BULLETIN 1724E-200 

RD-GD-2015-78

DESIGN MANUAL FOR

HIGH VOLTAGE TRANSMISSION LINES 

U.S. DEPARTMENT OF AGRICULTURE

RURAL UTILITIES SERVICE

ELECTRIC STAFF DIVISION

Disclaimer: The contents of this guidance document does not have the force and effect of law and 

is not meant to bind the public in any way. This document is intended only to provide clarity to 

the public regarding existing requirements under the law or agency policies.
Bulletin 1724E-200

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Bulletin l 724E-200 

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UNITED STATES DEPARTMENT OF AGRICULTURE 

Rural Utilities Service 

BULLETIN 1724E-200 

RD-GD-2015-78

SUBJECT: Design Manual for High Voltage Transmission Lines 

TO: All Electric Borrowers, Consulting Engineers, and Agency Electric Staff 

EFFECTIVE DATE: Date of Approval 

OFFICE OF PRIMARY INTEREST: Transmission Branch, Electric Staff Division 

FILING INSTRUCTIONS: This bulletin replaces Bulletin l 724E-200, "Design Manual for 

High Voltage Transmission Lines," dated August, 2009. 

AVAILABILITY: This bulletin can be accessed via the Internet at 

http://www.rurdev.usda.gov/RDU_Bulletins_Electric.html 

PURPOSE: This guide publication is a reference containing fundamental engineering 

guidelines and basic recommendations on structural and electrical aspects oftransmission line 

design, as well as explanations and illustrations. The many cross-references and examples 

should be of great benefit to engineers performing design work for Agency borrower 

transmission lines. The guide should be particularly helpful to relatively inexperienced 

engineers beginning their careers in transmission line design. 

CONTRIBUTORS: Current and former members ofthe Transmission Subcommittee ofthe 

Transmission and Distribution (T&D) Engineering Committee of the National Rural Electric 

Cooperative Association (NRECA). 

Current members are: 

Ballard, Dominic, East Kentucky Power Coop., Winchester, KY 

Beadle, Bob, North Carolina EMC, Raleigh, NC

Beckett, Thomas, Enercon Services, Inc., Kennasaw, GA 

Fan, Quan, Georgia Transmission Corp., Tucker, GA 

Johnson, Wilson, USDA, Rural Utilities Service, Washington, DC 

Lukkarila, Charles, Great River Energy, Maple Grove, MN 

McAndrew, Jeremy, South Mississippi Electric Power Association, Hattiesburg, MS 

Metro, Patti, National Rural Electric Cooperative Association, Arlington, VA 

Nordin, Bryan, Tri-State Generation & Transmission Association, Inc., Denver, CO 

Ruggeri, Erik, Power Engineers, Hailey, ID 

Shambrock, Aaron, South Central Power Company, Lancaster, OH 

Stokes, Gabrielle, USDA, Rural tilities Service, Washington, DC 

Twitty, John, PowerSouth Energ Cooperative, Andalusia, AL 

Christopher A. McLean 

Assistant Administrator, 

Electric Program 

\ i'_, I :J_ \

') 

Date 
Bulletin 1724E-200

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Bulletin 1724E-200

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TABLE OF CONTENTS

CHAPTER PAGE

1 GENERAL .............................................................................................................. 1-1 

2 TRANSMISSION LINE DOCUMENTATION ..................................................... 2-1 

3 TRANSMISSION LINE LOCATION, ENGINEERING SURVEY AND ............ 3-1 

RIGHT-OF-WAY ACTIVITIES

4 CLEARANCES TO GROUND, TO OBJECTS UNDER THE LINE ................... 4-1 

AND AT CROSSINGS

5 HORIZONTAL CLEARANCES FROM LINE CONDUCTORS ......................... 5-1 

TO OBJECTS AND RIGHT-OF-WAY WIDTH

6 CLEARANCES BETWEEN CONDUCTORS AND BETWEEN ........................ 6-1

CONDUCTORS AND OVERHEAD GROUND WIRES

7 INSULATOR SWING AND CLEARANCES OF CONDUCTORS ..................... 7-1 

FROM SUPPORTING STRUCTURES

8 INSULATION AND INSULATORS ..................................................................... 8-1 

9 CONDUCTORS AND OVERHEAD GROUND WIRES ..................................... 9-1 

10 PLAN AND PROFILE DRAWINGS ................................................................... 10-1 

11 LOADINGS AND LOAD FACTORS ................................................................. 11-1 

12 FOUNDATION STABILITY OF DIRECT-EMBEDDED POLES .................... 12-1 

13 STRUCTURES ..................................................................................................... 13-1 

14 GUYED STRUCTURES ...................................................................................... 14-1 

15 HARDWARE ....................................................................................................... 15-1 

16 UNDERBUILD..................................................................................................... 16-1 

APPENDIX

A TRANSMISSION LINE DESIGN DATA SUMMARY SHEET ......................... A-1 

AND SUPPORTING INFORMATION

B CONDUCTOR TABLES .......................................................................................B-1 

C INSULATION TABLES ........................................................................................C-1 

D AMPACITY, MVA, SURFACE GRADIENT TABLES ...................................... D-1 

E WEATHER DATA ................................................................................................. E-1 
Bulletin 1724E-200

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TABLE OF CONTENTS (CONT)

APPENDIX PAGE

F POLE DATA ..........................................................................................................F-1

G CROSSARM DATA.............................................................................................. G-1

H MISCELLANEOUS STRUCTURAL DATA....................................................... H-1

I RI AND TVI ............................................................................................................I-1

J INSULATOR SWING TABLES.............................................................................J-1

K SYMBOLS AND ABBREVIATIONS.................................................................. K-1

L SELECTED SI-METRIC CONVERSIONS...........................................................L-1

M INDEX ...................................................................................................................M-1

INDEX OF BULLETINS: Design, System

Transmission Facilities, Line Manual

ABBREVIATIONS

(See Appendix L for Engineering Symbols and Abbreviations)

AAAC All Aluminum Alloy Conductor

AAC All Aluminum Conductor

AACSR Aluminum Alloy Conductor Steel Reinforced

AC Alternating Current

ACCR Aluminum Conductor Composite Reinforced

ACAR Aluminum Conductor Alloy Reinforced

ACCC/TW Aluminum Conductor, Composite Core, Trapezoidal Wire

ACSR Aluminum Conductor Steel Reinforced

ACSS Steel Supported Aluminum Conductor

ACSR/AW Aluminum Conductor Steel Reinforced/Aluminum Clad Steel Reinforced

ACSR/SD Aluminum Conductor Steel Reinforced/Self Damping

ACSR/TW Aluminum Conductor Steel Reinforced/Trapezoidal Wire

ANSI American National Standards Institute

ASCE American Society of Civil Engineers

ASTM American Society for Testing and Materials

AWAC Aluminum Clad Steel, Aluminum Conductor

AWG American Wire Gauge

BIA Bureau of Indian Affairs

BLM Bureau of Land Management

CADD Computer-Aided Design and Drafting

CEQ Council on Environmental Quality

CFR Code of Federal Regulations

COE Corps of Engineers

DOE Department of Energy

DOI Department of Interior

EPA Environmental Protection Agency

EHV Extra High Voltage

EIS Environmental Impact Statement

EI&W Extreme Ice & Concurrent Wind

EPRI Electric Power Research Institute
Bulletin 1724E-200

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ABBREVIATIONS 

(continued from previous page)

(See Appendix L for Engineering Symbols and Abbreviations)

Eq. Equation

FAA Federal Aviation Agency

FEMA Federal Emergency Management Agency

FERC Federal Energy Regulatory Commission

FHA Federal Highway Administration

FLPMA Federal Land Policy and Management Act

FS Forest Service

FWS Fish and Wildlife Service

GIS Geographic Information System

GPS Global Positioning System 

IEEE Institute of Electrical and Electronics Engineers, Inc.

LF Load Factor

LWCF Land and Water Conservation Fund Act

M&E Mechanical and Electrical

MCOV Maximum Continuous Over Voltage

MOV Metal Oxide Varistor

NEPA National Environmental Protection Act

NERC National Electric Reliability Council

NESC National Electrical Safety Code

NPDES National Pollutant Discharge Elimination System

NPS National Park Service

NRCS Natural Resource Conservation Service

OHGW Overhead Ground Wire

PL Public Law

Psf Pounds per square foot

RI Radio Interference

RSL Residual Static Load

REA Rural Electrification Administration

ROW Right-of-Way

RTK-GPS Real Time Kinematic-Global Positioning System

RUS Rural Utilities Service

SHPO State Historical Preservation Officers

SML Specified Mechanical Load

SPCC Spill Prevention Control and Countermeasure

SYP Southern Yellow Pine

T2 Twisted Pair Aluminum Conductor

T&D Transmission and Distribution

TIN Triangular Irregular Network

TVI Television Interference

TW Trapezoidal Wire 

USC United States Code

USDA United States Department of Agriculture

USDI United States Department of the Interior

USGS United States Geological Survey
Bulletin 1724E-200

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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.

References in this bulletin to “NESC”, “NESC 2012”, or similar are references to the National 

Electrical Safety Code® (NESC®) (Accredited Standards Committee C2-2012).

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.
Bulletin 1724E-200

Page ix

LIST OF TABLES

Table

Number Table Name Brief Comment Page

3-1 Line Routing Considerations Routing 3-3

3-2 Summary of Potential Major Federal Permits 

or Licenses That May Be Required

Federal permits 3-8

4-1 Recommended Design Vertical Clearances 

of Conductors Above Ground, Roadways, 

Rails, or Water Surface

Vertical clearance 4-7

4-2 Recommended Design Vertical Clearances 

from Other Supporting Structures, Buildings 

and Other Installations 

Vertical clearance 4-9

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 4-13

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 wind5-2

5-2 Radial Operating Clearances (in feet) From 

IEEE 516 For Use In Determining 

Clearances To Vegetation From Conductors 

Horizontal clearancevegetation5-6

5-3 Typical Right-of-Way Widths Right-of-way 5-10

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 

swing

7-5
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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 7-7

8-1 Recommended Insulation Levels at Sea 

Level (Ceramic Suspension at Tangent and 

Small Angle Structures)

Insulation 8-2

8-2 Recommended Insulation Levels at Sea 

Level (Ceramic Posts at Tangent and Small 

Angle Structures)

Insulation 8-3

8-3 Reduced Shielding Angle Values Shield angles 8-6

8-4 Suggested Leakage Distances for

Contaminated Areas

Leakage distances 8-11

8-5 Summary of Recommended Insulator

Loading Limits

Insulator load limits 8-13

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 9-10

9-3 Recommended Conductor and

Overhead Ground Wire Tension and 

Temperature Limits

Tension and temp. 

limits

9-11

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 9-14

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 11-4

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

11-5

11-6 Recommended Load Factors and Strength 

Factors to be Applied to NESC District 

Loads 

Load factors and 

strength factors

11-19
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

11-20

12-1 Classification of Soils Based Soil description 12-3

on Field Tests

12-2 Presumptive Allowable Bearing Bearing capacity 12-8

Capacities, ksf 

12-3 Suggested Ranges of Presumptive Bearing capacity 12-8

Ultimate Bearing Capacities, psf 

13-1 Designated Stresses for Poles Wood characteristics 13-4

13-2 Designated Stresses for Crossarms Wood characteristics 13-4

13-3 Crossbrace Capacities X-brace 13-31

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 14-4

15-1 Strengths for ANSI C135.1 Machine Bolts, 

Double Arming Bolts and Double End Bolts

Bolt strengths 15-11

15-2 Strengths of ASTM A325 Heat Treated, 

High Strength Bolts

Bolt strengths 15-13

15-3 Galvanic Table of Various Metals Galvanic table 15-14

16-1 Recommended Minimum Vertical 

Clearances to Distribution or 

Communication Underbuild on 

Transmission Lines in Feet

Clearance to 

underbuild

16-4

C-1 Flashover Data for Porcelain String 

5-3/4” x 10” Standard Suspension Insulators

C-2

C-2 Flashover Data For Suspension Polymers 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
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Page xiii

LIST OF FIGURES

Figure 

Number Figure Name Brief Comment Page

4-1 Clearance Situations Covered in This 

Chapter

Vertical clearances 4-2

4-2 NESC Figure 234-5 Clearance to rail cars 4-5

4-3 Simplified Clearance Envelope Clearance to rail cars 4-6

4-4 Swimming Pool Clearances Vertical clearances for 

swimming pools

4-6

5-1 Horizontal Clearance Requirement Horizontal clearances 5-1

5-2 Radial Clearance Requirements to 

Vegetation

Clearance to vegetation 5-5

5-3 Clearance to Grain Bins, NESC

Figure 234-4a

Clearance to grain bins 5-7

5-4 Horizontal Clearance to Grain Bins, 

Conductors at Rest

Clearance to grain bins 5-7

5-5 Horizontal Clearance To Grain Bins, 

Conductors Displaced by 6 psf or Extreme 

Wind 

Clearance to grain bins 5-7

5-6 NESC Clearance to Grain Bins with 

Portable Loading Equipment

Clearance to grain bins 5-8

5-7 Simplified Recommendations for Clearances 

to Grain Bins with Portable Loading 

Equipment

Clearance to grain bins 5-8

5-8 A Top View of a Line Showing Total 

Horizontal Clearance Requirements

Horizontal clearance 5-9

5-9 ROW Width for Single Line of Structures 

(First Method)

ROW width 5-11

5-10 Clearance Between Conductors of One Line 

to Conductor of Another Line

Clearance between 

lines

5-13

5-11 Clearance Between Conductors of One Line 

and Structure of Another

Clearance between 

lines

5-13

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 6-9

6-4 Single Loop Galloping Analysis Galloping 6-10

6-5 Proper Phase Arrangements for Crossarm to 

Vertical Construction

Vertical transition of 

conductors

6-10

7-1 Illustration of Structure Insulator Swing 

Angle Limits and Conditions Under Which 

They Apply (Excludes Backswing)

Insulator swing 7-4

7-2 Forward and Backward Swing Angles Insulator swing 7-6

7-3 Typical Insulator Swing Chart for a TH-230 

Tangent Structure

Example swing chart 7-8

7-4 Horizontal and Vertical Spans Span definitions 7-9

7-5 Typical Insulator Swing Chart for a 

TH-233 Medium Angle Structure

Example swing chart 7-10

7-6 Insulator Swing Chart for Example 7-9 Example swing chart 7-13

8-1 A Standard Ceramic Suspension Bell Suspension bell 8-1

8-2 A Typical Ceramic 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 Ceramic Insulator Unit

Insulator contamination 8-9

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 9-4
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

9-8

9-6 Nomograph for Determining Level Span 

Equivalents of Non-Level Spans

Level span equivalents 9-19

9-7 Analysis for Application of Clipping Offsets Offset clipping 9-22

9-8 Line Section for Example 9-1 Example of ruling span 9-23

10-1 Sample of a Plan and Profile P&P sample 10-3

10-2 Conventional Symbols for Plan-Profile Symbols 10-4

10-3 Specimen Sag Template for Conductor Sag template 10-7

10-4 Application of Sag Template - Level Ground 

Span.

Level ground span 10-10

10-5 Check for Uplift Uplift 10-13

10-6 Sag Low Point, Vertical Spans and Uplift Vertical spans and 

uplift

10-14

10-7 Sample Check List for Review of Plan and 

Profile

Checklist 10-17

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

11-6

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

11-7

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

11-8

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

11-9
Bulletin 1724E-200

Page xvi

LIST OF FIGURES

(Continued from previous page)

Figure 

Number Figure Name Brief Comment Page

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

11-10

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

11-11

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

11-12

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

11-13

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

11-13

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

11-14

12-1 Embedment Depths in Poor Soil Embedment depths 12-4

12-2 Embedment Depths in Average Soil Embedment depths 12-5

12-3 Embedment Depths in Good Soil Embedment depths 12-5

12-4 Embedment Chart for Medium Dry Sand

Bulletin 1724e-205 “Embedment Depths for 

Concrete and Steel Poles”

Embedment depths 12-6

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 13-7

13-3.1 TP Type Structure 13-7

13-4 TS Type Structure POMS 13-10
Bulletin 1724E-200

Page xvii

LIST OF FIGURES

(Continued from previous page)

Figure 

Number Figure Name Brief Comment Page

13-4.1 TP Type Structures POMS 13-11

13-5 TS Type Structure Example 13-14

13-6 TP-69 Structure POMS Example 13-18

13-7 TSZ-1 Pole Top Assembly 13-24

13-8 TSZ-1 Example 13-25

13-9 HS vs. VS for TSZ-1 13-25

13-10 TU-1 Structure 13-26

13-10a Davit Arm 13-26

13-11 VS vs. HS for TUS-1 Structure of Ex.13-3 13-27

13-12 Assumed H-Frame Behavior H-frame behavior 13-28

13-13 Location of Point of Contraflexure Pt. of contraflexure 13-28

13-14 Crossbrace X-brace 13-30

13-15 Pole Top Bracing Arrangements Pole top for H-frames 13-31

13-16 Pole Top Assembly with Two Outside Braces Two outside braces 13-33

13-17 Pole Top Assembly with Inside Braces Inside braces 13-34

13-18 Structure 1 13-36

13-19 Structure 2 13-37

13-20 Structure 3 13-38

13-21 Structure 4 13-38

13-22 Structure 5 13-39

13-23 Structure 6 13-39

13-24 Example of an H-Frame 13-40

14-1 Deadend Structure 14-1

14-2 Comparison of Rods to Show Stability Concept Stability concept 14-6

14-3 Effective Unbraced Length for Various End 

Conditions

Unbraced lengths 14-7
Bulletin 1724E-200

Page xviii

LIST OF FIGURES

(Continued from previous page)

Figure 

Number Figure Name Brief Comment Page

14-4a,

14-4b

End Conditions for Bisector and In-Line 

Guyed Structures

End conditions for 

guyed poles

14-9

14-5 Axial Loads Induced in a Pole 14-9

14-6 Representation of Axial Loads and Double 

Accounting Loads 

14-10

14-7 Structure TS-4A 14-13

15-1 Suspension Clamp with Clevis or Ball and 

Socket Type of Connection

15-2

15-2 Post Type Insulator with Straight Line 

Trunion Clamps

15-2

15-3 Top Groove Hand Tie 15-3

15-4a Typical Bolted Deadend Clamp 15-4

15-4b Typical Compression Deadend 15-4

15-5 Suspension Insulators 15-5

15-6 Different Types of Hooks 15-6

15-7 Various Types of Ball and Clevis “Y” 

Connections

15-6

15-8 Anchor Shackle; Chain Shackle 15-6

15-9 Armor Rods Used with Suspension 

Insulators

15-7

15-10a Cushioned Suspension Unit 15-8

15-10b Double Cushioned Suspension (for Line 

Angles Greater than 30o)

15-8

15-11 Typical Suspension Damper 15-8

15-12 Spiral Vibration Damper for Small 

Conductors

15-8

15-13 Disc Weights, Ball Weights 15-10

15-14 Fasteners 15-10

15-15 Lag Screw 15-11

15-16 Grid Gains 15-11
Bulletin 1724E-200

Page xix

LIST OF FIGURES

(Continued from previous page)

Figure 

Number Figure Name Brief Comment Page

15-17 Spacer Fitting, Reinforcing Plate

and Gain Plate 

15-12

15-18 Small Angle Structure with Swing Angle 

Brackets

15-12

16-1 Horizontal Separation Requirements 

Between Transmission and Underbuild

16-2

16-2 Vertical Separation Requirements at 

Structure for Underbuild

16-2

16-3 Use of a Separate Pole to Mount a 

Distribution Transformer

16-6

16-4 Guying Distribution Underbuild 16-6

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
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Bulletin 1724E-200

Page 1-1

1 GENERAL

a 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.

b 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” or “RUS”) 

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. 

c National Electrical Safety Code (NESC): This bulletin is based on the 

requirements of the National Electrical Safety Code® (NESC®) (Accredited 

Standards Committee C2-2012). 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) by dialing 1-800-699-9277 or at the following website:

http://standards.ieee.org/about/nesc/

d 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.

e 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 U.S. Government 

Printing Office, P.O. Box 979050, St. Louis, MO, 63197-9000, or viewed online 

at http://www.gpo.gov.

Agency environmental regulations may be found on the following website:

http://www.rd.usda.gov/publications/regulations-guidelines/regulations/electric.
Bulletin 1724E-200

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Bulletin 1724E-200

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2 TRANSMISSION LINE DOCUMENTATION

a Purpose: The purpose of this chapter is to provide information regarding design 

documentation for transmission lines financed by the Rural Utilities Service.

b General: Policy and procedures pertaining to construction of transmission lines 

by agency electric borrowers are codified in 7 CFR Part 1724, “Electric 

Engineering, Architectural Services and Design Policies and Procedures” and 

7 CFR Part 1726, "Electric System Construction Policies and Procedures" 

(http://www.rd.usda.gov/publications/regulations-guidelines/ ). The requirements 

of 7 CFR Part 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.

c 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’ (RUS Form 265), 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. 

d Computer-Aided Design: This bulletin contains requirements for transmission 

line design by agency electric borrowers. It is recognized that there are computer- aided design programs available that can be utilized to accomplish many of the 

procedures and calculations described in this bulletin. Computer-aided design 

programs that adhere to RUS and NESC design requirements, and are performed 

by competent engineering personnel, are acceptable. Design data summaries and 

other documentation required to be submitted by this bulletin remain the same.
Bulletin 1724E-200

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Bulletin 1724E-200

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3 TRANSMISSION LINE LOCATION, ENGINEERING SURVEY AND RIGHT-OF 

WAY ACTIVITIES

a 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 can contribute 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 
Bulletin 1724E-200

Page 3-2

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.

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.
Bulletin 1724E-200

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TABLE 3-1

LINE ROUTING CONSIDERATIONS

Physical Sources • Highways USGS, state & county highway department maps

• Streams, rivers, lakes USGS, Army Corps of Engineers, flood insurance maps

• Railroads USGS, railroad

• Airstrips USGS, Federal Aviation Administration (FAA)

• Topography (major ridge lines, 

 floodplains, etc.)

USGS, flood insurance maps (FEMA), Army Corps of 

Engineers

• Transmission lines & distribution lines USGS, local utility system maps

• Pipelines,(water, gas, sewer),

 underground Electric

USGS, local utility system maps

• Occupied buildings Local tax maps, land use maps, local GIS maps

Biological Sources • Woodlands USGS, USDA - Forest Service,

• Wetlands USGS, Army Corps of Engineers, USDA National Conservation 

Resource Service, USDI Fish and Wildlife Service

• Waterfowl, wildlife refuge areas,

 endangered species & critical

 Habitat Areas

USDI - Fish and Wildlife Service, State Fish and Game Office

Human Environmental Sources

• Rangeland

USGS aerial survey, satellite mapping, county planning 

agencies, state planning agencies, state soil conservation 

service, mining bureau, U.S. Bureau of Land Management, 

NRCS

• Cropland

• Urban development

• Industrial development

• Mining areas

• Recreation or aesthetic areas,

 national parks, state and local parks

• Prime or unique farmland USGS, soil surveys, USDA - NRCS, state department of 

agriculture, county extension agent

• Irrigation (existing & potential) Irrigation district maps, applications for electrical service, aerial 

survey, state departments of agriculture and natural 

resources, water management districts

• Historic and archeological sites National Register of Historic Sites (existing), state historic 

preservation officer , state historic and archeological 

societies

• Wild and scenic rivers USGS maps, state maps, state department of natural resources, 

Department of Interior

Other Sources • Federal, state and county controlled

 lands

USGS, state maps, USDI Park Service, Bureau of Land 

Management, state department of natural resources, county 

maps, etc.
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b 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 such as the 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 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.

c 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 and 

inside the right-of-way. Costly details, misuse of survey time and effort, and 

misunderstanding on the part of the landowners should be avoided.

d 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 
Bulletin 1724E-200

Page 3-5

map the route of the line. Based on this survey, plan and 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 scheduling and costs should be taken in 

to consideration. Also, there may be some areas where trees and other vegetation 

could conceal relevant ground features. 

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 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.

e 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 
Bulletin 1724E-200

Page 3-6

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 have

been secured by the borrower should be returned to the engineer. 

f 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 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.

g 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.

h Permits, Easements, Licenses, Franchises, and Authorizations: The following is a 

list of permits, easements, licenses, franchises, and authorizations that commonly 

need to be obtained and is not meant to be exhaustive.

Private property Easement from owner and permission 

to cut danger trees

Railroad Permit or agreement

Highway Permit from state/county/city

Other public bodies Authorization

City, county or state Permit

Joint and common use pole Permit or agreement

Wire crossing 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 Bureau of Indian Affairs

BLM Bureau of Land Management

CEQ Council on Environmental Quality

CFR Code of Federal Regulations

COE Corps of Engineers

DOE Department of Energy

EIS Environmental Impact Statement

EPA Environmental Protection Agency

FAA Federal Aviation Agency
Bulletin 1724E-200

Page 3-7

FERC Federal Energy Regulatory Commission

FHA Federal Highway Administration

FLPMA Federal Land Policy and Management Act

FS Forest Service

FWS Fish and Wildlife Service

LWCF Land and Water Conservation Fund Act

NEPA National Environmental Protection Act

NPDES National Pollutant Discharge Elimination System

NPS National Park Service

PL Public Law

SHPO State Historical Preservation Officer

SPCC Spill Prevention Control and Countermeasure

USC 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

Action Requiring 

Permit, Approval, 

or Review

Agency

Permit, License, 

Compliance or 

Review

Relevant Laws and 

Regulations

NEPA (National 

Environmental 

Protection Act) 

Compliance

Federal; Action to 

grant right-of-way 

across land under 

Federal jurisdiction 

Lead Agency – EIS and Record of 

Decision

NEPA (42 USC 4321), 

CEQ (40 CFR 1500-1508). 

DOE NEPA implementing 

Regulations (10 CFR to 

1021)

Right-of-Way 

Across Land 

Under Federal 

Management

Preconstruction 

surveys; construction, 

operation, 

maintenance, and 

abandonment

Bureau of Land 

Management (BLM)

Right-of-way grant and 

special use permit

Federal Land Policy and 

Management Act (FLPMA) 

of 1976 (PL 94-579) 

43 USC 1761-1771

43 CFR 2800

Bureau of Indian 

Affairs (BIA), tribe

Right-of-way grant 

across American 

Indian lands

25 CFR 169

Forest Service (FS) Special use 

authorization permit or 

easement

36 CFR 251

National Park 

Service (NPS)

Authorization to cross 

National Park Service 

lands

18 USC, 36 CFR 14

Fish and Wildlife 

Service (FWS)

Special use permit for 

crossing a national 

wildlife refuge

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

Biological 

Resources

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 Migratory Bird Treaty Act 

of 1918

16 USC 703-712

50 CFR Ch 1

Protection of bald and 

golden eagles

FWS Compliance Bald and Golden Eagle 

Protection Act of 1972

(16 USC 668)

Paleontological 

Resources

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 3-9

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

Action Requiring 

Permit, Approval, 

or Review

Agency

Permit, License, 

Compliance or

Review

Relevant Laws and 

Regulations

Ground 

Disturbance 

and Water 

Quality 

Degradation

Construction sites with 

greater than five acres 

of land disturbance

Environmental 

Protection Agency

(EPA)

Section 402 National 

Pollutant Discharge 

Elimination System 

(NPDES) General 

Permit for Storm Water 

Discharges from 

Construction Activities

Clean Water Act

(33 USC 1342)

Construction across 

water resources

Army Corps of 

Engineers (COE)

General easement 10 USC 2668 to 2669

Crossing 100-year 

floodplain, streams, 

and rivers

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 agenciesReview 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)

Air Traffic 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

FAA Act of 1958

(49 USC 1501)

(14 CFR 77)

Section 1101 Air 

Space Permit for air 

space construction 

clearance

FAA Act of 1958

(49 USC 1501)

(14 CFR 77)
Bulletin 1724E-200

Page 3-10

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

Action Requiring 

Permit, Approval, 

or Review

Agency

Permit, License, 

Compliance or 

Review

Relevant Laws and 

Regulations

Cultural 

Resources

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 agencyPermits 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 agencyConsultation 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 agenciesPermit for study of 

historical, 

archaeological, and 

paleontological 

resources

Antiquities Act of 1906

(16 USC 432-433)

Investigation of cultural 

resources

Affected landmanaging agenciesPermits to excavate 

and remove 

archaeological 

resources on Federal 

lands; American Indian 

tribes with interests in 

resources must be 

consulted prior to 

issuance of permits

Archaeological Resources 

Protection Act of 1979 

(16 USC 470aa to 470ee)

(43 CFR 7)

Protection of 

segments, sites, and 

features related to 

national trails

Affected landmanaging agenciesNational Trails 

Systems Act 

compliance

National Trails System Act 

(PL 90-543)

(16 USC 1241 to 1249)

Rate regulation Sales for resale and 

transmission services

Federal Energy 

Regulatory 

Commission (FERC)

Federal Power Act 

compliance by power 

seller

Federal Power Act 

(16 USC 792)

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. 
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4 CLEARANCES TO GROUND, TO OBJECTS UNDER THE LINE AND AT 

CROSSINGS

a 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 2012 edition of the NESC. If the 2012 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 2012 NESC. 

b Assumptions

(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.

(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 2012 edition of the NESC for guidance.

Nominal Line-to-Line

Voltage 

(kV)

Maximum Line-to Line

Operating 

Voltage 

(kV)

34.5 *

46 *

69 72.5

115 121

138 145

161 169

230 242

*Maximum operating voltage has no effect on clearance requirements for these 

nominal voltages.
Bulletin 1724E-200

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FIGURE 4-1: CLEARANCE SITUATIONS COVERED IN THIS CHAPTER

c Design Vertical Clearance of Conductors. The recommended design vertical 

clearances under various conditions are provided in Table 4-1.

(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 

Table 4-2

 Table 4-2

Table 4-1

Table 4-3 Table 4-3
Bulletin 1724E-200

Page 4-3

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

(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.

(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 pedestrians-only 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) 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.

(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. 

 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 4-4

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. For reference 

components to Table 4-2, see Appendix A, Table A-2b of the NESC.

Item Description Reference height

1.0 Track rails 22.0

2.0 Streets, alleys, roads, driveways, and 

parking lots

14.0

3.0 Spaces and ways--pedestrians only 10.0

4.0 Other lands traversed by vehicles 14.0

5.0 Water areas--no sail boating 12.5

6.0 Water areas—sail boating

 Less than 20 acres 16.0

 20 to 200 acres 24.0

 200 to 2000 acres 30.0

 Over 2000 acres 36.0

7.0 Areas posted for rigging or launching 

sailboats 

See NESC Table 

From IEEE C2-2012, National Electric Safety Code® (NESC®), Copyright IEEE 2012. All rights reserved.

(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.

(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 
Bulletin 1724E-200

Page 4-5

than the one foot allowed, appropriate additional clearance should be 

provided.

d 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.

(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.c.(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.

(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.

(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):

FIGURE 4-2: NESC FIGURE 234-5

From IEEE C2-2012, National Electric Safety Code® (NESC®), Copyright IEEE 2012. All rights reserved.

10'-8"

V

3'

V

22'

20'

CLEARANCE 

REQUIRED BY 

RULE 232

10'-8"

 

V

3'

V

22'

20'

CLEARANCE 

REQUIRED BY 

RULE 232

10'-8"

V

3'

V

22'

20'

CLEARANCE 

REQUIRED BY 

RULE 232

10'-8"

Item 9.0

Table 5-1

V

3'

V

22'

20'

CLEARANCE 

REQUIRED BY 

RULE 232

V=(item 1.0, Table 4-1) - 20 ft.
Bulletin 1724E-200

Page 4-6

To simplify the design process, Figure 4-3, which defines the 

recommended clearances, may be used:

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) 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 C2-2012, National Electric Safety Code® (NESC®), Copyright IEEE 2012. All rights reserved.

A

B

A A

RADIUS A

POINT " C " is the vertical 

clearance over adjacent 

land.

C C

B

10'-8"

Item 9.0

Table 5-1

3'

Item 1.0

Table 4-1
Bulletin 1724E-200

Page 4-7

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 

& 46

69 115 138 161 230

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, industrial and commercial

 areas (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 20.5 23.2 23.7 24.6 25.1 25.5 26.9

 20 to 200 acres 28.5 31.2 31.7 32.6 33.1 33.5 34.9

 200 to 2000 acres 34.5 37.2 37.7 38.6 39.1 39.5 40.9

 Over 2000 acres 40.5 43.2 43.7 44.6 45.1 45.5 46.9

8.0 Public or private land and water areas

 posted for rigging or launching sailboats

 (Note E)

 Less than 20 acres 25.5 28.2 28.7 29.6 30.1 30.5 31.9

 20 to 200 acres 33.5 36.2 36.7 37.6 38.1 38.5 39.9

 200 to 2000 acres 39.5 42.2 42.7 43.6 44.1 44.5 45.9

 Over 2000 acres 45.5 48.2 48.7 49.6 50.1 50.5 51.9

ALTITUDE CORRECTION TO BE ADDED TO VALUES ABOVE:

Additional feet of clearance per 1000 feet of 

altitude above 3300 feet

.00 .02 .05 .07 .08 .12
Bulletin 1724E-200

Page 4-8

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.c of this bulletin.
Bulletin 1724E-200

Page 4-9

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) 34.5 

& 46

69 115 138 161 230

(E)

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 D) 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, ramps, and loading

 docks 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, flagpoles, banners, 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

8.0 Clearance in any direction from swimming pool 

 edge and diving platform base 

 (Clearance A, Figure 4-4)

25.0 27.2 27.7 28.6 29.1 29.5 30.9

 Clearance in any direction from diving structures

 (Clearance B, Figure 4-4)

17.0 19.2 19.7 20.6 21.1 21.5 22.9

ALTITUDE CORRECTION TO BE ADDED TO VALUES ABOVE

Additional feet of clearance per 1000 feet of altitude 

above 3300 feet

.00 .02 .05 .07 .08 .12

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, a supporting structure of another line, 

or intermediate poles in skip span construction.

(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 reference 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 4-10

(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)

e 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.

(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.
Bulletin 1724E-200

Page 4-11

(c) Maximum conductor temperature, no wind. See paragraph 4.c.(1). 

The same maximum temperature used for vertical clearance to 

ground should be used.

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.

(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.

(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) Examples of Clearance Calculations. The following example 

demonstrates the derivation of the vertical clearance of a category in Table 

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)

f 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.e 

should be attained.

g 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.

(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 4-12

(2) Assuming the line meets the assumptions given in section 4.b 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.

h 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.e.(1).(b) 

or 4.e.(1).(c) above, and the lower conductor is at 60°F initial sag.

i 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.b.(2) of this bulletin.
Bulletin 1724E-200

Page 4-13

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)

Nominal Voltage, Phase to Phase kV L-L 34.5 

& 46

69 115 138 161 230

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 H)

(kVLG) Clearances in feet

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 2.0 139.4 11.3

161 kV 2.0 97.6 8.5 9.9

138 kV 2.0 83.7 7.6 8.1 9.5

115 kV 2.0 69.7 6.7 7.1 7.6 9.0

69 kV 2.0 41.8 4.8 5.6 6.2 6.7 8.1

46 kV and below 2.0 26.4 3.8 4.3 5.2 5.7 6.2 7.6

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 4-14

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 for

correction factor upper conductors 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 4-15

Blank Page
Bulletin 1724E-200

Page 5-1

5 HORIZONTAL CLEARANCES FROM LINE CONDUCTORS TO OBJECTS AND

RIGHT-OF-WAY WIDTH

a General. The preliminary comments and assumptions in Chapter 4 of this bulletin 

also apply to this chapter.

b 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 5-1 are recommended design values. In order 

to provide an additional margin of safety, the recommended design values exceed 

the minimum clearances in the 2012 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. 

(1) Conditions Under Which Horizontal Clearances to Other Supporting 

Structures, Buildings and Other Installations Apply:

(a) 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., 1⁄4 in., or 1⁄2 in.). 

(b) 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.

FIGURE 5-1: HORIZONTAL CLEARANCE REQUIREMENT TO BUILDINGS

where:

φ = conductor swing out angle in degrees under 6 psf. of wind

Sf = conductor final sag at 60°F with 6 psf. of wind

x = horizontal clearance required per Tables 5-1 for conductors displaced by 6 psf wind 

(include altitude correction if necessary)

li = insulator string length (li = 0 for post insulators or restrained suspension insulators).

y = total horizontal distance from insulator suspension point (conductor attachment point 

for post insulators) to structure with conductors at rest

δ = structure deflection with a 6 psf. Wind

δ

y

x

∅

S

f

l

i
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

69 115 138 161 230

Max. Operating Voltage, Phase to Phase, kVL-L ---- 72.5 120.8 144.9 169.1 241.5

Max. Operating Voltage, Phase to Ground, kVL-G ---- 41.8 69.7 83.7 97.6 139.4

Horizontal Clearances - (Notes 1,2,3)

NESC

Basic 

Clear

Clearances in feet 

1.0 From a lighting support, traffic signal support

or supporting structure of another line

 At rest (NESC Rule 234B1a) 5.0 6.5 6.5 7.2 7.6 8.1 9.5

 Displaced by wind (NESC Rule 234B1b) 4.5 6.2 6.7 7.6 8.1 8.5 9.9

2.0 From buildings, walls, projections, guarded

windows, windows not designed to open,

balconies, and areas accessible to pedestrians

 At rest (NESC Rule 234C1a) 7.5 9.2 9.7 10.6 11.1 11.5 12.9

 Displaced by wind (NESC Rule 234C1b) 4.5 6.2 6.7 7.6 8.1 8.5 9.9

3.0 From signs, chimneys, billboards, radio, & TV

antennas, tanks & other installations not 

classified as buildings

 At rest (NESC Rule 234C1a) 7.5 9.2 9.7 10.6 11.1 11.5 12.9

 Displaced by wind (NESC Rule 234C1b) 4.5 6.2 6.7 7.6 8.1 8.5 9.9

4.0 From portions of bridges which are readily

accessible and supporting structures are not 

attached

 At rest (NESC Rule 234D1a) 7.5 9.2 9.7 10.6 11.1 11.5 12.9

 Displaced by wind (NESC Rule 234D1b) 4.5 6.2 6.7 7.6 8.1 8.5 9.9

5.0 From portions of bridges which are ordinarily

inaccessible and supporting structures are not

attached

 At rest (NESC Rule 234D1a) 6.5 8.2 8.7 9.6 10.1 10.5 11.9

 Displaced by wind (NESC Rule 234D1b) 4.5 6.2 6.7 7.6 8.1 8.5 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 34.5 

& 46

69 115 138 161 230

Max. Operating Voltage, Phase to Phase, kVL-L ---- 72.5 120.8 144.9 169.1 241.5

Max. Operating Voltage, Phase to Ground, kVL-G ---- 41.8 69.7 83.7 97.6 139.4

Horizontal Clearances - (Notes 1,2,3)

NESC

Basic 

Clear

Clearances in feet

6.0 Swimming pools – see section 4.d.(4) of 

Chapter 4 and item 8 of Table 4–2.

(NESC Rule 234E)

Clearance in any direction from swimming

pool edge (Clearance A, Figure 4-4 of this bulletin)

25.0 27.2 27.7 28.6 29.1 29.5 30.9

Clearance in any direction from diving 

structures (Clearance B, Figure 4-4 of this bulletin)

17.0 19.2 19.7 20.6 21.1 21.5 22.9

7.0 From grain bins loaded with permanently

attached conveyor

At rest (NESC Rule 234F1b) 15.0 17.2 17.7 18.6 19.1 19.5 20.9

Displaced by wind (NESC Rule 234C1b) 4.5 6.7 7.2 8.1 8.6 9.0 10.4

8.0 From grain bins loaded with a portable conveyor. 

Height ‘B’ 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 14.1 14.1 15.1 15.6 16.0 17.5

ALTITUDE CORRECTION TO BE ADDED TO VALUES ABOVE

Additional feet of clearance per 1000 feet of altitude above 

3300 feet

.02 .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. “B” is the height of the highest filling or probing port on a grain bin. Horizontal clearance is for the highest voltage of 

230 kV.

Ht = (24+B) + 1.5B

(See Note 3 and Fig. 5-7)
Bulletin 1724E-200

Page 5-4

(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 

minimum, 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, phaseto-ground distances, with appropriate altitude correction factors applied.

Where transmission system transient overvoltage factors are known, 

clearances shall be derived from Table 7, IEEE 516-2003, 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.
Bulletin 1724E-200

Page 5-5

yv

Ø

Sf

xv

i

FIGURE 5-2: RADIAL CLEARANCE REQUIREMENT TO VEGETATION

where:

φ = conductor swing out angle in degrees under all rated operating 

conditions

Sf = conductor final sag at all rated operating conditions

xv = radial clearance (include altitude correction if necessary)

li = insulator string length (li = 0 for post insulators or restrained 

suspension insulators).

y = horizontal clearance at the time of vegetation management work

δ = structure deflection at all rated operating conditions
Bulletin 1724E-200

Page 5-6

TABLE 5-2

RADIAL OPERATING CLEARANCES (in feet) FROM IEEE 516 FOR USE IN 

DETERMINING CLEARANCES TO VEGETATION FROM CONDUCTORS 

(NERC Standard FAC-003.2 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 34.5 & 

461

691 1151 1381 1611 2301,2

Max. Operating Voltage, Phase to Phase, kVL-L ---- 72.5 120.8 144.9 169.1 241.5

Max. Operating Voltage, Phase to Ground, kVL-G ---- 41.8 69.7 83.7 97.6 139.4

Radial Table 5 IEEE Standard 516 Operating 

Clearances

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 

3300 feet

.02 .02 .05 .07 .08 .12

Notes:

 1. 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).

2. The 230 kV clearance is based on 3.0 Per Unit switching surge.

3. 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 5-7

Ports

Probe

H

2V

Grain Bin

P

V1

T

Elevator

Permanent 

V1

H

V

Grain Bin

2

P

V1 P

V1

T

V

T

H

V2

P

H

V1 V1

Probe

Ports

Grain Bin

1

P

Permanent 

Elevator

Grain Bin

V1

P

2V

T

V

T

H

V2

P

H

V1 V1

Probe

Ports

Grain Bin

1

P

Permanent 

Elevator

Grain Bin

V1

P

2V

T

(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 5-3.

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

From IEEE C2-2012, National Electric Safety Code® (NESC®), Copyright IEEE 2012. 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:

FIGURE 5-4: HORIZONTAL 

CLEARANCE TO GRAIN

BINS, CONDUCTORS AT REST

P = clearance from item 7, Table 4-2

FIGURE 5-5: HORIZONTAL 

CLEARANCE TO GRAIN BINS,

CONDUCTORS DISPLACED 

BY 6 PSF WIND

Ports

Probe

Grain Bin

Elevator

Permanent 

Grain Bin

Grain Bin

Permanent 

Elevator

Grain Bin

Ports

Probe

No overhead lines

No Overhead Lines

Item 7.0

Table 5-1

P P
Bulletin 1724E-200

Page 5-8

The clearance envelope for portable loading equipment from NESC Figure 

234(b), is shown in Figure 5-6.

FIGURE 5-6: NESC CLEARANCE TO GRAIN BINS

WITH PORTABLE LOADING EQUIPMENT

From IEEE C2-2012, National Electric Safety Code® (NESC®), Copyright IEEE 2012. All rights reserved.

In order to simplify the clearance envelope, the horizontal clearances in category 

8 of Table 5-1 are shown as ‘H’ in the drawing below: 

FIGURE 5-7: SIMPLIFIED RECOMMENDATIONS FOR CLEARANCES 

TO GRAIN BINS WITH PORTABLE LOADING EQUIPMENT

 Total Horizontal Clearance = Ht = (24’ + B) + 1.5B

 Horizontal clearance is for highest voltage of 230kV

B
Bulletin 1724E-200

Page 5-9

(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.

(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 = (i + S f )sinφ + x + δ Eq. 5-1

Symbols are defined in Section 5.b.(1) and figure 5-1. The factor "δ" 

indicates that structure deflection should be taken into account. For post 

insulators, li = 0.

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.

( )( )















 = −

c

c

w

d F

12

tan 1 φ Eq. 5-2

where:

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 5-2.

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

 

Conductor 

position with no 

wind blowing.

Conductor in blown 

out position.

y

x

Top view of line
Bulletin 1724E-200

Page 5-10

(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 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

NESC Horizontal Clear. = 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)

c Right-of-Way (ROW) Width: For transmission lines, a right-of-way provides an 

environment which 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 5-3. 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

ROW Width, ft.

