURE
NESC Heavy Loading
High Wind 19 psf on the wires
Wires:
Conductor:
OHGW:
Pole:
477 kcmil, 26/7 ACSR
3/8” H.S.S
S.Y.P. (70-1)
Conductor loads:
Transverse
Vertical
Heavy Ldg
0.6193
1.5014
High wind
1.3585
0.6570
Manufacturers catalog data for crossarms:
Rated Ultimate
s, length
R, rise
Vert. load (Wc)
3000
8.0
2.7
3000
7.0
2.5
Weight of insulators (Wi):
102 lbs.
EI&W
0.8808
2.4092
Bulletin 1724E-200
Page 13-12
s
Solution:
For the 8.0' davit arm, the moment capacity
of the arm at the pole (Figure 13-9a):
Ma =
=
=
R
.5'
Wc
Wc(s)
(3000)(8.0)
24,000 ft-lbs.
FIGURE 13-9a: DAVIT
An equation for the vertical and horizontal spans can be developed. Since the arm is steel, a
strength factor ( φ ) of 1.0 is used.
2.5(0.6193)(2.7)HS+1.5(1.5014)(8.0)VS+1.5(102)(8.0) = (1.0)(24,000) ft-lbs.
4.1803HS+18.017VS = 22,776 ft-lbs.
For the 7.0' davit arm, the moment capacity of the arm at pole:
Ma =
=
=
Wc(s)
(3000)(7.0)
21,000 ft-lbs
An equation for the vertical and horizontal spans can be developed:
2.5(0.6193)(2.5)HS+1.5(1.5014)(7.0)VS+1.5(102)(7.0) = (1.0)(21,000) ft-lbs.
3.87HS+15.77VS = 19,929 ft-lbs.
In this example for the NESC heavy loading district loads, the magnitude of the vertical span is
not sensitive to the horizontal span (as shown in Figure 13-10). For horizontal spans between
400 and 1000 feet, the vertical span for the 8 foot arm as well as the 7 foot arm should be limited
to 1018 feet (for design purposes, use 1000 feet). Spans limited by the extreme winds are not a
factor in this example.
VERTICAL SPAN (FT.)
1200
8.0 ft. arm
1100
7.0 ft. arm
1000
900
800
400
600
800
1000
HORIZONTAL SPAN (FT.)
FIGURE 13-10: VS vs. HS FOR TUS-1 STRUCTURE OF EXAMPLE 13-3
Bulletin 1724E-200
Page 13-13
13.5 Design Calculations for Wood H-Frame Structures
13.5.1 General: There are various techniques available for analysis of H-frame structures:
•
•
•
Classical indeterminate structural analysis.
Matrix methods of structural analysis.
Approximate methods (explained in this section and subsequent sections).
In analyzing a statically indeterminate structure by approximate procedures, one assumption is
made for each degree of indeterminacy. These assumptions are based on logical interpretations
of how the structure will react to a given loading. For the H-frame with knee and V-braces, we
can assume that the structure will behave as shown in Figure 13-11.
Outside
Kneebraces
B
F
E
Crossbraces
D
C
A
FIGURE 13-11: ASSUMED H-FRAME BEHAVIOR
At some point in the poles, there will be an inflection point (a point of zero moment). If the pole
or column is uniform in cross section, it is common to assume that the inflection point is located
midway between points of bracing, shown as a dotted line in Figure 13-11. However, since the
pole is tapered, the following relationship may be used to determine the location of the inflection
point (see Figure 13-12, Equation 13-10 and Appendix H for application chart).
CD
xo
C A (2C A + C D )
=
x 2 C A 2 + C AC D + C D 2
(
X
CA
)
Eq. 13-10
where:
Xo
CA = circumference at base
CD = circumference at top
FIGURE 13-12: LOCATION OF POINT
OF CONTRAFLEXURE
By applying the same reasoning, the inflection point can be located on the other column.
Locating the inflection point on each column, and hence the point of zero moment, entails
two assumptions for the frame. Since the frame is statically indeterminate to the third degree, a
third assumption has to be made. A common third assumption is that the shear in the columns is
Bulletin 1724E-200
Page 13-14
distributed equally at the inflection points. The shear in the columns is equal to the horizontal
force on the structure above the level under consideration.
For a less rigid support, the inflection point moves toward the less rigid support. Two
conclusions can be made:
•
For a pole rotating in the ground, the inflection point "C" below the crossbraces, is
lowered. The lowering of the inflection point inreasing the moment induced in the
pole at the connection of the lower crossbrace. Since the amount of rotation of a base
is difficult to determine, the usual design approach is to always assume a rigid base.
•
For H-frames with outside kneebraces only, the point of inflection ‘F’above the
crossbrace (shown in Figure 13-11) is higher than the point of inflection for four
kneebraces. This higher point of inflection increases the moment in the pole at the
upper crossbrace-pole connection. For the H-frame with outside kneebraces only, the
designer may make one of two assumptions:
(1) When determining induced moments in the poles, the outside kneebraces are
ignored and no point of inflection exists between the crossbrace and the crossarm.
This is a conservative assumption and assumes that the purpose of outside braces
is to increase vertical spans only.
(2) It can be assumed that the point of inflection occurs at the crossarm. This
assumption will be used in the equations and examples which follow.
13.5.2 Crossbraces: The primary purpose of wood X-bracing for H-frame type structures is to
increase horizontal spans by increasing structure strength. Additional benefits achieved by
crossbracing include possible reduction of right-of-way costs by eliminating some guys and
reduction of lateral earth pressures. For an efficient design, several calculations should be made
in order to correctly locate the crossbrace.
The theoretical maximum tensile or compressive load which the wood crossbrace will be able to
sustain will largely be dependent on the capacity of the wood brace to sustain a compressive
load. Drawing TM-110, X-brace Assembly of Bulletins 1728F-810 and 811, is to be used for the
115, 138, 161 kV, and 230 kV tangent structures. The crossbrace dimension is 3-3/8" x 4-3/8"
for the 115 kV structure, 3-3/8" x 5-3/8" for 138 kV and 161 kV structures. The dimensions of
this X-brace for the TH-230 structure are 3-5/8" x 7-1/2" (minimum).
The maximum compressive load which a wood X-brace is able to sustain is determined by:
Aπ2 E
Pcr =
Eq. 13-1145
2
⎛ kl ⎞
⎜ ⎟
⎝ r ⎠
where:
Pcr = maximum compressive load, lbs.
A = area, in2
E = modulus of elasticity, psi.
kℓ = effective unbraced length, in.
r = radius of gyration, in. which will give you the
maximum kℓ/r ratio; kℓ and r must be
compatible for the same axis
FIGURE 13-13: CROSSBRACE
( )
Bulletin 1724E-200
Page 13-15
For an assumed 1 foot diameter pole, the following theoretical values apply:
TABLE 13-3
CROSSBRACE CAPACITIES
Crossbrace
TM-110
3-3/8" x 4-3/8"
3-3/8" x 5-3/8"
TM-110A
3-5/8" x 7-1/2"
A
Area
(in2)
r
Least Radius
of
Gyration (in.)
L
Distance
CL to CL
of Poles (ft.)
0.5L/0.707
less 1’ for
Pole Dia.,
(in.)
kl
r
Pcr for
E = 1.8 x 106
(lbs.)
14.77
18.14
0.9743
0.9743
12.5
15.5
97.6
123.1
100.2
126.3
26,100
20,200
27.19
1.05
19.5
157
149.5
21,600
The calculations included in Table 13-3 do not reflect the capacity of the hardware. RUS
Specifications for Double Armed and Braced Type Crossarm Assemblies (138 kV and 161 kV),
and RUS Specifications for Double Armed and Braced Type Crossarm Assemblies (230 kV)
require X-braces to withstand a tension or compression loading of 20,000 lbs. This ultimate
value correlates with the above theoretical ultimate loads in the table. It is recommended that
20,000 lbs. (ultimate) be used for design purposes, since this value assures one that the
crossbrace will sustain the indicated load.
For the 115 kV structure (TH-1AA) it is recommended that 20,000 lbs. be used as the ultimate
load the crossbrace is able to sustain. The hardware for the crossbrace is the same as
the hardware used with 138 kV and 161 kV structures.
13.5.3 V-Braces: The primary purpose of two V-braces on the outside of the poles is to
increase vertical spans. Two V-braces on the inside will increase horizontal spans. Four Vbraces increase both horizontal and vertical spans. The various bracing arrangements and their
designations for 161 kV structures are shown in Figure 13-14.
TH-10
TH-10X
TH-10VIX
TH-10VOX
TH-10V4X
FIGURE 13-14: POLE TOP BRACING ARRANGEMENTS
(‘X’ added to the pole top assembly nomenclature refers to crossbrace)
RUS Specifications for Double Armed and Braced Type Crossarm Assemblies (138 kV and
161 kV) specifies the following minimum strength requirements for the various pole top
assemblies:
Maximum vertical load (at any conductor position)
TH-10
8,000 lbs.
TH-10VO
14,000 lbs.
TH-10V4
14,000 lbs.
Bulletin 1724E-200
Page 13-16
Maximum transverse conductor load (total)
TH-10VO
15,000 lbs.
TH-10V4
15,000 lbs.
Maximum tension or compression in V-brace
20,000 lbs.
RUS Specifications for Double Armed and Braced Type Crossarm Assemblies (230 kV)
specifies the following minimum strength requirements for the TH-230 pole top assembly:
Maximum vertical load (at any conductor position)
TH-230
10,000 lbs.
Maximum transverse conductor load (total)
TH-230
15,000 lbs.
Maximum tension or compression in V-brace
TH-230
20,000 lbs.
When determining maximum vertical and horizontal spans as limited by H-frame top assemblies,
the above minimum strengths may be used as guidance.
13.5.4 Structure Analysis of H-frames: Equations 13-16 to 13-22 are used for calculating
forces in the various members of H-frame structures. As part of the structural analysis, span
limitations due to strength of the pole top assembly (Equations 13-12 to 13-15) should be
considered and suggested methods follow. Appropriate load factors and strength factors should
be applied in the respective equations.
Outside V-Braces: An H-frame structure with two outside V-braces in figure 13-14 (and shown
in greater detail in Figure 13-19) needs further explanation. A structure with two outside Vbraces has less rigidity above the crossbrace than a structure with than four V-braces. The
location of the point of contraflexure is difficult to determine. Equation 13-10, which calculates
the moment (ME) at the top of the crossbrace assumes that the point of contraflexure exists at the
crossarm. However, when using Equation 13-12 to determining span limitations due to strength
of the pole top assembly, a point of contraflexure is assumed between the top of the crossbrace
and the crossarm.
The maximum vertical span is determined for the maximum horizontal span.
Pt
b
Wt
a
o
FIGURE 13-15: POLE TOP ASSEMBLY WITH TWO OUTSIDE BRACES
Bulletin 1724E-200
Page 13-17
Ultimate force in the brace is:
( LF )Wt ( LF ) Pt (a )
+
≤ (φ )20,000 ⋅ lbs
(b )sin α
sin α
where:
Eq. 13-12
Wt = total vertical load at the phase wire, locations, lbs.,
Wt = VS(wc)+Wi,
VS = vertical span, ft.
wc = weight load per foot of conductor, lbs./ft.
Wi = total weight of the insulators, lbs.
Pt = total transverse load, lbs.
Pt = (HS)(3pc+2pg) where
HS = horizontal span, ft.
pc = wind load per foot of conductor, lbs./ft.
pg= wind load per foot of overhead ground wire, lbs./ft.
a = distance from the point of contraflexure to equivalent force, ft.
b = distance between poles, ft.
LF = load factor
α = angle the brace makes with the crossarm
Two Inside V-Braces: Pole bending moment, uplift, and force in the X-brace may be calculated
in the same manner as when four braces are used. Crossarm strength controls the maximum
vertical span.
Force in the braces is:
( LF )Wt ( LF ) Pt (a )
+
≤ (φ )20,000.lbs
(b )sin α
2 sin α
Eq. 13-13
Crossarm bending moment, (φ ) M o is:
(φ ) M o =
( LF )Wt (b )
2
Eq. 13-14
Pt
a
o
b
Wt
FIGURE 13-16: POLE TOP ASSEMBLY WITH INSIDE BRACES
Bulletin 1724E-200
Page 13-18
Four V-Braces: The following equations can be used to determine the maximum vertical span as
limited by four V-braces, given the maximum horizontal span:
For four V-braces, force in the outside braces is:
( LF )Wt
≤ (φ )20,000 lbs
sin α
Eq. 13-15
Force in the inside braces is:
( LF )Wt ( LF ) Pt (a )
+
≤ (φ )20,000 lbs
(b )sin α
2 sin α
from Eq. 13-13
13.5.5 Abbreviations: In Equations 13-16 to 13-23, all units should be consistent. The
following abbreviations apply:
De
F
Fs
HS
Ma
Mn
=
=
=
=
=
=
LF
Qu
Rn
U
V
Vn
VS
Wc
Wg
Wi
Wl-p
Wp
Wt
=
=
=
=
=
=
=
=
=
=
=
=
=
W1 =
W2
X
Y
a
=
=
=
=
b =
davg =
dbt =
dn =
dt =
embedment depth
wind pressure on a cylindrical surface, psf
presumptive skin friction value, psf
horizontal span, ft.
moment capacity of crossarm
moment capacity at the indicated location ‘n’, ft-lb.
includes moment reduction due to bolt hole,
i.e., Mn = Mcap-Mbh.
load factor (see Chapter 11 of this bulletin)
ultimate bearing resistance of the soil, psf
reaction at the indicated location,"n," lbs.
dummy variable
dummy variable
induced axial force at the indicated location, lbs.
vertical span, ft.
weight of conductors (plus ice, if any),lbs.
weight of OHGW (plus ice, if any),lbs.
total weight of the insulators
weight of a line person
weight of pole, lbs.
total weight equal to weight of conductors (plus ice, if
any, WC) plus weight of insulators,Wi.
total resistance due to skin friction around the
embedded portion of the pole, lbs.
total bearing resistance of the soil, lbs.
dummy variable
dummy variable
distance from Pt to the point of contraflexure above the
crossbrace for an H-frame structure with pole top
bracing. Ft.
spacing of the poles of an H-frame, ft.
average diameter of pole between groundline
and butt, ft.
diameter of pole at butt, ft.
diameter at location "n,” ft.
diameter of pole at top, ft.
Bulletin 1724E-200
Page 13-19
fs = calculated skin friction value, psf
hn = length as indicated, ft.
Pt = total horizontal force per unit length due to wind on the
conductors and overhead ground wire, lbs./ft.
sn = distance as shown, ft.
wc = weight per unit length of the conductors (plus ice, if
any), lbs./ft.
wg = weight per unit length of overhead ground wire (plus
ice, if any), lbs./ft.
φ = strength factor (see Chapter 11 of this bulletin)
13.5.6 Equations for Structure 1 (Figure 13-17): For this structure, the horizontal span is
reduced by 10 % to take into account P-delta (P-δ)moments (i.e. 0.90 in Equation 13-16). For a
more detailed analysis, see Equation 13-1 for single poles.
⎛
(LF )(F )(h )2 (2d t + d a ) ⎞⎟ ⎛ (LF )( pt )(h1 ) ⎞
HS A = ⎜⎜ (φ ) M A −
⎟(0.90)
⎟ / ⎜⎝
6
2
⎠
⎝
⎠
R A = ( LF )(W g + 3 / 2Wt + W p )
VS =
Wt
Eq. 13-17
(φ ) M a − (LF )(Wi )(s )
wc (s )(LF )
B
Eq. 13-18
B
Wt
S
Pt
Wt
h
A
Eq. 13-16
A
b
FIGURE 13-17: STRUCTURE 1
h
l
Bulletin 1724E-200
Page 13-20
13.5.7 Equations for Structure 2 (Figure 13-18):
⎛
(LF )(F )( y1 )2 (2d t + d b ) ⎞⎟
( )
HS B = ⎜⎜ (φ ) M B −
⎟ / (LF ) p g ( y1 )
6
⎝
⎠
2
⎛
(LF )(F )( y ) (2d t + d e ) ⎞⎟ (LF )( pt )( y o )
HS E = ⎜⎜ (φ ) M E −
⎟/
6
2
⎝
⎠
(LF )(F )(h − xo )(x1 )(d t + d c ) ⎞ (LF )( pt )(x1 )
⎛
HS D = ⎜ (φ ) M D −
⎟/
2
2
⎝
⎠
(LF )(F )(h − xo )(xo )(d t + d c ) ⎞ (LF )( pt )(xo )
⎛
HS A = ⎜ (φ ) M A −
⎟/
2
2
⎝
⎠
Eq. 13-19a
Eq. 13-19b
Eq. 13-19c
Eq. 13-19d
For crossbrace:
(
)
HS x = (φ )28,300(b ) − 2(LF )(F )(h − xo ) (2d t + d c ) / 6 / (LF )( pt )(h2 )
Eq. 13-19e
HS ( pt )(h2 ) − VS (wg )(b ) − 1.5VS (wc )(b ) = W1 (b ) + W p (b ) + X − Y
Eq. 13-19f
2
For uplift:
For bearing:
HS ( pt )(h2 ) + VS (wg )(b ) + 1.5VS (wc )(b ) = W2 (b ) − W p (b ) + X − Y + (w1 )(b ) Eq. 13-19g
where:
W1 = Fs (De )(d avg )π / S .F .
(
)
Eq. 13-19h
W2 = π d bt / 4 (Qu ) / S .F .
Eq. 13-19i
X = (F )(h − xo )(d t + d c )( xo )
Eq. 13-19j
Y = 2(F )(h ) (2d t + d a ) / 6
Eq. 13-19k
2
2
y
y 1
B
B
E
E
Pt
yo
h2 h1
h
D
D
C
C
A
A
x1
xo
b
FIGURE 13-18: STRUCTURE 2
Bulletin 1724E-200
Page 13-21
13.5.8 Equations for Structure 3 (Figure 13-19):
(LF )(F )( y1 )(z )(d t + d b ) ⎞ (LF )( pt )(z )
⎛
HS E = ⎜ (φ ) M E −
⎟/
2
2
⎝
⎠
Eq. 13-20
HSD, HSA = same as structure #2.
For crossbrace, uplift and bearing: same as structure #2
y
y
1
z
B
E
y
1
Pt
B
E
y
z1
B
F
B
F
zo
E
E
h2 h1 h
x1
xo
b
A
D
D
C
C
x1
C
C
a
h2 h1 h
D
D
Pt
xo
A
b
A
FIGURE 13-19: STRUCTURE 3
A
FIGURE 13-20: STRUCTURE 4
13.5.9 Equations for Structure 4 (Figure 13-20):
(LF )(F )( y − z o )(d t + d f )(z1 ) ⎞ (LF )( pt )(z1 )
⎛
⎟⎟ /
HS B = ⎜⎜ (φ ) M B −
2
2
⎠
⎝
Eq. 13-21a
(LF )(F )( y − z o )(d t + d f )(z o ) ⎞ (LF )( pt )(z o )
⎛
⎟⎟ /
HS E = ⎜⎜ (φ ) M E −
2
2
⎝
⎠
Eq. 13-21b
HSD, HSA = same as structure #2.
For uplift and bearing: same as structure #2.
For crossbrace:
HS x = ((φ )28,300(b ) − U + V ) /[(LF )( pt )(h2 − a )]
where:
2
U = 2(LF )(F )(h − x o ) (2d t + d c ) / 6
V = 2(LF )(F )( y − z o ) (2d t + d f ) / 6
2
Eq. 13-21c
Eq. 13-21d
Eq. 13-21e
Bulletin 1724E-200
Page 13-22
13.5.10 Equations for Structure 5 (Figure 13-21):
For crossbrace:
(
)
HS x = (φ )56,500(b ) − 2(LF )(F )(h − xo ) (2d t + d c ) / 6 /[(LF )( pt )(h2 )]
2
yo
Pt
Eq. 13-22
a
z1
Pt
z0
h2 h1 h
h2 h1 h
x1
x1
xo
x
0
b
FIGURE 13-21: STRUCTURE 5
b
FIGURE 13-22: STRUCTURE 6
13.5.11 Equations for Structure 6 (Figure 13-22):
For crossbrace:
HS x = ((φ )56,500(b ) − U + V ) /[(LF )( pt )(h2 − a )]
where:
U, V = same as structure #4
Eq. 13-23
Bulletin 1724E-200
Page 13-23
13.6 Example of an H-frame Analysis: For the 161 kV structure shown in Figure 13-23,
determine the horizontal span based on structure strength and uplift and plot the horizontal
versus vertical span for the pole top assembly.
.75"
d t = 7.96"
B
3.52'
7.5'
db= 8.81"
df = 9.19"
5.56'
2.19'
7.0'
F
E
3.98'
70'
15.5'
de = 9.65"
D
15.3'
dd = 11.33"
dc = 13.00"
Pt
C
39.25'
23.95'
15.5'
A
da = 15.64"
FIGURE 13-23: EXAMPLE OF AN H-FRAME
13.6.1 Given:
NESC heavy loading
High winds 19 psf on the wires and
22 psf on the structure
Heavy ice 1" radial ice
Extreme ice with
1” radial ice with 4 psf wind
concurrent wind
Pole:
Conductor:
OHGW:
Ruling Span:
Douglas fir 80-2
ACSR 795 kcmil 26/7
7/16 E.H.S.
800 ft.
Conductor Loads
Transverse Loads
Vertical Loads
Tension
Heavy Ldg District
0.7027 lbs./ft.
2.0938 lbs./ft.
10,400 lbs.
High Wind
1.7543 lbs./ft.
1.0940 lbs./ft.
---
Heavy Ice
0
3.7154 lbs./ft.
14,000 lbs
EI&W
1.0360
3.7154
OHGW Loads
Transverse Loads
Vertical Loads
Tension
Heavy Ldg District
0.4783 lbs./ft.
0.9803 lbs./ft.
5,900 lbs.
High Wind
0.6888 lbs./ft.
0.3990 lbs./ft.
---
Heavy Ice
0
2.1835 lbs./ft.
7,500 lbs.
EI&W
.8116
2.1835
Soil: Average. Presumptive skin friction (ultimate) of 250 psf for predominantly dry soil areas
and using native backfill; 500 psf when aggregate backfill is used.
Bulletin 1724E-200
Page 13-24
13.6.2 Solution for Heavy Loading District Loads: Maximum horizontal span based on structure
strength:
a. Equivalent load pt :
pt = 2 pg + 3 pc
= 2(0.4783) + 3(0.7027)
= 3.065 lbs / ft.
b. Determine location of equivalent load pt :
Distance from top =
2 pg (0.75) + 3 pc (7.75)
pt
= 5.56 ft.
c. Determine location of xo, x1, z0 and z1 for the X - brace location shown.
All diameters, d n , determined by Appendix F, and ratio xo /x1 or zo /z determined by Appendix H.
For xo , x1 :
d d 11.33
=
= 0.72
d a 15.64
xo
= 0.61
x
xo = 0.61(39.25)
∴
xo = 23.9 ft.
x1 = 15.3 ft.
and d c = 13.0 in.
For zo , z1 :
d d 8.81
=
= .91
d e 9.65
zo
= 0.53
z
zo = 0.53(7.5)
∴
zo = 3.98 ft.
z1 = 3.52 ft.
and d f = 9.19 in.
Bulletin 1724E-200
Page 13-25
d. Find the horizontal span limited by pole strength at B (see Figure 13 - 23) using Equation 13 - 21a :
(LF )(F )( y − z o )(d t + d f )(z1 ) (LF )( pt )(z1 )
HS B = (φ ) M B −
/
2
2
a. M B = 44,700 ft − lbs.
2.5(4 )(15.25 − 3.98)(0.663 + 0.766 )(3.52 ) ⎞ ⎛ 2.5(3.065)(3.52 ) ⎞
⎛
b. HS B = ⎜ (0.65)44,700 −
⎟ /⎜
⎟
2
2
⎝
⎠ ⎝
⎠
= 2,133 ft.
e. Horizontal span limited by pole strength at E :
(LF )(F )( y − z o )(d t + d f )(z o ) (LF )( pt )(z o )
HS E = (φ ) M E −
/
2
2
a. M E = M cap − M bh
M E = 58,800 − 8,400 ft. − lbs.
M E = 50,400 ft. − lbs
( M bh from Appendix F)
⎛
2.5(4 )(15.25 − 3.98)(0.663 + 0.766 )(3.98) ⎞ ⎛ 2.5(3.065)(3.98) ⎞
⎟⎟
b. HS E = ⎜⎜ (0.65)(50,400) −
⎟ /⎜
2
2
⎠ ⎝
⎝
⎠
= 2,127 ft.
f. For horizontal span limited by pole strength at locations D and A,
similar calculations can be made. The results are as follows :
HS D = 811 ft.
HS A = 1664 ft.
g. For horizontal span limited by strength of the crossbrace :
HS X = ((φ )28,300(b ) − U + V ) /[(OLF )( pt )(h2 − a )]
where :
U = 2(LF )(F )(h − xo ) (2d t + d c ) / 6
2
V = 2(LF )(F )( y − z o ) (2d t + d f ) / 6
2
U = 2(2.5)(4 )(70 − 23.9 ) (2(0.663) + 1.083) / 6
= 17,065 ft − lbs.
2
V = 2(2.5)(4 )(15.25 − 3.98) (2(0.663) + .766 ) / 6
= 885 ft − lbs.
HS X = [(0.65)28,300(15.5) − 17,065 + 885] /[(2.5)(3.065)(34.78)]
2
= 1009 ft.
Bulletin 1724E-200
Page 13-26
13.6.3 Solution for Heavy Loading District Loads - Maximum span limited by pole top
assembly follows:
a. From Equation 13 - 15.
( LF )Wt (VS )
≤ (φ )20,000.lbs
sin α
10,000 sin 39° − 1.5(135)
VS =
2.0938(1.5)
= 1938 ft.
b. From Equation 13 - 13 :
( LF )Wc (VS ) ( LF ) pt (a )(HS )
+
≤ (φ )20,000 lbs.
2 sin α
b sin α
1.5(2.0938)(VS ) 2.5(3.065)(2.19 + 3.52 )(HS )
+
≤ (0.50)20,000 lbs.
2sin39°
15.5sin39°
2.49VS + 4.48HS ≤ 10,000 lbs.
(For VS equal to the HS, the vertical span is 1,435 ft.)
13.6.4 Solution for Heavy Loading District Loads - Maximum span limited by uplift follows:
Assume dry native backfill, safety factor of 4.
HS ( pt )(h2 ) − VS (wg )(b ) − 1.5VS (wc )(b ) = W1 (b ) + W p (b ) + X − Y
where :
W1 = Fs (D )(d avg )π / SF
= 2649 lbs.
Wp = Wt. of one pole and half the weight of pole top assembly and crossbrace.
= 4200 + 800 / 2 = 4600 lbs.
X = F (h − xo )(d t + d c )( x o )
= 7705 ft − lbs.
( )
Y = 2(F ) h 2 (2d t + d a ) / 6
= 17,182 ft − lbs.
The equation is as follows :
124.13HS − 63.88VS = 102,900
(For VS = 0, maximum HS = 830 ft.)
Bulletin 1724E-200
Page 13-27
13.6.5 Check for extreme ice and concurrent wind: Span limitations based on pole strength and
crossbrace strength is controlled by NESC Heavy Loading conditions. The unit conductor loads when
load factors and strength factors accounted for, are greater for the Heavy Loading District load than for
the EI&W as shown below:
NESC
> EI&W
Transverse load:
7027(2.5)/.65 > 1.0360/.65 lbs/ft
2.7027 > 1.5938 lbs/ft.
Vertical load:
NESC
> EI&W
2.0938(1.5)/.65 > 3.7154 lbs/ft
4.8318 > 3.7154 lbs/ft
13.6.6 Check for Extreme Wind Conditions: Although span limitations based on pole strength and
crossbrace strength is controlled by NESC Heavy Loading conditions, span limitations based on uplift is
controlled by the extreme wind condition.
For Dry Native Backfill: For an assumed safety factor of 1.5, the following equation result:
222.2HS - 25.4VS = 142,862
(For VS=0, maximum HS=640 ft.)
For Aggregate Backfill: For an assumed safety factor of 1.5, the following equation results:
222.2HS - 25.4VS = 252,400
(For VS=0, maximum HS=1,135 ft.)
When considering uplift, it may be prudent to base calculations on the minimum vertical span as
limited by insulator swing.
13.6.7 Summary of Span Limitations:
Horizontal Span limits:
HSA = 1664 ft.
HSD = 811 ft.
HSE = 2127 ft.
HSB = 2133 ft.
HSx = 1009 ft.
Dry native backfill:
For a VS = 0, the HS (limited by uplift) = 640 ft.
Aggregate backfill:
For a VS = 0, the HS (limited by uplift) = 1,135 ft.
Vertical Span limited by Heavy District Loads:
VSpoletop = 1,435 ft., max. (For VS =HS)
A more efficient design could be achieved by moving the crossbrace.
Bulletin 1724E-200
Page 13-28
Blank Page
Bulletin 1724E-200
Page 14-1
14. GUYED STRUCTURES
14.1 Introduction: When a pole structure is guyed, loading on the poles is due to the combined
action of vertical and horizontal forces. Vertical forces on the pole include the vertical
component of the tension on the guy(s) and the weight of the conductors and insulators.
Horizontal forces include transverse due to wire tension at angle structures, horizontal wind
forces, and vertical and longitudinal forces from deadending.
Bisector guys are used on small angle structures, whereas head and back guys are used on large
angle structures and double deadends. Angles between 10 and 45 degrees may be turned on
what is called a “running” angle structure, utilizing bisector guys. Above 45 degrees, unequal
stresses will be set up in the conductor where it attaches to the suspension insulator clamp. The
sharper the angle or bend in the conductor at the clamp, the more unequal the stresses will be.
Any unbalanced longitudinal wire tensions loads on double deadend and large angle structures
can be more effectively carried by head and back guys. For large angle structures, the transverse
load due to wire tension loads will be a heavy and permanent. Therefore, head and back guys
will be more effective in carrying this load.
Figure 14-1 shows a deadend structure in which the conductors are connected to the structure by
strain insulators.
FIGURE 14-1: DEADEND STRUCTURE
(Head and back guys shown)
Deadend structures include:
•
•
Ordinary deadend structures that need only be designed to withstand the load resulting
from the difference in tensions of the conductor for the forward and back spans. This
condition occurs where there is a change in ruling spans.
Full deadend structures in which guys and anchors are designed to withstand the resultant
load when the conductors are assumed to be broken or slack on one side of the structure.
As mentioned in Chapter 10, it is suggested that full deadend structures be located at
intervals of five to ten miles to prevent progressive cascading-type failures.
In general for wood structures, guys and anchors should be installed at deadends, angles, long
spans where pole strength is exceeded, and at points of excess unbalanced conductor tension.
The holding power and condition of the soil (whether wet or dry, packed or loose, disturbed or
undisturbed, etc.) and the ability of the pole to resist buckling and deflection should be
considered. Unguyed steel and concrete pole structures are sometimes used at angles and
deadends to avoid the use of guys. In these cases, careful consideration needs to be made of the
structure and foundation design and deflection.
Bulletin 1724E-200
Page 14-2
14.2 Load Factors: In Chapter 11, Tables 11-6 and 11-7 give recommended minimum load
factors (LF) associated with the design guys and anchors. Table 14-1 summarizes the
application of the load factors and strength factors for guys and anchors.
TABLE 14-1
APPLICATION OF LOAD AND STRENGTH FACTORS FOR GUYED STRUCTURES
(GUYS AND ANCHORS)
Loading Districts:
NESC
(2.50)(a+b)
+ 1.65c
= G cosβ ≤ (0.9)Gu cosβ
Recommended
(2.50)(a+b)
+ 1.65c
= G cosβ ≤ ( φ )Gu cosβ
(See table 11-6 of
this bulletin for φ )
Extreme Winds and Extreme Ice with Concurrent Winds:
NESC
(1.00)(a+b)
+ 1.00c
= G cosβ ≤ (0.9)Gu cosβ
Recommended
(1.10)(a+b)
+ 1.100c
= G cosβ ≤ ( φ )Gu cosβ
Where:
a
b
c
Au
G
Gu
φ
cosβ
=
=
=
=
=
=
=
=
(See table 11-7 of
this bulletin for φ )
Transverse wind load on the conductor
Transverse wind load on the pole
Transverse component of wire tension load.
Rated anchor capacity
The calculated force in the guy, considering guy lead. The rated breaking
strength of the guy wire (Gu) and the anchor capacity (Au) multiplied by
their respective strength factor must equal or exceed this value.
Rated breaking strength of the guy wire
Strength factor; see table 11-7 of this bulletin
Guy slope with horizontal groundline
14.2.1 Longitudinal Strength: Longitudinal strength is applicable to crossings and locations
where unequal spans and unequal vertical loadings may occur. Required longitudinal strength of
wood tangent structures at crossings is defined by NESC Rule 261A2. The rule states that wood
tangent structures which meet transverse strength requirements without guys, shall be considered
as having the required longitudinal strength, provided that the longitudinal strength of the
structure is comparable to the transverse strength of the structure. If there is an angle in the line,
the wood structure will have the required longitudinal strength provided:
•
•
•
The angle is not over 20 degrees,
The angle structure is guyed in the plane of the resultant conductor tensions, and
The angle structure has sufficient strength to withstand, without guys, the transverse
loading which would exist if there were no angle at that structure (with the appropriate
load factors and strength factors applied).
14.2.2 Distribution Underbuild: Guying and anchors for distribution underbuild are to comply
with NESC Grade B provisions. Refer to Chapter 16 for additional information concerning
underbuild.
14.3 Clearances: Recommended clearances to be maintained between any phase conductor and
guy wires are indicated in Table 14-2. Refer to Chapter 7 for further details.
Bulletin 1724E-200
Page 14-3
TABLE 14-2
RECOMMENDED MINIMUM CLEARANCES IN INCHES
FROM CONDUCTOR TO SURFACE OF STRUCTURE OR TO GUY WIRES (Note A)
Nominal Voltage, Phase to Phase,kV
Standard Number of 5-3/4”x10”
Insulators on Tangent Structures
Max. Operating Voltage, Phase to
Phase, kV
Max. Operating Voltage, Phase to
Ground, kV
34.5
46
69
115
138
161
230
3
3
4
7
8
10
12
34.5
46
72.5
120.8
144.9
169.1
241.5
19.9
26.6
41.8
69.7
83.7
97.6
139.4
Wind Condition
NO WIND CLEARANCE
Min. clearance to guy at no wind
(Notes A, B)
Clearance, in.
19
19
25
42
48
60
71
9
11
16
26
30
35
50
MODERATE WIND CLEARANCE
(based on NESC Rule 235E, Table
235-6)
Min. clear. to structure at 6 psf of
wind (Notes C, D)
Min. clear. to jointly used structures
and a 6 psf of wind (Notes C,
D)
Min. clearance to anchor guys at
6 psf (Notes C, D)
11
13
18
28
32
37
52
13
16
22
34
40
46
64
HIGH WIND CLEARANCE
Min. clearance to guys at high wind
3
3
5
10
12
14
20
Notes:
(A) If insulators in excess of the standard number for tangent structures are used, the no-wind
clearance value given should be increased by 6 in. for each additional bell. For instance, extra
insulation in the form of additional insulator bells may be used on steel structures where
grounding is a problem or the structures are located in high isokeraunic areas. In these
instances, the no wind clearances should be increased. If excess insulators are needed for
contamination purposes only, the additional clearance is not necessary
(B) For post insulators, the no-wind clearance to structure or guy is the length of the post
insulator.
(C) A higher wind may be assumed if deemed necessary.
(D) The following values should be added as appropriate where the altitude exceeds 3300 feet
Additional inches of clearance per 1000 feet of altitude above 3300 feet:
Nominal Voltage, KV
Clearance to structure
Clearance to guy
34.5
0
0
46
0
0
69
0.14
017
115
0.43
0.53
138
0.57
0.72
161
0.72
0.90
230
1.15
1.44
Bulletin 1724E-200
Page 14-4
14.4 Design
14.4.1 Bisector Guys: For structures utilizing bisector guys, the guys have to be designed to
sustain the resultant transverse load due to longitudinal wire tension loads in Table 14-1:
c =2 (T) (Sin θ/2)
where:
T = maximum design tension, lbs.
θ = line angle
The transverse load (a) due to wind on the conductors for an angle structure is given as:
a = (p) (HS) (cos θ/2)
where:
p = wind load in lbs./ft.
HS = horizontal span, ft.
θ = line angle; cos θ/2 is usually set equal to one
Wind on the structure may be converted to a horizontal force (b) at the point of guy attachment.
14.4.2 Head and Back Guys: Wood pole deadends, double deadends, and large angle
structures will normally require head and back guys. For tangent deadends and double deadends,
the transverse strength of the structure must be sufficient to carry the appropriate wind load. In
some cases, bisector guys or crossbraces may have to be used to meet transverse strength
requirements. The tension in the guy should take into account the slope of the guy.
14.5 Pole Strength: Once the tension in the guy wire has been calculated, the compressive
strength of the pole should be calculated and checked to see if the pole selected will be adequate
for the intended use.
14.5.1 Stability Concept: The selection of structural members is based on three characteristics:
strength, stiffness, and stability. When considering a guyed wood, steel or concrete pole, it is
important that the designer check the stability of the structure for the expected loadings.
For an example of stability, consider the axial load carrying capabilities of the rods in
Figure 14-2. The rod on the left is unquestionably “more stable” to axial loads than the rod on
the right. Consideration of material strength alone is not sufficient to predict the behavior of a
long slender member. As an example, the rod on the right might be able to sustain 1000 lbs axial
load when considering strength (ultimate compressive stress times area), but could only sustain
750 lbs. when considering stability of the system. The rod on the right is more likely to become
laterally unstable through sidewise buckling.
FIGURE 14-2: COMPARISON OF RODS TO SHOW
STABILITY CONCEPT
a
b
Bulletin 1724E-200
Page 14-5
14.5.2 Critical Column Loads: In transmission structures, the guyed pole acts as a column,
sustaining axial loads induced in the pole from vertical guy components. The taller the pole, the
less load the guyed pole can sustain in compression before the structure becomes “unstable”.
Stability of a column can be thought of in one of two ways:
a. The column is unstable when the axial force would cause large lateral defections even
when the lateral load was very small.
b. When a column subjected to an axial force, a small deflection may be produced. The
column is considered stable if the deflection disappears when the lateral force is removed,
and the bar returns to its straight form. If the axial force (P) is gradually increased, a
condition is reached in which the straight form of equilibrium becomes unstable and a
small lateral force will produce a deflection which does not disappear when the lateral
force is removed. The “critical” load is then the axial force which causes buckling or
collapses due to any bowing or lateral disturbance.
14.5.3 Calculation of Buckling Loads: For long slender columns, the critical buckling load is
determined by the general equation:
π EI
2
Pcr =
where:
Pcr
E
I
kl
(kl) 2
=
=
=
=
(Pcr is independent of the yield
stress of the material).
critical buckling load, lbs. or kips
modulus of elasticity, psi
moment of inertia, in4
the effective unbraced length of the column; kl
depends on restraint end conditions of the
column.
Where for the various end conditions of the column, Pcr is idealized in Figure 14-3 below:
P
P
P
a
b
c
FIGURE 14-3: EFFECTIVE UNBRACED LENGTH FOR VARIOUS END CONDITIONS
Bulletin 1724E-200
Page 14-6
Assumptions made in the above calculations:
•
•
•
•
•
The column is perfectly straight initially.