Nominal Line-to-Line Voltage in kV

69 115 138 161 230

75-100 100 100-150 100-150 125-200

d 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 5-11

FIGURE 5-9: ROW WIDTH FOR SINGLE LINE OF STRUCTURES 

W = A + 2(l

i +S f)sinφ + 2δ + 2x

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.b.(1) and Table 5-1 

and appropriate clearance derived from Section 5.b.(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 rightof-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. 

e 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, 

W

A y

x

Ø

i

S

f
Bulletin 1724E-200

Page 5-12

the borrower would generally be expected to pay for moving the line. If the rightof-way is on private land, the highway department should pay. Considerations 

involved in placing a line on a road right-of-way should also include evaluation of 

local ordinances and requirements.

f 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.d). The distance between the two lines is 

governed by the two criteria provided in section 5.f.1. If one of the lines involved 

is an EHV line (345 kV and above), the National Electrical Safety Code should be 

referred to for additional applicable clearance rules not covered in this bulletin.

(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’. 

 ( ) 1 1 2 C = 6.5 + δ − δ (NESC Rule 233B1) Eq. 5-5

[( ) ] ( ) 2 1 2 22 1 2 12

.4 C = 6.5 + kVLG + kVLG − + δ − δ (NESC Rule 233B1) Eq. 5-6

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
Bulletin 1724E-200 

Page 5-13

C3

δ

1 δ2

FIGURE 5-10: CLEARANCE BETWEEN CONDUCTORS OF ONE LINE

TO CONDUCTOR OF ANOTHER LINE

(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. 

( ) ( ) 3 22 21 12

4. C '6 kVLG −+−+= δδ Eq. 5-7

. 

Additional 1.5 feet have been added to the NESC clearance and included 

in equation 5-7 to obtain the design clearance ‘C3’.

FIGURE 5-11: CLEARANCE BETWEEN CONDUCTORS OF ONE LINE

AND STRUCTURE OF ANOTHER

C1 2 ,C

δ

1 δ2

where:

kV = the maximum line-to-ground voltage in kV

another in feet

Other symbols are defined in Figure 5-1.
Bulletin 1724E-200

Page 5-14

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.f.(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.

(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.

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.

(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 5-15

BLANK PAGE
Bulletin 1724E-200

Page 6-1

6 CLEARANCES BETWEEN CONDUCTORS AND BETWEEN CONDUCTORS AND 

OVERHEAD GROUND WIRES

a General. The preliminary comments and assumptions of Chapter 4, section 4.b, 

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.

b 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.

(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.b.(2), 6.b.(3), and 6.b.(4) of 

this section should be met.

FIGURE 6-1: EXAMPLE OF VERTICAL AND HORIZONTAL

SEPARATION VALUES

(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.

( ) ( ) max H = 0.025 kV + Fc S f + i sinφ Eq. 6-1

H

V
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-to- ground 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

i  = length of the insulator string in feet, 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 RUS STANDARD STRUCTURE

(For separations less than those shown, see Sections 6.b.(2), 6.b.(3), and 6.b.(4) to calculate 

horizontal separation) (See Notes E & F)

Nominal voltage, Line-to-Line Voltage in kV 34.5 & 

46

69 115 138 161 230

Max. Operating Voltage, Phase to Phase, kV ---- 72.5 120.8 144.9 169.1 241.5

Max. Operating Voltage, Phase to Ground, kV ---- 41.8 69.7 83.7 97.6 139.4

Vertical Separation Separation in feet

Minimum Vertical Separation at Support

1. Phases of the same circuit (Note A) 3.2 4.0 5.6 6.4 7.2 9.6

(Based on NESC Table 235-5)

2. Phases of different circuits (Notes B & D) 5.4 6.3 8.2 9.1 10.1 12.8

(Based on NESC Table 235-5,footnote 7 

criteria for different utilities)

3. Phase conductors and overhead ground

wires (Based on NESC 235C and 233C3)

2.5 2.9 3.9 4.3 4.8 6.4

Minimum Vertical Separation in Span

4. Phases of the same circuit (Notes A & G) 2.5* 3.3 4.9 5.7 6.5 9.0

(Based on NESC Table 235-5 and NESC 

235C2b(1)), H ≥ 1.0 ft., Figure 6-4

5. Phases of different circuits (Notes C, D & G) 4.2 5.2 7.0 7.9 8.9 11.7

(Based on NESC Table 235-5, footnote

7 criteria for different utilities NESC Rule 

235C2b.), H ≥ 1.0 ft., 

Figure 6-4 

6. Phase conductors and overhead ground

 wires (H ≥ 1.0 ft., Figure 6-4), Notes D & G

1.9** 2.2** 3.2 3.7 4.1 5.6

ALTITUDE CORRECTION TO BE ADDED TO VALUES ABOVE 

Clearance values in table above shall be increased 3% for each 1,000 ft. in excess of 3,300 ft. above 

mean sea level.

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 (kV kV ) (NoteD) LG LG 12

6 8.7

12

.4

12

40 = + 1 + 2 − + Eq. 6-2

where:

kVLG1 = Line to ground voltage circuit one, kilovolts.

kVLG2 = Line to ground voltage circuit two, kilovolts.

*75% of corresponding value in Line 1.

**75% of corresponding values in Line 3.
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. 

V (kV kV ) (NoteD) LG LG 12

6 50

12

.4 (50 8.7) 12.4

12

40 .75 + 1 + 2 − + 



 



 = + − Eq. 6-2a

(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.c of this bulletin.

(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.

( ) ( )( )( )

2 .025 i

c

c c p

w

E d S

H kV  = + + Eq. 6-3

where:

dc = conductor diameter in inches

wc = weight of conductor in lb/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 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.

(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 span, given the horizontal separation 
Bulletin 1724E-200

Page 6-5

at the structure and the sag and length of the ruling span. See Chapter 9 

for a discussion of ruling span.

( ) ( ) 













 − − =

c RS

i

F S

H kV L RS max

max

.025  sinφ Eq. 6-4

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.

(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:

( ) u

v

S S

D B L RS −− =



max Eq. 6-5

where:

Lmax = maximum allowable span in feet

Dv = required vertical separation at mid-span in feet

B = vertical separation at supports in feet

Sl = sag of lower conductor in feet without ice

Su = sag of upper conductor wire in feet with ice

RS = ruling span in feet

(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

Lower conductor at 32° F, 

final sag, no ice.

 

 

H

v D

In the span, phases of different circuits:

NESC Vertical Separation ( 50) 12

.4 (50 8.7) 12

.4

12

40 0.75 + 1 + 2 − 



 



 = + − LG LG kV kV

 = 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)

c Maximum Span as Limited by Conductor Separation Under Differential Ice 

Loading Conditions.

(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.c.(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.

(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. 

FIGURE 6-2: MINIMUM DISTANCE BETWEEN CONDUCTORS

Upper conductor at 32oF, final sag,

ice for medium or heavy loading district.
Bulletin 1724E-200

Page 6-7

(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).

d 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.

e Maximum Span as Limited by Galloping.

(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.
Bulletin 1724E-200

Page 6-8

(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 6-9

FIGURE 6-3: GUIDE FOR PREPARATION OF LISSAJOUS ELLIPSES















 = −

c

c

w

1 p φ tan Eq. 6-6

Single Loop Double Loop

Major Axis M = 1.25 Si + 1.0 Eq. 6-7

8

2

3

8 3

1.0

2

















+ −

= +

a

L

S

a L

M

i

Eq. 6-8

where 

2

2

2

Si

L

a  + 

 



 =

Distance ‘B’ B = 0.25 Si Eq. 6-9 B = 0.2M Eq. 6-10

Minor Axis D = 0.4M Eq. 6-11 D = 2 M −1.0 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 fee.

D = minor axis of Lissajous ellipses in feet

B,Ø = as defined in figure above

Ø

i

Si M

B

D

POINT OF CONDUCTOR 

ATTACHMENT

POINT OF SUSPENSION 

INSULATOR SUPPORT

Ø+ Ø

2
Bulletin 1724E-200

Page 6-10

FIGURE 6-4: SINGLE LOOP GALLOPING ANALYSIS

f 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.

FIGURE 6-5: PROPER PHASE ARRANGEMENTS FOR CROSSARM 

TO VERTICAL CONSTRUCTION

1

2

3 3

2

1

1 2

3

1

3

2
Bulletin 1724E-200

Page 6-11

Blank Page
Bulletin 1724E-200

Page 7-1

7 INSULATOR SWING AND CLEARANCES OF CONDUCTORS FROM 

SUPPORTING STRUCTURES

a 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 

or opposite direction. The algebraic sum of the two forces determines 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.

b 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.

(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).

(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 
Bulletin 1724E-200

Page 7-2

withstand most of the severe voltage stress situations for wind conditions 

that are not expected to occur often. 

Refer to Table 7-1 for minimum clearances from conductor to structure 

and guys, and for additional clearance required at altitudes above 3,300 

feet.

Conditions at which moderate wind clearances are to be maintained 

follow:

- 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 Rule 235.B.2 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.

(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 up to a 

60 Hz flashover. 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.
Bulletin 1724E-200

Page 7-3

- 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 7-4

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

Conditions* at which 

clearances are to be 

maintained

• Line angle Force due 

to line angle (if any)

Force due 

to line angle (if any)

Force due 

to line angle (if any)

• Wind force 0 6 psf minimum 10 year mean wind, 

recommended value

• Temperature 60oF 32oF or lower Temp. at which wind 

value is expected

• Conductor tension Final tension Initial tension Final tension

MEDIUM AND 

LARGE ANGLE 

STRUCTURES

Conditions* at which 

clearances are to be 

maintained

• Line angle Force due 

to line angle 

Force due 

to line angle 

Force due 

to line angle 

• Wind force 0 6 psf minimum 10 year mean wind, 

min. recommended

value

• Temperature 60oF 60oF or lower Temp. at which wind 

value is expected

• Conductor tension Final tension Final tension Final tension

a = No wind clearance b = Moderate wind clearance c = High wind clearance

*See text for full explanation of conditions.

a

O1

O2

b

wind

O3

c

wind

a

Ø1

b Ø2

wind

c

wind

Ø3
Bulletin 1724E-200

Page 7-5

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

Max. Operating Voltage, Phase to 

Phase, kV

34.5 46 72.5 120.8 144.9 169.1 241.5

Max. Operating Voltage, Phase to 

Ground, kV

19.9 26.6 41.8 69.7 83.7 97.6 139.4

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

Moderate Wind Clearance

 (NESC Table 235-6)

Min. clear. to structure at 6 psf of 

 wind in inches. Notes C, D 9 11 16 26 30 35 50

Min. clear. to jointly used structures

 and a 6 psf of wind in inches.

 Notes C, D

11 13 18 28 32 37 52

Min. clearance to anchor guys at 6 psf

 in inches Notes C, D 13 16 22 34 40 46 64

High Wind Clearance

 (Not NESC)

Min. clearance to structure or guy at 

 high wind in inches

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 

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. For non-ceramic suspension insulators, 

the no wind clearance should be, at minimum, the length of the insulator plus 2”. 

(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 34.5 46 69 115 138 161 230

 Clearance to structure 0 0 .14 .43 .57 .72 1.15

 Clearance to anchor guy 0 0 .17 .54 .72 .90 1.44
Bulletin 1724E-200

Page 7-6

(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 Basic Clearance(Table 235-6) + .25(kVL-L – 50)

= 16 inches + .25(120.8-50) inches

= 16 inches + 17.7 inches

NESC Clear. in any direction.= 33.7 inches ( clearance in Table 7-1is 34 inches)

c 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. 

FIGURE 7-2: FORWARD AND BACKWARD SWING ANGLES

d 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 

forward

swing

back 

swing

direction of line angle

normal position of 

insulators (no wind, 

no ice)
Bulletin 1724E-200

Page 7-7

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.

TABLE 7-2

INSULATOR SWING ANGLE VALUES IN DEGREES

(For insulator string with ball hooks)

Structure and 

Voltage

Number of 

Insulators

No Wind

Swing Angle

Moderate Wind

Swing Angle

High Wind

Swing Angle

69 kV

 TS-1, TS-1X 4 21.3 41.4 74.9 TSZ-1, TSZ-2 4 41.7 61.2 82.6 TH-1,TH-1G 4 35.6 61.2 85.6

115 kV – TH-1A 7 28.3 58.7 80.8

161 kV – TH-10 10 16.4 53.2 77.7

230 kV – TH-230 12 16.5 47.5 74.8

e 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 7-5 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.
Bulletin 1724E-200

Page 7-8

FIGURE 7-3: TYPICAL INSULATOR SWING CHART FOR A TH-230 TANGENT

STRUCTURE (Moderate Wind Swing Condition Only, 9 psf assumed instead of minimum 

NESC 6 psf, No Line Angle Assumed)

600 700

VERTICAL SPAN

800

800 900 1000

700

600

500

400

HORIZONTAL SPAN

32° INITIAL CURVE

INSULATIOR SWING ALLOWABLE

INSULATIOR SWING EXCESSIVE

INSULATOR SWING CHART

TH-230 STRUCTURE

9# WIND13 INSULATORS/STRING
Bulletin 1724E-200

Page 7-9

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

L

1/2L 1/2L

VS VS

VS

L

1 2

1 2

1 2

#1

#2

#3

HS
Bulletin 1724E-200 

Page 7-10

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. 

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)

f 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. 

( )( )( ) ( )( )

( )( ) ( )( ) c i

c

VS w W

T HS p

2/1

2 sin θ 2

tan

+

+ φ = Eq. 7-1

( )( )

12

Fd

p c

c = Eq. 7-2

VERTICAL SPAN

HORIZONTAL SPAN

INSULATOR SWING CHART

TH-233 STRUCTURE

9# WIND

16 INSULATORS/STRING

500 600 700 800 900 1000

600

500

400

300

200

100

10°

13° (120° CURVE)

11°

12°

14°

15°

16°

17°

18°

SWING

EXCESSIVE

ALLOWABLE

SWING

 LINE ANGLE
Bulletin 1724E-200

Page 7-11

Ø = angle with the vertical through which the insulator string swings, in 

degrees

θ = line angle, in degrees

T = conductor tension, pounds

HS = horizontal span, feet

VS = vertical span, feet

pc = wind load per unit length of bare conductor in pounds per foot

wc = weight per unit length of bare conductor in pounds per foot

Wi = weight of insulator string (wind pressure neglected), in pounds. (See 

Appendix C for insulator string weights).

dc = conductor diameter in inches

F = wind force in lbs/ft

2

In order for equation 7-1 to be used properly, the following sign conventions are to be followed:

Condition Sign Assumed

• Wind - Blowing insulator toward structure +

• “(2)(T)(sin θ/2)” term (force on insulator due 

to line angle):

 Pulling insulator toward structure +

 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 -

g 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.

( )( )( ) ( )( )

( )( ) ( )( ) c

i

c

c

w

W

w

T HS p VS

tan 2

2 sin θ 2 − + = 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.

h Excessive Angles of Insulator Swing. If upon spotting a line, calculations show a 

structure will have excessive insulator swing, one or more of the measures 

outlined in Section 10.d of Chapter 10 of this bulletin may be required to alleviate 

the problem.
Bulletin 1724E-200

Page 7-12

i 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.

(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

(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 calculation tables and the swing 

chart in Figure 7-6 are created.

j 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.

(1) Same Information as 7 i (1):

(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.
Bulletin 1724E

-200

Page 7-13

 

HORIZONTAL SPAN IN FEET

TH-10 161kV 800' Ruling Span795 Kcmil 26/7 ACSR6244 lbs. Tension At 0° Initial, 6 psf Wind

4633 lbs. Tension At 60° Final, No Wind

0 400 800 1200

0

800

400

1000

600

200

200 600 1000 1400

60°F Final

No Wind Insulator

Swing Limit

60°F Final

1° Line Angle

0° Line Angle

2° Line Angle

Moderate Wind

Insulator SwingLimit

0°F Initial

High Wind Condition Does Not Control

Unacceptable

Acceptable

VERTICAL SPAN IN FEET

FIGURE 7-6: INSULATOR SWING CHART FOR EXAMPLE 7-9
Bulletin 1724E-200

Page 7-14

FIGURE 7-6 INSULATOR SWING CHART FOR EXAMPLE 7-9 (continued) 

( )( )( ) ( )( )

( )( ) ( )( ) c

i

c

c

w

W

w

T HS p VS

tan 2

2 sin θ 2 − + = φ

Note: for the no wind case, vertical span is independent 

of horizontal span. It is only dependent upon line angle.

Θ 1° 2° Ø = angle with the vertical through which insulator 

string swings.

sin θ/2 .00872 .01745

a) (2)(T)(sin θ/2) 80.26 161.71 θ = line angle

b) (HS)(pc) 0 0 T = conductor tension

a + b 80.26 161.71 HS = horizontal span

c) (wc)(tan Ø) .32 .32 VS = vertical span

d) (a + b)/c 251.13 502.25 pc = wind load on conductors

e) 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 Structure: TH-10________ Ruling span 800___ft.

sin θ/2 Conductor: 795 26/7 ACSR Loading district: Heavy

a) (2)(T)(sin θ/2) Voltage: 161 kV_______ No of Insulators: 10___

b) (HS)(pc) Insulator Swing Condition: No wind____________

a + b (F=0 lbs at 60°F)

c) (wc)(tan Ø) Ø = 16.4°_______

d) (a + b)/c pc = 0 lbs./ft____ Conductor dia: 1.108 __

e) Wi/(2)(wc) wc= 1.0940 lbs./ft pc = (d)(F)

d – e = VS T= 4,633 lbs___ 12

Wi= 135 lbs

Ø = 16.4°
Bulletin 1724E-200

Page 7-15

FIGURE 7-6: INSULATOR SWING CHART FOR EXAMPLE 7-9 (continued) 

( )( )( ) ( )( )

( )( ) ( )( ) c

i

c

c

w

W

w

T HS p VS

tan 2

2 sin θ 2 − + = φ

θ = 0° HS=200 HS=400 HS=800 HS=1000 Ø = angle with the vertical through which 

insulator string swings.

sin θ/2 0 0 0 0

a) (2)(T)(sin θ/2) 0 0 0 0 θ = line angle

b) (HS)(pc) 110.80 221.60 443.20 554.00 T = conductor tension

a + b 110.80 221.60 443.20 554.00 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

θ = 1° HS=200 HS=400 HS=800 HS=1000

sin θ/2 .008727 .008727 .008727 .008727

a) (2)(T)(sin θ/2) 1.08.98 108.98 108.98 108.98

b) (HS)(pc) 110.80 221.60 443.20 554.00

a + b 219.78 330.58 552.18 662.98

c) (wc)(tan Ø) 1.460 1.460 1.460 1.460

d) (a + b)/c 150.29 226.05 377.59 453.35

e) Wi/(2)(wc) 61.70 61.70 61.70 61.70

d – e = VS 88.59 164.35 315.89 391.65

θ = 2° HS=200 HS=400 HS=800 HS=1000 Structure: TH-10________ Ruling span 800___ft.

sin θ/2 .017452 .017452 .017452 .017452 Conductor: 795 26/7 ACSR Loading district: Heavy

a) (2)(T)(sin θ/2) 217.95 217.95 217.95 217.95 Voltage: 161 kV_______ No of Insulators: 10___

b) (HS)(pc) 110.80 221.60 443.20 554.00 Insulator Swing Condition: Moderate wind______

a + b 328.75 439.55 661.15 771.95 (F=6 psf at 0°F)

c) (wc)(tan Ø) 1.460 1.460 1.460 1.460 Ø = 53.2°_______

d) (a + b)/c 224.80 300.57 452.10 527.87 pc = 0.554 lbs./ft____ Conductor dia: 1.108__

e) Wi/(2)(wc) 61.70 61.70 61.70 61.70 wc= 1.0940 lbs./ft pc = (d)(F)

d – e = VS 163.10 238.87 390.40 466.17 T= 6,244 lbs___ 12

Wi= 135 lbs

Ø = 53.2°
Bulletin 1724E-200

Page 7-16

FIGURE 7-6: INSULATOR SWING CHART FOR EXAMPLE 7-9 (continued) 

( )( )( ) ( )( )

( )( ) ( )( )c

i

c

c

w

W

w

T HS p VS

tan 2

2 sin  ̧ 2 − + = φ

θ = 0° HS=200 HS=400 HS=800 HS=1000 Ø = angle with the vertical through which 

insulator string swings.

sin θ/2 0 0 0 0

a) (2)(T)(sin θ/2) 0 0 0 0 θ = line angle

b) (HS)(pc) 230.80 461.60 923.20 1154.00 T = conductor tension

a + b 230.80 461.60 923.20 1154.00 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° HS=200 HS=400 HS=800 HS=1000

sin θ/2 .008727 .008727 .008727 .008727

a) (2)(T)(sin θ/2) 181.51 181.51 181.51 181.51

b) (HS)(pc) 230.80 461.60 923.20 1154.00

a + b 412.31 643.11 1104.71 1335.51

c) (wc)(tan Ø) 5.02 5.02 5.02 5.02

d) (a + b)/c 82.17 128.17 220.17 266.17

e) Wi/(2)(wc) 61.70 61.70 61.70 61.70

d – e = VS 20.47 66.47 158.47 204.47

θ = 2° HS=200 HS=400 HS=800 HS=1000 Structure: TH-10________ Ruling span 800___ft.

sin θ/2 .017452 .017452 .017452 .017452 Conductor: 795 26/7 ACSR Loading district: Heavy

a) (2)(T)(sin θ/2) 363.01 363.01 363.01 363.01 Voltage: 161 kV_______ No of Insulators: 10___

b) (HS)(pc) 230.80 461.60 923.01 1154.00 Insulator Swing Condition: High wind__________

a + b 593.81 824.61 1286.21 1517.01 (F=12.5 psf at 32°F)

c) (wc)(tan Ø) 5.02 5.02 5.02 5.02 Ø = 77.7°_______

d) (a + b)/c 118.35 164.35 256.34 302.34 pc = 1.154 lbs./ft____ Conductor dia: 1.108__

e) Wi/(2)(wc) 61.70 61.70 61.70 61.70 wc= 1.0940 lbs./ft pc = (d)(F)

d – e = VS 56.65 102.65 194.64 240.64 T= 10,400 lbs___ 12

Wi= 135 lbs

Ø = 77.7°
Bulletin 1724E-200

Page 7-17

BLANK PAGE
Bulletin 1724E-200

Page 8-1

8 INSULATION AND INSULATORS

a 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 

ceramic, toughened glass, fiberglass rods and sheds of non-ceramic or silicone 

construction.

The main types of insulators used on transmission lines are suspension insulators 

using bells or non-ceramic strings, pin insulators, and vertical and horizontal 

posts. Several suspension bell units are connected in a string to achieve the 

insulation level desired. The non-ceramic suspension is one unit with an 

insulation level determined largely by its length. Horizontal post units are made 

of ceramic or non-ceramic material and are single units with a desired rating. See 

Figures 8-1 and 8-2.

FIGURE 8-1: A STANDARD CERAMIC SUSPENSION BELL

FIGURE 8-2: A TYPICAL CERAMIC HORIZONTAL POST INSULATOR 

b Insulator Materials. 

(1) Ceramic insulators have been the industry standard as specified by 

ANSI requirements for electrical and mechanical capacities. Although 

ceramic insulators have a history of long, useful lives, the strings are 

heavy and subject to breakage from gunshots. The connecting portions of 

ceramic insulators are metal components which are embedded in high

strength cement as specified by ANSI standards. Strength ratings for 

ceramic insulators are verified by proof loading requirements of each 

manufactured unit, and stamped accordingly.

(2) Toughened glass insulators are similar in construction to the ceramic 

insulator. They are heavy, and are also subject to vandalism exposure. 

ANSI fabrication standards are also available for toughened glass. 
Bulletin 1724E-200

Page 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. 

Non-ceramic assemblies offer varieties of end fittings, lengths and 

strength capacities. They are much lighter in weight than their ceramic and 

glass counterparts. Non-ceramics 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.

c 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.

(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.

(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 INSULATION LEVELSAT SEA LEVEL

(CERAMIC 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

Impulse

Positive Negative

Total Leakage

Distance

inches

34.5 3 215 130 355 340 34.5

46 3 215 130 355 340 34.5

69 4 270 170 440 415 46

115 7 435 295 695 670 80.5

138 8 485 335 780 760 92

161 10 590 415 945 930 115

230 12 690 490 1105 1105 138

*See NESC Rule 273, Table 273-1 for minimum insulation level requirements

(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.
Bulletin 1724E-200

Page 8-3

Curve is a plot of the equation:

F= (17.93B)/(460 + T)

Where T = 60° F and

B is standard atmospheric pressure 

at various altitudes in inches of Hg.

d Insulation Levels Using Post Insulators. Agency recommended electrical 

characteristics for horizontal post insulators are given in Table 8-2.

TABLE 8-2

RECOMMENDED INSULATION LEVELS AT SEA LEVEL

(CERAMIC POSTS AT TANGENT AND SMALL ANGLE STRUCTURES)

Flashover Characteristics in kV

Design 

Type

ANSI 

C29.7 

Class

60 Hz

Dry 

Flashover

60 Hz 

Wet 

Flashover

Positive 

Critical 

Flashover

Negative 

Critical 

Flashover

Leakage 

Distance

Length 

(inches)

34.5 57-32 100 70 160 260 22 14

46 57-33 125 95 200 344 29 16.5

69 57-36 180 150 300 425 53 25

115 - 380 330 610 760 100 48

138 - 430 390 690 870 110 54

Note: Negative Critical Flashover not specified in ANSI C29.7

e 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. Insulation levels for non-ceramic 

insulators shall generally meet or exceed recommended insulation levels for 

ceramic insulators.

f High Altitude Considerations.

(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)
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).

(2) Example of Insulation Needed at Altitudes less than 3,300 feet. A line is 

located at 3,000 feet elevation. The derating factor (from Figure 8-3) is 

0.92. At 115 kV, using the sea-level requirement for low frequency dry 

flashover of 435 kV from Table 8-1, the line would require 473 kV 

(435/0.92) at 3,000 feet. An 8 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).

(3) Example of Insulation Needed at Altitudes Greater than 3,300 feet. When 

the insulation derating factor for the line altitude is at a value less than 

approximately 0.9 (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. A line is located at 8,000 feet elevation. The derating factor (from 

Figure 8-3) is 0.77. At 115kV, using the sea-level requirement for low 

frequency dry flashover of 435kV from Table 8-1, take 90% of 435kV 

which equals 392kV. The line would require 509kV (392/0.77) at 8,000 

feet. A 9 bell string should be used instead of 7 bells.

(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. If the majority of the line is located at an elevation less than 

3,300 feet, then apply the procedure given in paragraph 8.f.(2) to the 

weighted average altitude. If the majority of the line is above 3,300 feet, 

use the procedure in paragraph 8.f.(3).

(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 either paragraph 8.f.(2) or 8.f.(3) 

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 derating factor for the line, or a section of the line, is less 

than 90% of the derating factor at the minimum altitude. The 

insulation for this portion of the line should be calculated using the 

procedure given in paragraph 8.f.(3). 

(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.
Bulletin 1724E-200

Page 8-5

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:

 5430 + 7580 Average altitude = 2 = 6505 ft.

From Figure 8-3 the derating factor for an average altitude of 6505 ft is 

0.81. Since the entire line is above 3,300 feet, use the procedure in 

paragraph 8.f.(3). 

The insulation value should be brought up to approximately 90 percent of 

the sea level value, which for 161 kV is:

 (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.

g Lightning Considerations.

(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.h. Of the remaining two causes of flashovers, 

lightning is the more severe for lines of 230 kV and below.

(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° 
Bulletin 1724E-200

Page 8-6

Pole 

ground

wires

Shield

angle

Cross

connection

Overhead

ground wire

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 30

99 26

116 21

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.

FIGURE 8-4: SHIELDING ANGLE, POLE AND OVERHEAD GROUND WIRES
Bulletin 1724E-200

Page 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.

(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) “AC Transmission Line reference Book – 200kV and Above,” Palo 

Alto, Calif., Electric Power Research Institute, Third Edition.

(b) “1243-1997 – IEEE Guide for Improving the Lightning 

Performance of Transmission Lines,” IEEE Power and 

Engineering Society, 1997, Reaffirmed 2008.

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.

(5) Lightning Arresters. In areas where structure grounding is difficult to 

achieve, or the lightning performance of an existing transmission line 
Bulletin 1724E-200

Page 8-8

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.

h 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.

(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 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.
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Page 8-9

FIGURE 8-5: CONTAMINATION BREAKDOWN PROCESS OF A SINGLE CERAMIC 

INSULATOR UNIT

(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 

MOISTURE LAYER

FORMS ON

CONDUCTING

MATERIAL

(A)

INITIAL CONDUCTING STATE

(B)

LEAKAGE CURRENT DRIES OUT

MOISTURE NEAR PIN

(C)

ARC BRIDGES OVER DRY AREA

HEATING AND ENLARGING IT

(D)

ENLARGED DRY AREA HOLDS ENTIRE 

UNIT VOLTAGE AND ARC EXTINGUISHES

ARC RESTRIKES AS MORE MOISTURE

APPEARS ON DRY AREA

(E)

ARC BRIDGES ENTIRE 

INSULATOR

(F)

DRY AREA

DRY AREA

CONTAMINATION 

LAYER

ARC

ARC
Bulletin 1724E-200

Page 8-10

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.

(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 Disadvantages

• No extra leakage distance required. • Higher initial costs.

• Longer intervals between insulator 

washings.

• Small but continuous power loss.

• No radio noise (due to a more uniform 

voltage distribution across string).

• Not entirely successful in very heavily 

contaminated areas.
Bulletin 1724E-200

Page 8-11

TABLE 8-4

SUGGESTED LEAKAGE DISTANCES FOR CONTAMINATED AREAS

Contaminate

Level Environment

Equivalent Amount

NaCl

mg/cm2

Suggested Leakage

Distance rms L-G*

in/kV

Very Light 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.

0-.03 NA-1.0

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.

.03-.06 1.0-1.25

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).

.06-.1 1.5-1.75

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.

.1-.25 2.0-2.5

*rms L-G is root mean square line to ground voltage

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 8-12

i Mechanical Considerations (Ceramic and Non-ceramic)

(1) Suspension Insulators. Strength rating methods and nomenclature vary 

depending on the insulator material.

For ceramic, 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 non-ceramic 

insulator’s failure rating. These procedures are similar to the M&E for 

ceramic, but no electrical test is applied.

ANSI C 29.2 defines standard mechanical ratings for ceramic 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 

ceramic 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 extreme 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 ceramic and 50 percent of the M&E 

strength for non-ceramics.

Generally, ceramic 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.
Bulletin 1724E-200

Page 8-13

TABLE 8-5

SUMMARY OF RECOMMENDED INSULATOR LOADING LIMITS

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, 

non-ceramic suspension insulators may be pulled towards the structure 

because of their light weight.

(2) Horizontal Post Insulators (Ceramic 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 ceramic 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 

ceramic 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 

Insulator Type NESC District Loading Extreme Loading

Suspension

Ceramic 40% M&E 65% M&E

Non-Ceramic 40% SML 50% SML

Horizontal Post

Ceramic 40% Cantilever

50% Tension, Compression

65% Cantilever

65% Tension, Compression

Non-Ceramic 40% SCL

50% STL

50% SCL

50% STL

Vertical Post

Ceramic 750 lbs

Non-Ceramic Industry standard does not currently exist, use mfr specs

Vertical Pin

Ceramic 500 lbs --

Non-Ceramic Industry standard does not currently exist, use mfr specs
Bulletin 1724E-200

Page 8-14

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 non-ceramic 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: Ceramic 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 ceramic 

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 from 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.

(3) Ceramic 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 

district loading and the resultant of conductor tension on line angles. 

These limits 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.

(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.

(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 

an ultimate cantilever strength of 2,800 lbs. The conductor to be used is 

477 kcmil 26/7 ACSR. Determine the maximum vertical span under:
Bulletin 1724E-200

Page 8-15

(a) Heavy loading district conditions; and 

(b) 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.

(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) = load

M&E rating = load/(0.4) 

M&E rating = 10000 lbs./(0.4) = 25000 lbs.

Under extreme ice conditions the insulator can be loaded to 50 percent of 

its M&E rating. Therefore:

(M&E rating)(.65) = load

M&E rating = load/(0.65)

M&E rating = 16,000 lbs./(0.65) = 24,615 lbs.

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 8-16

Blank Page
Bulletin 1724E-200

Page 9-1

9 CONDUCTORS AND OVERHEAD GROUND WIRES

a 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

b Types of Conductors. Of the currently available types of conductors, some are 

used much more extensively than others. Sections 9.b.(1) through 9.b.(11) 

provide descriptions of many of the conductor types.

(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 concentrically-stranded 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.

FIGURE 9-1: TYPICAL ACSR STRANDINGS

6 AL/1 St 18 AL/1 S 36 AL/1 S

12 AL/7 St 26 AL/7 St 45AL/7 St 54AL/7 St

54 AL/19 St 84 AL/19 St
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.

(2) ACSR/AW (Aluminum Conductor, Aluminum-Clad Steel Reinforced). ACSR/AW conductor is similar to conventional ACSR except the core 

wires are high strength aluminum-clad 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.

(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.

FIGURE 9-2: 1350 ALUMINUM CONDUCTOR STRANDINGS

(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.

7 STRAND 19 STRAND 37 STRAND

37 STRAND 91 STRAND
Bulletin 1724E-200

Page 9-3

(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.

FIGURE 9-3: TYPICAL ACAR STRANDINGS

(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.

(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:

3/4 12/7 30/7 54/7

48/13 24/13 18/19 42/19 72/19

33/28 63/28 24/37 54/37
Bulletin 1724E-200

Page 9-4

• 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

(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) 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.

(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.

(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 
Bulletin 1724E-200

Page 9-5

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 

precautions 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.

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, 
Bulletin 1724E-200

Page 9-6

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.

c Selecting a Conductor Type.

(1) Agency Standards. The conductor selected should generally be of a type 

and stranding listed as being acceptable for use on 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”.

(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..

(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.

(4) Strength. The strength of the conductor and its ability to sustain 

mechanical loads without unreasonable sags must be evaluated.

d Selection of Conductor Size. 

(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. 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 1/0 123.3 kcmil

46 2/0 155.4 kcmil

69 3/0 195.7 kcmil

115 266.8 kcmil 312.8 kcmil

138 336.4 kcmil 394.5 kcmil

161 397.5 kcmil 465.4 kcmil

230 795 kcmil 927.2 kcmil
Bulletin 1724E-200

Page 9-7

(2) Voltage Drop Considerations. Not only should the conductor be 

sufficiently large to meet the requirements of paragraph 9.d.(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 62-5, “Electrical Characteristics of REA Alternating Current 

Transmission Line Designs.”

(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 B of this bulletin for ampacity tables.

(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.

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.

(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. 
Bulletin 1724E-200

Page 9-8

FIGURE 9-5: RESULTS OF A TYPICAL ECONOMICAL CONDUCTOR

ANALYSIS – 230 kV, 795 vs. 954 vs. 1272 kcmil ACSR

e Overhead Ground Wires (OHGW).

(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.

(2) Aluminum-Clad Steel Strand. A thick cladding of aluminum makes 

aluminum-clad 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.”

(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.

Accumulated 

present worth

cost in dollars

x 10,000 per mile

20

18

16

14

12

10

100

Assumed Load in MW

140 180 220 260

954

795

1272
Bulletin 1724E-200

Page 9-9

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.

f Conductor and Overhead Ground Wire Design Tensions. 

(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.

(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.i.(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.

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:
Bulletin 1724E-200

Page 9-10

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 11-2 

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).

(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.

(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 9-11

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

Warm Islands (Altitudes Sea Level-9,000 ft) 50o F

Warm Islands (Altitudes over 9,000ft) 15o F

• Tension limits for condition 4 are to be met at the temperature at 60° F.

• Tension limits for condition 5 & 6 are to be met at 15o F.

Tension Condition

(See section 9.d.(2) for explanation)

Tension Limits 

(percentage of rated breaking strength)

Conductor

OHGW High 

Strength Steel

OHGW Extra 

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.i 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 9-12 

g Ruling Span. 

(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. 

(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 avg 3/2 max −+= LLL avg 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:

n

n

LLLL

LLLL RS

++

++ + . . . +

=

321

3 3

3

3

2

3

1 Eq. 9-2

+ . . . +
Bulletin 1724E-200

Page 9-13

where:

L1, L2, L3, etc. = the different span length in the line 

segment, in feet

Other symbols are as previously defined.

(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.
Bulletin 1724E-200

Page 9-14

(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.

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)

Assumed RS

is greater than

Actual RS

Assumed RS 

is less than

Actual RS

Conductor temperature is 

less than temperature at 

which the conductor was 

strung

Actual sag is less than 

predicted--

INCREASED

TENSIONS

Actual sag is greater than

predicted--

CLEARANCE

PROBLEMS

Conductor temperature is 

greater than temperature at 

which the conductor was 

strung

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

h Determining Conductor Sags and Tensions. Determination of conductor sags and 

tensions, given a set of tension limits as outlined in section 9.f, 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.
Bulletin 1724E-200

Page 9-15

• 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.

i Aeolian Vibration.

(1) General. Overhead conductors of transmission lines are subject to aeolian 

vibration and galloping, both of which are produced by wind. Galloping is 

discussed in section 6.e. 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:

dC

V f = 3.26 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):

( )( )















 =

c

avg

w

T g

f

LL

2

1 Eq. 9-4
Bulletin 1724E-200

Page 9-16

where:

 LL = loop length in feet

TAVG = average conductor tension in pounds wC = unit weight of conductor in pounds per foot g = universal gravitational constant, 32.2 ft/sec

2

Other symbols are as previously defined.

(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.

(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 
Bulletin 1724E-200

Page 9-17

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.

j Galloping. See Chapter 6 for details.

k 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:

wc

T Lmax = 1.33 Eq. 9-5

where:

wc weight of conductor in pounds per foot

T ltant tension at support, pounds

Lmax imum span, feet

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.

l Sag and Tension Relationships. The relationships in paragraphs 9.l.(1) through 

9.l.(3) are useful for understanding the sag-tension relationships for conductors:

(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.

h

c

T

w L S

8

2

= 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:















 = −1

2

cosh

h

c

c

h

T

w L

w

T S Eq. 9-7

(2) Inclined Span Sags. See Figure 9-6 for method of determining inclined 

span sags.
Bulletin 1724E-200

Page 9-18

(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:

h

c

h c h T

w L

T T w S T

2 = + = cosh 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:

2 2

w S TT T

T c

h

h

avg = +

+ = Eq. 9-9

where:

Tavg = average tension in pounds
Bulletin 1724E-200

Page 9-19

FIGURE 9-6: NOMOGRAPH FOR DETERMINING LEVEL SPAN 

 EQUIVALENTS OF NON-LEVEL SPANS

From IEEE Standard 524-2003, “IEEE Guide to the Installation of Overhead Transmission Line 

Conductors,” copyright 2004 IEEE. All rights reserved.

EXAMPLE

Assume span with L=1000', B=100'

If deadend span, 

correction = 10' (see above)

If suspension span,

correction = 25' (see above)

Equivalent span = 1000' + correction.

Read chart sag for equiv. span length.

L

C

B

100

200

300

1500

2000

2500

3000

3500

4000

1000

900

800

700

600

500

400

30

20

25

35

45

40

50

60

70

80

90

100

*For spans between a 

suspension and deadend

tower, use suspension

span correction.

150

200

250

300

350

400

500

HORIZONTAL SPACING OF 

SUPPORTS (L.)

VERTICAL SPACING OF SUPPORTS 

(B.)

SAG

2

3

4

5

10

15

20

25

30

40

50

60

80

100

150

200

250

300

2.5

5

7.5

10

12.5

15

20

25

37.5

50

62.5

75

EQUIVALENT SPAN CORRECTION

(Add to horizontal spacing to obtain 

equivalent span length)

S

Formula for equivalent span length:

Equiv. deadend span = 2C-A

Equiv. suspension span = √AC

*For spans between a 

suspension and deadend 

tower, use suspension span 

Example: Assume span with A=1000 ft,

B = 100 ft. if deadend span correction = 10 ft 

(see above). If suspension span, correction =2.5 

ft (see above). Equivalent span = 1000 ft + 

correction . Read chart sag for equivalent span 

length.

Sag is based on parabolic functions. If sag 

exceeds 5 % of span, do not use this chart.
Bulletin 1724E-200

Page 9-20

m Stringing Conductors.

(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.

(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.

(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 
Bulletin 1724E-200

Page 9-21

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.

n 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 524-2003, IEEE, 2004.
Bulletin 1724E-200

Page 9-22

 ∑ CONDUCTOR LENGTH IN TRAVELERS = ∑ CONDUCTOR LENGTH IN SUSPENSION CLAMPS

FIGURE 9-7: ANALYSIS FOR APPLICATION OF CLIPPING OFFSETS

From IEEE Standard 524-2003, “IEEE Guide to the Installation of Overhead Transmission Line 

Conductors,” copyright 2004 IEEE. All rights reserved.
Bulletin 1724E-200

Page 9-23

o Example 9-1: Determination of Ruling Span: Determine the ruling span for the 

line segment given below using both the exact and approximate 

method.

FIGURE 9-8: LINE SECTION FOR EXAMPLE 9-1

 Solution, Exact Method:

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.

p 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.

925 ft 1380 ft 495 ft 1005 ft

n

n

L L L L

L L L L RS

+ + + +

+ + + + = 



1 2 3

3 3

3

3

2

3

1

925 1380 495 1005

925 1380 495 1005 RS

3 3 3 3

+ + +

+ + + =
Bulletin 1724E-200

Page 9-24

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.

wc

T LMAX =1.33 See Eq. 9-5

LMAX = 1.33 12600 lbs. = 8007 ft.

 2.0930 lbs/ft.

q 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:

2 2

w S TT T

T c

h

h

avg = +

+ = 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:

h

c

h c h T

w L

T T w S T

2 = + = cosh See Eq. 9-8

T = Th + wcS

T = 9173 + (1.094)(21.95)

T = 9197 lbs.

2

w S T T c h = avg −
Bulletin 1724E-200

Page 9-25

Blank Page
Bulletin 1724E-200 

Page 10-1 

10 PLAN-PROFILE DRAWINGS

a 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.

b 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.

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 
Bulletin 1724E-200

Page 10-2

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 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 three-dimensional 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. Traditional 

methods used to spot structures can be as much as 70-80 percent more 

conservative than the computer aided design and drafting approach.
Bulletin 1724E-200

Page 10-3

FIGURE 10-1: SAMPLE OF A PLAN AND PROFILE
Bulletin 1724E-200

Page 10-4

FIGURE 10-2: CONVENTIONAL SYMBOLS FOR PLAN-PROFILE

PLAN

Transmission Line CL

Telephone Lines T T T T T

R/W Lines

State Lines

Township, Range, 

and District Lines

Section Lines

County Lines

Property Lines

Highway and Main Roads U.S. 40

8 ft. gravel Local Roads

Railroads

Fences (all kinds)

Existing O.H. Power Line

(Ownership and Voltage)

O P S 69kV

Smaller Streams

Creeks

Rivers

Ponds

Buildings (State Kind)

Wooded section

Marsh

Orchard

Depression

Barn

PROFILE

Center Line

Sidehill, right

Sidehill, left

P.I. (Point of 

Intersection)
Bulletin 1724E-200

Page 10-5

c 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.

(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.

(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.h 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.
Bulletin 1724E-200

Page 10-6

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:

( ) SRS RS

L S

2





 



 = Eq. 10-1

where:

S = sag of other span in ft.

SRS = sag of ruling span in ft.

L = length of other span in ft.

RS = ruling span sag in ft.

(b) Apply catenary sag correction for long spans having large sags.

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.
Bulletin 1724E-200

Page 10-7

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

(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.

C

B

167°F FINAL

Hot Curve

60°F FINAL

Normal Curve

0°F Initial

Cold Curve

Structure Height

Scale

90

85

80

75

70

65

60

55

50

TS-1

Ground 

level

 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

 

G

 VERTICAL 1" = 20 ft

SCALE: HORIZONTAL 1" = 200 ft

TS-1

50

55

60

65

70

75

80

85

90

Structure Height

Scale

0°F Initial

Cold Curve

60°F FINAL

Normal Curve

167°F FINAL

Hot Curve

B

C

G

Ground 

level

TS-1

50

55

60

65

70

75

80

85

90

Structure Height

Scale

0°F Initial

Cold Curve

60°F FINAL

Normal Curve

167°F FINAL

Hot Curve

B

C

G

Ground 

level
Bulletin 1724E-200

Page 10-8

d Structure Spotting

(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.
Bulletin 1724E-200

Page 10-9

(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:

(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

(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 Hframe structures. Selection of the proper pole may be affected by various 

criteria, such as span-controlled-by-clearance or span-limited-by-polestrength, for a given pole height and class or bracing.
Bulletin 1724E-200

Page 10-10

(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". 