The axial load is concentrically applied at the end of the column.
The column is assumed to be perfectly elastic.
Stresses do not exceed the proportional limit.
The column is uniform in section properties.
14.5.4 Buckling of Guyed Steel and Concrete Poles: For guyed steel and concrete poles, all
the assumptions in paragraph 14.5.3 are violated. As such, the engineer will often ask the pole
manufacturer to check the axial capacity of the pole. The engineer must give the pole
manufacturer information concerning guy size and strength, yield stress, guy locations, and guy
leads. In the case of steel poles, the pole manufacturer should also check the capacity of the guy
attachments. It is recommended that in the case of concrete poles, the pole manufacturer should
design the guy attachment or at least check the capacity of the pole and attachment when the
owner has selected the hardware.
14.5.5 Buckling of Guyed Wood Poles: For a guyed wood poles, all the assumptions in
paragraph 14.5.3 are also violated. As such, the engineer must apply appropriate safety factors
to account for realistic cases and the variability of wood. Equations for buckling of a wood
column with no taper follow:
Fixed – Free End
Figure 14-3a
Conditions
For a column with no
taper
P cr =
π 2 EI
4l
2
Fixed – Pinned End
Figure 14-3b
Pcr =
2π 2 EI
l2
Pinned – Pinned End
Figure 14-3c
Pcr =
π 2 EI
l2
One method of calculating the buckling capacity of a tapered wood column was developed by
Gere and Carter. This method modifies the critical buckling load as follows:
Pcr = PA P ∗
⎛d
P = ⎜⎜ g
⎝ da
where:
PA
∗
α
⎞
⎟⎟
⎠
E
IA
dg
= Critical load for a uniform column with circular cross
sections having diameter d (at guy attachment), lbs.
= A multiplier dependent on the end conditions of the
column, lbs.
= Modulus of Elasticity, psi
= Moment of Inertia at the guy attachment, in4
= Diameter at the groundline, in.
da
= Diameter at the point of guy attachment, in.
P∗
= Distance from the groundline to the point of guy
attachment, in.
α = An exponent that is a function of shape of the column
l
For tapered round columns, the equations become:
Bulletin 1724E-200
Page 14-7
Conditions
Fixed – Free End
For a tapered column
(circular cross section)
π EI A ⎛ d g
⎜
Pcr =
4 l 2 ⎜⎝ d a
2
⎞
⎟⎟
⎠
2.7
Fixed – Pinned End
2π EI A ⎛ d g
⎜⎜
Pcr =
l2
⎝ da
2
⎞
⎟⎟
⎠
2.0
Pinned – Pinned End
π EI A ⎛ d g
⎜
Pcr =
l 2 ⎜⎝ d a
2
⎞
⎟⎟
⎠
2.0
When using the Gere and Carter method for the NESC district loads with load factors, strength
factors between 0.65 to 0.5 respectively are recommended. The resulting safety factor will be
between 2.5 and 3.0. For extreme wind loads, it is recommended that strength factors between
0.65 and 0.5 be used, resulting in a safety factor between 1.5 and 2.0. For deadends, lower
strength factors (or higher safety factor) should be used.
14.5.6 General Application Notes: For unbraced guyed single poles at small and medium
angles structures using bisector guys, certain assumptions are made as to the end constraints. In
the direction of the bisector guy, the structure appears to be pinned at the point of the guy
attachment and fixed at the base. However, 90° to the bisector guy, the structure appears to be a
cantilevered column. Since the conductors and phase wires offer some constraint, the actual end
conditions may be assumed to be between fixed-free and fixed-pinned (Figure 14-4a). When
checking buckling, it is suggested that the end conditions of pinned-pinned be assumed.
Buckling Mode
Longitudinally
Transversely
End Conditions
Bisector Guyed
In-Line Guyed
pinned-pinned
pinned-fixed
pinned-fixed
pinned-fixed
Bisector Guyed Structure
FIGURE 14-4a
In-line Guyed Structure
FIGURE 14-4b
FIGURE 14-4: END CONDITIONS FOR BISECTOR AND IN-LINE GUYED STRUCTURES
For in-line guyed poles at medium angles and large angle deadends, the structure appears to be
pinned at the point of guyed attachment and fixed at the base in both directions (Figure 14-4b).
For in-line guyed poles at tangent deadends without side guys, it is suggested that fixed-free be
assumed.
In many instances, axial loads are applied intermittently along the pole. In Figure 14-5a, the
static wire and phase wire are guyed at their respective locations. The axial loads acting on the
pole on the left are applied as shown in Figure 14-5b.
Bulletin 1724E-200
Page 14-8
In such instances, the usual engineering practice is to assume an unbraced length from the
groundline to the lowest guy attachment and the induced axial load in the pole equal to the sum
of all axial loads included by the vertical component of the guys.
a
b
FIGURE 14-5: AXIAL LOADS INDUCED IN A POLE
When the structure is considered to be a double deadend or large angle, the poles, guys, and
anchors must sustain the full deadend load with an appropriate load factor. For the tangent
double deadend shown in Figure 14-6, the poles must sustain the maximum axial load which
might occur if all phase conductors on one side of the structure were removed (see Figure 14-6a
and 14-6b). However, to “double account” the loads, as shown in Figure 14-6c would be too
conservative.
a
b
c
FIGURE 14-6: REPRESENTATION OF AXIAL LOADS (a & b)
AND DOUBLE ACCOUNTING LOADS (c)
For wood pole lines, deadends and large angle structures will often require a higher class pole
than that used as the base class pole for the line. Ways to control or reduce the pole class needed
at deadends and large angles include:
•
Relocate and/or increase the height of tangent structures adjacent to guyed angle and
deadends. This would allow the use of shorter poles with guyed structures, and as a
result would allow use a lower class pole with no sacrifice in safety.
•
Decrease the guy slope. This will decrease the vertical load component pole.
Bulletin 1724E-200
Page 14-9
As a note, angle and deadend structures usually comprise about 5 percent of the total structures
of a line. Use of conservative safety factors for these critical structures results in a greater
overload margin without significantly affecting the total cost of the transmission line.
The engineer should consider guying single pole structures used for small angles, even if the
pole has adequate strength to carry the load. Wood poles have a tendency to “creep” with time
when subjected to a sustained load. For steel or concrete poles, the engineer should also
consider the use of guyed poles at angles or deadend structures. Use of guys will prevent
unguyed steel and concrete poles from having large diameters at the groundline and will reduce
the cost of foundations.
14.6 Anchors: The holding power of the anchor will largely depend on whether the soil is wet
or dry, packed or loose, disturbed or undisturbed. Since soils vary considerably between
locations, the holding power of an anchor will also vary considerably.
In areas with a fluctuating water table, the capacity of the anchors should take into account the
submerged unit weight of the soil. If at any time the holding power of an anchor is questionable
due to variable soil conditions, the anchor should be tested. The primary types of anchors
include log anchors, plate anchors, power screw anchors, and rock anchors. The selection of the
appropriate anchor will largely depend on the type of soil condition.
14.6.1 Log Anchor Assemblies: The two log anchors in the construction drawings (agency
Bulletins 1728F-810 and 811, units TA-2L and 4L) are 8″ x 5′ - 0″ and 8″ x 8′ - 0″, and have an
ultimate holding power of 16,000 lbs. and 32,000 lbs. These logs, using one or two anchor rods
may be used in combination to provide sufficient holding power for guys. “Average” soil is
considered to be medium dense, coarse sand and stiff to very stiff silts and clays. Log anchors
should be derated or should not be used in soils of soft clay, organic material, saturated material,
or loose sand or silt.
14.6.2 Plate Anchors: The plate anchor assembly TA-3P in Bulletins 1728F-810 and 811, is
rated at an ultimate holding power of 16,000 lbs and 24,000 lbs. In firm soils, where the
engineer would like to minimize digging, plate anchors may prove economical.
14.6.3 Power Screw Anchors: Screw anchors are being used more often because of their easy
installation. They are most appropriate for locations where firm soils are at large depths. The
screw anchor assembles TA-2H to TA-4H of Bulletins 1728F-810 and 811 should be installed
per manufacturer’s recommendations. In addition to the anchor unit being shown on the plan
and profile, the capacity of the screw anchor should also be shown. Screw anchors have a higher
safety factor than other types of anchors. This higher safety factor is reflected in Information
Bulletin 202-1, “List of Materials Acceptable for Use on Systems of USDA Rural Development
Electrification,” by a reduced designated ultimate holding capacity (70 percent of the
manufacturer’s suggested holding capacity).
14.7 Drawings: A summary drawing should be prepared for each line, showing the
arrangement of guys for each type of structure to be used. The drawing will greatly facilitate the
review of the plan and profile, and simplify the construction of the line.
Guys required for various line angles are based on certain spans. Since actual spans will vary,
the guying requirements shown will not be suitable for all conditions. Sometimes, it is desirable
to make a guying guide for each angle structure which relates horizontal span to the angle of the
line (see the example, paragraph 14.8).
Bulletin 1724E-200
Page 14-10
The Guying Guide drawing also shows (1) points of attachment of the guy to the pole, (2) slope
of the guys, (3) type of structure, and (4) guys and anchors required.
14.8 Example: Develop guying guides for TH-12 161 kV structure.
14.8.1 Design Parameters
General Loading and Structure Information:
NESC Heavy Loading
Extreme Wind:
Heavy Ice:
Extreme Ice with
Concurrent winds
19 psf on wires,
1” radial
1” radial
Pole:
Conductor:
Overhead ground wire:
Ruling Span:
Guy Wire:
Douglas fir 80-2
795 kcmil 26/7 ACSR
7/16” E.H.S.
800 ft.
7/16” E.H.S.
22 psf on the structure
4 psf
Conductor Loads, lbs/ft:
Transverse
Vertical
Conductor
tensions
Heavy
0.7027
2.0938
10,400 lbs.
High Wind
1.7543
1.0940
NA
Heavy Ice
High Wind
0.6888
0.3990
NA
Heavy Ice
0
3.7154
12940 lbs.
EI&W
1.0360
3.7154
13240 lbs.
Overhead Ground Wire loads, lbs/ft:
Transverse
Vertical
OHGW
tensions
Heavy
0.4783
0.9804
5,900 lbs.
0
2.1835
7,500 lbs.
EI&W
.8116
2.1835
7800 lbs.
Guy wire: 7/16” E.H.S.
Ultimate tension (R.B.S.):
Horizontal strength with 1/1 lead:
20,800 lbs.
14,700 lbs.
Anchors: 8,000 lbs. and 16,000 lbs.
Ultimate Capacity:
Horizontal strength with 1/1 lead:
16,000 lbs. and 32,000 lbs.
11,300 lbs. and 22,600 lbs.
Soil: Average, presumptive ultimate bearing capacity approximately equal to 4000 psf.
Bulletin 1724E-200
Page 14-11
14.8.2 Solution for Heavy Loading District:
a. Wind on the wires:
Conductor:
a = .7027 (HS) (cos θ/2)
OHGW:
a = .4783 (HS) (cos θ/2)
b. Wind on the pole:
b = 143 lbs.
Here (b) is based on an 80-2 pole with the guy located 60 ft. from the ground. The
equivalent horizontal load (b), at this location is determined by Mwp/lever arm.
b = 8590 ft.-lbs./60 ft.
c. Wire tension loads:
Conductor:
OHGW:
c = 2(10,400) sin θ/2
c = 2(5,900) sin θ/2
d. Equations from Table 14-1 of this bulletin:
General Equation:
2.50(a+b) +1.65c = Gcosβ ≤ .65Gucosβ or
2.50(a+b) +1.65c = Gcosβ ≤ .65Aucosβ
For one conductor:
2.50 [(.7027) (HS) (cos θ/2) + (143)] + 1.65 [2(10,400) (sin θ/2)] ≤ .65Gu (or Au) cosβ
358 + (1.757) (HS) (cos θ/2) + 34,320 (sin θ/2) ≤ .65Gu cosβ or ≤ .65Aucosβ
550 + (2.703) (HS) (cos θ/2) + 52,800 (sin θ/2) ≤ Gu cosβ or ≤ Aucosβ
For one OHGW:
2.50 [(.4783) (HS) (cos θ/2) + (neg.)] + 1.65 [2(5,900) (sin θ/2)] ≤ .65Gu (or Au) cosβ
(1.196) (HS) (cos θ/2) +(19,470) (sin θ/2) ≤ .65Gu cosβ or ≤ .65Aucosβ
(1.840) (HS) (cos θ/2) +(29,954) (sin θ/2) ≤ Gu cosβ or ≤ Aucosβ
Case 1: Using 1 guy wire and 1 anchor for the three conductors and 1 guy wire and 1 anchor for
both OHGW, the following general equations result (1/1 leads).
For the 3 conductors:
3(550) + 3(2.703)(HS)(cos θ/2) + 3(52800)(sin θ/2) ≤ Gu cosβ or ≤ Aucosβ
1650 + 8.109 (HS)(cos θ/2) + (158,400)(sin θ/2) ≤ 14,700 lbs.(for guy)
1650 + 8.109 (HS)(cos θ/2) + (158,400)(sin θ/2) ≤ 11,300 lbs. (for anchor)
For the 2 OHGW’s:
2(1.840)(HS)(cos θ/2) + 2(29,954)(sin θ/2) ≤ Gu cosβ or ≤ Aucosβ
3.680(HS)(cos θ/2) + (59,908)(sin θ/2) ≤14,700 lbs. (for guy)
3.680(HS)(cos θ/2) + (59,908)(sin θ/2) ≤11,300 lbs. (for anchor)
Case 2: Using 2 guy wires and 2 anchors for the three conductors and 1 guy wire and 1 anchor
for both OHGW, the following general equations result (1/1 leads).
For the 3 conductors:
1650 + (8.109)(HS)(cos θ/2) + (158,400)(sin θ/2) ≤ (2)14,700 lbs. (for guy)
Bulletin 1724E-200
Page 14-12
1650 + (8.109)(HS)(cos θ/2) + (158,400)(sin θ/2) ≤ (2)11,300 lbs. (for anchor)
For the OHGW: (same as above)
See the Guying Guide at the end of this example for plots of controlling equations.
e. Checking for buckling of the poles. Since the outside poles carry the maximum axial load, it
is necessary only to examine this pole. Longitudinal buckling is considered since this condition
is the critical case. Weight of the conductor and OHGW is included in the calculations.
The following example calculations are for Case 1 above.
The maximum axial load which various poles can sustain can be calculated for various heights of
structures. The Gere and Carter method is used to calculate Pcr below:
Pole
Class &
Height
60-1
60-2
60-3
80-1
80-2
80-3
Unbraced Length, ℓ
Ground to Lowest
Guy Attachment,
ft.
42
60
dg
da
in.
in.
15.03
14.09
13.15
16.72
15.64
14.55
9.83
9.14
8.44
9.76
9.05
8.35
IA
At Point da
(πd4/64)
in4
458
343
249
445
329
239
π EI A ⎛ d g
⎜
Pcr =
l 2 ⎜⎝ d a
2
⎞
⎟⎟
⎠
2.0
pinned-pinned assumed
lbs.
79935
60733
45108
47784
35948
26485
Assuming that horizontal spans are equal to the vertical span, the previous equations in item d
above be revised to include the weight of the conductor and OHGW on the outside pole. The
total axial load in the pole is the sum of the axial loads induced in the pole from guying the three
conductors and two OHGW, and the vertical weight of the OHGW and conductor. Half of the
vertical load from the outside phase is carried by the middle pole and other half is carried by the
outside pole. For this example, since the guy leads are 1 to 1, the vertical axial load from the
guy wire will be equal to the horizontal component of the guy wire.
Cond.
OHGW
Total
Wire Weight + Induced Axial Load, Guying 3 conductors and 2 OHGW’s
1.5(.5)(2.0938)HS+
8.109(HS)(cos θ/2)
+1652 +158,400(sinθ/2)
1.5(.9804)HS + 3.680(HS)(cos θ/2)
+ 59,908(sinθ/2)
(3.0401)HS + 11.789(HS)(cos θ/2)
+1652 +218,300(sinθ/2)
≤ .65Pcr
Bulletin 1724E-200
Page 14-13
GUYING GUIDE
Structure:
Conductor Type:
OHGW Type:
Guy Wire Type
TH – 12
795 26/7
7/16 ״E. H. S.
7/16 ״E. H. S
Ruling Span
Max. Tension (L, M, H):
Max. Tension (L, M, H):
Ultimate Strength
Heavy Loading District
pC: 0.7027 lbs./ft.
wC: 2.0938 lbs./ft.
800 ft.
10,400 lbs.
5,900 lbs.
20.800 lbs.
pg: 0.4783 lbs/ft.
wg: 0.9804 lbs/ft.
20°
Line Angle
15°
9ft.
1
1
10°
80
-2
D
80
-3
TG-11A
TG-11C
Case 2
F
60
-2
DF
DF
5°
Case 1
60
-3
0
200
400
600
800
1000
1200
1400
80
-1
D
TA-3P
or
2-TA-3P
F
DF
1600
1800
2000
Horizontal Span
Line Angle chart/drawing
Case 1
For OHGW:
For conductor:
TG - 11A, TA - 3P
TG - 11A, TA - 3P
Case 2
For OHGW:
For conductor:
TG – 11A, TA-3P
TG – 11C, (2)TA - 3P
Total guys and anchors:
(2) TG - 11A
(2) TA - 3P
Total guys and anchors:
1 - TG – 11A
1 - TG – 11C
3 - TA – 3P
Limitation:
Limitation:
TA-3P to conductor
TA - 3P to conductor
TA-3P
8 ft.
Bulletin 1724E-200
Page 14-14
Blank Page
Bulletin 1724E-200
Page 15-1
15. HARDWARE
15.1 General: Hardware for transmission lines can be separated into conductor-related
hardware and structure-related hardware.
Conductor-Related Hardware: For many transmission lines, the conductor may constitute the
most expensive single component of investment. Yet, this is the one component which is most
exposed to danger and most easily damaged. In the design of any line, appropriate emphasis
should be given to mechanical and electrical demands on the design of conductor-related
hardware used to support, join, separate, and reinforce the overhead conductor and overhead
groundwire. Conductor motion hardware is used to diminish damage to the overhead conductors
from vibration. Selection and proper installation of conductor accessories will have considerable
influence on the operation and maintenance of a transmission line. Electrical, mechanical, and
material design considerations are generally involved in the design of conductor support
hardware and conductor motion hardware.
Structure Related Hardware: This includes any hardware necessary to frame a structure, to
accommodate guying and other types of pole attachments to the structure and to provide
necessary conductor-to-structure clearances. As structure–related hardware items are the
connecting pieces for structural members, proper selection of this hardware is necessary to
assure structure strength. At the same time, proper selection of structure-related hardware
includes use of designs that are static proof or incorporate static proof aids to help minimize
possible radio and television interference emanations from the line (see Appendix I).
Selection of conductor-related and structure-related hardware should consider corrosion and the
damage and degradation of strength and visual esthetics that corrosion can cause. In addition to
selecting hardware made of materials that are less likely to corrode, the designer should be
certain that the materials selected are compatible with one another and will not corrode when in
contact with each other.
15.2 Conductor-Related Hardware
15.2.1 Suspension Clamps: Contoured suspension clamps are designed to match the conductor
diameter in order to guard against conductor ovaling and excessively high compressive stresses
on the conductor. Suspension clamps may be made from galvanized malleable iron or forged
steel. Aluminum liners are recommended for aluminum conductors. Copper liners are
recommended for copper conductors only. The connector fitting will usually be either a socket
or clevis (see Figure 15-1). When using clamps with liners on conductors covered by armor
rods, designers should select clamps that have the proper seating diameter for the effective
diameter of the conductor and armor rod. Liners can be expected to add 1/10 inch to the
conductor diameter. There are a few clamps made for large line angles (up to 120o). However,
these clamps are available only for small conductor sizes. When a transmission line with large
conductors has to make a turn along its route, strain clamps should be used. In the case of
medium angles (greater than a 30 degree line angle) double suspension clamps connected to a
yoke plate may be needed to make a gradual turn.
FIGURE 15-1: SUSPENSION CLAMP WITH
CLEVIS OR BALL AND SOCKET
TYPE OF CONNECTION
U bolt
Bulletin 1724E-200
Page 15-2
Cushioned suspension clamps are sometimes used to support the conductor and reduce the static
and bending stresses in the conductor. Cushioned suspension clamps are further explained in the
conductor motion hardware section (Section 15.3).
15.2.2 Clamp Top Clamps: Clamp top clamps for vertical and horizontal post insulators are
popular because of they are simple to install. The clamps, made of malleable iron or aluminum
alloy, are mounted on a metal cap. The clamp itself is composed of a removable trunion cap
screw (keeper piece) and a trunion saddle piece (Figure 15-2).
FIGURE 15-2: POST TYPE INSULATOR WITH STRAIGHT LINE
TRUNION CLAMPS
Straight line clamps are designed to hold conductors without damage on tangent and line angles
of up to approximately 15o. The maximum acceptable vertical angle (each side of clamp) is
considered to be approximately 15o with the horizontal. Since the keeper piece of the clamp is
not designed to provide the support for upward loading, this clamp should not be used where
uplift conditions could occur. Angle clamps are available which are designed to take up to a 60o
line angle. However, when line angles are greater than 15o to 20o, suspension insulators should
be used. The designer should coordinate with the trunion clamp manufacturer concerning the
compatibility of the clamp design for longitudinal loads on the line.
15.2.3 Tied Supports: A large portion of lower voltage construction involves tying conductors
to pin and post insulator supports. Hand ties (Figure 15-3) are occasionally vulnerable to
loosening from various forces and motion from differential ice buildup, ice dropping, galloping,
and vibration. Factory formed ties with secure fit, low stress concentration and uniformity of
installation may eliminate mechanical difficulties and radio interference problems associated
with loose tie wires.
FIGURE 15-3: TOP GROOVE HAND TIE
Bulletin 1724E-200
Page 15-3
15.2.4 Deadend Clamps: Deadending a conductor may be accomplished by using formed type
deadends, automatic deadends, bolted deadends or compression type deadends (See
Figures 15-4a and 15-4b). Because of the strength limitations of formed and automatic
deadends, these types are limited to primarily small conductor sizes and distribution line use.
The two basic methods of deadending a transmission conductor are by use of bolted deadend
clamps and by compression type deadend clamps.
Deadend clamps, or strain clamps as they are sometimes called, are made from three basic types
of material as follows:
Aluminum Alloy Type:
General Notes: This type is corrosion resistant. It minimizes power losses, minimizes
hysteresis and eddy currents, minimizes excessive conductor heating in the conductor
clamping area and is lightweight. This clamp is the most widely used.
Application: No armor rods or tape are required. Clamps are to be used with ACSR or all
aluminum conductors. These clamps are not to be used with copper or copperclad
conductors.
Malleable Iron:
General Notes: This clamp is somewhat lightweight. The range of conductor sizes is limited.
Application: Clamps are to have aluminum or copper liners. Clamps with copper liners are
to be used for copper or copper-clad conductors. Clamps with aluminum liners are used for
ACSR and other aluminum composite type conductors
Forged Steel:
General Notes: Forged steel clamps are heavy in weight.
Application: Clamps may be used with all aluminum, copper or ACSR conductors. Clamps
are to have aluminum or copper liners. Clamps with copper liners are to be used for copper or
copper-clad conductors. Clamps with aluminum liners are used for ACSR and other
aluminum composite type conductors.
FIGURE 15-4a: TYPICAL BOLTED DEADEND CLAMP
30°
30°
FIGURE 15-4b: TYPICAL COMPRESSION DEADEND
Bulletin 1724E-200
Page 15-4
The ultimate strength of the body of the bolted clamps should meet or exceed the ultimate
strength of the conductor the clamp is designed to hold. The holding power of a bolt type or
compression type clamp should meet the following criteria:
•
•
Clamps have to be capable of holding at least 90 percent of the strength of the largest
conductor for which the clamp is designed to hold in a short-time load.
Clamps have to hold a sustained load of 75 percent of the strength of the conductor for 3
days.
For bolted type clamps, the amount of torque to tighten the bolts depends on the size of the bolt.
Torque will range from 300 in-lbs. for 3/8” bolts to 400 in.-lbs. for 5/8” bolts. Clamps should
also meet certain corrosion resistance tests and heat cycling tests.
Suspension and deadend clamps for use on high voltage transmission lines are specially designed
to control corona. Designs usually involve providing smooth and rounded surfaces rather than
sharp edges and by placing all the clamp nuts and studs within the protection of the electrical
shield.
Installation of compression splices, deadend clamps, and bolted deadend clamps should follow
the manufacturer’s recommendations.
15.2.5 Splices: Conductor splices may be automatic compression type splices, formed type
splices, or crimp compression type splices. For most transmission conductors, the crimped
compression type splice is used because of its high strength capabilities. Splices should meet the
same strength, corrosion resistance and heat cycling requirements as the deadend clamps.
15.2.6 Strain Yokes: Two or more insulator strings may be connected in parallel by using
yokes to:
•
•
•
Provide the strength needed to sustain heavy loads at deadend structures;
Increase the safety factor for long-span river crossings; and
Make a gradual turn at large angles.
Usually, it is more economical to supply higher strength rated insulators than to use yokes. One
disadvantage to using higher strength rated insulators (36,000 lbs and higher) is that the ball and
socket size changes for porcelain insulators which will require other related hardware to be
coordinated.
15.2.7 Insulators: Mechanical and electrical requirements of insulators are discussed in
Chapter 8. Where suspension insulators are exposed to salt sprays or corrosive industrial
emissions, insulators using enlarged pin shafts or corrosion intercepting sleeves are
recommended to prolong the life of the insulator pins. Use of corroision intercepting sleeves
provide an air space between the pin and the cement. With this design, corrosion can attack the
expandable long-lived sleeve. Any increase in the volume of the rust line only distorts the
sleeve. However, without the sleeve, bursting stresses would be imposed on the adjacent
porcelain. Other types of insulators have enlarged shafts near the cement lines which provide
additional sacrificial metal for corrosion.
On lower voltage lines, pin and post type insulators are mounted on structure crossarms.
The side and top wire grooves generally limit the size of the conductor with armor rods
that can be installed to a maximum of 4/0 and 336.4 kcmil ACSR.
Bulletin 1724E-200
Page 15-5
FIGURE 15-5: SUSPENSION INSULATORS
(Ball and Socket Type, Left, and Clevis-Eye Type, Right)
15.2.8 Fittings: Fittings used to attach the insulator to the structure may include hooks, “Y”
ball/clevis, ball eyes, ball clevises and chain, anchor or vee shackles. The “C” hooks suggested
on agency standard construction drawings are the self locking hooks. With the insulator cap in
place, the opening of the hook is sufficiently restricted so that accidental disconnection cannot
occur. Fittings should meet or exceed the ANSI M&E ratings of the insulators. Various fitting
types are shown in Figure 15-6, 15-7 and 15-8.
FIGURE 15-6: DIFFERENT TYPES OF HOOKS
(Self Locking “C” Hook, Left; Ball Hook, Middle, Clevis Type Hook, Right)
FIGURE 15-7: VARIOUS TYPES OF BALL AND CLEVIS “Y” CONNECTIONS
FIGURE 15-8: ANCHOR SHACKLE (Left); CHAIN SHAKLE (Right)
Bulletin 1724E-200
Page 15-6
15.3 Conductor Motion Hardware
15.3.1 Aeolian Vibration: All conductors are in some state of vibration, varying from
extremely slight to temporarily severe. Selection of the proper hardware to improve conductor
life will depend on the degree of vibration. Suspension clamps do not restrict vibration, but
these clamps should be designed to keep to a minimum the effect of such vibration on the
conductor. Methods to reduce the effects that aeolian vibration has on lines include the
following:
Armor Rods: Armor rods (Figure 15-9) should be used on lines in areas where mild vibrations
may occur. Armor rods, wrenched or preformed, are helical layers of round rods which are
installed over the conductor at the points of attachment to the supporting structures. The primary
purpose of armor rods is to provide additional rigidity to the conductor at its point of support.
The use of armor rods accomplishes:
•
•
•
Alleviating changes of mechanical stress buildup at the point of support by providing a
gentler slope of curvature for the incoming conductor,
Increasing conductor life from fatigue failure by increasing the flexural rigidity of the
conductor, and reducing bending stresses in the conductor,
Protecting the conductor from flashover damage and mechanical wear at the points of
support.
In laboratory tests, the placement of armor rods on the conductor has allowed the conductor
to withstand considerably more vibration cycles without fatigue failure. Tests such as these
show that there is a significant reduction in stress afforded through the use of armor rods.
Armor Rod
FIGURE 15-9: ARMOR RODS USED WITH SUSPENSION INSULATORS
Cushioned Suspension Units: These units use resilient cushioning in conjunction with armor
rods to further reduce the static and dynamic bending stresses in the conductor (See
Figures 15-10a and 15-10b). With this cushioning, the compressive clamping force is decreased,
thereby reducing stress concentration notches. For line angles greater than 30o, single support
units should be replaced with double units. When considering longitudinal loads for a line using
cushioned suspension units, the designer should consider that the units have a slip load of
approximately 20 percent of the rated breaking strength of the conductor. A disadvantage to
cushioned suspension units is that it is very difficult to remove or install these units with hot line
tools.
FIGURE 15-10a:
CUSHIONED SUSPENSION
UNIT
FIGURE 15-10b:
DOUBLE CUSHIONED SUSPENSION
(For Line Angles Greater Than 30º)
Bulletin 1724E-200
Page 15-7
Dampers: These are used in areas of severe vibration. They act to attenuate aeolian vibration
amplitudes and thereby reduce the dynamic bending stress at hardware locations and extend
conductor life. Suspension dampers (figure 15-11) make use of the connecting cables between
weights to dissipate the energy supplied to the damper. Use of spiral dampers (Figure 15-12) is
limited to small conductor sizes (Figure 15-12).
When a vibration wave passes the damper location, the clamp of a suspension type damper
oscillates up and down, causing flexure of the damper cable and creating relative motion
between the damper clamp and damper weights. Stored energy from the vibration wave is
dissipated to the damper in the form of heat. For a damper to be effective, its response
characteristics should be consistent with the frequencies of the conductor on which it is installed.
Dampers of various designs are available from a number of manufactures. The number of
dampers required, as well as their location in the span should be determined by consultation with
the damper manufacturer.
Damper Clamp
Conductor
Tapered Sleeve
Damper Weight
Damper Cable
Drain Hole
FIGURE 15-11: TYPICAL SUSPENSION DAMPER
FIGURE 15-12: SPIRAL VIBRATION DAMPER FOR SMALL CONDUCTORS
Application of armor rods, cushion suspension or dampers or a combination thereof should be on
a case-by-case basis. A certain item should not be used merely because it has given satisfactory
performance in another location.
If prevailing wind conditions and the terrain are such that vibration will occur most of the time,
some form of vibration protection should be investigated. Dampers should be selected on the
basis of the frequencies one expects to encounter in the terrain that must be traversed. The
engineer should not specify a certain type of damper or armor rod simply because everyone else
is using them. An improperly located damper can affect the amount of protection and ability of
the damper to suppress the damaging effects of aeolian vibration.
Armor rods are meant to be reinforcement items, not dampers. Vibrations are passed on through
the conductor clamp basically without any attenuation, and then dissipated in the supporting
structure. If the structure is made of steel and if fatigue can be a problem then use of dampers
along with armor rods should be investigated. However, care should be exercised in selecting
the distance between the ends of the armor rods and the dampers, if both are to be used.
Bulletin 1724E-200
Page 15-8
15.3.2
•
•
•
Galloping: Hazards associated with galloping conductors include:
Contact between phases or between phase conductors and ground wires,
Racking of the structure,
Possible mechanical damage at supports.
Aerodynamic drag dampers and interphase spacers are used to limit the amplitude of the
conductor during galloping. Historically, effectiveness of anti-galloping devices has been
erratic.
15.3.3 Bundled Conductors: Bundled connectors are not used very often on transmission lines
under 230 kV but are often economically justified above 230 kV. Bundled conductors can
experience aeolian vibration, galloping, corona vibration, and subconductor oscillation. For a
bundled conductor with spacers, aeolian vibration may be reduced by a factor of 10. However,
galloping of ice coated conductors will occur more readily and more severely on bundled lines
than on single conductors in the same environment.
Subconductor oscillation, though, has caused a major share of the problems to date. It is caused
by one conductor lying in the wake of an upstream conductor and thereby being excited to
vibrate in a nearly horizontal ellipse. Damage has consisted of conductor wear as well as spacer
deterioration and breakage. To reduce subconductor oscillation, subspan length or the distance
between spacers should be kept below 250 feet.
The primary purpose of spacers is to reduce the probability of conductor contact and magnitude
of vibration. Spacers may be rigid, articulated or flexible. They may be open-coil and closedcoil springs, and wire rope and steel strand connecting members. Spacers should grip bundled
conductors securely to avoid abrasion of the subconductors and to prevent conductor
entanglement during strong winds.
15.3.4 Insulator Swing: Occasionally, tie-down weights are used to control conductor position
by preventing excessive uplift and swinging. A line should not be designed to use tie-down
weights as a means of preventing the conductor from swinging into the structure. Sometimes
due to a low Vertical/Horizontal span ratio, weights may have to be used on an occasional
structure. Two types of tie down weights are shown in Figure 15-13.
Attach to the suspension
clamps via hold down
shackles
FIGURE 15-13: DISC WEIGHTS (Left), BALL WEIGHTS (Right)
15.4 Structure Related Hardware for Wood Structures
15.4.1 Fasteners: Threaded rods and machine bolts are frequently used on wood transmission
structures (Figure 15-14). A static-proof bolt has a washer securely fixed to the head of the bolt
and is furnished with washer nuts. Variations of the static-proof bolt include shoulder eye bolts
with round or curved washers welded to the eye, forged shoulder eye bolts and forged eye bolts.
MF type locknuts, used in conjunction with a regular nut or washer nut, form a solid unit which
Bulletin 1724E-200
Page 15-9
does not loosen from vibration and helps to maintain a static proof installation. The strengths
and tensile stress areas of bolts conforming to ANSI C135.1 are shown in the Table 15-1.
Machine Bolt
Double Arming Bolt,
Fully Threaded
Static Proof Bolt
With Forged Washer
Nut
StaticProof
ProofDouble
DoubleEnd
End
Static
Bolts Bolts with M/F
Locknuts
Shoulder Eye Bolt
with Curved
Washer
Static Proof
Double Arming Bolts
MF type Locknut
FIGURE 15-14: FASTENERS
TABLE 15-1
STRENGTHS OF ANSI C135.1 MACHINE BOLTS, DOUBLE ARMING
BOLTS, AND DOUBLE END BOLTS
Machine Bolt
Diameter
in.
Tensile
Stress Area
sq. in.
Minimum Tensile
Strength
lbs.
1/2
5/8
3/4
7/8
1
0.142
0.226
0.334
0.462
0.606
7,800
12,400
18,350
25,400
33,500
Lag screws (Figure 13-5) are sometimes used in lieu of bolts when shear loads are small. A lag
screw with fettered edges is driven into the wood and maintains its holding power with cone
shaped threads. When lag screws are used, the moment capacity of the wood pole is reduced in
the same manner as a bolt hole reduces moment capacity.
FIGURE 15-15: LAG SCREW
Anti-split bolts help prevent the propagation of checking and splitting at the end of crossarms. A
three inch edge distance should be provided between the anti-split bolt and the edge of the arm.
Bulletin 1724E-200
Page 15-10
15.4.2 Framing Fittings: The primary purpose for using grid gains is to reduce bolt hole
slotting by distributing the shear load of the bolt over a large wood area. The specially shaped
teeth of the grid gain press into the wood surface and offer maximum resistance to movement
both with and across the grain of the wood. The use of grid gains will strengthen bolt
connections and are recommended anytime a bolt must carry large shear loads. Two applications
of grid gains are shown in Figure 15-16.
Grid Gains
Application of Grid Gains
FIGURE 15-16: GRID GAINS
The gain plate (between a pole and a crossarm) and the reinforcing plate (on the outside of an
arm) provide additional metal bearing surface for transfer of the vertical load from the crossarm
to the crossarm mounting bolt. The gain plate eliminates a potential decay area between two
wood contact areas. A reinforcing plate, also called a ribbed tie plate, will prevent the crossarm
from splitting or checking when the nut is tightened.
When double crossarms are used to allow longer vertical spans or to increase longitudinal
strength capabilities, spacer fittings Figure 15-17 are needed to separate the crossarms and to
provide a point of attachment for suspension insulators. If fixed spacers are used, poles should
be gained. Since the standard fixed spacing sizes are 7-1/2”, 9”, 10-1/2”, and 12”, the crossarm
may be bowed +1/2 inch. The brand on the butt and face of the pole should include proper
designation of the fixed spacer size. Adjustable spacers will fit a range of pole diameters. When
they are used the pole need not be gained.
Spacer Fitting
Reinforcing Plate
and Gain Plate
FIGURE 15-17: SPACER FITTING, REINFORCING PLATE
AND GAIN PLATE
15.4.3 Swing Angle Brackets: Swing angle brackets are used to provide increased clearance
between phase conductors and the structure to which the conductors are attached (Figure 15-18).
These brackets cab be mounted horizontally or vertically. The two primary types of angle
brackets are the rod type for light loads, and angle iron type for heavier loads.
Bulletin 1724E-200
Page 15-11
FIGURE 15-18: SMALL ANGLE
STRUCTURE WITH SWING
ANGLE BRACKETS
15.4.4 Guy Attachments: The primary types of guy attachments used on wood transmission
line structures include the wrap guy, guying plates, pole eye plates, guying tees, and pole bands.
Other types of guy attachments such as formed straps, angle bolt eyes, and goat hooks are used
primarily on distribution lines. Guy attachments are used to attach the insulators to the structure
as well as providing a means of guying the structure.
15.5 Structure Related Hardware for Concrete and Steel Structures: Much of the structure
related hardware used on wood construction may be appropriate to use on steel or concrete
structures. However, hardware items with grid teeth, such as grid gains or guy attachments with
grid teeth, are not appropriate for use on steel or concrete structures. Likewise, lag screws and
gain plates are not used on steel and concrete poles. Since steel and concrete poles do not shrink
and swell with age and weather, spring washers may not be needed to keep the hardware tight
over time.
In many instances, higher strength bolts are used with steel or concrete poles. Bolts such
ASTM A325, Specification for High-Strength Bolts for Structural Steel Joints, may be
specified instead of the ANSI C135 bolts. Table 15-2 gives the strength ratings for bolts
conforming to ASTM Standard A325.
TABLE 15-2
STRENGTHS OF ASTM A325
HEAT TREATED, HIGH STRENGTH BOLTS
Machine Bolt
Diameter
in.
1/2
5/8
3/4
7/8
1
Tensile
Stress Area
sq. in.
0.142
0.226
0.334
0.462
0.606
Minimum Tensile
Strength
lbs.
17,500
27,100
40,100
55,450
72,700
Minimum Yield
Strength
lbs.
13,050
20,800
30,700
42,500
55,570
Proper selection and design of end fittings and guy attachments is necessary to obtain the
necessary capacity. For example, for steel structures, it may be necessary to use reinforcing
washers on the backside of a guy attachment or end fitting to prevent the nut or bolt head from
pulling through the wall of the steel pole. Selection of hardware should be coordinated with the
Bulletin 1724E-200
Page 15-12
steel pole supplier or concrete pole supplier to obtain the capacity and performance desired.
Selection of hardware should also consider proper fit with other hardware.
When using standard class concrete or steel poles, the owner should provide the pole
manufacturer with the load capabilities, attachment method, and attachment location of all
appurtenances. The pole manufacture should verify that the pole will not have a localized
strength problem at the attachment point. Items to consider if standard class steel or
concrete poles are guyed include:
•
•
•
•
Localized buckling at the guy attachment,
Field holes in the wrong locations,
Unexpected torsion on the pole due to the fact that the pole is not round and the correct
guy plate location does not fall on one of the pole’s flat surfaces, and
Sliding of the slip joint under heavy conductor loads.
In the use of concrete and steel structures, a means for climbing the structure should be provided.
The NESC Rule 261N states the requirements for climbing devices and attachments to the
structure. Based on this requirement, it is recommended that step bolts, removable steps,
ladders, and each attachment to the pole be designed to support a minimum of a 300-pound
worker and equipment multiplied by a 2.0 load factor. The load should be applied at the outer
edge of the step or bolt and should be supported without permanent deformation. Refer to agency
Bulletins 1724E-204, -206, -214, and -216, for additional guidelines on the use of concrete and
steel structures.
15.6 Corrosion of Hardware: Corrosion may be defined as the destruction of metal by a
chemical or electro-chemical reaction with its environment. Certain industrial and sea coast
environments accelerate the rate of corrosion. Parameters which stimulate corrosion include air
(oxygen) dissolved in water, airborne acids, sulphur compounds (from cinders, coke, coal dust,)
salt dissolved in water, corona, etc.
Any two dissimilar metals when placed together in the presence of an electrolyte form a simple
battery. One metal becomes an anode, sacrificing itself to the other metal which becomes the
cathode. One method to reduce the rate of corrosion is to select metals which are compatible
with one another. Table 15-3 details the galvanic voltage of various metals commonly used for
transmission line hardware. The greater the algebraic difference between the metals selected, the
more rapid the rate of corrosion will be of the more electronegative metal selected.
TABLE 15-3
GALVANIC TABLE OF VARIOUS METALS
Silver
Copper
Lead
Tin
Iron
Chromium
Zinc
Aluminum
+.79
+.34
-.13
-.15
-.35
-.47
-.77
-1.337
As an example, when malleable iron suspension clamps are used, aluminum liners should be
furnished in order to reduce the rate of corrosion of the aluminum conductor. As another
example, the selection of staples to be used on the pole ground wire must be compatible material
to the ground wire (see Drawing TM-9 in Bulletins 1728F-810 and 1728F-811).
Bulletin 1724E-200
Page 15-13
Other methods of reducing the rate of corrosion are to galvanize tin plate, paint or cover metals
with corrosion inhibitors. The life of used metals can be prolonged by increasing metal
thickness.
Bulletin 1724E-200
Page 15-14
Blank Page
Bulletin 1724E-200
Page 16-1
16. UNDERBUILD
16.1 General: Placing of underbuild distribution or communications circuits on transmission
lines is a practice that is becoming more prevalent as available rights-of-way decrease. Although
underbuild distribution lines increase the initial cost of a transmission line, common sharing of a
right-of-way is sometimes necessary in order to build the line.
The following factors should be considered in designing a common use line: hazards to
personnel and property, costs, difficulties of construction, operation and maintenance. Adequate
structure arrangement and conductor separation should be provided to minimize the possibility
of conductor contacts, and to provide safe working conditions. Adequate electrical protection
involves prompt and positive de-energization of power circuits in the event of conductor contact
or flashover. Obtaining and maintaining a low ground resistance to earth is desirable to limit the
magnitude of voltage rise, duration of hazardous voltage, and lightning damage.
16.2 Addition of Distribution Underbuild to an Existing Transmission Line: Distribution
circuits can be added to existing transmission structures only if the original transmission
structure was designed for the new particular underbuild facilities or the total structure facilities
meets the current edition of the NESC.
16.3 Strength Requirements: Standard distribution construction is required to meet NESC
Grade C construction in accordance with 7 CFR Part 1724. However, underbuild distribution on
transmission circuits, with the exception of the crossarms, are to be built to meet all requirements
of NESC Grade B construction. This means that the loading on the pole due to the distribution
circuits has to be calculated using NESC Grade B overload capacity factor and strength factors,
It also means that all guying for the underbuild must meet the guying requirements for
transmission. Distribution crossarms on transmission structures may be designed for NESC
Grade C construction, except at angles where they have to be designed for NESC Grade B
construction.
16.4 Line-to-Ground Clearances: Since the lowest conductors on a transmission line with
underbuild will usually be those of the distribution circuits, the clearances to ground and
clearances in crossing situations will in most instances be limited by the requirements stipulated
in the NESC for distribution circuits.
The problem of providing satisfactory clearance becomes more involved when multiple
distribution circuits or conductors cross on the same structure. In these instances, very careful
attention need to be given to the allowable clearance in Section 23 of the NESC.
Particular attention should be given to the use of reduced size distribution neutrals since the
clearance to ground for the neutral, by virtue of its increased sag and position on the pole or
crossarm, may be the controlling factor for pole height. In some cases, it may be more
economical to increase the size of the neutral to reduce its sag.
16.5 Separation Between Transmission and Underbuild Distribution Circuits: The
clearances discussed in this section are intended to provide not only operating clearances but
also sufficient working clearances. A distribution line worker has to be able to access and work
on the distribution underbuild without encroaching upon the required safety (zone) clearances of
the transmission conductors.
16.5.1 Horizontal Separation: The horizontal separation at the support between the lowest
transmission conductor(s) and the highest distribution conductor(s) or neutral should be at least
1 foot if possible as illustrated in Figure 16-1.
Bulletin 1724E-200
Page 16-2
1' min. if
possible
FIGURE 16-1: HORIZONTAL
SEPARATION REQUIREMENTS
BETWEEN TRANSMISSION AND
UNDERBUILD
D
v
FIGURE 16-2: VERTICAL
SEPARATION REQUIREMENTS AT
STRUCTURE FOR UNDERBUILD
16.5.2 Vertical Clearance to Underbuild at Supports: Recommended minimum vertical
clearances between the transmission conductors and the underbuild conductors at the support are
shown in Table 16-1. These clearances apply regardless of the amount of horizontal separation
between transmission and underbuild conductors (see Figure 16-2).
16.5.3 Vertical Clearance to Underbuild at any Point in the Span: Recommended minimum
vertical clearances at any point along the span are shown in Table 16.1.
These clearances apply for the condition below which yields the least separation between the
upper and lower conductor.
a. An upper conductor final sag at a temperature of 32°, no wind, with radial thickness of ice
for the applicable loading district;
b. An upper conductor final sag at a temperature of 167ºF;
c. Upper conductor final sag at a maximum design temperature, no wind. For high voltage bulk
transmission lines of major importance to the system, consideration should be given to the
use of 212ºF as the maximum design conductor temperature.
The sag of the underbuild conductor to be used is the final sag, at the same ambient temperature
as the upper conductor without electrical loading and without ice loading.
If the transmission line or portion thereof is at an altitude which is greater than 3300 feet, an
additional clearance (as indicated in Table 16-1) has to be added to both clearances at the
structure (Category 1) and clearances at the midspan point (Category 2).
16.5.4 Additional Clearance Requirements for Communication Underbuild: For
communication underbuild, the low point of the transmission conductors at final sag,
60˚ F, no wind, should not be lower than a straight line joining the points of support of the
highest communication underbuild.
Bulletin 1724E-200
Page 16-3
TABLE 16-1
RECOMMENDED MINIMUM VERTICAL CLEARANCES TO DISTRIBUTION OR
COMMUNICATION UNDERBUILD ON TRANSMISSION LINES IN FEET
(Circuits may be of the same or different utilities)
(Based on NESC Rule 235 and Table 235-5)
Transmission Nominal voltage, Phase
to Phase
Max. Operating Voltage, Phase to Phase
Max. Operating Voltage, Phase to Ground
kVL-L
34.5
46
69
115
138
161
230
kVL-L
kVL-G
36.2
20.2
48.3
27.9
72.5
41.8
120.8
69.7
144.9
83.7
169.1
97.6
241.5
139.4
Vertical Clearances Between Transmission and
Distribution Conductors
1. Clearance at the support from point of
suspension of transmission conductor to
point of suspension of underbuild
distribution or communication conductor.
Nominal underbuild voltage in kV line-toline: (Note A)
a. 25 kV and below (including
communications conductors)
b. 34.5 kV
2. Clearance at any point in span from
transmission conductor to underbuild
conductor. Nominal underbuild voltage in
kV line-to-line (Note A):
a. 25 kV and below (including
communications conductors)
b. 34.5 kV
Clearances in Feet
4.7
5
5.4
6.4
6.8
7.3
8.7
4.9
5.2
5.6
6.5
7.0
7.5
8.9
3.7
3.8
4.2
5.2
5.6
6.1
7.5
3.8
4.0
4.3
5.4
5.8
6.3
7.7
0.08
0.12
Vertical Clearances Between Transmission
Conductors and Distribution Structures
ALTITUDE CORRECTION TO BE ADDED TO VALUES ABOVE
Additional feet of clearance per 1000 feet
0.02
of altitude above 3300 feet
(See Table 4-2)
0.02
0.05
0.06
Note:
(A) An additional .5 feet of clearance is added to the NESC clearance to obtain the recommended design
clearances.
16.5.5 Span Length and Clearance to Underbuild: The conditions of either Paragraph 16.5.2
or Paragraph 16.5.3 above will dictate what the minimum clearance to underbuild at the structure
should be. If the clearance to an underbuild is dictated by Paragraph 16.5.3 of this section, the
clearance at the structure would have to be increased. Vertical separation at the structure may
depend upon the relative sags of transmission and underbuild conductors. Since the span length
has an effect on relative sags, the resulting maximum span as limited by vertical clearance to
underbuild should be calculated to ensure that the vertical separation at the support is correct for
each span.
Bulletin 1724E-200
Page 16-4
The formula for maximum span as limited by clearance to underbuild is:
Lma x = (RS )
A− B
Sl − Su
Eq. 16-1
where:
Lmax
RS
A
B
Sℓ
Su
=
=
=
=
=
maximum span in feet
ruling span in feet
allowable separation at midspan in feet
vertical separation at supports in feet
underbuild sag at the same ambient temperature as the
transmission conductor, final, in feet
= transmission conductor sag at condition resulting in
least separation to underbuild, final sag, in feet
16.6 Climbing Space: Climbing space through the lower circuits should be preserved on one
side of the pole or in one quadrant from the ground to the top of the pole as required by the
NESC. Working space should be provided in the vicinity of crossarms. Jumpers should be kept
short enough to prevent their being displaced into the climbing space.
16.7 Overhead Ground Wires and Distribution Neutrals: Standard distribution underbuild
construction has its own neutral. This neutral may be tied to the transmission pole ground wire
in order to improve its grounding. Depending on the characteristic of the circuits, a common
ground or a separate ground is acceptable. If separate grounds are used, the pole ground wires
should be located on opposite sides of the pole. Similar materials should be used for both the
transmission pole ground wire and for the distribution pole ground wire and ground rod. For
example, if copper is used for the transmission pole ground, then copper and/or copperclad
should be used for the distribution ground rod and pole ground wire. Use of similar materials
will reduce the possibility of galvanic corrosion. Likewise, the distribution anchors and
transmission anchors should be of similar material as the ground rods and wire used for the pole
butt wraps.
For distribution underbuild on concrete transmission poles, the neutral may be tied to the
external pole ground using a compression connector in locations where the neutral is to be
grounded. A lead from the pole ground should then be tied to a separate ground rod via a
compression connector six inches to one foot above the ground level. Similarly, in the case of
steel poles, there may be situations where the neutral of the distribution underbuild is to be
grounded. In these instances, the pole may be used as the ground path but not as a ground
electrode. A grounding connector mounted on the pole needs to be specified just below the
location of the neutral on the pole. The ground pad near the ground line should then be used to
connect a driven ground rod to the pole.
16.8 Addition of Poles for Underbuild: There may be structures where it is either desirable or
necessary to transfer distribution circuits to separate poles. Such situations include:
•
•
•
•
Large Line Angles (Figure 16-3)
Deadends
Tap-offs
Sectionalizing Structures
•
•
•
Substation Approaches
Transformers or Regulators (Figure 16-4)
Capacitors
Bulletin 1724E-200
Page 16-5
Transmission
Distribution
FIGURE 16-3: TRANSFERENCE OF THE DISTRIBUTION CIRCUIT
TO A SEPARATE POLE AT A LARGE ANGLE
Location of transformers on structures carrying both transmission and distribution lines should
be avoided. Not only does the transformer create an unbalanced load on the structure, but the
additional conductors necessary for service drops may make working on the structure hazardous
to personnel. A ground rod should be installed at every pole location with a transformer and the
transformer grounded per NESC requirements.
(See Table 4-2
for Clearance)
Transformer
Pole
FIGURE 16-4: USE OF A SEPARATE POLE TO MOUNT
A DISTRIBUTION TRANSFORMER
16.9 Guying: The need to provide additional guys to compensate for the effect of underbuild
on structures is readily apparent. However, there are locations where special attention has to be
given to the guying being proposed. One example is a common use pole with a line tap.
Tension due to
vertical loading
only
M
x
Transmission Line
N
P
x
Guy
Distribution
Sketch (a)
Sketch (b)
FIGURE 16-5: GUYING DISTRIBUTION UNDERBUILD
Bulletin 1724E-200
Page 16-6
For winds perpendicular to the transmission line, the guying described in Figure 16-5 may be
insufficient. This will be true if consideration has been given only to underbuild deadend tension
shown as forces (x) in the figure. The maximum transverse load acts on half the sum of adjacent
spans, (MN+NP)/2, of the transmission and distribution circuits.
These forces have to be added to the tensions of tap conductors in order to determine the proper
amount of guying required. If winds are parallel to the transmission line, the deadend loading of
the tap is larger and this load should be used. Guying of the distribution underbuild is to meet
Grade B construction.
A general rule is that where the transmission circuit or the distribution circuit requires guys, both
circuits should be guyed. The guys should be designed to carry the entire transverse load on the
structure at maximum loading conditions. All drawings should show location and slope of guys
to assure adequate clearances when guys are required. Positions of guys should be clear from
other hardware or electrical connections, such as connectors between neutral and pole ground
wire. Where guys may pass close to conductors, minimum clearances in accordance with Table
4-2 should be met.
16.10 Example: Maximum Span as Limited by Clearance to Underbuild: A 69 kV single
pole transmission is to be built with a 25 kV underbuild distribution circuit. Determine
maximum span as limited by clearance between transmission conductors and underbuild.
16.10.1 Given:
•
•
•
•
Vertical separation between transmission and distribution conductors at the structure is
11.0 ft.
Ruling span: 300 ft.
NESC Heavy loading district
Conditions for the conductor:
a. Transmission conductor is at 32°F with ½” ice while the distribution conductor is
at an ambient temperature of 0°F during the winter.
b. Transmission conductor is at 212°F maximum design temperature while the
distribution conductor is at an ambient temperature of 0°F during the winter.
c. Transmission conductor is at 212°F maximum design temperature while the
distribution conductor is at an ambient temperature of 90°F during the summer.
Transmission Conductor
477 kcmil 26/7 ACSR
(a)
(b)
(c)
Distribution Conductor
4/0 6/1 ACSR
Loading
Condition
Final sag
(ft.)
Ambient Temp.
Final sag (ft.)
32ºF, 1/2” ice
212ºF
212ºF
4.40
6.73
6.73
0°F
0°F
90°F
1.60
1.60
3.98
16.10.2 Solution:
From Table 16-1 the required vertical clearance at midspan between the transmission and
distribution conductors is 4.2 feet.
Bulletin 1724E-200
Page 16-7
Next, calculate the separation between the upper and lower conductor for each loading condition
given above:
(a) 11’ - 4.40’ + 1.60’ = 8.20’
(b) 11’ - 6.73’ + 1.60’ = 5.87’
(c) 11’ - 6.73’ + 3.98’ = 8.25’
The condition (b) results in the least separation between the transmission and underbuild
conductors; therefore, the condition (b) conductor sag values will be used in the following
equation:
Lma x = (RS )
A− B
Sl − Su
Eq. 16-1
Substituting:
RS
A
B
Sl
=
=
=
=
=
300
4.2
11
1.60
6.73
Lma x = (300 )
4.2 − 11
1.60 − 6.73
Lmax = 345 feet
The maximum span as limited by the separation between the transmission conductors and the
distribution underbuild is 345 feet.
For situations where greater span lengths are necessary, the separation at the structure should be
increased. In addition, consideration should be given for the effects of ice jumping as described
in Section 6.3 of this manual.
Bulletin 1724E-200
Page 16-8
Blank Page
Bulletin 1724E-200
Page A-1
APPENDIX A
TRANSMISSION LINE DESIGN DATA
SUMMARY SHEET AND SUPPORTING INFORMATION
•
Sample Summary Sheet
A-3
•
Instructions
A-5
•
Suggested Outline for Design Data Summary Book
A-10
Bulletin 1724E-200
Page A-2
Blank Page
Bulletin 1724E-200
Page A-3
I. GENERAL INFORMATION
BORROWER:
DATE:
LINE IDENTIFICATION:
VOLTAGE
TRANSMISSION LINE DESIGN
DATA SUMMARY
LENGTH
TRANSMISSION
UNDERBUILD
TRANSMISSION
UNDERBUILD
___________kV
___________kV
___________mi
___________mi.
.
TYPE OF TANGENT STRUCTURE:
BASE POLE:
____________HT. ____________CL
DESIGNED BY:
II. CONDUCTOR DATA
TRANSMISSION
OHGW
UNDERBUILD
COMMON NEUTRAL
TRANSMISSION
(lbs./ft.)
OHGW
(lbs./ft.)
UNDERBUILD
(lbs./ft.)
COMM.NEUTRAL
(lbs./ft.)
SIZE (kcmil or in.)
STRANDING
MATERIAL
DIAMETER (in)
WEIGHT (lbs./ft.)
RATED STRENGTH (lbs.)
III. DESIGN LOADS (Wires)
NESC:__________________LOADING DISTRICT
a. ICE:
_________in.
b. WIND ON ICED COND. ____psf
Vertical.
Transverse
c. CONSTANT K ___________
Resultant + K
HEAVY ICE(NO WIND) ______in.
Vertical.
HIGH WIND(NO ICE) ______psf
Transverse
EXTREME HIGH WIND/ICE
ICE:
_________in.
WIND ON ICED COND. ____psf
Vertical.
Transverse
IV. SAG & TENSION DATA
SPANS
AVERAGE(EST)
___________ft
MAXIMUM(EST)
SOURCE OF SAG-TENSION DATA:
TRANSMISSION
TENSIONS (% RATED STRENGTH)
INITIAL
NESC
a. UNLOADED (0˚ 15˚ 30˚)
NESC
b. LOADED (0˚ 15˚ 30˚)
FINAL
___________ft..
OHGW
INITIAL
FINAL
RULING(EST)
UNDERBUILD
INITIAL
FINAL
____________ft.
COMM.NEUTRAL
INITIAL
FINAL
_____˚F
_____˚F
MAXIMUM ICE
32 ˚F
HIGH WIND (NO ICE)
_____˚F
UNLOADED LOW TEMPERATURE _____˚F
SAGS (FT)
NESC DISTRICT LOADED
_____˚F
UNLOADED HIGH TEMP(120˚FOR OHGW &U.B.)___˚F
MAXIMUM ICE
32˚F
LOADED 1/2” ICE, NO WIND
32˚F
V. CLEARANCES
MINIMUM CLEARANCES TO BE MAINTAINED AT:_____________________________________________________________________
CLEARANCES
IN FEET
RAILROADS
HIGHWAY
CULTIVATED
FIELDS
ADDITIONAL .
ALLOWANCE
TRANSMISSION
UNDERBUILD
VI. RIGHT OF WAY
WIDTH
_____________
FT. (MIN.)
_____________
FT. (MAX.)
Bulletin 1724E-200
Page A-4
VII. CONDUCTOR MOTION DATA
HISTORY OF CONDUCTOR GALLOPING:
HISTORY OF AEOLIAN VIBRATION:
a. TYPE OF VIBRATION DAMPERS USED (IF ANY)
b. TYPE OF ARMOR RODS USED (IF ANY)
VIII. INSULATION
NO. OF THUNDERSTORM DAYS/YR______________ELEV.ABOVE SEA LEVEL (MIN, MAX, ft.)____________________
CONTAMINATION EXPECTED?_____________MAX EST. FOOTING RESISTANCE___________Ω
SHIELD ANGLE __________˚
STRUCTURE
STRUCTURE
NO. OF BELLS /
60 HZ DRY
INSULATOR SIZE
SML / M & E
TYPE
DESIGNATION
POLYMER /
FLASHOVER
(DIAMETER &
RATING / POST
LENGTH)
STRENGTH
PIN OR POST
OTHER
TANGENT
ANGLE
STRAIN STRUC
IX. INSULATOR SWING
CRITERIA: (1)_________PSF ON BARE CONDUCTOR AT __________(6 psf MIN) FOR ___________________in. CLEARANCE
(2)_________PSF HIGH WIND ON BARE CONDUCTOR AT ___________˚ F FOR _______________in. CLEARANCE
ALLOWABLE SWING ANGLE:
ANGLE IN DEGREES
STRUCTURE.
NO. OF
6 psf MIN.
TYPE
INSULATORS.
WIND(1)
HIGH WIND (2)
NO WIND
OTHER
X. ENVIRONMENTAL AND METEORLOGICAL DATA
TEMPERATURE: MIN__________˚ MAX.__________˚
AVERAGE YEARL LOW
_____________˚
MAXIMUM HEIGHT OF SNOW ON THE GROUND
EXTREME 10 SEC. WIND GUSTS (mph):
10 YR. ___________ 50 YR.__________ 100 YR___________
DESCRIBE TERRAIN AND CHARACTERISTICS OF SOIL
UNDER THE CONDUCTOR(ft.):
CORROSIVENESS OF ATMOSPHERE:
XI. STRUCTURE DATA (FOR SINGLE POLES AND H-FRAMES)
POLE MATERIAL:_____________________________
TYPE OF FOUNDATION: TANGENT:____________ANGLE:____________
ARM MATERIAL: Trans_________________________
DEADEND_________________GUYED STRUCTURES____________
Underbuild_________________________
TANGENT STRUCTURE TYPE___________________
BASE POLE
SUMMARY OF SPANS (ft.) FOR TANGENT STRUCT.
_____FT.____CL
OTHER HEIGHTS/CLASSES AND BRACING
LEVEL GROUND SPAN
MAX. HORIZON. SPAN LIMITED BY STRUCTURE STRENGTH
MAX. VERTICAL SPAN LIMITED BY STRUCTURE STRENGTH
MAX. HORIZONTAL SPAN LIMITED BY COND. SEPARATION
MAX. SPAN LIMITED BY UNDERBUILD
MAX. SPAN LIMITED BY GALLOPING
EMBEDMENT DEPTH
PRESERVATIVE OF WOOD POLE (TYPE &RETENT.)_______________________
FOR BASE POLE:_____________________________
CORROSION PROTECTION FOR STEEL POLES ___________________________
GUYING: TYPE OF ANCHORS: ____________________________ GUY SIZE AND R.B.S.:___________________________________
XII. LINE DESCRIPTION
TANGENTS__________________%
MEDIUM ANGLES____________%
LIGHT ANGLES ______________%
DEADEND &
HEAVY ANGLES______________%
AVERAGE NUMBER OF
LINE ANGLES PER mi. ______________________
MAXIMUM DISTANCE BETWEEN
FULL DEADENDS (mi.)___________________
Bulletin 1724E-200
Page A-5
INSTRUCTIONS FOR FILLING OUT SAMPLE SUMMARY SHEET
I.
GENERAL INFORMATION
BORROWER – Agency borrower designation.
DATE – Date when design data was completed.
LINE IDENTIFICATION – The name of the line, usually expressed in terms of the line’s
endpoints. If the line design is “project design data” that is to be used for several line
designs, the term “project design data” should be entered.
VOLTAGE – Nominal line-to-line voltage of both transmission and underbuild
distribution circuit in kV. If there is no underbuild, fill in N. A. (not appropriate)
LENGTH – Self-explanatory.
TYPE OF TANGENT STRUCTURE – Give agency designation for tangent structure
type used (for example, “TH-10”). If the structure is not a standard agency structure, the
word “special” should be filled in.
BASE POLE – The height and class of pole used most widely in line.
DESIGNED BY – Individual and/or firm doing the designing.
II.
CONDUCTOR DATA
SIZE – For conductors, size in AWG numbers or kcmil. For steel wire, diameter in
inches.
STRANDING – Number of strands. For ACSR conductor, give aluminum first, steel
second. For example: 26/7.
MATERIAL – Indicate conductor or wire type. For example, ACSR, 6201;or EHS (extra
high strength steel).
DIAMETER – Diameter of conductor, in.
WEIGHT – Weight per foot of bare conductor, lbs/ft.
RATED STRENGTH – Standard rated strength of conductor.
III.
DESIGN LOADS
NESC LOADING DISTRICT – Indicate the National Electrical Safety Code loading
district on which design is based. Use “H” for heavy, “M” for medium, and “L” for light
loading district.
Bulletin 1724E-200
Page A-6
a. Ice – Radial in. of ice on conductor for loading district specified.
b. Wind – Wind force in lbs. for loading district specified.
c. Constant “K” – Constant from NESC to be added to resultant of horizontal and
vertical load (at standard loading district condition) for determining conductor sags
and tensions.
HEAVY ICE – (no–wind, in.) – Radial thickness (in.) of ice conductor for the heavy
icing condition for which line is designed (if any).
HIGH WIND – (no ice – psf) – The high wind value in lbs/sq. ft. for which the line is
designed.
COMBINED EXTREME ICE/WIND – The loadings associated with the 50 yr extreme
ice/wind from the figures in 11.3 of this bulletin. The radial thickness of ice and the unit
loads should be given for the vertical loads. The high wind associated with the radial
thickness of ice should be given for the tansverse loads as well as the unit loads.
LOADING TABLE - Conductor or wire loads in lbs. per linear ft. for conditions
indicated at left.
IV.
SAG & TENSION DATA
SPANS – AVG., MAX., and RULING – Self-explanatory.
SOURCE OF SAG-TENSION DATA – Self-explanatory.
TENSION TABLE – Initial and final tension values in percent of rated strength at
loading conditions indicated on the left should be given. In those boxes where there is a
dotted line in the center, the specified tension limiting values (in percent) should be given
above the line. The actual resulting tension value (in percent) should be given below the
line. For all other boxes the tension value should be the actual resulting value (in
percent). The details of loading condition should be filled in on the left as follows:
a. Unloaded (0º, 15º, 30º) – Indicate appropriate temperature. Heavy loading district
will be 0ºF, medium will be 15ºF, light will be, 30ºF.
b. NESC Loaded (0º, 15º, 30º) – Specify appropriate temperature.
c. Maximum Ice – Use the same maximum radial ice as indicated in the
DESIGN LOADS section.
d. High Wind – Use the same value as in the DESIGN LOAD section.
e. Unloaded Low Temperature – Specify lowest temperature that can be expected to
occur every winter.
SAG TABLE – Specify initial and/or final sags in ft. for conditions indicated. Specify
maximum conductor operation temperature in the appropriate box on the left. Sags for
the overhead ground wire and underbuild conductors are for a temperature of 120ºF.
Note: When sag and tension calculations are done, tension limits are usually specified at
several conditions. However, only one of the conditions will usually control, resulting in
tensions, at the other conditions, that are lower than the limit.
V.
CLEARANCES
MINIMUM CLEARANCES TO BE MAINTAINED AT – Specify maximum sag
condition at which minimum clearances are to be maintained. Generally, it will be at the
high temperature condition but it may be possible for the sag at NESC loading (H, M, L)
to be the controlling case.
Bulletin 1724E-200
Page A-7
CLEARANCE TABLE – Indicate clearance which will be used for plan and profile and
design. Extra boxes are for special situations.
VI.
RIGHT-OF-WAY WIDTH
Indicate width value used. If more than one value is used, give largest and smallest
value.
VII.
CONDUCTOR MOTION DATA
HISTORY OF CONDUCTOR GALLOPING – Indicate if conductor galloping has ever
occurred in the area and how often it can be expected.
HISTORY OF AEOLIAN VIBRATION – Indicate whether or not the line is in an area
prone to aeolian vibration.
a. Type of Vibration Dampers Used (if any) – Self-explanatory.
b. Type of Armor Rods Used (if any) – Indicate whether standard armor rods, cushioned
suspension units or nothing is used.
VIII. INSULATION
NUMBER OF THUNDERSTORM DAYS/YEAR – Self -explanatory.
ELEVATION ABOVE SEA LEVEL (min., max., ft.) – Give the altitude in ft. above sea
level of the minimum and maximum elevation points of the line
CONTAMINATION EXPECTED? – Indicate contamination problems which may affect
the performance of the insulation. The following are recommended terms: None, Light,
Medium, Heavy, Sea Coast Area.
MAXIMUM ESTIMATED FOOTING RESISTANCE. – Give the estimated maximum
electrical footing resistance (in ohms) expected to be encountered along the length of the
line. Where the footing resistance is high, the value to which the footing resistance will
be reduced, by using special measures, should be indicated by putting this value in
parentheses. For example, 70(20).
SHIELD ANGLE – If the basic tangent structure being used is not a standard structure,
its shield angle should be given.
INSULATION TABLE – For the structure type indicated, the structure numerical
designation and the number of suspension bells should be given. If post insulators are
used instead of suspension, the word “post” or “pin” should be put in the second column.
If nonceramic insulators are used, indicate ‘susp-nci’ or ‘post-nci’. The 60 Hz dry
flashover value for the entire string of insulators (or post) should be given. The column
“insulator size” should contain the diameter and length of the insulator. For suspension
bell, the M&E strength should be given. For post insulator, the ultimate cantilever
strength should be entered. For nonceramic insulators suspension or posts, give the SML
ratings.
Bulletin 1724E-200
Page A-8
IX.
INSULATOR SWING
CRITERIA – Self-explanatory
INSULATOR SWING TABLE – For the primary structures used in the line and the
number of insulators used, the insulator swing angles under the 6 lb. minimum condition,
the high wind condition and under the no wind condition should be given.. Angles
measured from a vertical through the point of insulator string suspension away from
structure should be indicated by following them with an asterisk (*).
X.
ENVIRONMENTAL & METEORLOGICAL DATA
TEMPERATURE – The minimum, maximum, and average yearly low temperature
recorded in the area of the line should be given.
MAXIMUM HEIGHT OF SNOW ON GROUND UNDER CONDUCTOR
(ft.) – Self-explanatory.
CORROSIVENESS OF ATMOSPHERE – Indicate corrosiveness of the atmosphere by
severe, moderate, or light.
EXTREME 10 SEC WIND GUSTS – Give the annual extreme wind with mean
recurrence intervals of 10, 50, and 100 years. For 50 year, see Figures 11-2a to 11-2d of
Chapter 11. For 10 year, see paragraph 7.2.3 of Chapter 7.
DESCRIBE TERRAIN & CHARACTER OF SOIL – A brief description should be given
as to whether the terrain is flat, hilly, rolling piedmont, or mountainous. Indicate whether
the soil firmness is good, average, or poor. Give approximate depth of ground water
table. Describe corrosiveness of soil.
XI.
STRUCTURE DATA (For single poles and H-frames)
POLE MATERIAL – Indicate wood, steel, or concrete. If wood, indicate species.
ARM MATERIAL – If a crossarm is used, indicate wood, steel or fiberglass..
TYPE OF FOUNDATION – For tangent, angle, or deadend structures, indicate direct
embedded or caisson for the majority of the structures within each type. For example, if
most of the angle and deadends are unguyed, indicate the predominant foundation for
each type.
STRUCTURE TABLE The various maximum span values should be given for the base
pole and structure configuration. Values should also be given for other pole heights,
wood classes or standard steel/concrete pole classes, bracing and configurations that are
expected to be commonly used.
a. Level Ground Span – Give the maximum span for height of pole, limited by
clearance to ground only.
b. Maximum Horizontal Span Limited by Structure Strength – For single pole
structures, give the maximum span as limited by pole strength. For H-frame
structures, the effect of the bracing must be included. If vertical post insulators are
used, their maximum horizontal span value should be included if it is less than that of
the rest of the structure, and should be indicated as such by placing the term “ins”
after the value. If underbuild is to be used on the line, its effect should be included.
c.
d.
e.
f.
Bulletin 1724E-200
Page A-9
Maximum Vertical Span Limited by Structure Strength – Give the maximum
vertical span limited by either crossarm strength, crossarm brace strength, or
horizontal post insulator strength. If horizontal post insulators are the limiting factor,
the term “ins” should be placed after the span value. If the structure is such that the
maximum horizontal span affects the maximum vertical span, the assumed maximum
horizontal span should be the value shown in the “maximum horizontal span” box.
Maximum Horizontal Span Limited by Conductor Separation – Give the
maximum span value from Equation 6-1 or 6-2 in Chapter 6 of this bulletin.
Maximum Span Limited by Underbuild – Give the maximum span limited by
separation between underbuild conductors, or between underbuild and transmission
conductors, whichever is more limited.
Maximum Span Limited by Galloping – Give the maximum span that can be
allowed before galloping ellipses touch.
EMBEDMENT DEPTH – Indicate the pole embedment depth used. If the standard
values are used, indicate “standard”. If other values are use, indicate by how much they
differ from the standard value. For example, std. + 2 ft.
PRESERVATIVE FOR WOOD POLES – Type and retention level of preservative.
CORROSION PROTECTION FOR STEEL POLES – Indicate weathering steel,
galvanized steel, or painted.
GUYING – Indicate whether log, screw or other anchors are used and the predominant
anchor capacity. For example: Log, 8,000/16,000 lbs. The diameter, type and rated
breaking strength (rbs) of the guy strand should be given.
XII.
LINE DESCRIPTION
For the respective structures types, indicate the percentage of the total number of structures used.
Calculate the average number of line angles per mile and give the maximum distance in miles
between full deadends: (“Full” deadends refer to strain type structures that are designed to
remain standing if all conductors and overhead ground wires are cut on either side of the
structure.)
Bulletin 1724E-200
Page A-10
SUGGESTED OUTLINE FOR
DESIGN DATA SUMMARY BOOK
Given below is a suggested outline for a Design Data Summary Book. The outline is primarily
intended for lines of 230 kV Generally, a well prepared design data book should include all the
material indicated below. However, some judgment should be used in submitting more or less
information as deemed appropriate.
I.
Transmission Line Design Data Summary
II.
General Information
A.
Line identification, description and role in system
B.
Description of terrain and weather
C.
Design criteria and applicable codes and standards
D.
Selection of conductor and OHGW
Selection of conductor and OHGW type
2.
Selection of conductor and OHGW size/
Economic conductor analysis
E.
Determination of maximum conductor temperature
F.
Selection of structure type and average height
G.
III.
1.
1.
Economic evaluation of alternate structures
2.
Selection of optimum structure height
Construction cost estimate
Supporting Calculations to Part I
A.
Conductor sag and tension tables (computer printout and source)
B.
OHGW sag and tension values (computer printout and source)
C.
Vertical and horizontal clearances and ROW width
D.
Insulation considerations
E.
Level ground span
Bulletin 1724E-200
Page A-11
F.
Maximum span limited by conductor separation
1.
Horizontal separation
2.
Vertical and diagonal separation
G.
Maximum span limited by underbuild (if applicable)
H.
Galloping analysis
I.
Unguyed structure strength calculations
J.
1.
Maximum horizontal span limited by pole strength, ‘X’ bracing, poles
(including post insulators; if applicable)
2.
Maximum vertical span limited by structure strength
3.
Loading trees for steel or concrete structures; selection method for
standard class poles
4.
Hardware limitations
5.
Insulator strength requirements
6.
Foundation type; embedment depths; selection method; soil information
Guyed structure calculations
1.
Minimum spacing of anchors
2.
Guy and anchor calculations and application charts
3.
Maximum axial loads for guyed pole
4.
Guy attachments and their strengths
5.
Arrangement of guys and anchors and application guides
K.
Sample insulator swing calculations and application charts for all structures
L.
Diagrams for all non-standard structures or assemblies anticipated for use on the
line
M.
Sag-clearance template if a CADD program is not used for the plan-profile
Bulletin 1724E-200
Page A-12
Blank Page
Bulletin 1724E-200
Page B-1
APPENDIX B
CONDUCTOR TABLES
•
Conductor Mechanical Loading Tables
B-2
•
Overhead Ground Wire Loading Tables
B-7
Bulletin 1724E-200
Page B-2
CONDUCTOR MECHANICAL
LOADING TABLES
The tables that follow give horizontal, vertical, and resultant vector loads on conductors and
overhead ground wires under standard NESC loading district conditions, high wind conditions,
and heavy ice conditions.
Bulletin 1724E-200
Page B-3
ACSR CONDUCTORS
NESC DISTRICT LOADINGS
LIGHT
.00" ICE, 9 LB., K=.05
VERT.
TRANS RESULTANT
STRAND LB/FT.
LB/FT.
LB/FT.
6/1
0.1452
0.2985
0.3819
6/1
0.1831
0.3353
0.4320
6/1
0.2309
0.3765
0.4917
6/1
0.2911
0.4223
0.5629
18/1
0.2894
0.4568
0.5907
26/7
0.3673
0.4815
0.6556
18/1
0.3653
0.5130
0.6798
26/7
0.4630
0.5408
0.7619
30/7
0.5271
0.5558
0.8160
18/1
0.4316
0.5573
0.7548
MEDIUM
.25" ICE, 4 LB. WIND, K=.20
VERT.
TRANS RESULTANT
LB/FT.
LB/FT.
LB/FT.
0.3467
0.2993
0.6580
0.3998
0.3157
0.7094
0.4647
0.3340
0.7723
0.5439
0.3543
0.8491
0.5565
0.3697
0.8681
0.6446
0.3807
0.9486
0.6557
0.3947
0.9653
0.7649
0.4070
1.0664
0.8352
0.4137
1.1320
0.7403
0.4143
1.0484
HEAVY
.5" ICE, 4 LB. WIND, K=.30
VERT.
TRANS RESULTANT
LB/FT.
LB/FT.
LB/FT.
0.7036
0.4660
1.1439
0.7719
0.4823
1.2102
0.8539
0.5007
1.2899
0.9520
0.5210
1.3853
0.9789
0.5363
1.4162
1.0774
0.5473
1.5084
1.1015
0.5613
1.5363
1.2222
0.5737
1.6501
1.2987
0.5803
1.7225
1.2045
0.5810
1.6373
ULTIMATE
STRENGTH DIAM. WT./FT.
LBS.
IN.
LBS.
4380
0.398
0.1452
5310
0.447
0.1831
6620
0.502
0.2309
8350
0.563
0.2911
6880
0.609
0.2894
11300
0.642
0.3673
8680
0.684
0.3653
14100
0.721
0.4630
17300
0.741
0.5271
9940
0.743
0.4316
NAME
RAVEN
QUAIL
PIGEON
PENGUIN
WAXWING
PARTRIDGE
MERLIN
LINNET
ORIOLE
CHICKADEE
SIZE
1/0
2/0
4/0
266.8
266.8
336.4
336.4
336.4
397.5
397.5
IBIS
LARK
PELICAN
FLICKER
HAWK
HEN
OSPREY
PARAKEET
DOVE
EAGLE
397.5
397.5
477.
477.
477.
477.