Hot Curves (Maximum Sag) A = Dimension from top of pole to point of 

attachment of lowest conductor.- Curve 1 - Lowest Conductor Sag Position B = Sag in level ground span.

Curve 2 - Basic Ground Clearance Curve C = Total ground clearance.

Curve 3 - Edge of Template or Reference Line D = Setting depth of pole

Point 4 - Intersection Locates Pole of Basic

Height

E = Length of pole.

Point 5 - Tangent to Ground Profile 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 

F

 E

D

C

B

A

G

B

5

3 2 1

GROUND LINE G

C

D

 E

5

B

F

3 2 1

A

B

GROUND LINE G

C

D

 E

5

B

F

3 2 1

A

B

GROUND LINE G

C

D

 E

5

B

F

3 2 1

A

B

GROUND LINE G

C

D

 E

4 5

B

F

3 2 1

A

B

GROUND LINE
Bulletin 1724E-200

Page 10-11

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.

(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 there is 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.

(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 
Bulletin 1724E-200

Page 10-12

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) Relocate structures to adjust horizontal-vertical span ratio;

(b) Increase structure height or lower adjacent structures;

(c) Use a different structure, one with greater allowable swing angle or 

a deadend structure; or

(d) Add weight at insulators to provide the needed vertical force.

(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 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.d.(1).(c) of this chapter).
Bulletin 1724E-200

Page 10-13

FIGURE 10-5: CHECK FOR UPLIFT

(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 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.

Cold Curve

Cold Curve Uplift Exists at 

Center 

Structure

No Uplift at 

Center Structure, 

Check for Allowable 

Insulator Swing
Bulletin 1724E-200

Page 10-14

FIGURE 10-6: SAG LOW POINT, VERTICAL SPANS AND UPLIFT Structure No. 2 Vertical Span

1 2

3

5

7 Structure No. 4 Uplift

Structure No. 5 Vertical Span

4

6

Structure No. 1

Vertical Span

Structure No. 4 

Uplift

Structure No. 5 Vertical Span

4

6

Structure No. 3

Vertical Span

Figure 10-6 Sag Low Point, Vertical Spans and Uplift
Bulletin 1724E-200

Page 10-15

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 extreme 

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.

(9) 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 
Bulletin 1724E-200

Page 10-16

to each 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) 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 10-17

Profile: ____________________________ Date: _______________________________

Line: ______________________________ Voltage: ______________

Plan and Profile Drawing Nos.___________ Checked by: __________________________

Loadings

NESC District __________________

50 yr extreme wind(psf) ___________

Extreme ice load (radial inches)_____

Ruling Span: _________________________

Conductor: _________________________ Design Tension: ______________________

OHGW: ___________________________ Design Tension: ______________________

Underbuild: ________________________ Design Tension: ______________________

Sheet Number

PLAN

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 10-18

Blank Page
Bulletin 1724E-200

Page 11-1

11 LOADINGS AND LOAD FACTORS

a 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 2012 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.

b Loads.

(1) NESC Loading Districts. The NESC divides the country into four 

weather or loading districts, as shown in Figure 11-1.

FIGURE 11-1: NESC LOADING DISTRICTS

From IEEE C2-2012, National Electric Safety Code® (NESC®), Copyright IEEE 2012. All rights reserved. 

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.
Bulletin 1724E-200

Page 11-2

TABLE 11-1

ICE, WIND, TEMPERATURE, AND CONSTANTS

NESC Loading Design 

Temp. 

(Fo)

Radial Ice 

Thickness

(inches)

Wind 

Loading

Constants

(lbs/ft)

Loading District

Heavy 0° 0.50 4 psf 0.30

Medium 15° 0.25 4 psf 0.20

Light 30° 0 9 psf 0.05

Warm Islands*

(SL – 9,000ft) 50° 0 9 psf 0.05

Warm Islands*

(above 9,000ft) 15° 0.25 4 psf 0.20

Extreme Wind 60° 0 See 

Figure 11-2 NA

Extreme Ice with Concurrent Wind 15° See Figure 

11-3

See Figure 

11-3 NA

*Based on altitude of American Samoa, Guam, Hawaii, Puerto Rico, Virgin Islands, and other 

islands 0°-25° latitude, N or S 

SL —Sea Level

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.

(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.

(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 11-2. The NESC 

allows linear interpolation when considering locations between isotachs. 
Bulletin 1724E-200

Page 11-3

Local meteorological data should also be evaluated in determining 

a design high wind speed. 

Equations in Tables 250-2 and 250-3 of the NESC should be 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.

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

(from 2012 NESC 250C)

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 Bw

0.5)]/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) kZ

≤ 33 1.00

34 – 50 1.10

51 – 80 1.20

 81 – 115 1.30

116 – 165 1.40
Bulletin 1724E-200

Page 11-4

TABLE 11-3

WIRE GUST RESPONSE FACTOR, GRF

Height of Wire At 

the Structure 

h (ft.)

Wire, GRF, for Various Span Lengths in feet

251 - 500 501 - 750 751 - 1000 1001 -1500

≤33 0.86 0.79 0.75 0.73

34 – 50 0.82 0.76 0.72 0.70

51 – 80 0.80 0.75 0.71 0.69

81 – 115 0.78 0.73 0.70 0.68

116 – 165 0.77 0.72 0.69 0.67

TABLE 11-4

COMBINED FACTOR kZ*GRF

FOR COMMON WIRE HEIGHTS

Height of Wire At 

the Structure 

h (ft.)

Wire, GRF, for Various Span Lengths in feet)

251 – 500 501 - 750 751 - 1000 1001 -1500

34 - 50 0.90 0.84 0.79 0.77

51 - 80 0.96 0.90 0.85 0.83

 81 - 115 1.01 0.95 0.91 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

(from 2012 NESC 250C)

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 Bs

0.5)]/kv2 where 

Es = 0.346 (33/(0.670h)1/7 and 

Bs = 1/(1+0.375h/220) 

kv = 1.43

h = height of the structure above groundline

Cf = drag coefficient

A = projected wind area in square feet 
Bulletin 1724E-200

Page 11-5

TABLE 11-5

STRUCTURE kZ, GRF , and COMBINED kZ GRF Factor

Height of 

Structure, ft kZ GRF

Combined

’kZ GRF’ 

factor

≤ 33 0.9 1.02 0.92

34 – 50 1.0 0.97 0.97

51 – 80 1.1 0.93 1.02

81 – 115 1.2 0.89 1.07

116 – 165 1.3 0.86 1.12
Bulletin 1724E-200

Page 11-6

FIGURE 11-2a: BASIC WIND SPEED IN MILES PER HOUR AT 33 FT. ABOVE GROUND 

For use in calculating Extreme Wind Load (50-year mean recurrence interval). From IEEE C2-2012, National Electric Safety Code® (NESC®), Copyright IEEE 2012. All rights reserved.
Bulletin 1724E-200

Page 11-7

FIGURE 11-2b BASIC WIND SPEED IN MILES PER HOUR AT 33 FT. ABOVE GROUND. 

For use in calculating Extreme Wind Load (50-year mean recurrence interval). From IEEE C2-2012, National Electric Safety Code® (NESC®), Copyright IEEE 2012. All rights reserved.

Notes:

1. Values are nominal design 3-second gust wind speeds in miles per hour (m/s) at 33 

ft. (10 m) 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.

Special Wind Region

Location V mph (m/s)

Hawaii 105 (47)

Puerto Rico 145 (65)

Guam 170 (76)

Virgin Islands 145 (65)

American Samoa 125 (56)
Bulletin 1724E-200

Page 11-8

FIGURES 11-2c & -2d: BASIC WIND SPEED IN MILES PER HOUR 

AT 33 FT. ABOVE GROUND For use in calculating Extreme Wind Load. (50-year mean recurrence interval)

From IEEE C2-2012, National Electric Safety Code® (NESC®), Copyright IEEE 2012. All rights reserved.

Figure 11-2d

Notes:

1. Values are nominal design 3-second gust wind 

speeds in mph (m/s) at 33 ft (10 m) 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 11-2c
Bulletin 1724E-200

Page 11-9

FIGURE 11-2e: BASIC WIND SPEED IN MILES PER HOUR AT 33 FT. ABOVE GROUND

For use in calculating Extreme Wind Load. (50-year mean recurrence interval)

From IEEE C2-2012, National Electric Safety Code® (NESC®), Copyright IEEE 2012. All rights reserved.

(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. The warm island district is not held to extreme ice with 

concurrent wind loads. 

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.
Bulletin 1724E-200

Page 11-10

FIGURE 11-3a: UNIFORM ICE THICKNESS DUE TO FREEZING RAIN WITH

CONCURRENT 3-SECOND GUST WIND SPEEDS (50 yr. mean recurrence)

From IEEE C2-2012, National Electric Safety Code® (NESC®), Copyright IEEE 2012. All rights reserved.

 Fig 11-3f

Fig 11-3e
Bulletin 1724E-200

Page 11-11

FIGURE 11-3b: UNIFORM ICE THICKNESS DUE TO FREEZING RAIN WITH

CONCURRENT 3-SECOND GUST WIND SPEEDS (50 yr. mean recurrence)

From IEEE C2-2012, National Electric Safety Code® (NESC®), Copyright IEEE 2012. All rights reserved.

Figure 11-3d
Bulletin 1724E-200

Page 11-12

FIGURE 11-3c: UNIFORM ICE THICKNESS DUE TO FREEZING RAIN WITH 

CONCURRENT 3-SECOND GUST WIND SPEEDS FOR ALASKA 

(50 year mean recurrence interval)

From IEEE C2-2012, National Electric Safety Code® (NESC®), Copyright IEEE 2012. All rights reserved.
Bulletin 1724E-200

Page 11-13

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)

From IEEE C2-2012, National Electric Safety Code® (NESC®), Copyright IEEE 2012. All rights reserved.
Bulletin 1724E-200

Page 11-14

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)

(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

• A broken wire • Stringing loads • Construction and maintenance activities • 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 2012 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 2010. 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.

From IEEE C2-2012, National Electric Safety Code® (NESC®), Copyright IEEE 2012. All rights reserved.
Bulletin 1724E-200

Page 11-15

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 an event occurred, it could result in 

damage to several (perhaps numerous) support arms and/or ground wire 

peaks. 

(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 
Bulletin 1724E-200

Page 11-16

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:

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 transverse 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).

(7) Example of Extreme Ice/Wind Calculations.

Using the same example line in the previous paragraph (11.b.(6)), the line 

located in northern Mississippi 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
Bulletin 1724E-200

Page 11-17

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

c 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. 

d 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 = measure of material strength or 

resistance

Ø = a strength factor, less than 1.0

Q = load

LF = 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. 

(1) Example Calculation Showing the Use of Strength and Load Factors.

A Douglas fir, 55 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 7.5 feet. The length of the moment arm used to 

calculate the induced moment at groundline is 45.5 feet.
Bulletin 1724E-200

Page 11-18

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)(45.5 feet)

 MMoment capacity at the groundline > 131,250 ft.-lbs

The pole should have a moment capacity of 131 ft-kips at the groundline. 

A class 3 Douglas fir pole would provide this moment capacity at the 

groundline. 

(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. Refer to the calculations in Chapter 13 required for point of 

maximum stress in wood poles taller than 55 ft.
Bulletin 1724E-200

Page 11-19

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 261-1) (Note 5)

FACTORS NESC RUS

LOAD FACTORS

Vertical Loads 1.50 1.50

Transverse Loads

Wind 2.50 2.50

Wire Tension 1.65 1.65

Longitudinal Loads

At crossings

General 1.10 1.33

Deadends 1.65 1.65

Elsewhere

General 1.00 1.33

Deadends 1.65 1.65

STRENGTH FACTORS (Note 3)

Steel and Prestressed Concrete Structures 1.00 1.00

Wood and Reinforced Concrete Poles (Note 4) 0.65 0.65

Wood Crossarms and Crossbraces (Note 4) 0.65 0.50

Fiber-Reinforced Polymer Poles, Crossarms,

 and Braces

1.00 1.00

Guy Wire Assemblies 0.90 0.65 (Note 1)

Guy Anchors and Foundations 1.00 0.65

Guy Attachment Assemblies (includes guy 

hardware) 

1.00 0.65 (Note 2)

Conductor Support Hardware (Note 6) 1.00 1.00

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 than 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 11-20

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 261-1) (Note 5)

FACTORS NESC RUS

LOAD FACTORS

Vertical Loads 1.00 1.10

Transverse Loads

Wind 1.00 1.10

Wire Tension 1.00 1.00

Longitudinal Loads

At crossings

General 1.00 1.00

Deadends 1.00 1.10

Elsewhere

General 1.00 1.00

Deadends 1.00 1.10

STRENGTH FACTORS (Note 3)

Steel and Prestressed Concrete Structures 1.00 1.00

Wood and Reinforced Concrete Poles (Note 4) 0.75 0.75

Wood Crossarms and Crossbraces (Note 4) 0.75 0.65

Fiber-Reinforced Polymer Poles, Crossarms,

 and Braces

1.00 1.00

Guy Wire Assemblies 0.90 0.65 (Note 1)

Guy Anchors and Foundations 1.00 0.65

Guy Attachment Assemblies (includes guy 

hardware, bracket and guy attachment 

assemblies) 

Not Specified 0.65 (Note 2)

Conductor Support Hardware (Note 6) 0.80 0.80

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 than 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 11-21

Blank Page
Bulletin 1724E-200

Page 12-1

12 FOUNDATION STABILITY OF DIRECT-EMBEDDED POLES

a General. Every structure standing above ground is subjected to lateral and 

vertical forces. In the case of direct-embedded wood, steel or prestressed concrete

transmission structures, it is desirable to depend on the earth to resist these forces. 

The embedded portion of a pole provides this resistance by distributing the loads 

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 plumb 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).

b Site Survey. 

(1) Soil Borings. Depending on the transmission line and knowledge of the 

soil conditions along the corridor, the need for soil borings must be 

determined. If the line is composed of H2 or higher class wood poles, or 

equivalent strength steel or concrete poles, the need for soil borings may 

be greater. The decision to take borings will also depend on existing soil 

information. Variation of the soil will determine the frequency of the 

borings. Borings should be considered at locations where additional 

lateral loads will occur, such as unguyed angle structures and deadend 

structures composed of steel or concrete poles.

For transmission line projects that are a few miles in length to ones that 

are longer, a geotechnical report, which includes soil borings and 

subsurface analysis, is usually a small percentage of the overall cost of the 

project. A few borings appropriately placed along the route of the line can 

provide valuable data to analyze the most economical and stable 

embedment depths. This is particularly true when CAD programs include 

a function for analyzing subsurface soil data for embedment depths.

(2) Embedment Depths. In deciding embedment depths for many typical 

agency borrower wood pole lines, economics may 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 of the pole 

length, plus 2 feet.
Bulletin 1724E-200

Page 12-2

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

submerged weight of soil below the water table, frictional forces 

along the surface area of embedded poles are reduced along with 

reduction in the strength of the soil to resist lateral and vertical 

forces. 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.

• 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.

Subsurface soil conditions may exist that are so poor that direct 

embedment is not the appropriate option for support of the structure. In 

these cases actual soil boring information may be needed to determine 

alternative foundation options and structure types.

(3) Field Survey. A field survey is a method that can be used to estimate

whether a soil is "good," "average," or "poor." It should be noted that 

embedment depth design based on field survey data is subject to a wide 

variation in results. The location for obtaining the most reliable soil data 

using field survey methods would be at the depth where the pole would 

bear and at any transition between soil layers along the depth of 

embedment of the pole. 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:
Bulletin 1724E-200

Page 12-3

TABLE 12-1

CLASSIFICATION OF SOILS BASED ON FIELD TESTS

Term Field Test

Very soft Squeezes between fingers when fist is closed

Soft Easily molded by fingers

Firm Molded by strong pressure of fingers

Stiff Dented by strong pressure of fingers

Very Stiff Dented only slightly by finger pressure

Hard Dented only slightly by pencil point

Term Field Test

Loose Easily penetrated with a 1/2 in. reinforcing rod pushed by 

hand 

Firm Easily penetrated with a 1/2 in. reinforcing rod driven with 

a 5 lb. hammer 

Dense Penetrated 1 ft. with a 1/2 in. reinforcing rod with a 5 lb. 

Hammer

Very dense Penetrated only a few inches with a 1/2 in. reinforcing rod 

driven with a 5 lb. hammer

c Pole Stability.

(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

The graphs in Figures 12-1 through 12-3 are based on Equation 12-1:

e

e e

L D

S D

P

2. .662

3.75

− − = 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
Bulletin 1724E-200

Page 12-4

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.

FIGURE 12-1: EMBEDMENT DEPTHS IN POOR SOIL

5 6 7 8 9 10

0

2,000

4,000

6,000

Load 2' from the top (lbs.)

40'

60'

90'

Embedment Depth (ft.)

POOR SOIL

0
Bulletin 1724E-200

Page 12-5

FIGURE 12-2: EMBEDMENT DEPTHS IN AVERAGE SOIL

FIGURE 12-3: EMBEDMENT DEPTHS IN GOOD SOIL

AVERAGE SOIL

7 8 9 10

Embedment Depth (ft.)

Load 2' from the top (lbs.)

10,000

40'

60'

90'

8,000

6,000

4,000

2,000

0

5 6

Load 2' from the top (lbs.)

6,000

8,000

10,000

4,000

2,000

0

5 6 7 8 9 10

40' 60'

90'

Embedment Depth (ft.)

GOOD SOIL
Bulletin 1724E-200

Page 12-6

FIGURE 12-4: EMBEDMENT CHART FOR MEDIUM DRY SAND

AGENCY BULLETIN 1724E-205 “EMBEDMENT DEPTHS

FOR CONCRETE AND STEEL POLES”
Bulletin 1724E-200

Page 12-7

(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.

(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.

d 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 by taking the bearing capacity of the soil into consideration. 

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. 

Engineering design 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 12-8

TABLE 12-2

PRESUMPTIVE ALLOWABLE BEARING CAPACITIES, ksf

TABLE 12-3

SUGGESTED RANGES OF PRESUMPTIVE

ULTIMATE BEARING CAPACITIES, psf*

Specific Description (Dry) psf

Clay, soft 2000 - 6000

Clay, ordinary 6000 - 9000

Clay, stiff 12000

Clay, hard 15000

Sand, loose 4500

Sand, compact and silty 9000

Sand, compact and clean 15000

Hardpan 40000

General Description (Dry)

Poor Soil 1500 - 4000

Average Soil 5000 – 9000

Good soil 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.

Soil Description Chicago

1966

Atlanta

1950

Uniform Building Code

1964

Clay, very soft 0.5 2.0 1.5

Clay, soft 1.5 2.0 1.5

Clay, ordinary 2.5 4.0

Clay, medium stiff 3.5 2.5

Clay, stiff 4.5 4.0

Clay, hard 6.0 8.0

Sand, compact and clean 5.0

Sand, compact and silty 3.0

Inorganic silt, compact 2.5 1.5

Sand, loose and fine 1.5

Sand, loose and coarse, or

 sand-gravel mixture, or

 compact and fine 2.5

Gravel, loose, and compact

 coarse sand 8.0 8.0

Sand-gravel, compact 12.0 8.0

Hardpan, cemented sand,

 cemented gravel 12.0 20.0

Soft rock

Sedimentary layered rock

 (hard shale, sandstone, 

 siltstone)

30.0

Bedrock 200.0 200.0
Bulletin 1724E-200

Page 12-9

e 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.

f 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 of the soil is preferred. 

Proper compaction of the backfill is extremely important in helping to prevent 

structure failures.
Bulletin 1724E-200

Page 12-10

Blank Page
Bulletin 1724E-200

Page 13-1

13 STRUCTURES 

a 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:

- Strength: Horizontal spans are limited by crossbrace, poles, etc. Vertical 

spans are limited by crossarms, post insulators, and structure strength. For 

H-frame structures, horizontal and vertical spans are also limited by 

pullout resistance for H-frame structures.

- Conductor Separation: Conductor separation is intended to provide 

adequate space for line crew personnel on poles, prevention of contact and 

flashover between conductors.

- Clearances-to-Ground: Limits on spans are directly related to height of 

structures.

- 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 
Bulletin 1724E-200

Page 13-2

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 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. 

FIGURE 13-1: SELECTION OF LEVEL GROUND SPAN

FIGURE 13-2: STRUCTURE COST PER MILE RELATED TO POLE HEIGHT

b Steel and Concrete Structures - General Design Considerations. Rural Utilities 

Service provides several bulletins on design considerations for steel and concrete 

pole structures. 

Structure per mile or

span length, feet

Class 2

Class 1

Span limit due

to strength

Pole height, feet

Span limit due to

conductor sag

A

B

Pole height, feet

Structure costs per mile

36

34

32

30

28

70 80 90 100 110

Class 2(1x)

Class 1(1x)

Class 2(2x)
Bulletin 1724E-200

Page 13-3

• 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 13-4

c Wood Structures - General Design Considerations.

(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)

Western larch 1710 8400

Southern yellow pine 1800 8000

Douglas fir 1920 8000

Lodgepole pine 1340 6600

Jack pine 1220 6600

Red (Norway) pine 1630 6600

Ponderosa pine 1260 6000

Western red cedar 1120 6000

Northern white cedar 800 4000

*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)

Designated Ult. 

Bending Stress 

(M.O.R.)* (psi)

End Grain Max 

Crushing 

Strength (psi)

Across Grain 

Stress 

(psi)

Shear 

Parallel to 

Grain (psi)

Douglas fir 1920 7400 7420 910 1140

SYP 1800 7400 7070 1000 1310

*M.O.R. = Modulus of Rupture

(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.

(a) 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.
Bulletin 1724E-200

Page 13-5

(b) 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 species and amounts of 

treatment, refer to agency Bulletin 1728F-700, “Specification for 

Wood Poles, Stubs, and Anchor Logs.”

(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

d Design Calculations for Single Wood Pole Structures. In accordance with NESC 

Rule 261.A.2.a, single pole wood structures shall be designed to withstand the 

loads multiplied by the appropriate load factors without exceeding the permitted 

stress level at the point of maximum stress. The NESC Rule states that for wood 

poles 55 ft or less in total length, design shall not exceed the permitted stress level 

at the ground line. 

For poles 60 ft or longer in total length, the point of maximum stress shall be 

determined according to ANSI 05.1.2008, as referenced in NESC Rule 261.A.2.b. 

Typically for poles 60 ft or longer, the point of maximum stress occurs above the 

ground line. According to ANSI 05.1.2008, the theoretical point of maximum 

stress for a single pole with a uniform taper is located where the circumference is 

one and one half times the circumference at the point of applied, or net pull, load. 

At the point of maximum stress, the resulting available moment is to be multiplied 

by the appropriate strength factors. 

For determining maximum horizontal spans limited by pole strength, two methods 

are to be used. 

- The Ground Line Method shall be used for poles 55 ft or less in total 

length. 

- For poles 60 ft or longer in total length, the Point of Maximum Stress 

Method shall be used. Example problems follow that illustrate how these 

methods are to be used.

(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.
Bulletin 1724E-200

Page 13-6 

• 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

ground line or point of maximum stress and will affect horizontal

span lengths by 2 to 10 percent.

• P-delta (P-δ) moments will also increase induced 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.d.(1).(a).

The strength of the crossarm for TS structures and the strength of the 

insulator for TP structures have 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. 

Equation 13-1 is the general equation for determining the moment induced 

in the pole from the applied loads represented in Figs. 13-3 and 13-3.1. 

This equation is the basis for the Ground Line and Point of Maximum 

Stress Methods to be used to determine maximum horizontal spans. 

( ) ( ) ( ) ( ) φ MM gA == 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 moment capacity of the pole, ft-lbs. 

For moment capacities of wood poles, (see 

Appendix F);

Fb = designated ultimate bending stress (M.O.R.) 

S = section modulus of the pole (see Appendix H).

LF = load factor associated with the particular load

Mg = the induced moment

Other symbols are defined by Equations 13-2, 13-3, 13-4, 13-5 (a-c).

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 deflection. 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. 
Bulletin 1724E-200

Page 13-7 

Sc

Sa Sb

h

pg Sg

Pc

Pc Pc

ha, hb hc

Pt

A

hg

h1

(a) Ground Line Method for Poles 55 Feet and Under. Refer to Figures 

13-3 or 13-3.1 when considering the equations and symbols that 

follow. 

+ 

Figure 13-3: TS Type Structure 

Figure 13-3.1: TP Type Structure 

Sb h

pg

Sg

Pc

ha

Pc

a

b

c

hb

hc

Pc

Pt

Sc

Sa

h1

hg
Bulletin 1724E-200

Page 13-8 

(1) Mwp = groundline moment due to wind on the pole 

( )( )( )

72

2 2 hddF M at

wp

+ = Eq. 13-2 

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

(2) Mwc = groundline moment due to wind on the wires 

( ) hpM HS wc = t 1 Eq. 13-3 

where: 

HS = horizontal span, feet 

h1 = arm of pt, feet; in the example

( )( ) ( )( ) ( )( ) ( )( )

t

ggcccbca

P

phphphph h+++

1 = Eq. 13-3.1 

pc, pg = transverse wire loads

Pt = sum of transverse unit wire loads, lbs/ft; in 

example,

Pt = 3 pc + pg for single circuit, single pole structures

(3) 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 insulator, lbs. (For TP structure, Wi = 0)

(4) Mp- = groundline moment due to pole deflection 

M Eq. 13-5 p-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. 
Bulletin 1724E-200

Page 13-9 

( ( )( )( ) ) ( ) ( ) mag

g

t

imp ddE

p HS h 

















=

1

3

3 78.6 1 144 Eq. 13-6

E = modulus of elasticity, psi 

dg = diameter of pole at groundline, inches 

d1 = diameter of pole, inches, at height "h1" above ground 

line

δmag = deflection magnifier, no units, (assume 1.15 initially)

h1 = effective height to the conductors, feet 

HS = horizontal span, feet 

pt = total transverse load per unit length of all wires, 

lbs./ft.

After substitutions of Mwp, Mwc, Mvo, and Mp 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.d.(2) for an example of how the 

calculation of HS is carried out.) 

( ) ( ) ( ) ( ) φ MM gA == LF Mwp + LF Mwc + LF Mvo + LF M p−δ Eq. 13-1 

( ) ( )

a

acbb HS

a HS b HS c

2

4

0

2

2

−±− =

=++

Eq. 13-7

Once “HS” has been calculated, check the assumption of 

δmag = 1.15: 

 Eq. 13-8

(See example problems for calculations of Pcr) 

(b) Point of Maximum Stress Method for Poles 60 feet and longer. 

For wood poles 60 feet or longer in total length and utilizing either 

the TS or TP configuration, the following procedure should be 

followed to calculate the point of maximum stress, POMS, on the 

pole and resulting allowable moment and maximum horizontal 

span. 

For wood poles 60 feet, or longer, in total length, utilizing either 

the TP or TS pole type assembly, refer to Figs. 13-4 and 13-4.1. 

( )

P

HS W

cr

t

 

.1 25 1

1

−

δmag=
Bulletin 1724E-200

Page 13-10 

Figure 13-4: TS Type Structure POMS

Sc

Sa Sb

h

pg

Sg

Pc

Pc Pc

ha, hb

hc

Pt

h1

A

Embedment

Poms

h1max

h2

hg

a b

c

H
Bulletin 1724E-200

Page 13-11 

Figure 13-4.1: TP Type Structure POMS

(1) Calculate location of the resultant load (net pull), Pt 

Pt = 3 pc + pg

( )( ) ( )( ) ( )( ) c b c c c ( )( g g)

 Pt

a +++ phphphph h1 = Eq. 13-3.1 

h1 = Moment arm of Pt above groundline, feet 

Embedment

Sb

h

pg

Sg

Pc

ha

A

Pc

a

b

c

hb

hc

hg

Pc

S Pt c

Sa

h1

Poms

h1max

h2

H
Bulletin 1724E-200

Page 13-12 

(2) Find the circumference, Cms, at the point of maximum 

stress, Poms. 

- Cms = 1.5 times circumference at Pt, Cpt (ANSI 05.1.2008) 

- Calculate distance from Pt to top of pole 

- Refer to Appendix F, this bulletin, to determine diameter of 

pole at Pt, dpt. Interpolate if necessary

- Use dpt to calculate Cpt : Cpt = π · dpt Eq. 13-9 

- Multiply Cpt by 1.5 to calculate Cms : 

Cms= 1.5 · Cpt Eq. 13-10 

(3) Locate where Poms occurs on the pole. 

- Calculate the pole diameter, dms, at the point of maximum 

stress

- π

ms

C

ms

d = Eq. 13-11

- Refer to Appendix F, this bulletin to determine where dms

occurs on the pole. Interpolate if necessary. 

- This determines distance, h2, from top of pole to dms and is 

the location of the Poms

- Subtract h2 from pole height above ground, h, to determine 

distance, H, from groundline to Poms

- h1max = h1 - H 

(4) Calculate the allowable moment, Ma, at the point of 

maximum stress of the pole. 

Ma = FbS Eq. 13-13 

Fb = fiber stress, psi

32

3 d ms S π

= Eq. 13-14

S = Section Modulus at point of maximum stress, in3

(5) Calculate the maximum horizontal span based on the point 

of maximum stress of the pole. 

- Moment at Poms due to wind on pole:

( )( )( )

72

2 2

M t ms hddF 2

wp

+ = Eq. 13-2 

h2 = distance from Poms location to top of pole, feet 

dt = pole diameter at top, inches

dms = pole diameter at Poms, inches

F = wind pressure, psf 
Bulletin 1724E-200

Page 13-13 

( )

P

HS W

cr

t

mag

 

.1 25 1

1

−

δ =

- Moment at Poms due to wind on wires: 

( ) hpM HS wc = t 1max Eq. 13-3 

- Moment at Poms due to unbalanced vertical load:

Mvo = 1.25HS(wcsc + wgsg) + Wist Eq. 13-4 

Note: For TP structure, Wi = 0

- Moment at Poms due to pole deflection: 

Mp-d = 1.25HS(wt)δimp

 

 Eq. 13-5

where:

wt = total weight per unit length of all wires, lbs./ft. mp =

δimp = improved estimate of deflection of the structure, ft. 

( ( )( )( ) )

( ) ( ) mag

ms pt

t

imp ddE

p HS h 

















= 3

3

1max 78.6 144 Eq. 13-6

E = modulus of elasticity, psi

dms = diameter of pole at point of maximum stress, inches 

dpt = diameter of pole at the resultant load, pt, inches 

 δmag = deflection magnifier, no units, (assume 1.15 initially) 

h1max = distance from location of Pt to Poms, feet

HS = horizontal span, feet 

Pt = total transverse load per unit length of all wires, lbs./ft. 

- After substitutions of Mwp, Mwc, Mvo, and Mp have been 

made into Eq.13-1, the equation can be reduced to a 

quadratic equation (below) and solved for the horizontal 

span. 

( ) ( ) ( ) ( ) φ MM gA == LF Mwp + LF Mwc + LF Mvo + LF M p−δ Eq. 13-1

( ) ( )

a

acbb HS

a HS b HS c

2

4

0

2

2

−±− =

=++

Eq. 13-7 

- Once “HS” has been calculated, check the assumption of mag = 

1.15: 

 Eq. 13-8 

- See example problems for calculations of Pcr
Bulletin 1724E-200

Page 13-14 

h1 = 39.82’

Sa = 5.5’

h = 47.5’

pg

Sg

Pc

Pc Pc

ha, hb

=36.0’

hc = 

43.0’

Pt

A

hg = 46.75’

55’

wc = 2.09 lb/ft

Sb = 5.5’

Sc = 3.75’

a b

c

(2) Example Problems for Maximum Horizontal Spans. The following 

example problems illustrate calculating the maximum horizontal span 

using the Ground Line and Point of Maximum Stress Methods. 

(a) Example Problem for Maximum Horizontal Span for TS-1 structure, 55 

Foot Pole. Using the Ground Line Method, determine the maximum 

horizontal span for a 55 ft, Class 1, Southern Yellow Pine, 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. 

Figure 13-5: TS Type Structure Example 

Given:

NESC Heavy Loading 4 psf, 0.5 inch radial ice

Extreme wind 19 psf on the wires

22 psf on the structure

Extreme Ice with 4 psf, 1 inch radial ice

Concurrent Wind(EI&W)

Pole: 55-1, Southern Yellow Pine

Conductor: 795 kcmil, 26/7 ACSR (Drake)

Ground wire: 3/8" H.S.S.
Bulletin 1724E-200

Page 13-15

Conductor loads, lbs./ft:

Heavy Extreme Wind EI&W

Transverse 0.7027 1.754 1.036

Vertical 2.0938 1.0940 3.7154 Ground wire loads, lbs./ft:

Heavy Extreme Wind EI&W Transverse 0.4533 0.5700 0.7868

Vertical 0.8079 0.2730 1.9667

Other information:

Fb(pole) = 8000 psi

Fb (crossarm) = 7400 psi

Wi , Wt. of insulator = 58 lbs.

Dia. (top) = 8.59 in.

Dia. (groundline) = 14.61 in.

pt(total unit load) = 3(0.7027)+0.4533 = 2.5614 lbs./ft.

wt(total unit load) = 3(2.0938)+0.8077 = 7.0891 lbs./ft

Pcr(critical buckling load) = 25,098 lb (see chapter 14 for fix–free condition)

( )( ) ( )( ) ( )( ) ( )( )

t

a c b c c c g g

P

h p h p h p h p h

+ + +

1 = Eq. 13-3

( )( ) ( )( ) ( )( ) ( )( )

2.5614

36 0.7027 36 0.7027 43 0.7027 46.75 0.4533

1

+ + + h =

39.82 h1 = ft = 478 in

E = 1.8 E 06 psi

da = dpt = Diameter at h1 above ground line= 9.57 in

dg = Diameter at ground line = 14.61 in

I = ππddpppp

4

64

I = 412 in4

PPcccc = �

ππ2EEEE

4ll2 � · �

ddgg

ddaa

�

2.7

PPcccc = �

ππ2(1.8)(106)(412)

4(478)2 � · �

(14.61)

(9.57) �

2.7

Pcr = 25,098 lb
Bulletin 1724E-200

Page 13-16 

( )( )( )

72

2 2 hddF

M gt

wp

+ =

wc = t( ) hpM 1 HS

Mwc = ( ) 82.395614.2 HS

Mwc = 0.102 HS

21731.10

)75.3)(58()]5.0)(8077.0()75.3)(0938.2[(25.1

+=

= + +

M HS

M HS

vo

vo

imp

p t imp

HS

M HS w

δ

δ δ

)0891.7(25.1

25.1

=

=

( ( )( )( ) ) ( ) ( ) mag

g

t

imp ddE

p HS h δ δ

















=

1

3

3 78.6 1 144

( ( )( )( ) )

( ) ( ) 15.1

57.961.14068.1

5614.278.6 1448.39

3

3















 = E

HS δ imp

δ imp = )15.1(0029.0 HS

δ imp = 0033.0 HS

2 0292.0

)0033.0)(0891.7(25.1

25.1

HS

HS HS

M p HS wt imp

=

=

δ = δ

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.

(1) Eq. 13-2 

(2) Eq. 13-3 

(3) Mvo = 1.25HS(wcst + wgsg) + Wist Eq. 13-4 

(4) Eq. 13-5 

Eq. 13-6 

assume δmag = 1.15 initially 

( )( )( )

72

5.4761.1459.824 2 +× M wp =

M lbft wp 985,3 −=
Bulletin 1724E-200

Page 13-17 

( ) ( ) ( ) ( ) φM A = LF Mwp + LF Mwc + LF Mvo + LF M p−δ

( ) ( ) ( ) ( ) 2 = + HS + HS ++ )0292.0(5.1)21731.10(5.1)102(5.2)985,3(5.2)200,204)(65.0( HS

2 HS ++= 465.15255963,9730,132 HS ++ 0438.05.325 HS

0438.0 465.270 0442,122 2 HS + HS =−

(5) Eq. 13-1 

- MA = 204.2 ft-K from Appendix F, groundline moment at 

embedment = 7.5 ft 

(6) 

Eq. 13-7 

(7) Once the HS has been calculated, the assumption of 1.15 as 

the magnifier should be checked. Pcr = 25,098 lb assuming 

fixed free conditions. (See Chapter 14) 

 Eq. 13-8 

Since the δmag check shows a value different from 1.15, 

recalculate the HS using 1.17 as the δmag. Recalculating the 

HS with δmag 1.17 gives HS = 423 feet. Assumption of 

1.15 as δmag is acceptable. 

(8) Lateral Stability. The Equivalent load 2 feet from the top is 

approximately 4300 lbs. From Figure 12-2 (average soil), 

the embedment depth for a 4300 lb. load 2 feet from the top 

is between 7.5 and 8.5 feet. Lines nearby have performed 

well with the standard embedment depths. Engineering 

judgment dictates that a 7.5 foot embedment depth for the 

55 foot pole will be sufficient. 

( ) ( )

a

acbb HS

a HS b HS c

2

4

0

2

2

−±− =

=++

)0438.0(2

)442,122)(0438.0(4)465.270(465.270 2 ±− − − HS =

HS = 423 feet

( )

P

HS W

cr

t

mag .1 25 1

1

−

δ =

( ) mag

25,098

.1 25(423 .7) 0891 1

1

−

δ =

δ mag = .1 17
Bulletin 1724E-200

Page 13-18 

61’

pg

Sg

Pc

ha = 45’

A

Pc

9’

a

b

c

hb

hc

hg

Pc

Pt

Sa, Sb, Sc

4’ h1

Poms

h1max

6’

5’

5’

H = 11.5’

h2

(b) Example Problem for Maximum Horizontal Spans for TP 

Structure, 70 foot Pole. Using the Point of Maximum Stress 

Method, determine the maximum horizontal span for a 69 kV TP69, 70 ft, Class 1, Southern Yellow Pine pole (Figure 13-6). 

Terrain is predominantly level, flat, and open. ("sg" is negligible; 

see Equation 13-4). Location and magnitude of resultant loads are

indicated in Figure 13-4. Similar calculations can be performed for 

TS pole top assemblies, see example problem in 13.4.2.1. 

FIGURE 13-6: TP-69 STRUCTURE POMS EXAMPLE
Bulletin 1724E-200

Page 13-19 

Given:

NESC Heavy Loading 4 psf, 0.5 inch radial ice

Extreme wind 19 psf on the wires

22 psf on the structure

Extreme Ice with 4 psf, 1 inch radial ice

Concurrent Wind(EI&W)

Pole: Southern Yellow Pine

Conductor: 795 kcmil, 26/7 ACSR 

(Drake)

Ground wire: 3/8" H.S.S.

Conductor Loads:

Heavy Extreme Wind EI&W

Transverse 0.7027 1.754 1.036

Vertical 2.0938 1.0940 3.7154

Ground wire loads, lbs./ft:

Heavy Extreme Wind EI&W

Transverse 0.4533 0.5700 0.7868

Vertical 0.8079 0.2730 1.9667

Other information:

Fb = 8,000 psi

Diameter (top of pole) = 8.594 in

Diameter (groundline) = 15.88 in

pt (total wire transverse unit load) = 2.5614 lbs./ft.

wt (total wire vertical unit load) = 7.0891 lbs./ft

(1) Calculate location of the resultant load, Pt

Pt = 3(0.7027) + 0.453 = 2.5614 lb/ft 

Eq. 13-3 

(2) Find the circumference, Cms, at the point of maximum 

stress

- Pt at 60.9 feet from the pole butt (51.9 ft + 9 ft 

embedment), or 9.1 ft from pole top 

- From pole data, Appendix F, 70/1 wood pole, interpolate 

between diameter at 9ft and 10ft from pole top to get 

diameter at Pt

- dpt = 9.66 inches 

- Pole circumference at Pt, Cpt = π · 9.66 in Eq. 13-9 

- Cpt = 30.35 in 

- Cms = (1.5)(30.35 in) Eq. 13-10 

- Cms = 45.53 in 

 ground above ft. 9.51 line

5614.2

)4533.0)(5.60()7027.0)(55()7027.0)(50()7027.0)(45(

1

=

+ + + h =
Bulletin 1724E-200

Page 13-20 

(3) Locate where the point of maximum stress, Poms, occurs on 

the pole. 

== 5.14 in

π

ms

ms

C d Eq. 13-11 

Using Appendix F, for the 70 foot, class 1 pole, a diameter 

of 14.5 inches occurs 49.5 ft from the top of the pole by 

interpolation. Therefore, the Poms occurs 49.5 feet from the 

top of the pole, which is 11.5 feet above the ground line. 

Poms = 49.5 feet (from tip) 

Poms = 11.5 feet (above ground line) 

(4) Calculate the allowable moment, Ma, at Poms

Fb = 8,000 psi 

3

3 3

3.299

32

)5.14(

32

in d S ms == = π π Eq. 13-14 

Ma = FbS Eq. 13-13 

ft lbs

ftin

inlb in Ma

= −

=

533,199

)/12(

)3.299)(/000,8( 2 3

(5) Calculate the maximum horizontal span based on point of 

maximum stress of the pole

- Moment at Poms due to wind on Pole: 

( )( )( )

72

2 2

M t ms hddF 2

wp

+ = Eq. 13-2 

[ ]( )

( )

lbft

Mwp

−=

+ =

312,4

126

5.495.14)59.8)(2(4 2

- Moment at Poms due to wind on wires: 

( ) hM HS wc = P 1t max Eq. 13-3 

( )

HS

M HS wc

5.103

4.405614.2

=

=
Bulletin 1724E-200

Page 13-21 

- Moment at Poms due to vertical offset:

Mvo = 1.25HS(wcsc + wgsg) + Wist Eq. 13-4 

HS

M vo HS

0.11

)]5.0)(807.0()4)(0938.2[(25.1

=

= +

- Secondary Moments: 

mag

pt

t

imp ddE

p HS h = 

))((

)]144)()()()(78.6[(

3

ms

3

1max Eq. 13-6 

Pt = 2.5614 lb/ft 

dpt = 9.7 in 

dms = diameter at Poms = 14.5 in 

δmag = assume 1.15 

h1max = 40.4 ft 

E = 1.8 x 106

 psi 

HS

HS

imp

0035.0

15.1

)7.9)(5.14)(108.1(

)]144)(4.40)()(5614.2)(78.6[(

6 3

3

=

×

×

δ =

2 0310.0

)0035.0)(0891.7(25.1

25.1

HS

HS HS

M p HS wt imp

=

=

δ = δ

Eq. 13-5 

- Total Moments:

HS ft

HS

HS HS

HS HS HS

HS HS HS

Ma LF M wp LF M wc LF Mvo LF M p

403

093.0

3.3138.275

)0465.0(2

)916,118)(0465.0(4)8.275(8.275

275.8 0.0465 0916,118

129,696 0465.05.163.259780,10

 (.65)(199, 533) )0310.0(5.1)0.11(5.1)7.103)(5.2()312,4)(5.2(

)()()()(

2

2

2

2

=

+− = +− − − =

+ =−

+= ++

= + + +

f = + + + δ Eq. 13-

Eq. 13-7
Bulletin 1724E-200

Page 13-22 

- Check Magnifier:

OK

lb

d

d

l

EI P

P

w HS

mag

pt

cr

cr

t

mag

,172.1

296,24

)403)(25.1)(0891.7( 1

1

296,24

7.9

5.14

)485(4

)6.434)(108.1(

4

)25.1( 1

1

7.2

2

2 6

7.2

max

2

2

=

−

=

=





 



 ∗



 



 × =

















∗



 



 =

−

=

hl inft

in

d

I pt

4854.40

6.434

64

)7.9(

64

 14.5 d in

 9.7 d in

where,

1max

4

4 4

ms

pt

===

===

=

=

p

HS = 403 ft 

Note: If magnifier check had shown δmag to be significantly different from 1.15 on the 

order of ± 0.03 or greater, then recalculate the horizontal span, HS, using the new 

δmag that was found from the check. 

(6) 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:

( )( )( )

( )( )( ) cc

x arm ci

LF sw

M LF sW VS − = φ − Eq. 13-15

where:

Mx-arm = FbS, moment capacity of the arm, ft-lbs

Fb = the designated bending stress

S = the section modulus of the arm (see Appendix G.)

wc = weight of the conductor per unit length, lbs./ft

sc = moment arm, feet

Wi = insulator weight, lbs.

VS

φ

=

=

vertical span, feet

strength factor (from Table 11-6 or 11-7) 
Bulletin 1724E-200

Page 13-23 

(a) Example of Vertical Span Calculations for TS Pole Top Assembly 

(Heavy Loading). 

wc =2.0938 lbs./ft. 

S = 22.7 in3 for a 4-5/8” X 5-5/8” crossarm

φ = .50 

LF = 1.5 Heavy Loading District

Use 795 kcmil, 26/7 conductor 

( )( )( )

( )( )( )

( )

( )( )( )

( )( )( )

.381

5.50938.25.1

5.5505.1)000,14)(50.0(

.50

000,14

12/7.227400

50.0

ft

VS

lbsW

ft lbs

M

SFM

LF sw

M LF sW VS

i

a

ba

cc

a ci

=

− =

=

= −

=

=

− =

Check vertical span for extreme ice with concurrent wind,

wc = 3.7154 lbs./ft., φ = 0.65 and LF = 1.1 for extreme ice with 

concurrent wind 

(b) Example of Vertical Span Calculations for TP Pole Top Assembly 

(Heavy Loading). 

To determine the vertical span for TP pole top assembly, the 

moment capacity of the post insulator at the pole is calculated. For 

purposes of this calculation, a polymer post insulator was chosen 

with an ultimate cantilever strength of 6,060 lbs and a section 

length of 4 feet. 

From Appendix B, Conductors, the weights per unit for the two 

conditions of the 795 kcmil, 26/7 ACSR “Drake” conductor are:

Heavy Loading District of 0.5 inch radial ice = 2.0938 lb-ft

Extreme radial ice of 1.0 inch = 3.7154 lb-ft

Span Limits for Heavy District Loading:

(1.1)(50)(5.5)

VS = (0.65)(14,000) −

(1.1)(3.7154)(5.5)

= 391 ft.
Bulletin 1724E-200

Page 13-24

S

"a"

In accordance with Table 8.5, utilize 40% of ultimate cantilever 

rating.

40%(6,606 lbs) = 2,424 lbs

ft lbs ft

lbs 1,157

2.0938 /

2,424 =

Span limits for extreme ice condition:

In accordance with Table 8.5, utilize 50% of ultimate 

cantilever rating.

(0.50)(6,606 lbs) = 3,303 lbs

ft lbs ft

lbs 889

3.7154 /

3,303 =

The maximum vertical Span for this TP pole top assembly 

example is 889 ft. 

(7) 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-to-phase faulting due to ice unloading or galloping. 

FIGURE 13-7: 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.
Bulletin 1724E-200

Page 13-25

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 13-8).

Given:

Loadings: NESC heavy loading district

Wires

Conductor: 266.8 kcmil, 26/7 ACSR (Partridge)

OHGW: 3/8” H.S.S

Pole S.Y.P. (70-1)

 FIGURE 13-8: TSZ-1 EXAMPLE FIGURE 13-9: HS vs. VS FOR TSZ-1

Solution:

Moment capacity of crossarm at “a”:

Ma = Maximum vertical load (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’.

 (LF)pc(1.5ft)(HS) + (LF)wc(3.22ft)VS + (LF)wi(3.22ft) = φ Ma

2.5(0.5473)(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.

 VS = - 0.393HS + 1004.6 

This equation defines the graph shown in Figure 13.9. 

For HS = VS, Span = 720 ft. 

1.5ft

3.22 ft

"a"
Bulletin 1724E-200

Page 13-26

(8) 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 13-10, plot the horizontal versus 

vertical span for steel davit arms.

Given:

Loadings: NESC Heavy Loading

Extreme Wind 19 psf on the wires

Wires:

Conductor: 477 kcmil, 26/7 ACSR 

OHGW: 3/8” H.S.S

Pole: S.Y.P. (70-1)

Conductor loads: Heavy Ldg Extreme wind EI&W

Transverse 0.6193 1.3585 0.8808

Vertical 1.5014 0.6570 2.4092

Manufacturers catalog data for crossarms:

Rated Ultimate 

Vert. load (Wc) s, length R, rise

3000 8.0 2.7

3000 7.0 2.5

Weight of insulators (Wi): 102 lbs.

FIGURE 13-10: TU-1 STRUCTURE

Solution:

For the 8.0' davit arm, the moment capacity 

of the arm at the pole (Figure 13-10a):

Ma = Maximum vertical load (s)

= (3000)(7.5)

= 22,500 ft-lbs.

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.

 (LF)pc(2.7ft)HS + (LF)wc(7.5ft)VS + (LF)wi(7.5ft) = φ (Ma)

2.5(0.6193)(2.7)HS+1.5(1.5014)(7.5)VS+1.5(102)(7.5) = (1.0)(22,500) ft-lbs.

 4.1803HS+16.89VS = 21,352.5 ft-lbs.

 VS = -0.25HS + 1264.2

R

s

.5'

Wc

FIGURE 13-10a: DAVIT 

7.0'

8.0'

14'

14'

14'
Bulletin 1724E-200

Page 13-27

For the 7.0' davit arm, the moment capacity of the arm at pole:

Ma = Wc(s)

= (3000)(6.5)

= 19,500 ft-lbs

An equation for the vertical and horizontal spans can be developed:

2.5(0.6193)(2.5)HS+1.5(1.5014)(6.5)VS+1.5(102)(6.5) = (1.0)(19,500) ft-lbs.

 3.87HS+14.64VS = 18,505.5 ft-lbs.

 VS = -0.26HS + 1264.0

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 13-11). For horizontal spans between 

300 and 1000 feet, the vertical span for the 8 foot arm as well as the 7 foot arm should be limited 

to 1004 feet (for design purposes, use 1000 feet). Spans limited by the extreme winds are not a 

factor in this example.

FIGURE 13-11: VS vs. HS FOR TUS-1 STRUCTURE OF EXAMPLE 13.4.4

e Design Calculations for Wood H-Frame Structures. 

(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).

• Finite element analysis

Computer-aided design programs are available that accomplish finite 

element analyses for structural design. These programs are acceptable for 

use as long as they are in accordance with RUS and NESC design criteria. 
Bulletin 1724E-200

Page 13-28

Outside

Kneebraces

Crossbraces

B F

C

A

D

E

As with any design methodology, use of these programs must be 

performed by competent engineering personnel.

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 

13-12.

FIGURE 13-12: 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 13-12. However, since the pole 

is tapered, the following relationship may be used to determine the 

location of the inflection point (see Figure 13-13, Equation 13-16 and 

Appendix H for application chart).

( )

( ) 2 2 2

2

A A D D

o A A D

C C C C

C C C

x

x

+ +

+ = Eq. 13-16

where:

CA = circumference at base

CD = circumference at top

FIGURE 13-13: LOCATION OF POINT OF CONTRAFLEXURE

X

o

CA

CD

X
Bulletin 1724E-200

Page 13-29 

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 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

increasing 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 13-12) is higher than the

point of inflection for four kneebraces. This higher point of

inflection increases the moment in the pole at the upper crossbracepole connection. For the H-frame with outside kneebraces only,

the designer may make one of two assumptions:

- 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. 

- 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.

(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, Xbrace 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).
Bulletin 1724E-200

Page 13-30 

45

The maximum compressive load which a wood X-brace is able to sustain 

is determined by:

( )

2

2





 kl 





=

r

A E Pcr

π Eq. 13-17

FIGURE 13-14: CROSSBRACE

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
Bulletin 1724E-200

Page 13-31

For an assumed 1 foot diameter pole, the following theoretical values 

apply:

TABLE 13-3

CROSSBRACE CAPACITIES

Crossbrace 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.)

TM-110

3-3/8" x 4-3/8" 14.77 0.9743 12.5 97.6 100.2 26,100

3-3/8" x 5-3/8" 18.14 0.9743 15.5 123.1 126.3 20,200

TM-110A

3-5/8" x 7-1/2" 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. Agency specifications for Double Armed and Braced Type 

Crossarm Assemblies (138 kV and 161 kV), and agency 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.

(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 V-braces increase both horizontal and 

vertical spans. The various bracing arrangements and their designations 

for 161 kV structures are shown in Figure 13-15.

FIGURE 13-15: POLE TOP BRACING ARRANGEMENTS

(‘X’ added to the pole top assembly nomenclature refers to crossbrace)

Agency 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:

TH-10 TH-10X TH-10VIX TH-10VOX TH-10V4X
Bulletin 1724E-200

Page 13-32

Maximum vertical load (at any conductor position)

TH-10 8,000 lbs.

TH-10VO 14,000 lbs.

TH-10V4 14,000 lbs.

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.

Agency 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.

(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 V-braces 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.
Bulletin 1724E-200

Page 13-33

The maximum vertical span is determined for the maximum horizontal 

span.

FIGURE 13-16: POLE TOP ASSEMBLY WITH TWO OUTSIDE BRACES

Ultimate force in the brace is:

( )

( ) lbs

b

LF Wt LF Pt a

+ ≤ ( )20,000 ⋅ sin

( )

sin

( ) φ

a a

Eq. 13-12

where:

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 Xbrace 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:

( )

( ) lbs

b

LF Wt LF Pt a ( )20,000. sin

( )

2sin

( ) φ

a a

+ ≤ Eq. 13-13

Crossarm bending moment, Mo (φ) is:

( )

2

( ) ( ) LF W b

M t φ o = Eq. 13-14

Wt

Pt o

a

b
Bulletin 1724E-200

Page 13-34 

Wt

t P

o

a

b

FIGURE 13-17: POLE TOP ASSEMBLY WITH INSIDE BRACES

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: 

lbs LF Wt 000,20)( sin

)( φ

≤ Eq. 13-15

Force in the inside braces is: 

( )

( ) lbs

b

LF Wt LF t aP 000,20)( sin

)(

2sin

)( φ

a a

+ ≤ from Eq. 13-13

(5) Abbreviations. In Equations 13-16 to 13-23, all units should be consistent. 

The following abbreviations apply: 

De = embedment depth

F = wind pressure on a cylindrical surface, psf

Fs = presumptive skin friction value, psf

HS = horizontal span, ft.

Ma = moment capacity of crossarm

Mn = moment capacity at the indicated location ‘n’, ft-lb. 

includes moment reduction due to bolt hole, 

i.e., Mn = Mcap-Mbh.

LF = load factor (see Chapter 11 of this bulletin)

Qu = ultimate bearing resistance of the soil, psf

Rn = reaction at the indicated location,"n," lbs.

U = dummy variable

V = dummy variable

Vn = induced axial force at the indicated location, lbs.

VS = vertical span, ft.

Wc = weight of conductors (plus ice, if any),lbs.

Wg = weight of OHGW (plus ice, if any),lbs.

Wi = total weight of the insulators

Wl-p = weight of a line person

Wp = weight of pole, lbs.

Wt = total weight equal to weight of conductors (plus ice, if

any, WC) plus weight of insulators,Wi. 
Bulletin 1724E-200

Page 13-35

W1 = total resistance due to skin friction around the 

embedded portion of the pole, lbs.

W2 = total bearing resistance of the soil, lbs.

X = dummy variable

Y = dummy variable

a = distance from Pt to the point of contraflexure above the 

crossbrace for an H-frame structure with pole top 

bracing. Ft.

b = spacing of the poles of an H-frame, ft.

davg = average diameter of pole between groundline 

and butt, ft.

dbt = diameter of pole at butt, ft.

dn = diameter at location "n,” ft.

dt = diameter of pole at top, ft.

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)
Bulletin 1724E-200

Page 13-36

b

Wt Wt Wt

h

t P

S

B B

A A

l h

(6) Equations for Structure 1 (Figure 13-18). 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.

( )( )( ) ( ) ( )( )( ) (0.90) 2

/

6

2 ( ) 1

2





 



















 + = − LF F h d d LF p h HS M t a t

A φ A Eq. 13-16 

( )( 3/ 2 ) RA = LF Wg + Wt +Wp Eq. 13-17

( )( )( )

w (s)(LF)

M LF W s VS

c

a − i = (φ) Eq. 13-18

FIGURE 13-18: STRUCTURE 1
Bulletin 1724E-200

Page 13-37

(7) Equations for Structure 2 (Figure 13-19).

( )( )( ) ( ) ( )( )( ) 1

2

1 /

6

2 ( ) LF p yLF F y d d HS M g

t b

B B 













 + = φ − Eq. 13-19a

( )( )( ) ( ) ( )( )( )

2

/

6

2 ( )

2

t e t o

E E

LF F y d d LF p y HS M 













 + = φ − Eq. 13-19b

( )( )( )( )( ) ( )( )( )

2

/

2 ( ) 1 1 LF F h x x d d LF p x HS M o t c t

D D 



 



 − + = φ − Eq. 13-19c

( )( )( )( )( ) ( )( )( )

2

/

2 ( ) o o t c t o

A A

LF F h x x d d LF p x HS M 



 



 − + = φ − Eq. 13-19d

For crossbrace:

( ( ) ( )( )( ) ( ) ) ( )( )( ) 2

2 HS ( )28,300 b 2 LF F h x 2d d / 6 / LF p h x = φ − − o t + c t Eq. 13-19e

For uplift:

HS(pt)(h2 )−VS(wg )(b)−1.5VS(wc )(b)= W1 (b)+Wp (b)+ X −Y Eq. 13-19f

For bearing:

HS(p )(h ) VS(w )(b) VS(w )(b) W (b) W (b) X Y (W )(b) t 2 g 5 c 2 p 1 + +1. = − + − + Eq. 13-19g*

where:

( )( ) / . . W1 = Fs De davg π S F Eq. 13-19h

( / 4)( )/ . . 2 W2 = π dbt Qu S F Eq. 13-19i

( )( )( )( ) o t c o X = F h − x d + d x Eq. 13-19j

2( )( ) (2 )/ 6 2

t a Y = F h d + d Eq. 13-19k

FIGURE 13-19: STRUCTURE 2

b

h

A

t

2 1

A

C C

D D

E E

B B y

y

1

x

x

1

o

P

h

yo

h
Bulletin 1724E-200

Page 13-38

(8) Equations for Structure 3 (Figure 13-20).

( )( )( )( )( ) ( )( )( )

2

/

2 ( ) 1 LF F y z d d LF p z HS M t b t

E E 



 



 + = φ − Eq. 13-20

HSD, HSA = same as structure #2.

For crossbrace, uplift and bearing: same as structure #2

FIGURE 13-20: STRUCTURE 3 FIGURE 13-21: STRUCTURE 4

(9) Equations for Structure 4 (Figure 13-21).

( )( )( )( )( ) ( )( )( )

2

/

2 ( ) 1 1 LF F y z d d z LF p z HS M t o t f

B B 













 − + = − Eq. 13-21

( )( )( )( )( ) ( )( )( )

2

/

2 ( ) o t f o t o

E E

LF F y z d d z LF p z HS M 













 − + = − Eq. 13-21

HSD, HSA = same as structure #2.

For uplift and bearing: same as structure #2.

For crossbrace:

HS ( (b) U V ) [(LF)(p )(h a)] x = (φ)28,300 − + / t 2 − Eq. 13-21c

where:

2( )( )( ) (2 )/ 6 2

o t c U = LF F h − x d + d Eq. 13-21d

2( )( )( ) (2 )/ 6 2

o t f V = LF F y − z d + d Eq. 13-21e

28,300 lb is the maximum load of the crossbrace equivalent to (20,000lb)*2cos(45°)

h h h

A

t

2 1

A

C C

D D

E E

B B

y

z

y

1

1

o

P

x

x b

b

h

A

t

2 1

A

C C

D D

E E

y B B

1

1

o

P

1

o

F F a z

y

z

x

x

h h
Bulletin 1724E-200

Page 13-39

(10) Equations for Structure 5 (Figure 13-22).

For crossbrace:

( ( ) ( )( )( ) ( ) ) [( )( )( )] 2

2 HS ( )56,500 b 2 LF F h x 2d d / 6 / LF p h x = φ − − o t + c t Eq. 13-22

FIGURE 13-22: STRUCTURE 5 FIGURE 13-23: STRUCTURE 6

(11) Equations for Structure 6 (Figure 13-23).

For crossbrace:

HS ( (b) U V ) [(LF)(p )(h a)] x = (φ)56,500 − + / t 2 − Eq. 13-23

where:

U, V = same as structure #4

h h h

t

2 1

1

o

P

y

b

o

x

x

h h h

t

2 1

1

0

P

b

0

1

a

x

x

z

z
Bulletin 1724E-200

Page 13-40

f Example of an H-frame Analysis. For the 161 kV structure shown in Figure 13-

24, determine the horizontal span based on structure strength and uplift and plot 

the horizontal versus vertical span for the pole top assembly.

FIGURE 13-24: EXAMPLE OF AN H-FRAME

(1) Given:

NESC heavy loading

Extreme winds - 19 psf on the wires and

22 psf on the structure

Extreme ice - 1" radial ice

Extreme ice with 

concurrent wind

1” radial ice with 4 psf wind

Pole: Douglas fir 80-2

Conductor: ACSR 795 kcmil 26/7

OHGW: 7/16 E.H.S.

Ruling Span: 800 ft.

Conductor Loads Heavy Ldg District Extreme Wind Heavy Ice EI&W

Transverse 

Loads

0.7027 lbs./ft. 1.7543 lbs./ft. 0 1.0360

Vertical Loads 2.0938 lbs./ft. 1.0940 lbs./ft. 3.7154 lbs./ft. 3.7154

Tension 10,400 lbs. --- 14,000 lbs XXXXX

OHGW Loads Heavy Ldg District Extreme Wind Heavy Ice EI&W

Transverse Loads 0.4783 lbs./ft. 0.6888 lbs./ft. 0 .8116

Vertical Loads 0.9803 lbs./ft. 0.3990 lbs./ft. 2.1835 lbs./ft. 2.1835

Tension 5,900 lbs. --- 7,500 lbs. XXXXX

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.

d = 7.96"

d = 8.81"

d = 9.19"

d = 9.65"

d = 11.33"

d = 13.00"

d = 15.64"

t

b

f

e

d

c

a

15.5'

70'

39.25'

23.95' 15.5'

15.3'

A

C

D

.75"

7.0'

7.5'

5.56'

2.19' 

3.52'

3.98'

Pt

E

B

F
Bulletin 1724E-200

Page 13-41

( )

( )

d . in.

z ft

z ft

z

z

z

d

d

z , z

d . in

x ft

x ft

x

x

x

d

d

f

o

o

o

e

d

o

c

o

o

o

a

d

and 919

3.52 .

3.98 .

0.53 7.5

0.53

.91

9.65

8.81

For :

and 130 .

15.3 .

23.9 .

0.61 39.25

0.61

0.72

15.64

11.33

1

1

1

=

=

=

=

∴ =

= =

=

=

=

=

∴ =

= =

(2) Solution for Heavy Loading District Loads. Maximum horizontal span based on 

structure strength:

(a) Equivalent Load pt:

(b) Determine location of equivalent load, pt:

(c) Determine location of x0, x1, and z1 for the X-brace location shown. All 

diameters, dn, determined by Appendix F, and ration x0/x1 or z0/z 

determined by Appendix H.

For x0, x1:

( ) ( )

3.065 / .

2 0.4783 3 0.7027

2 3

lbs ft

p p p t g c

=

= +

= +

( ) ( )

5.56 .

2 0.75 3 7.75

Distance from top g

ft

p

p p

t

c

=

+ =
Bulletin 1724E-200

Page 13-42

( )( )( )( )( ) ( )( )( )

( )( )( )( ) ( )( )

 2,133 .

2

2.5 3.065 3.52 /

2

2.5 4 15.25 3.98 0.663 0.766 3.52 (0.65)44,700

 44,700 .

2

/

2 ( ) 1 1

ft

HS

M ft lbs

LF F y z d d z LF p z HS M

B

B

t o t f

B B

=





 



 



 



 − + = −

= −

− + = φ −

( )( )( )( )( ) ( )( )( )

( )( )( )( ) ( )( )

 2,127 .

2

2.5 3.065 3.98 /

2

2.5 4 15.25 3.98 0.663 0.766 3.98 (0.65)(50,400)

 ( from Appendix F)

 50,400 .

 58,800 8,400 . .

 

2

/

2 ( )

ft

HS

M

M ft lbs

M ft lbs

M M M

LF F y z d d z LF p z HS M

E

bh

E

E

E cap bh

o t f o t o

E E

=





 



 



 



− +  = −

= −

= − −

= −

− + = φ −

HS ft

HS ft

A

D

1664

811 .

=

=

( ( ) ) [( )( )( )]

( )( )( ) ( )

( )( )( ) ( )

( )( )( ) ( ( ) )

( )( )( ) ( ( ) )

[ ( ) ] [( )( )( )]

 1009 .

(0.65)28,300 15.5 17,065 885 / 2.5 3.065 34.78

 885 .

2 2.5 4 15.25 3.98 2 0.663 .766 / 6

 17,065 .

2 2.5 4 70 23.9 2 0.663 1.083 / 6

2 2 / 6

2 2 / 6

where :

( )28,300 /

2

2

2

2

2

ft

HS

ft lbs

V

ft lbs

U

V LF F y z d d

U LF F h x d d

HS b U V OLF p h a

X

o t f

o t c

X t

=

= − +

= −

= − +

= −

= − +

= − +

= − +

= φ − + −

(d) Find the horizontal span limited by pole strength at B (see Figure 

13 – 23) using Equation 21a:

(e) Horizontal span limited by pole strength at E:

(f) For horizontal span limited by pole strength at locations D and A, 

similar calculations can be made. The results are as follows:

(g) For horizontal span limited by strength of the crossbrace:
Bulletin 1724E-200

Page 13-43

(3) Solution for Heavy Loading District Loads - Maximum span limited by 

pole top assembly follows.

(a)

(b)

(4) Solution for Heavy Loading District Loads - Maximum span limited by uplift 

follows. 

Assume dry native backfill, safety factor of 4.

( )

( )

( )

( ) ( )( )

( )( ) ( )( )( )

(For VS equal to the HS, the verticalspan is1,435 ft.)

2.49 4.48 10,000 .

(0.50)20,000 . 15.5sin39

2.5 3.065 2.19 3.52

2sin39

1.5 2.0938

( )20,000 . sin

( )

2sin

( )

From Equation13-13:

1938 .

2.0938 1.5

10,000sin 39 1.5 135

( )20,000. sin

( )

From Equation13-15.

VS HS lbs

lbs VS HS

lbs

b

LF W VS LF p a HS

ft

VS

lbs LF W VS

c t

t

+ ≤

≤ °

+

+ °

+ ≤

=

° − =

≤

φ

a a

φ

a

( )( ) ( )( ) ( )( ) ( ) ( )

( )( )

( )( )( )

( )( )( )

(For VS 0, maximum HS 830 ft.)

124.13 63.88 102,900

The equation is asfollows:

 17,182 .

2 2 / 6

 7705 .

 4200 800 2 4600 .

W Wt. of one pole and half the weight of pole top assembly and crossbrace.

 2649 .

/

where :

1.5

2

p

1

2 c 1

= =

− =

= −

= +

= −

= − +

= + =

=

=

=

− − = + + −

HS VS

ft lbs

Y F h d d

ft lbs

X F h x d d x

/ lbs

lbs

W F D d SF

HS p h VS w b VS w b W b W b X Y

t a

o t c o

s avg

t g p

π
Bulletin 1724E-200

Page 13-44

(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.

NESC > EI&W Vertical load: 2.0938(1.5)/.65 > 3.7154 lbs/ft 4.8318 > 3.7154 lbs/ft

(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.

(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 13-45

Blank Page
Bulletin 1724E-200

Page 14-1

14 GUYED STRUCTURES

a 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.
Bulletin 1724E-200

Page 14-2

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.

b 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 (See table 11-7 of 

this bulletin for φ )

Where:

a = Transverse wind load on the conductor

b = Transverse wind load on the pole

c = Transverse component of wire tension load.

Au = Rated anchor capacity

G = 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.

Gu = Rated breaking strength of the guy wire

φ = Strength factor; see table 11-6 and 11-7 of this bulletin

cosβ = Guy slope with horizontal groundline 

(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, 
Bulletin 1724E-200

Page 14-3

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).

(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.

c 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 14-4

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 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

Max. Operating Voltage, Phase to 

Phase, kV 34.5 46 72.5 120.8 144.9 169.1 241.5

Max. Operating Voltage, Phase to 

Ground, kV 19.9 26.6 41.8 69.7 83.7 97.6 139.4

Wind Condition Clearance, in.

NO WIND CLEARANCE

Min. clearance to guy at no wind

 (Notes A, B) 19 19 25 42 48 60 71

MODERATE WIND CLEARANCE 

(based on NESC Rule 235E, Table 

235-6)

Min. clear. to structure at 6 psf of 

wind (Notes C, D) 9 11 16 26 30 35 50

Min. clear. to jointly used structures 

and a 6 psf of wind (Notes C, 

D) 11 13 18 28 32 37 52

Min. clearance to anchor guys at 

6 psf (Notes C, D) 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 34.5 46 69 115 138 161 230

Clearance to structure 0 0 0.14 0.43 0.57 0.72 1.15

 Clearance to guy 0 0 017 0.53 0.72 0.90 1.44
Bulletin 1724E-200

Page 14-5

d Design

(1) Bisector Guys. For structures utilizing bisector guys, the guys have to be 

designed to sustain the resultant transverse load (c) due to longitudinal 

wire tension loads in Table 14-1, transverse load (a) due to wind on the 

conductors, and wind on the structure (b):

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.

(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.

e 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.

(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.
Bulletin 1724E-200

Page 14-6 

FIGURE 14-2: COMPARISON OF RODS TO SHOW 

STABILITY CONCEPT

 a b

(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 is 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. 

(3) Calculation of Buckling Loads. For long slender columns, the critical 

buckling load is determined by the general equation: 

(Pcr is independent of the yield 

stress of the material).

where:

Pcr = critical buckling load, lbs. or kips

E = modulus of elasticity, psi 4 I = moment of inertia, in

 kl = the effective unbraced length of the column; kl

depends on restraint end conditions of the 

column.

2

k)(

EI P

2

cr

π

=
Bulletin 1724E-200

Page 14-7

Where for the various end conditions of the column, Pcr is idealized in 

Figure 14-3 below:

FIGURE 14-3: EFFECTIVE UNBRACED LENGTH FOR VARIOUS END CONDITIONS

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.

(4) Buckling of Guyed Steel and Concrete Poles. For guyed steel and concrete 

poles, all the assumptions in paragraph 14.e.(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.

(5) Buckling of Guyed Wood Poles. For guyed wood poles, all the 

assumptions in paragraph 14.e.(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:

Conditions Fixed – Free End

Figure 14-3a

Fixed – Pinned End

Figure 14-3b

Pinned – Pinned End

Figure 14-3c

For a column with no 

taper 2

2

4

EI Pcr

π

= 2

2

cr

2 EI P



π = 2 

EI P

2

cr π=

a

P

b

P

c

P
Bulletin 1724E-200

Page 14-8 

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:

∗ CR = A PPP

where:

PA = Critical load for a uniform column with circular cross

sections having diameter d (at guy attachment), lbs.

∗ P = A multiplier dependent on the end conditions of the 

column, lbs.

E = Modulus of Elasticity, psi

AI = Moment of Inertia at the guy attachment, in4

dg = Diameter at the groundline, in.

a d = Diameter at the point of guy attachment, in.

l = Distance from the groundline to the point of guy 

attachment, in.

α = An exponent that is a function of shape of the column

For tapered round columns, the equations become: 

Conditions Fixed – Free End Fixed – Pinned End Pinned – Pinned End

For a tapered column 

(circular cross section)

- Fixed-Free End Pcr equation normally used for in-line tangent 

deadends with no side guys. Formula developed using shape 

factor, k = 2. (kl)

2 = (2l)2 = 4l2

. 

- Fixed-Pinned End Pcr equation normally used for in-line guyed 

poles at medium and large angle deadends. Formula developed 

using k = 0.7. (kl)

2 = (0.7l)2

 = 0.49l

2

, thus giving the “2” in the 

numerator. 

- Pinned-Pinned End Pcr equation normally used for bisector guys. 

Formula developed using k = 1.0. (kl)

2 = (1l)2

= l

2

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. 

2.7

a

A g

cr d

d

4

EI P 













 = 2

2



π 2.0

a

A g

cr d

EI d

P 













 = 2

2 2



π

2.0

a

A g

cr d

EI d

P 













 = 2

2



π

a















 =∗

a

g

d

d

P
Bulletin 1724E-200

Page 14-9

Bisector Guyed Structure In-line Guyed Structure

End Conditions

Buckling Mode Bisector Guyed In-Line Guyed

pinned-pinned pinned-fixed

pinned-fixed pinned-fixed

Longitudinally

Transversely pinned-fixed

pinned-pinned pinned-fixed

Bisector Guyed In-Line Guyed Buckling Mode

End Conditions

Bisector Guyed Structure In-line Guyed Structure

Transversely

Longitudinally

pinned-fixed pinned-fixed

pinned-pinned pinned-fixed

Bisector Guyed In-Line Guyed Buckling Mode

End Conditions

Bisector Guyed Structure In-line Guyed Structure

Transversely

Longitudinally

pinned-fixed pinned-fixed

pinned-pinned pinned-fixed

Bisector Guyed In-Line Guyed Buckling Mode

End Conditions

Bisector Guyed Structure In-line Guyed Structure

a b

(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.

FIGURE 14-4a 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. 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.

 FIGURE 14-5: AXIAL LOADS INDUCED IN A POLE
Bulletin 1724E-200

Page 14-10

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.

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 on the 

component pole.

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 

a b

c
Bulletin 1724E-200

Page 14-11

groundline and will reduce the cost of foundations. The engineer should 

also consider the case of guyed small angle structures where the wind load 

applied on the conductors in the direction of the guys could cause 

unbalanced load conditions.

f 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.

(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.

(2) Plate Anchors. The plate anchor assemblies TA-2P and TA-3P in 

Bulletins 1728F-810 and 811, are rated at an ultimate holding power of 

16,000 lbs and 24,000 lbs, respectively. In firm soils, where the engineer 

would like to minimize digging, plate anchors may prove economical.

(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 TA4H 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).

g 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. The Guying Guide 

drawing should also show (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.
Bulletin 1724E-200

Page 14-12

h Guying Example Problem.

(1) Single pole guying example problem.

(a) Given Information. Assume that an RUS standard TS-4A (115 kV, 

Suspension Angle), three-phase, pole-top assembly needs to be 

constructed at a line angle (θ) of 30 degrees. (Fig. 14-7) The 

assembly is to be installed on an 80 ft., class 1 Southern Yellow 

Pine pole. The phase conductors are 556.5 kcmil (26/7) ACSR 

with a 7/16 EHS shieldwire. One-half the sum of the adjacent 

spans (HS) is 400 feet. For purposes of illustration for this 

example, calculations will be shown for four (4) standard RUS 

down guy assemblies used with four (4) standard RUS anchor 

assemblies. NESC Grade B construction is to be used and the pole 

is located in the NESC Heavy loading district.

(b) Statement of Problem. Determine the loads that the bisector guy 

and anchor assemblies need to hold, and subsequently determine 

the adequate standard RUS assemblies that should be used for this 

example. In addition, determine if the buckling capacity of the 

pole is adequate.

Tabulation of Data:

Pole Data: RUS Data:

Lp = 80 ft (length of pole) F = 4 lb/ft2 (Table 11-1)

h = 70 ft (height above ground) Fw = 2.5 = Wind Load Factor (Table 11-6)

Lg = 10 ft (bottom to ground line) Ft = 1.65 = Tension Load Factor (Table 11-6)

dt = 8.6 in (diameter at top) Fv = 1.5= Vertical Load Factor (Table 11-6)

dg = 16.9 in (diameter at ground line) wC = wind on conductor, lb/ft

wV = vertical weight of conductor, lb/ft 

Conductor Data – NESC Heavy Loading District 

Conductor Wc (lb/ft) Wv, (lb/ft) Tc (lb)

556.5 kcmil 0.6423 1.6533 7,500

7/16 EHS 0.4783 0.980 45,900

Conductor Attachment Heights: (TS-4A), (Center of brackets from top of pole)

Shieldwire = 0.6 ft ( = 69.4 ft from groundline)

Top (A) Phase = 9.0 ft ( = 61 ft from groundline)

Middle (B) Phase = 18.0 ft ( = 52 ft from groundline)

Bottom (C) Phase = 27.0 ft ( = 43 ft from groundline)

Guy Assembly Attachment Heights: (TS-4A), (From top of pole)

Shieldwire = 2.0 ft ( = 68.0 ft from groundline) 

Top (A) Phase = 9.25 ft ( = 60.75 ft from groundline) 

Middle (B) Phase = 18.25 ft ( = 51.75 ft from groundline) 

Bottom (C) Phase = 27.25 ft ( = 42.75 ft from groundline) 
Bulletin 1724E-200

Page 14-13

Figure 14-7: Structure TS-4A 

(c) Calculations.

(1) Wind Load on the Pole Surface (b): 

( ) 2

72

(2 ) h

d d

M F t g

wp 



 



 + = (EQ 13-2)

 2 (70) 72

((2)(8.6) 16.7) (4) 



 



 + =

 = 9,228 ft – lb

Determine wind load per guy attachment:

- Divide wind moment load for the pole by the number of guy attachments

- 9,228 ft–lb/ 4 guys = 2,307 ft-lb per guy

Determine force on each guy (b) due to wind on pole moment by dividing 

wind pole moment by height of guy attachment above ground:

- bSW = 2,307 ft-lb/68.0 ft = 34 lb

- bA = 2,307 ft-lb/60.75 ft = 38 lb

- bB = 2,307 ft-lb/51.75 ft = 45 lb

- bC = 2,307 ft-lb/42.75 ft = 54 lb

C

B

A

SW

TS-4A

80 ft Class 1, SYP

30◦

Line Angle

68.0’

60.75’

51.75’

35.0’

Guy attachment 

height above 

ground

45.0’ 55.0’ 60.0’

Guy lead distance from pole

βC

42.75’

βB βA βSW
Bulletin 1724E-200

Page 14-14

(2) Transverse wind load on conductor and neutral, a: 

a = (Wc) (HS)(cos θ/2) (Para. 14.d.(1))

aA = aB = aC = (0.6423 lb/ft)(400 ft)(cos 15°) = 249 lb

aSW = (0.4783 lb/ft)(400 ft)(cos 15°) = 185 lb

(3) Transverse wire tension, c:

c = 2 (Tc)(sin θ/2) (Para. 14.d.(1))

cA = cB = cC = 2 (7,500 lb)(sin 15°) = 3,883 lb

cSW = 2 (5,900 lb) (sin 15°) = 3,054 lb

(4) Calculate horizontal guying, Gh, load at each guy 

attachment 

 

Gh = Fw (a + b) + Ft c = G (cos β) ≤ 0.65 GU (cos β) (See Table 14-1)

 G = Guy load, lb; GA = load in guy A, for example

 GU = Rated breaking strength of the guy wire, lb

Gh = Horizontal guy load, lb

GhA = Horizontal guy load at attachment A, for example

β = Guy angle relative to the ground, degrees

 

Note: NESC Load Factors for Grade B construction are included in these 

calculations.

GhSW = 2.5 (185 lb + 34 lb) + 1.65 (3,054 lb) = 5,587 lb = GSW (cos βSW)

GhA = 2.5 (249 lb + 38 lb) + 1.65 (3,883 lb) = 7,125 lb = GA (cos βA)

GhB = 2.5 (249 lb + 45 lb) + 1.65 (3,883 lb) = 7,142 lb = GB (cos βB)

GhC = 2.5 (249 lb + 54 lb) + 1.65 (3,883 lb) = 7,165 lb = GC (cos βC)

tan β = (Guy attachment height above ground) ÷ (Guy lead distance from pole)

 β = tan-1 (Guy attachment height above ground) ÷ (Guy lead distance from pole)

βSW = tan-1 (68 ft) ÷ (60 ft) = 48.6°

βA = tan-1 (60.75 ft) ÷ (55 ft) = 47.8°

βB = tan-1 (51.75 ft) ÷ (45 ft) = 49.0°

βC = tan-1 (42.75 ft) ÷ (35 ft) = 50.7°

(5) Calculate force in each guy 

GhSW = GSW (cos βSW), or GSW = GhSW ÷ cos βSW

GSW = GhSW ÷ cos βSW = 5,587 lb ÷ cos 48.6° = 8,448 lb

GA = GhA ÷ cos βA = 7,125 lb ÷ cos 47.8° = 10,607 lb

GB = GhB ÷ cos βB = 7,142 lb ÷ cos 49.0° = 10,886 lb

GC = GhC ÷ cos βC = 7,165 lb ÷ cos 50.7° = 11,312 lb
Bulletin 1724E-200

Page 14-15

(d) Selection of Guying Components.

(1) Select guy attachment, guy wire, and anchor.

- Guy Attachment capacity

- Guy wire capacity, GU, and

- Anchor capacity, AU, 

Each of these must be greater than guy force, G.

(2) Selection of Guy Attachment.

Based on the calculations above, the horizontal loads at the 

guy attachments on the pole are the following:

- GhSW = 5,587 lb

- GhA = 7,125 lb

- GhB = 7,142 lb

- GhC = 7,165 lb

Since these calculated loads include the appropriate load 

factors, they can be compared to the permitted loads of the 

guy attachments. The permitted loads must be greater than 

the calculated loads.

Guy attachments are typically dead end tees, pole bands, or 

pole eye plates. See RUS guy attachment details in RUS 

Bulletins 1728F-810 and -811. The load rating of the 

actual guy attachment used shall be multiplied by the RUS 

strength factor of 0.65 to determine the permitted load. The 

permitted load rating must be greater than the calculated 

load for that guy attachment. Assume a medium duty 

guying tee rated at 25,000 lb horizontal load. (See TG-25, 

RUS Bulletin 1728F-811.)

- GhA ≤ 0.65 (Horizontal Rated Load of Guy 

Attachment)

- 7,125 lb ≤ 0.65 (25,000 lb)

- 7,125 lb ≤ 16,250 lb

- Guy attachment is adequate

- A similar analysis will reveal that this guy 

attachment is adequate at the other guy attachment 

points also.
Bulletin 1724E-200

Page 14-16

(3) Selection of Guy Wires.

Based on the calculations above, the loads in the guys are 

the following:

- GSW = 8,448 lb

- GA = 10,607 lb

- GB = 10,886 lb

- GC = 11,312 lb

Since these calculated loads include the appropriate load 

factors, they can be compared to the permitted load of the 

guy wire. The permitted load must be greater than the 

calculated load. As indicated in Table 14-1, the permitted 

load of the guy wire is obtained by multiplying the rated 

breaking strength by 0.65.

For this example, 7/16 EHS wire has been assumed for the 

guy wire with a rated breaking strength of 20,800 lb. From 

Table 14-1 of this bulletin, we know that the load in each of 

the guy wires must be less than the permitted load on the 

guy wire.

Using guy A as an example:

GA ≤ 0.65 GU, where GU = the rated breaking strength of 

the guy wire

10,607 lb ≤ 0.65(20,800 lb) 

10,607 lb ≤ 13,520 lb

Therefore, 7/16 EHS wire is adequate for guying at 

attachment A. A similar analysis will reveal that 7/16 EHS 

wire is adequate for guying at the other attachment points.

(4) Selection of Anchors.

Repeating the guy loads used above:

- GSW = 8,448 lb = ASW = required anchor capacity for 

shieldwire guy

- GA = 10,607 lb = AA= required anchor capacity for guy A

- GB = 10,886 lb = AB = required anchor capacity for guy B

- GC = 11,312 lb = AC = required anchor capacity for guy C

Since these calculated loads include the appropriate load 

factors, they can be compared to the permitted load of the 

anchors. From Table 14-1, the permitted load for an anchor 

is equal to 0.65 times the rated anchor capacity. For this 

example, the anchor for guy A:
Bulletin 1724E-200

Page 14-17

- AA ≤ 0.65 AU, where AU = the rated anchor capacity

- Using an AU = 20,000 lb for a power installed screw 

anchor

- 10,607 lb ≤ 0.65 (20,000 lb)

- 10,607 lb ≤ 13,000 lb

- Therefore, the 20,000 lb-rated power installed screw 

anchor is adequate for guys A, B, C, and the 

shieldwire guy. For the shieldwire guy, a 16,000 lbrated anchor could be used. For ease of 

construction, a 20,000 lb-rated anchor could be used 

for the conductors and shieldwire guys.

Anchors should always be installed in accordance with the 

manufacturer’s recommendations. An engineering 

evaluation should be made to determine if soil conditions 

are adequate to provide the required anchor resistance.

(e) Selection of pole class.

As presented in para. 14.e.(5), the column strengths of wood poles 

at guyed locations should be examined for their ability to sustain 

loads due to the vertical weight of the conductors, equipment, and 

the vertical component of the load supported by the guys. 

In this example, the bisector guyed pole is assumed to be in the 

Pinned – Pinned End condition and the following formula is used 

to calculate the critical buckling axial load, or Pcr:

PPcccc = �

ππ2EEIIaa

ll2 � · �

ddgg

ddaa

�

2.0

 (Para. 14.e.(5))

where:

E = Modulus of Elasticity

IA = Moment of Inertia at the lowest guy attachment, in4

dg = Diameter at the groundline, in.

da = Diameter at the point of lowest guy attachment

ll = Distance from the groundline to the point of lowest guy 

attachment, in.

wVC = Weight of conductor, lb/ft

wVSW = Weight of shieldwire, lb/ft

(1) Determine the vertical load on the pole.

- Determine the weight of the conductors and shieldwire, 

WVT, and vertical guying load on pole
Bulletin 1724E-200

Page 14-18

-WVT = Weight of conductors and shieldwire = FV [HS(3(wVC) + 1(wVSW))]

-WVT = 1.5[400( 3 (1.6533) + 1 (0.9804))]

-WVT = 3,564 lb

- Note: NESC Load Factor (FV) for Grade B construction is included in 

this calculation.

(2) Calculate vertical guying load at each guy attachment.

 GV = Vertical Guying Load at each guy = G × sin β

 GVSW = GSW × sin βSW = 8,448 lb × sin 48.6° = 6,337 lb

 GVA = GA × sin βA = 10,607 lb × sin 47.8° = 7,858 lb

 GVB = GB × sin βB = 10,886 lb × sin 49.0° = 8,216 lb

 GVC = GC ÷ sin βC = 11,312 lb ÷ sin 50.7° = 8,754 lb

Guy Attachment Load in Guy, G, lb Vertical Guy Load at 

Attachment, Gv, lb

SW 8,448 6,337

A 10,607 7,858

B 10,886 8,216

C 11,312 8,754

31,165 lb = Total 

- Total Vertical Load on Pole = WVT + Total Vertical Guying 

Load

- Total Vertical Load on Pole = 3,564 lb + 31,165 lb = 34,729 lb

- Calculate Pcr of 80 ft, Class 1 Southern Yellow Pine Pole in 

this guying configuration

- PPcccc = �

ππ2EEIIaa

ll2 � · �

ddgg

ddaa

�

2.0

- E = 1,800,000 psi

- Iaa = ππddaa

4

64

= 939 in4

- dg = 16.72 in

- da = 11.76 in

- l = 42.75 ft = 513 in

PPcccc = �

ππ2(1.8)(106)(939)

(513)2 � · �

(16.72)

(11.76)

�

2.0

Pcr = 128,133lb

- Total Vertical Load on Pole < 0.65 Pcr

- 34,729 lb < 0.65(128,133 lb) 

- 34,729 lb < 83,286 lb

- Vertical capacity of 80 ft, Class 1 Southern Yellow Pine is 

adequate
Bulletin 1724E-200

Page 14-19

(2) Moving Guys Closer to Poles and Structures. It is important to understand 

the process that must be used if guys are moved closer to a pole or 

structure. This causes the guy angle, β, with respect to the ground to 

increase and causes an increase of forces on guying components. The 

permitted load for a component of the guying system may be exceeded. 

Other concerns include pole splitting that may result if increased vertical 

loads exceed wood strength. In such cases alternatives may need to be 

considered that would support the increased loads. A list of possible 

alternatives includes, but is not limited to:

o Higher strength attachment hardware

o Split guys

o Wood poles with greater strength

o Non-wood structures

o Change structure type

o Self-supporting structure
Bulletin 1724E-200

Page 14-20

Blank Page
Bulletin 1724E-200

Page 15-1

15 HARDWARE

a 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.

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.

b Conductor-Related Hardware. 

(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.
Bulletin 1724E-200

Page 15-2 

FIGURE 15-1: SUSPENSION CLAMP WITH CLEVIS OR 

 BALL AND SOCKET TYPE OF CONNECTION

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.c). 

(2) Clamp Top Clamps. Clamp top clamps for vertical and horizontal post 

insulators are popular because 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. 



U bolt
Bulletin 1724E-200

Page 15-3

(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

(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. 
Bulletin 1724E-200

Page 15-4

FIGURE 15-4a: TYPICAL BOLTED DEADEND CLAMP

FIGURE 15-4b: TYPICAL COMPRESSION DEADEND

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.