556.5
556.5
556.5
556.5
26/7
30/7
18/1
24/7
26/7
30/7
18/1
24/7
26/7
30/7
0.5469
0.6228
0.5180
0.6145
0.6570
0.7470
0.6040
0.7170
0.7660
0.8720
0.5873
0.6045
0.6105
0.6345
0.6435
0.6623
0.6593
0.6855
0.6953
0.7148
0.8525
0.9179
0.8506
0.9333
0.9696
1.0483
0.9441
1.0420
1.0845
1.1775
0.8680
0.9511
0.8488
0.9552
1.0015
1.0992
0.9550
1.0789
1.1319
1.2460
0.4277
0.4353
0.4380
0.4487
0.4527
0.4610
0.4597
0.4713
0.4757
0.4843
1.1677
1.2460
1.1551
1.2554
1.2990
1.3920
1.2599
1.3773
1.4278
1.5368
1.3446
1.4348
1.3350
1.4514
1.5014
1.6069
1.4614
1.5962
1.6533
1.7754
0.5943
0.6020
0.6047
0.6153
0.6193
0.6277
0.6263
0.6380
0.6423
0.6510
1.7701
1.8560
1.7656
1.8765
1.9241
2.0251
1.8900
2.0190
2.0737
2.1910
16300
20300
11800
17200
19500
23800
13700
19800
22600
27800
0.783
0.806
0.814
0.846
0.858
0.883
0.879
0.914
0.927
0.953
0.5469
0.6228
0.5180
0.6145
0.6570
0.7470
0.6040
0.7170
0.7660
0.8720
KINGBIRD
ROOK
GOSBEAK
EGRET
CUCKOO
DRAKE
MALLARD
TERN
CONDOR
RAIL
636.
636.
636.
636.
795.
795.
795.
795.
795.
954.
18/1
24/7
26/7
30/19
24/7
26/7
30/19
45/7
54/7
45/7
0.6910
0.8190
0.8750
0.9880
1.0240
1.0940
1.2350
0.8960
1.0240
1.0750
0.7050
0.7478
0.7425
0.7643
0.8190
0.8310
0.8550
0.7973
0.8198
0.8738
1.0372
1.1590
1.1976
1.2991
1.3612
1.4238
1.5521
1.2493
1.3617
1.4353
1.0610
1.2067
1.2605
1.3825
1.4412
1.5162
1.6671
1.3042
1.4415
1.5149
0.4800
0.4990
0.4967
0.5063
0.5307
0.5360
0.5467
0.5210
0.5310
0.5550
1.3645
1.5058
1.5548
1.6723
1.7358
1.8081
1.9545
1.6044
1.7362
1.8134
1.5864
1.7498
1.8014
1.9325
2.0139
2.0938
2.2547
1.8678
2.0145
2.1103
0.6467
0.6657
0.6633
0.6730
0.6973
0.7027
0.7133
0.6877
0.6977
0.7217
2.0131
2.1721
2.2197
2.3463
2.4312
2.5086
2.6649
2.2904
2.4319
2.5302
15700
22000
25200
31500
27900
31500
38400
22100
28200
25900
0.940
0.997
0.990
1.019
1.092
1.108
1.140
1.063
1.093
1.165
0.6910
0.8190
0.8750
0.9880
1.0240
1.0940
1.2350
0.8960
1.0240
1.0750
CARDINAL
BUNTING
GRACKLE
BITTERN
PHEASANT
LAPWING
FALCON
CHUKAR
BLUEBIRD
954.
1192.5
1192.5
1272.
1272.
1590.
1590.
1780.
2156.
54/7
45/7
54/19
45/7
54/19
45/7
54/19
84/19
84/19
1.2290
1.3440
1.5330
1.4340
1.6350
1.7920
2.0440
2.0740
2.5110
0.8970
0.9765
1.0035
1.0088
1.0365
1.1265
1.1588
1.2015
1.3215
1.5715
1.7113
1.8822
1.8033
1.9859
2.1667
2.3996
2.4469
2.8875
1.6785
1.8265
2.0267
1.9299
2.1424
2.3367
2.6020
2.6498
3.1365
0.5653
0.6007
0.6127
0.6150
0.6273
0.6673
0.6817
0.7007
0.7540
1.9712
2.1227
2.3173
2.2255
2.4323
2.6301
2.8898
2.9408
3.4259
2.2835
2.4644
2.6758
2.5812
2.8052
3.0368
3.3155
3.3810
3.9175
0.7320
0.7673
0.7793
0.7817
0.7940
0.8340
0.8483
0.8673
0.9207
2.6980
2.8811
3.0870
2.9969
3.2154
3.4492
3.7223
3.7904
4.3242
33800
3200
41900
34100
43600
42200
54500
51000
60300
1.196
1.302
1.338
1.345
1.382
1.502
1.545
1.602
1.762
1.2290
1.3440
1.5330
1.4340
1.6350
1.7920
2.0440
2.0740
2.5110
Bulletin 1724E-200
Page B-4
ACSR CONDUCTORS
HIGH WIND LOADINGS
WT./FT
LBS.
0.1452
0.1831
0.2309
0.2911
0.2894
0.3673
0.3653
0.4630
0.5271
0.4316
13 psf
16 psf
21 psf
26 psf
31 psf
6 psf
TRANS RESULTANT TRANS RESULTANT TRANS RESULTANT TRANS RESULTANT TRANS RESULTANT TRANS
SWING
LB/FT
LB/FT
LB/FT
LB/FT
LB/FT
LB/FT
LB/FT
LB/FT
LB/FT
LB/FT
LB/FT
ANGLE
0.4312
0.4550
0.5307
0.5502
0.6965
0.7115
0.8623
0.8745
1.0282
1.0384
0.1990
53.88
0.4843
0.5177
0.5960
0.6235
0.7823
0.8034
0.9685
0.9857
1.1548
1.1692
0.2235
50.67
0.5438
0.5908
0.6693
0.7080
0.8785
0.9083
1.0877
1.1119
1.2968
1.3172
0.2510
47.39
0.6099
0.6758
0.7507
0.8051
0.9853
1.0274
1.2198
1.2541
1.4544
1.4833
0.2815
44.04
0.6598
0.7204
0.8120
0.8620
1.0658
1.1043
1.3195
1.3509
1.5733
1.5996
0.3045
46.46
0.6955
0.7865
0.8560
0.9315
1.1235
1.1820
1.3910
1.4387
1.6585
1.6987
0.3210
41.15
0.7410
0.8262
0.9120
0.9824
1.1970
1.2515
1.4820
1.5264
1.7670
1.8044
0.3420
43.11
0.7811
0.9080
0.9613
1.0670
1.2618
1.3440
1.5622
1.6293
1.8626
1.9193
0.3605
37.90
0.8028
0.9603
0.9880
1.1198
1.2968
1.3998
1.6055
1.6898
1.9143
1.9855
0.3705
35.10
0.8049
0.9133
0.9907
1.0806
1.3003
1.3700
1.6098
1.6667
1.9194
1.9673
0.3715
40.72
NAME
RAVEN
QUAIL
PIGEON
PENGUIN
WAXWING
PARTRIDGE
MERLIN
LINNET
ORIOLE
CHICKADEE
SIZE
1/0
2/0
4/0
266.8
266.8
336.4
336.4
336.4
397.5
397.5
STRAND
6/1
6/1
6/1
6/1
18/1
26/7
18/1
26/7
30/7
18/1
IBIS
LARK
PELICAN
FLICKER
HAWK
HEN
OSPREY
PARAKEET
DOVE
EAGLE
397.5
397.5
477.
477.
477.
477.
556.5
556.5
556.5
556.5
26/7
30/7
18/1
24/7
26/7
30/7
18/1
24/7
26/7
30/7
0.5469
0.6228
0.5180
0.6145
0.6570
0.7470
0.6040
0.7170
0.7660
0.8720
0.8483
0.8732
0.8818
0.9165
0.9295
0.9566
0.9523
0.9902
1.0043
1.0324
1.0093
1.0725
1.0227
1.1034
1.1383
1.2137
1.1277
1.2225
1.2630
1.3514
1.0440
1.0747
1.0853
1.1280
1.1440
1.1773
1.1720
1.2187
1.2360
1.2707
1.1786
1.2421
1.2026
1.2845
1.3192
1.3943
1.3185
1.4139
1.4541
1.5411
1.3703
1.4105
1.4245
1.4805
1.5015
1.5453
1.5383
1.5995
1.6223
1.6678
1.4754
1.5419
1.5158
1.6030
1.6389
1.7163
1.6526
1.7529
1.7940
1.8820
1.6965
1.7463
1.7637
1.8330
1.8590
1.9132
1.9045
1.9803
2.0085
2.0648
1.7825
1.8541
1.8382
1.9333
1.9717
2.0538
1.9980
2.1061
2.1496
2.2414
2.0228
2.0822
2.1028
2.1855
2.2165
2.2811
2.2708
2.3612
2.3948
2.4619
2.0954
2.1733
2.1657
2.2702
2.3118
2.4003
2.3497
2.4676
2.5143
2.6118
0.3915
0.4030
0.4070
0.4230
0.4290
0.4415
0.4395
0.4570
0.4635
0.4765
35.60
32.91
38.16
34.54
33.14
30.58
36.04
32.51
31.18
28.65
KINGBIRD
ROOK
GOSBEAK
EGRET
CUCKOO
DRAKE
MALLARD
TERN
CONDOR
RAIL
636.
636.
636.
636.
795.
795.
795.
795.
795.
954.
18/1
24/7
26/7
30/19
24/7
26/7
30/19
45/7
54/7
45/7
0.6910
0.8190
0.8750
0.9880
1.0240
1.0940
1.2350
0.8960
1.0240
1.0750
1.0183
1.0801
1.0725
1.1039
1.1830
1.2003
1.2350
1.1516
1.1841
1.2621
1.2306
1.3555
1.3842
1.4815
1.5646
1.6241
1.7466
1.4591
1.5654
1.6579
1.2533
1.3293
1.3200
1.3587
1.4560
1.4773
1.5200
1.4173
1.4573
1.5533
1.4312
1.5614
1.5837
1.6799
1.7800
1.8383
1.9585
1.6768
1.7811
1.8890
1.6450
1.7448
1.7325
1.7833
1.9110
1.9390
1.9950
1.8603
1.9128
2.0388
1.7842
1.9274
1.9409
2.0387
2.1681
2.2263
2.3463
2.0648
2.1696
2.3048
2.0367
2.1602
2.1450
2.2078
2.3660
2.4007
2.4700
2.3032
2.3682
2.5242
2.1507
2.3102
2.3166
2.4188
2.5781
2.6382
2.7615
2.4713
2.5801
2.7435
2.4283
2.5756
2.5575
2.6324
2.8210
2.8623
2.9450
2.7461
2.8236
3.0096
2.5247
2.7027
2.7030
2.8117
3.0011
3.0643
3.1935
2.8886
3.0035
3.1958
0.4700
0.4985
0.4950
0.5095
0.5460
0.5540
0.5700
0.5315
0.5465
0.5825
34.22
31.33
29.50
27.28
28.07
26.86
24.78
30.68
28.09
28.45
CARDINAL
BUNTING
GRACKLE
BITTERN
PHEASANT
LAPWING
FALCON
CHUKAR
BLUEBIRD
954.
1192.5
1192.5
1272.
1272.
1590.
1590.
1780.
2156.
54/7
45/7
54/19
45/7
54/19
45/7
54/19
84/19
84/19
1.2290
1.3440
1.5330
1.4340
1.6350
1.7920
2.0440
2.0740
2.5110
1.2957
1.4105
1.4495
1.4571
1.4972
1.6272
1.6738
1.7355
1.9088
1.7858
1.9483
2.1098
2.0444
2.2169
2.4205
2.6419
2.7043
3.1542
1.5947
1.7360
1.7840
1.7933
1.8427
2.0027
2.0600
2.1360
2.3493
2.0133
2.1955
2.3522
2.2962
2.4635
2.6874
2.9020
2.9772
3.4387
2.0930
2.2785
2.3415
2.3538
2.4185
2.6285
2.7038
2.8035
3.0835
2.4272
2.6454
2.7987
2.7562
2.9193
3.1812
3.3894
3.4873
3.9766
2.5913
2.8210
2.8990
2.9142
2.9943
3.2543
3.3475
3.4710
3.8177
2.8680
3.1248
3.2794
3.2479
3.4116
3.7151
3.9222
4.0434
4.5694
3.0897
3.3635
3.4565
3.4746
3.5702
3.8802
3.9913
4.1385
4.5518
3.3251
3.6221
3.7812
3.7589
3.9267
4.2740
4.4842
4.6291
5.1985
0.5980
0.6510
0.6690
0.6725
0.6910
0.7510
0.7725
0.8010
0.8810
25.95
25.84
23.58
25.13
22.91
22.74
20.70
21.12
19.33
Bulletin 1724E-200
Page B-5
ACSR CONDUCTORS
MISCELLANEOUS LOADINGS
DIAM. WT./FT
NAME
SIZE STRAND IN.
LBS.
RAVEN
1/0
6/1
0.398 0.1452
QUAIL
2/0
6/1
0.447 0.1831
PIGEON
4/0
6/1
0.502 0.2309
PENGUIN 266.8
6/1
0.563 0.2911
WAXWING 266.8
18/1
0.609 0.2894
PARTRIDG 336.4
26/7
0.642 0.3673
MERLIN
336.4
18/1
0.684 0.3653
LINNET
336.4
26/7
0.721 0.4630
ORIOLE
397.5
30/7
0.741 0.5271
18/1
0.743 0.4316
CHICKADE 397.5
0.75 INCH ICE 1PSF
1 INCH ICE
1PSF
1.25 INCH ICE
1PSF
WT./FT
TRANS
WT./FT
TRANS
WT./FT
TRANS
LBS.
LB/FT
LBS.
LB/FT
LBS.
LB/FT
1.2159
0.1582
1.8837
0.1998
2.7069
0.2415
1.2995
0.1623
1.9825
0.2039
2.8210
0.2456
1.3986
0.1668
2.0987
0.2085
2.9543
0.2502
1.5157
0.1719
2.2348
0.2136
3.1093
0.2553
1.5569
0.1758
2.2903
0.2174
3.1791
0.2591
1.6656
0.1785
2.4092
0.2202
3.3083
0.2618
1.7027
0.1820
2.4594
0.2237
3.3716
0.2653
1.8349
0.1851
2.6031
0.2268
3.5268
0.2684
1.9177
0.1868
2.6921
0.2284
3.6220
0.2701
1.8241
0.1869
2.5991
0.2286
3.5296
0.2703
IBIS
LARK
PELICAN
FLICKER
HAWK
HEN
OSPREY
PARAKEE
DOVE
EAGLE
397.5
397.5
477.
477.
477.
477.
556.5
556.5
556.5
556.5
26/7
30/7
18/1
24/7
26/7
30/7
18/1
24/7
26/7
30/7
0.783
0.806
0.814
0.846
0.858
0.883
0.879
0.914
0.927
0.953
0.5469
0.6228
0.5180
0.6145
0.6570
0.7470
0.6040
0.7170
0.7660
0.8720
1.9767
2.0740
1.9767
2.1030
2.1567
2.2700
2.1233
2.2689
2.3301
2.4603
0.1903
0.1922
0.1928
0.1955
0.1965
0.1986
0.1983
0.2012
0.2023
0.2044
2.7641
2.8686
2.7738
2.9101
2.9675
3.0886
2.9406
3.0971
3.1623
3.3006
0.2319
0.2338
0.2345
0.2372
0.2382
0.2403
0.2399
0.2428
0.2439
0.2461
3.7071
3.8187
3.7264
3.8726
3.9337
4.0626
3.9134
4.0808
4.1500
4.2964
0.2736
0.2755
0.2762
0.2788
0.2798
0.2819
0.2816
0.2845
0.2856
0.2878
KINGBIRD
ROOK
GOSBEAK
EGRET
CUCKOO
DRAKE
MALLARD
TERN
CONDOR
RAIL
636.
636.
636.
636.
795.
795.
795.
795.
795.
954.
18/1
24/7
26/7
30/19
24/7
26/7
30/19
45/7
54/7
45/7
0.940
0.997
0.990
1.019
1.092
1.108
1.140
1.063
1.093
1.165
0.6910
0.8190
0.8750
0.9880
1.0240
1.0940
1.2350
0.8960
1.0240
1.0750
2.2672
2.4484
2.4978
2.6379
2.7420
2.8269
2.9977
2.5869
2.7429
2.8610
0.2033
0.2081
0.2075
0.2099
0.2160
0.2173
0.2200
0.2136
0.2161
0.2221
3.1035
3.3024
3.3497
3.4987
3.6255
3.7154
3.8962
3.4614
3.6267
3.7673
0.2450
0.2498
0.2492
0.2516
0.2577
0.2590
0.2617
0.2553
0.2578
0.2638
4.0952
4.3118
4.3569
4.5150
4.6645
4.7594
4.9501
4.4914
4.6660
4.8290
0.2867
0.2914
0.2908
0.2933
0.2993
0.3007
0.3033
0.2969
0.2994
0.3054
CARDINAL
BUNTING
GRACKLE
BITTERN
PHEASAN
LAPWING
FALCON
CHUKAR
BLUEBIRD
954.
1192.5
1192.5
1272.
1272.
1590.
1590.
1780.
2156.
54/7
45/7
54/19
45/7
54/19
45/7
54/19
84/19
84/19
1.196
1.302
1.338
1.345
1.382
1.502
1.545
1.602
1.762
1.2290
1.3440
1.5330
1.4340
1.6350
1.7920
2.0440
2.0740
2.5110
3.0440
3.2578
3.4804
3.3879
3.6234
3.8924
4.1845
4.2676
4.8538
0.2247
0.2335
0.2365
0.2371
0.2402
0.2502
0.2538
0.2585
0.2718
3.9598
4.2066
4.4404
4.3501
4.5971
4.9034
5.2088
5.3097
5.9457
0.2663
0.2752
0.2782
0.2788
0.2818
0.2918
0.2954
0.3002
0.3135
5.0311
5.3109
5.5559
5.4678
5.7263
6.0698
6.3886
6.5072
7.1930
0.3080
0.3168
0.3198
0.3204
0.3235
0.3335
0.3371
0.3418
0.3552
Transverse loadings are based on 1 psf on
the indicated ice condition. Transverse
loadings other than 1psf can be obtained by
multiplying the transverse loading value in the
table by the amount of the expected wind load
For example, the transverse load caused by a
6 psf wind on a 477 kcmil 26/7 conductor
covered by 1 inch of radial ice is:
.2382(6) = 1.4292 lb/ft.
Bulletin 1724E-200
Page B-6
6201 A LUM INUM A LLO Y CO NDUCTO RS
NE S C DIS TRICT LO A DING S
NA M E
A ZUS A
A NA HE IM
A M HE RS T
A LLIA NCE
B UTTE
CA NTO N
CA IRO
DA RIE N
E LO IN
F LINT
G RE E LE Y
S IZE
123.3
155.4
195.7
246.9
312.8
394.5
465.4
559.5
652.4
740.8
927.2
LIG HT
.00" ICE , 9 LB ., K = .05
V E RT.
TRA NS RE S ULTA NT
LB /FT
LB /FT
LB /FT
0.1157
0.2985
0.3701
0.1459
0.3353
0.4156
0.1837
0.3765
0.4689
0.2318
0.4223
0.5317
0.2936
0.4815
0.6140
0.3703
0.5408
0.7054
0.4369
0.5873
0.7819
0.5252
0.6435
0.8806
0.6124
0.6953
0.9765
0.6954
0.7433
1.0678
0.8704
0.8310
1.2534
S TRA ND
7
7
7
7
19
19
19
19
19
37
37
M E DIUM
.25" ICE , 4 LB W IND, K = .20
V E RT.
TRA NS RE S ULTA NT
LB /FT
LB /F T
LB /F T
0.3172
0.2993
0.6361
0.3626
0.3157
0.6807
0.4175
0.3340
0.7347
0.4846
0.3543
0.8003
0.5709
0.3807
0.8862
0.6722
0.4070
0.9858
0.7580
0.4277
1.0704
0.8697
0.4527
1.1804
0.9783
0.4757
1.2878
1.0812
0.4970
1.3900
1.2926
0.5360
1.5993
HE A V Y
.5" ICE , 4 LB W IND, K = .30
V E RT.
TRA NS RE S ULTA NT
LB /F T
LB /FT
LB /FT
0.6741
0.4660
1.1195
0.7347
0.4823
1.1789
0.8067
0.5007
1.2495
0.8927
0.5210
1.3337
1.0037
0.5473
1.4432
1.1295
0.5737
1.5668
1.2346
0.5943
1.6702
1.3696
0.6193
1.8031
1.4997
0.6423
1.9314
1.6225
0.6637
2.0530
1.8702
0.7027
2.2979
6201 A LUM INUM A LLO Y CO NDUCTO RS
HIG H W IND LO A DING S
NA M E
A ZUS A
A NA HE IM
A M HE RS T
A LLIA NCE
B UTTE
CA NTO N
CA IRO
DA RIE N
E LO IN
F LINT
G RE E LE Y
S IZE
123.3
155.4
195.7
246.9
312.8
394.5
465.4
559.5
652.4
740.8
927.2
W T./F T
LB S .
0.1157
0.1459
0.1837
0.2318
0.2936
0.3703
0.4369
0.5252
0.6124
0.6954
0.8704
S TRA ND
7
7
7
7
19
19
19
19
19
37
37
13 ps f
16 ps f
21 ps f
26 ps f
31 ps f
TRA NS RE S ULTA NT TRA NS RE S ULTA NT TRA NS RE S ULTA NT TRA NS RE S ULTA NT TRA NS RE S ULTA NT
LB /FT
LB /FT
LB /FT
LB /FT
LB /F T
LB /F T
LB /F T
LB /F T
LB /FT
LB /FT
0.4312
0.4464
0.5307
0.5431
0.6965
0.7060
0.8623
0.8701
1.0282
1.0347
0.4843
0.5058
0.5960
0.6136
0.7823
0.7957
0.9685
0.9794
1.1548
1.1639
0.5438
0.5740
0.6693
0.6941
0.8785
0.8975
1.0877
1.1031
1.2968
1.3098
0.6099
0.6525
0.7507
0.7856
0.9853
1.0122
1.2198
1.2417
1.4544
1.4728
0.6955
0.7549
0.8560
0.9050
1.1235
1.1612
1.3910
1.4216
1.6585
1.6843
0.7811
0.8644
0.9613
1.0302
1.2618
1.3150
1.5622
1.6055
1.8626
1.8990
0.8483
0.9542
1.0440
1.1317
1.3703
1.4382
1.6965
1.7519
2.0228
2.0694
0.9295
1.0676
1.1440
1.2588
1.5015
1.5907
1.8590
1.9318
2.2165
2.2779
1.0043
1.1762
1.2360
1.3794
1.6223
1.7340
2.0085
2.0998
2.3948
2.4718
1.0736
1.2791
1.3213
1.4932
1.7343
1.8685
2.1472
2.2570
2.5601
2.6528
1.2003
1.4827
1.4773
1.7147
1.9390
2.1254
2.4007
2.5536
2.8623
2.9917
6201 A LUM INUM A LLO Y CO NDUCTO RS - M IS CE LLA NE O US LO A DING S
NA M E
S IZE
S TRA ND
A ZUS A
A NA HE IM
A M HE RS T
A LLIA NCE
B UTTE
CA NTO N
CA IRO
DA RIE N
E LO IN
F LINT
G RE E LE Y
123.3
155.4
195.7
246.9
312.8
394.5
465.4
559.5
652.4
740.8
927.2
7
7
7
7
19
19
19
19
19
37
37
0.75 " ICE
W T./F T
TRA NS
LB S .
for 1ps f
LB /FT
1.1864
0.1582
1.2623
0.1623
1.3514
0.1668
1.4564
0.1719
1.5919
0.1785
1.7422
0.1851
1.8667
0.1903
2.0249
0.1965
2.1765
0.2023
2.3192
0.2076
2.6033
0.2173
1.0 " ICE
W T./F T
TRA NS
LB S .
for 1ps f
LB /FT
1.8542
0.1998
1.9453
0.2039
2.0515
0.2085
2.1755
0.2136
2.3355
0.2202
2.5104
0.2268
2.6541
0.2319
2.8357
0.2382
3.0087
0.2439
3.1713
0.2493
3.4918
0.2590
1.25 " ICE
W T./FT
TRA NS
LB S .
for 1ps f
LB /FT
2.6774
0.2415
2.7838
0.2456
2.9071
0.2502
3.0500
0.2553
3.2346
0.2618
3.4341
0.2684
3.5971
0.2736
3.8020
0.2798
3.9964
0.2856
4.1789
0.2909
4.5358
0.3007
Trans vers e Loadings other than 1 ps f on the indic ated ic e
c ondition c an be obtained by m ultiply ing the trans vers e l
value in the table by the am ount of the ex pec ted wind loa
per foot.
For ex am ple, the trans vers e load c aus ed by a 6 ps f wind
wind on a 559.5 k c m il c onduc tor c overed by 1 inc h of rad
.2382(6) = 1.4292 lb/ft.
Bulletin 1724E-200
Page B-7
1350 ALUMINUM ALLOY CONDUCTORS
NESC DISTRICT LOADINGS
NAME
POPPY
ASTRE
PHLOX
OXLIP
VALERIAN
DAISY
LAUREL
TULIP
CANNA
GOLDENTUFT
COSMOS
SYRINGA
DAHLIA
MISTLETOE
ORCHID
ARBUTUS
LILAC
ANEMONE
CROCUS
MAGNOLIA
GOLDENROD
HAWTHORN
NARCESSUS
COREOPSIS
SIZE
1/0
2/0
3/0
4/0
250.
266.8
266.8
336.4
397.5
450.
477.
477.
556.5
556.5
636.
795.
795.
874.5
874.5
954.
954.
1192.5
1272.
1590
STRAND
7
7
7
7
19
7
19
19
19
19
19
37
19
37
37
37
61
37
61
37
61
61
61
61
LIGHT
.00" ICE, 9 LB., K=.05
VERT.
TRANS RESULTANT
LB/FT
LB/FT
LB/FT
0.0991
0.2760
0.3433
0.1249
0.3105
0.3847
0.1575
0.3480
0.4320
0.1986
0.3915
0.4890
0.2347
0.4305
0.5403
0.2505
0.4395
0.5559
0.2505
0.4448
0.5604
0.3128
0.4995
0.6394
0.3731
0.5430
0.7088
0.4224
0.5775
0.7655
0.4478
0.5948
0.7945
0.4478
0.5963
0.7957
0.5220
0.6420
0.8774
0.5220
0.6435
0.8786
0.5970
0.6885
0.9613
0.7460
0.7695
1.1217
0.7460
0.7710
1.1228
0.8210
0.8078
1.2017
0.8210
0.8085
1.2023
0.8960
0.8430
1.2802
0.8960
0.8445
1.2813
1.1190
0.9435
1.5137
1.1920
0.9750
1.5900
1.4900
1.0898
1.8960
MEDIUM
.25" ICE, 4 LB WIND, K=.20
VERT.
TRANS RESULTANT
LB/FT
LB/FT
LB/FT
0.2912
0.2893
0.6105
0.3313
0.3047
0.6501
0.3795
0.3213
0.6972
0.4386
0.3407
0.7554
0.4909
0.3580
0.8076
0.5104
0.3620
0.8257
0.5126
0.3643
0.8289
0.5976
0.3887
0.9128
0.6759
0.4080
0.9895
0.7395
0.4233
1.0521
0.7721
0.4310
1.0842
0.7727
0.4317
1.0851
0.8658
0.4520
1.1767
0.8665
0.4527
1.1776
0.9601
0.4727
1.2702
1.1427
0.5087
1.4508
1.1433
0.5093
1.4516
1.2335
0.5257
1.5409
1.2339
0.5260
1.5413
1.3232
0.5413
1.6296
1.3238
0.5420
1.6304
1.5878
0.5860
1.8925
1.6739
0.6000
1.9782
2.0194
0.6510
2.3218
HEAVY
.5" ICE, 4 LB WIND, K=.30
VERT.
TRANS RESULTANT
LB/FT
LB/FT
LB/FT
0.6388
0.4560
1.0849
0.6932
0.4713
1.1383
0.7569
0.4880
1.2006
0.8341
0.5073
1.2762
0.9025
0.5247
1.3439
0.9257
0.5287
1.3661
0.9301
0.5310
1.3710
1.0378
0.5553
1.4770
1.1342
0.5747
1.5714
1.2121
0.5900
1.6480
1.2518
0.5977
1.6871
1.2530
0.5983
1.6885
1.3651
0.6187
1.7988
1.3664
0.6193
1.8002
1.4787
0.6393
1.9110
1.6948
0.6753
2.1244
1.6961
0.6760
2.1258
1.8015
0.6923
2.2300
1.8022
0.6927
2.2307
1.9058
0.7080
2.3330
1.9070
0.7087
2.3344
2.2121
0.7527
2.6366
2.3112
0.7667
2.7350
2.7043
0.8177
3.1252
ULTIMATE
STRENGTH
LBS.
1990
2510
3040
3830
4660
4830
4970
6150
7110
7890
8360
8690
9750
9940
11400
13900
14300
15000
15800
16400
16900
21100
22000
27000
1350 ALUMINUM ALLOY CONDUCTORS
HIGH WIND LOADINGS
NAME
POPPY
ASTER
PHLOX
OXLIP
DAISY
LAUREL
TULIP
CANNA
GOLDENTUFT
COSMOS
SYRINGA
DAHLIA
MISTLETOE
ORCHID
ARBUTUS
LILAC
ANEMONE
CROCUS
MAGNOLIA
GOLDENROD
HAWTHORN
NARCESSUS
COREOPSIS
SIZE
1/0
2/0
3/0
4/0
266.8
266.8
336.4
397.5
450.
477.
477.
556.5
556.5
636.
795.
795.
874.5
874.5
954.
954.
1192.5
1272.
1590
STRAND
7
7
7
7
7
19
19
19
19
19
37
19
37
37
37
61
37
61
37
61
61
61
61
WT./FT
LBS.
0.0991
0.1249
0.1575
0.1986
0.2505
0.2505
0.3128
0.3731
0.4224
0.4478
0.4478
0.5220
0.5220
0.5970
0.7460
0.7460
0.8210
0.8210
0.8960
0.8960
1.1190
1.1920
1.1940
13 psf
TRANS RESULTANT
LB/FT
LB/FT
0.3987
0.4108
0.4485
0.4656
0.5027
0.5268
0.5655
0.5994
0.6348
0.6825
0.6424
0.6895
0.7215
0.7864
0.7843
0.8686
0.8342
0.9350
0.8591
0.9688
0.8613
0.9707
0.9273
1.0642
0.9295
1.0660
0.9945
1.1599
1.1115
1.3386
1.1137
1.3404
1.1668
1.4267
1.1678
1.4275
1.2177
1.5118
1.2198
1.5135
1.3628
1.7634
1.4083
1.8451
1.5741
1.9757
16 psf
TRANS RESULTANT
LB/FT
LB/FT
0.4907
0.5006
0.5520
0.5660
0.6187
0.6384
0.6960
0.7238
0.7813
0.8205
0.7907
0.8294
0.8880
0.9415
0.9653
1.0349
1.0267
1.1102
1.0573
1.1483
1.0600
1.1507
1.1413
1.2550
1.1440
1.2575
1.2240
1.3618
1.3680
1.5582
1.3707
1.5605
1.4360
1.6541
1.4373
1.6553
1.4987
1.7461
1.5013
1.7484
1.6773
2.0163
1.7333
2.1036
1.9373
2.2757
21 psf
TRANS RESULTANT
LB/FT
LB/FT
0.6440
0.6516
0.7245
0.7352
0.8120
0.8271
0.9135
0.9348
1.0255
1.0557
1.0378
1.0676
1.1655
1.2067
1.2670
1.3208
1.3475
1.4122
1.3878
1.4582
1.3913
1.4615
1.4980
1.5863
1.5015
1.5896
1.6065
1.7138
1.7955
1.9443
1.7990
1.9475
1.8848
2.0558
1.8865
2.0574
1.9670
2.1615
1.9705
2.1646
2.2015
2.4696
2.2750
2.5684
2.5428
2.8091
26 psf
TRANS RESULTANT
LB/FT
LB/FT
0.7973
0.8035
0.8970
0.9057
1.0053
1.0176
1.1310
1.1483
1.2697
1.2941
1.2848
1.3090
1.4430
1.4765
1.5687
1.6124
1.6683
1.7210
1.7182
1.7756
1.7225
1.7798
1.8547
1.9267
1.8590
1.9309
1.9890
2.0767
2.2230
2.3448
2.2273
2.3489
2.3335
2.4737
2.3357
2.4758
2.4353
2.5949
2.4397
2.5990
2.7257
2.9464
2.8167
3.0585
3.1482
3.3670
31 psf
TRANS RESULTANT
LB/FT
LB/FT
0.9507
0.9558
1.0695
1.0768
1.1987
1.2090
1.3485
1.3630
1.5138
1.5344
1.5319
1.5523
1.7205
1.7487
1.8703
1.9072
1.9892
2.0335
2.0486
2.0970
2.0538
2.1020
2.2113
2.2721
2.2165
2.2771
2.3715
2.4455
2.6505
2.7535
2.6557
2.7585
2.7823
2.9009
2.7848
2.9033
2.9037
3.0388
2.9088
3.0437
3.2498
3.4371
3.3583
3.5636
3.7536
3.9389
6 psf
TRANS
SWING
LB/FT
ANGLE
0.1840
61.7
0.2070
58.9
0.2320
55.8
0.2610
52.7
0.2930
49.5
0.2965
49.8
0.3330
46.8
0.3620
44.1
0.3850
42.3
0.3965
41.5
0.3975
41.6
0.4280
39.3
0.4290
39.4
0.4590
37.6
0.5130
34.5
0.5140
34.6
0.5385
33.3
0.5390
33.3
0.5620
32.1
0.5630
32.1
0.6290
29.3
0.6500
28.6
0.7265
31.3
DIAM.
WT./FT
IN.
LBS.
0.368
0.0991
0.414
0.1249
0.464
0.1575
0.522
0.1986
0.574
0.2347
0.586
0.2505
0.593
0.2505
0.666
0.3128
0.724
0.3731
0.770
0.4224
0.793
0.4478
0.795
0.4478
0.856
0.5220
0.858
0.5220
0.918
0.5970
1.026
0.7460
1.028
0.7460
1.077
0.8210
1.078
0.8210
1.124
0.8960
1.126
0.8960
1.258
1.1190
1.300
1.1920
1.453
1.4900
Bulletin 1724E-200
Page B-8
1350 ALUMINUM ALLOY CONDUCTORS
MISCELLANEOUS LOADINGS
NAME
POPPY
ASTRE
PHLOX
OXLIP
VALERIAN
DAISY
LAUREL
TULIP
CANNA
GOLDENTUFT
COSMOS
SYRINGA
DAHLIA
MISTLETOE
ORCHID
ARBUTUS
LILAC
ANEMONE
CROCUS
MAGNOLIA
GOLDENROD
HAWTHORN
SIZE
STRAND
1/0
2/0
3/0
4/0
250.
266.8
266.8
336.4
397.5
450.
477.
477.
556.5
556.5
636.
795.
795.
874.5
874.5
954.
954.
1192.5
7
7
7
7
19
7
19
19
19
19
19
37
19
37
37
37
61
37
61
37
61
61
DIAM.
WT./FT
IN.
LBS.
0.368 0.0991
0.414 0.1249
0.464 0.1575
0.522 0.1986
0.574 0.2347
0.586 0.2505
0.593 0.2505
0.666 0.3128
0.724 0.3731
0.770 0.4224
0.793 0.4478
0.795 0.4478
0.856 0.5220
0.858 0.5220
0.918 0.5970
1.026 0.7460
1.028 0.7460
1.077 0.8210
1.078 0.8210
1.124 0.8960
1.126 0.8960
1.258 1.1190
.75 " ICE
1.0 " ICE
1.25 " ICE
WT./FT
TRANS WT./FT
TRANS WT./FT
TRANS
LBS.
for 1psf
LBS.
for 1psf
LBS.
for 1psf
LB/FT
LB/FT
LB/FT
1.1418
0.1557
1.8003
0.1973
2.6142
0.2390
1.2105
0.1595
1.8833
0.2012
2.7115
0.2428
1.2898
0.1637
1.9781
0.2053
2.8218
0.2470
1.3849
0.1685
2.0913
0.2102
2.9531
0.2518
1.4695
0.1728
2.1920
0.2145
3.0700
0.2562
1.4965
0.1738
2.2228
0.2155
3.1044
0.2572
1.5031
0.1744
2.2315
0.2161
3.1153
0.2578
1.6335
0.1805
2.3846
0.2222
3.2911
0.2638
1.7478
0.1853
2.5170
0.2270
3.4416
0.2687
1.8400
0.1892
2.6235
0.2308
3.5624
0.2725
1.8869
0.1911
2.6775
0.2328
3.6235
0.2744
1.8888
0.1913
2.6800
0.2329
3.6266
0.2746
2.0199
0.1963
2.8300
0.2380
3.7956
0.2797
2.0217
0.1965
2.8325
0.2382
3.7988
0.2798
2.1527
0.2015
2.9821
0.2432
3.9670
0.2848
2.4024
0.2105
3.2654
0.2522
4.2839
0.2938
2.4043
0.2107
3.2679
0.2523
4.2870
0.2940
2.5250
0.2148
3.4039
0.2564
4.4382
0.2981
2.5259
0.2148
3.4051
0.2565
4.4397
0.2982
2.6438
0.2187
3.5373
0.2603
4.5862
0.3020
2.6457
0.2188
3.5398
0.2605
4.5893
0.3022
2.9918
0.2298
3.9269
0.2715
5.0175
0.3132
Bulletin 1724E-200
Page B-9
SIZE
3/8
7/16
3/8
7/16
7 NO. 9
7 NO. 8
7 NO. 7
STRAND
7
7
7
7
LIGHT
.00" ICE, 9 LB., K=.05
VERT.
TRANS RESULTANT
LB/FT
LB/FT
LB/FT
0.2730
0.2700
0.4340
0.3990
0.3263
0.5654
0.2730
0.2700
0.4340
0.3990
0.3263
0.5654
0.2076
0.2573
0.3806
0.2618
0.2888
0.4398
0.3300
0.3248
0.5130
MEDIUM
.25" ICE, 4 LB WIND, K=.20
VERT.
TRANS RESULTANT
LB/FT
LB/FT
LB/FT
0.4626
0.2867
0.7443
0.6120
0.3117
0.8868
0.4626
0.2867
0.7443
0.6120
0.3117
0.8868
0.3920
0.2810
0.6823
0.4592
0.2950
0.7458
0.5423
0.3110
0.8252
HEAVY
.5" ICE, 4 LB WIND, K=.30
VERT.
TRANS RESULTANT
LB/FT
LB/FT
LB/FT
0.8077
0.4533
1.2262
0.9804
0.4783
1.3908
0.8077
0.4533
1.2262
0.9804
0.4783
1.3908
0.7318
0.4477
1.1578
0.8121
0.4617
1.2341
0.9101
0.4777
1.3278
ULTIMATE
STRENGTH
LBS.