(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.

30°

30°
Bulletin 1724E-200

Page 15-5

(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.

(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 (CIS) are recommended to 

prolong the life of the insulator pins. Use of CIS provides 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.

FIGURE 15-5: SUSPENSION INSULATORS 

(Ball and Socket Type, Left, and Clevis-Eye Type, Right)

(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.
Bulletin 1724E-200

Page 15-6 

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 15-7

c Conductor Motion Hardware.

(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:

• Alleviates changes of mechanical stress buildup at the point of 

support by providing a gentler slope of curvature for the incoming 

conductor, • Increases conductor life from fatigue failure by increasing the 

flexural rigidity of the conductor, and reducing bending stresses in 

the conductor, • Protects 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.

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.

Armor Rod
Bulletin 1724E-200

Page 15-8

FIGURE 15-10a:

CUSHIONED SUSPENSION 

UNIT

FIGURE 15-10b:

DOUBLE CUSHIONED SUSPENSION 

(For Line Angles Greater Than 30o)

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 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. 

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.

Damper Clamp Conductor

Damper Weight Damper Cable Drain Hole

Tapered Sleeve
Bulletin 1724E-200

Page 15-9

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.

(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.

(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 closed-coil 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.

(4) Insulator Swing. Occasionally, tie-down weights are used to control 

conductor position by preventing excessive uplift and swinging. A line 
Bulletin 1724E-200

Page 15-10

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.

FIGURE 15-13: DISC WEIGHTS (Left), BALL WEIGHTS (Right)

d Structure Related Hardware for Wood Structures.

(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 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.

FIGURE 15-14: FASTENERS

Machine Bolt

Static Proof Bolt 

With Forged Washer 

Nut

Shoulder Eye Bolt

with Curved 

Washer

Double Arming Bolt,

Fully Threaded

Static Proof Double End 

Bolts with M/F 

Locknuts

MF type Locknut

Static Proof 

Double Arming Bolts 

Attach to the suspension 

clamps via hold down 

shackles

Static Proof Double End

Bolts 
Bulletin 1724E-200

Page 15-11

TABLE 15-1

STRENGTHS OF MACHINE BOLTS, DOUBLE ARMING 

BOLTS, AND DOUBLE END BOLTS 

(Ref: ANSI C135.1, Table 10)

Machine Bolt

Diameter

in.

Tensile

Stress Area

sq. in.

Minimum Tensile

Strength

lbs.

1/2 0.142 7,800

5/8 0.226 12,400

3/4 0.334 18,350

7/8 0.462 25,400

1 0.606 33,500

Lag screws (Figure 15-15) 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.

(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.

FIGURE 15-16: GRID GAINS

Grid Gains Application of Grid Gains
Bulletin 1724E-200

Page 15-12

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.

FIGURE 15-17: SPACER FITTING, REINFORCING PLATE

AND GAIN PLATE

(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 can 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.

FIGURE 15-18: SMALL ANGLE

STRUCTURE WITH SWING 

ANGLE BRACKETS

Spacer Fitting Reinforcing Plate

and Gain Plate
Bulletin 1724E-200

Page 15-13

(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.

(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 as 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 HEAT TREATED, HIGH STRENGTH BOLTS 

(Ref: ASTM A325, Table 4)

Machine Bolt

Diameter

in.

Tensile

Stress Area

sq. in.

Minimum Tensile

Strength

lbs.

Minimum Yield

Strength

lbs.

1/2 0.142 17,500 13,050

5/8 0.226 27,100 20,800

3/4 0.334 40,100 30,700

7/8 0.462 55,450 42,500

1 0.606 72,700 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 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 

manufacturer 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:
Bulletin 1724E-200

Page 15-14

• 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.

(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

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). 

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.

Silver +.79

Copper +.34

Lead -.13

Tin -.15

Iron -.35

Chromium -.47

Zinc -.77

Aluminum -1.337
Bulletin 1724E-200

Page 15-15

Blank Page
Bulletin 1724E-200

Page 16-1

16 UNDERBUILD

a 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.

Among the factors that should be considered in designing a common use line are 

design loads and clearance requirements added to the structures by the additional 

circuits, 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.

b 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.

c 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. 

d 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.

e 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 
Bulletin 1724E-200

Page 16-2

to be able to access and work on the distribution underbuild without encroaching 

upon the required safety (zone) clearances of the transmission conductors.

(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.

(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).

(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.

1' min. if 

possible

1' min. if 

possible

Dv

FIGURE 16-1:

HORIZONTAL SEPARATION

REQUIREMENTS BETWEEN

TRANSMISSION AND UNDERBUILD

FIGURE 16-2:

VERTICAL SEPARATION

REQUIREMENTS AT STRUCTURE 

FOR UNDERBUILD
Bulletin 1724E-200

Page 16-3

If the transmission line or portion thereof is at an altitude which is greater 

than 3,300 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).

(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 16-4

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 kVL-L 34.5 46 69 115 138 161 230

Max. Operating Voltage, Phase to Phase kVL-L 36.2 48.3 72.5 120.8 144.9 169.1 241.5

Max. Operating Voltage, Phase to Ground kVL-G 20.2 27.9 41.8 69.7 83.7 97.6 139.4

Vertical Clearances Between Transmission and 

Distribution Conductors Clearances in Feet

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)

4.7 5 5.4 6.4 6.8 7.3 8.7

b. 34.5 kV 4.9 5.2 5.6 6.5 7.0 7.5 8.9

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)

3.7 3.8 4.2 5.2 5.6 6.1 7.5

b. 34.5 kV 3.8 4.0 4.3 5.4 5.8 6.3 7.7

Vertical Clearances Between Transmission 

Conductors and Distribution Structures (See Table 4-2)

ALTITUDE CORRECTION TO BE ADDED TO VALUES ABOVE

Additional feet of clearance per 1000 feet 

of altitude above 3300 feet

0.02 0.02 0.05 0.06 0.08 0.12

Note:

(A) An additional 0.5 feet of clearance is added to the NESC clearance to obtain the recommended design 

clearances.

(B) Values for lines 1.a and b are based on Equation 6.2:

V (kV kV ) (NoteA) LG LG 12

6 8.7

12

.4

12

40 = + 1 + 2 − +

where:

kVLG1 = Line to ground voltage circuit one, kilovolts.

kVLG2 = Line to ground voltage circuit two, kilovolts.

(C) Values for Lines 2.a and b are based on Equation 6.2a:

V (kV kV ) (NoteA) LG LG 12

6 50

12

.4 (50 8.7) 12.4

12

40 .75 + 1 + 2 − + 



 



 = + −
Bulletin 1724E-200

Page 16-5

(5) Span Length and Clearance to Underbuild. The conditions of either 

Paragraph 16.e.(2) or Paragraph 16.e.(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.e.(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.

The formula for maximum span as limited by clearance to underbuild is:

Eq. 16-1

where:

Lmax = maximum span in feet

RS = ruling span in feet

A = allowable separation at midspan in feet

B = vertical separation at supports in feet

Sl = underbuild sag at the same ambient temperature as the 

transmission conductor, final, in feet

Su = transmission conductor sag at condition resulting in 

least separation to underbuild, final sag, in feet

f 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.

g 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 

( ) u

ma x S S

A B L RS −

− =


Bulletin 1724E-200

Page 16-6

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. 

h 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:

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.

FIGURE 16-3: USE OF A SEPARATE POLE TO MOUNT

 A DISTRIBUTION TRANSFORMER

i 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.

FIGURE 16-4: GUYING DISTRIBUTION UNDERBUILD

For winds perpendicular to the transmission line, the guying described in Figure 

16-4 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. 

• Large Line Angles • Substation Approaches

• Deadends • Transformers or Regulators (Figure 16-3)

• Tap-offs • Capacitors

• Sectionalizing Structures

M P

Tension due to

vertical loading

only

Guy

Sketch (b)

Transmission Line

Distribution

N

Sketch (a)

x

x

Transformer 

Pole

(See Table 4-2 

for Clearance)

(See Table 4-2 

Transformer 

(See Table 4-2 

Transformer 
Bulletin 1724E-200

Page 16-7

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 Tables 4-2 and 5-1 should be met. 

j 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.

(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 1⁄2” 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

Distribution Conductor

4/0 6/1 ACSR

Loading 

Condition

Final sag 

(ft.)

Ambient Temp. Final sag (ft.)

(a) 32oF, 1/2” ice 4.40 0°F 1.60

(b) 212oF 6.73 0°F 1.60

(c) 212oF 6.73 90°F 3.98
Bulletin 1724E-200

Page 16-8

(2) Solution.

From Table 16-1 the required vertical clearance at midspan between the 

transmission and distribution conductors is 4.2 feet. 

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:

Eq. 16-1

Substituting:

RS = 300

A = 4.2

B = 11

Sl = 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.c of this 

manual.

( ) u

ma x S S

A B L RS −− =



( ) 1.60 6.73

4.2 11 300 −

− = ma x L
Bulletin 1724E-200

Page 16-9

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

TRANSMISSION LINE DESIGN

DATA SUMMARY

I. GENERAL INFORMATION

BORROWER: DATE:

LINE IDENTIFICATION:

VOLTAGE 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

SIZE (kcmil or in.)

STRANDING

MATERIAL

DIAMETER (in)

WEIGHT (lbs./ft.)

RATED STRENGTH (lbs.)

III. DESIGN LOADS (Wires) TRANSMISSION

(lbs./ft.)

OHGW

(lbs./ft.)

UNDERBUILD

(lbs./ft.)

COMM.NEUTRAL

(lbs./ft.)

NESC:__________________LOADING DISTRICT

a. ICE: _________in. Vertical.

b. WIND ON ICED COND. ____psf Transverse

c. CONSTANT K ___________ Resultant + K

HEAVY ICE(NO WIND) ______in. Vertical.

HIGH WIND(NO ICE) ______psf Transverse

EXTREME ICE w/ CONCURRENT WIND

 ICE: _________in. Vertical.

 WIND ON ICED COND. ____psf Transverse

IV. SAG & TENSION DATA

SPANS AVERAGE(EST) ___________ft MAXIMUM(EST) ___________ft.. RULING(EST) ____________ft.

SOURCE OF SAG-TENSION DATA: TRANSMISSION OHGW UNDERBUILD COMM.NEUTRAL

TENSIONS (% RATED STRENGTH) INITIAL FINAL INITIAL FINAL INITIAL FINAL INITIAL FINAL

NESC a. UNLOADED (0 ̊ 15 ̊ 30 ̊) _____ ̊F

NESC b. LOADED (0 ̊ 15 ̊ 30 ̊) _____ ̊F

MAXIMUM ICE 15  ̊F

HIGH WIND (NO ICE) 60 ̊F 

UNLOADED LOW TEMPERATURE _____ ̊F

SAGS (FT)

NESC DISTRICT LOADED _____ ̊F 

UNLOADED HIGH TEMP(120 ̊FOR OHGW &U.B.)___ ̊F

MAXIMUM ICE 15 ̊F

LOADED 1/2” ICE, NO WIND 15 ̊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 

TYPE

STRUCTURE 

DESIGNATION

NO. OF BELLS /

POLYMER /

PIN OR POST

60 HZ DRY 

FLASHOVER

INSULATOR SIZE

(DIAMETER & 

LENGTH)

SML / M & E 

RATING / POST 

STRENGTH

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. 

TYPE

NO. OF 

INSULATORS.

6 psf MIN. 

WIND(1)

HIGH WIND (2) NO WIND OTHER

X. ENVIRONMENTAL AND METEORLOGICAL DATA

TEMPERATURE: MIN__________ ̊ MAX.__________ ̊

AVERAGE YEARL LOW _____________ ̊

EXTREME 10 SEC. WIND GUSTS (mph):

10 YR. ___________ 50 YR.__________ 100 YR___________

MAXIMUM HEIGHT OF SNOW ON THE GROUND

UNDER THE CONDUCTOR(ft.):

DESCRIBE TERRAIN AND CHARACTERISTICS OF SOIL

CORROSIVENESS OF ATMOSPHERE:

XI. STRUCTURE DATA (FOR SINGLE POLES AND H-FRAMES)

POLE MATERIAL:_____________________________ 

ARM MATERIAL: Trans_________________________

 Underbuild_________________________

TYPE OF FOUNDATION: TANGENT:____________ANGLE:____________

DEADEND_________________GUYED STRUCTURES____________

TANGENT STRUCTURE TYPE___________________

SUMMARY OF SPANS (ft.) FOR TANGENT STRUCT.

BASE POLE

_____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 

FOR BASE POLE:_____________________________

PRESERVATIVE OF WOOD POLE (TYPE &RETENT.)_______________________

CORROSION PROTECTION FOR STEEL POLES ___________________________

GUYING: TYPE OF ANCHOR AND R.B.S.: ___________________________ GUY SIZE AND R.B.S.:________________________________

XII. LINE DESCRIPTION

TANGENTS__________________% LIGHT ANGLES ______________%

AVERAGE NUMBER OF 

LINE ANGLES PER mi. ______________________

MEDIUM ANGLES____________%

DEADEND & 

HEAVY ANGLES______________%

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 applicable)

LENGTH – Self-explanatory.

TYPE OF TANGENT STRUCTURE – Give agency designation for predominant 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.

EXTREME ICE with CONCURRENT 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 transverse 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.b.(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.
Bulletin 1724E-200

Page A-9

c. 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.

d. 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.

e. 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.

f. 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. 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. Description of methodology used to perform design. If computer aided design 

program is used, give name of program.

E. Selection of conductor and OHGW

1. Selection of conductor and OHGW type

2. Selection of conductor and OHGW size/

Economic conductor analysis

F. Determination of maximum conductor temperature 

G. Selection of structure type and average height

1. Economic evaluation of alternate structures

2. Selection of optimum structure height

H. Construction cost estimate

III. 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

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

J. 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-9
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

LIGHT MEDIUM HEAVY

.00" ICE, 9 LB., K=.05 .25" ICE, 4 LB. WIND, K=.20 .5" ICE, 4 LB. WIND, K=.30 ULTIMATE

VERT. TRANS RESULTANT VERT. TRANS RESULTANT VERT. TRANS RESULTANT STRENGTH DIAM. WT./FT.

NAME SIZE STRAND LB/FT. LB/FT. LB/FT. LB/FT. LB/FT. LB/FT. LB/FT. LB/FT. LB/FT. LBS. IN. LBS.

RAVEN 1/0 6/1 0.1452 0.2985 0.3819 0.3467 0.2993 0.6580 0.7036 0.4660 1.1439 4380 0.398 0.1452

QUAIL 2/0 6/1 0.1831 0.3353 0.4320 0.3998 0.3157 0.7094 0.7719 0.4823 1.2102 5310 0.447 0.1831

PIGEON 3/0 6/1 0.2309 0.3765 0.4917 0.4647 0.3340 0.7723 0.8539 0.5007 1.2899 6620 0.502 0.2309

PENGUIN 4/0 6/1 0.2911 0.4223 0.5629 0.5439 0.3543 0.8491 0.9520 0.5210 1.3853 8350 0.563 0.2911

WAXWING 266.8 18/1 0.2894 0.4568 0.5907 0.5565 0.3697 0.8681 0.9789 0.5363 1.4162 6880 0.609 0.2894

PARTRIDGE 266.8 26/7 0.3673 0.4815 0.6556 0.6446 0.3807 0.9486 1.0774 0.5473 1.5084 11300 0.642 0.3673

MERLIN 336.4 18/1 0.3653 0.5130 0.6798 0.6557 0.3947 0.9653 1.1015 0.5613 1.5363 8680 0.684 0.3653

LINNET 336.4 26/7 0.4630 0.5408 0.7619 0.7649 0.4070 1.0664 1.2222 0.5737 1.6501 14100 0.721 0.4630

ORIOLE 336.4 30/7 0.5271 0.5558 0.8160 0.8352 0.4137 1.1320 1.2987 0.5803 1.7225 17300 0.741 0.5271

CHICKADEE 397.5 18/1 0.4316 0.5573 0.7548 0.7403 0.4143 1.0484 1.2045 0.5810 1.6373 9940 0.743 0.4316

IBIS 397.5 26/7 0.5469 0.5873 0.8525 0.8680 0.4277 1.1677 1.3446 0.5943 1.7701 16300 0.783 0.5469

LARK 397.5 30/7 0.6228 0.6045 0.9179 0.9511 0.4353 1.2460 1.4348 0.6020 1.8560 20300 0.806 0.6228

PELICAN 477. 18/1 0.5180 0.6105 0.8506 0.8488 0.4380 1.1551 1.3350 0.6047 1.7656 11800 0.814 0.5180

FLICKER 477. 24/7 0.6145 0.6345 0.9333 0.9552 0.4487 1.2554 1.4514 0.6153 1.8765 17200 0.846 0.6145

HAWK 477. 26/7 0.6570 0.6435 0.9696 1.0015 0.4527 1.2990 1.5014 0.6193 1.9241 19500 0.858 0.6570

HEN 477. 30/7 0.7470 0.6623 1.0483 1.0992 0.4610 1.3920 1.6069 0.6277 2.0251 23800 0.883 0.7470

OSPREY 556.5 18/1 0.6040 0.6593 0.9441 0.9550 0.4597 1.2599 1.4614 0.6263 1.8900 13700 0.879 0.6040

PARAKEET 556.5 24/7 0.7170 0.6855 1.0420 1.0789 0.4713 1.3773 1.5962 0.6380 2.0190 19800 0.914 0.7170

DOVE 556.5 26/7 0.7660 0.6953 1.0845 1.1319 0.4757 1.4278 1.6533 0.6423 2.0737 22600 0.927 0.7660

EAGLE 556.5 30/7 0.8720 0.7148 1.1775 1.2460 0.4843 1.5368 1.7754 0.6510 2.1910 27800 0.953 0.8720

KINGBIRD 636. 18/1 0.6910 0.7050 1.0372 1.0610 0.4800 1.3645 1.5864 0.6467 2.0131 15700 0.940 0.6910

ROOK 636. 24/7 0.8190 0.7478 1.1590 1.2067 0.4990 1.5058 1.7498 0.6657 2.1721 22000 0.997 0.8190

GOSBEAK 636. 26/7 0.8750 0.7425 1.1976 1.2605 0.4967 1.5548 1.8014 0.6633 2.2197 25200 0.990 0.8750

EGRET 636. 30/19 0.9880 0.7643 1.2991 1.3825 0.5063 1.6723 1.9325 0.6730 2.3463 31500 1.019 0.9880

CUCKOO 795. 24/7 1.0240 0.8190 1.3612 1.4412 0.5307 1.7358 2.0139 0.6973 2.4312 27900 1.092 1.0240

DRAKE 795. 26/7 1.0940 0.8310 1.4238 1.5162 0.5360 1.8081 2.0938 0.7027 2.5086 31500 1.108 1.0940

MALLARD 795. 30/19 1.2350 0.8550 1.5521 1.6671 0.5467 1.9545 2.2547 0.7133 2.6649 38400 1.140 1.2350

TERN 795. 45/7 0.8960 0.7973 1.2493 1.3042 0.5210 1.6044 1.8678 0.6877 2.2904 22100 1.063 0.8960

CONDOR 795. 54/7 1.0240 0.8198 1.3617 1.4415 0.5310 1.7362 2.0145 0.6977 2.4319 28200 1.093 1.0240

RAIL 954. 45/7 1.0750 0.8738 1.4353 1.5149 0.5550 1.8134 2.1103 0.7217 2.5302 25900 1.165 1.0750

CARDINAL 954. 54/7 1.2290 0.8970 1.5715 1.6785 0.5653 1.9712 2.2835 0.7320 2.6980 33800 1.196 1.2290

BUNTING 1192.5 45/7 1.3440 0.9765 1.7113 1.8265 0.6007 2.1227 2.4644 0.7673 2.8811 32000 1.302 1.3440

GRACKLE 1192.5 54/19 1.5330 1.0035 1.8822 2.0267 0.6127 2.3173 2.6758 0.7793 3.0870 41900 1.338 1.5330

BITTERN 1272. 45/7 1.4340 1.0088 1.8033 1.9299 0.6150 2.2255 2.5812 0.7817 2.9969 34100 1.345 1.4340

PHEASANT 1272. 54/19 1.6350 1.0365 1.9859 2.1424 0.6273 2.4323 2.8052 0.7940 3.2154 43600 1.382 1.6350

LAPWING 1590. 45/7 1.7920 1.1265 2.1667 2.3367 0.6673 2.6301 3.0368 0.8340 3.4492 42200 1.502 1.7920

FALCON 1590. 54/19 2.0440 1.1588 2.3996 2.6020 0.6817 2.8898 3.3155 0.8483 3.7223 54500 1.545 2.0440

CHUKAR 1780. 84/19 2.0740 1.2015 2.4469 2.6498 0.7007 2.9408 3.3810 0.8673 3.7904 51000 1.602 2.0740

BLUEBIRD 2156. 84/19 2.5110 1.3215 2.8875 3.1365 0.7540 3.4259 3.9175 0.9207 4.3242 60300 1.762 2.5110

ACSR CONDUCTORS

NESC DISTRICT LOADINGS
Bulletin 1724E-200

Page B-4

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

NAME SIZE STRAND LBS. LB/FT LB/FT LB/FT LB/FT LB/FT LB/FT LB/FT LB/FT LB/FT LB/FT LB/FT ANGLE

RAVEN 1/0 6/1 0.1452 0.4312 0.4550 0.5307 0.5502 0.6965 0.7115 0.8623 0.8745 1.0282 1.0384 0.1990 53.88

QUAIL 2/0 6/1 0.1831 0.4843 0.5177 0.5960 0.6235 0.7823 0.8034 0.9685 0.9857 1.1548 1.1692 0.2235 50.67

PIGEON 3/0 6/1 0.2309 0.5438 0.5908 0.6693 0.7080 0.8785 0.9083 1.0877 1.1119 1.2968 1.3172 0.2510 47.39

PENGUIN 4/0 6/1 0.2911 0.6099 0.6758 0.7507 0.8051 0.9853 1.0274 1.2198 1.2541 1.4544 1.4833 0.2815 44.04

WAXWING 266.8 18/1 0.2894 0.6598 0.7204 0.8120 0.8620 1.0658 1.1043 1.3195 1.3509 1.5733 1.5996 0.3045 46.46

PARTRIDGE 266.8 26/7 0.3673 0.6955 0.7865 0.8560 0.9315 1.1235 1.1820 1.3910 1.4387 1.6585 1.6987 0.3210 41.15

MERLIN 336.4 18/1 0.3653 0.7410 0.8262 0.9120 0.9824 1.1970 1.2515 1.4820 1.5264 1.7670 1.8044 0.3420 43.11

LINNET 336.4 26/7 0.4630 0.7811 0.9080 0.9613 1.0670 1.2618 1.3440 1.5622 1.6293 1.8626 1.9193 0.3605 37.90

ORIOLE 336.4 30/7 0.5271 0.8028 0.9603 0.9880 1.1198 1.2968 1.3998 1.6055 1.6898 1.9143 1.9855 0.3705 35.10

CHICKADEE 397.5 18/1 0.4316 0.8049 0.9133 0.9907 1.0806 1.3003 1.3700 1.6098 1.6667 1.9194 1.9673 0.3715 40.72

IBIS 397.5 26/7 0.5469 0.8483 1.0093 1.0440 1.1786 1.3703 1.4754 1.6965 1.7825 2.0228 2.0954 0.3915 35.60

LARK 397.5 30/7 0.6228 0.8732 1.0725 1.0747 1.2421 1.4105 1.5419 1.7463 1.8541 2.0822 2.1733 0.4030 32.91

PELICAN 477. 18/1 0.5180 0.8818 1.0227 1.0853 1.2026 1.4245 1.5158 1.7637 1.8382 2.1028 2.1657 0.4070 38.16

FLICKER 477. 24/7 0.6145 0.9165 1.1034 1.1280 1.2845 1.4805 1.6030 1.8330 1.9333 2.1855 2.2702 0.4230 34.54

HAWK 477. 26/7 0.6570 0.9295 1.1383 1.1440 1.3192 1.5015 1.6389 1.8590 1.9717 2.2165 2.3118 0.4290 33.14

HEN 477. 30/7 0.7470 0.9566 1.2137 1.1773 1.3943 1.5453 1.7163 1.9132 2.0538 2.2811 2.4003 0.4415 30.58

OSPREY 556.5 18/1 0.6040 0.9523 1.1277 1.1720 1.3185 1.5383 1.6526 1.9045 1.9980 2.2708 2.3497 0.4395 36.04

PARAKEET 556.5 24/7 0.7170 0.9902 1.2225 1.2187 1.4139 1.5995 1.7529 1.9803 2.1061 2.3612 2.4676 0.4570 32.51

DOVE 556.5 26/7 0.7660 1.0043 1.2630 1.2360 1.4541 1.6223 1.7940 2.0085 2.1496 2.3948 2.5143 0.4635 31.18

EAGLE 556.5 30/7 0.8720 1.0324 1.3514 1.2707 1.5411 1.6678 1.8820 2.0648 2.2414 2.4619 2.6118 0.4765 28.65

KINGBIRD 636. 18/1 0.6910 1.0183 1.2306 1.2533 1.4312 1.6450 1.7842 2.0367 2.1507 2.4283 2.5247 0.4700 34.22

ROOK 636. 24/7 0.8190 1.0801 1.3555 1.3293 1.5614 1.7448 1.9274 2.1602 2.3102 2.5756 2.7027 0.4985 31.33

GOSBEAK 636. 26/7 0.8750 1.0725 1.3842 1.3200 1.5837 1.7325 1.9409 2.1450 2.3166 2.5575 2.7030 0.4950 29.50

EGRET 636. 30/19 0.9880 1.1039 1.4815 1.3587 1.6799 1.7833 2.0387 2.2078 2.4188 2.6324 2.8117 0.5095 27.28

CUCKOO 795. 24/7 1.0240 1.1830 1.5646 1.4560 1.7800 1.9110 2.1681 2.3660 2.5781 2.8210 3.0011 0.5460 28.07

DRAKE 795. 26/7 1.0940 1.2003 1.6241 1.4773 1.8383 1.9390 2.2263 2.4007 2.6382 2.8623 3.0643 0.5540 26.86

MALLARD 795. 30/19 1.2350 1.2350 1.7466 1.5200 1.9585 1.9950 2.3463 2.4700 2.7615 2.9450 3.1935 0.5700 24.78

TERN 795. 45/7 0.8960 1.1516 1.4591 1.4173 1.6768 1.8603 2.0648 2.3032 2.4713 2.7461 2.8886 0.5315 30.68

CONDOR 795. 54/7 1.0240 1.1841 1.5654 1.4573 1.7811 1.9128 2.1696 2.3682 2.5801 2.8236 3.0035 0.5465 28.09

RAIL 954. 45/7 1.0750 1.2621 1.6579 1.5533 1.8890 2.0388 2.3048 2.5242 2.7435 3.0096 3.1958 0.5825 28.45

CARDINAL 954. 54/7 1.2290 1.2957 1.7858 1.5947 2.0133 2.0930 2.4272 2.5913 2.8680 3.0897 3.3251 0.5980 25.95

BUNTING 1192.5 45/7 1.3440 1.4105 1.9483 1.7360 2.1955 2.2785 2.6454 2.8210 3.1248 3.3635 3.6221 0.6510 25.84

GRACKLE 1192.5 54/19 1.5330 1.4495 2.1098 1.7840 2.3522 2.3415 2.7987 2.8990 3.2794 3.4565 3.7812 0.6690 23.58

BITTERN 1272. 45/7 1.4340 1.4571 2.0444 1.7933 2.2962 2.3538 2.7562 2.9142 3.2479 3.4746 3.7589 0.6725 25.13

PHEASANT 1272. 54/19 1.6350 1.4972 2.2169 1.8427 2.4635 2.4185 2.9193 2.9943 3.4116 3.5702 3.9267 0.6910 22.91

LAPWING 1590. 45/7 1.7920 1.6272 2.4205 2.0027 2.6874 2.6285 3.1812 3.2543 3.7151 3.8802 4.2740 0.7510 22.74

FALCON 1590. 54/19 2.0440 1.6738 2.6419 2.0600 2.9020 2.7038 3.3894 3.3475 3.9222 3.9913 4.4842 0.7725 20.70

CHUKAR 1780. 84/19 2.0740 1.7355 2.7043 2.1360 2.9772 2.8035 3.4873 3.4710 4.0434 4.1385 4.6291 0.8010 21.12

BLUEBIRD 2156. 84/19 2.5110 1.9088 3.1542 2.3493 3.4387 3.0835 3.9766 3.8177 4.5694 4.5518 5.1985 0.8810 19.33

ACSR CONDUCTORS

HIGH WIND LOADINGS
0.75 INCH ICE 1PSF 1 INCH ICE 1PSF 1.25 INCH ICE 1PSF

DIAM. WT./FT W T./FT TRANS W T./FT TRANS WT./FT TRANS

NAME SIZE STRAND IN. LBS. LBS. LB/FT LBS. LB/FT LBS. LB/FT

RAVEN 1/0 6/1 0.398 0.1452 1.2159 0.1582 1.8837 0.1998 2.7069 0.2415QUAIL 2/0 6/1 0.447 0.1831 1.2995 0.1623 1.9825 0.2039 2.8210 0.2456PIGEON 3/0 6/1 0.502 0.2309 1.3986 0.1668 2.0987 0.2085 2.9543 0.2502PENGUIN 4/0 6/1 0.563 0.2911 1.5157 0.1719 2.2348 0.2136 3.1093 0.2553WAXWING 266.8 18/1 0.609 0.2894 1.5569 0.1758 2.2903 0.2174 3.1791 0.2591PARTRIDGE 266.8 26/7 0.642 0.3673 1.6656 0.1785 2.4092 0.2202 3.3083 0.2618MERLIN 336.4 18/1 0.684 0.3653 1.7027 0.1820 2.4594 0.2237 3.3716 0.2653LINNET 336.4 26/7 0.721 0.4630 1.8349 0.1851 2.6031 0.2268 3.5268 0.2684ORIOLE 336.4 30/7 0.741 0.5271 1.9177 0.1868 2.6921 0.2284 3.6220 0.2701CHICKADEE 397.5 18/1 0.743 0.4316 1.8241 0.1869 2.5991 0.2286 3.5296 0.2703IBIS 397.5 26/7 0.783 0.5469 1.9767 0.1903 2.7641 0.2319 3.7071 0.2736LARK 397.5 30/7 0.806 0.6228 2.0740 0.1922 2.8686 0.2338 3.8187 0.2755PELICAN 477. 18/1 0.814 0.5180 1.9767 0.1928 2.7738 0.2345 3.7264 0.2762FLICKER 477. 24/7 0.846 0.6145 2.1030 0.1955 2.9101 0.2372 3.8726 0.2788HAW K 477. 26/7 0.858 0.6570 2.1567 0.1965 2.9675 0.2382 3.9337 0.2798HEN 477. 30/7 0.883 0.7470 2.2700 0.1986 3.0886 0.2403 4.0626 0.2819OSPREY 556.5 18/1 0.879 0.6040 2.1233 0.1983 2.9406 0.2399 3.9134 0.2816PARAKEET 556.5 24/7 0.914 0.7170 2.2689 0.2012 3.0971 0.2428 4.0808 0.2845DOVE 556.5 26/7 0.927 0.7660 2.3301 0.2023 3.1623 0.2439 4.1500 0.2856EAGLE 556.5 30/7 0.953 0.8720 2.4603 0.2044 3.3006 0.2461 4.2964 0.2878KINGBIRD 636. 18/1 0.940 0.6910 2.2672 0.2033 3.1035 0.2450 4.0952 0.2867ROOK 636. 24/7 0.997 0.8190 2.4484 0.2081 3.3024 0.2498 4.3118 0.2914GOSBEAK 636. 26/7 0.990 0.8750 2.4978 0.2075 3.3497 0.2492 4.3569 0.2908EGRET 636. 30/19 1.019 0.9880 2.6379 0.2099 3.4987 0.2516 4.5150 0.2933CUCKOO 795. 24/7 1.092 1.0240 2.7420 0.2160 3.6255 0.2577 4.6645 0.2993DRAKE 795. 26/7 1.108 1.0940 2.8269 0.2173 3.7154 0.2590 4.7594 0.3007MALLARD 795. 30/19 1.140 1.2350 2.9977 0.2200 3.8962 0.2617 4.9501 0.3033TERN 795. 45/7 1.063 0.8960 2.5869 0.2136 3.4614 0.2553 4.4914 0.2969CONDOR 795. 54/7 1.093 1.0240 2.7429 0.2161 3.6267 0.2578 4.6660 0.2994RAIL 954. 45/7 1.165 1.0750 2.8610 0.2221 3.7673 0.2638 4.8290 0.3054CARDINAL 954. 54/7 1.196 1.2290 3.0440 0.2247 3.9598 0.2663 5.0311 0.3080BUNTING 1192.5 45/7 1.302 1.3440 3.2578 0.2335 4.2066 0.2752 5.3109 0.3168GRACKLE 1192.5 54/19 1.338 1.5330 3.4804 0.2365 4.4404 0.2782 5.5559 0.3198BITTERN 1272. 45/7 1.345 1.4340 3.3879 0.2371 4.3501 0.2788 5.4678 0.3204PHEASANT 1272. 54/19 1.382 1.6350 3.6234 0.2402 4.5971 0.2818 5.7263 0.3235LAPWING 1590. 45/7 1.502 1.7920 3.8924 0.2502 4.9034 0.2918 6.0698 0.3335FALCON 1590. 54/19 1.545 2.0440 4.1845 0.2538 5.2088 0.2954 6.3886 0.3371CHUKAR 1780. 84/19 1.602 2.0740 4.2676 0.2585 5.3097 0.3002 6.5072 0.3418BLUEBIRD 2156. 84/19 1.762 2.5110 4.8538 0.2718 5.9457 0.3135 7.1930 0.3552

ACSR CONDUCTORS

MISCELLANEOUS LOADINGS

Transverse loadingthe indicated ice coloadings other than multiplying the transtable by the amounFor example, the tr6 psf wind on a 477 covered by 1 inch o.2382(6) = 1.4292 l
Bulletin 1724E-200

Page B-6

LIGHT MEDIUM HEAVY

.00" ICE, 9 LB., K=.05 .25" ICE, 4 LB WIND, K=.20 .5" ICE, 4 LB WIND, K=.30 ULTIMATE

VERT. TRANS RESULTANT VERT. TRANS RESULTANT VERT. TRANS RESULTANT STRENGTH DIAM. WT./FT

NAME SIZE STRAND LB/FT LB/FT LB/FT LB/FT LB/FT LB/FT LB/FT LB/FT LB/FT LBS. IN. LBS.

AZUSA 123.3 7 0.1157 0.2985 0.3701 0.3172 0.2993 0.6361 0.6741 0.4660 1.1195 4460 0.398 0.1157

ANAHEIM 155.4 7 0.1459 0.3353 0.4156 0.3626 0.3157 0.6807 0.7347 0.4823 1.1789 5390 0.447 0.1459

AMHERST 195.7 7 0.1837 0.3765 0.4689 0.4175 0.3340 0.7347 0.8067 0.5007 1.2495 6790 0.502 0.1837

ALLIANCE 246.9 7 0.2318 0.4223 0.5317 0.4846 0.3543 0.8003 0.8927 0.5210 1.3337 8560 0.563 0.2318

BUTTE 312.8 19 0.2936 0.4815 0.6140 0.5709 0.3807 0.8862 1.0037 0.5473 1.4432 11000 0.642 0.2936

CANTON 394.5 19 0.3703 0.5408 0.7054 0.6722 0.4070 0.9858 1.1295 0.5737 1.5668 13300 0.721 0.3703

CAIRO 465.4 19 0.4369 0.5873 0.7819 0.7580 0.4277 1.0704 1.2346 0.5943 1.6702 15600 0.783 0.4369

DARIEN 559.5 19 0.5252 0.6435 0.8806 0.8697 0.4527 1.1804 1.3696 0.6193 1.8031 18800 0.858 0.5252

ELOIN 652.4 19 0.6124 0.6953 0.9765 0.9783 0.4757 1.2878 1.4997 0.6423 1.9314 21900 0.927 0.6124

FLINT 740.8 37 0.6954 0.7433 1.0678 1.0812 0.4970 1.3900 1.6225 0.6637 2.0530 24400 0.991 0.6954

GREELEY 927.2 37 0.8704 0.8310 1.2534 1.2926 0.5360 1.5993 1.8702 0.7027 2.2979 30500 1.108 0.8704

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

NAME SIZE STRAND LBS. LB/FT LB/FT LB/FT LB/FT LB/FT LB/FT LB/FT LB/FT LB/FT LB/FT LB/FT ANGLE

AZUSA 123.3 7 0.1157 0.4312 0.4464 0.5307 0.5431 0.6965 0.7060 0.8623 0.8701 1.0282 1.0347 0.1990 59.8

ANAHEIM 155.4 7 0.1459 0.4843 0.5058 0.5960 0.6136 0.7823 0.7957 0.9685 0.9794 1.1548 1.1639 0.2235 56.9

AMHERST 195.7 7 0.1837 0.5438 0.5740 0.6693 0.6941 0.8785 0.8975 1.0877 1.1031 1.2968 1.3098 0.2510 53.8

ALLIANCE 246.9 7 0.2318 0.6099 0.6525 0.7507 0.7856 0.9853 1.0122 1.2198 1.2417 1.4544 1.4728 0.2815 50.5

BUTTE 312.8 19 0.2936 0.6955 0.7549 0.8560 0.9050 1.1235 1.1612 1.3910 1.4216 1.6585 1.6843 0.3210 47.6

CANTON 394.5 19 0.3703 0.7811 0.8644 0.9613 1.0302 1.2618 1.3150 1.5622 1.6055 1.8626 1.8990 0.3605 44.2

CAIRO 465.4 19 0.4369 0.8483 0.9542 1.0440 1.1317 1.3703 1.4382 1.6965 1.7519 2.0228 2.0694 0.3915 41.9

DARIEN 559.5 19 0.5252 0.9295 1.0676 1.1440 1.2588 1.5015 1.5907 1.8590 1.9318 2.2165 2.2779 0.4290 39.2

ELOIN 652.4 19 0.6124 1.0043 1.1762 1.2360 1.3794 1.6223 1.7340 2.0085 2.0998 2.3948 2.4718 0.4635 37.1

FLINT 740.8 37 0.6954 1.0736 1.2791 1.3213 1.4932 1.7343 1.8685 2.1472 2.2570 2.5601 2.6528 0.4955 35.5

GREELEY 927.2 37 0.8704 1.2003 1.4827 1.4773 1.7147 1.9390 2.1254 2.4007 2.5536 2.8623 2.9917 0.5540 32.5

1.0 " ICE 1.5 " ICE

WT./FT TRANS WT./FT TRANS

NAME SIZE STRAND LBS. for 1psf LBS. for 1psf 

LB/FT LB/FT Transverse Loadings other than 1 psf on the indicated ice 

AZUSA 123.3 7 1.8542 0.1998 3.6561 0.2832 condition can be obtained by multiplying the transverse loading 

ANAHEIM 155.4 7 1.9453 0.2039 3.7777 0.2873 value in the table by the amount of the expected wind load 

AMHERST 195.7 7 2.0515 0.2085 3.9181 0.2918 per foot.

ALLIANCE 246.9 7 2.1755 0.2136 4.0800 0.2969

BUTTE 312.8 19 2.3355 0.2202 4.2891 0.3035 For example, the transverse load caused by a 6 psf wind on a 6psf

CANTON 394.5 19 2.5104 0.2268 4.5132 0.3101 wind on a 559.5 kcmil conductor covered by 1 inch of radial ice is:

CAIRO 465.4 19 2.6541 0.2319 4.6954 0.3153

DARIEN 559.5 19 2.8357 0.2382 4.9236 0.3215 .2382(6) = 1.4292 lb/ft.

ELOIN 652.4 19 3.0087 0.2439 5.1395 0.3273

FLINT 740.8 37 3.1713 0.2493 5.3419 0.3326

GREELEY 927.2 37 3.4918 0.2590 5.7352 0.3423

ACSR CONDUCTORS

HIGH WIND LOADINGS

6201 ALUMINUM ALLOY CONDUCTORS

NESC DISTRICT LOADINGS

6201 ALUMINUM ALLOY CONDUCTORS - MISCELLANEOUS LOADINGS
Bulletin 1724E-200

Page B-7

LIGHT MEDIUM HEAVY

.00" ICE, 9 LB., K=.05 .25" ICE, 4 LB WIND, K=.20 .5" ICE, 4 LB WIND, K=.30 ULTIMATE

VERT. TRANS RESULTANT VERT. TRANS RESULTANT VERT. TRANS RESULTANT STRENGTH DIAM. WT./FT

NAME SIZE STRAND LB/FT LB/FT LB/FT LB/FT LB/FT LB/FT LB/FT LB/FT LB/FT LBS. IN. LBS.

POPPY 1/0 7 0.0991 0.2760 0.3433 0.2912 0.2893 0.6105 0.6388 0.4560 1.0849 1990 0.368 0.0991

ASTRE 2/0 7 0.1249 0.3105 0.3847 0.3313 0.3047 0.6501 0.6932 0.4713 1.1383 2510 0.414 0.1249

PHLOX 3/0 7 0.1575 0.3480 0.4320 0.3795 0.3213 0.6972 0.7569 0.4880 1.2006 3040 0.464 0.1575

OXLIP 4/0 7 0.1986 0.3915 0.4890 0.4386 0.3407 0.7554 0.8341 0.5073 1.2762 3830 0.522 0.1986

VALERIAN 250. 19 0.2347 0.4305 0.5403 0.4909 0.3580 0.8076 0.9025 0.5247 1.3439 4660 0.574 0.2347

DAISY 266.8 7 0.2505 0.4395 0.5559 0.5104 0.3620 0.8257 0.9257 0.5287 1.3661 4830 0.586 0.2505

LAUREL 266.8 19 0.2505 0.4448 0.5604 0.5126 0.3643 0.8289 0.9301 0.5310 1.3710 4970 0.593 0.2505

TULIP 336.4 19 0.3128 0.4995 0.6394 0.5976 0.3887 0.9128 1.0378 0.5553 1.4770 6150 0.666 0.3128

CANNA 397.5 19 0.3731 0.5430 0.7088 0.6759 0.4080 0.9895 1.1342 0.5747 1.5714 7110 0.724 0.3731

GOLDENTUFT 450. 19 0.4224 0.5775 0.7655 0.7395 0.4233 1.0521 1.2121 0.5900 1.6480 7890 0.770 0.4224

COSMOS 477. 19 0.4478 0.5948 0.7945 0.7721 0.4310 1.0842 1.2518 0.5977 1.6871 8360 0.793 0.4478

SYRINGA 477. 37 0.4478 0.5963 0.7957 0.7727 0.4317 1.0851 1.2530 0.5983 1.6885 8690 0.795 0.4478

DAHLIA 556.5 19 0.5220 0.6420 0.8774 0.8658 0.4520 1.1767 1.3651 0.6187 1.7988 9750 0.856 0.5220

MISTLETOE 556.5 37 0.5220 0.6435 0.8786 0.8665 0.4527 1.1776 1.3664 0.6193 1.8002 9940 0.858 0.5220

ORCHID 636. 37 0.5970 0.6885 0.9613 0.9601 0.4727 1.2702 1.4787 0.6393 1.9110 11400 0.918 0.5970

ARBUTUS 795. 37 0.7460 0.7695 1.1217 1.1427 0.5087 1.4508 1.6948 0.6753 2.1244 13900 1.026 0.7460

LILAC 795. 61 0.7460 0.7710 1.1228 1.1433 0.5093 1.4516 1.6961 0.6760 2.1258 14300 1.028 0.7460

ANEMONE 874.5 37 0.8210 0.8078 1.2017 1.2335 0.5257 1.5409 1.8015 0.6923 2.2300 15000 1.077 0.8210

CROCUS 874.5 61 0.8210 0.8085 1.2023 1.2339 0.5260 1.5413 1.8022 0.6927 2.2307 15800 1.078 0.8210

MAGNOLIA 954. 37 0.8960 0.8430 1.2802 1.3232 0.5413 1.6296 1.9058 0.7080 2.3330 16400 1.124 0.8960

GOLDENROD 954. 61 0.8960 0.8445 1.2813 1.3238 0.5420 1.6304 1.9070 0.7087 2.3344 16900 1.126 0.8960

HAWTHORN 1192.5 61 1.1190 0.9435 1.5137 1.5878 0.5860 1.8925 2.2121 0.7527 2.6366 21100 1.258 1.1190

NARCESSUS 1272. 61 1.1920 0.9750 1.5900 1.6739 0.6000 1.9782 2.3112 0.7667 2.7350 22000 1.300 1.1920

COREOPSIS 1590 61 1.4900 1.0898 1.8960 2.0194 0.6510 2.3218 2.7043 0.8177 3.1252 27000 1.453 1.4900

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

NAME SIZE STRAND LBS. LB/FT LB/FT LB/FT LB/FT LB/FT LB/FT LB/FT LB/FT LB/FT LB/FT LB/FT ANGLE

POPPY 1/0 7 0.0991 0.3987 0.4108 0.4907 0.5006 0.6440 0.6516 0.7973 0.8035 0.9507 0.9558 0.1840 61.7

ASTER 2/0 7 0.1249 0.4485 0.4656 0.5520 0.5660 0.7245 0.7352 0.8970 0.9057 1.0695 1.0768 0.2070 58.9

PHLOX 3/0 7 0.1575 0.5027 0.5268 0.6187 0.6384 0.8120 0.8271 1.0053 1.0176 1.1987 1.2090 0.2320 55.8

OXLIP 4/0 7 0.1986 0.5655 0.5994 0.6960 0.7238 0.9135 0.9348 1.1310 1.1483 1.3485 1.3630 0.2610 52.7

DAISY 266.8 7 0.2505 0.6348 0.6825 0.7813 0.8205 1.0255 1.0557 1.2697 1.2941 1.5138 1.5344 0.2930 49.5

LAUREL 266.8 19 0.2505 0.6424 0.6895 0.7907 0.8294 1.0378 1.0676 1.2848 1.3090 1.5319 1.5523 0.2965 49.8

TULIP 336.4 19 0.3128 0.7215 0.7864 0.8880 0.9415 1.1655 1.2067 1.4430 1.4765 1.7205 1.7487 0.3330 46.8

CANNA 397.5 19 0.3731 0.7843 0.8686 0.9653 1.0349 1.2670 1.3208 1.5687 1.6124 1.8703 1.9072 0.3620 44.1

GOLDENTUFT 450. 19 0.4224 0.8342 0.9350 1.0267 1.1102 1.3475 1.4122 1.6683 1.7210 1.9892 2.0335 0.3850 42.3

COSMOS 477. 19 0.4478 0.8591 0.9688 1.0573 1.1483 1.3878 1.4582 1.7182 1.7756 2.0486 2.0970 0.3965 41.5

SYRINGA 477. 37 0.4478 0.8613 0.9707 1.0600 1.1507 1.3913 1.4615 1.7225 1.7798 2.0538 2.1020 0.3975 41.6

DAHLIA 556.5 19 0.5220 0.9273 1.0642 1.1413 1.2550 1.4980 1.5863 1.8547 1.9267 2.2113 2.2721 0.4280 39.3

MISTLETOE 556.5 37 0.5220 0.9295 1.0660 1.1440 1.2575 1.5015 1.5896 1.8590 1.9309 2.2165 2.2771 0.4290 39.4

ORCHID 636. 37 0.5970 0.9945 1.1599 1.2240 1.3618 1.6065 1.7138 1.9890 2.0767 2.3715 2.4455 0.4590 37.6

ARBUTUS 795. 37 0.7460 1.1115 1.3386 1.3680 1.5582 1.7955 1.9443 2.2230 2.3448 2.6505 2.7535 0.5130 34.5

LILAC 795. 61 0.7460 1.1137 1.3404 1.3707 1.5605 1.7990 1.9475 2.2273 2.3489 2.6557 2.7585 0.5140 34.6

ANEMONE 874.5 37 0.8210 1.1668 1.4267 1.4360 1.6541 1.8848 2.0558 2.3335 2.4737 2.7823 2.9009 0.5385 33.3

CROCUS 874.5 61 0.8210 1.1678 1.4275 1.4373 1.6553 1.8865 2.0574 2.3357 2.4758 2.7848 2.9033 0.5390 33.3

MAGNOLIA 954. 37 0.8960 1.2177 1.5118 1.4987 1.7461 1.9670 2.1615 2.4353 2.5949 2.9037 3.0388 0.5620 32.1

GOLDENROD 954. 61 0.8960 1.2198 1.5135 1.5013 1.7484 1.9705 2.1646 2.4397 2.5990 2.9088 3.0437 0.5630 32.1

HAWTHORN 1192.5 61 1.1190 1.3628 1.7634 1.6773 2.0163 2.2015 2.4696 2.7257 2.9464 3.2498 3.4371 0.6290 29.3

NARCESSUS 1272. 61 1.1920 1.4083 1.8451 1.7333 2.1036 2.2750 2.5684 2.8167 3.0585 3.3583 3.5636 0.6500 28.6

COREOPSIS 1590 61 1.1940 1.5741 1.9757 1.9373 2.2757 2.5428 2.8091 3.1482 3.3670 3.7536 3.9389 0.7265 31.3

1350 ALUMINUM ALLOY CONDUCTORS

NESC DISTRICT LOADINGS

1350 ALUMINUM ALLOY CONDUCTORS

HIGH WIND LOADINGS
Bulletin 1724E-200

Page B-8

.75 " ICE 1.0 " ICE 1.25 " ICE

WT./FT TRANS WT./FT TRANS WT./FT TRANS

NAME SIZE STRAND DIAM. WT./FT LBS. for 1psf LBS. for 1psf LBS. for 1psf 

IN. LBS. LB/FT LB/FT LB/FT

POPPY 1/0 7 0.368 0.0991 1.1418 0.1557 1.8003 0.1973 2.6142 0.2390

ASTRE 2/0 7 0.414 0.1249 1.2105 0.1595 1.8833 0.2012 2.7115 0.2428

PHLOX 3/0 7 0.464 0.1575 1.2898 0.1637 1.9781 0.2053 2.8218 0.2470

OXLIP 4/0 7 0.522 0.1986 1.3849 0.1685 2.0913 0.2102 2.9531 0.2518

VALERIAN 250. 19 0.574 0.2347 1.4695 0.1728 2.1920 0.2145 3.0700 0.2562

DAISY 266.8 7 0.586 0.2505 1.4965 0.1738 2.2228 0.2155 3.1044 0.2572

LAUREL 266.8 19 0.593 0.2505 1.5031 0.1744 2.2315 0.2161 3.1153 0.2578

TULIP 336.4 19 0.666 0.3128 1.6335 0.1805 2.3846 0.2222 3.2911 0.2638

CANNA 397.5 19 0.724 0.3731 1.7478 0.1853 2.5170 0.2270 3.4416 0.2687

GOLDENTUFT 450. 19 0.770 0.4224 1.8400 0.1892 2.6235 0.2308 3.5624 0.2725

COSMOS 477. 19 0.793 0.4478 1.8869 0.1911 2.6775 0.2328 3.6235 0.2744

SYRINGA 477. 37 0.795 0.4478 1.8888 0.1913 2.6800 0.2329 3.6266 0.2746

DAHLIA 556.5 19 0.856 0.5220 2.0199 0.1963 2.8300 0.2380 3.7956 0.2797

MISTLETOE 556.5 37 0.858 0.5220 2.0217 0.1965 2.8325 0.2382 3.7988 0.2798

ORCHID 636. 37 0.918 0.5970 2.1527 0.2015 2.9821 0.2432 3.9670 0.2848

ARBUTUS 795. 37 1.026 0.7460 2.4024 0.2105 3.2654 0.2522 4.2839 0.2938

LILAC 795. 61 1.028 0.7460 2.4043 0.2107 3.2679 0.2523 4.2870 0.2940

ANEMONE 874.5 37 1.077 0.8210 2.5250 0.2148 3.4039 0.2564 4.4382 0.2981

CROCUS 874.5 61 1.078 0.8210 2.5259 0.2148 3.4051 0.2565 4.4397 0.2982

MAGNOLIA 954. 37 1.124 0.8960 2.6438 0.2187 3.5373 0.2603 4.5862 0.3020

GOLDENROD 954. 61 1.126 0.8960 2.6457 0.2188 3.5398 0.2605 4.5893 0.3022

HAWTHORN 1192.5 61 1.258 1.1190 2.9918 0.2298 3.9269 0.2715 5.0175 0.3132

NARCESSUS 1272. 61 1.300 1.1920 3.1040 0.2333 4.0522 0.2750 5.1558 0.3167

COREOPSIS 1590 61 1.453 1.4900 3.5447 0.2461 4.5404 0.2878 5.6916 0.3294

Transverse Loadings other than 1 psf on the indicated ice For example, the transverse load caused by a 6 psf wind 

condition can be obtained by multiplying the transverse loading on a 336.4 kcmil conductor covered by 1 inch of radial ice is:

value in the table by the amount of the expected wind load .2222(6) = 1.3332 lb/ft.

per foot.

1350 ALUMINUM ALLOY CONDUCTORS

MISCELLANEOUS LOADINGS
Bulletin 1724E-200

Page B-9

LIGHT MEDIUM HEAVY

.00" ICE, 9 LB., K=.05 .25" ICE, 4 LB WIND, K=.20 .5" ICE, 4 LB WIND, K=.30 ULTIMATE

VERT. TRANS RESULTANT VERT. TRANS RESULTANT VERT. TRANS RESULTANT STRENGTH DIAM.

NAME SIZE STRAND LB/FT LB/FT LB/FT LB/FT LB/FT LB/FT LB/FT LB/FT LB/FT LBS. IN.

HS STL 3/8 7 0.2730 0.2700 0.4340 0.4626 0.2867 0.7443 0.8077 0.4533 1.2262 10800 0.360

HS STL 7/16 7 0.3990 0.3263 0.5654 0.6120 0.3117 0.8868 0.9804 0.4783 1.3908 14500 0.435

EHS STL 3/8 7 0.2730 0.2700 0.4340 0.4626 0.2867 0.7443 0.8077 0.4533 1.2262 15400 0.360

EHS STL 7/16 7 0.3990 0.3263 0.5654 0.6120 0.3117 0.8868 0.9804 0.4783 1.3908 20800 0.435

AL CLAD 7 NO. 9 0.2076 0.2573 0.3806 0.3920 0.2810 0.6823 0.7318 0.4477 1.1578 12630 0.343

AL CLAD 7 NO. 8 0.2618 0.2888 0.4398 0.4592 0.2950 0.7458 0.8121 0.4617 1.2341 15930 0.385

AL CLAD 7 NO. 7 0.3300 0.3248 0.5130 0.5423 0.3110 0.8252 0.9101 0.4777 1.3278 19060 0.433

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

NAME SIZE STRAND LBS. LB/FT LB/FT LB/FT LB/FT LB/FT LB/FT LB/FT LB/FT LB/FT LB/FT LB/FT ANGLE

HS STL 3/8 7 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

HS STL 7/16 7 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

EHS STL 3/8 7 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

EHS STL 7/16 7 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

AL CLAD 7 NO. 9 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

AL CLAD 7 NO. 8 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

AL CLAD 7 NO. 7 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

0.75 " ICE 1.0 " ICE 1.25 " ICE

WT./FT TRANS WT./FT TRANS WT./FT TRANS

SIZE STRAND LBS. for 1psf LBS. for 1psf LBS. for 1psf 

NAME LB/FT LB/FT LB/FT Transverse Loadings other than 1 psf on the indicated ice 

HS STL 3/8 7 1.3083 0.1550 1.9642 0.1967 2.7756 0.2383 condition can be obtained by multiplying the transverse loading 

HS STL 7/16 7 1.5042 0.1613 2.1835 0.2029 3.0182 0.2446 value in the table by the amount of the expected wind load 

EHS STL 3/8 7 1.3083 0.1550 1.9642 0.1967 2.7756 0.2383 per foot.

EHS STL 7/16 7 1.5042 0.1613 2.1835 0.2029 3.0182 0.2446

AL CLAD 7 NO. 9 1.2270 0.1536 1.8777 0.1953 2.6838 0.2369 For example, the transverse load caused by a 6 psf wind on

AL CLAD 7 NO. 8 1.3204 0.1571 1.9841 0.1988 2.8033 0.2404 3/8" HIGH STRENGTH STEEL OHGW covered by 1 inch of radial ice is:

AL CLAD 7 NO. 7 1.4333 0.1611 2.1120 0.2028 2.9461 0.2444

.1967(6) = 1.1802 lb/ft.

OVERHEAD GROUND WIRES

NESC DISTRICT LOADINGS

OVERHEAD GROUND WIRES - MISCELLANEOUS LOADINGS

HIGH WIND LOADINGS

OVERHEAD GROUND WIRES
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 C29.12-2006 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

Units in 

string

60Hz

Flashover-kV

Impulse Flashover, kV

1.5 X 50

Dry Wet Positive Negative

2 155 90 250 250

3 215 130 355 340

4 270 170 440 415

5 325 215 525 495

6 380 255 610 585

7 435 295 695 670

8 485 335 780 760

9 540 375 860 845

10 590 415 945 930

11 640 455 1025 1015

12 690 490 1105 1105

13 735 525 1185 1190

14 785 565 1265 1275

15 830 600 1345 1360

16 875 630 1425 1440

17 920 660 1505 1530

18 965 690 1585 1615

19 1010 720 1665 1700

20 1055 750 1745 1785

21 1095 775 1820 1865

22 1135 800 1895 1945

23 1175 825 1970 2025

24 1215 850 2045 2105

25 1255 875 2120 2185
Bulletin 1724E-200

Page C-3

TABLE C-2

FLASHOVER DATA FOR SUSPENSION POLYMERS 

(ANSI C29.12-2006)

Electrical Values

Low Frequency flashover Critical Impulse Flashover

ANSI

Class

Dry

(kV)

Wet

(kV)

Positive

(kV)

Negative

(kV)

60-1 365 310 610 585

60-2 410 350 675 670

60-3 470 415 780 760

60-4 485 455 860 845

60-5 560 490 925 930

60-6 620 545 1025 1015

60-7 670 580 1105 1105

60-8 720 620 1185 1190

60-9 810 690 1345 1360

60-10 900 755 1490 1530

60-11 925 795 1575 1600

60-12 980 830 1665 1700

60-13 1060 890 1825 1870

60-14 1345 1290 2530 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 2.00 45 34.5 kV, 46 kV

4 2.50 58 69 kV

5 3.00 71

6 3.50 84

7 3.92 96 115 kV

8 4.42 109

9 4.92 122

10 5.33 135 161 kV

11 5.83 147

12 6.33 160 230 kV

13 6.83 173

14 7.25 186

15 7.75 198

16 8.25 211

*Exact length and weight will vary slightly depending upon conductor

suspension hardware used.
Bulletin 1724E-200

Page C-5

Blank Page
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 120oF 167oF 212oF

Summer ambient 104oF 104oF 104oF

Winter ambient 32oF 32oF 32oF

Wind (ft./sec.) 2 2 2 ft./sec.

Ampacity 

Summer Rating

Ampacity 

Winter Rating

NAME SIZE STRAND

120

Deg F

167

Deg F

212

Deg F

120

Deg F

167

Deg F

212

Deg F

RAVEN 1/0 6/1 70 195 257 240 292 330

QUAIL 2/0 6/1 77 223 294 275 335 379

PIGEON 3/0 6/1 85 255 338 315 384 435

PENGUIN 4/0 6/1 92 291 386 357 439 497

WAXWING 266.8 18/1 110 359 478 442 543 616

PARTRIDGE 266.8 26/7 108 364 484 447 550 624

MERLIN 336.4 18/1 119 416 554 511 630 715

LINNET 336.4 26/7 117 420 561 517 637 724

ORIOLE 336.4 30/7 115 423 565 520 642 729

CHICKADEE 397.5 18/1 120 461 616 544 700 795

IBIS 397.5 26/7 122 466 624 574 708 806

LARK 397.5 30/7 120 469 629 578 714 812

PELICAN 477. 18/1 131 516 692 636 786 894

FLICKER 477. 24/7 128 521 699 641 793 902

HAWK 477. 26/7 127 522 701 644 796 906

HEN 477. 30/7 124 526 706 648 801 913

OSPREY 556.5 18/1 135 568 763 700 866 986

PARAKEET 556.5 24/7 130 573 771 706 874 996

DOVE 556.5 26/7 129 575 774 709 878 1000

EAGLE 556.5 30/7 126 579 779 713 884 1007

KINGBIRD 636. 18/1 136 617 815 761 943 1053

ROOK 636. 24/7 131 623 839 768 952 1085

GOSBEAK 636. 26/7 129 625 843 770 955 1089

EGRET 636. 30/19 125 629 849 776 962 1097

CUCKOO 795. 24/7 126 715 967 882 1096 1251

DRAKE 795. 26/7 123 718 972 886 1101 1257

MALLARD 795. 30/19 116 723 979 892 1110 1267

TERN 795. 45/7 131 709 959 874 1086 1240

CONDOR 795. 54/7 126 715 967 882 1096 1251

RAIL 954. 45/7 120 793 1076 978 1218 1393

CARDINAL 954. 54/7 112 800 1086 987 1229 1406

BUNTING 1192.5 45/7 84 908 1238 1121 1400 1604

GRACKLE 1192.5 54/19 65 927 1264 1144 1429 1637

BITTERN 1272. 45/7 61 944 1289 1165 1457 1670

PHEASANT 1272. 54/19 21 964 1317 1190 1489 1706

LAPWING 1590. 45/7 1079 1480 1330 1670 1919

FALCON 1590. 54/19 1103 1514 1361 1709 1963

CHUKAR 1780. 84/19 1168 1608 1440 1813 2085

BLUEBIRD 2156 84/19 1304 1803 1606 2030 2340
Bulletin 1724E-200 

Page D-3 

TABLE D-2: MVA LIMITS

MVA LIMIT FOR 212 DEGREE OF OPERATION AT THE INDICATED VOLTAGE

(S = Summer; W = Winter)

CONDUCTOR 34.5 kV 46 kV 69 kV 115 kV 138 kV 161 kV 230 KV

NAME SIZE & 

STRAND S W S W S W S W S W S W S W 

RAVEN 1/0 6/1 15 20 20 26 31 39 51 66 61 79 72 92 102 132

QUAIL 2/0 6/1 18 23 23 30 35 45 59 75 70 91 82 106 117 151

PIGEON 3/0 6/1 20 26 27 35 40 52 67 87 81 104 94 121 134 173

PENGUIN 4/0 6/1 23 30 31 40 46 59 77 99 92 119 108 139 154 198

WAXWING 266.8 18/1 29 37 38 49 57 74 95 123 114 147 133 172 190 245

PARTRIDGE 266.8 26/7 29 37 39 50 58 75 96 124 116 149 135 174 193 249

MERLIN 336.4 18/1 33 43 44 57 66 85 110 142 132 171 155 199 221 285

LINNET 336.4 26/7 34 43 45 58 67 87 112 144 134 173 156 202 224 288

ORIOLE 336.4 30/7 34 44 45 58 68 87 113 145 135 174 158 203 225 290

CHICKADEE 397.5 18/1 37 48 37 48 74 95 123 158 147 190 172 222 246 317

IBIS 397.5 26/7 37 48 37 48 75 96 124 160 149 193 174 225 249 321

LARK 397.5 30/7 38 48 38 48 75 97 125 162 150 194 175 226 250 323

PELICAN 477. 18/1 41 53 41 53 83 107 138 178 165 214 193 249 276 356

FLICKER 477. 24/7 42 54 42 54 83 108 139 180 167 216 195 252 278 359

HAWK 477. 26/7 42 54 42 54 84 108 140 180 168 216 196 253 279 361

HEN 477. 30/7 42 55 42 55 84 109 141 182 169 218 197 254 281 364

OSPREY 556.5 18/1 46 59 46 59 91 118 152 196 182 236 213 275 304 393

PARAKEET 556.5 24/7 46 60 46 60 92 119 154 198 184 238 215 278 307 397

DOVE 556.5 26/7 46 60 46 60 93 120 154 199 185 239 216 279 308 398

EAGLE 556.5 30/7 47 60 47 60 93 120 155 201 186 241 217 281 310 401

KINGBIRD 636. 18/1 49 63 49 63 97 126 162 210 195 252 227 294 324 419

ROOK 636. 24/7 50 65 50 65 100 130 167 216 201 259 234 303 334 432

GOSBEAK 636. 26/7 50 65 50 65 101 130 168 217 201 260 235 304 336 434

EGRET 636. 30/19 51 66 51 66 101 131 169 219 203 262 237 306 338 437

CUCKOO 795. 24/7 58 75 58 75 116 150 193 249 231 299 270 349 385 498

DRAKE 795. 26/7 58 75 58 75 116 150 194 250 232 301 271 351 387 501

MALLARD 795. 30/19 59 76 59 76 117 151 195 252 234 303 273 353 390 505

TERN 795. 45/7 57 74 57 74 115 148 191 247 229 296 267 346 382 494

CONDOR 795. 54/7 58 75 58 75 116 150 193 249 231 299 270 349 385 498

RAIL 954. 45/7 64 83 64 83 129 166 214 277 257 333 300 388 429 555

CARDINAL 954. 54/7 65 84 65 84 130 168 216 280 260 336 303 392 433 560

BUNTING 1192.5 45/7 74 96 74 96 148 192 247 319 296 383 345 447 493 639

GRACKLE 1192.5 54/19 76 98 76 98 151 196 252 326 302 391 352 457 504 652

BITTERN 1272. 45/7 77 100 77 100 154 200 257 333 308 399 359 466 514 665

PHEASANT 1272. 54/19 79 102 79 102 157 204 262 340 315 408 367 476 525 680

LAPWING 1590. 45/7 88 115 88 115 177 229 295 382 354 459 413 535 590 764

FALCON 1590. 54/19 90 117 90 117 181 235 302 391 362 469 422 548 603 782

CHUKAR 1780. 84/19 96 125 96 125 192 249 320 415 384 498 448 581 640 831

BLUEBIRD 2156 84/19 108 140 108 140 215 280 359 466 431 559 503 653 718 932
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 3.1 4.8

40 4.0 6.3

45 5.2 8.1

49 6.0 9.6

50 6.4 10.0

55 7.7 12.0

60 9.0 14.1

65 10.8 16.9

70 12.5 19.5

75 14.4 22.5

80 16.4 28.9

85 18.5 32.3

90 20.7 36.1

95 23.1 40.0

100 25.6 44.1

105 28.2 48.4

110 31.0 53.0

115 33.9 57.7

120 36.9 63.1

*Based on:

F = .00256V2 (for cylindrical surfaces)

F = .004 V2 (for flat 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 1.23 1.23 1/18

200 1.14 1.14 1.12

100 1.07 1.07 1.06

50 1.00 1.00 1.00

25 0.93 0.88 0.94

10 0.84 0.74(76 mph min.) 0.87

5 0.78 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

PROBABILITY OF EXCEEDING DESIGN WIND SPEEDS

DURING REFERENCE PERIOD

Annual

Probability

Pa

Reference (Exposure) Period, n (years)

1 5 10 25 50 100

.04(1/25) 0.04 0.18 0.34 0.64 0.87 0.98

.02(1/50) 0.02 0.10 0.18 0.40 0.64 0.87

.01(1/100) 0.01 0.05 0.10 0.22 0.40 0.64

.005(1/200) 0.005 0.02 0.05 0.10 0.22 0.39
Bulletin 1724E-200

Page E-4

FIGURE E-1: ISOKERAUNIC LEVELS FOR THE UNITED STATES
Bulletin 1724E-200

Page E-5

Blank Page
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 Cl-H1 Cl-1 Cl-2 Cl-3

50 0.9 0.9 0.8 0.7 0.8 0.8 0.7

55 1.1 1.0 1.0 0.9 1.0 1.0 0.9

60 1.4 1.3 1.2 1.1 1.3 1.2 1.1

65 1.6 1.5 1.4 1.3 1.5 1.4 1.3

70 1.9 1.8 1.7 1.6 1.8 1.7 1.5

75 2.2 2.1 2.0 1.8 2.1 1.9 1.8

80 2.6 2.4 2.3 2.1 2.4 2.2 2.1

85 3.0 2.8 2.6 2.4 2.7 2.5 2.4

90 3.4 3.2 3.0 2.7 3.1 2.9 2.7

95 3.9 3.6 3.4 3.6 3.3

100 4.4 4.1 3.8 4.0 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 0.9 0.8 0.8 0.7 0.9 0.8 0.8 0.7

55 1.1 1.0 0.9 0.9 1.1 1.0 0.9 0.9

60 1.3 1.2 1.1 1.1 1.3 1.2 1.1 1.0

65 1.6 1.5 1.4 1.3 1.6 1.4 1.4 1.2

70 1.8 1.7 1.6 1.5 1.8 1.7 1.6 1.5

75 2.1 2.0 1.9 1.7 2.1 2.0 1.8 1.7

80 2.5 2.3 2.2 2.0 2.5 2.3 2.1 2.0

85 2.8 2.6 2.5 2.3 2.8 2.6 2.4 2.3

90 3.2 3.0 2.8 2.6 3.2 3.0 2.8 2.6

95 3.7 3.4 3.2 3.6 3.4 3.2

100 4.2 3.9 3.6 4.1 3.9 3.6

Note: See Chapter 13 of this bulletin for Point of Maximum Stress design requirements 

for poles longer than 55 feet.
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)

Note: See Chapter 13 of this bulletin for Point of Maximum Stress design requirements for poles 

longer than 55 feet.

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

*based on standard 10% + 2 feet embedment depth
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 11,400

H5 10,000

H4 8,700

H3 7,500

H2 6,400

H1 5,400

1 4,500

2 3,700

3 3,000

4 2,400

5 1,900

6 1,500

7 1,200

9 740

10 370

Reference: American National Standards Institute 05.1.2008, Annex B.
Bulletin 1724E-200

Page F-5

DOUGLAS FIR AND SOUTHERN YELLOW PINE

Ultimate Bending Stress – 8000 psi

55 ft. 55 ft. Class H1 Class 1 Class 2 Class 3

Dist.

(ft.)

Dia.

(in.)

Area

(sq. in.)

Moment

(ft-k)

Dia.

(in.)

Area

(sq. in.)

Moment

(ft-k)

Dist.

(ft.)

Dia.

(in.)

Area

(sq. in.)

Moment

(ft-k)

Dia.

(in.)

Area

(sq. in.)

Moment

(ft-k)

Dist.

(ft.)

0 9.23 66.92 51.5 8.59 58.01 41.5 0 7.96 49.74 33.0 7.32 42.10 25.7 0

1 9.36 68.87 53.7 8.72 59.73 43.4 1 8.08 51.25 34.5 7.43 43.41 26.9 1

2 9.50 70.84 56.1 8.85 61.48 45.3 2 8.20 52.79 36.1 7.55 44.75 28.2 2

3 9.63 72.84 58.5 8.97 63.26 47.3 3 8.32 54.34 37.7 7.66 46.11 29.4 3

4 9.76 74.87 60.9 9.10 65.05 49.3 4 8.44 55.93 39.3 7.78 47.49 30.8 4

5 9.90 76.93 63.4 9.23 66.88 51.4 5 8.56 57.53 41.0 7.89 48.89 32.1 5

6 10.03 79.01 66.0 9.35 68.73 53.6 6 8.68 59.16 42.8 8.00 50.31 33.6 6

7 10.16 81.12 68.7 9.48 70.60 55.8 7 8.80 60.81 44.6 8.12 51.75 35.0 7

8 10.30 83.26 71.4 9.61 72.5 58.0 8 8.92 62.48 46.4 8.23 53.20 36.5 8

9 10.43 85.43 74.3 9.73 74.42 60.4 9 9.04 64.17 48.3 8.34 54.68 38.0 9

10 10.56 87.63 77.1 9.86 76.37 62.8 10 9.16 65.89 50.3 8.46 56.18 39.6 10

11 10.70 89.85 80.1 9.99 78.35 65.2 11 9.28 67.63 52.5 8.57 57.71 41.2 11

12 10.83 92.10 83.1 10.11 80.35 67.7 12 9.40 69.40 54.4 8.69 59.25 42.9 12

13 10.96 94.38 86.2 10.24 82.37 70.3 13 9.52 71.18 56.5 8.80 60.81 44.6 13

14 11.10 96.69 89.4 10.37 84.42 72.9 14 9.64 72.99 58.6 8.91 62.39 46.3 14

15 11.23 99.02 92.7 10.49 86.50 75.6 15 9.76 74.82 60.9 9.03 63.99 48.1 15

16 11.36 101.39 96.0 10.62 88.60 78.4 16 9.88 76.68 63.1 9.14 65.61 50.0 16

17 11.49 103.78 99.4 10.75 90.73 81.3 17 10.00 78.55 65.5 9.25 67.25 51.9 17

18 11.63 106.19 102.9 10.87 92.88 84.2 18 10.12 80.45 67.9 9.37 68.92 53.8 18

19 11.76 108.64 106.5 11.00 95.05 87.1 19 10.24 82.37 70.3 9.48 70.60 55.8 19

20 11.89 111.12 110.1 11.13 92.26 90.2 20 10.36 84.32 72.8 9.59 72.30 57.8 20

21 12.03 113.62 113.9 11.25 99.48 93.3 21 10.48 86.29 75.4 9.71 74.03 59.9 21

22 12.16 116.15 117.7 11.38 101.73 96.5 22 10.60 88.28 78.0 9.82 75.77 62.0 22

23 12.29 118.71 121.6 11.51 104.01 99.7 23 10.72 90.29 80.7 9.94 77.53 64.2 23

24 12.43 121.29 125.6 11.63 106.31 103.1 24 10.84 92.32 83.4 10.05 79.32 66.4 24

25 12.56 123.90 129.7 11.76 108.64 106.5 25 10.96 94.38 86.2 10.16 81.12 68.7 25

26 12.69 126.55 133.9 11.89 110.99 110.0 26 11.08 96.46 89.1 10.28 82.95 71.0 26

27 12.83 129.21 138.1 12.01 113.37 113.5 27 11.20 98.57 92.0 10.39 84.79 73.4 27

28 12.96 131.91 142.5 12.14 115.78 117.1 28 11.32 100.69 95.0 10.50 86.66 75.9 28

29 13.09 134.64 146.9 12.27 118.20 120.8 29 11.44 102.84 98.1 10.62 88.55 78.3 29

30 13.23 137.39 151.4 12.39 120.66 124.6 30 11.56 105.01 101.2 10.73 90.45 80.9 30

31 13.36 140.17 156.0 12.52 123.14 128.5 31 11.68 107.21 104.4 10.85 92.38 83.5 31

32 13.49 142.98 160.8 12.65 125.64 132.4 32 11.80 109.42 107.6 10.96 94.33 86.1 32

33 13.63 145.81 165.6 12.77 128.17 136.4 33 11.92 111.66 111.0 11.07 96.29 88.9 33

34 13.76 148.68 170.5 12.90 130.72 140.5 34 12.04 113.92 114.3 11.19 98.28 91.6 34

35 13.89 151.57 175.5 13.03 133.30 144.7 35 12.16 116.21 117.8 11.30 100.29 94.4 35

36 14.03 154.49 180.6 13.15 135.91 149.0 36 12.28 118.52 121.3 11.41 102.32 97.3 36

37 14.16 157.44 185.8 13.28 138.54 153.3 37 12.40 120.85 124.9 11.53 104.36 100.3 37

38 14.29 160.41 191.0 13.41 141.19 157.8 38 12.52 123.20 128.6 11.64 106.43 103.2 38

39 14.42 163.42 196.4 13.53 143.87 162.3 39 12.64 125.58 132.3 11.75 108.52 106.3 39

40 14.56 166.45 201.9 13.66 146.58 166.9 40 12.76 127.97 136.1 11.87 110.63 109.4 40

41 14.69 169.51 207.5 13.79 149.31 171.6 41 12.89 130.40 140.0 11.98 112.76 112.6 41

42 14.82 172.60 213.2 13.91 152.07 176.3 42 13.01 132.84 144.0 12.10 114.91 115.8 42

43 14.96 175.71 219.0 14.04 154.85 181.2 43 13.13 135.31 148.0 12.21 117.08 119.1 43

44 15.09 178.85 224.9 14.17 157.66 186.1 44 13.25 137.79 152.1 12.32 119.27 122.5 44

45 15.22 182.02 230.9 14.29 160.49 191.2 45 13.37 140.31 156.3 12.44 121.48 125.9 45

46 15.36 185.22 237.0 14.42 163.34 196.3 46 13.49 142.84 160.5 12.55 123.71 129.4 46

47 15.49 188.45 243.3 14.55 166.23 201.5 47 13.61 145.40 164.9 12.66 125.96 132.9 47

48 15.62 191.70 249.6 14.67 169.13 206.8 48 13.73 147.98 169.3 12.78 128.24 136.5 48

49 15.76 194.98 256.0 14.80 172.07 212.2 49 13.85 150.58 173.8 12.89 130.53 140.2 49

50 15.82 196.64 259.3 14.87 173.62 215.1 50 13.91 152.04 176.3 12.96 131.88 142.4 50

51 15.89 198.31 262.6 14.94 175.19 218.0 51 13.98 153.50 178.8 13.03 133.25 144.6 51

52 15.96 199.98 265.9 15.00 176.76 221.0 52 14.05 154.97 181.4 13.09 134.62 146.9 52

53 16.02 201.66 269.3 15.07 178.34 223.9 53 14.11 156.45 184.0 13.16 136.00 149.1 53

54 16.09 203.34 272.7 15.14 179.92 226.9 54 14.18 157.94 186.6 13.23 137.38 151.4 54

55 16.16 205.04 276.1 15.20 181.52 230.0 55 14.25 159.43 189.3 13.29 138.77 153.7 55
Bulletin 1724E-200

Page F-6

DOUGLAS FIR AND SOUTHERN YELLOW PINE

Ultimate Bending Stress – 8000 psi

60 ft. 60 ft. Class H1 Class 1 Class 2 Class 3

Dist.

(ft.)

Dia.

(in.)

Area

(sq. in.)

Moment

(ft-k)

Dia.

(in.)

Area

(sq. in.)

Moment

(ft-k)

Dist.

(ft.)

Dia.

(in.)

Area

(sq. in.)

Moment

(ft-k)

Dia.

(in.)

Area

(sq. in.)

Moment

(ft-k)

Dist.

(ft.)

0 9.231 66.92 51.5 8.594 58.01 41.5 0 7.958 49.74 33.0 7.32 42.10 25.7 0

1 9.361 68.82 53.7 8.718 59.70 43.4 1 8.076 51.22 34.5 7.43 43.39 26.9 1

2 9.49 70.74 55.9 8.842 61.40 45.2 2 8.194 52.73 36.0 7.55 44.71 28.1 2

3 9.62 72.68 58.3 8.966 63.13 47.2 3 8.311 54.26 37.6 7.66 46.05 29.4 3

4 9.75 74.66 60.7 9.09 64.89 49.2 4 8.429 55.81 39.2 7.77 47.41 30.7 4

5 9.879 76.66 63.1 9.213 66.67 51.2 5 8.547 57.38 40.9 7.88 48.78 32.0 5

6 10.01 78.68 65.6 9.337 68.47 53.3 6 8.665 58.97 42.6 7.99 50.18 33.4 6

7 10.14 80.73 68.2 9.461 70.30 55.4 7 8.783 60.59 44.3 8.11 51.60 34.8 7

8 10.27 82.81 70.9 9.585 72.15 57.6 8 8.901 60.22 46.2 8.22 53.03 36.3 8

9 10.4 84.92 73.6 9.708 74.03 59.9 9 9.019 63.88 48.0 8.33 54.49 37.8 9

10 10.53 87.05 76.4 9.832 75.93 62.2 10 9.137 65.56 49.9 8.44 55.96 39.4 10

11 10.66 89.21 79.2 9.956 77.85 64.6 11 9.255 67.27 51.9 8.55 57.46 41.0 11

12 10.79 91.39 82.2 10.08 79.80 67.0 12 9.372 68.99 53.9 8.67 58.97 42.6 12

13 10.92 93.60 85.2 10.2 81.77 69.5 13 9.49 70.74 55.9 8.78 60.51 44.3 13

14 11.05 95.84 88.2 10.33 83.77 72.1 14 9.608 72.51 58.1 8.89 62.06 46.0 14

15 11.18 98.10 91.4 10.45 85.79 74.7 15 9.726 74.30 60.2 9.00 63.63 47.7 15

16 11.31 100.39 94.6 10.57 87.83 77.4 16 9.844 76.11 62.4 9.11 65.23 49.5 16

17 11.44 102.71 97.9 10.7 89.90 80.2 17 9.962 77.94 64.7 9.23 66.84 51.4 17

18 11.57 105.05 101.2 10.82 91.99 83.0 18 10.08 79.80 67.0 9.34 68.47 53.3 18

19 11.69 107.42 104.7 10.95 94.11 85.8 19 10.2 81.68 69.4 9.45 70.12 55.2 19

20 11.82 109.82 108.2 11.07 96.25 88.8 20 10.32 83.58 71.8 9.56 71.80 57.2 20

21 11.95 112.24 111.8 11.19 98.41 91.8 21 10.43 85.50 74.3 9.67 73.49 59.2 21

22 12.08 114.69 115.5 11.32 100.60 94.9 22 10.55 87.44 76.9 9.79 75.20 61.3 22

23 12.21 117.16 119.2 11.44 102.81 98.0 23 10.67 89.40 79.5 9.90 76.93 63.4 23

24 12.34 119.66 123.1 11.57 105.05 101.2 24 10.79 91.39 82.2 10.01 78.68 65.6 24

25 12.47 122.19 127.0 11.69 107.31 104.5 25 10.91 93.40 84.9 10.12 80.45 67.9 25

26 12.6 124.74 131.0 11.81 109.60 107.9 26 11.02 95.43 87.7 10.23 82.24 70.1 26

27 12.73 127.32 135.1 11.94 111.91 111.3 27 11.14 97.48 90.5 10.35 84.05 72.5 27

28 12.86 129.93 139.3 12.06 114.24 114.8 28 11.26 99.56 93.4 10.46 85.88 74.8 28

29 12.99 132.56 143.5 12.18 116.60 118.4 29 11.38 101.65 96.4 10.57 87.73 77.3 29

30 13.12 135.22 147.9 12.31 118.98 122.0 30 11.49 103.77 99.4 10.68 89.60 79.8 30

31 13.25 137.91 152.3 12.43 121.38 125.7 31 11.61 105.91 102.5 10.79 91.49 82.3 31

32 13.38 140.62 156.8 12.56 123.81 129.5 32 11.73 108.07 105.6 10.91 93.40 84.9 32

33 13.51 143.36 161.4 12.68 126.27 133.4 33 11.85 110.25 108.9 11.02 95.33 87.5 33

34 13.64 146.13 166.1 12.8 128.74 137.4 34 11.97 112.46 112.1 11.13 97.28 90.2 34

35 13.77 148.92 170.9 12.93 131.24 141.4 35 12.08 114.69 115.5 11.24 99.24 93.0 35

36 13.9 151.74 175.8 13.05 133.77 145.5 36 12.2 116.93 118.9 11.35 101.23 95.8 36

37 14.03 154.58 180.7 13.17 136.32 149.7 37 12.32 119.21 122.4 11.47 103.24 98.6 37

38 14.16 157.45 185.8 13.3 138.89 153.9 38 12.44 121.50 125.9 11.58 105.27 101.6 38

39 14.29 160.35 190.9 13.42 141.49 158.3 39 12.56 123.81 129.5 11.69 107.31 104.5 39

40 14.42 163.27 196.2 13.55 144.11 162.7 40 12.67 126.15 133.2 11.80 109.38 107.6 40

41 14.55 166.22 201.5 13.67 146.76 167.2 41 12.79 126.51 137.0 11.91 111.46 110.7 41

42 14.68 169.20 207.0 13.79 149.43 171.8 42 12.91 130.89 140.8 12.03 113.57 113.8 42

43 14.81 172.20 212.5 13.92 152.12 176.4 43 13.03 133.29 144.7 12.14 115.70 117.0 43

44 14.94 175.23 218.1 14.04 154.84 181.2 44 13.15 135.71 148.7 12.25 117.84 120.3 44

45 15.07 178.29 223.9 14.16 157.58 186.0 45 13.26 138.16 152.7 12.36 120.01 123.6 45

46 15.2 181.37 229.7 14.29 160.35 190.9 46 13.38 140.62 156.8 12.47 122.19 127.0 46

47 15.33 184.48 235.6 14.41 163.14 195.9 47 13.5 143.11 161.0 12.59 124.39 130.5 47

48 15.46 187.62 241.6 14.54 165.95 201.0 48 13.62 145.62 165.2 12.70 126.62 134.0 48

49 15.59 190.78 247.8 14.66 168.79 206.2 49 13.73 148.15 169.6 12.81 128.86 137.5 49

50 15.72 193.96 254.0 14.78 171.66 211.5 50 13.85 150.71 174.0 12.92 131.12 141.2 50

51 15.84 197.18 260.4 14.91 174.54 216.8 51 13.97 153.28 178.5 13.03 133.41 144.9 51

52 15.97 200.42 266.8 15.03 177.45 222.3 52 14.09 155.88 183.0 13.15 135.71 148.7 52

53 16.1 203.69 273.4 15.16 180.39 227.8 53 14.21 158.50 187.6 13.26 138.03 152.5 53

54 16.23 206.98 280.0 15.28 183.35 233.4 54 14.32 161.14 192.4 13.37 140.37 156.4 54

55 16.3 208.69 283.5 15.35 184.95 236.5 55 14.39 162.65 195.1 13.44 141.78 158.7 55
Bulletin 1724E-200

Page F-7

DOUGLAS FIR AND SOUTHERN YELLOW PINE

Ultimate Bending Stress – 8000 psi

60 ft. 60 ft. Class H1 Class 1 Class 2 Class 3

Dist.

(ft.)

Dia.

(in.)

Area

(sq. in.)

Moment

(ft-k)

Dia.

(in.)

Area

(sq. in.)

Moment

(ft-k)

Dist.

(ft.)

Dia.

(in.)

Area

(sq. in.)

Moment

(ft-k)

Dia.

(in.)

Area

(sq. in.)

Moment

(ft-k)

Dist.

(ft.)

56 16.37 210.40 287.0 15.41 186.57 239.6 56 14.46 164.17 197.8 13.50 143.20 161.1 56

57 16.43 212.13 290.5 15.48 188.19 242.8 57 14.52 165.69 200.5 13.57 144.62 163.5 57

58 16.5 213.86 294.1 15.55 189.82 245.9 58 14.59 167.22 203.3 13.64 146.05 166.0 58

59 16.57 215.59 297.7 15.61 191.46 249.1 59 14.66 168.75 206.1 13.70 147.48 168.4 59

60 16.63 217.33 301.3 15.68 193.10 252.3 60 14.73 170.29 209.0 13.77 148.92 170.9 60
Bulletin 1724E-200

Page F-8

DOUGLAS FIR AND SOUTHERN YELLOW PINE

Ultimate Bending Stress – 8000 psi

65 ft. 65 ft. Class H1 Class 1 Class 2 Class 3

Dist.

(ft.)

Dia.

(in.)

Area

(sq. in.)

Moment

(ft-k)

Dia.

(in.)

Area

(sq. in.)

Moment

(ft-k)

Dist.

(ft.)

Dia.

(in.)

Area

(sq. in.)

Moment

(ft-k)

Dia.

(in.)

Area

(sq. in.)

Moment

(ft-k)

Dist.

(ft.)