10800
14500
15400
20800
12630
15930
19060
OVERHEAD GROUND WIRES
HIGH WIND LOADINGS
SIZE
3/8
7/16
3/8
7/16
7 NO. 9
7 NO. 8
7 NO. 7
STRAND
7
7
7
7
13 psf
16 psf
21 psf
26 psf
31 psf
6 psf
WT./FT
TRANS RESULTANT TRANS RESULTANT TRANS RESULTANT TRANS RESULTANT TRANS RESULTANT TRANS
SWING
LBS.
LB/FT
LB/FT
LB/FT
LB/FT
LB/FT
LB/FT
LB/FT
LB/FT
LB/FT
LB/FT
LB/FT
ANGLE
0.2730
0.3900
0.4761
0.4800
0.5522
0.6300
0.6866
0.7800
0.8264
0.9300
0.9692
0.1800
33.4
0.3990
0.4713
0.6175
0.5800
0.7040
0.7613
0.8595
0.9425
1.0235
1.1238
1.1925
0.2175
28.6
0.2730
0.3900
0.4761
0.4800
0.5522
0.6300
0.6866
0.7800
0.8264
0.9300
0.9692
0.1800
33.4
0.3990
0.4713
0.6175
0.5800
0.7040
0.7613
0.8595
0.9425
1.0235
1.1238
1.1925
0.2175
28.6
0.2076
0.3716
0.4256
0.4573
0.5022
0.6003
0.6351
0.7432
0.7716
0.8861
0.9101
0.1715
39.6
0.2618
0.4171
0.4924
0.5133
0.5762
0.6738
0.7228
0.8342
0.8743
0.9946
1.0285
0.1925
36.3
0.3300
0.4691
0.5735
0.5773
0.6650
0.7578
0.8265
0.9382
0.9945
1.1186
1.1662
0.2165
33.3
OVERHEAD GROUND WIRES - MISCELLANEOUS LOADINGS
SIZE
STRAND
3/8
7/16
3/8
7/16
7 NO. 9
7 NO. 8
7 NO. 7
7
7
7
7
0.75 " ICE
1.0 " ICE
WT./FT
TRANS WT./FT
TRANS
LBS.
for 1psf
LBS.
for 1psf
LB/FT
LB/FT
1.3083
0.1550
1.9642
0.1967
1.5042
0.1613
2.1835
0.2029
1.3083
0.1550
1.9642
0.1967
1.5042
0.1613
2.1835
0.2029
1.2270
0.1536
1.8777
0.1953
1.3204
0.1571
1.9841
0.1988
1.4333
0.1611
2.1120
0.2028
1.25 " ICE
WT./FT
TRANS
LBS.
for 1psf
LB/FT
2.7756
0.2383
3.0182
0.2446
2.7756
0.2383
3.0182
0.2446
2.6838
0.2369
2.8033
0.2404
2.9461
0.2444
Transverse Loadings other than 1 psf on the indicated ice
condition can be obtained by multiplying the transverse loading
value in the table by the amount of the expected wind load
per foot.
For example, the transverse load caused by a 6 psf wind on
3/8" HIGH STRENGTH STEEL OHGW covered by 1 inch of radial ice is:
.1967(6) = 1.1802 lb/ft.
Bulletin 1724E-200
Page B-10
Blank Page
Bulletin 1724E-200
Page C-1
APPENDIX C
INSULATION TABLES
•
Flashover Data For Porcelain String
5-3/4”X 10” Standard Suspension Insulators
C-2
•
Flashover Data For Suspension Polymers
ANSI C29.12-1997
C-3
•
Approximate Weights and Length of Insulator Strings Using
Standard 5-3/4 in. x 10 in. Suspension Bells
C-4
Bulletin 1724E-200
Page C-2
TABLE C-1
FLASHOVER DATA FOR PORCELAIN STRING
5-3/4”X 10” STANDARD SUSPENSION INSULATORS
60Hz
Flashover-kV
Units in
string
Impulse Flashover, kV
1.5 X 50
Dry
Wet
Positive
Negative
2
3
4
5
155
215
270
325
90
130
170
215
250
355
440
525
250
340
415
495
6
7
8
9
10
380
435
485
540
590
255
295
335
375
415
610
695
780
860
945
585
670
760
845
930
11
12
13
14
15
640
690
735
785
830
455
490
525
565
600
1025
1105
1185
1265
1345
1015
1105
1190
1275
1360
16
17
18
19
20
875
920
965
1010
1055
630
660
690
720
750
1425
1505
1585
1665
1745
1440
1530
1615
1700
1785
21
22
23
24
25
1095
1135
1175
1215
1255
775
800
825
850
875
1820
1895
1970
2045
2120
1865
1945
2025
2105
2185
Bulletin 1724E-200
Page C-3
TABLE C-2
FLASHOVER DATA FOR SUSPENSION POLYMERS
(ANSI C29.12-1997)
Electrical Values
Low Frequency flashover
Critical Impulse Flashover
ANSI
Class
Dry
(kV)
Wet
(kV)
Positive
(kV)
Negative
(kV)
60-1
60-2
60-3
60-4
60-5
60-6
60-7
60-8
60-9
60-10
60-11
60-12
60-13
60-14
365
410
470
485
560
620
670
720
810
900
925
980
1060
1345
310
350
415
455
490
545
580
620
690
755
795
830
890
1290
610
675
780
860
925
1025
1105
1185
1345
1490
1575
1665
1825
2530
585
670
760
845
930
1015
1105
1190
1360
1530
1600
1700
1870
2630
Bulletin 1724E-200
Page C-4
TABLE C-3
APPROXIMATE WEIGHTS AND LENGTHS OF
INSULATOR STRINGS USING STANDARD
5-3/4” x 10” SUSPENSION BELLS WITH A BALL HOOK*
Number of
Insulators
Length of String
(Includes Suspension
Hardware), Ft.
Weight of String
(Includes Suspension
Hardware), Lbs.
Max. Voltage- for the
Number of Insulators
(Tangent)
3
4
5
6
7
8
9
10
11
12
13
14
15
16
2.00
2.50
3.00
3.50
3.92
4.42
4.92
5.33
5.83
6.33
6.83
7.25
7.75
8.25
45
58
71
84
96
109
122
135
147
160
173
186
198
211
34.5 kV, 46 kV
69 kV
*Exact length and weight will vary slightly depending upon conductor
suspension hardware used.
115 kV
161 kV
230 kV
Bulletin 1724E-200
Page D-1
APPENDIX D
AMPACITY, MVA, SURFACE GRADIENT TABLES
•
Ampacity Of ACSR Conductors
D-2
•
MVA Limits
D-3
Bulletin 1724E-200
Page D-2
TABLE D-1
AMPACITY OF ACSR CONDUCTORS
Conductor Temperature
Summer ambient
Winter ambient
Wind (ft./sec.)
NAME
RAVEN
QUAIL
PIGEON
PENGUIN
WAXWING
PARTRIDGE
MERLIN
LINNET
ORIOLE
CHICKADEE
IBIS
LARK
PELICAN
FLICKER
HAWK
HEN
OSPREY
PARAKEET
DOVE
EAGLE
KINGBIRD
ROOK
GOSBEAK
EGRET
CUCKOO
DRAKE
MALLARD
TERN
CONDOR
RAIL
CARDINAL
BUNTING
GRACKLE
BITTERN
PHEASANT
LAPWING
FALCON
CHUKAR
BLUEBIRD
SIZE
1/0
2/0
3/0
4/0
266.8
266.8
336.4
336.4
397.5
397.5
397.5
397.5
477.
477.
477.
477.
556.5
556.5
556.5
556.5
636.
636.
636.
636.
795.
795.
795.
795.
795.
954.
954.
1192.5
1192.5
1272.
1272.
1590.
1590.
1780.
2156
120ºF
104ºF
32ºF
2
STRAND
6/1
6/1
6/1
6/1
18/1
26/7
18/1
26/7
30/7
18/1
26/7
30/7
18/1
24/7
26/7
30/7
18/1
24/7
26/7
30/7
18/1
24/7
26/7
30/19
24/7
26/7
30/19
45/7
54/7
45/7
54/7
45/7
54/19
45/7
54/19
45/7
54/19
84/19
84/19
167ºF
212ºF
104ºF
104ºF
32ºF
32ºF
2
2
Ampacity
Summer Rating
120
167
212
Deg F
Deg F
Deg F
70
195
257
77
223
294
85
255
338
92
291
386
110
359
478
108
364
484
119
416
554
117
420
561
115
423
565
120
461
616
122
466
624
120
469
629
131
516
692
128
521
699
127
522
701
124
526
706
135
568
763
130
573
771
129
575
774
126
579
779
136
617
815
131
623
839
129
625
843
125
629
849
126
715
967
123
718
972
116
723
979
131
709
959
126
715
967
120
793
1076
112
800
1086
84
908
1238
65
927
1264
61
944
1289
21
964
1317
1079
1480
1103
1514
1168
1608
1304
1803
ft./sec.
Ampacity
Winter Rating
120
167
212
Deg F
Deg F
Deg F
240
292
330
275
335
379
315
384
435
357
439
497
442
543
616
447
550
624
511
630
715
517
637
724
520
642
729
544
700
795
574
708
806
578
714
812
636
786
894
641
793
902
644
796
906
648
801
913
700
866
986
706
874
996
709
878
1000
713
884
1007
761
943
1053
768
952
1085
770
955
1089
776
962
1097
882
1096
1251
886
1101
1257
892
1110
1267
874
1086
1240
882
1096
1251
978
1218
1393
987
1229
1406
1121
1400
1604
1144
1429
1637
1165
1457
1670
1190
1489
1706
1330
1670
1919
1361
1709
1963
1440
1813
2085
1606
2030
2340
Bulletin 1724E-200
Page D-3
TABLE D-2: MVA LIMITS
MVA LIMIT FOR 212 DEGREE F OPERATION AT THE INDICATED VOLTAGE
(S = Summer; W = Winter)
CONDUCTOR
SIZE &
NAME
STRAND
RAVEN
QUAIL
PIGEON
PENGUIN
WAXWING
PARTRIDGE
MERLIN
LINNET
ORIOLE
CHICKADEE
IBIS
LARK
PELICAN
FLICKER
HAWK
HEN
OSPREY
PARAKEET
DOVE
EAGLE
KINGBIRD
ROOK
GOSBEAK
EGRET
CUCKOO
DRAKE
MALLARD
TERN
CONDOR
RAIL
CARDINAL
BUNTING
GRACKLE
BITTERN
PHEASANT
LAPWING
FALCON
CHUKAR
BLUEBIRD
1/0
2/0
3/0
4/0
266.8
266.8
336.4
336.4
397.5
397.5
397.5
397.5
477.
477.
477.
477.
556.5
556.5
556.5
556.5
636.
636.
636.
636.
795.
795.
795.
795.
795.
954.
954.
1192.5
1192.5
1272.
1272.
1590.
1590.
1780.
2156
6/1
6/1
6/1
6/1
18/1
26/7
18/1
26/7
30/7
18/1
26/7
30/7
18/1
24/7
26/7
30/7
18/1
24/7
26/7
30/7
18/1
24/7
26/7
30/19
24/7
26/7
30/19
45/7
54/7
45/7
54/7
45/7
54/19
45/7
54/19
45/7
54/19
84/19
84/19
34.5 kV
46 kV
69 kV
115 kV
138 kV
161 kV
230 KV
S
W
S
W
S
W
S
W
S
W
S
W
S
W
15
18
20
23
29
29
33
34
34
37
37
38
41
42
42
42
46
46
46
47
49
50
50
51
58
58
59
57
58
64
65
74
76
77
79
88
90
96
108
20
23
26
30
37
37
43
43
44
48
48
48
53
54
54
55
59
60
60
60
63
65
65
66
75
75
76
74
75
83
84
96
98
100
102
115
117
125
140
20
23
27
31
38
39
44
45
45
37
37
38
41
42
42
42
46
46
46
47
49
50
50
51
58
58
59
57
58
64
65
74
76
77
79
88
90
96
108
26
30
35
40
49
50
57
58
58
48
48
48
53
54
54
55
59
60
60
60
63
65
65
66
75
75
76
74
75
83
84
96
98
100
102
115
117
125
140
31
35
40
46
57
58
66
67
68
74
75
75
83
83
84
84
91
92
93
93
97
100
101
101
116
116
117
115
116
129
130
148
151
154
157
177
181
192
215
39
45
52
59
74
75
85
87
87
95
96
97
107
108
108
109
118
119
120
120
126
130
130
131
150
150
151
148
150
166
168
192
196
200
204
229
235
249
280
51
59
67
77
95
96
110
112
113
123
124
125
138
139
140
141
152
154
154
155
162
167
168
169
193
194
195
191
193
214
216
247
252
257
262
295
302
320
359
66
75
87
99
123
124
142
144
145
158
160
162
178
180
180
182
196
198
199
201
210
216
217
219
249
250
252
247
249
277
280
319
326
333
340
382
391
415
466
61
70
81
92
114
116
132
134
135
147
149
150
165
167
168
169
182
184
185
186
195
201
201
203
231
232
234
229
231
257
260
296
302
308
315
354
362
384
431
79
91
104
119
147
149
171
173
174
190
193
194
214
216
216
218
236
238
239
241
252
259
260
262
299
301
303
296
299
333
336
383
391
399
408
459
469
498
559
72
82
94
108
133
135
155
156
158
172
174
175
193
195
196
197
213
215
216
217
227
234
235
237
270
271
273
267
270
300
303
345
352
359
367
413
422
448
503
92
106
121
139
172
174
199
202
203
222
225
226
249
252
253
254
275
278
279
281
294
303
304
306
349
351
353
346
349
388
392
447
457
466
476
535
548
581
653
102
117
134
154
190
193
221
224
225
246
249
250
276
278
279
281
304
307
308
310
324
334
336
338
385
387
390
382
385
429
433
493
504
514
525
590
603
640
718
132
151
173
198
245
249
285
288
290
317
321
323
356
359
361
364
393
397
398
401
419
432
434
437
498
501
505
494
498
555
560
639
652
665
680
764
782
831
932
Bulletin 1724E-200
Page D-4
Blank Page
Bulletin 1724E-200
Page E-1
APPENDIX E
WEATHER DATA
•
Wind Velocities and Pressures
E-2
•
Conversion Factors for Other Mean Recurrence Intervals
E-3
•
Map of Isokeraunic Levels for the United States
E-4
Bulletin 1724E-200
Page E-2
TABLE E-1
WIND VELOCITIES AND PRESSURES
Actual Wind Velocity,
mi/hr.
psf on a Cylindrical
Surface
psf on a Flat
Surface
35
40
45
49
50
55
60
65
70
75
80
85
90
95
100
105
110
115
120
3.1
4.0
5.2
6.0
6.4
7.7
9.0
10.8
12.5
14.4
16.4
18.5
20.7
23.1
25.6
28.2
31.0
33.9
36.9
4.8
6.3
8.1
9.6
10.0
12.0
14.1
16.9
19.5
22.5
28.9
32.3
36.1
40.0
44.1
48.4
53.0
57.7
63.1
*Based on:
F = .00256V2 (for cylindrical surfaces)
Where:
F= wind force in pounds per square foot.
V= wind velocity in miles per hour.
Bulletin 1724E-200
Page E-3
TABLE E-2
CONVERSION FACTORS FOR OTHER
MEAN RECURRENCE INTERVALS
Peak gust wind speed, V (mph)
Continental U.S.
MRI
(years
)
V=85-100
V>100 (hurricane)
Alaska
500
200
100
50
25
10
1.23
1.14
1.07
1.00
0.93
0.84
1/18
1.12
1.06
1.00
0.94
0.87
5
0.78
1.23
1.14
1.07
1.00
0.88
0.74(76 mph
min.)
0.66(60 mph
min.)
0.81
Note:
Conversion factors for the column “V>100 (hurricane)” are
approximate. For the MRI (mean recurrence interval) = 50 as
shown, the actual return period, as represented by the design
wind speed map in Figures 11-2a to 11-2d, varies from 50 to
approximately 90 years. For an MRI = 500, the conversion
factor is theoretically “exact” as shown.
TABLE E-3
PROBABLILITY OF EXCEEDING DESIGN WIND SPEEDS
DURING REFERENCE PERIOD
Annual
Probablility
Pa
.04(1/25)
.02(1/50)
.01(1/100)
.005(1/200
)
Reference (Exposure) Period, n (years)
1
5
10
25
50
100
0.04
0.02
0.01
0.005
0.18
0.10
0.05
0.02
0.34
0.18
0.10
0.05
0.64
0.40
0.22
0.10
0.87
0.64
0.40
0.22
0.98
0.87
0.64
0.39
FIGURE E-1: ISOKERAUNIC LEVELS FOR THE UNITED STATES
Bulletin 1724E-200
Page E-4
Bulletin 1724E-200
Page F-1
APPENDIX F
POLE DATA
•
Moments (ft-k) at Groundline Due to a 1 psf Wind on the Pole
F-2
•
Moment Capacities for Wood Poles at Groundline
F-3
•
Pole Classes
F-4
•
Moment Capacities for D.F. and SYP Along the Pole
F-5
•
Moment Reduction due to a Bolt Hole in the Pole
F-20
•
Weight and Volume of D.F. and SYP Poles
F-22
Bulletin 1724E-200
Page F-2
TABLE F-1
MOMENTS (FT-K) AT GROUNDLINE
DUE TO A 1 PSF WIND ON THE POLE
6000 psi
Western Red Cedar
6600 psi
Lodgepole Pine
Ht.
Cl-H1
Cl-1
Cl-2
Cl-3
50
55
60
0.9
1.1
0.9
1.0
0.8
1.0
1.4
1.6
1.9
2.2
1.3
1.5
1.8
2.1
2.6
3.0
3.4
3.9
4.4
65
70
75
80
85
90
95
100
Cl-H1
Cl-1
Cl-2
Cl-3
0.7
0.9
0.8
1.0
0.8
1.0
0.7
0.9
1.2
1.4
1.7
2.0
1.1
1.3
1.6
1.8
1.3
1.5
1.8
2.1
1.2
1.4
1.7
1.9
1.1
1.3
1.5
1.8
2.4
2.8
3.2
2.3
2.6
3.0
2.1
2.4
2.7
2.4
2.7
3.1
2.2
2.5
2.9
2.1
2.4
2.7
3.6
4.1
3.4
3.8
3.6
4.0
3.3
3.7
8000 psi
Douglas Fir and
Southern Yellow Pine
8400 psi
Western Larch
Ht.
Cl-H1
Cl-1
Cl-2
Cl-3
Cl-H1
Cl-1
Cl-2
Cl-3
50
55
60
65
0.9
1.1
1.3
0.8
1.0
1.2
0.8
0.9
1.1
0.7
0.9
1.1
0.9
1.1
1.3
0.8
1.0
1.2
0.8
0.9
1.1
0.7
0.9
1.0
1.6
1.8
2.1
2.5
1.5
1.7
2.0
2.3
1.4
1.6
1.9
2.2
1.3
1.5
1.7
2.0
1.6
1.8
2.1
2.5
1.4
1.7
2.0
2.3
1.4
1.6
1.8
2.1
1.2
1.5
1.7
2.0
2.8
3.2
3.7
2.6
3.0
3.4
2.5
2.8
3.2
2.3
2.6
2.8
3.2
3.6
2.6
3.0
3.4
2.4
2.8
3.2
2.3
2.6
4.2
3.9
3.6
4.1
3.9
3.6
70
75
80
85
90
95
100
Bulletin 1724E-200
Page F-3
TABLE F-2
MOMENT CAPACITIES (FT-K) AT GROUNDLINE
For Western Red Cedar (6000 psi), Lodgepole Pine (6600 psi),
Douglas Fir and Southern Yellow Pine (8000 psi) and Western Larch (8400 psi)
6000 psi
Western Red Cedar
6600 psi
Lodgepole Pine
Ht.
ClassH1
Class 1
Class 2
Class 3
Class 1
Class 2
Class 3
Ht.
50
222.2
186.1
154.2
126.2
186.9
153.9
125.1
50
55
245.4
206.9
172.7
137.9
202.5
167.8
137.2
55
60
270.4
229.3
192.7
150.4
225.5
182.5
150.2
60
65
297.1
246.7
202.4
163.7
243.4
198.2
159.0
65
70
317.7
265.1
218.6
177.9
262.4
214.8
173.4
70
75
339.4
284.4
235.7
192.9
282.4
232.4
188.8
75
80
362.2
304.8
253.8
203.1
303.4
251.0
205.1
80
85
386.1
326.2
266.0
219.6
317.5
263.6
216.1
85
90
411.1
348.6
285.6
230.7
340.4
283.8
227.5
90
95
441.6
367.3
301.9
368.0
300.5
95
100
473.4
395.5
326.6
387.8
317.7
100
8000 psi
Douglas Fir & Southern Yellow Pine
8400 psi
Western Larch
Ht.
ClassH1
Class 1
Class 2
Class 3
ClassH1
Class 1
Class 2
Class 3
Ht.
50
220.3
187.2
152.1
121.7
222.4
183.9
148.7
123.0
50
55
246.4
204.2
167.1
134.7
243.6
201.1
163.8
136.4
55
60
266.8
222.3
183.0
148.7
264.3
219.4
179.9
145.4
60
65
288.4
241.5
200.0
163.5
294.4
238.9
203.5
160.4
65
70
311.2
261.9
218.1
179.4
318.0
259.5
215.3
176.4
70
75
335.3
283.4
230.3
190.2
333.8
281.3
227.7
187.3
75
80
360.6
306.2
250.2
201.5
359.6
296.1
247.8
198.7
80
85
387.2
321.5
263.7
213.3
386.7
320.0
261.5
210.6
85
90
405.2
337.5
285.5
225.5
405.0
336.2
275.8
229.9
90
95
438.0
357.3
303.2
438.3
365.6
301.5
95
100
461.5
387.3
321.5
462.1
386.7
319.9
100
Bulletin 1724E-200
Page F-4
TABLE F-3
POLE CLASSES
Wood poles are separated into 15 classes based on the minimum circumference of the pole 6 feet
from the butt. The minimum circumferences have been calculated in order for each species (in a
given class) to develop stresses approximately equal to those shown in the table. These stresses
are developed at the groundline, when a horizontal load is applied 2 feet from the top of the pole.
The horizontal loads used in these calculations are as follows:
Class
Horizontal Load (lbs.)
H6
H5
H4
H3
H2
H1
1
2
3
4
5
6
7
9
10
11,400
10,000
8,700
7,500
6,400
5,400
4,500
3,700
3,000
2,400
1,900
1,500
1,200
740
370
Bulletin 1724E-200
Page F-5
DOUGLAS FIR AND SOUTHERN YELLOW PINE
Ultimate Bending Stress – 8000 psi
55 ft.
Dist.
(ft.)
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
Dia.
(in.)
9.23
9.36
9.50
9.63
9.76
9.90
10.03
10.16
10.30
10.43
10.56
10.70
10.83
10.96
11.10
11.23
11.36
11.49
11.63
11.76
11.89
12.03
12.16
12.29
12.43
12.56
12.69
12.83
12.96
13.09
13.23
13.36
13.49
13.63
13.76
13.89
14.03
14.16
14.29
14.42
14.56
14.69
14.82
14.96
15.09
15.22
15.36
15.49
15.62
15.76
15.82
15.89
15.96
16.02
16.09
16.16
55 ft.
Class H1
Area
Moment
(sq. in.)
(ft-k)
66.92
51.5
68.87
53.7
70.84
56.1
72.84
58.5
74.87
60.9
76.93
63.4
79.01
66.0
81.12
68.7
83.26
71.4
85.43
74.3
87.63
77.1
89.85
80.1
92.10
83.1
94.38
86.2
96.69
89.4
99.02
92.7
101.39
96.0
103.78
99.4
106.19
102.9
108.64
106.5
111.12
110.1
113.62
113.9
116.15
117.7
118.71
121.6
121.29
125.6
123.90
129.7
126.55
133.9
129.21
138.1
131.91
142.5
134.64
146.9
137.39
151.4
140.17
156.0
142.98
160.8
145.81
165.6
148.68
170.5
151.57
175.5
154.49
180.6
157.44
185.8
160.41
191.0
163.42
196.4
166.45
201.9
169.51
207.5
172.60
213.2
175.71
219.0
178.85
224.9
182.02
230.9
185.22
237.0
188.45
243.3
191.70
249.6
194.98
256.0
196.64
259.3
198.31
262.6
199.98
265.9
201.66
269.3
203.34
272.7
205.04
276.1
Dia.
(in.)
8.59
8.72
8.85
8.97
9.10
9.23
9.35
9.48
9.61
9.73
9.86
9.99
10.11
10.24
10.37
10.49
10.62
10.75
10.87
11.00
11.13
11.25
11.38
11.51
11.63
11.76
11.89
12.01
12.14
12.27
12.39
12.52
12.65
12.77
12.90
13.03
13.15
13.28
13.41
13.53
13.66
13.79
13.91
14.04
14.17
14.29
14.42
14.55
14.67
14.80
14.87
14.94
15.00
15.07
15.14
15.20
Class 1
Area
(sq. in.)
58.01
59.73
61.48
63.26
65.05
66.88
68.73
70.60
72.5
74.42
76.37
78.35
80.35
82.37
84.42
86.50
88.60
90.73
92.88
95.05
92.26
99.48
101.73
104.01
106.31
108.64
110.99
113.37
115.78
118.20
120.66
123.14
125.64
128.17
130.72
133.30
135.91
138.54
141.19
143.87
146.58
149.31
152.07
154.85
157.66
160.49
163.34
166.23
169.13
172.07
173.62
175.19
176.76
178.34
179.92
181.52
Moment
(ft-k)
41.5
43.4
45.3
47.3
49.3
51.4
53.6
55.8
58.0
60.4
62.8
65.2
67.7
70.3
72.9
75.6
78.4
81.3
84.2
87.1
90.2
93.3
96.5
99.7
103.1
106.5
110.0
113.5
117.1
120.8
124.6
128.5
132.4
136.4
140.5
144.7
149.0
153.3
157.8
162.3
166.9
171.6
176.3
181.2
186.1
191.2
196.3
201.5
206.8
212.2
215.1
218.0
221.0
223.9
226.9
230.0
Dist.
(ft.)
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
Dia.
(in.)
7.96
8.08
8.20
8.32
8.44
8.56
8.68
8.80
8.92
9.04
9.16
9.28
9.40
9.52
9.64
9.76
9.88
10.00
10.12
10.24
10.36
10.48
10.60
10.72
10.84
10.96
11.08
11.20
11.32
11.44
11.56
11.68
11.80
11.92
12.04
12.16
12.28
12.40
12.52
12.64
12.76
12.89
13.01
13.13
13.25
13.37
13.49
13.61
13.73
13.85
13.91
13.98
14.05
14.11
14.18
14.25
Class 2
Area
(sq. in.)
49.74
51.25
52.79
54.34
55.93
57.53
59.16
60.81
62.48
64.17
65.89
67.63
69.40
71.18
72.99
74.82
76.68
78.55
80.45
82.37
84.32
86.29
88.28
90.29
92.32
94.38
96.46
98.57
100.69
102.84
105.01
107.21
109.42
111.66
113.92
116.21
118.52
120.85
123.20
125.58
127.97
130.40
132.84
135.31
137.79
140.31
142.84
145.40
147.98
150.58
152.04
153.50
154.97
156.45
157.94
159.43
Moment
(ft-k)
33.0
34.5
36.1
37.7
39.3
41.0
42.8
44.6
46.4
48.3
50.3
52.5
54.4
56.5
58.6
60.9
63.1
65.5
67.9
70.3
72.8
75.4
78.0
80.7
83.4
86.2
89.1
92.0
95.0
98.1
101.2
104.4
107.6
111.0
114.3
117.8
121.3
124.9
128.6
132.3
136.1
140.0
144.0
148.0
152.1
156.3
160.5
164.9
169.3
173.8
176.3
178.8
181.4
184.0
186.6
189.3
Dia.
(in.)
7.32
7.43
7.55
7.66
7.78
7.89
8.00
8.12
8.23
8.34
8.46
8.57
8.69
8.80
8.91
9.03
9.14
9.25
9.37
9.48
9.59
9.71
9.82
9.94
10.05
10.16
10.28
10.39
10.50
10.62
10.73
10.85
10.96
11.07
11.19
11.30
11.41
11.53
11.64
11.75
11.87
11.98
12.10
12.21
12.32
12.44
12.55
12.66
12.78
12.89
12.96
13.03
13.09
13.16
13.23
13.29
Class 3
Area
(sq. in.)
42.10
43.41
44.75
46.11
47.49
48.89
50.31
51.75
53.20
54.68
56.18
57.71
59.25
60.81
62.39
63.99
65.61
67.25
68.92
70.60
72.30
74.03
75.77
77.53
79.32
81.12
82.95
84.79
86.66
88.55
90.45
92.38
94.33
96.29
98.28
100.29
102.32
104.36
106.43
108.52
110.63
112.76
114.91
117.08
119.27
121.48
123.71
125.96
128.24
130.53
131.88
133.25
134.62
136.00
137.38
138.77
Moment
(ft-k)
25.7
26.9
28.2
29.4
30.8
32.1
33.6
35.0
36.5
38.0
39.6
41.2
42.9
44.6
46.3
48.1
50.0
51.9
53.8
55.8
57.8
59.9
62.0
64.2
66.4
68.7
71.0
73.4
75.9
78.3
80.9
83.5
86.1
88.9
91.6
94.4
97.3
100.3
103.2
106.3
109.4
112.6
115.8
119.1
122.5
125.9
129.4
132.9
136.5
140.2
142.4
144.6
146.9
149.1
151.4
153.7
Dist.
(ft.)
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
Bulletin 1724E-200
Page F-6
DOUGLAS FIR AND SOUTHERN YELLOW PINE
Ultimate Bending Stress – 8000 psi
60 ft.
Dist.
(ft.)
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
Dia.
(in.)
9.231
9.361
9.49
9.62
9.75
9.879
10.01
10.14
10.27
10.4
10.53
10.66
10.79
10.92
11.05
11.18
11.31
11.44
11.57
11.69
11.82
11.95
12.08
12.21
12.34
12.47
12.6
12.73
12.86
12.99
13.12
13.25
13.38
13.51
13.64
13.77
13.9
14.03
14.16
14.29
14.42
14.55
14.68
14.81
14.94
15.07
15.2
15.33
15.46
15.59
15.72
15.84
15.97
16.1
16.23
16.3
60 ft.
Class H1
Area
Moment
(sq. in.)
(ft-k)
66.92
51.5
68.82
53.7
70.74
55.9
72.68
58.3
74.66
60.7
76.66
63.1
78.68
65.6
80.73
68.2
82.81
70.9
84.92
73.6
87.05
76.4
89.21
79.2
91.39
82.2
93.60
85.2
95.84
88.2
98.10
91.4
100.39
94.6
102.71
97.9
105.05
101.2
107.42
104.7
109.82
108.2
112.24
111.8
114.69
115.5
117.16
119.2
119.66
123.1
122.19
127.0
124.74
131.0
127.32
135.1
129.93
139.3
132.56
143.5
135.22
147.9
137.91
152.3
140.62
156.8
143.36
161.4
146.13
166.1
148.92
170.9
151.74
175.8
154.58
180.7
157.45
185.8
160.35
190.9
163.27
196.2
166.22
201.5
169.20
207.0
172.20
212.5
175.23
218.1
178.29
223.9
181.37
229.7
184.48
235.6
187.62
241.6
190.78
247.8
193.96
254.0
197.18
260.4
200.42
266.8
203.69
273.4
206.98
280.0
208.69
283.5
Dia.
(in.)
8.594
8.718
8.842
8.966
9.09
9.213
9.337
9.461
9.585
9.708
9.832
9.956
10.08
10.2
10.33
10.45
10.57
10.7
10.82
10.95
11.07
11.19
11.32
11.44
11.57
11.69
11.81
11.94
12.06
12.18
12.31
12.43
12.56
12.68
12.8
12.93
13.05
13.17
13.3
13.42
13.55
13.67
13.79
13.92
14.04
14.16
14.29
14.41
14.54
14.66
14.78
14.91
15.03
15.16
15.28
15.35
Class 1
Area
(sq. in.)
58.01
59.70
61.40
63.13
64.89
66.67
68.47
70.30
72.15
74.03
75.93
77.85
79.80
81.77
83.77
85.79
87.83
89.90
91.99
94.11
96.25
98.41
100.60
102.81
105.05
107.31
109.60
111.91
114.24
116.60
118.98
121.38
123.81
126.27
128.74
131.24
133.77
136.32
138.89
141.49
144.11
146.76
149.43
152.12
154.84
157.58
160.35
163.14
165.95
168.79
171.66
174.54
177.45
180.39
183.35
184.95
Moment
(ft-k)
41.5
43.4
45.2
47.2
49.2
51.2
53.3
55.4
57.6
59.9
62.2
64.6
67.0
69.5
72.1
74.7
77.4
80.2
83.0
85.8
88.8
91.8
94.9
98.0
101.2
104.5
107.9
111.3
114.8
118.4
122.0
125.7
129.5
133.4
137.4
141.4
145.5
149.7
153.9
158.3
162.7
167.2
171.8
176.4
181.2
186.0
190.9
195.9
201.0
206.2
211.5
216.8
222.3
227.8
233.4
236.5
Dist.
(ft.)
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
Dia.
(in.)
7.958
8.076
8.194
8.311
8.429
8.547
8.665
8.783
8.901
9.019
9.137
9.255
9.372
9.49
9.608
9.726
9.844
9.962
10.08
10.2
10.32
10.43
10.55
10.67
10.79
10.91
11.02
11.14
11.26
11.38
11.49
11.61
11.73
11.85
11.97
12.08
12.2
12.32
12.44
12.56
12.67
12.79
12.91
13.03
13.15
13.26
13.38
13.5
13.62
13.73
13.85
13.97
14.09
14.21
14.32
14.39
Class 2
Area
(sq. in.)
49.74
51.22
52.73
54.26
55.81
57.38
58.97
60.59
60.22
63.88
65.56
67.27
68.99
70.74
72.51
74.30
76.11
77.94
79.80
81.68
83.58
85.50
87.44
89.40
91.39
93.40
95.43
97.48
99.56
101.65
103.77
105.91
108.07
110.25
112.46
114.69
116.93
119.21
121.50
123.81
126.15
126.51
130.89
133.29
135.71
138.16
140.62
143.11
145.62
148.15
150.71
153.28
155.88
158.50
161.14
162.65
Moment
(ft-k)
33.0
34.5
36.0
37.6
39.2
40.9
42.6
44.3
46.2
48.0
49.9
51.9
53.9
55.9
58.1
60.2
62.4
64.7
67.0
69.4
71.8
74.3
76.9
79.5
82.2
84.9
87.7
90.5
93.4
96.4
99.4
102.5
105.6
108.9
112.1
115.5
118.9
122.4
125.9
129.5
133.2
137.0
140.8
144.7
148.7
152.7
156.8
161.0
165.2
169.6
174.0
178.5
183.0
187.6
192.4
195.1
Dia.
(in.)
7.32
7.43
7.55
7.66
7.77
7.88
7.99
8.11
8.22
8.33
8.44
8.55
8.67
8.78
8.89
9.00
9.11
9.23
9.34
9.45
9.56
9.67
9.79
9.90
10.01
10.12
10.23
10.35
10.46
10.57
10.68
10.79
10.91
11.02
11.13
11.24
11.35
11.47
11.58
11.69
11.80
11.91
12.03
12.14
12.25
12.36
12.47
12.59
12.70
12.81
12.92
13.03
13.15
13.26
13.37
13.44
Class 3
Area
(sq. in.)
42.10
43.39
44.71
46.05
47.41
48.78
50.18
51.60
53.03
54.49
55.96
57.46
58.97
60.51
62.06
63.63
65.23
66.84
68.47
70.12
71.80
73.49
75.20
76.93
78.68
80.45
82.24
84.05
85.88
87.73
89.60
91.49
93.40
95.33
97.28
99.24
101.23
103.24
105.27
107.31
109.38
111.46
113.57
115.70
117.84
120.01
122.19
124.39
126.62
128.86
131.12
133.41
135.71
138.03
140.37
141.78
Moment
(ft-k)
25.7
26.9
28.1
29.4
30.7
32.0
33.4
34.8
36.3
37.8
39.4
41.0
42.6
44.3
46.0
47.7
49.5
51.4
53.3
55.2
57.2
59.2
61.3
63.4
65.6
67.9
70.1
72.5
74.8
77.3
79.8
82.3
84.9
87.5
90.2
93.0
95.8
98.6
101.6
104.5
107.6
110.7
113.8
117.0
120.3
123.6
127.0
130.5
134.0
137.5
141.2
144.9
148.7
152.5
156.4
158.7
Dist.
(ft.)
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
Bulletin 1724E-200
Page F-7
DOUGLAS FIR AND SOUTHERN YELLOW PINE
Ultimate Bending Stress – 8000 psi
60 ft.
Dist.
(ft.)
56
57
58
59
60
Dia.
(in.)
16.37
16.43
16.5
16.57
16.63
60 ft.
Class H1
Area
Moment
(sq. in.)
(ft-k)
210.40
287.0
212.13
290.5
213.86
294.1
215.59
297.7
217.33
301.3
Dia.
(in.)
15.41
15.48
15.55
15.61
15.68
Class 1
Area
(sq. in.)
186.57
188.19
189.82
191.46
193.10
Moment
(ft-k)
239.6
242.8
245.9
249.1
252.3
Dist.
(ft.)
56
57
58
59
60
Dia.
(in.)
14.46
14.52
14.59
14.66
14.73
Class 2
Area
(sq. in.)
164.17
165.69
167.22
168.75
170.29
Moment
(ft-k)
197.8
200.5
203.3
206.1
209.0
Dia.
(in.)
13.50
13.57
13.64
13.70
13.77
Class 3
Area
(sq. in.)
143.20
144.62
146.05
147.48
148.92
Moment
(ft-k)
161.1
163.5
166.0
168.4
170.9
Dist.
(ft.)
56
57
58
59
60
Bulletin 1724E-200
Page F-8
DOUGLAS FIR AND SOUTHERN YELLOW PINE
Ultimate Bending Stress – 8000 psi
65 ft.
Dist.
(ft.)
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
Dia.
(in.)
9.23
9.36
9.48
9.61
9.74
9.86
9.99
10.12
10.25
10.37
10.50
10.63
10.75
10.88
11.01
11.13
11.26
11.39
11.51
11.64
11.77
11.89
12.02
12.15
12.27
12.40
12.53
12.65
12.78
12.91
13.03
13.16
13.29
13.41
13.54
13.67
13.80
13.92
14.05
14.18
14.30
14.43
14.56
14.68
14.81
14.94
15.06
15.19
15.32
15.44
15.57
15.70
15.82
15.95
16.08
16.20
65 ft.
Class H1
Area
Moment
(sq. in.)
(ft-k)
66.9
51.5
68.8
53.6
70.7
55.8
72.6
58.1
74.5
60.4
76.4
62.8
78.4
65.3
80.4
67.8
82.4
70.4
84.5
73.0
86.6
75.7
88.7
78.5
90.8
81.4
93.0
84.3
95.1
87.3
97.3
90.3
99.6
93.4
101.8
96.6
104.1
99.9
106.4
103.2
108.7
106.6
111.1
110.1
113.5
113.7
115.9
117.3
118.3
121.0
120.8
124.8
123.3
128.7
125.8
132.6
128.3
136.6
130.9
140.8
133.4
144.9
136.0
149.2
138.7
153.6
141.3
158.0
144.0
162.5
146.7
167.1
149.5
171.8
152.2
176.6
155.0
181.5
157.8
186.4
160.7
191.5
163.5
196.6
166.4
201.9
169.3
207.2
172.3
212.6
175.2
218.1
178.2
223.7
181.2
229.4
184.3
235.2
187.3
241.1
190.4
247.1
193.5
253.1
196.7
259.3
199.8
265.6
203.0
272.0
206.2
278.5
Dia.