0 9.23 66.9 51.5 8.59 58.0 41.5 0 7.96 49.7 33.0 7.32 42.1 25.7 0

1 9.36 68.8 53.6 8.72 59.7 43.3 1 8.07 51.2 34.4 7.43 43.4 26.9 1

2 9.48 70.7 55.8 8.84 61.3 45.2 2 8.19 52.7 36.0 7.54 44.7 28.1 2

3 9.61 72.6 58.1 8.96 63.0 47.1 3 8.31 54.2 37.5 7.65 46.0 29.3 3

4 9.74 74.5 60.4 9.08 64.8 49.0 4 8.42 55.7 39.1 7.76 47.3 30.6 4

5 9.86 76.4 62.8 9.20 66.5 51.0 5 8.54 57.2 40.7 7.87 48.7 32.0 5

6 9.99 78.4 65.3 9.32 68.3 53.0 6 8.65 58.8 42.4 7.98 50.1 33.3 6

7 10.12 80.4 67.8 9.44 70.1 55.1 7 8.77 60.4 44.1 8.10 51.5 34.7 7

8 10.25 82.4 70.4 9.57 71.9 57.3 8 8.89 62.0 45.9 8.21 52.9 36.2 8

9 10.37 84.5 73.0 9.69 73.7 59.5 9 9.00 63.6 47.7 8.32 54.3 37.6 9

10 10.50 86.6 75.7 9.81 75.6 61.8 10 9.12 65.3 49.6 8.43 55.8 39.2 10

11 10.63 88.7 78.5 9.93 77.4 64.1 11 9.23 67.0 51.5 8.54 57.2 40.7 11

12 10.75 90.8 81.4 10.05 79.3 66.5 12 9.35 68.7 53.5 8.65 58.7 42.3 12

13 10.88 93.0 84.3 10.17 81.3 68.9 13 9.47 70.4 55.5 8.76 60.3 44.0 13

14 11.01 95.1 87.3 10.29 83.2 71.4 14 9.58 72.1 57.6 8.87 61.8 45.7 14

15 11.13 97.3 90.3 10.42 85.2 73.9 15 9.70 73.9 59.7 8.98 63.3 47.4 15

16 11.26 99.6 93.4 10.54 87.2 76.6 16 9.81 75.6 61.9 9.09 64.9 49.2 16

17 11.39 101.8 96.6 10.66 89.2 79.2 17 9.93 77.4 64.1 9.20 66.5 51.0 17

18 11.51 104.1 99.9 10.78 91.3 82.0 18 10.05 79.3 66.4 9.31 68.1 52.8 18

19 11.64 106.4 103.2 10.90 93.3 84.8 19 10.16 81.1 68.7 9.42 69.7 54.8 19

20 11.77 108.7 106.6 11.02 95.4 87.6 20 10.28 83.0 71.1 9.53 71.4 56.7 20

21 11.89 111.1 110.1 11.14 97.5 90.6 21 10.39 84.8 73.5 9.64 73.0 58.7 21

22 12.02 113.5 113.7 11.26 99.7 93.6 22 10.51 86.7 76.0 9.75 74.7 60.7 22

23 12.15 115.9 117.3 11.39 101.8 96.6 23 10.63 88.7 78.5 9.86 76.4 62.8 23

24 12.27 118.3 121.0 11.51 104.0 99.7 24 10.74 90.6 81.1 9.98 78.2 65.0 24

25 12.40 120.8 124.8 11.63 106.2 102.9 25 10.86 92.6 83.5 10.09 79.9 67.2 25

26 12.53 123.3 128.7 11.75 108.4 106.2 26 10.97 94.6 86.5 10.20 81.7 69.4 26

27 12.65 125.8 132.6 11.87 110.7 109.5 27 11.09 96.6 89.3 10.31 83.4 71.7 27

28 12.78 128.3 136.6 11.99 113.0 112.9 28 11.21 98.6 92.1 10.42 85.2 74.0 28

29 12.91 130.9 140.8 12.11 115.3 116.4 29 11.32 100.7 95.0 10.53 87.1 76.4 29

30 13.03 133.4 144.9 12.24 117.6 119.9 30 11.44 102.7 97.9 10.64 88.9 78.8 30

31 13.16 136.0 149.2 12.36 119.9 123.5 31 11.55 104.8 100.9 10.75 90.8 81.3 31

32 13.29 138.7 153.6 12.48 122.3 127.2 32 11.67 107.0 104.0 10.86 92.6 83.8 32

33 13.41 141.3 158.0 12.60 124.7 130.9 33 11.79 109.1 107.1 10.97 94.5 86.4 33

34 13.54 144.0 162.5 12.72 127.1 134.8 34 11.90 111.2 110.3 11.08 96.4 89.1 34

35 13.67 146.7 167.1 12.84 129.5 138.6 35 12.02 113.4 113.6 11.19 98.4 91.8 35

36 13.80 149.5 171.8 12.96 132.0 142.6 36 12.13 115.6 116.9 11.30 100.3 94.5 36

37 13.92 152.2 176.6 13.09 134.5 146.7 37 12.25 117.8 120.3 11.41 102.3 97.3 37

38 14.05 155.0 181.5 13.21 137.0 150.8 38 12.37 120.1 123.8 11.52 104.3 100.2 38

39 14.18 157.8 186.4 13.33 139.5 155.0 39 12.48 122.4 127.3 11.63 106.3 103.1 39

40 14.30 160.7 191.5 13.45 142.1 159.2 40 12.60 124.6 130.8 11.75 108.3 106.0 40

41 14.43 163.5 196.6 13.57 144.7 163.6 41 12.71 126.9 134.5 11.86 110.4 109.1 41

42 14.56 166.4 201.9 13.69 147.3 168.0 42 12.83 129.3 138.2 11.97 112.5 112.1 42

43 14.68 169.3 207.2 13.81 149.9 172.5 43 12.95 131.6 142.0 12.08 114.6 115.3 43

44 14.81 172.3 212.6 13.94 152.5 177.1 44 13.06 134.0 145.8 12.19 116.7 118.5 44

45 14.94 175.2 218.1 14.06 155.2 181.8 45 13.18 136.4 149.8 12.30 118.8 121.7 45

46 15.06 178.2 223.7 14.18 157.9 186.5 46 13.29 138.8 153.8 12.41 120.9 125.1 46

47 15.19 181.2 229.4 14.30 160.6 191.4 47 13.41 141.2 157.8 12.52 123.1 128.4 47

48 15.32 184.3 235.2 14.42 163.3 196.3 48 13.53 143.7 161.9 12.63 125.3 131.9 48

49 15.44 187.3 241.1 14.54 166.1 201.3 49 13.64 146.2 166.1 12.74 127.5 135.4 49

50 15.57 190.4 247.1 14.66 168.9 206.4 50 13.76 148.7 170.4 12.85 129.7 138.9 50

51 15.70 193.5 253.1 14.79 171.7 211.5 51 13.87 151.2 174.8 12.96 132.0 142.5 51

52 15.82 196.7 259.3 14.91 174.5 216.8 52 13.99 153.7 179.2 13.07 134.2 146.2 52

53 15.95 199.8 265.6 15.03 177.4 222.1 53 14.11 156.3 183.7 13.18 136.5 149.9 53

54 16.08 203.0 272.0 15.15 180.3 227.6 54 14.22 158.8 188.3 13.29 138.8 153.8 54

55 16.20 206.2 278.5 15.27 183.2 233.1 55 14.34 161.4 192.9 13.40 141.1 157.6 55
Bulletin 1724E-200

Page F-9

DOUGLAS FIR AND SOUTHERN YELLOW PINE

Ultimate Bending Stress – 8000 psi

65 ft. 65 ft. Class H1 Class 1 Class 2 Class 3

Dist.

(ft.)

Dia.

(in.)

Area

(sq. in.)

Moment

(ft-k)

Dia.

(in.)

Area

(sq. in.)

Moment

(ft-k)

Dist.

(ft.)

Dia.

(in.)

Area

(sq. in.)

Moment

(ft-k)

Dia.

(in.)

Area

(sq. in.)

Moment

(ft-k)

Dist.

(ft.)

56 16.33 209.5 285.1 15.39 186.1 238.7 56 14.45 164.1 197.6 13.51 143.5 161.6 56

57 16.46 212.7 291.8 15.51 189.0 244.4 57 14.57 166.7 202.4 13.63 145.8 165.6 57

58 16.58 216.0 298.5 15.63 192.0 250.1 58 14.69 169.4 207.3 13.74 148.2 169.6 58

59 16.71 219.3 305.4 15.76 195.0 256.0 59 14.80 172.1 212.2 13.85 150.6 173.8 59

60 16.78 221.1 309.1 15.82 196.6 259.3 60 14.87 173.6 215.1 13.91 152.0 176.3 60

61 16.84 222.9 312.8 15.89 198.3 262.6 61 14.94 175.2 218.0 13.98 153.5 178.8 61

62 16.91 224.6 316.6 15.96 200.0 265.9 62 15.00 176.8 221.0 14.05 155.0 181.4 62

63 16.98 226.4 320.3 16.02 201.7 269.3 63 15.07 178.3 223.9 14.11 156.5 184.0 63

64 17.05 228.2 324.1 16.09 203.3 272.7 64 15.14 179.9 226.9 14.18 157.9 186.6 64

65 17.11 230.0 328.0 16.16 205.0 276.1 65 15.20 181.5 230.0 14.25 159.4 189.3 65
Bulletin 1724E-200

Page F-10

DOUGLAS FIR AND SOUTHERN YELLOW PINE

Ultimate Bending Stress – 8000 psi

70 ft. 70 ft. Class H1 Class 1 Class 2 Class 3

Dist.

(ft.)

Dia.

(in.)

Area

(sq. 

in.)

Moment

(ft-k)

Dia.

(in.)

Area

(sq. 

in.)

Moment

(ft-k)

Dist.

(ft.)

Dia.

(in.)

Area

(sq. 

in.)

Moment

(ft-k)

Dia.

(in.)

Area

(sq. 

in.)

Moment

(ft-k)

Dist.

(ft.)

0 9.23 66.9 51.5 8.59 58.0 41.5 0 7.96 49.7 33.0 7.32 42.1 25.7 0

1 9.36 68.7 53.6 8.71 59.6 43.3 1 8.07 51.2 34.4 7.43 43.4 26.9 1

2 9.48 70.6 55.8 8.83 61.3 45.1 2 8.19 52.6 35.9 7.54 44.7 28.1 2

3 9.60 72.4 58.0 8.95 62.8 47.0 3 8.30 54.1 37.4 7.65 46.0 29.3 3

4 9.73 74.3 60.3 9.07 64.6 48.9 4 8.42 55.6 39.0 7.76 47.3 30.6 4

5 9.85 76.2 62.6 9.19 66.3 50.8 5 8.53 57.1 40.6 7.87 48.6 31.9 5

6 9.98 78.2 65.0 9.31 68.1 52.8 6 8.64 58.7 42.3 7.98 50.0 33.2 6

7 10.10 80.1 67.5 9.43 69.8 54.9 7 8.76 60.2 44.0 8.09 51.4 34.6 7

8 10.23 82.1 70.0 9.55 71.6 57.0 8 8.87 61.8 45.7 8.20 52.8 36.0 8

9 10.35 84.1 72.6 9.67 73.4 59.2 9 8.99 63.4 47.5 8.31 54.2 37.2 9

10 10.47 86.2 75.2 9.79 75.2 61.4 10 9.10 65.1 49.3 8.42 55.6 39.0 10

11 10.60 88.2 77.9 9.91 77.1 63.6 11 9.22 66.7 51.2 8.52 57.1 40.5 11

12 10.72 90.3 80.7 10.03 79.0 66.0 12 9.33 68.4 53.2 8.63 58.6 42.1 12

13 10.85 92.4 83.5 10.15 80.9 68.4 13 9.44 70.1 55.1 8.74 60.0 43.7 13

14 10.97 94.5 86.4 10.27 82.8 70.8 14 9.56 71.8 57.2 8.85 61.6 45.4 14

15 11.10 96.7 89.4 10.38 84.7 73.3 15 9.67 73.5 59.2 8.96 63.1 47.1 15

16 11.22 98.9 92.5 10.50 86.7 75.9 16 9.79 75.2 61.4 9.07 64.2 48.9 16

17 11.34 101.1 95.6 10.62 88.6 78.5 17 9.90 77.0 63.6 9.18 66.2 50.7 17

18 11.47 103.3 98.7 10.74 90.6 81.1 18 10.02 78.8 65.8 9.29 67.8 52.5 18

19 11.59 105.6 102.0 10.86 92.7 83.9 19 10.13 80.6 68.1 9.40 69.4 54.4 19

20 11.72 107.8 105.3 10.98 94.7 86.7 20 10.25 82.4 70.4 9.51 71.0 56.3 20

21 11.84 110.1 108.7 11.10 96.8 89.5 21 10.36 84.3 72.8 9.62 72.7 58.2 21

22 11.97 112.5 112.2 11.22 98.9 92.5 22 10.47 86.2 75.2 9.73 74.3 60.3 22

23 12.09 114.8 115.7 11.34 101.0 94.5 23 10.59 88.1 77.7 9.84 76.0 62.3 23

24 12.22 117.2 119.3 11.46 103.1 98.5 24 10.70 90.0 80.3 9.95 77.7 64.4 24

25 12.34 119.6 123.0 11.58 105.3 101.6 25 10.82 91.9 82.9 10.06 79.4 66.6 25

26 12.46 122.0 126.7 11.70 107.5 104.8 26 10.93 93.9 85.5 10.17 81.2 68.8 26

27 12.59 124.5 130.6 11.82 109.7 108.8 27 11.05 95.8 88.2 10.28 82.9 71.0 27

28 12.71 126.9 134.5 11.94 111.9 111.3 28 11.16 97.8 91.0 10.38 84.7 73.3 28

29 12.84 129.4 138.4 12.06 114.2 114.7 29 11.28 99.8 93.8 10.49 86.5 75.6 29

30 12.96 131.9 142.5 12.18 116.4 118.1 30 11.39 101.9 96.7 10.60 88.3 78.0 30

31 13.09 134.5 146.6 12.29 118.7 121.6 31 11.50 103.9 99.6 10.71 90.1 80.5 31

32 13.21 137.1 150.9 12.41 121.0 125.2 32 11.62 106.9 102.6 10.82 92.0 83.0 32

33 13.33 139.6 155.2 12.53 123.4 128.9 33 11.73 108.1 105.7 10.93 93.9 85.5 33

34 13.46 142.3 159.6 12.65 125.7 132.6 34 11.85 110.2 108.8 11.04 95.7 88.1 34

35 13.58 144.9 164.0 12.77 128.1 136.4 35 11.96 112.4 112.0 11.15 97.7 90.7 35

36 13.71 147.6 168.6 12.89 130.5 140.2 36 12.08 114.5 115.3 11.26 99.6 93.4 36

37 13.83 150.3 173.2 13.01 133.0 144.2 37 12.19 116.7 118.6 11.37 101.5 96.2 37

38 13.96 153.0 177.9 13.13 135.4 148.2 38 12.30 118.9 121.9 11.48 103.5 99.0 38

39 14.08 155.7 182.7 13.25 137.9 152.2 39 12.42 121.1 125.4 11.59 105.5 101.9 39

40 14.20 158.5 187.6 13.37 140.4 156.4 40 12.53 123.4 128.9 11.70 107.5 104.8 40

41 14.33 161.3 192.6 13.49 142.9 160.6 41 12.65 125.6 132.4 11.81 109.5 107.7 41

42 14.45 164.1 197.6 13.61 145.4 164.9 42 12.76 127.9 126.0 11.92 111.5 110.8 42

43 14.58 166.9 202.8 13.73 148.0 169.3 43 12.88 130.2 139.7 12.03 113.6 113.8 43

44 14.70 169.8 208.0 13.85 150.6 173.8 44 12.99 132.5 143.5 12.14 115.7 117.0 44

45 14.83 172.6 213.3 13.97 153.2 178.3 45 13.11 134.9 147.3 12.24 117.8 120.2 45

46 14.95 175.6 218.7 14.09 155.8 182.9 46 13.22 137.3 151.2 12.35 119.9 123.4 46

47 15.07 178.5 224.2 14.20 158.5 187.6 47 13.33 139.6 155.2 12.46 122.0 126.7 47

48 15.20 181.4 229.8 14.32 161.1 192.4 48 13.45 142.1 159.2 12.57 124.2 130.1 48

49 15.32 184.4 235.5 14.44 163.5 197.2 49 13.56 144.5 163.3 12.68 126.3 133.5 49

50 15.45 187.4 241.3 14.56 166.6 202.1 50 13.68 146.9 167.5 12.79 128.5 137.0 50

51 15.57 190.5 247.2 14.68 169.3 207.1 51 13.79 149.4 171.7 12.90 130.7 140.5 51

52 15.70 193.5 253.1 14.80 172.1 212.2 52 13.91 151.9 176.0 13.01 133.0 144.2 52

53 15.82 196.6 259.2 14.92 174.9 217.4 53 14.02 154.4 180.4 13.12 135.2 147.8 53

54 15.95 199.7 265.3 15.04 177.7 222.7 54 14.13 156.9 184.8 13.23 137.5 151.6 54

55 16.07 202.8 271.6 15.16 180.5 228.0 55 14.25 159.5 189.4 13.34 139.7 155.3 55
Bulletin 1724E-200

Page F-11

DOUGLAS FIR AND SOUTHERN YELLOW PINE

Ultimate Bending Stress – 8000 psi

70 ft. 70 ft. Class H1 Class 1 Class 2 Class 3

Dist.

(ft.)

Dia.

(in.)

Area

(sq. in.)

Moment

(ft-k)

Dia.

(in.)

Area

(sq. in.)

Moment

(ft-k)

Dist.

(ft.)

Dia.

(in.)

Area

(sq. in.)

Moment

(ft-k)

Dia.

(in.)

Area

(sq. in.)

Moment

(ft-k)

Dist.

(ft.)

56 16.19 206.0 278.0 15.28 183.3 233.4 56 14.36 162.0 194.0 13.45 142.1 159.2 56

57 16.32 209.1 284.4 15.40 186.2 239.0 57 14.48 164.6 198.6 13.56 144.4 163.1 57

58 16.44 212.3 291.0 15.52 189.1 244.6 58 14.59 167.2 203.4 13.67 146.7 167.1 58

59 16.57 215.6 297.6 15.64 192.0 250.2 59 14.71 169.9 208.2 13.78 149.1 171.1 59

60 16.69 218.8 304.4 15.76 195.0 256.0 60 14.82 172.5 213.1 13.89 151.4 175.3 60

61 16.82 222.1 311.2 15.88 198.0 261.9 61 14.94 175.2 218.1 14.00 153.8 179.4 61

62 16.94 225.4 318.2 16.00 200.9 267.8 62 15.05 177.9 223.1 14.11 156.3 183.7 62

63 17.06 228.7 325.2 16.11 203.9 273.9 63 15.16 180.6 228.2 14.21 158.7 188.0 63

64 17.19 232.0 332.4 16.23 207.9 280.0 64 15.28 183.3 233.4 14.32 161.1 192.4 64

65 17.26 233.9 336.3 16.30 208.9 283.5 65 15.35 185.0 236.5 14.39 162.7 195.1 65

66 17.32 235.7 340.2 16.37 210.4 287.0 66 15.41 186.6 239.6 14.46 164.2 197.8 66

67 17.39 237.5 344.2 16.43 212.1 290.5 67 15.48 188.2 242.8 14.52 165.7 200.5 67

68 17.46 239.3 348.1 16.50 213.9 294.1 68 15.55 189.8 245.9 14.59 167.2 203.3 68

69 17.52 241.2 352.2 16.57 215.6 297.7 69 15.61 191.5 249.1 14.66 168.8 206.1 69

70 17.59 243.0 356.2 16.63 217.3 301.3 70 15.68 193.1 252.3 14.73 170.3 209.0 70
Bulletin 1724E-200

Page F-12

DOUGLAS FIR AND SOUTHERN YELLOW PINE

Ultimate Bending Stress – 8000 psi

75 ft. 75 ft. Class H1 Class 1 Class 2 Class 3

Dist.

(ft.)

Dia.

(in.)

Area

(sq. in.)

Moment

(ft-k)

Dia.

(in.)

Area

(sq. in.)

Moment

(ft-k)

Dist.

(ft.)

Dia.

(in.)

Area

(sq. in.)

Moment

(ft-k)

Dia.

(in.)

Area

(sq. in.)

Moment

(ft-k)

Dist.

(ft.)

0 9.23 66.9 51.3 8.59 58.0 41.5 0 7.96 49.7 33.0 7.32 42.1 25.7 0

1 9.35 68.7 53.6 8.71 59.6 43.3 1 8.07 51.1 34.4 7.43 43.3 26.8 1

2 9.48 70.5 55.7 8.83 61.2 45.1 2 8.18 52.5 35.8 7.53 44.6 28.0 2

3 9.60 72.3 57.9 8.95 62.9 46.9 3 8.29 54.0 37.3 7.64 45.8 29.2 3

4 9.72 74.2 60.1 9.06 64.5 48.8 4 8.40 55.4 38.8 7.75 47.1 30.4 4

5 9.84 76.1 62.4 9.18 66.2 50.7 5 8.51 56.9 40.4 7.85 48.4 31.7 5

6 9.96 78.0 64.8 9.30 67.9 52.6 6 8.62 58.4 42.0 7.96 49.7 33.0 6

7 10.09 79.9 67.2 9.42 69.7 54.7 7 8.73 59.9 43.6 8.06 51.1 34.3 7

8 10.21 81.9 69.6 9.54 71.4 56.7 8 8.84 61.4 45.3 8.17 52.4 35.7 8

9 10.33 83.8 72.2 9.65 73.2 58.9 9 8.95 63.0 47.0 8.28 53.8 37.1 9

10 10.45 85.8 74.8 9.77 75.0 61.1 10 9.06 64.5 48.8 8.38 55.2 38.5 10

11 10.58 87.8 77.4 9.89 76.8 63.3 11 9.18 66.1 50.6 8.49 56.6 40.0 11

12 10.70 89.9 80.1 10.01 78.6 65.6 12 9.29 67.7 52.4 8.59 58.0 41.5 12

13 10.82 92.0 82.9 10.12 80.5 67.9 13 9.40 69.4 54.3 8.70 59.5 43.1 13

14 10.94 94.0 85.8 10.24 82.4 70.3 14 9.51 71.0 56.3 8.81 60.9 44.7 14

15 11.06 96.2 88.7 10.36 84.3 72.8 15 9.62 72.7 58.2 8.91 62.4 46.3 15

16 11.19 98.3 91.6 10.48 86.2 73.5 16 9.73 74.3 60.3 9.02 63.9 48.0 16

17 11.31 100.5 94.7 10.59 88.2 77.8 17 9.84 76.0 62.4 9.12 65.4 49.7 17

18 11.43 102.6 97.8 10.71 90.1 80.4 18 9.95 77.8 64.5 9.23 66.9 51.5 18

19 11.55 104.8 100.9 10.83 92.1 83.1 19 10.06 79.5 66.7 9.34 68.5 53.3 19

20 11.68 107.1 104.2 10.95 94.1 85.9 20 10.17 81.3 68.9 9.44 70.0 55.1 20

21 11.80 109.3 107.5 11.06 96.2 88.7 21 10.28 83.0 71.2 9.55 71.6 57.0 21

22 11.92 111.6 110.9 11.18 98.2 91.5 22 10.39 84.8 73.8 9.66 73.2 58.9 22

23 12.04 113.9 114.3 11.30 100.3 94.4 23 10.50 86.7 75.9 9.76 74.8 60.9 23

24 12.16 116.2 117.8 11.42 102.4 97.4 24 10.61 88.5 78.3 9.87 76.5 62.9 24

25 12.29 118.6 121.4 11.54 104.5 100.5 25 10.73 90.4 80.8 9.97 78.1 64.9 25

26 12.41 120.9 125.1 11.65 106.6 103.6 26 10.84 92.2 83.3 10.08 79.8 67.0 26

27 12.53 123.3 128.8 11.77 108.8 106.7 27 10.95 94.1 85.9 10.19 81.5 69.2 27

28 12.65 125.8 132.6 11.89 111.0 110.0 28 11.06 96.0 88.5 10.29 83.2 71.4 28

29 12.78 128.2 136.5 12.01 113.2 113.3 29 11.17 98.0 91.2 10.40 84.9 73.6 29

30 12.90 130.7 140.5 12.12 115.4 116.6 30 11.28 99.9 93.9 10.50 86.7 75.9 30

31 13.02 133.2 144.5 12.24 117.7 120.1 31 11.39 101.9 96.7 10.61 88.4 78.2 31

32 13.14 135.7 148.6 12.36 120.0 123.5 32 11.50 103.9 99.6 10.72 90.2 80.5 32

33 13.27 138.2 152.8 12.48 122.3 127.1 33 11.61 105.9 102.5 10.82 92.0 83.0 33

34 13.39 140.8 157.0 12.59 124.6 130.7 34 11.72 107.9 105.4 10.93 93.8 85.4 34

35 13.51 143.3 161.4 12.71 126.9 134.4 35 11.83 110.0 108.4 11.03 95.6 87.9 35

36 13.63 146.0 165.8 12.83 129.3 138.2 36 11.94 112.0 111.5 11.14 97.5 90.5 36

37 13.75 148.6 170.3 12.95 131.7 142.0 37 12.05 114.1 114.6 11.25 99.3 93.1 37

38 13.88 151.2 174.9 13.06 134.1 145.9 38 12.16 116.2 117.8 11.35 101.2 95.8 38

39 14.00 153.9 179.5 13.18 136.5 149.9 39 12.28 118.4 121.1 11.46 103.1 98.5 39

40 14.12 156.6 184.3 13.30 138.9 154.0 40 12.39 120.5 124.4 11.57 105.1 101.2 40

41 14.24 159.3 189.1 13.42 141.4 158.1 41 12.50 122.7 127.7 11.67 107.0 104.1 41

42 14.37 162.1 194.0 13.54 143.9 162.3 42 12.61 124.8 131.2 11.78 108.9 106.9 42

43 14.49 164.9 199.0 13.65 146.4 166.6 43 12.72 127.0 134.7 11.88 110.9 109.8 43

44 14.61 167.6 204.1 13.77 148.9 170.9 44 12.83 129.3 138.2 11.99 112.9 112.8 44

45 14.73 170.5 209.3 13.89 151.5 175.3 45 12.94 131.5 141.8 12.10 114.9 115.8 45

46 14.85 173.3 214.5 14.01 154.1 179.8 46 13.05 133.8 145.5 12.20 116.9 118.9 46

47 14.98 176.2 219.9 14.12 156.7 184.4 47 13.16 136.0 149.2 12.31 119.0 122.0 47

48 15.10 179.1 225.3 14.24 159.3 189.0 48 13.27 138.3 153.0 12.41 121.0 125.2 48

49 15.22 182.0 230.8 14.36 161.9 193.7 49 13.38 140.7 156.9 12.52 123.1 128.5 49

50 15.34 184.9 236.4 14.48 164.6 198.6 50 13.49 143.0 160.8 12.62 125.2 131.7 50

51 15.47 187.9 242.1 14.59 167.3 203.4 51 13.60 145.4 164.8 12.73 127.3 135.1 51

52 15.59 190.8 247.9 14.71 170.0 208.4 52 13.72 147.7 168.8 12.84 129.5 138.5 52

53 15.71 193.8 253.8 14.83 172.7 213.4 53 13.83 150.1 173.0 12.94 131.6 142.0 53

54 15.83 196.9 259.7 14.95 175.5 218.5 54 13.94 152.5 177.2 13.05 133.8 145.5 54

55 15.95 199.9 265.8 15.06 178.2 223.7 55 14.05 155.0 181.4 13.16 136.0 149.1 55
Bulletin 1724E-200

Page F-13

DOUGLAS FIR AND SOUTHERN YELLOW PINE

Ultimate Bending Stress – 8000 psi

75 ft. 75ft. Class H1 Class 1 Class 2 Class 3

Dist.

(ft.)

Dia.

(in.)

Area

(sq. in.)

Moment

(ft-k)

Dia.

(in.)

Area

(sq. in.)

Moment

(ft-k)

Dist.

(ft.)

Dia.

(in.)

Area

(sq. in.)

Moment

(ft-k)

Dia.

(in.)

Area

(sq. in.)

Moment

(ft-k)

Dist.

(ft.)

56 16.08 203.0 272.0 15.18 181.0 229.0 56 14.16 157.4 185.7 13.26 138.2 152.7 56

57 16.20 206.1 278.2 15.30 183.8 234.4 57 14.27 159.9 190.1 13.37 140.4 156.4 57

58 16.32 209.2 284.6 15.42 186.7 239.8 58 14.38 162.4 194.6 13.48 142.6 160.1 58

59 16.44 212.4 291.0 15.53 189.5 245.4 59 14.49 164.9 199.1 13.58 144.9 164.0 59

60 16.57 215.5 297.5 15.65 192.4 251.0 60 14.60 167.4 203.7 13.69 147.1 167.8 60

61 16.69 218.7 304.2 15.77 195.3 256.7 61 14.71 170.0 208.4 13.79 149.4 171.8 61

62 16.81 221.9 310.9 15.89 198.3 262.5 62 14.82 172.5 213.1 13.90 151.7 175.8 62

63 16.93 225.2 317.8 16.01 201.2 268.4 63 14.93 175.1 217.9 14.01 154.1 179.8 63

64 17.05 228.4 324.7 16.12 204.2 274.3 64 15.04 177.7 222.8 14.11 156.4 183.9 64

65 17.18 231.7 331.17 16.24 207.2 280.4 65 15.15 180.4 227.8 14.22 158.8 188.1 65

66 17.30 235.0 338.8 16.36 210.2 286.5 66 15.27 183.0 232.8 14.32 161.1 192.4 66

67 17.42 238.4 346.1 16.48 213.2 292.7 67 15.38 185.7 237.9 14.43 163.5 196.7 67

68 17.54 241.7 353.4 16.59 216.3 299.0 68 15.49 188.4 243.1 14.54 166.0 201.0 68

69 17.67 245.1 360.9 16.71 219.3 305.4 69 15.60 191.1 248.3 14.64 168.4 205.5 69

70 17.73 247.0 365.0 16.78 221.1 309.1 70 15.66 192.7 251.5 14.71 169.9 208.3 70

71 17.80 248.8 369.1 16.84 222.9 312.8 71 15.73 194.4 254.8 14.78 171.5 211.1 71

72 17.87 250.7 373.3 16.91 224.6 316.6 72 15.80 196.0 258.0 14.84 173.0 214.0 72

73 17.93 252.6 377.5 16.98 226.4 320.3 73 15.86 197.7 261.3 14.91 174.6 216.9 73

74 18.00 254.5 381.7 17.05 228.2 324.1 74 15.93 199.3 264.6 14.98 176.2 219.9 74

75 18.07 256.4 386.0 17.11 230.0 328.0 75 16.00 201.0 268.0 15.04 177.7 222.8 75
Bulletin 1724E-200

Page F-14

DOUGLAS FIR AND SOUTHERN YELLOW PINE

Ultimate Bending Stress – 8000 psi

80 ft. 80 ft. Class H1 Class 1 Class 2 Class 3

Dist.

(ft.)

Dia.

(in.)

Area

(sq. in.)

Moment

(ft-k)

Dia.

(in.)

Area

(sq. in.)

Moment

(ft-k)

Dist.

(ft.)

Dia.

(in.)

Area

(sq. in.)

Moment

(ft-k)

Dia.

(in.)

Area

(sq. in.)

Moment

(ft-k)

Dist.

(ft.)

0 9.231 66.92 51.5 8.594 58.01 41.5 0 7.958 49.74 33.0 7.321 42.10 25.7 0

1 9.351 66.68 53.5 8.711 59.59 43.3 1 8.067 51.12 34.4 7.424 43.29 26.8 1

2 9.472 70.46 55.6 8.827 61.19 45.0 2 8.177 52.52 35.8 7.528 44.50 27.9 2

3 9.592 72.27 57.8 8.943 62.81 46.8 3 8.287 53.93 37.2 7.631 45.73 29.1 3

4 9.713 74.09 60.0 9.059 64.45 48.7 4 8.396 55.37 38.7 7.734 46.98 30.3 4

5 9.833 75.94 62.2 9.175 66.12 50.6 5 8.506 56.83 40.3 7.837 48.24 31.5 5

6 9.954 77.81 64.5 9.291 67.80 52.5 6 8.616 58.30 41.9 7.941 49.52 32.8 6

7 10.07 79.71 66.9 9.407 69.51 54.5 7 8.726 59.80 43.5 8.044 50.82 34.1 7

8 10.19 81.63 69.3 9.523 71.23 56.5 8 8.835 61.31 45.1 8.147 52.13 35.4 8

9 10.31 83.57 71.8 9.64 72.98 58.6 9 8.945 62.84 46.8 8.25 53.46 36.8 9

10 10.44 85.53 74.4 9.756 74.75 60.8 10 9.055 64.39 48.6 8.353 54.81 38.2 10

11 10.56 87.51 77.0 9.872 76.54 63.0 11 9.164 65.96 50.46 8.457 56.17 39.6 11

12 10.68 89.52 79.6 9.988 78.35 65.2 12 9.274 67.55 52.2 8.56 57.55 41.1 12

13 10.8 91.55 82.4 10.1 80.18 67.5 13 9.384 69.16 54.1 8.663 58.94 42.6 13

14 10.92 93.61 85.2 10.22 82.04 69.9 14 9.493 70.78 56.0 8.766 60.36 44.1 14

15 11.04 95.68 88.0 10.34 83.91 72.3 15 9.603 72.43 58.0 8.87 61.79 45.7 15

16 11.16 97.78 90.9 10.45 85.81 74.7 16 9.713 74.09 60.0 8.973 63.23 47.3 16

17 11.28 99.91 93.9 10.57 87.73 77.3 17 9.822 75.78 62.0 9.076 64.70 48.9 17

18 11.4 102.05 96.9 10.68 89.67 79.8 18 9.932 77.48 64.1 9.179 66.18 50.6 18

19 11.52 104.22 100.0 10.8 91.63 82.5 19 10.04 79.20 66.3 9.283 67.68 52.4 19

20 11.64 106.41 103.2 10.92 93.61 85.2 20 10.15 80.94 68.5 9.386 69.19 54.1 20

21 11.76 108.62 106.5 11.03 95.61 87.9 21 10.26 82.70 70.7 9.489 70.72 55.9 21

22 11.88 110.86 109.8 11.15 97.63 90.7 22 10.37 84.47 73.0 9.592 72.27 57.8 22

23 12 113.12 113.1 11.27 99.68 93.6 23 10.48 86.27 75.3 9.696 73.83 59.7 23

24 12.12 115.40 116.6 11.38 101.74 96.5 24 10.59 88.09 77.7 9.799 75.41 61.6 24

25 12.24 117.71 120.1 11.5 103.83 99.5 25 10.7 89.92 80.2 9.902 77.01 63.5 25

26 12.36 120.03 123.7 11.61 105.94 102.5 26 10.81 91.77 82.7 10.01 78.62 65.6 26

27 12.48 122.38 127.3 11.73 108.07 105.6 27 93.64 85.2 10.11 80.25 67.6 27

28 12.6 124.76 131.0 11.85 110.22 108.8 28 95.54 87.8 10.21 81.90 69.7 28

29 12.72 127.15 134.8 11.96 112.39 112.0 29 97.44 90.5 10.31 83.57 71.8 29

30 12.84 129.57 138.7 12.08 114.58 115.3 30 99.37 93.1 10.42 85.25 74.0 30

31 12.96 132.01 142.6 12.19 116.80 118.7 31 101.32 95.9 10.52 86.94 76.2 31

32 13.09 134.48 146.6 12.31 119.03 122.1 32 103.29 98.7 10.62 88.66 78.5 32

33 13.21 136.96 150.7 12.43 121.29 125.6 33 105.27 101.6 10.73 90.39 80.8 33

34 13.33 139.47 154.9 12.54 123.57 129.2 34 107.28 104.5 10.83 92.14 83.2 34

35 13.45 142.01 159.1 12.66 125.87 132.8 35 109.30 107.4 10.93 93.90 85.6 35

36 13.57 144.56 163.4 12.78 128.19 136.5 36 111.34 110.5 11.04 95.68 88.0 36

37 13.69 147.14 167.8 12.89 130.53 140.2 37 113.40 113.6 11.14 97.48 90.5 37

38 13.81 149.74 172.3 13.01 132.89 144.0 38 115.48 116.7 11.24 99.30 93.0 38

39 13.93 152.36 176.8 13.12 135.27 147.9 39 117.58 119.9 11.35 101.13 95.6 39

40 14.05 155.01 181.5 13.24 137.68 151.9 40 119.70 123.1 11.45 102.98 98.3 40

41 14.17 157.68 186.2 13.36 140.10 155.9 41 121.84 126.5 11.55 104.84 100.9 41

42 14.29 160.37 191.0 13.47 142.55 160.0 42 123.99 129.8 11.66 106.72 103.7 42

43 14.41 163.09 195.8 13.59 145.02 164.2 43 126.17 133.3 11.76 108.62 106.5 43

44 14.53 165.82 200.8 13.7 147.51 168.5 44 128.36 136.7 11.86 110.54 109.3 44

45 14.65 168.58 205.8 13.82 150.02 172.8 45 130.57 140.3 11.97 112.47 112.2 45

46 14.77 171.37 210.9 13.94 152.55 177.2 46 132.80 143.9 12.07 114.42 115.1 46

47 14.89 174.17 216.1 14.05 155.10 181.6 47 135.05 147.6 12.17 116.39 118.1 47

48 15.01 177.00 221.4 14.17 157.68 186.2 48 137.32 151.3 12.28 118.37 121.1 48

49 15.13 179.85 226.8 14.29 160.27 190.8 49 139.61 155.1 12.38 120.37 124.2 49

50 15.25 182.73 232.3 14.4 162.89 195.5 50 141.91 159.0 12.48 122.38 127.3 50

51 15.37 185.62 237.8 14.52 165.53 200.3 51 144.24 162.9 12.59 124.42 130.5 51

52 15.49 188.54 243.4 14.63 168.19 205.1 52 146.58 166.9 12.69 126.47 133.7 52

53 15.61 191.49 249.2 14.75 170.87 210.0 53 148.95 170.9 12.79 128.53 137.0 53

54 15.73 194.45 255.0 14.87 173.57 215.0 54 151.33 175.0 12.9 130.61 140.4 54

55 15.86 197.44 260.9 14.98 176.29 220.1 55 153.73 179.2 13 132.71 143.8 55
Bulletin 1724E-200

Page F-15

DOUGLAS FIR AND SOUTHERN YELLOW PINE

Ultimate Bending Stress – 8000 psi

80 ft. 80 ft. Class H1 Class 1 Class 2 Class 3

Dist.

(ft.)

Dia.

(in.)

Area

(sq. in.)

Moment

(ft-k)

Dia.

(in.)

Area

(sq. in.)

Moment

(ft-k)

Dist.

(ft.)

Dia.

(in.)

Area

(sq. in.)

Moment

(ft-k)

Dia.

(in.)

Area

(sq. in.)

Moment

(ft-k)

Dist.

(ft.)

56 15.98 200.45 266.9 15.1 179.04 225.3 56 14.1 156.15 183.5 13.1 134.83 147.2 56

57 16.1 203.49 272.9 15.21 181.80 230.5 57 14.21 158.59 187.8 13.21 136.96 150.7 57

58 16.22 206.54 279.1 15.33 184.59 235.8 58 14.32 161.05 192.2 13.31 139.11 154.3 58

59 16.34 209.62 285.4 15.45 187.39 241.2 59 14.43 163.52 196.6 13.41 141.28 157.9 59

60 16.46 212.72 291.7 15.56 190.22 246.7 60 14.54 166.02 201.1 13.52 143.46 161.6 60

61 16.58 215.85 298.2 15.68 193.07 252.3 61 14.65 168.53 205.7 13.62 145.66 165.3 61

62 16.7 219.00 304.7 15.8 195.94 257.9 62 14.76 171.07 210.4 13.72 147.88 169.1 62

63 16.82 222.17 311.4 15.91 198.84 263.6 63 14.87 173.62 215.1 13.82 150.11 172.9 63

64 16.94 225.36 318.1 16.03 201.75 269.5 64 14.98 176.19 219.9 13.93 152.36 176.8 64

65 17.06 228.58 325.0 16.14 204.68 275.4 65 15.09 178.78 224.8 14.03 154.63 180.8 65

66 17.18 231.82 331.9 16.26 207.64 281.3 66 15.2 181.39 229.7 14.13 156.91 184.8 66

67 17.3 235.08 338.9 16.38 201.62 287.4 67 15.31 184.02 234.7 14.24 159.21 188.9 67

68 17.42 238.36 346.0 16.49 213.61 293.6 68 15.42 186.66 239.8 14.34 161.53 193.0 68

69 17.54 241.67 353.3 16.61 216.63 299.8 69 15.53 189.33 245.0 14.44 163.87 197.2 69

70 17.66 245.00 360.6 16.72 219.67 306.2 70 15.64 192.02 250.2 14.55 166.22 201.5 70

71 17.78 248.35 368.0 16.84 222.74 312.6 71 15.75 194.72 255.5 14.65 168.58 205.8 71

72 17.9 251.73 375.6 16.96 225.82 319.1 72 15.86 197.44 260.9 14.75 170.97 210.2 72

73 18.02 255.13 383.2 17.07 228.92 325.7 73 15.96 200.18 266.3 14.86 173.37 214.6 73

74 18.14 258.55 390.9 17.19 232.05 332.4 74 16.07 202.94 271.9 14.96 175.79 219.2 74

75 18.21 260.46 395.3 17.26 233.86 336.3 75 16.14 204.63 275.3 15.03 177.36 222.1 75

76 18.28 262.37 399.6 17.32 235.67 340.2 76 16.21 206.33 278.7 15.09 178.94 225.1 76

77 18.34 264.29 404.0 17.39 237.49 344.2 77 16.28 208.04 282.2 15.16 180.53 228.1 77

78 18.41 266.22 408.5 17.46 239.32 348.1 78 16.34 209.75 285.6 15.23 182.13 231.1 78

79 18.48 268.16 412.9 17.52 241.16 352.2 79 16.41 211.47 289.2 15.29 183.73 234.2 79

80 18.54 270.10 417.4 17.59 243.00 356.2 80 16.48 213.20 292.7 15.36 185.34 237.3 80
Bulletin 1724E-200

Page F-16

DOUGLAS FIR AND SOUTHERN YELLOW PINE

Ultimate Bending Stress – 8000 psi

85 ft. 85 ft. Class H1 Class 1 Class 2 Class 3

Dist.

(ft.)

Dia.

(in.)

Area

(sq. in.)

Moment

(ft-k)

Dia.

(in.)

Area

(sq. in.)

Moment

(ft-k)

Dist.

(ft.)

Dia.

(in.)

Area

(sq. in.)

Moment

(ft-k)

Dia.

(in.)

Area

(sq. in.)

Moment

(ft-k)

Dist.

(ft.)