(in.)
8.59
8.72
8.84
8.96
9.08
9.20
9.32
9.44
9.57
9.69
9.81
9.93
10.05
10.17
10.29
10.42
10.54
10.66
10.78
10.90
11.02
11.14
11.26
11.39
11.51
11.63
11.75
11.87
11.99
12.11
12.24
12.36
12.48
12.60
12.72
12.84
12.96
13.09
13.21
13.33
13.45
13.57
13.69
13.81
13.94
14.06
14.18
14.30
14.42
14.54
14.66
14.79
14.91
15.03
15.15
15.27
Class 1
Area
(sq. in.)
58.0
59.7
61.3
63.0
64.8
66.5
68.3
70.1
71.9
73.7
75.6
77.4
79.3
81.3
83.2
85.2
87.2
89.2
91.3
93.3
95.4
97.5
99.7
101.8
104.0
106.2
108.4
110.7
113.0
115.3
117.6
119.9
122.3
124.7
127.1
129.5
132.0
134.5
137.0
139.5
142.1
144.7
147.3
149.9
152.5
155.2
157.9
160.6
163.3
166.1
168.9
171.7
174.5
177.4
180.3
183.2
Moment
(ft-k)
41.5
43.3
45.2
47.1
49.0
51.0
53.0
55.1
57.3
59.5
61.8
64.1
66.5
68.9
71.4
73.9
76.6
79.2
82.0
84.8
87.6
90.6
93.6
96.6
99.7
102.9
106.2
109.5
112.9
116.4
119.9
123.5
127.2
130.9
134.8
138.6
142.6
146.7
150.8
155.0
159.2
163.6
168.0
172.5
177.1
181.8
186.5
191.4
196.3
201.3
206.4
211.5
216.8
222.1
227.6
233.1
Dist.
(ft.)
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
Dia.
(in.)
7.96
8.07
8.19
8.31
8.42
8.54
8.65
8.77
8.89
9.00
9.12
9.23
9.35
9.47
9.58
9.70
9.81
9.93
10.05
10.16
10.28
10.39
10.51
10.63
10.74
10.86
10.97
11.09
11.21
11.32
11.44
11.55
11.67
11.79
11.90
12.02
12.13
12.25
12.37
12.48
12.60
12.71
12.83
12.95
13.06
13.18
13.29
13.41
13.53
13.64
13.76
13.87
13.99
14.11
14.22
14.34
Class 2
Area
(sq. in.)
49.7
51.2
52.7
54.2
55.7
57.2
58.8
60.4
62.0
63.6
65.3
67.0
68.7
70.4
72.1
73.9
75.6
77.4
79.3
81.1
83.0
84.8
86.7
88.7
90.6
92.6
94.6
96.6
98.6
100.7
102.7
104.8
107.0
109.1
111.2
113.4
115.6
117.8
120.1
122.4
124.6
126.9
129.3
131.6
134.0
136.4
138.8
141.2
143.7
146.2
148.7
151.2
153.7
156.3
158.8
161.4
Moment
(ft-k)
33.0
34.4
36.0
37.5
39.1
40.7
42.4
44.1
45.9
47.7
49.6
51.5
53.5
55.5
57.6
59.7
61.9
64.1
66.4
68.7
71.1
73.5
76.0
78.5
81.1
83.5
86.5
89.3
92.1
95.0
97.9
100.9
104.0
107.1
110.3
113.6
116.9
120.3
123.8
127.3
130.8
134.5
138.2
142.0
145.8
149.8
153.8
157.8
161.9
166.1
170.4
174.8
179.2
183.7
188.3
192.9
Dia.
(in.)
7.32
7.43
7.54
7.65
7.76
7.87
7.98
8.10
8.21
8.32
8.43
8.54
8.65
8.76
8.87
8.98
9.09
9.20
9.31
9.42
9.53
9.64
9.75
9.86
9.98
10.09
10.20
10.31
10.42
10.53
10.64
10.75
10.86
10.97
11.08
11.19
11.30
11.41
11.52
11.63
11.75
11.86
11.97
12.08
12.19
12.30
12.41
12.52
12.63
12.74
12.85
12.96
13.07
13.18
13.29
13.40
Class 3
Area
(sq. in.)
42.1
43.4
44.7
46.0
47.3
48.7
50.1
51.5
52.9
54.3
55.8
57.2
58.7
60.3
61.8
63.3
64.9
66.5
68.1
69.7
71.4
73.0
74.7
76.4
78.2
79.9
81.7
83.4
85.2
87.1
88.9
90.8
92.6
94.5
96.4
98.4
100.3
102.3
104.3
106.3
108.3
110.4
112.5
114.6
116.7
118.8
120.9
123.1
125.3
127.5
129.7
132.0
134.2
136.5
138.8
141.1
Moment
(ft-k)
25.7
26.9
28.1
29.3
30.6
32.0
33.3
34.7
36.2
37.6
39.2
40.7
42.3
44.0
45.7
47.4
49.2
51.0
52.8
54.8
56.7
58.7
60.7
62.8
65.0
67.2
69.4
71.7
74.0
76.4
78.8
81.3
83.8
86.4
89.1
91.8
94.5
97.3
100.2
103.1
106.0
109.1
112.1
115.3
118.5
121.7
125.1
128.4
131.9
135.4
138.9
142.5
146.2
149.9
153.8
157.6
Dist.
(ft.)
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
Bulletin 1724E-200
Page F-9
DOUGLAS FIR AND SOUTHERN YELLOW PINE
Ultimate Bending Stress – 8000 psi
65 ft.
Dist.
(ft.)
56
57
58
59
60
61
62
63
64
65
Dia.
(in.)
16.33
16.46
16.58
16.71
16.78
16.84
16.91
16.98
17.05
17.11
65 ft.
Class H1
Area
Moment
(sq. in.)
(ft-k)
209.5
285.1
212.7
291.8
216.0
298.5
219.3
305.4
221.1
309.1
222.9
312.8
224.6
316.6
226.4
320.3
228.2
324.1
230.0
328.0
Dia.
(in.)
15.39
15.51
15.63
15.76
15.82
15.89
15.96
16.02
16.09
16.16
Class 1
Area
(sq. in.)
186.1
189.0
192.0
195.0
196.6
198.3
200.0
201.7
203.3
205.0
Moment
(ft-k)
238.7
244.4
250.1
256.0
259.3
262.6
265.9
269.3
272.7
276.1
Dist.
(ft.)
56
57
58
59
60
61
62
63
64
65
Dia.
(in.)
14.45
14.57
14.69
14.80
14.87
14.94
15.00
15.07
15.14
15.20
Class 2
Area
(sq. in.)
164.1
166.7
169.4
172.1
173.6
175.2
176.8
178.3
179.9
181.5
Moment
(ft-k)
197.6
202.4
207.3
212.2
215.1
218.0
221.0
223.9
226.9
230.0
Dia.
(in.)
13.51
13.63
13.74
13.85
13.91
13.98
14.05
14.11
14.18
14.25
Class 3
Area
(sq. in.)
143.5
145.8
148.2
150.6
152.0
153.5
155.0
156.5
157.9
159.4
Moment
(ft-k)
161.6
165.6
169.6
173.8
176.3
178.8
181.4
184.0
186.6
189.3
Dist.
(ft.)
56
57
58
59
60
61
62
63
64
65
Bulletin 1724E-200
Page F-10
DOUGLAS FIR AND SOUTHERN YELLOW PINE
Ultimate Bending Stress – 8000 psi
70 ft.
Dist.
(ft.)
Dia.
(in.)
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
9.23
9.36
9.48
9.60
9.73
9.85
9.98
10.10
10.23
10.35
10.47
10.60
10.72
10.85
10.97
11.10
11.22
11.34
11.47
11.59
11.72
11.84
11.97
12.09
12.22
12.34
12.46
12.59
12.71
12.84
12.96
13.09
13.21
13.33
13.46
13.58
13.71
13.83
13.96
14.08
14.20
14.33
14.45
14.58
14.70
14.83
14.95
15.07
15.20
15.32
15.45
15.57
15.70
15.82
15.95
16.07
70 ft.
Class H1
Area
Moment
(sq.
(ft-k)
in.)
66.9
51.5
68.7
53.6
70.6
55.8
72.4
58.0
74.3
60.3
76.2
62.6
78.2
65.0
80.1
67.5
82.1
70.0
84.1
72.6
86.2
75.2
88.2
77.9
90.3
80.7
92.4
83.5
94.5
86.4
96.7
89.4
98.9
92.5
101.1
95.6
103.3
98.7
105.6
102.0
107.8
105.3
110.1
108.7
112.5
112.2
114.8
115.7
117.2
119.3
119.6
123.0
122.0
126.7
124.5
130.6
126.9
134.5
129.4
138.4
131.9
142.5
134.5
146.6
137.1
150.9
139.6
155.2
142.3
159.6
144.9
164.0
147.6
168.6
150.3
173.2
153.0
177.9
155.7
182.7
158.5
187.6
161.3
192.6
164.1
197.6
166.9
202.8
169.8
208.0
172.6
213.3
175.6
218.7
178.5
224.2
181.4
229.8
184.4
235.5
187.4
241.3
190.5
247.2
193.5
253.1
196.6
259.2
199.7
265.3
202.8
271.6
Dia.
(in.)
8.59
8.71
8.83
8.95
9.07
9.19
9.31
9.43
9.55
9.67
9.79
9.91
10.03
10.15
10.27
10.38
10.50
10.62
10.74
10.86
10.98
11.10
11.22
11.34
11.46
11.58
11.70
11.82
11.94
12.06
12.18
12.29
12.41
12.53
12.65
12.77
12.89
13.01
13.13
13.25
13.37
13.49
13.61
13.73
13.85
13.97
14.09
14.20
14.32
14.44
14.56
14.68
14.80
14.92
15.04
15.16
Class 1
Area
(sq.
in.)
58.0
59.6
61.3
62.8
64.6
66.3
68.1
69.8
71.6
73.4
75.2
77.1
79.0
80.9
82.8
84.7
86.7
88.6
90.6
92.7
94.7
96.8
98.9
101.0
103.1
105.3
107.5
109.7
111.9
114.2
116.4
118.7
121.0
123.4
125.7
128.1
130.5
133.0
135.4
137.9
140.4
142.9
145.4
148.0
150.6
153.2
155.8
158.5
161.1
163.5
166.6
169.3
172.1
174.9
177.7
180.5
Moment
(ft-k)
41.5
43.3
45.1
47.0
48.9
50.8
52.8
54.9
57.0
59.2
61.4
63.6
66.0
68.4
70.8
73.3
75.9
78.5
81.1
83.9
86.7
89.5
92.5
94.5
98.5
101.6
104.8
108.8
111.3
114.7
118.1
121.6
125.2
128.9
132.6
136.4
140.2
144.2
148.2
152.2
156.4
160.6
164.9
169.3
173.8
178.3
182.9
187.6
192.4
197.2
202.1
207.1
212.2
217.4
222.7
228.0
Dist.
(ft.)
Dia.
(in.)
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
7.96
8.07
8.19
8.30
8.42
8.53
8.64
8.76
8.87
8.99
9.10
9.22
9.33
9.44
9.56
9.67
9.79
9.90
10.02
10.13
10.25
10.36
10.47
10.59
10.70
10.82
10.93
11.05
11.16
11.28
11.39
11.50
11.62
11.73
11.85
11.96
12.08
12.19
12.30
12.42
12.53
12.65
12.76
12.88
12.99
13.11
13.22
13.33
13.45
13.56
13.68
13.79
13.91
14.02
14.13
14.25
Class 2
Area
(sq.
in.)
49.7
51.2
52.6
54.1
55.6
57.1
58.7
60.2
61.8
63.4
65.1
66.7
68.4
70.1
71.8
73.5
75.2
77.0
78.8
80.6
82.4
84.3
86.2
88.1
90.0
91.9
93.9
95.8
97.8
99.8
101.9
103.9
106.9
108.1
110.2
112.4
114.5
116.7
118.9
121.1
123.4
125.6
127.9
130.2
132.5
134.9
137.3
139.6
142.1
144.5
146.9
149.4
151.9
154.4
156.9
159.5
Moment
(ft-k)
Dia.
(in.)
33.0
34.4
35.9
37.4
39.0
40.6
42.3
44.0
45.7
47.5
49.3
51.2
53.2
55.1
57.2
59.2
61.4
63.6
65.8
68.1
70.4
72.8
75.2
77.7
80.3
82.9
85.5
88.2
91.0
93.8
96.7
99.6
102.6
105.7
108.8
112.0
115.3
118.6
121.9
125.4
128.9
132.4
126.0
139.7
143.5
147.3
151.2
155.2
159.2
163.3
167.5
171.7
176.0
180.4
184.8
189.4
7.32
7.43
7.54
7.65
7.76
7.87
7.98
8.09
8.20
8.31
8.42
8.52
8.63
8.74
8.85
8.96
9.07
9.18
9.29
9.40
9.51
9.62
9.73
9.84
9.95
10.06
10.17
10.28
10.38
10.49
10.60
10.71
10.82
10.93
11.04
11.15
11.26
11.37
11.48
11.59
11.70
11.81
11.92
12.03
12.14
12.24
12.35
12.46
12.57
12.68
12.79
12.90
13.01
13.12
13.23
13.34
Class 3
Area
(sq.
in.)
42.1
43.4
44.7
46.0
47.3
48.6
50.0
51.4
52.8
54.2
55.6
57.1
58.6
60.0
61.6
63.1
64.2
66.2
67.8
69.4
71.0
72.7
74.3
76.0
77.7
79.4
81.2
82.9
84.7
86.5
88.3
90.1
92.0
93.9
95.7
97.7
99.6
101.5
103.5
105.5
107.5
109.5
111.5
113.6
115.7
117.8
119.9
122.0
124.2
126.3
128.5
130.7
133.0
135.2
137.5
139.7
Moment
(ft-k)
25.7
26.9
28.1
29.3
30.6
31.9
33.2
34.6
36.0
37.2
39.0
40.5
42.1
43.7
45.4
47.1
48.9
50.7
52.5
54.4
56.3
58.2
60.3
62.3
64.4
66.6
68.8
71.0
73.3
75.6
78.0
80.5
83.0
85.5
88.1
90.7
93.4
96.2
99.0
101.9
104.8
107.7
110.8
113.8
117.0
120.2
123.4
126.7
130.1
133.5
137.0
140.5
144.2
147.8
151.6
155.3
Dist.
(ft.)
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
Bulletin 1724E-200
Page F-11
DOUGLAS FIR AND SOUTHERN YELLOW PINE
Ultimate Bending Stress – 8000 psi
70 ft.
Dist.
(ft.)
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
Dia.
(in.)
16.19
16.32
16.44
16.57
16.69
16.82
16.94
17.06
17.19
17.26
17.32
17.39
17.46
17.52
17.59
70 ft.
Class H1
Area
Moment
(sq. in.)
(ft-k)
206.0
278.0
209.1
284.4
212.3
291.0
215.6
297.6
218.8
304.4
222.1
311.2
225.4
318.2
228.7
325.2
232.0
332.4
233.9
336.3
235.7
340.2
237.5
344.2
239.3
348.1
241.2
352.2
243.0
356.2
Dia.
(in.)
15.28
15.40
15.52
15.64
15.76
15.88
16.00
16.11
16.23
16.30
16.37
16.43
16.50
16.57
16.63
Class 1
Area
(sq. in.)
183.3
186.2
189.1
192.0
195.0
198.0
200.9
203.9
207.9
208.9
210.4
212.1
213.9
215.6
217.3
Moment
(ft-k)
233.4
239.0
244.6
250.2
256.0
261.9
267.8
273.9
280.0
283.5
287.0
290.5
294.1
297.7
301.3
Dist.
(ft.)
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
Dia.
(in.)
14.36
14.48
14.59
14.71
14.82
14.94
15.05
15.16
15.28
15.35
15.41
15.48
15.55
15.61
15.68
Class 2
Area
(sq. in.)
162.0
164.6
167.2
169.9
172.5
175.2
177.9
180.6
183.3
185.0
186.6
188.2
189.8
191.5
193.1
Moment
(ft-k)
194.0
198.6
203.4
208.2
213.1
218.1
223.1
228.2
233.4
236.5
239.6
242.8
245.9
249.1
252.3
Dia.
(in.)
13.45
13.56
13.67
13.78
13.89
14.00
14.11
14.21
14.32
14.39
14.46
14.52
14.59
14.66
14.73
Class 3
Area
(sq. in.)
142.1
144.4
146.7
149.1
151.4
153.8
156.3
158.7
161.1
162.7
164.2
165.7
167.2
168.8
170.3
Moment
(ft-k)
159.2
163.1
167.1
171.1
175.3
179.4
183.7
188.0
192.4
195.1
197.8
200.5
203.3
206.1
209.0
Dist.
(ft.)
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
Bulletin 1724E-200
Page F-12
DOUGLAS FIR AND SOUTHERN YELLOW PINE
Ultimate Bending Stress – 8000 psi
75 ft.
Dist.
(ft.)
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
Dia.
(in.)
9.23
9.35
9.48
9.60
9.72
9.84
9.96
10.09
10.21
10.33
10.45
10.58
10.70
10.82
10.94
11.06
11.19
11.31
11.43
11.55
11.68
11.80
11.92
12.04
12.16
12.29
12.41
12.53
12.65
12.78
12.90
13.02
13.14
13.27
13.39
13.51
13.63
13.75
13.88
14.00
14.12
14.24
14.37
14.49
14.61
14.73
14.85
14.98
15.10
15.22
15.34
15.47
15.59
15.71
15.83
15.95
75 ft.
Class H1
Area
Moment
(sq. in.)
(ft-k)
66.9
51.3
68.7
53.6
70.5
55.7
72.3
57.9
74.2
60.1
76.1
62.4
78.0
64.8
79.9
67.2
81.9
69.6
83.8
72.2
85.8
74.8
87.8
77.4
89.9
80.1
92.0
82.9
94.0
85.8
96.2
88.7
98.3
91.6
100.5
94.7
102.6
97.8
104.8
100.9
107.1
104.2
109.3
107.5
111.6
110.9
113.9
114.3
116.2
117.8
118.6
121.4
120.9
125.1
123.3
128.8
125.8
132.6
128.2
136.5
130.7
140.5
133.2
144.5
135.7
148.6
138.2
152.8
140.8
157.0
143.3
161.4
146.0
165.8
148.6
170.3
151.2
174.9
153.9
179.5
156.6
184.3
159.3
189.1
162.1
194.0
164.9
199.0
167.6
204.1
170.5
209.3
173.3
214.5
176.2
219.9
179.1
225.3
182.0
230.8
184.9
236.4
187.9
242.1
190.8
247.9
193.8
253.8
196.9
259.7
199.9
265.8
Dia.
(in.)
8.59
8.71
8.83
8.95
9.06
9.18
9.30
9.42
9.54
9.65
9.77
9.89
10.01
10.12
10.24
10.36
10.48
10.59
10.71
10.83
10.95
11.06
11.18
11.30
11.42
11.54
11.65
11.77
11.89
12.01
12.12
12.24
12.36
12.48
12.59
12.71
12.83
12.95
13.06
13.18
13.30
13.42
13.54
13.65
13.77
13.89
14.01
14.12
14.24
14.36
14.48
14.59
14.71
14.83
14.95
15.06
Class 1
Area
(sq. in.)
58.0
59.6
61.2
62.9
64.5
66.2
67.9
69.7
71.4
73.2
75.0
76.8
78.6
80.5
82.4
84.3
86.2
88.2
90.1
92.1
94.1
96.2
98.2
100.3
102.4
104.5
106.6
108.8
111.0
113.2
115.4
117.7
120.0
122.3
124.6
126.9
129.3
131.7
134.1
136.5
138.9
141.4
143.9
146.4
148.9
151.5
154.1
156.7
159.3
161.9
164.6
167.3
170.0
172.7
175.5
178.2
Moment
(ft-k)
41.5
43.3
45.1
46.9
48.8
50.7
52.6
54.7
56.7
58.9
61.1
63.3
65.6
67.9
70.3
72.8
73.5
77.8
80.4
83.1
85.9
88.7
91.5
94.4
97.4
100.5
103.6
106.7
110.0
113.3
116.6
120.1
123.5
127.1
130.7
134.4
138.2
142.0
145.9
149.9
154.0
158.1
162.3
166.6
170.9
175.3
179.8
184.4
189.0
193.7
198.6
203.4
208.4
213.4
218.5
223.7
Dist.
(ft.)
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
Dia.
(in.)
7.96
8.07
8.18
8.29
8.40
8.51
8.62
8.73
8.84
8.95
9.06
9.18
9.29
9.40
9.51
9.62
9.73
9.84
9.95
10.06
10.17
10.28
10.39
10.50
10.61
10.73
10.84
10.95
11.06
11.17
11.28
11.39
11.50
11.61
11.72
11.83
11.94
12.05
12.16
12.28
12.39
12.50
12.61
12.72
12.83
12.94
13.05
13.16
13.27
13.38
13.49
13.60
13.72
13.83
13.94
14.05
Class 2
Area
(sq. in.)
49.7
51.1
52.5
54.0
55.4
56.9
58.4
59.9
61.4
63.0
64.5
66.1
67.7
69.4
71.0
72.7
74.3
76.0
77.8
79.5
81.3
83.0
84.8
86.7
88.5
90.4
92.2
94.1
96.0
98.0
99.9
101.9
103.9
105.9
107.9
110.0
112.0
114.1
116.2
118.4
120.5
122.7
124.8
127.0
129.3
131.5
133.8
136.0
138.3
140.7
143.0
145.4
147.7
150.1
152.5
155.0
Moment
(ft-k)
33.0
34.4
35.8
37.3
38.8
40.4
42.0
43.6
45.3
47.0
48.8
50.6
52.4
54.3
56.3
58.2
60.3
62.4
64.5
66.7
68.9
71.2
73.8
75.9
78.3
80.8
83.3
85.9
88.5
91.2
93.9
96.7
99.6
102.5
105.4
108.4
111.5
114.6
117.8
121.1
124.4
127.7
131.2
134.7
138.2
141.8
145.5
149.2
153.0
156.9
160.8
164.8
168.8
173.0
177.2
181.4
Dia.
(in.)
7.32
7.43
7.53
7.64
7.75
7.85
7.96
8.06
8.17
8.28
8.38
8.49
8.59
8.70
8.81
8.91
9.02
9.12
9.23
9.34
9.44
9.55
9.66
9.76
9.87
9.97
10.08
10.19
10.29
10.40
10.50
10.61
10.72
10.82
10.93
11.03
11.14
11.25
11.35
11.46
11.57
11.67
11.78
11.88
11.99
12.10
12.20
12.31
12.41
12.52
12.62
12.73
12.84
12.94
13.05
13.16
Class 3
Area
(sq. in.)
42.1
43.3
44.6
45.8
47.1
48.4
49.7
51.1
52.4
53.8
55.2
56.6
58.0
59.5
60.9
62.4
63.9
65.4
66.9
68.5
70.0
71.6
73.2
74.8
76.5
78.1
79.8
81.5
83.2
84.9
86.7
88.4
90.2
92.0
93.8
95.6
97.5
99.3
101.2
103.1
105.1
107.0
108.9
110.9
112.9
114.9
116.9
119.0
121.0
123.1
125.2
127.3
129.5
131.6
133.8
136.0
Moment
(ft-k)
25.7
26.8
28.0
29.2
30.4
31.7
33.0
34.3
35.7
37.1
38.5
40.0
41.5
43.1
44.7
46.3
48.0
49.7
51.5
53.3
55.1
57.0
58.9
60.9
62.9
64.9
67.0
69.2
71.4
73.6
75.9
78.2
80.5
83.0
85.4
87.9
90.5
93.1
95.8
98.5
101.2
104.1
106.9
109.8
112.8
115.8
118.9
122.0
125.2
128.5
131.7
135.1
138.5
142.0
145.5
149.1
Dist.
(ft.)
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
Bulletin 1724E-200
Page F-13
DOUGLAS FIR AND SOUTHERN YELLOW PINE
Ultimate Bending Stress – 8000 psi
75 ft.
Dist.
(ft.)
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
Dia.
(in.)
16.08
16.20
16.32
16.44
16.57
16.69
16.81
16.93
17.05
17.18
17.30
17.42
17.54
17.67
17.73
17.80
17.87
17.93
18.00
18.07
75ft.
Class H1
Area
Moment
(sq. in.)
(ft-k)
203.0
272.0
206.1
278.2
209.2
284.6
212.4
291.0
215.5
297.5
218.7
304.2
221.9
310.9
225.2
317.8
228.4
324.7
231.7
331.17
235.0
338.8
238.4
346.1
241.7
353.4
245.1
360.9
247.0
365.0
248.8
369.1
250.7
373.3
252.6
377.5
254.5
381.7
256.4
386.0
Dia.
(in.)
15.18
15.30
15.42
15.53
15.65
15.77
15.89
16.01
16.12
16.24
16.36
16.48
16.59
16.71
16.78
16.84
16.91
16.98
17.05
17.11
Class 1
Area
(sq. in.)
181.0
183.8
186.7
189.5
192.4
195.3
198.3
201.2
204.2
207.2
210.2
213.2
216.3
219.3
221.1
222.9
224.6
226.4
228.2
230.0
Moment
(ft-k)
229.0
234.4
239.8
245.4
251.0
256.7
262.5
268.4
274.3
280.4
286.5
292.7
299.0
305.4
309.1
312.8
316.6
320.3
324.1
328.0
Dist.
(ft.)
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
Dia.
(in.)
14.16
14.27
14.38
14.49
14.60
14.71
14.82
14.93
15.04
15.15
15.27
15.38
15.49
15.60
15.66
15.73
15.80
15.86
15.93
16.00
Class 2
Area
(sq. in.)
157.4
159.9
162.4
164.9
167.4
170.0
172.5
175.1
177.7
180.4
183.0
185.7
188.4
191.1
192.7
194.4
196.0
197.7
199.3
201.0
Moment
(ft-k)
185.7
190.1
194.6
199.1
203.7
208.4
213.1
217.9
222.8
227.8
232.8
237.9
243.1
248.3
251.5
254.8
258.0
261.3
264.6
268.0
Dia.
(in.)
13.26
13.37
13.48
13.58
13.69
13.79
13.90
14.01
14.11
14.22
14.32
14.43
14.54
14.64
14.71
14.78
14.84
14.91
14.98
15.04
Class 3
Area
(sq. in.)
138.2
140.4
142.6
144.9
147.1
149.4
151.7
154.1
156.4
158.8
161.1
163.5
166.0
168.4
169.9
171.5
173.0
174.6
176.2
177.7
Moment
(ft-k)
152.7
156.4
160.1
164.0
167.8
171.8
175.8
179.8
183.9
188.1
192.4
196.7
201.0
205.5
208.3
211.1
214.0
216.9
219.9
222.8
Dist.
(ft.)
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
Bulletin 1724E-200
Page F-14
DOUGLAS FIR AND SOUTHERN YELLOW PINE
Ultimate Bending Stress – 8000 psi
80 ft.
Dist.
(ft.)
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
Dia.
(in.)
9.231
9.351
9.472
9.592
9.713
9.833
9.954
10.07
10.19
10.31
10.44
10.56
10.68
10.8
10.92
11.04
11.16
11.28
11.4
11.52
11.64
11.76
11.88
12
12.12
12.24
12.36
12.48
12.6
12.72
12.84
12.96
13.09
13.21
13.33
13.45
13.57
13.69
13.81
13.93
14.05
14.17
14.29
14.41
14.53
14.65
14.77
14.89
15.01
15.13
15.25
15.37
15.49
15.61
15.73
15.86
80 ft.
Class H1
Area
Moment
(sq. in.)
(ft-k)
66.92
51.5
66.68
53.5
70.46
55.6
72.27
57.8
74.09
60.0
75.94
62.2
77.81
64.5
79.71
66.9
81.63
69.3
83.57
71.8
85.53
74.4
87.51
77.0
89.52
79.6
91.55
82.4
93.61
85.2
95.68
88.0
97.78
90.9
99.91
93.9
102.05
96.9
104.22
100.0
106.41
103.2
108.62
106.5
110.86
109.8
113.12
113.1
115.40
116.6
117.71
120.1
120.03
123.7
122.38
127.3
124.76
131.0
127.15
134.8
129.57
138.7
132.01
142.6
134.48
146.6
136.96
150.7
139.47
154.9
142.01
159.1
144.56
163.4
147.14
167.8
149.74
172.3
152.36
176.8
155.01
181.5
157.68
186.2
160.37
191.0
163.09
195.8
165.82
200.8
168.58
205.8
171.37
210.9
174.17
216.1
177.00
221.4
179.85
226.8
182.73
232.3
185.62
237.8
188.54
243.4
191.49
249.2
194.45
255.0
197.44
260.9
Dia.
(in.)
8.594
8.711
8.827
8.943
9.059
9.175
9.291
9.407
9.523
9.64
9.756
9.872
9.988
10.1
10.22
10.34
10.45
10.57
10.68
10.8
10.92
11.03
11.15
11.27
11.38
11.5
11.61
11.73
11.85
11.96
12.08
12.19
12.31
12.43
12.54
12.66
12.78
12.89
13.01
13.12
13.24
13.36
13.47
13.59
13.7
13.82
13.94
14.05
14.17
14.29
14.4
14.52
14.63
14.75
14.87
14.98
Class 1
Area
(sq. in.)
58.01
59.59
61.19
62.81
64.45
66.12
67.80
69.51
71.23
72.98
74.75
76.54
78.35
80.18
82.04
83.91
85.81
87.73
89.67
91.63
93.61
95.61
97.63
99.68
101.74
103.83
105.94
108.07
110.22
112.39
114.58
116.80
119.03
121.29
123.57
125.87
128.19
130.53
132.89
135.27
137.68
140.10
142.55
145.02
147.51
150.02
152.55
155.10
157.68
160.27
162.89
165.53
168.19
170.87
173.57
176.29
Moment
(ft-k)
41.5
43.3
45.0
46.8
48.7
50.6
52.5
54.5
56.5
58.6
60.8
63.0
65.2
67.5
69.9
72.3
74.7
77.3
79.8
82.5
85.2
87.9
90.7
93.6
96.5
99.5
102.5
105.6
108.8
112.0
115.3
118.7
122.1
125.6
129.2
132.8
136.5
140.2
144.0
147.9
151.9
155.9
160.0
164.2
168.5
172.8
177.2
181.6
186.2
190.8
195.5
200.3
205.1
210.0
215.0
220.1
Dist.
(ft.)
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
Dia.
(in.)
7.958
8.067
8.177
8.287
8.396
8.506
8.616
8.726
8.835
8.945
9.055
9.164
9.274
9.384
9.493
9.603
9.713
9.822
9.932
10.04
10.15
10.26
10.37
10.48
10.59
10.7
10.81
Class 2
Area
(sq. in.)
49.74
51.12
52.52
53.93
55.37
56.83
58.30
59.80
61.31
62.84
64.39
65.96
67.55
69.16
70.78
72.43
74.09
75.78
77.48
79.20
80.94
82.70
84.47
86.27
88.09
89.92
91.77
93.64
95.54
97.44
99.37
101.32
103.29
105.27
107.28
109.30
111.34
113.40
115.48
117.58
119.70
121.84
123.99
126.17
128.36
130.57
132.80
135.05
137.32
139.61
141.91
144.24
146.58
148.95
151.33
153.73
Moment
(ft-k)
33.0
34.4
35.8
37.2
38.7
40.3
41.9
43.5
45.1
46.8
48.6
50.46
52.2
54.1
56.0
58.0
60.0
62.0
64.1
66.3
68.5
70.7
73.0
75.3
77.7
80.2
82.7
85.2
87.8
90.5
93.1
95.9
98.7
101.6
104.5
107.4
110.5
113.6
116.7
119.9
123.1
126.5
129.8
133.3
136.7
140.3
143.9
147.6
151.3
155.1
159.0
162.9
166.9
170.9
175.0
179.2
Dia.
(in.)
7.321
7.424
7.528
7.631
7.734
7.837
7.941
8.044
8.147
8.25
8.353
8.457
8.56
8.663
8.766
8.87
8.973
9.076
9.179
9.283
9.386
9.489
9.592
9.696
9.799
9.902
10.01
10.11
10.21
10.31
10.42
10.52
10.62
10.73
10.83
10.93
11.04
11.14
11.24
11.35
11.45
11.55
11.66
11.76
11.86
11.97
12.07
12.17
12.28
12.38
12.48
12.59
12.69
12.79
12.9
13
Class 3
Area
(sq. in.)
42.10
43.29
44.50
45.73
46.98
48.24
49.52
50.82
52.13
53.46
54.81
56.17
57.55
58.94
60.36
61.79
63.23
64.70
66.18
67.68
69.19
70.72
72.27
73.83
75.41
77.01
78.62
80.25
81.90
83.57
85.25
86.94
88.66
90.39
92.14
93.90
95.68
97.48
99.30
101.13
102.98
104.84
106.72
108.62
110.54
112.47
114.42
116.39
118.37
120.37
122.38
124.42
126.47
128.53
130.61
132.71
Moment
(ft-k)
25.7
26.8
27.9
29.1
30.3
31.5
32.8
34.1
35.4
36.8
38.2
39.6
41.1
42.6
44.1
45.7
47.3
48.9
50.6
52.4
54.1
55.9
57.8
59.7
61.6
63.5
65.6
67.6
69.7
71.8
74.0
76.2
78.5
80.8
83.2
85.6
88.0
90.5
93.0
95.6
98.3
100.9
103.7
106.5
109.3
112.2
115.1
118.1
121.1
124.2
127.3
130.5
133.7
137.0
140.4
143.8
Dist.
(ft.)
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
Bulletin 1724E-200
Page F-15
DOUGLAS FIR AND SOUTHERN YELLOW PINE
Ultimate Bending Stress – 8000 psi
80 ft.
Dist.
(ft.)
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
Dia.
(in.)
15.98
16.1
16.22
16.34
16.46
16.58
16.7
16.82
16.94
17.06
17.18
17.3
17.42
17.54
17.66
17.78
17.9
18.02
18.14
18.21
18.28
18.34
18.41
18.48
18.54
80 ft.
Class H1
Area
Moment
(sq. in.)
(ft-k)
200.45
266.9
203.49
272.9
206.54
279.1
209.62
285.4
212.72
291.7
215.85
298.2
219.00
304.7
222.17
311.4
225.36
318.1
228.58
325.0
231.82
331.9
235.08
338.9
238.36
346.0
241.67
353.3
245.00
360.6
248.35
368.0
251.73
375.6
255.13
383.2
258.55
390.9
260.46
395.3
262.37
399.6
264.29
404.0
266.22
408.5
268.16
412.9
270.10
417.4
Dia.
(in.)
15.1
15.21
15.33
15.45
15.56
15.68
15.8
15.91
16.03
16.14
16.26
16.38
16.49
16.61
16.72
16.84
16.96
17.07
17.19
17.26
17.32
17.39
17.46
17.52
17.59
Class 1
Area
(sq. in.)
179.04
181.80
184.59
187.39
190.22
193.07
195.94
198.84
201.75
204.68
207.64
201.62
213.61
216.63
219.67
222.74
225.82
228.92
232.05
233.86
235.67
237.49
239.32
241.16
243.00
Moment
(ft-k)
225.3
230.5
235.8
241.2
246.7
252.3
257.9
263.6
269.5
275.4
281.3
287.4
293.6
299.8
306.2
312.6
319.1
325.7
332.4
336.3
340.2
344.2
348.1
352.2
356.2
Dist.
(ft.)
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
Dia.
(in.)
14.1
14.21
14.32
14.43
14.54
14.65
14.76
14.87
14.98
15.09
15.2
15.31
15.42
15.53
15.64
15.75
15.86
15.96
16.07
16.14
16.21
16.28
16.34
16.41
16.48
Class 2
Area
(sq. in.)
156.15
158.59
161.05
163.52
166.02
168.53
171.07
173.62
176.19
178.78
181.39
184.02
186.66
189.33
192.02
194.72
197.44
200.18
202.94
204.63
206.33
208.04
209.75
211.47
213.20
Moment
(ft-k)
183.5
187.8
192.2
196.6
201.1
205.7
210.4
215.1
219.9
224.8
229.7
234.7
239.8
245.0
250.2
255.5
260.9
266.3
271.9
275.3
278.7
282.2
285.6
289.2
292.7
Dia.
(in.)
13.1
13.21
13.31
13.41
13.52
13.62
13.72
13.82
13.93
14.03
14.13
14.24
14.34
14.44
14.55
14.65
14.75
14.86
14.96
15.03
15.09
15.16
15.23
15.29
15.36
Class 3
Area
(sq. in.)
134.83
136.96
139.11
141.28
143.46
145.66
147.88
150.11
152.36
154.63
156.91
159.21
161.53
163.87
166.22
168.58
170.97
173.37
175.79
177.36
178.94
180.53
182.13
183.73
185.34
Moment
(ft-k)
147.2
150.7
154.3
157.9
161.6
165.3
169.1
172.9
176.8
180.8
184.8
188.9
193.0
197.2
201.5
205.8
210.2
214.6
219.2
222.1
225.1
228.1
231.1
234.2
237.3
Dist.
(ft.)
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
Bulletin 1724E-200
Page F-16
DOUGLAS FIR AND SOUTHERN YELLOW PINE
Ultimate Bending Stress – 8000 psi
85 ft.
Dist.
(ft.)
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
Dia.
(in.)
9.23
9.35
9.47
9.59
9.71
9.83
9.94
10.06
10.18
10.30
10.42
10.54
10.66
10.78
10.90
11.01
11.13
11.25
11.37
11.49
11.61
11.73
11.85
11.96
12.08
12.20
12.32
12.44
12.56
12.68
12.80
12.92
13.03
13.15
13.27
13.39
13.51
13.63
13.75
13.87
13.99
14.10
14.22
14.34
14.46
14.58
14.70
14.82
14.94
15.06
15.17
15.29
15.41
15.53
15.65
15.77
85 ft.
Class H1
Area
Moment
(sq. in.)
(ft-k)
66.92
51.5
68.66
53.5
70.42
55.6
72.20
57.7
74.00
59.9
75.82
62.1
77.67
64.4
79.53
66.7
81.42
69.1
83.34
71.5
85.27
74.0
87.23
76.6
89.20
79.2
91.21
81.9
93.23
84.6
95.27
87.4
97.34
90.3
99.43
93.2
101.54
96.2
103.68
99.3
105.83
102.4
108.01
105.6
110.21
108.8
112.44
112.1
114.68
115.5
116.95
118.9
119.24
122.4
121.55
126.0
123.88
129.7
126.24
133.4
128.62
137.2
131.02
141.0
133.44
144.9
135.88
148.9
138.35
153.0
140.84
157.2
143.35
161.4
145.89
165.7
148.44
170.1
151.02
174.5
153.62
179.0
156.24
183.6
158.89
188.3
161.55
193.1
164.24
197.9
166.95
202.8
169.69
207.8
172.44
212.9
175.22
218.1
178.02
223.3
180.04
228.7
183.69
234.1
186.55
239.6
189.44
245.2
192.35
250.9
195.28
256.6
Dia.
(in.)
8.59
8.71
8.82
8.93
9.05
9.16
9.27
9.38
9.50
9.61
9.72
9.84
9.95
10.06
10.17
10.29
10.40
10.51
10.63
10.74
10.85
10.96
11.08
11.19
11.30
11.41
11.53
11.64
11.75
11.87
11.98
12.09
12.20
12.32
12.43
12.54
12.66
12.77
12.88
12.99
13.11
13.22
13.33
13.45
13.56
13.67
13.78
13.90
14.01
14.12
14.24
14.35
14.46
14.57
14.69
14.80
Class 1
Area
(sq. in.)
58.01
59.55
61.10
62.67
64.26
65.88
67.51
69.16
70.84
72.53
74.24
75.98
77.73
79.50
81.29
83.11
84.94
86.79
88.67
90.56
92.47
94.40
96.36
98.33
100.32
102.34
104.37
106.42
108.49
110.59
112.70
114.83
116.99
119.16
121.35
123.56
125.80
128.05
130.32
132.62
134.93
137.26
139.61
141.99
144.38
146.79
149.23
151.68
154.15
156.64
159.16
161.69
164.24
166.81
169.41
172.02
Moment
(ft-k)
41.5
43.2
44.9
46.7
48.4
50.3
52.2
54.1
56.1
58.1
60.2
62.3
64.4
66.7
68.9
71.2
73.6
76.0
78.5
81.0
83.6
86.3
88.9
91.7
94.5
97.3
100.3
103.2
106.3
109.4
112.5
115.7
119.0
122.3
125.7
129.2
132.7
136.3
139.9
143.6
147.4
151.2
155.1
159.1
163.1
167.2
171.4
175.7
180.0
184.3
188.8
193.3
197.9
202.6
207.3
212.1
Dist.
(ft.)
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
Dia.
(in.)
7.96
8.06
8.17
8.28
8.38
8.49
8.60
8.71
8.81
8.92
9.03
9.13
9.24
9.35
9.45
9.56
9.67
9.77
9.88
9.99
10.09
10.20
10.31
10.41
10.52
10.63
10.73
10.84
10.95
11.05
11.16
11.27
11.37
11.48
11.59
11.69
11.80
11.91
12.02
12.12
12.23
12.34
12.44
12.55
12.66
12.76
12.87
12.98
13.08
13.19
13.30
13.40
13.51
13.62
13.72
13.83
Class 2
Area
(sq. in.)
49.74
51.08
52.44
53.82
55.22
56.63
58.07
59.52
60.99
62.47
63.98
65.50
67.04
68.60
70.18
71.77
73.38
75.01
76.66
78.33
80.01
81.71
83.43
85.17
86.93
88.70
90.49
92.30
94.13
95.97
97.84
99.72
101.61
103.53
105.47
107.42
109.39
111.38
113.38
115.41
117.45
119.51
121.59
123.68
125.80
127.93
130.08
132.25
134.43
136.63
138.86
141.09
143.35
145.63
147.92
150.23
Moment
(ft-k)
33.0
34.3
35.7
37.1
38.6
40.1
41.6
43.2
44.8
46.4
48.1
49.8
51.6
53.4
55.3
57.2
59.1
61.1
63.1
65.2
67.3
69.5
71.7
73.9
76.2
78.6
80.9
83.4
85.9
88.4
91.0
93.6
96.3
99.1
101.8
104.7
107.6
110.5
113.5
116.6
119.7
122.9
126.1
129.3
132.7
136.1
139.5
143.0
146.6
150.2
153.9
157.6
161.4
165.2
169.2
173.1
Dia.
(in.)
7.32
7.42
7.52
7.62
7.72
7.82
7.93
8.03
8.13
8.23
8.33
8.43
8.53
8.63
8.73
8.83
8.93
9.03
9.13
9.24
9.34
9.44
9.54
9.64
9.74
9.84
9.94
10.04
10.14
10.24
10.34
10.44
10.54
10.65
10.75
10.85
10.95
11.05
11.15
11.25
11.35
11.45
11.55
11.65
11.75
11.85
11.95
12.06
12.16
12.26
12.36
12.46
12.56
12.66
12.76
12.86
Class 3
Area
(sq. in.)
42.10
43.26
44.45
45.64
46.86
48.09
49.33
50.60
51.87
53.17
54.48
55.80
57.14
58.50
59.88
61.27
62.67
64.09
65.53
66.98
68.45
69.94
71.44
72.96
74.49
76.04
77.60
79.18
80.78
82.39
84.02
85.67
87.33
89.00
90.69
92.40
94.13
95.87
97.62
99.40
101.18
102.99
104.81
106.64
108.49
110.36
112.25
114.15
116.06
117.99
119.94
121.90
123.88
125.88
127.89
129.92
Moment
(ft-k)
25.7
26.8
27.9
29.0
30.2
31.4
32.6
33.8
35.1
36.5
37.8
39.2
40.6
42.1
43.6
45.1
46.7
48.2
49.9
51.5
53.3
55.0
56.8
58.6
60.5
62.3
64.3
66.3
68.3
70.3
72.4
74.6
76.7
79.0
81.2
83.5
85.9
88.3
90.7
93.2
95.7
98.3
100.9
103.6
106.3
109.0
111.8
114.7
117.6
120.5
123.5
126.6
129.7
132.8
136.0
139.2
Dist.
(ft.)
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
Bulletin 1724E-200
Page F-17
DOUGLAS FIR AND SOUTHERN YELLOW PINE
Ultimate Bending Stress – 8000 psi
85 ft.
Dist.
(ft.)
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
81
82
83
84
85
Dia.
(in.)
15.89
16.01
16.13
16.24
16.36
16.48
16.60
16.72
16.84
16.96
17.08
17.19
17.31
17.43
17.55
17.67
17.79
17.91
18.03
18.15
18.26
18.38
18.50
18.62
18.69
18.75
18.82
18.89
18.96
19.02
85 ft.
Class H1
Area
Moment
(sq. in.)
(ft-k)
198.24
262.5
201.22
268.4
204.22
274.4
207.24
280.5
210.28
286.7
213.35
293.0
216.44
299.4
219.55
305.9
222.68
312.5
225.83
319.1
229.01
325.9
232.21
332.7
235.43
339.7
238.68
346.7
241.94
353.9
245.23
361.1
248.54
368.4
251.87
375.9
255.23
383.4
258.60
391.0
262.00
398.8
265.42
406.6
268.87
414.6
272.33
422.6
274.29
427.2
276.26
431.8
278.23
436.4
280.21
441.1
282.20
445.8
284.19
450.5
Dia.
(in.)
14.91
15.03
15.14
15.25
15.36
15.48
15.59
15.70
15.81
15.93
16.04
16.15
16.27
16.38
16.49
16.60
16.72
16.83
16.94
17.06
17.17
17.28
17.39
17.51
17.57
17.64
17.71
17.77
17.84
17.91
Class 1
Area
(sq. in.)
174.65
177.30
179.98
182.67
185.38
188.12
190.87
193.64
196.43
199.25
202.08
204.93
207.80
210.70
213.61
216.54
219.49
222.47
225.46
228.47
231.50
234.56
237.63
240.72
242.56
244.41
246.27
248.13
250.00
251.88
Moment
(ft-k)
217.0
222.0
227.0
232.2
237.3
242.6
248.0
253.4
258.9
264.5
270.1
275.9
281.7
287.6
293.6
299.6
305.8
312.0
318.3
324.7
331.2
337.8
344.4
351.2
355.2
359.3
363.4
367.5
371.7
375.9
Dist.
(ft.)
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
81
82
83
84
85
Dia.
(in.)
13.94
14.04
14.15
14.26
14.36
14.47
14.58
14.68
14.79
14.90
15.00
15.11
15.22
15.33
15.43
15.54
15.65
15.75
15.86
15.97
16.07
16.18
16.29
16.39
16.46
16.53
16.59
16.66
16.73
16.79
Class 2
Area
(sq. in.)
152.56
154.91
157.27
159.65
162.05
164.47
166.91
169.36
171.83
174.32
176.83
179.36
181.90
184.46
187.04
189.64
192.25
194.88
197.54
200.20
202.89
205.60
208.32
211.06
212.78
214.52
216.25
218.00
219.75
221.51
Moment
(ft-k)
177.2
181.3
185.5
189.7
194.0
198.3
202.8
207.2
211.8
216.4
221.1
225.9
230.7
235.6
240.5
245.6
250.7
255.8
261.1
266.4
271.8
277.2
282.7
288.3
291.9
295.4
299.0
302.7
306.3
310.0
Dia.
(in.)
12.96
13.06
13.16
13.26
13.36
13.47
13.57
13.67
13.77
13.87
13.97
14.07
14.17
14.27
14.37
14.47
14.57
14.67
14.78
14.88
14.98
15.08
15.18
15.28
15.35
15.41
15.48
15.55
15.61
15.68
Class 3
Area
(sq. in.)
131.96
134.02
136.09
138.18
140.29
142.41
144.55
146.71
148.88
151.06
153.27
155.48
157.72
159.97
162.23
164.52
166.81
169.13
171.46
173.80
176.17
178.54
180.94
183.35
184.95
186.57
188.19
189.82
191.46
193.10
Moment
(ft-k)
142.5
145.9
149.3
152.7
156.2
159.8
163.4
167.1
170.8
174.6
178.4
182.3
186.2
190.2
194.3
198.4
202.6
206.8
211.1
215.5
219.9
224.3
228.9
233.4
236.5
239.6
242.8
245.9
249.1
252.3
Dist.
(ft.)
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
81
82
83
84
85
Bulletin 1724E-200
Page F-18
DOUGLAS FIR AND SOUTHERN YELLOW PINE
Ultimate Bending Stress – 8000 psi
90 ft.
Dist.
(ft.)
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
Dia.
(in.)
9.23
9.35
9.46
9.58
9.69
9.81
9.92
10.04
10.16
10.27
10.39
10.50
10.62
10.73
10.85
10.96
11.08
11.20
11.31
11.43
11.54
11.66
11.77
11.89
12.00
12.12
12.24
12.35
12.47
12.58
12.70
12.81
12.93
13.05
13.16
13.28
13.39
13.51
13.62
13.74
13.85
13.97
14.09
14.20
14.32
14.43
14.55
14.66
14.78
14.89
15.01
15.13
15.24
15.36
15.47
15.59
90 ft.
Class H1
Area
Moment
(sq. in.)
(ft-k)
66.92
51.5
68.61
53.4
70.32
55.4
72.05
57.5
73.80
59.6
75.57
61.8
77.36
64.0
79.17
66.2
81.00
68.6
82.86
70.9
84.73
73.3
86.63
75.8
88.55
78.3
90.48
80.9
92.44
83.6
94.42
86.3
96.42
89.0
98.45
91.8
100.49
94.7
102.55
97.7
104.64
100.6
106.74
103.7
108.87
106.8
111.02
110.0
113.19
113.2
115.38
116.5
117.59
119.9
119.82
123.3
122.07
126.8
124.35
130.4
126.64
134.0
128.96
137.7
131.30
141.5
133.65
145.3
136.03
149.2
138.43
153.2
140.85
157.2
143.29
161.3
145.76
165.5
148.24
169.7
150.75
174.0
153.27
178.4
155.82
182.9
158.39
187.4
160.97
192.0
163.58
196.7
166.21
210.5
168.87
206.3
171.54
211.3
174.23
216.3
176.95
221.3
179.68
226.5
182.44
231.7
185.22
237.0
188.01
242.4
190.83
247.9
Dia.
(in.)
8.59
8.70
8.81
8.92
9.03
9.14
9.25
9.36
9.47
9.58
9.69
9.80
9.91
10.02
10.13
10.24
10.35
10.46
10.57
10.68
10.79
10.90
11.01
11.12
11.23
11.34
11.45
11.56
11.67
11.78
11.89
12.00
12.11
12.22
12.33
12.44
12.55
12.66
12.77
12.88
12.99
13.10
13.21
13.32
13.43
13.54
13.65
13.76
13.87
13.98
14.09
14.20
14.31
14.42
14.53
14.64
Class 1
Area
(sq. in.)
58.01
59.51
61.02
62.55
64.10
65.67
67.25
68.86
70.49
72.13
73.80
75.48
77.18
78.90
80.64
82.40
84.14
85.97
87.79
89.62
91.48
93.35
95.24
97.15
99.08
101.03
103.00
104.98
106.99
109.01
111.05
113.12
115.20
117.30
119.42
121.56
123.71
125.89
128.08
130.30
132.53
134.78
137.05
139.34
141.65
143.98
146.33
148.69
151.08
153.48
155.90
158.34
160.80
163.28
165.78
168.30
Moment
(ft-k)
41.5
43.2
44.8
46.5
48.3
50.0
51.9
53.7
55.6
57.6
59.6
61.7
63.8
65.9
68.1
70.3
72.6
75.0
77.3
79.8
82.3
84.8
87.4
90.0
92.7
95.5
98.3
101.1
104.1
107.0
110.0
113.1
116.3
119.5
122.7
126.0
129.4
132.8
136.3
139.9
143.5
147.1
150.9
154.7
158.5
162.5
166.4
170.5
174.6
178.8
183.0
187.4
191.7
196.2
200.7
205.3
Dist.
(ft.)
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
Dia.
(in.)
7.96
8.06
8.17
8.28
8.38
8.49
8.59
8.70
8.81
8.91
9.02
9.12
9.23
9.34
9.44
9.55
9.66
9.76
9.87
9.97
10.08
10.19
10.29
10.40
10.50
10.61
10.72
10.82
10.93
11.03
11.14
11.25
11.35
11.46
11.57
11.67
11.78
11.88
11.99
12.10
12.20
12.31
12.41
12.52
12.63
12.73
12.84
12.94
13.05
13.16
13.26
13.37
13.48
13.58
13.69
13.79
Class 2
Area
(sq. in.)
49.74
51.07
52.42
53.79
55.18
56.59
58.01
59.45
60.91
62.39
63.88
65.39
66.92
68.47
70.04
71.62
73.22
74.84
76.47
78.13
79.80
81.49
83.19
84.92
86.66
88.42
90.20
91.99
93.80
95.63
97.48
99.35
101.23
103.13
105.05
106.99
108.94
110.91
112.90
114.91
116.93
118.98
121.04
123.12
125.21
127.32
129.45
131.60
133.77
135.95
138.16
140.37
142.61
144.87
147.14
149.43
Moment
(ft-k)
33.0
34.3
35.7
37.1
38.5
40.0
41.5
43.1
44.7
46.3
48.1
49.7
51.5
53.3
55.1
57.0
58.9
60.9
62.9
64.9
67.0
69.2
71.5
73.6
75.9
78.2
80.5
83.0
85.4
87.9
90.5
93.1
95.8
98.5
101.2
104.1
106.9
109.8
112.8
115.8
118.9
122.0
125.2
128.5
131.7
135.1
138.5
142.0
145.5
149.1
152.7
156.4
160.1
164.0
167.8
171.8
Dia.
(in.)
7.32
7.42
7.52
7.62
7.72
7.81
7.91
8.01
8.11
8.21
8.31
8.40
8.50
8.60
8.70
8.80
8.90
9.00
9.09
9.19
9.29
9.39
9.49
9.59
9.69
9.78
9.88
9.98
10.08
10.18
10.28
10.38
10.47
10.57
10.67
10.77
10.87
10.97
11.07
11.16
11.26
11.36
11.46
11.56
11.66
11.75
11.85
11.95
12.05
12.15
12.25
12.35
12.44
12.54
12.64
12.74
Class 3
Area
(sq. in.)
42.10
43.24
44.39
45.56
46.75
47.95
49.17
50.40
51.65
52.91
54.19
55.48
56.79
58.11
59.45
60.81
62.18
63.56
64.96
66.38
67.81
69.25
70.71
72.19
73.68
75.19
76.71
78.25
79.80
81.37
82.95
84.55
86.16
87.79
89.43
91.09
92.77
94.46
96.16
97.88
99.62
101.37
103.13
104.91
106.71
108.52
110.35
112.19
114.05
115.92
117.81
119.71
121.63
123.56
125.51
127.48
Moment
(ft-k)
25.7
26.7
27.8
28.9
30.1
31.2
32.4
33.6
34.9
36.2
37.5
38.9
40.2
41.7
43.1
44.6
46.1
47.7
49.2
50.9
52.5
54.2
55.9
57.7
59.5
61.3
63.2
65.1
67.0
69.0
71.0
73.1
75.2
77.3
79.5
81.8
84.0
86.3
88.7
91.1
93.5
96.0
98.5
101.0
103.7
106.3
109.0
111.7
114.5
117.4
120.2
123.2
126.1
129.2
132.2
135.3
Dist.
(ft.)
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
Bulletin 1724E-200
Page F-19
DOUGLAS FIR AND SOUTHERN YELLOW PINE
Ultimate Bending Stress – 8000 psi
90 ft.
Dist.
(ft.)
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
81
82
83
84
85
86
87
88
89
90
Dia.
(in.)
15.70
15.82
15.93
16.05
16.17
16.28
16.40
16.51
16.63
16.74
16.86
16.97
17.09
17.21
17.32
17.44
17.55
17.67
17.78
17.90
18.01
18.13
18.25
18.36
18.48
18.59
18.71
18.82
18.94
19.01
19.07
19.14
19.21
19.27
19.34
90 ft.
Class H1
Area
Moment
(sq. in.)
(ft-k)
193.67
253.4
196.54
259.1
199.42
264.8
202.32
270.6
205.25
276.5
208.19
282.5
211.16
288.5
214.14
294.7
217.15
300.9
220.18
307.2
223.23
313.6
226.30
320.1
229.40
326.7
232.51
333.4
235.64
340.1
238.80
347.0
241.97
353.9
245.17
361.0
248.39
368.1
251.63
375.3
254.89
382.6
258.17
390.1
261.47
397.6
264.79
405.2
268.14
412.9
271.50
420.7
274.89
428.6
278.30
436.6
281.72
444.6
283.72
449.4
285.72
454.1
287.72
458.9
289.73
463.7
291.76
468.6
293.78
473.5
Dia.
(in.)
14.75
14.86
14.97
15.08
15.19
15.30
15.41
15.52
15.63
15.74
15.85
15.96
16.07
16.18
16.29
16.40
16.51
16.62
16.73
16.84
16.95
17.06
17.17
17.28
17.39
17.50
17.61
17.72
17.83
17.89
17.96
18.03
18.09
18.16
18.23
Class 1
Area
(sq. in.)
170.84
173.39
175.96
178.56
181.17
183.80
186.45
189.12
191.81
194.52
197.24
199.99
202.75
205.53
208.34
211.16
214.00
216.86
219.73
222.63
225.55
228.48
231.43
234.41
237.40
240.41
243.44
246.49
249.55
451.43
253.31
255.20
257.10
259.00
260.91
Moment
(ft-k)
210.0
214.7
219.5
224.4
229.3
234.3
239.4
244.6
249.8
255.1
260.5
265.9
271.5
277.1
282.8
288.5
294.4
300.3
306.3
312.4
218.5
324.7
331.1
337.5
343.9
350.5
357.2
363.9
370.7
374.9
379.1
383.4
387.6
391.9
396.3
Dist.
(ft.)
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
81
82
83
84
85
86
87
88
89
90
Dia.
(in.)
13.90
14.01
14.11
14.22
14.32
14.43
14.54
14.64
14.75
14.85
14.96
15.07
15.17
15.28
15.38
15.49
15.60
15.70
15.81
15.92
16.02
16.13
16.23
16.34
16.45
16.55
16.66
16.76
16.87
16.94
17.00
17.07
17.14
17.20
17.27
Class 2
Area
(sq. in.)
151.74
154.06
156.41
158.77
161.14
163.54
165.95
168.39
170.84
173.30
175.79
178.29
180.81
183.35
185.90
188.47
191.07
193.67
196.30
198.94
201.61
204.28
206.98
209.70
212.43
215.18
217.95
220.73
223.53
225.31
227.09
228.88
230.67
232.48
234.29
Moment
(ft-k)
175.8
179.8
183.9
188.1
192.4
196.7
201.0
205.5
210.0
214.5
219.2
223.9
228.6
233.4
238.3
243.3
248.3
253.4
258.6
263.9
269.2
274.6
280.0
285.5
291.1
296.8
302.5
308.4
314.3
318.0
321.8
325.6
329.4
333.3
337.2
Dia.
(in.)
12.84
12.94
13.04
13.13
13.23
13.33
13.43
13.53
13.63
13.73
13.82
13.92
14.02
14.12
14.22
14.32
14.41
14.51
14.61
14.71
14.81
14.91
15.01
15.10
15.20
15.30
15.40
15.50
15.60
15.66
15.73
15.80
15.86
15.93
16.00
Class 3
Area
(sq. in.)
129.45
131.45
133.46
135.48
137.52
139.58
141.65
143.74
145.84
147.95
150.09
152.23
154.40
156.57
158.77
160.97
163.20
165.44
167.69
169.96
172.24
174.54
176.86
179.19
181.53
183.89
186.27
188.66
191.07
192.71
194.35
196.01
197.67
199.34
201.02
Moment
(ft-k)
138.5
141.7
145.0
148.3
151.7
155.1
158.5
162.0
165.6
169.2
172.9
176.6
180.4
184.2
188.1
192.0
196.0
200.1
204.2
208.3
212.6
216.8
221.2
225.5
230.0
234.5
239.0
243.7
248.3
251.5
254.8
258.0
261.3
264.6
268.0
Dist.
(ft.)
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
81
82
83
84
85
86
87
88
89
90
Bulletin 1724E-200
Page F-20
MOMENT REDUCTION DUE TO A
BOLT HOLE IN A POLE
The reduction in moment capacity of a pole caused by a bolt hole is calculated by the equation:
( Fb (b)(b 2 sin 2θ + d n cos 2 θ )
72(1000)
2
M bh =
where:
Fb = Ultimate fiber stress of the wood (psi)
dn = Pole diameter at location ‘n’ (inches)
b = Width of hole, taken as bolt diameter
plus 1/16 inch (inches)
Mbh = Reduction in strength (ft-kips)
The drawings below explain the Pole Moment Reduction table which follows:
0 = 0°
Neutral Axis
-1
0 = sin (3.5/d n )
Neutral Axis
The Pole Moment Reduction table which follows is based on 1000 psi for the fiber stress. For
any species of wood, this number should be multiplied by the fiber stress of the wood divided by
1000.
Bulletin 1724E-200
Page F-21
TABLE F-4
POLE MOMENT (ft-k) REDUCTION
DUE TO BOLT HOLES FOR 1000 psi FIBER STRESS
POLE
3/4 in. *
DIAM 0 DEGREES
THETA
9
0.914
0.78
9.1
0.934
0.93
9.2
0.955
0.96
9.3
0.976
0.98
9.4
0.997
1.00
9.5
1.018
1.02
9.6
1.040
1.04
9.7
1.062
1.06
9.8
1.084
1.08
9.9
1.106
1.11
10
1.128
1.13
10.1
1.151
1.15
10.2
1.174
1.17
10.3
1.197
1.20
10.4
1.221
1.22
10.5
1.244
1.24
10.6
1.268
1.27
10.7
1.292
1.29
10.8
1.316
1.32
10.9
1.341
1.34
11
1.365
1.37
11.1
1.390
1.39
11.2
1.416
1.42
11.3
1.441
1.44
11.4
1.467
1.47
11.5
1.492
1.49
11.6
1.518
1.52
11.7
1.545
1.54
11.8
1.571
1.57
11.9
1.598
1.60
12
1.625
1.63
12.1
1.652
1.65
12.2
1.680
1.68
12.3
1.707
1.71
12.4
1.735
1.74
12.5
1.763
1.76
12.6
1.792
1.79
12.7
1.820
1.82
12.8
1.849
1.85
12.9
1.878
1.88
13
1.907
1.91
13.1
1.937
1.94
13.2
1.966
1.97
13.3
1.996
2.00
13.4
2.026
2.03
13.5
2.057
2.06
13.6
2.087
2.09
13.7
2.118
2.12
13.8
2.149
2.15
13.9
2.180
2.18
14
2.212
2.21
14.1
2.244
2.24
14.2
2.275
2.28
14.3
2.308
2.31
14.4
2.340
2.34
14.5
2.373
2.37
14.6
2.405
2.41
14.7
2.439
2.44
14.8
2.472
2.47
14.9
2.505
2.51
15
2.539
2.54
7/8 in. *
0 DEGREES
THETA
1.055
0.897
1.078
1.078
1.102
1.102
1.126
1.126
1.151
1.151
1.175
1.175
1.200
1.200
1.225
1.225
1.251
1.251
1.276
1.276
1.302
1.302
1.328
1.328
1.355
1.355
1.381
1.381
1.408
1.408
1.436
1.436
1.463
1.463
1.491
1.491
1.519
1.519
1.547
1.547
1.576
1.576
1.604
1.604
1.633
1.633
1.663
1.663
1.692
1.692
1.722
1.722
1.752
1.752
1.782
1.782
1.813
1.813
1.844
1.844
1.875
1.875
1.906
1.906
1.938
1.938
1.970
1.970
2.002
2.002
2.035
2.035
2.067
2.067
2.100
2.100
2.133
2.133
2.167
2.167
2.201
2.201
2.235
2.235
2.269
2.269
2.303
2.303
2.338
2.338
2.373
2.373
2.408
2.408
2.444
2.444
2.480
2.480
2.516
2.516
2.552
2.552
2.589
2.589
2.626
2.626
2.663
2.663
2.700
2.700
2.738
2.738
2.776
2.776
2.814
2.814
2.852
2.852
2.891
2.891
2.930
2.930
*BOLT HOLE = BOLT DIAMETER + 1/16 in.
1
in. *
0 DEGREES
THETA
1.195
1.017
1.222
1.222
1.249
1.249
1.276
1.276
1.304
1.304
1.332
1.332
1.360
1.360
1.388
1.388
1.417
1.417
1.446
1.446
1.476
1.476
1.505
1.505
1.535
1.535
1.566
1.566
1.596
1.596
1.627
1.627
1.658
1.658
1.690
1.690
1.721
1.721
1.753
1.753
1.786
1.786
1.818
1.818
1.851
1.851
1.884
1.884
1.918
1.918
1.952
1.952
1.986
1.986
2.020
2.020
2.055
2.055
2.090
2.090
2.125
2.125
2.161
2.161
2.196
2.196
2.233
2.233
2.269
2.269
2.306
2.306
2.343
2.343
2.380
2.380
2.418
2.418
2.456
2.456
2.494
2.494
2.532
2.532
2.571
2.571
2.610
2.610
2.650
2.650
2.689
2.689
2.729
2.729
2.770
2.770
2.810
2.810
2.851
2.851
2.892
2.892
2.934
2.934
2.976
2.976
3.018
3.018
3.060
3.060
3.103
3.103
3.146
3.146
3.189
3.189
3.232
3.232
3.276
3.276
3.320
3.320
Bulletin 1724E-200
Page F-22
TABLE F-5
VOLUMES FOR DOUGLAS FIR AND
SOUTHERN YELLOW PINE POLES, (cu. ft.)
Height
Pole Classes
ft.
H1
1
2
3
50
55
60
65
70
75
80
85
90
44.1
51.2
58.0
65.2
72.8
80.9
89.5
98.5
106.6
39.3
45.0
51.1
57.2
64.5
71.8
79.6
86.6
93.9
34.1
39.2
44.6
50.5
56.7
62.3
69.3
75.6
83.3
24.4
33.7
38.6
43.8
49.3
54.4
59.7
65.2
71.1
TALBE F-6
POLE WEIGHTS FOR DOUGLAS FIR (TREATED)
(50 pcf assumed) (lbs.)
Height
Pole Classes
ft.
H1
1
2
3
50
55
60
65
70
75
80
85
90
2200
2560
2900
3260
3640
4050
4480
4930
5330
1970
2250
2560
2860
3225
3590
3980
4330
4700
1700
1960
2230
2530
2840
3120
3470
3780
4170
1220
1690
1930
2190
2470
2720
2990
3260
3560
TABLE F-7
POLE WEIGHTS FOR SOUTHERN YELLOW PINE (TREATED)
(60 pcf assumed) (lbs.)
Height
Pole Classes
ft.
H1
1
2
3
50
55
60
65
70
75
80
85
90
2650
3070
3480
3900
4370
4850
5380
5910
6400
2360
2700
3070
3430
3870
4300
4780
5200
5630
2050
2350
2680
3030
3400
3740
4160
4540
5000
1470
2020
2320
2630
2960
3260
3580
3910
4270
Bulletin 1724E-200
Page G-1
APPENDIX G
CROSSARM DATA
•
•
Moment Capacities of
Standard Crossarms
G-2
Crossarm Loading Chart
G-3
Bulletin 1724E-200
Page G-2
MOMENT CAPACITIES OF
STANDARD CROSSARM SIZES
The following table gives moment capacities (MXX, MYY ) of standard size crossarms for
transmission structures in RUS Form 805. The moment capacities are based on the dressed size
of the arms and a modulus of rupture of 7400 psi. MXX is the moment resistance for vertical and
MYY is the moment resistance for longitudinal loads. Section moduli are also given for the
respective axis.
TABLE G-1
CROSSARM SIZES AND MOMENT CAPACITIES
Crossarm Size
SXX(in3)
MXX(ft-k)
SYY(in3)
MYY (ft-k)
3-5/8 x 9-3/8
(2) 3-5/8 x 9-3/8
3-5/8 x 5-5/8
(2) 3-5/8 x 5-5/8
4-1/8 x 5-1/8
(2) 4-1/8 x 5-1/8
4-5/8 x 5-5/8
(2) 5/8 x 5-5/8
5-3.8 x 7-5/8
5-5/8 x 7-3/8
49.9
99.8
17.7
35.3
16.7
33.3
22.7
45.4
49.2
48.2
30.8
61.6
10.9
21.8
10.3
20.6
14.0
28.0
30.4
29.7
18.9
37.8
11.2
22.5
13.3
26.7
18.6
37.1
34.5
36.6
11.7
23.3
6.9
13.9
16.5
16.5
11.5
22.9
21.2
22.5
Example:
Given:
Determine the maximum vertical span for a TSS-1L (69 kV)
Conductor: 266.8 26/7 ACSR
Ldg. Dist:
Heavy
Cond. Wt. (wc):
1.0776 lbs./ft.
51 lbs.
Insulator wt. (Wi):
Moment arm(s):
5.5 ft.
Procedure:
Moment capacity of TSS-1L arm (4-5/8” x 5-5/8”) is 14.0 ft-k.
V .S . =
φMa −(OLF ) (Wi ) ( s)
(OLF ) (Wc ) (s )
= (0.50)(14,000 ) −1.5 (51) (5.5)
(1.5) (1.0776) (5.5)
= 740 ft.
Bulletin 1724E-200
Page G-3
FIGURE G-1
Crossarm Loading Chart - Maximum Permitted Vertical Loads
of Various Sizes of Douglas Fir Crossarms
(A fiber stress of 7400 x 0.5 or 3700 psi is assumed)
8,000
7,000
6,000
Load in Pounds
5,000
4,000
3-5/8 x 9-3/8
3,000
5-5/8 x7-3/8
4-5/8 x 5-5/8
2,000
3-5/8 x 5-5/8
1,000
4-1/8 x 5-
0
2
3
4
5
6
7
Moment Arm in Feet
8
9
10
Bulletin 1724E-200
Page G-4
Blank Page
Bulletin 1724E-200
Page H-1
APPENDIX H
MISCELLANEOUS STRUCTURAL DATA
• Properties of Common Sections
H-2
• Curve for Locating Plane of Contra-flexure
for Braced H-frame structures
H-3
• Tensile Strength of Bolts
H-4
• Rated Breaking Strength of Guy Wire
H-4
Bulletin 1724E-200
Page H-2
TABLE H-1
PROPERTIES OF COMMON SECTIONS
FIGURE H-1
CURVE FOR LOCATING PLANE OF CONTRAFLEXURE
IN X-BRACED H-FRAME STRUCTURES
Bulletin 1724E-200
Page H-3
Bulletin 1724E-200
Page H-4
TABLE H-2
STRENGTHS FOR MACHINE BOLTS
DOUBLE ARMING BOLTS, DOUBLE END BOLTS
(Conforming to ANSI C135.1)
Machine Bolt
Diameter (in.)
1/2”
5/8”
3/4”
7/8”
1”
Tension Stress
Area (in.2)
0.142
0.226
0.334
0.462
0.606
Min. Tensile
Strength (lbs.)
7,800
12, 400
18,350
25,400
33,500
TABLE H-3
STRENGTHS OF ASTM A325
HEAT TREATED, HIGH STRENGTH BOLTS
Machine Bolt
Diameter
(in.)
1/2
5/8
3/4
7/8
1
Tensile
Stress Area
(sq. in.)
0.142
0.226
0.334
0.462
0.606
Minimum Tensile
Strength
(lbs.)
17,500
27,100
40,100
55,450
72,700
Minimum Yield
Strength
(lbs.)
13,050
20,800
30,700
42,500
55,570
TABLE H-4
STRENGTH OF GUY STRANDS
Strand Size
Description
3/8 in.
7 No. 9 AWG
3/8 in.
7/16 in.
7 No. 8 AWG
7 No. 7 AWG
7/16 in.
H.S.
A.C.S
E.H.S
H.S.
A.C.S
A.C.S
E.H.S
Minimum Breaking
Strength (lbs)
10,800
12,600
14,400
14,500
15,930
19,060
20,080
H.S.= high strength, E.H.S. = extra high strength, A.C.S.= aluminum clad steel
Bulletin 1724E-200
Page I-1
APPENDIX I
RI AND TVI
•
Insulator and Hardware RIV
Performance Values
I-2
•
Some Possible Sources of RI
or RVI on Transmission Lines
I-2
•
Formulae for Calculating Surface
Gradients of Conductors
I-3
•
Surface Gradient for Typical Designs
I-5
Bulletin 1724E-200
Page I-2
INSULATOR AND HARDWARE RIV PERFORMANCE VALUES
The values below give recommended maximum RIV levels for insulators plus hardware
assemblies for various voltages. The RIV values are measured using the procedure outlined in
NEMA publication 107, Methods of Measuring Radio Noise – 1964.
TABLE I-1
RIV LEVELS
kVLL
34.5
46
69
115
138
161
230
RIV Level in Microvolts at 1000
kHZ*
100
200
200
200
200
500
500
Note:
The values in Table I-1 are from Figure 3 of “Transmission System Radio
Influence”-IEEE Committee Report – Power Apparatus and System, August
1965. (This publication is the major work on the subject.)
SOME POSSIBLE SOURCES OF RI OR TVI
ON TRANSMISSION LINES
1. Poor contact between metal parts of suspension insulators; an insufficient vertical span or an
uplift condition can cause this.
2. Poor contact between clamps and clamp support brackets on clamp-top insulators;
3. Loose conductor clamps;
4. Loose hardware which can result from wood shrinkage, structure vibration or wind
movement;
5. Loose crossarm braces or bolts;
6. Loose insulator mounting brackets;
7. Loose staples, bonding wire or ground wire;
8. Staples, bonding wire or ground wire too near ungrounded hardware;
9. Bond or ground wire clamped against wood under washer;
10. Unbonded guy wires too close to each other or to pole hardware;
11. Slack guy wire causing poor contact at pole attachments or at anchor eye;
12. Metal-to-metal clearance insufficient on pole hardware;
13. “Trash” on conductors (bits of wire, metal kite strings, tree limb, etc.).
Bulletin 1724E-200
Page I-3
FORMULAE FOR CALCULATING SURFACE
GRADIENTS OF CONDUCTORS
Excessively high conductor surface gradients can result in radio noise, television interference,
and corona. The equations below can be used to check the surface gradient. They are
approximate but yield reasonably accurate results. They assume phase conductors that are far
apart compared to their diameter.
Equation for Single Conductor per Phase:
g=
kV LL
3 r ln
Eq. I-1
D
r
where:
kVLL = line-to-line voltage, kV
r = conductor radius, cm.
D = geometric mean distance (GMD) of the
phase conductors, cm.
g = conductor surface gradient, kV/cm
Equation for Two Conductor Bundle per Phase:
g=
kV LL (1 + 2 r / s )
2 3 r ln
D
rs
Eq. I-2
where:
All the symbols are the same as those above with the addition
that:
s = the separation between subconductors, cm.
Application of Formulae:
It is recommended that transmission line designs that have unusually close phase spacing have
the conductor surface gradient checked. A maximum conductor gradient of 16 kV/cm should be
used.
Bulletin 1724E-200
Page I-4
Example
Determine the conductor gradient for a 230 kV line with (1) a 556.5 kcmil (dove) ACSR
conductor and (2) a 1272 kcmil (pheasant) conductor. GMD for TH-230 is 24.57 feet or 784.90
cm.
556.5 kcmil conductor:
r=
.927
2
(2.54) = 1.18
230 (1.05)
g=
3 (1.18)1n
748.90
1.18
g = 18.3 kV/cm.
The 556.5 kcmil conductor should not be used for 230 kV lines.
1272 kcmil Conductor (1 Conductor):
r=
g=
1.382
2
g=
(2.54) = 1.755
230 (1.05)
3 (1.755) 1n
g = 13.12 kV/cm.
748.90
1.755
Bulletin 1724E-200
Page I-5
TABLE I-2
SURFACE GRADIENT FOR TYPICAL DESIGNS
16 kV/cm recommended to minimize
radio noise
Conductor
Diameter
Radius
(inches)
RAVEN
QUAIL
PIGEON
PENGUIN
WAXWING
PARTRIDGE
MERLIN
LINNET
ORIOLE
CHICKADEE
IBIS
LARK
PELICAN
FLICKER
HAWK
HEN
OSPREY
PARAKEET
DOVE
EAGLE
KINGBIRD
ROOK
GROSBEAK
EGRET
0.398
0.447
0.502
0.563
0.609
0.642
0.684
0.721
0.741
0.743
0.783
0.806
0.814
0.846
0.858
0.883
0.879
0.914
0.927
0.953
0.94
0.977
0.99
1.019
0.199
0.224
0.251
0.282
0.305
0.321
0.342
0.361
0.371
0.372
0.392
0.403
0.407
0.423
0.429
0.442
0.440
0.457
0.464
0.477
0.470
0.489
0.495
0.510
TP-3
TP-3
TS-1 TU-1AA
GMD
GMD
GMD
GMD
2.53
2.53
3.00
3.59
(feet)
77.15
77.15
91.33 109.35
(cm)
Gradien Gradien Gradien Gradien
t
t
t
t
Radiu
s
(kV/cm) (kV/cm) (kV/cm) (kV/cm)
(cm)
34.5
46
69
161
0.505
0.568
0.638
0.715
0.773
0.815
0.869
0.916
0.941
0.944
0.994
1.024
1.034
1.074
1.090
1.121
1.116
1.161
1.177
1.210
1.194
1.241
1.257
1.294
8.23
7.50
6.84
6.25
5.88
5.64
5.37
5.15
5.04
5.03
4.83
4.73
4.69
4.55
4.51
4.41
4.42
4.29
4.25
4.16
4.20
4.08
4.04
3.95
10.97
10.00
9.12
8.33
7.83
7.52
7.16
6.87
6.72
6.71
6.44
6.30
6.25
6.07
6.01
5.88
5.90
5.72
5.66
5.55
5.60
5.44
5.39
5.27
15.92
14.50
13.22
12.06
11.33
10.87
10.34
9.93
9.72
9.69
9.31
9.10
9.03
8.76
8.67
8.48
8.51
8.25
8.17
7.99
8.08
7.84
7.76
7.59
35.91
32.68
29.76
27.14
25.49
24.44
23.24
22.29
21.81
21.76
20.88
20.41
20.25
19.65
19.44
19.00
19.07
18.50
18.30
17.91
18.10
17.56
17.38
17.00
TH-230
GMD
24.57
748.85
Gradien
t
(kV/cm)
230
37.78
34.19
30.94
28.04
26.22
25.06
23.75
22.70
22.18
22.13
21.17
20.65
20.48
19.82
19.59
19.12
19.19
18.57
18.35
17.92
18.13
17.55
17.36
16.94
Bulletin 1724E-200
Page I-6
TABLE I-2 (Continued)
SURFACE GRADIENT FOR TYPICAL DESIGNS
16 kV/cm recommended to minimize
radio noise
Conductor
CUCKOO
DRAKE
MALLARD
TERN
CONDOR
RAIL
CARDINAL
BUNTING
GRACKLE
BITTERN
PHEASANT
LAPWING
FALCON
CHUKAR
BLUEBIRD
Diameter
Radius
(inches)
1.092
1.108
1.14
1.063
1.093
1.165
1.196
1.302
1.338
1.345
1.382
1.502
1.545
1.602
1.762
0.546
0.554
0.570
0.532
0.547
0.583
0.598
0.651
0.669
0.673
0.691
0.751
0.773
0.801
0.881
TP-3
TP-3
TS-1 TU-1AA
GMD
GMD
GMD
GMD
2.53
2.53
3.00
3.59
(feet)
77.15
77.15
91.33 109.35
(cm)
Gradien Gradien Gradien Gradien
t
t
t
t
Radiu
s
(kV/cm) (kV/cm) (kV/cm) (kV/cm)
(cm)
34.5
46
69
161
1.387
1.407
1.448
1.350
1.388
1.480
1.519
1.654
1.699
1.708
1.755
1.908
1.962
2.035
2.238
3.75
3.71
3.63
3.83
3.75
3.57
3.51
3.29
3.23
3.21
3.15
2.96
2.90
2.83
2.64
5.00
4.95
4.84
5.11
5.00
4.77
4.67
4.39
4.30
4.28
4.20
3.95
3.87
3.77
3.52
7.20
7.12
6.97
7.35
7.20
6.86
6.72
6.31
6.18
6.15
6.03
5.67
5.55
5.40
5.04
16.11
15.93
15.59
16.45
16.10
15.33
15.03
14.08
13.79
13.74
13.46
12.64
12.37
12.04
11.21
TH-230
GMD
24.57
748.85
Gradien
t
(kV/cm)
230
15.98
15.79
15.41
16.35
15.97
15.13
14.80
13.79
13.48
13.42
13.12
12.24
11.95
11.60
10.72
Bulletin 1724E-200
Page J-1
APPENDIX J
INSULATOR SWING TABLES
Bulletin 1724E-200
Page J-2
TABLE J-1
INSULATOR SWING VALUES FOR STANDARD TANGENT STRUCTURES
(Porcelain Insulators with Ball Hook and Suspension Clamp
per Drawing TM-1A. Insulator String Lengths per TABLE C-3)
Number of
Insulators
Insulator Swing
Angle In
Degrees
(no wind
clearance,
note 1)
Insulator Swing
Angle In
Degrees
(moderate wind
clearance,
note 2)
Insulator Swing
Angle In
Degrees
(high wind
clearance,
note 3)
3
3
3
40.2
40.8
40.2
69.8
69.8
70.5
82.0
82.0
82.3
3
25.3
52.3
68.0
3
3
3
3
3
3
3
3
25.3
67.9
40.8
40.8
77.0
52.6
41.3
77.0
52.9
92.9
72.5
70.1
101.9
77.1
72.9
101.9
68.0
108.6
89.5
89.1
115.1
90.5
89.8
115.1
46 kV
TS-1, TS-1X
TS-1L, TS-1LX
TS-2, TS-2X
TSD-1, TSD-1X
TSD-2, TSD-2X
TS-9
TSS-1, TSS-2
TSS-1L
TSS-9
TSZ-1, TSZ-2
TH-1, TH-1G
TH-9, TH-9G
3
3
3
3
3
3
3
3
3
3
3
3
40.2
40.8
40.2
25.3
25.3
67.9
40.8
40.8
77.0
52.6
41.3
77.0
64.5
64.5
65.0
47.7
48.0
86.9
64.9
64.9
97.2
72.3
67.8
97.2
82.0
82.0
82.3
68.0
68.0
108.6
89.5
89.5
115.1
90.5
89.8
115.1
69 kV
TS-1, TS-1X
TS-1L, TS-1LX
TS-2, TS-2X
TSD-1, TSD-1X
TSD-2, TSD-2X
TS-9
TSS-1, TSS-2
TSS-1L
TSS-9
4
4
4
4
4
4
4
4
4
20.0
33.5
20.0
17.8
17.8
45.8
25.9
35.1
45.8
38.5
53.5
38.5
38.5
38.5
71.7
45.8
60.9
79.2
74.0
74.0
74.2
62.8
62.8
93.2
85.4
85.4
106.6
Sturcture and
Voltage
34.5 kV
TS-1, TS-1X
TS-1L, TS-1LX
TS-2, TS-2X
TSD-1, TSD1X,
TSD-2, TSD-2X
TS-9
TSS-1, TSS-2
TSS-1L
TSS-9
TSZ-1, TSZ-2
TH-1, TH-1G
TH-9, TH-9G
Bulletin 1724E-200
Page J-3
TABLE J-1 (Continued)
INSULATOR SWING VALUES FOR STANDARD TANGENT STRUCTURES
(Porcelain Insulators with Ball Hook and Suspension Clamp
per Drawing TM-1A. Insulator String Lengths per TABLE C-3)
Number of
Insulators
Insulator Swing
Angle In
Degrees
(no wind
clearance)
Insulator Swing
Angle In
Degrees
(moderate wind
clearance)
Insulator Swing
Angle In
Degrees
(high wind
clearance)
4
4
41.7
35.6
61.2
61.2
81.4
85.6
4
66.5
86.2
106.6
4
35.6
61.2
85.6
4
27.2
56.1
81.3
4
33.7
60.0.
84.6
7
7
26.9
28.3
54.2
58.7
80.2
80.8
7
22.1
55.5
78.1
7
22.1
55.5
78.1
138 kV
TH-10 SERIES
8
19.9
54.5
77.2
161 kV
TH-10 SERIES
10
16.4
50.5
77.7
230 kV
TH-230
TH-230
12
13
16.5
15.2
47.8
43.9
74.8
76.0
Sturcture and
Voltage
69 kV (continued)
TSZ-1, TSZ-2
TH-1, TH-1G
TH-1B,
TH-1BG
TH-1A,
TH-1AA,
TH-1AAX
TS-115
115 Kv
TS-115
TH-1A
TH-1AA,TH1AAX
TH-10 SERIES
Notes:
1. Conditions at which insulator swing no wind clearances are to be maintained follow (See Chapter 7 of this
bulletin):
• Wind: Assume no wind.
• Temperature: Assume a temperature of 60°F.
2. Conditions at which insulator swing moderate wind clearances are to be maintained follow (See Chapter 7
of this bulletin):
• Wind: Assume a wind of at least 6 psf blowing. A wind pressure values of no higher than 9 psf
(60 mph) should be used for the moderate wind clearance design
• Temperature: A temperature of no more than 32°F should be used for tangent and small angle
structures where the insulator string is suspended from a crossarm. A lower temperature value should
be used where such a temperature can be reasonably expected to occur in conjunction with the wind
value assumed.
3. Conditions at which insulator swing high wind clearances are to be maintained follow (See Chapter 7 of
this bulletin):
• Wind: The minimum assumed wind value should be at least the 10-year mean recurrence interval.
More wind may be assumed if deemed appropriate.
• Temperature: The temperature assumed should be that temperature at which the wind is expected to
occur. The conductor should be assumed to be at initial tension conditions.
Bulletin 1724E-200
Page J-4
Blank Page
Bulletin 1724E-200
Page K-1
APPENDIX K
SYMBOLS AND ABBREVIATIONS
A = Cross sectional area
ft2, in2
A = Separation between points of insulator string for two phases
ft2
A = Allowable separation at midspan
ft
AU = Designated ultimate anchor capacity
lbs
B = Vertical separation at supports
ft
C = Clearance between a supply conductor and an object or
ground. May be specified as C1 C2, C3, etc.
C = Circumference of pole. Depending on the location, the
circumference may be indicated as CA, CB CC .
in
ft, in
De = Embedment depth
ft
Dv = Vertical separation between conductors
ft
EC = Experience factor for horizontal separation requirements
E = Experience factor for horizontal separation requirements. It
is generally recommended that E be greater then 1.25.
E = Modulus of elasticity of wood
psi
EI&W = Extreme Ice and Concurrent Wind
F = Wind pressure on a cylindrical surface
Fb = Designated ultimate bending stress for either the pole or the
crossarm
Fc = Experience factor to be used in horizontal separation
requirements (Fc = 1.15 for light loading district, 1.2 for
medium loading district, and 1.25 for heavy loading
district).
Fs
= Designated ultimate skin friction of soil
G, GN = Calculated force in the guy, considering guy lead
GU = Rated breaking strength of guy.
H = Horizontal separation between the phase conductors at the
structure.
HS = Horizontal span. For any structure the HS = (L1 + L2)/2 and
is the horizontal distance between the midspan points of
adjacent spans. The horizontal span times the wind force
per foot on the conductor (pc) will yield the total horizontal
force per conductor on the structure.
HSN = For an H-frame structure, HSA, HSB, etc., are the horizontal
spans limited by pole strength at locations on the pole.
HSR = Horizontal span limited by bearing
psf
psi
psf
lbs
lbs
ft
ft
ft
ft
Bulletin 1724E-200
Page K-2
APPENDIX K
SYMBOLS AND ABBREVIATIONS
HSx = Horizontal span as limited by crossbrace strength
Of an H-frame structure
ft
I = Moment of inertia of a structural member
in4
L
ft
=
Span length or the horizontal distance from one structure to
an adjacent structure. L1, L2, L3, etc., are designations for
difference spans.
Lavg
= Average span length
ft
Lmax
= Maximum span length
ft
LF = Load Factor
LL = Loop length of conductor when vibrating
ft
M = Major axis of Lissagous ellipses
ft
Ma
= Moment capacity of crossarms
ft.-lbs
Mg
= Moment capacity of a pole at groundline
ft.-lbs
MN = Moment capacity at the indicated location.
ft-lbs
Mbh
= Moment capacity at the indicated location.
ft-lbs
Mwp
= Moment due to wind on the pole.
ft-lbs
P = Horizontal force.
PC
lbs
= Force due to wind on conductors (plus ice, if any)
lbs
Pg
= Force due to wind on OHGW (plus ice, if any)
lbs
Pt
= Force due to wind on conductors and OHGW (plus ice)
lbs
= Critical buckling load for a member in compression
lbs
Pcr
P-δ = P-delta moment, additional moment due to deflection
ft-lbs
R = Rise of a davit arm
ft
R
lbs
Rg
Total transverse load due to wind on the conductors and
OHGW and wire tension load for conductors and OHGW
Total transverse load due to wind on the OHGW (Pg) and
=
wire tension load for OHGW (Tg)
=
RS = Ruling Span
S = Section modulus of a structural member equal I/c
lbs
ft
in3
Bulletin 1724E-200
Page K-3
APPENDIX K
SYMBOLS AND ABBREVIATIONS
S = Sag of conductor
ft
Se = Soil constant
Sf
= Final Sag of a bare conductor at condition specified
ft
Si = Sag of an iced conductor
ft
Sℓ
= Sag of the lower bare conductor
ft
Siℓ
= Sag of an iced lower conductor
ft
SRS
= Sag at midspan for a span equal to the ruling span
ft
= Sag of an upper conductor
ft
Siu = Sag of an iced upper conductor
ft
SP = Diagonal distance between phase conductors at structure
ft
T =
Tc
=
Tg
=
Th
=
Resultant tension at support
lbs
Average conductor tension
lbs
Average OHGW tension
lbs
Su
Tavg
Horizontal component of tension
T
Average conductor tension in a span, (Tavg= h +T )
2
=
lbs
lbs
V = Wind velocity
miles/hr
V = Vertical separation between phase conductors at a structure
ft
VS = Vertical span, the horizontal distance between the maximum ft
sag points of two adjacent spans. The vertical span times the
weight of the loaded conductor per foot (Wc) will yield the
vertical force per conductor.
W = Weight
W =
Wc
=
Wg
=
Wp
=
lbs
Right-of-way width
ft
Weight of conductors (plus ice, if any)
lbs
Weight of OHGW (plus ice, if any)
lbs
Weight of pole
lbs
Wi = Weight of insulators
lbs
V = Wind velocity
miles/hr
V = Vertical separation between phase conductors at a structure
ft
Bulletin 1724E-200
Page K-4
APPENDIX K
SYMBOLS AND ABBREVIATIONS
a = Length as indicated
ft
a = Insulator swing clearance for normal condition
in
b = Distance between two poles for an H-frame
ft
b = Bolt hole diameter; width of a section
in
b = Insulator swing clearance for 6 psf wind condition
in
c = Insulator swing clearance for high wind condition
in
c = Distance from the neutral axis to the extreme fiber
in
dc = Diameter of conductor
in
dg = Diameter of overhead ground wire
in
dg = Diameter at the groundline of a pole
in
dn = Diameter of a pole. Depending on the location the diameter
may be indicated as da, db, dc, dd, , etc.
in
dt = Diameter at the top of a pole
in
f = Frequency of conductor vibration
Hz
fb = Computed bending stress
psi
a = Length as indicated
ft
a = Insulator swing clearance for normal condition
in
b = Distance between two poles for an H-frame
ft
b = Bolt hole diameter; width of a section
in
b = Insulator swing clearance for 6 psf wind condition
in
c = Insulator swing clearance for high wind condition
in
c = Distance from the neutral axis to the extreme fiber.
in
dc = Diameter of conductor
in
dg = Diameter of overhead ground wire
in
dg = Diameter at the groundline of a pole.
in
Bulletin 1724E-200
Page K-5
APPENDIX K
SYMBOLS AND ABBREVIATIONS
dn = Diameter of a pole. Depending on the location the diameter
may be indicated as da, db, dc, dd, , etc.
in
dt = Diameter at the top of a pole
in
f = Frequency of conductor vibration
Hz
fb = Computed bending stress
psi
fs = Computed skin friction of soil
psf
g = Acceleration due to gravity 9.81 (32.2)
ft/sec2
g = Conductor surface gradient
hn = Length, may be indicated as h1, h2, h3, or ha, hb hc, etc.
ft.
kVL-G = Line to ground voltage
kV
kVL-L = Line to line voltage
kV
ℓ = Unbraced length used in buckling calculations
ft.
ℓi = Insulator string length
in. ft.
mc = Mass per unit length of the conductor
lbm/ft.
mg = Mass for unit length of the overhead ground wire
lbs./ft.
pc = Horizontal force per unit length due to wind on the
conductors (plus ice, if any)
lbs/ft.
pg = Horizontal force per unit length due to wind on the overhead
ground wire (plus ice, if any)
lbs/ft
pt = Total horizontal force per unit length due to wind on the
conductors and overhead ground wire
lbs/ft
qa = Calculated allowable soil bearing capacity
psf
qu = Calculated ultimate soil bearing capacity.
psf
r = Radius of gyration. a property of a cross section equal to
I/A.
lbs/ft
r = Radius of conductor
in.
rc = Resultant load per unit length on conductor including ice
and wind and K factor
lbs/ft
Bulletin 1724E-200
Page K-6
APPENDIX K
SYMBOLS AND ABBREVIATIONS
s = Maximum moment arm for a crossarm
ft.
wc = Weight per unit length of the conductors (plus ice, if any)
lbs/ft.
wg = Weight per unit length of the overhead ground wire (plus
ice, if any)
lbs/ft.
xn, yn, = Length. May be indicated as x0, x1, z0, x1, etc.
zn
ft.
Bulletin 1724E-200
Page L-1
APPENDIX L
SELECTED SI-METRIC CONVERSIONS
AREA
To Convert From
circular mil (cmil)
square centimeter (cm2)
square foot (ft2)
square inch (in2)
square kilometer (km2)
square mile (mi2)
To
Multiply by
2
square meter (m )
square meter (m2)
square meter (m2)
square meter (m2)
square meter (m2)
square meter (m2)
5.067075
*1.000
*9.290304
*6.451600
*1.000
2.589988
E – 10
E – 04
E – 02
E – 04
E + 06
E + 06
FORCE
To Convert From
To
Multiply by
kilogram force (kgf)
Kip
pound force (lbf)
newton (N)
newton (N)
newton (N)
*9.806650
4.448222 E + 03
4.448222
FORCE PER LENGTH
To Convert From
To
Multiply by
kilogram force per
meter (kgf/m)
pound per foot (lb/ft)
newton per meter (N/m)
newton per meter (N/m)
*9.806650
1.459390 E + 01
DENSITY
To Convert From
pound per cubic inch
(lb/in3)
pound per cubic foot
(lb/ft3)
To
kilogram per cubic
meter (kg/m3)
kilogram per cubic
meter (kg/m3)
Multiply by
2.767990 E + 04
1.601846 E + 01
LENGTH
To Convert From
foot (ft)
inch (in)
kilometer (km)
mile (mi)
*Exact Conversion.
To
meter (m)
meter (m)
meter (m)
meter (m)
Multiply by
3.048
*2.540
*1.000
*1.609344
E – 01
E – 02
E + 03
E + 03
BULLETIN 1724E-200
Page L-2
SELECTED SI-METRIC CONVERSIONS (Continued)
LINEAR DENSITY
To Convert From
pound per foot (lb/ft)
pound per inch (lb/in)
To
kilogram per meter (kg/m)
kilogram per meter (kg/m)
Multiply by
1.488164
1.785797 E + 01
LOAD CONCENTRATION
To Convert From
pound per square
inch (lb/in2)
pound per square
foot (lb/ft2)
ton per square
foot (ton/ft2)
To
kilogram per square
meter (kg/m2)
kilogram per square
meter (kg/m2)
kilogram per square
meter (kg/m2)
Multiply by
7.03069 E + 02
4.882428
9.071847 E + 02
MASS
To Convert From
pound (avoirdupois) (lb)
To
kilogram (kg)
Multiply by
4.535924 E - 01
PRESSURE
To Convert From
kip per square inch
(kip/in2)
kip per square foot
(kip/ft2)
newton per square
meter (N/m2)
pound per square
foot (lb/ft2)
pound per square
inch (lb/in2)
To
Multiply by
pascal (Pa)
6.894757 E + 06
pascal (Pa)
4.788026 E + 04
pascal (Pa)
*1.000
pascal (Pa)
4.788026 E + 04
pascal (Pa)
6.894757 E + 03
BENDING MOMENT
To Convert From
kilogram force
meter (kgf-m)
kip-foot (kip-ft)
pound-foot (lb-ft)
*Exact Conversion.
To
Multiply by
newton meter (N-m)
newton meter (N-m)
newton meter (N-m)
*9.806650
1.355818
1.355818
Bulletin 1724E-200
Page L-3
SELECTED SI-METRIC CONVERSIONS, (Continued)
VELOCITY
To Convert From
foot per second (ft/s)
kilometer per hour (km/h)
mile per hour (mi/h or mph)
meter per hour (m/h)
To
Multiply by
meter per second (m/s)
meter per second (m/s)
meter per second (m/s)
meter per second (m/s)
*3.048
2.777778
4.470400
2.777778
E - 01
E - 01
E - 01
E - 04
VOLUME
To Convert From
3
cubic foot (ft )
cubic inch (in3)
cubic kilometer (km3)
cubic millimeter (mm3)
To
Multiply by
3
cubic meter (m )
cubic meter (m3)
cubic meter (m3)
cubic meter (m3)
2.831685
1.638706
*1.000
*1.000
E - 02.
E - 05
E + 09
E - 09
TEMPERATURE
To Convert From
Degrees
Fahrenheit
ºF
Degrees
Celsius
ºC
XºC =
9/5 X + 32
--------------
XºF =
---------------
5/9(X – 32)
BULLETIN 1724E-200
Page L-4
Blank page
Bulletin 1724E-200
Page M-1
Subject
INDEX
Page Numbers
A
AAC Aluminum conductor (1350 H-19)
AAAC (6201 conductor)
AACSR conductor
ACAR conductor
ACCC conductor
ACCR conductor
ACSR conductor
ACSR/AW conductor
ACSR/SD conductor
ACSR/TW
ACSS
AWAC conductor
Aeolian vibration
Ampacity, conductor
Anchors
logs
plate
power screw
Armor rods
Authorizations
AWAC conductor
Axial loading, for guyed structures
4-2, 9-2
4-2, 9-2, 9-6, 9-8, 9-15
9-4
9-2, 9-3
9-4, 9-5
9-4
4-2, 9-1, 9-2, 9-6, 9-8
9-2
9-3
9-4
9-4, 9-5
9-3
9-3, 9-4, 9-8, 9-13, 9-14, 9-15, 15-6
to 15-7
9-6, D-2
11-17, 11-18, 14-2, 14-9
14-9
14-9
14-9
15-1, 15-3, 15-4, 15-6, 15-7
3-5
9-3
14-2, 14-4 to 14-8
B
Backfill
Backswing
Bearing capacity
Bisector guys
Bolt hole, moment reduction due to
Buckling
Buckling, calculation of buckling loads
Building, clearance over
Building, horizontal clearance to
Bundled conductors
12-8
7-5
12-6, 12-7
14-1, 14-4, 14-7
13-4, F-20, F-21
10-13, 14-4 to 14-7, 15-12
14-5 to 14-7, 14-12
4-4, 4-6 to 4-8
5-1, 5-2, 5-3, 5-9
15-8
C
Calculation of a ruling span
Checklist, review of plan and profile
Clamp top clamps
9-11, 9-12, 9-21
10-15
15-2
Bulletin 1724E-200
Page M-2
Subject
INDEX
Clearance
at crossings
between transmission and underbuild
distribution conductors
examples of, calculations
for lines along roads in rural districts
for lines over buildings
for lines over railroads
for lines over swimming pools
for sag template
horizontal
horizontal to vegetation
insulator swing
minimum horizontal clearance of conductors to
objects
over water
radial and horizontal, to vegetation
side hill
to grain bins
to guys
to objects under line
to rail cars
to swimming pools
to tall vehicles
to vegetation
under differential ice loading
vertical, between conductors of different lines at
noncrossing situations
vertical, between conductors where one line crosses
over another
vertical, conductors to ground
vertical, conductors to ground (underbuild
distribution),
vertical clearance to underbuild
Climbing space
Communication underbuild
Conductor
AAC (1350 H-19 aluminum)
AAAC-6201
AACSR
ACAR
ACCC
ACCR
Page Numbers
10-10, 4-9 to 4-13
16-1, 16-2, 16-3, 16-4
4-9, 4-10, 4-11, 5-9, 6-5, 6-6, 7-5
4-3
4-4, 4-8
4-4, 4-5, 4-6, 4-7
4-5, 4-8, 5-3
4-4
5-1 to 5-3, Chapter 5
5-4, 5-5
Chapter 13
Chapter 5
4-4, 4-6, 4-7
5-4, 5-5
10-8, 10-13
4-8, 5-3 to 5-7
14-3, 7-4
4-6, 4-7, 4-8, Chapter 4
4-4, 4-5, 5-3
4-5, 4-6, 4-7, 4-8, 5-3
4-3
5-4, 5-5
6-6, 6-7
4-10
4-9 to 4-13
4-1, 4-2, 4-6, 4-7
16-1, 16-2
16-2, 16-3, 16-4, 16-6
16-4
16-2, 16-3
4-2, 9-2
4-2, 9-2
9-4
9-2, 9-3
9-4, 9-5
9-4
Bulletin 1724E-200
Page M-3
Subject
INDEX
ACSR
ACSR/AW
ACSR/SD (self-damping)
ACSR/TW
ACSS
ampacity tables
AWAC
bundled
corrosion considerations
design for vibration
design tensions
determination of conductor sags and tensions
economic considerations
extreme ice tension
extreme ice and concurrent wind tension
extreme wind tension
final unloaded tension
high temperature
initial unloaded tension
mechanical loading tables
minimum size
motion hardware
ruling span of
related hardware
sagging of
selection of size
selection of type
standard loaded tension
stringing of
swing angle
temperature
thermal consideration
twisted pair (T-2)
vibration
voltage drop considerations of
Considerations in establishing radial and horizontal
clearances to vegetation
Contamination, insulation
Contraflexure for H-frames
Corrosion of hardware
Corrosion considerations, conductor
Crossarm braces
Page Numbers
4-2, 9-1, 9-2, 9-6, 9-8
9-2
9-3
9-4
9-4, 9-5
9-6, D-2
9-3
15-8
9-5
9-3, 9-8, 9-10, 9-14
9-8, 9-9
9-13, 9-16, 9-17
9-1, 9-6
9-9, 9-10, 11-2
9-9, 9-10, 11-2
9-9, 9-10, 11-2
9-8, 9-10
9-4, 9-5
9-7, 9-9, 9-15
B-2 to B-9
9-6
15-1, 15-6 to 15-8
9-11 to 9-13, 9-21
15-1 to 15-8
9-19
9-6
9-5
9-9
9-18
5-8, Chapter 7, 7-3, 7-5, 7-6, 7-9
4-2, 4-9, 4-10, 5-1, 7-1, 7-2, 7-3,
9-6, 9-10, 9-13, 9-15, 11-2, 16-2
9-5
9-4
9-8, 9-10, 9-14, 9-15, 15-6, 15-7,
15-8
9-6
5-4, 5-5
8-7 to 8-10
13-13, 13-14, H-3
15-12
9-5
13-15, 13-16, 13-17
Bulletin 1724E-200
Page M-4
Subject
INDEX
Crossarm data
moment capacities
crossarm loading chart
Crossarm fittings
Crossarm, wood, designated stresses
Crossbraces
Cushioned suspension unit
Page Numbers
G-2
G-3
15-8, 15-9, 15-10, 15-17
13-3
13-15, 13-8
9-15, 15-2, 15-6
D
Dampers
Deadend clamps
Deflection, structure
Design data summary
Design data summary book, suggested outline
Design data summary form
Design data summary form, instructions for filling out
Determining conductor sags and tensions
9-15, 15-7, 15-8
15-3, 15-4
4-12, 5-1, 5-5, 5-8 to 5-12
13-4 to 13-8
2-1, Appendix A
A-10, A-11
A-3, A-4
A-5 to A-9
9-13 to 9-17
E
Easements
Electrical characteristics of insulators
Embedment depths
Embedment depths of wood poles
Embedment depths of steel/concrete poles
Environmental criteria
Establishing a ruling span
Excessive insulator swing
Extreme ice
Extreme ice with concurrent wind
Extreme ice, conductor tension
Extreme winds,
conductor tension
gust response factors for
velocity pressure exposure coefficients
3-3, 3-4, 3-5 to 3-8
8-2, 8-3
12-1, 12-2 to 12-6
12-2 to 12-4
12-5, 12-6
3-1, 3-5 to 3-8
9-11 to 9-13
7-9, 10-10, 10-11
11-2
11-2, 11-8 to 11-13
9-9, 9-10
11-2 to 11-8, 11-14
9-9, 9-10
11-3, 11-4
11-3
F
Fasteners
Fault clearing
Fault clearing and switching surges
15-8, 15-9, 15-11
4-1
4-1
Bulletin 1724E-200
Page M-5
Subject
Field survey, soil
Final unloaded conductor tension
Fittings
Footing resistance
Foundation stability
INDEX
Page Numbers
12-2
9-8, 9-10
15-5, 15-10, 15-11
8-6, 8-7
Chapter 12, 12-3 to 12-7
G
Gain plate
Galloping
Grid gains
Gust response factor
wire
structure
Guy attachments
Guy strands, strength
Guyed structures
Guys
bisector
clearance to
for steel and concrete poles
for wood poles
force in
head and back
hold-down (uplift)
in-line
rated breaking strength of
strength factors
15-10
6-7, 6-8, 6-9, 15-8
15-10
11-3, 11-4
11-4
15-11
H-4
10-14, Chapter 14, 16-5, 16-6
14-1, 14-4, 14-7
14-3, 7-4
14-6
14-6, 14-7
14-2
14-1, 14-4
10-11
14-7, 10-13
H-4
11-16 to 11-18, 14-2
H
Hardware
armor rods
bolts
clamp top clamps
conductor motion
conductor-related hardware
corrosion of
crossarm fittings
cushioned suspension units
dampers
deadend clamps
fasteners
9-15, 15-1, 15-3, 15-6, 15-7
15-8, 15-9, 15-11, 15-12, H-4
15-2
9-14, 9-15, 15-6 to 15-8
15-1 to 15-8
15-12
15-10
9-15, 15-2, 15-6
9-10, 9-15, 15-7
15-3, 15-4
15-8, 15-9
Bulletin 1724E-200
Page M-6
Subject
INDEX
fittings
gain plate
grid gains
guy attachment
reinforcing plate
spacer fitting
splices
stepbolts
strain yokes
structure-related
suspension clamps
swing angle brackets
tied supports
Head and back guys
High temperature conductors
High wind (insulator swing) clearance
Hold down guys (uplift)
Horizontal clearance recommendations
Horizontal separation
Horizontal separation recommendations
Horizontal span, definition
Horizontal span, max. as limited by structure strength
single pole structures
H-frames
Page Numbers
15-5, 15-8, 15-9, 15-11
15-10
15-10
15-11
15-10
15-10
15-4
15-12
15-4
15-8 to 15-12
15-1, 15-2, 15-6
15-10, 15-11
15-2
14-1, 14-4
9-4, 9-5
7-2, 7-3, 7-4
10-11
Chapter 5, 5-1 to 5-7
6-1
6-1, 6-2
7-7
13-4 to 13-9
13-16 to 13-27
I
IEEE 516
Ice loading
Ice loading, differential
Initial unloaded conductor tension
In-line guys
Insulation
footing resistance
high altitude considerations
recommended agency levels
tables for
Insulation contamination
Insulator greasing
Insulator washing
Insulator lengths
Insulator load limits
porcelain and non-ceramic
5-4
11-2
6-6, 6-7, 11-13
9-8, 9-10, 9-15
10-13, 14-7
Chapter 8
8-2, 8-6, 8-7
8-3, 8-4, 8-5
8-2, 8-3
C-2, C-3
8-7 to 8-10
8-10
8-10
C-4
8-11 to 8-14
Bulletin 1724E-200
Page M-7
Subject
INDEX
post, pin, suspension
Insulator orientation
Insulator swing,
charts
effect on design
excessive
formulae for
Insulator string flashover data
Insulator swing clearance
Insulator swing tables, structure
Insulator swing values
Insulator weights, suspension
Insulators,
corrosion of
electrical characteristics of
horizontal post (porcelain and non-ceramic)
horizontal post (special considerations)
lengths, suspension
load limits of
mechanical considerations of post and pin
mechanical considerations of suspension
porcelain vertical post and pin mounted on
crossarms
post
suspension
types
weights, suspension
Page Numbers
8-11 to 8-14
8-8
Chapter 7, 10-10, 10-11, 13-1, 15-8
7-6, 7-8, 7-9, 7-11 to 7-14
7-6
7-9
7-8, 7-9
8-2, 8-3, C-2, C-3
7-1 to 7-5
Appendix J, 7-6
7-5, 7-6, J-2 to J-3
C-4
15-12
8-2, 8-3
8-1, 8-3, 8-11, 8-12
8-12
C-4
8-11
8-11, 8-12, 8-13
8-11 to 8-14
8-11, 8-12, 8-13
8-1 to 8-3, 8-9, 8-12, 8-13
8-1 to 8-3, 8-9, 8-11, 8-12, 8-13
8-1
C-4
L
Licenses
Lightning
Lightning arresters
Lightning flashover mechanism
Line routing considerations
Line survey
Load factors
Loading, axial (for guyed structures)
Loads
extreme wind
combined ice and wind (NESC)
extreme ice
extreme ice with concurrent wind (50 yr)
3-5 to 3-8
8-5 to 8-7
8-7
8-5
3-1, 3-2
3-3, 3-4
Chapters 11 and 13, 14-2
14-4 to 14-9
11-2 to 11-8, 11-14
11-1, 11-2
11-2
11-2, 11-8 to 11-13
Bulletin 1724E-200
Page M-8
Subject
INDEX
ice
NESC district loads
longitudinal loads
Longitudinal loads
Longitudinal structure strength
Page Numbers
11-2
11-1, 11-2
11-13
11-13
10-13, 11-13, 11-14
M
Meteorological data
wind velocities and pressures
annual extreme winds
annual extreme ice with concurrent wind maps
thunderstorm days per year
Moderate wind (insulator swing) clearance
Moment capacities for wood poles
Moment reduction due to bolt hole
E-2
11-2 to 11-8
11-8 to 11-13
E-4
7-1 to 7-4
F-3, F-5 to F-19
F-20, F-21
N
NERC FAC 003
NESC loading districts
No wind (insulator swing) clearance
5-4, 5-5
11-1, 11-2
7-1, 7-3, 7-4
O
Offset clipping
Overhead ground wire
sags and clearances
selection of size and type
tension limits
9-19, 9-20
8-5, 8-6, 9-7 to 9-10, 10-4,
6-3, 6-7
9-8
9-9, 9-10
P
Permits
Percy Thomas formula
Photogrammetry
Plan-profile drawings,
preparation of
Pole, moment capacities
Pole classes
Pole embedment depth
Pole stability
3-5 to 3-8
6-4
3-3, 3-4
3-4, Chapter 10
10-1 to 10-4
F-5 to F-19
F-4
12-1 to 12-6
Bulletin 1724E-200
Page M-9
Subject
INDEX
direct embedded, wood
direct embedded, steel and concrete
Pole top assembly, TP and TS
Pole top assembly, wishbone
Pole top assembly, H-frame
Pole, weight
Poles, wood, designated stresses
Post insulator
Preservative treatment
Page Numbers
12-2, 12-3, 12-4
12-5 to 12-6
13-4 to 13-9
13-10
13-15 to 13-18
F-22
13-3
8-1 to 8-3, 8-11, 8-12, 8-13
13-3
R
Rail cars, clearance to
Reconnaissance and preliminary survey
Reference component and tall Vehicles/boats
Rerouting
RI and TVI
Right-of-way
calculated width
clearing
typical width
width
width for a line directly next to a road
width for two or more structures on a single
right-of-way
Roads, clearances for lines along roads in rural districts
Route selection
Route survey
Ruling span
calculation of
effects of a wrong
establishment of
4-4, 4-5, 4-6, 4-7
3-3
4-3
3-4, 3-5
I-2 to I-6
3-3, 3-5
5-8 to 5-13
3-5
5-9
5-9
5-10
5-11
4-3
3-1, 3-2, 3-3
3-3, 3-4, 10-1
9-11, 9-13, 10-5, 10-6
9-10
9-12, 9-13
9-11
S
Sag, overhead ground wire
Sag and tension relationships
Sag template,
curves
Sagging of conductors
Section properties, (structural)
Selection of conductor size
Selection of conductor type
6-7
9-16
10-4 to 10-7
10-5 to 10-7
9-19, 9-20
H-2
9-6, 9-7
9-5
Bulletin 1724E-200
Page M-10
Subject
INDEX
Self-damping conductor
Separation, horizontal
between transmission and underbuild
distribution conductors
Separation, minimum vertical
Separation between lines as dictated by minimum
clearance between conductors carried on different
lines
Separation between lines as dictated by minimum
clearance of conductors from one line to the
supporting structure of another
Shielding angle
Side hill clearance
Single pole structures, a method of structural analysis
of
Site survey
Soil,
bearing capacity
construction backfill
Soils, description of types
Spaces and ways accessible to pedestrians only
Span,
definition of
horizontal, definition
maximum, as limited by structure strength for
single pole structures
maximum, as limited by structure strength for
H-frame structures
maximum, as limited by clearance to underbuild
maximum, as limited by conductor separation
maximum, as limited by conductor separation under
differential ice loading
maximum, as limited by galloping
maximum possible
vertical
Splices
Standard loaded conductor tension
Stepbolts
Strain yokes
Strength factors
Strength of pole top assembly, H-frames
Stringing of conductors
Structure, designated stresses, wood
Structure deflection
Page Numbers
9-3
6-1, 6-2
16-1, 16-2, 16-3, 16-4
6-1 to 6-3
5-10
5-11
8-5, 8-6
10-13
13-4 to 13-8
12-1
12-7, 12-8
12-6, 12-7
12-8
12-2
4-3, 4-6, 4-7
7-7, 10-10, 10-11, 10-12
7-7
13-4 to 13-8
13-12 to 13-27
16-3, 16-4
6-1, 6-2, 6-4, 6-5
6-6, 6-7
6-7, 6-8, 6-9
9-15, 9-16
10-8, 10-10, 10-11, 10-12
15-4
9-9
15-12
15-4
11-16 to 11-18
13-15 to 13-18
9-18
13-3
5-1, 5-4, 5-8 to 5-12, 13-4 to 13-7
Bulletin 1724E-200
Page M-11
Subject
INDEX
Structure related hardware
Structure spotting
Structure strength, longitudinal
Structure uplift (H-frame)
Structures,
general design considerations for steel/concrete
general design considerations for wood
guyed
H-frames, a method of analysis of
single pole, a method of analysis of
Suspension clamps
Suspension insulators
Swimming pools, lines over
Swing angle bracket
Page Numbers
15-8 to 15-12
10-7 to 10-14
10-13, 11-13, 11-14
12-8
Chapter 13
13-2
13-3
Chapter 14, 10-13
13-13 to 13-27
13-4 to 13-12
15-1, 15-2, 15-6
8-1, 8-2, 8-11, 8-12, 8-13
4-5, 4-8
15-10, 15-11
T
T2 Conductor
Temperature, conductor
Thermal considerations, conductor
Thunderstorm days, map
Tied Supports
TVI and RI
9-4
4-2, 4-9, 4-10, 5-1, 9-6, 16-2
9-6
E-4
15-2
I-2 to I-6
U
Underbuild,
addition to existing transmission line
clearance between transmission and underbuild
distribution conductor
distribution neutrals
horizontal separation from transmission conductor
sag template curves
strength requirements
vertical clearance to ground
Uplift
V
Chapter 16
16-1
16-1, 16-2, 16-3
16-4
16-1, 16-2
4-4, 10-4 to 10-8
Chapter 11, 16-1
16-1, 16-2, 16-3
10-10 to 10-13, 12-8, 13-20, 13-21
Bulletin 1724E-200
Page M-12
Subject
INDEX
V-braces
Vegetation, clearance to
Vehicles, tall, clearance to
Velocity pressure exposure coefficient
structure
wire
Vertical separation
minimum
Vertical span,
definition
maximum vertical span limited by structure
strength for single pole structures
maximum limited vertical span limited by structure
strength for H-frames
Voltage, maximum operating
Page Numbers
13-15 to 13-18
5-4, 5-5
4-3
11-4
11-3,11-4
6-1, 6-2, 6-3, 6-4, 6-5, 16-3
6-3
10-8, 10-10
7-7, 10-10, 10-11, 10-12
13-9 to 13-12
13-15 to 13-19
4-1
W
Wind, annual extreme winds
Wind, annual extreme ice with concurrent wind
Wind, velocities and pressures
Wood, preservative treatment
Wood, designated stresses for
Wood, stress limitations
11-2 to 11-8, 11-14
11-8 to 11-13
11-3, 11-4, E-2
13-3
13-3
13-3