0 9.23 66.92 51.5 8.59 58.01 41.5 0 7.96 49.74 33.0 7.32 42.10 25.7 0

1 9.35 68.66 53.5 8.71 59.55 43.2 1 8.06 51.08 34.3 7.42 43.26 26.8 1

2 9.47 70.42 55.6 8.82 61.10 44.9 2 8.17 52.44 35.7 7.52 44.45 27.9 2

3 9.59 72.20 57.7 8.93 62.67 46.7 3 8.28 53.82 37.1 7.62 45.64 29.0 3

4 9.71 74.00 59.9 9.05 64.26 48.4 4 8.38 55.22 38.6 7.72 46.86 30.2 4

5 9.83 75.82 62.1 9.16 65.88 50.3 5 8.49 56.63 40.1 7.82 48.09 31.4 5

6 9.94 77.67 64.4 9.27 67.51 52.2 6 8.60 58.07 41.6 7.93 49.33 32.6 6

7 10.06 79.53 66.7 9.38 69.16 54.1 7 8.71 59.52 43.2 8.03 50.60 33.8 7

8 10.18 81.42 69.1 9.50 70.84 56.1 8 8.81 60.99 44.8 8.13 51.87 35.1 8

9 10.30 83.34 71.5 9.61 72.53 58.1 9 8.92 62.47 46.4 8.23 53.17 36.5 9

10 10.42 85.27 74.0 9.72 74.24 60.2 10 9.03 63.98 48.1 8.33 54.48 37.8 10

11 10.54 87.23 76.6 9.84 75.98 62.3 11 9.13 65.50 49.8 8.43 55.80 39.2 11

12 10.66 89.20 79.2 9.95 77.73 64.4 12 9.24 67.04 51.6 8.53 57.14 40.6 12

13 10.78 91.21 81.9 10.06 79.50 66.7 13 9.35 68.60 53.4 8.63 58.50 42.1 13

14 10.90 93.23 84.6 10.17 81.29 68.9 14 9.45 70.18 55.3 8.73 59.88 43.6 14

15 11.01 95.27 87.4 10.29 83.11 71.2 15 9.56 71.77 57.2 8.83 61.27 45.1 15

16 11.13 97.34 90.3 10.40 84.94 73.6 16 9.67 73.38 59.1 8.93 62.67 46.7 16

17 11.25 99.43 93.2 10.51 86.79 76.0 17 9.77 75.01 61.1 9.03 64.09 48.2 17

18 11.37 101.54 96.2 10.63 88.67 78.5 18 9.88 76.66 63.1 9.13 65.53 49.9 18

19 11.49 103.68 99.3 10.74 90.56 81.0 19 9.99 78.33 65.2 9.24 66.98 51.5 19

20 11.61 105.83 102.4 10.85 92.47 83.6 20 10.09 80.01 67.3 9.34 68.45 53.3 20

21 11.73 108.01 105.6 10.96 94.40 86.3 21 10.20 81.71 69.5 9.44 69.94 55.0 21

22 11.85 110.21 108.8 11.08 96.36 88.9 22 10.31 83.43 71.7 9.54 71.44 56.8 22

23 11.96 112.44 112.1 11.19 98.33 91.7 23 10.41 85.17 73.9 9.64 72.96 58.6 23

24 12.08 114.68 115.5 11.30 100.32 94.5 24 10.52 86.93 76.2 9.74 74.49 60.5 24

25 12.20 116.95 118.9 11.41 102.34 97.3 25 10.63 88.70 78.6 9.84 76.04 62.3 25

26 12.32 119.24 122.4 11.53 104.37 100.3 26 10.73 90.49 80.9 9.94 77.60 64.3 26

27 12.44 121.55 126.0 11.64 106.42 103.2 27 10.84 92.30 83.4 10.04 79.18 66.3 27

28 12.56 123.88 129.7 11.75 108.49 106.3 28 10.95 94.13 85.9 10.14 80.78 68.3 28

29 12.68 126.24 133.4 11.87 110.59 109.4 29 11.05 95.97 88.4 10.24 82.39 70.3 29

30 12.80 128.62 137.2 11.98 112.70 112.5 30 11.16 97.84 91.0 10.34 84.02 72.4 30

31 12.92 131.02 141.0 12.09 114.83 115.7 31 11.27 99.72 93.6 10.44 85.67 74.6 31

32 13.03 133.44 144.9 12.20 116.99 119.0 32 11.37 101.61 96.3 10.54 87.33 76.7 32

33 13.15 135.88 148.9 12.32 119.16 122.3 33 11.48 103.53 99.1 10.65 89.00 79.0 33

34 13.27 138.35 153.0 12.43 121.35 125.7 34 11.59 105.47 101.8 10.75 90.69 81.2 34

35 13.39 140.84 157.2 12.54 123.56 129.2 35 11.69 107.42 104.7 10.85 92.40 83.5 35

36 13.51 143.35 161.4 12.66 125.80 132.7 36 11.80 109.39 107.6 10.95 94.13 85.9 36

37 13.63 145.89 165.7 12.77 128.05 136.3 37 11.91 111.38 110.5 11.05 95.87 88.3 37

38 13.75 148.44 170.1 12.88 130.32 139.9 38 12.02 113.38 113.5 11.15 97.62 90.7 38

39 13.87 151.02 174.5 12.99 132.62 143.6 39 12.12 115.41 116.6 11.25 99.40 93.2 39

40 13.99 153.62 179.0 13.11 134.93 147.4 40 12.23 117.45 119.7 11.35 101.18 95.7 40

41 14.10 156.24 183.6 13.22 137.26 151.2 41 12.34 119.51 122.9 11.45 102.99 98.3 41

42 14.22 158.89 188.3 13.33 139.61 155.1 42 12.44 121.59 126.1 11.55 104.81 100.9 42

43 14.34 161.55 193.1 13.45 141.99 159.1 43 12.55 123.68 129.3 11.65 106.64 103.6 43

44 14.46 164.24 197.9 13.56 144.38 163.1 44 12.66 125.80 132.7 11.75 108.49 106.3 44

45 14.58 166.95 202.8 13.67 146.79 167.2 45 12.76 127.93 136.1 11.85 110.36 109.0 45

46 14.70 169.69 207.8 13.78 149.23 171.4 46 12.87 130.08 139.5 11.95 112.25 111.8 46

47 14.82 172.44 212.9 13.90 151.68 175.7 47 12.98 132.25 143.0 12.06 114.15 114.7 47

48 14.94 175.22 218.1 14.01 154.15 180.0 48 13.08 134.43 146.6 12.16 116.06 117.6 48

49 15.06 178.02 223.3 14.12 156.64 184.3 49 13.19 136.63 150.2 12.26 117.99 120.5 49

50 15.17 180.04 228.7 14.24 159.16 188.8 50 13.30 138.86 153.9 12.36 119.94 123.5 50

51 15.29 183.69 234.1 14.35 161.69 193.3 51 13.40 141.09 157.6 12.46 121.90 126.6 51

52 15.41 186.55 239.6 14.46 164.24 197.9 52 13.51 143.35 161.4 12.56 123.88 129.7 52

53 15.53 189.44 245.2 14.57 166.81 202.6 53 13.62 145.63 165.2 12.66 125.88 132.8 53

54 15.65 192.35 250.9 14.69 169.41 207.3 54 13.72 147.92 169.2 12.76 127.89 136.0 54

55 15.77 195.28 256.6 14.80 172.02 212.1 55 13.83 150.23 173.1 12.86 129.92 139.2 55
Bulletin 1724E-200

Page F-17

DOUGLAS FIR AND SOUTHERN YELLOW PINE

Ultimate Bending Stress – 8000 psi

85 ft. 85 ft. Class H1 Class 1 Class 2 Class 3

Dist.

(ft.)

Dia.

(in.)

Area

(sq. in.)

Moment

(ft-k)

Dia.

(in.)

Area

(sq. in.)

Moment

(ft-k)

Dist.

(ft.)

Dia.

(in.)

Area

(sq. in.)

Moment

(ft-k)

Dia.

(in.)

Area

(sq. in.)

Moment

(ft-k)

Dist.

(ft.)

56 15.89 198.24 262.5 14.91 174.65 217.0 56 13.94 152.56 177.2 12.96 131.96 142.5 56

57 16.01 201.22 268.4 15.03 177.30 222.0 57 14.04 154.91 181.3 13.06 134.02 145.9 57

58 16.13 204.22 274.4 15.14 179.98 227.0 58 14.15 157.27 185.5 13.16 136.09 149.3 58

59 16.24 207.24 280.5 15.25 182.67 232.2 59 14.26 159.65 189.7 13.26 138.18 152.7 59

60 16.36 210.28 286.7 15.36 185.38 237.3 60 14.36 162.05 194.0 13.36 140.29 156.2 60

61 16.48 213.35 293.0 15.48 188.12 242.6 61 14.47 164.47 198.3 13.47 142.41 159.8 61

62 16.60 216.44 299.4 15.59 190.87 248.0 62 14.58 166.91 202.8 13.57 144.55 163.4 62

63 16.72 219.55 305.9 15.70 193.64 253.4 63 14.68 169.36 207.2 13.67 146.71 167.1 63

64 16.84 222.68 312.5 15.81 196.43 258.9 64 14.79 171.83 211.8 13.77 148.88 170.8 64

65 16.96 225.83 319.1 15.93 199.25 264.5 65 14.90 174.32 216.4 13.87 151.06 174.6 65

66 17.08 229.01 325.9 16.04 202.08 270.1 66 15.00 176.83 221.1 13.97 153.27 178.4 66

67 17.19 232.21 332.7 16.15 204.93 275.9 67 15.11 179.36 225.9 14.07 155.48 182.3 67

68 17.31 235.43 339.7 16.27 207.80 281.7 68 15.22 181.90 230.7 14.17 157.72 186.2 68

69 17.43 238.68 346.7 16.38 210.70 287.6 69 15.33 184.46 235.6 14.27 159.97 190.2 69

70 17.55 241.94 353.9 16.49 213.61 293.6 70 15.43 187.04 240.5 14.37 162.23 194.3 70

71 17.67 245.23 361.1 16.60 216.54 299.6 71 15.54 189.64 245.6 14.47 164.52 198.4 71

72 17.79 248.54 368.4 16.72 219.49 305.8 72 15.65 192.25 250.7 14.57 166.81 202.6 72

73 17.91 251.87 375.9 16.83 222.47 312.0 73 15.75 194.88 255.8 14.67 169.13 206.8 73

74 18.03 255.23 383.4 16.94 225.46 318.3 74 15.86 197.54 261.1 14.78 171.46 211.1 74

75 18.15 258.60 391.0 17.06 228.47 324.7 75 15.97 200.20 266.4 14.88 173.80 215.5 75

76 18.26 262.00 398.8 17.17 231.50 331.2 76 16.07 202.89 271.8 14.98 176.17 219.9 76

77 18.38 265.42 406.6 17.28 234.56 337.8 77 16.18 205.60 277.2 15.08 178.54 224.3 77

78 18.50 268.87 414.6 17.39 237.63 344.4 78 16.29 208.32 282.7 15.18 180.94 228.9 78

79 18.62 272.33 422.6 17.51 240.72 351.2 79 16.39 211.06 288.3 15.28 183.35 233.4 79

80 18.69 274.29 427.2 17.57 242.56 355.2 80 16.46 212.78 291.9 15.35 184.95 236.5 80

81 18.75 276.26 431.8 17.64 244.41 359.3 81 16.53 214.52 295.4 15.41 186.57 239.6 81

82 18.82 278.23 436.4 17.71 246.27 363.4 82 16.59 216.25 299.0 15.48 188.19 242.8 82

83 18.89 280.21 441.1 17.77 248.13 367.5 83 16.66 218.00 302.7 15.55 189.82 245.9 83

84 18.96 282.20 445.8 17.84 250.00 371.7 84 16.73 219.75 306.3 15.61 191.46 249.1 84

85 19.02 284.19 450.5 17.91 251.88 375.9 85 16.79 221.51 310.0 15.68 193.10 252.3 85
Bulletin 1724E-200

Page F-18

DOUGLAS FIR AND SOUTHERN YELLOW PINE

Ultimate Bending Stress – 8000 psi

90 ft. 90 ft. Class H1 Class 1 Class 2 Class 3

Dist.

(ft.)

Dia.

(in.)

Area

(sq. in.)

Moment

(ft-k)

Dia.

(in.)

Area

(sq. in.)

Moment

(ft-k)

Dist.

(ft.)

Dia.

(in.)

Area

(sq. in.)

Moment

(ft-k)

Dia.

(in.)

Area

(sq. in.)

Moment

(ft-k)

Dist.

(ft.)

0 9.23 66.92 51.5 8.59 58.01 41.5 0 7.96 49.74 33.0 7.32 42.10 25.7 0

1 9.35 68.61 53.4 8.70 59.51 43.2 1 8.06 51.07 34.3 7.42 43.24 26.7 1

2 9.46 70.32 55.4 8.81 61.02 44.8 2 8.17 52.42 35.7 7.52 44.39 27.8 2

3 9.58 72.05 57.5 8.92 62.55 46.5 3 8.28 53.79 37.1 7.62 45.56 28.9 3

4 9.69 73.80 59.6 9.03 64.10 48.3 4 8.38 55.18 38.5 7.72 46.75 30.1 4

5 9.81 75.57 61.8 9.14 65.67 50.0 5 8.49 56.59 40.0 7.81 47.95 31.2 5

6 9.92 77.36 64.0 9.25 67.25 51.9 6 8.59 58.01 41.5 7.91 49.17 32.4 6

7 10.04 79.17 66.2 9.36 68.86 53.7 7 8.70 59.45 43.1 8.01 50.40 33.6 7

8 10.16 81.00 68.6 9.47 70.49 55.6 8 8.81 60.91 44.7 8.11 51.65 34.9 8

9 10.27 82.86 70.9 9.58 72.13 57.6 9 8.91 62.39 46.3 8.21 52.91 36.2 9

10 10.39 84.73 73.3 9.69 73.80 59.6 10 9.02 63.88 48.1 8.31 54.19 37.5 10

11 10.50 86.63 75.8 9.80 75.48 61.7 11 9.12 65.39 49.7 8.40 55.48 38.9 11

12 10.62 88.55 78.3 9.91 77.18 63.8 12 9.23 66.92 51.5 8.50 56.79 40.2 12

13 10.73 90.48 80.9 10.02 78.90 65.9 13 9.34 68.47 53.3 8.60 58.11 41.7 13

14 10.85 92.44 83.6 10.13 80.64 68.1 14 9.44 70.04 55.1 8.70 59.45 43.1 14

15 10.96 94.42 86.3 10.24 82.40 70.3 15 9.55 71.62 57.0 8.80 60.81 44.6 15

16 11.08 96.42 89.0 10.35 84.14 72.6 16 9.66 73.22 58.9 8.90 62.18 46.1 16

17 11.20 98.45 91.8 10.46 85.97 75.0 17 9.76 74.84 60.9 9.00 63.56 47.7 17

18 11.31 100.49 94.7 10.57 87.79 77.3 18 9.87 76.47 62.9 9.09 64.96 49.2 18

19 11.43 102.55 97.7 10.68 89.62 79.8 19 9.97 78.13 64.9 9.19 66.38 50.9 19

20 11.54 104.64 100.6 10.79 91.48 82.3 20 10.08 79.80 67.0 9.29 67.81 52.5 20

21 11.66 106.74 103.7 10.90 93.35 84.8 21 10.19 81.49 69.2 9.39 69.25 54.2 21

22 11.77 108.87 106.8 11.01 95.24 87.4 22 10.29 83.19 71.5 9.49 70.71 55.9 22

23 11.89 111.02 110.0 11.12 97.15 90.0 23 10.40 84.92 73.6 9.59 72.19 57.7 23

24 12.00 113.19 113.2 11.23 99.08 92.7 24 10.50 86.66 75.9 9.69 73.68 59.5 24

25 12.12 115.38 116.5 11.34 101.03 95.5 25 10.61 88.42 78.2 9.78 75.19 61.3 25

26 12.24 117.59 119.9 11.45 103.00 98.3 26 10.72 90.20 80.5 9.88 76.71 63.2 26

27 12.35 119.82 123.3 11.56 104.98 101.1 27 10.82 91.99 83.0 9.98 78.25 65.1 27

28 12.47 122.07 126.8 11.67 106.99 104.1 28 10.93 93.80 85.4 10.08 79.80 67.0 28

29 12.58 124.35 130.4 11.78 109.01 107.0 29 11.03 95.63 87.9 10.18 81.37 69.0 29

30 12.70 126.64 134.0 11.89 111.05 110.0 30 11.14 97.48 90.5 10.28 82.95 71.0 30

31 12.81 128.96 137.7 12.00 113.12 113.1 31 11.25 99.35 93.1 10.38 84.55 73.1 31

32 12.93 131.30 141.5 12.11 115.20 116.3 32 11.35 101.23 95.8 10.47 86.16 75.2 32

33 13.05 133.65 145.3 12.22 117.30 119.5 33 11.46 103.13 98.5 10.57 87.79 77.3 33

34 13.16 136.03 149.2 12.33 119.42 122.7 34 11.57 105.05 101.2 10.67 89.43 79.5 34

35 13.28 138.43 153.2 12.44 121.56 126.0 35 11.67 106.99 104.1 10.77 91.09 81.8 35

36 13.39 140.85 157.2 12.55 123.71 129.4 36 11.78 108.94 106.9 10.87 92.77 84.0 36

37 13.51 143.29 161.3 12.66 125.89 132.8 37 11.88 110.91 109.8 10.97 94.46 86.3 37

38 13.62 145.76 165.5 12.77 128.08 136.3 38 11.99 112.90 112.8 11.07 96.16 88.7 38

39 13.74 148.24 169.7 12.88 130.30 139.9 39 12.10 114.91 115.8 11.16 97.88 91.1 39

40 13.85 150.75 174.0 12.99 132.53 143.5 40 12.20 116.93 118.9 11.26 99.62 93.5 40

41 13.97 153.27 178.4 13.10 134.78 147.1 41 12.31 118.98 122.0 11.36 101.37 96.0 41

42 14.09 155.82 182.9 13.21 137.05 150.9 42 12.41 121.04 125.2 11.46 103.13 98.5 42

43 14.20 158.39 187.4 13.32 139.34 154.7 43 12.52 123.12 128.5 11.56 104.91 101.0 43

44 14.32 160.97 192.0 13.43 141.65 158.5 44 12.63 125.21 131.7 11.66 106.71 103.7 44

45 14.43 163.58 196.7 13.54 143.98 162.5 45 12.73 127.32 135.1 11.75 108.52 106.3 45

46 14.55 166.21 210.5 13.65 146.33 166.4 46 12.84 129.45 138.5 11.85 110.35 109.0 46

47 14.66 168.87 206.3 13.76 148.69 170.5 47 12.94 131.60 142.0 11.95 112.19 111.7 47

48 14.78 171.54 211.3 13.87 151.08 174.6 48 13.05 133.77 145.5 12.05 114.05 114.5 48

49 14.89 174.23 216.3 13.98 153.48 178.8 49 13.16 135.95 149.1 12.15 115.92 117.4 49

50 15.01 176.95 221.3 14.09 155.90 183.0 50 13.26 138.16 152.7 12.25 117.81 120.2 50

51 15.13 179.68 226.5 14.20 158.34 187.4 51 13.37 140.37 156.4 12.35 119.71 123.2 51

52 15.24 182.44 231.7 14.31 160.80 191.7 52 13.48 142.61 160.1 12.44 121.63 126.1 52

53 15.36 185.22 237.0 14.42 163.28 196.2 53 13.58 144.87 164.0 12.54 123.56 129.2 53

54 15.47 188.01 242.4 14.53 165.78 200.7 54 13.69 147.14 167.8 12.64 125.51 132.2 54

55 15.59 190.83 247.9 14.64 168.30 205.3 55 13.79 149.43 171.8 12.74 127.48 135.3 55
Bulletin 1724E-200

Page F-19

DOUGLAS FIR AND SOUTHERN YELLOW PINE

Ultimate Bending Stress – 8000 psi

90 ft. 90 ft. Class H1 Class 1 Class 2 Class 3

Dist.

(ft.)

Dia.

(in.)

Area

(sq. in.)

Moment

(ft-k)

Dia.

(in.)

Area

(sq. in.)

Moment

(ft-k)

Dist.

(ft.)

Dia.

(in.)

Area

(sq. in.)

Moment

(ft-k)

Dia.

(in.)

Area

(sq. in.)

Moment

(ft-k)

Dist.

(ft.)

56 15.70 193.67 253.4 14.75 170.84 210.0 56 13.90 151.74 175.8 12.84 129.45 138.5 56

57 15.82 196.54 259.1 14.86 173.39 214.7 57 14.01 154.06 179.8 12.94 131.45 141.7 57

58 15.93 199.42 264.8 14.97 175.96 219.5 58 14.11 156.41 183.9 13.04 133.46 145.0 58

59 16.05 202.32 270.6 15.08 178.56 224.4 59 14.22 158.77 188.1 13.13 135.48 148.3 59

60 16.17 205.25 276.5 15.19 181.17 229.3 60 14.32 161.14 192.4 13.23 137.52 151.7 60

61 16.28 208.19 282.5 15.30 183.80 234.3 61 14.43 163.54 196.7 13.33 139.58 155.1 61

62 16.40 211.16 288.5 15.41 186.45 239.4 62 14.54 165.95 201.0 13.43 141.65 158.5 62

63 16.51 214.14 294.7 15.52 189.12 244.6 63 14.64 168.39 205.5 13.53 143.74 162.0 63

64 16.63 217.15 300.9 15.63 191.81 249.8 64 14.75 170.84 210.0 13.63 145.84 165.6 64

65 16.74 220.18 307.2 15.74 194.52 255.1 65 14.85 173.30 214.5 13.73 147.95 169.2 65

66 16.86 223.23 313.6 15.85 197.24 260.5 66 14.96 175.79 219.2 13.82 150.09 172.9 66

67 16.97 226.30 320.1 15.96 199.99 265.9 67 15.07 178.29 223.9 13.92 152.23 176.6 67

68 17.09 229.40 326.7 16.07 202.75 271.5 68 15.17 180.81 228.6 14.02 154.40 180.4 68

69 17.21 232.51 333.4 16.18 205.53 277.1 69 15.28 183.35 233.4 14.12 156.57 184.2 69

70 17.32 235.64 340.1 16.29 208.34 282.8 70 15.38 185.90 238.3 14.22 158.77 188.1 70

71 17.44 238.80 347.0 16.40 211.16 288.5 71 15.49 188.47 243.3 14.32 160.97 192.0 71

72 17.55 241.97 353.9 16.51 214.00 294.4 72 15.60 191.07 248.3 14.41 163.20 196.0 72

73 17.67 245.17 361.0 16.62 216.86 300.3 73 15.70 193.67 253.4 14.51 165.44 200.1 73

74 17.78 248.39 368.1 16.73 219.73 306.3 74 15.81 196.30 258.6 14.61 167.69 204.2 74

75 17.90 251.63 375.3 16.84 222.63 312.4 75 15.92 198.94 263.9 14.71 169.96 208.3 75

76 18.01 254.89 382.6 16.95 225.55 218.5 76 16.02 201.61 269.2 14.81 172.24 212.6 76

77 18.13 258.17 390.1 17.06 228.48 324.7 77 16.13 204.28 274.6 14.91 174.54 216.8 77

78 18.25 261.47 397.6 17.17 231.43 331.1 78 16.23 206.98 280.0 15.01 176.86 221.2 78

79 18.36 264.79 405.2 17.28 234.41 337.5 79 16.34 209.70 285.5 15.10 179.19 225.5 79

80 18.48 268.14 412.9 17.39 237.40 343.9 80 16.45 212.43 291.1 15.20 181.53 230.0 80

81 18.59 271.50 420.7 17.50 240.41 350.5 81 16.55 215.18 296.8 15.30 183.89 234.5 81

82 18.71 274.89 428.6 17.61 243.44 357.2 82 16.66 217.95 302.5 15.40 186.27 239.0 82

83 18.82 278.30 436.6 17.72 246.49 363.9 83 16.76 220.73 308.4 15.50 188.66 243.7 83

84 18.94 281.72 444.6 17.83 249.55 370.7 84 16.87 223.53 314.3 15.60 191.07 248.3 84

85 19.01 283.72 449.4 17.89 451.43 374.9 85 16.94 225.31 318.0 15.66 192.71 251.5 85

86 19.07 285.72 454.1 17.96 253.31 379.1 86 17.00 227.09 321.8 15.73 194.35 254.8 86

87 19.14 287.72 458.9 18.03 255.20 383.4 87 17.07 228.88 325.6 15.80 196.01 258.0 87

88 19.21 289.73 463.7 18.09 257.10 387.6 88 17.14 230.67 329.4 15.86 197.67 261.3 88

89 19.27 291.76 468.6 18.16 259.00 391.9 89 17.20 232.48 333.3 15.93 199.34 264.6 89

90 19.34 293.78 473.5 18.23 260.91 396.3 90 17.27 234.29 337.2 16.00 201.02 268.0 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:

72(1000)

( ( )( sin cos ) 2 2 2 2

b θ n θ

bh

F b b d M+ =

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:

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.

Neutral Axis

0 = 0° 0 = sin (3.5/d ) -1

n

Neutral Axis
Bulletin 1724E-200

Page F-21

 

 

POLE 3/4 in. * 7/8 in. * 1 in. *

DIAM 0 DEGREES THETA 0 DEGREES THETA 0 DEGREES THETA

9 0.914 0.78 1.055 0.897 1.195 1.017

9.1 0.934 0.93 1.078 1.078 1.222 1.222

9.2 0.955 0.96 1.102 1.102 1.249 1.249

9.3 0.976 0.98 1.126 1.126 1.276 1.276

9.4 0.997 1.00 1.151 1.151 1.304 1.304

9.5 1.018 1.02 1.175 1.175 1.332 1.332

9.6 1.040 1.04 1.200 1.200 1.360 1.360

9.7 1.062 1.06 1.225 1.225 1.388 1.388

9.8 1.084 1.08 1.251 1.251 1.417 1.417

9.9 1.106 1.11 1.276 1.276 1.446 1.446

10 1.128 1.13 1.302 1.302 1.476 1.476

10.1 1.151 1.15 1.328 1.328 1.505 1.505

10.2 1.174 1.17 1.355 1.355 1.535 1.535

10.3 1.197 1.20 1.381 1.381 1.566 1.566

10.4 1.221 1.22 1.408 1.408 1.596 1.596

10.5 1.244 1.24 1.436 1.436 1.627 1.627

10.6 1.268 1.27 1.463 1.463 1.658 1.658

10.7 1.292 1.29 1.491 1.491 1.690 1.690

10.8 1.316 1.32 1.519 1.519 1.721 1.721

10.9 1.341 1.34 1.547 1.547 1.753 1.753

11 1.365 1.37 1.576 1.576 1.786 1.786

11.1 1.390 1.39 1.604 1.604 1.818 1.818

11.2 1.416 1.42 1.633 1.633 1.851 1.851

11.3 1.441 1.44 1.663 1.663 1.884 1.884

11.4 1.467 1.47 1.692 1.692 1.918 1.918

11.5 1.492 1.49 1.722 1.722 1.952 1.952

11.6 1.518 1.52 1.752 1.752 1.986 1.986

11.7 1.545 1.54 1.782 1.782 2.020 2.020

11.8 1.571 1.57 1.813 1.813 2.055 2.055

11.9 1.598 1.60 1.844 1.844 2.090 2.090

12 1.625 1.63 1.875 1.875 2.125 2.125

12.1 1.652 1.65 1.906 1.906 2.161 2.161

12.2 1.680 1.68 1.938 1.938 2.196 2.196

12.3 1.707 1.71 1.970 1.970 2.233 2.233

12.4 1.735 1.74 2.002 2.002 2.269 2.269

12.5 1.763 1.76 2.035 2.035 2.306 2.306

12.6 1.792 1.79 2.067 2.067 2.343 2.343

12.7 1.820 1.82 2.100 2.100 2.380 2.380

12.8 1.849 1.85 2.133 2.133 2.418 2.418

12.9 1.878 1.88 2.167 2.167 2.456 2.456

13 1.907 1.91 2.201 2.201 2.494 2.494

13.1 1.937 1.94 2.235 2.235 2.532 2.532

13.2 1.966 1.97 2.269 2.269 2.571 2.571

13.3 1.996 2.00 2.303 2.303 2.610 2.610

13.4 2.026 2.03 2.338 2.338 2.650 2.650

13.5 2.057 2.06 2.373 2.373 2.689 2.689

13.6 2.087 2.09 2.408 2.408 2.729 2.729

13.7 2.118 2.12 2.444 2.444 2.770 2.770

13.8 2.149 2.15 2.480 2.480 2.810 2.810

13.9 2.180 2.18 2.516 2.516 2.851 2.851

14 2.212 2.21 2.552 2.552 2.892 2.892

14.1 2.244 2.24 2.589 2.589 2.934 2.934

14.2 2.275 2.28 2.626 2.626 2.976 2.976

14.3 2.308 2.31 2.663 2.663 3.018 3.018

14.4 2.340 2.34 2.700 2.700 3.060 3.060

14.5 2.373 2.37 2.738 2.738 3.103 3.103

14.6 2.405 2.41 2.776 2.776 3.146 3.146

14.7 2.439 2.44 2.814 2.814 3.189 3.189

14.8 2.472 2.47 2.852 2.852 3.232 3.232

14.9 2.505 2.51 2.891 2.891 3.276 3.276

15 2.539 2.54 2.930 2.930 3.320 3.320

*BOLT HOLE = BOLT DIAMETER + 1/16 in.

TABLE F-4

POLE MOMENT (ft-k) REDUCTION

DUE TO BOLT HOLES FOR 1000 psi FIBER STRESS
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 44.1 39.3 34.1 24.4

55 51.2 45.0 39.2 33.7

60 58.0 51.1 44.6 38.6

65 65.2 57.2 50.5 43.8

70 72.8 64.5 56.7 49.3

75 80.9 71.8 62.3 54.4

80 89.5 79.6 69.3 59.7

85 98.5 86.6 75.6 65.2

90 106.6 93.9 83.3 71.1

TALBE F-6

POLE WEIGHTS FOR DOUGLAS FIR (TREATED)

(50 pcf assumed) (lbs.)

Height Pole Classes

ft. H1 1 2 3

50 2200 1970 1700 1220

55 2560 2250 1960 1690

60 2900 2560 2230 1930

65 3260 2860 2530 2190

70 3640 3225 2840 2470

75 4050 3590 3120 2720

80 4480 3980 3470 2990

85 4930 4330 3780 3260

90 5330 4700 4170 3560

TABLE F-7

POLE WEIGHTS FOR SOUTHERN YELLOW PINE (TREATED)

(60 pcf assumed) (lbs.)

Height Pole Classes

ft. H1 1 2 3

50 2650 2360 2050 1470

55 3070 2700 2350 2020

60 3480 3070 2680 2320

65 3900 3430 3030 2630

70 4370 3870 3400 2960

75 4850 4300 3740 3260

80 5380 4780 4160 3580

85 5910 5200 4540 3910

90 6400 5630 5000 4270
Bulletin 1724E-200

Page F-23

Blank Page
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 49.9 30.8 18.9 11.7

(2) 3-5/8 x 9-3/8 99.8 61.6 37.8 23.3

3-5/8 x 5-5/8 17.7 10.9 11.2 6.9

(2) 3-5/8 x 5-5/8 35.3 21.8 22.5 13.9

4-1/8 x 5-1/8 16.7 10.3 13.3 16.5

(2) 4-1/8 x 5-1/8 33.3 20.6 26.7 16.5

4-5/8 x 5-5/8 22.7 14.0 18.6 11.5

(2) 5/8 x 5-5/8 45.4 28.0 37.1 22.9

5-3.8 x 7-5/8 49.2 30.4 34.5 21.2

5-5/8 x 7-3/8 48.2 29.7 36.6 22.5

Example: Determine the maximum vertical span for a TSS-1L (69 kV)

Given: Conductor: 266.8 26/7 ACSR

Ldg. Dist: Heavy

Cond. Wt. (wc): 1.0776 lbs./ft.

Insulator wt. (Wi): 51 lbs.

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.

LF W (s)

M LF W s V S c

a i

( ) ( )

( ) ( ) ( ) . . − = φ

( )

740 .

(1.5) (1.0776)(5.5)

(0.50)(14,000) 1.5(51) 5.5

= 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 7,400 X 0.5 or 3,700 psi is assumed)
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
Bulletin 1724E

-200

Page H-3

FIGURE H-1

CURVE FOR LOCATING PLANE OF CONTRAFLEXURE 

IN X-BRACED H-FRAME STRUCTURES
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.)

Tension Stress 

Area (in.2)

Min. Tensile 

Strength (lbs.)

1/2” 0.142 7,800

5/8” 0.226 12, 400

3/4” 0.334 18,350

7/8” 0.462 25,400

1” 0.606 33,500

TABLE H-3

STRENGTHS OF ASTM A325 

HEAT TREATED, HIGH STRENGTH BOLTS

Machine Bolt

Diameter

(in.)

Tensile

Stress Area

(sq. in.)

Minimum Tensile

Strength

(lbs.)

Minimum Yield

Strength

(lbs.)

1/2 0.142 17,500 13,050

5/8 0.226 27,100 20,800

3/4 0.334 40,100 30,700

7/8 0.462 55,450 42,500

1 0.606 72,700 55,570

TABLE H-4

STRENGTH OF GUY STRANDS

Strand Size Description Minimum Breaking 

Strength (lbs)

3/8 in. H.S. 10,800

7 No. 9 AWG A.C.S 12,600

3/8 in. E.H.S 14,400

7/16 in. H.S. 14,500

7 No. 8 AWG A.C.S 15,930

7 No. 7 AWG A.C.S 19,060

7/16 in. E.H.S 20,080

H.S.= high strength, E.H.S. = extra high strength, A.C.S.= aluminum clad steel
Bulletin 1724E-200

Page H-5

Blank Page
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

RIV Level in Microvolts at 1000 

kHZ*

34.5 100

46 200

69 200

115 200

138 200

161 500

230 500

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:

r

r n

kV

g D

LL

3 

= Eq. I-1

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:

rs

r n

kV r s

g D

LL

2 3 

(1+ 2 / ) =

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 = 2.54 1.18

2

927 ( ) . =

g = 

1.18

748.90

3 1.18

230 1.05

( )1

( )

n

g = 18.3 kV/cm.

The 556.5 kcmil conductor should not be used for 230 kV lines.

1272 kcmil Conductor (1 Conductor):

r = 2.54 1.755

2

1.382 ( ) =

g = g = 

1.755

748.90

3 1.755

230 1.05

( )1

( )

n

g = 13.12 kV/cm.
Bulletin 1724E-200

Page I-5

TABLE I-2

SURFACE GRADIENT FOR TYPICAL DESIGNS

16 kV/cm recommended to minimize

radio noise TP-3 TP-3 TS-1 TU-1AA TH-230

GMD GMD GMD GMD GMD

(feet) 2.53 2.53 3.00 3.59 24.57

(cm) 77.15 77.15 91.33 109.35 748.85

Gradient Gradient Gradient Gradient Gradient

Radius Radius (kV/cm) (kV/cm) (kV/cm) (kV/cm) (kV/cm)

Conductor Diameter (inches) (cm) 34.5 46 69 161 230

RAVEN 0.398 0.199 0.505 8.23 10.97 15.92 35.91 37.78

QUAIL 0.447 0.224 0.568 7.50 10.00 14.50 32.68 34.19

PIGEON 0.502 0.251 0.638 6.84 9.12 13.22 29.76 30.94

PENGUIN 0.563 0.282 0.715 6.25 8.33 12.06 27.14 28.04

WAXWING 0.609 0.305 0.773 5.88 7.83 11.33 25.49 26.22

PARTRIDGE 0.642 0.321 0.815 5.64 7.52 10.87 24.44 25.06

MERLIN 0.684 0.342 0.869 5.37 7.16 10.34 23.24 23.75

LINNET 0.721 0.361 0.916 5.15 6.87 9.93 22.29 22.70

ORIOLE 0.741 0.371 0.941 5.04 6.72 9.72 21.81 22.18

CHICKADEE 0.743 0.372 0.944 5.03 6.71 9.69 21.76 22.13

IBIS 0.783 0.392 0.994 4.83 6.44 9.31 20.88 21.17

LARK 0.806 0.403 1.024 4.73 6.30 9.10 20.41 20.65

PELICAN 0.814 0.407 1.034 4.69 6.25 9.03 20.25 20.48

FLICKER 0.846 0.423 1.074 4.55 6.07 8.76 19.65 19.82

HAWK 0.858 0.429 1.090 4.51 6.01 8.67 19.44 19.59

HEN 0.883 0.442 1.121 4.41 5.88 8.48 19.00 19.12

OSPREY 0.879 0.440 1.116 4.42 5.90 8.51 19.07 19.19

PARAKEET 0.914 0.457 1.161 4.29 5.72 8.25 18.50 18.57

DOVE 0.927 0.464 1.177 4.25 5.66 8.17 18.30 18.35

EAGLE 0.953 0.477 1.210 4.16 5.55 7.99 17.91 17.92

KINGBIRD 0.94 0.470 1.194 4.20 5.60 8.08 18.10 18.13

ROOK 0.977 0.489 1.241 4.08 5.44 7.84 17.56 17.55

GROSBEAK 0.99 0.495 1.257 4.04 5.39 7.76 17.38 17.36

EGRET 1.019 0.510 1.294 3.95 5.27 7.59 17.00 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 TP-3 TP-3 TS-1 TU-1AA TH-230

GMD GMD GMD GMD GMD

(feet) 2.53 2.53 3.00 3.59 24.57

(cm) 77.15 77.15 91.33 109.35 748.85

Gradient Gradient Gradient Gradient Gradient

Radius Radius (kV/cm) (kV/cm) (kV/cm) (kV/cm) (kV/cm)

Conductor Diameter (inches) (cm) 34.5 46 69 161 230

CUCKOO 1.092 0.546 1.387 3.75 5.00 7.20 16.11 15.98

DRAKE 1.108 0.554 1.407 3.71 4.95 7.12 15.93 15.79

MALLARD 1.14 0.570 1.448 3.63 4.84 6.97 15.59 15.41

TERN 1.063 0.532 1.350 3.83 5.11 7.35 16.45 16.35

CONDOR 1.093 0.547 1.388 3.75 5.00 7.20 16.10 15.97

RAIL 1.165 0.583 1.480 3.57 4.77 6.86 15.33 15.13

CARDINAL 1.196 0.598 1.519 3.51 4.67 6.72 15.03 14.80

BUNTING 1.302 0.651 1.654 3.29 4.39 6.31 14.08 13.79

GRACKLE 1.338 0.669 1.699 3.23 4.30 6.18 13.79 13.48

BITTERN 1.345 0.673 1.708 3.21 4.28 6.15 13.74 13.42

PHEASANT 1.382 0.691 1.755 3.15 4.20 6.03 13.46 13.12

LAPWING 1.502 0.751 1.908 2.96 3.95 5.67 12.64 12.24

FALCON 1.545 0.773 1.962 2.90 3.87 5.55 12.37 11.95

CHUKAR 1.602 0.801 2.035 2.83 3.77 5.40 12.04 11.60

BLUEBIRD 1.762 0.881 2.238 2.64 3.52 5.04 11.21 10.72
Bulletin 1724E-200

Page I-7

Blank Page
Bulletin 1724E-200

Page J-1

APPENDIX J

INSULATOR SWING TABLES
Bulletin 1724E-200

Page J-2

TABLE J

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)

Structure and 

Voltage

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)

34.5 kV

TS-1, TS-1X 3 40.2 69.8 82.0

TS-1L, TS-1LX 3 40.8 69.8 82.0

TS-2, TS-2X 3 40.2 70.5 82.3

TSD-1, TSD- 1X, 3 25.3 52.3 68.0

TSD-2, TSD-2X 3 25.3 52.9 68.0

TS-9 3 67.9 92.9 108.6

TSS-1, TSS-2 3 40.8 72.5 89.5

TSS-1L 3 40.8 70.1 89.1

TSS-9 3 77.0 101.9 115.1

TSZ-1, TSZ-2 3 52.6 77.1 90.5

TH-1, TH-1G 3 41.3 72.9 89.8

TH-9, TH-9G 3 77.0 101.9 115.1

46 kV

TS-1, TS-1X 3 40.2 64.5 82.0

TS-1L, TS-1LX 3 40.8 64.5 82.0

TS-2, TS-2X 3 40.2 65.0 82.3

TSD-1, TSD-1X 3 25.3 47.7 68.0

TSD-2, TSD-2X 3 25.3 48.0 68.0

TS-9 3 67.9 86.9 108.6

TSS-1, TSS-2 3 40.8 64.9 89.5

TSS-1L 3 40.8 64.9 89.5

TSS-9 3 77.0 97.2 115.1

TSZ-1, TSZ-2 3 52.6 72.3 90.5

TH-1, TH-1G 3 41.3 67.8 89.8

TH-9, TH-9G 3 77.0 97.2 115.1

69 kV

TS-1, TS-1X 4 20.0 38.5 74.0

TS-1L, TS-1LX 4 33.5 53.5 74.0

TS-2, TS-2X 4 20.0 38.5 74.2

TSD-1, TSD-1X 4 17.8 38.5 62.8

TSD-2, TSD-2X 4 17.8 38.5 62.8

TS-9 4 45.8 71.7 93.2

TSS-1, TSS-2 4 25.9 45.8 85.4

TSS-1L 4 35.1 60.9 85.4

TSS-9 4 45.8 79.2 106.6
Bulletin 1724E-200

Page J-3

TABLE J (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)

Structure and 

Voltage

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)

69 kV (continued)

TSZ-1, TSZ-2 4 41.7 61.2 81.4

TH-1, TH-1G 4 35.6 61.2 85.6

TH-1B, 

TH-1BG 4 66.5 86.2 106.6

TH-1A, 4 35.6 61.2 85.6

TH-1AA, 

TH-1AAX 4 27.2 56.1 81.3

TS-115 4 33.7 60.0. 84.6

115 Kv

TS-115 7 26.9 54.2 80.2

TH-1A 7 28.3 58.7 80.8

TH-1AA,TH1AAX 7 22.1 55.5 78.1

TH-10 SERIES 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 12 16.5 47.8 74.8

TH-230 13 15.2 43.9 76.0

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.

in

C = Circumference of pole. Depending on the location, the 

circumference may be indicated as CA, CB, CC

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 than 1.25

E = Modulus of elasticity of wood psi

EI&W = Extreme Ice and Concurrent Wind

F = Wind pressure on a cylindrical surface psf

Fb = Designated ultimate bending stress for either the pole or the 

crossarm

psi

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 psf

G, GN = Calculated force in the guy, considering guy lead lbs

GU = Rated breaking strength of guy lbs

H = Horizontal separation between the phase conductors at the 

structure.

ft

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

ft

HSN = For an H-frame structure, HSA, HSB, etc., are the horizontal ft
Bulletin 1724E-200

Page K-2

APPENDIX K

SYMBOLS AND ABBREVIATIONS

spans limited by pole strength at locations on the pole

HSR = Horizontal span limited by bearing ft

HSx = Horizontal span as limited by crossbrace strength

Of an H-frame structure

ft

I = Moment of inertia of a structural member in4

L = Span length or the horizontal distance from one structure to 

an adjacent structure. L1, L2, L3, etc., are designations for 

difference spans

ft

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 lbs

PC = 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

Pcr = Critical buckling load for a member in compression lbs

R = Rise of a davit arm ft 

R = Total transverse load due to wind on the conductors and 

OHGW and wire tension load for conductors and OHGW

lbs

Rg = Total transverse load due to wind on the OHGW (Pg) and 

wire tension load for OHGW (Tg) lbs

RS = Ruling Span ft
Bulletin 1724E-200

Page K-3 

APPENDIX K

SYMBOLS AND ABBREVIATIONS

S = Section modulus of a structural member equal I/c in3

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

Su = Sag of an upper conductor ft

Siu = Sag of an iced upper conductor ft

SP = Diagonal distance between phase conductors at structure ft

T = Resultant tension at support lbs

Tc = Average conductor tension lbs

Tg = Average OHGW tension lbs

Th = Horizontal component of tension lbs

Tavg = Average conductor tension in a span, (Tavg= ) 2

ThT + 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 

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

ft

W = Weight lbs

W = Right-of-way width ft

Wc = Weight of conductors (plus ice, if any) lbs

Wg = Weight of OHGW (plus ice, if any) lbs

Wp = Weight of pole lbs

Wi = Weight of insulators lbs

V = Wind velocity miles/hr
Bulletin 1724E-200

Page K-4

APPENDIX K

SYMBOLS AND ABBREVIATIONS

V = Vertical separation between phase conductors at a structure ft

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
Bulletin 1724E-200

Page K-5

APPENDIX K

SYMBOLS AND ABBREVIATIONS

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

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
Bulletin 1724E-200

Page K-6

APPENDIX K

SYMBOLS AND ABBREVIATIONS

r = Radius of conductor in.

rc = Resultant load per unit length on conductor including ice 

and wind and K factor

lbs/ft

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, 

zn

= Length. May be indicated as x0, x1, z0, x1, etc. ft.
Bulletin 1724E-200

Page K-7 

Blank Page 
Bulletin 1724E-200

Page L-1

APPENDIX L

SELECTED SI-METRIC CONVERSIONS

AREA

To Convert From To Multiply by

circular mil (cmil) square meter (m2) 5.067075 E – 10

square centimeter (cm2) square meter (m2) *1.000 E – 04

square foot (ft2) square meter (m2) *9.290304 E – 02

square inch (in2) square meter (m2) *6.451600 E – 04

square kilometer (km2) square meter (m2) *1.000 E + 06

square mile (mi2) square meter (m2) 2.589988 E + 06

FORCE

To Convert From To Multiply by

kilogram force (kgf) newton (N) *9.806650

Kip newton (N) 4.448222 E + 03

pound force (lbf) newton (N) 4.448222

FORCE PER LENGTH

To Convert From To Multiply by

kilogram force per

 meter (kgf/m) newton per meter (N/m) *9.806650

pound per foot (lb/ft) newton per meter (N/m) 1.459390 E + 01

DENSITY

To Convert From To Multiply by

pound per cubic inch

 (lb/in3)

kilogram per cubic

 meter (kg/m3) 2.767990 E + 04

pound per cubic foot

 (lb/ft3)

kilogram per cubic

 meter (kg/m3) 1.601846 E + 01

LENGTH

To Convert From To Multiply by

foot (ft) meter (m) 3.048 E – 01

inch (in) meter (m) *2.540 E – 02

kilometer (km) meter (m) *1.000 E + 03

mile (mi) meter (m) *1.609344 E + 03

*Exact Conversion.
Bulletin 1724E-200

Page L-2

SELECTED SI-METRIC CONVERSIONS (Continued)

LINEAR DENSITY

To Convert From To Multiply by

pound per foot (lb/ft) kilogram per meter (kg/m) 1.488164

pound per inch (lb/in) kilogram per meter (kg/m) 1.785797 E + 01

LOAD CONCENTRATION

To Convert From To Multiply by

pound per square 

 inch (lb/in2)

kilogram per square 

 meter (kg/m2) 7.03069 E + 02

pound per square 

 foot (lb/ft2)

kilogram per square 

 meter (kg/m2) 4.882428

ton per square 

 foot (ton/ft2)

kilogram per square 

 meter (kg/m2) 9.071847 E + 02

MASS

To Convert From To Multiply by

pound (avoirdupois) (lb) kilogram (kg) 4.535924 E - 01

PRESSURE

To Convert From To Multiply by

kip per square inch

 (kip/in2) pascal (Pa) 6.894757 E + 06

kip per square foot 

 (kip/ft2) pascal (Pa) 4.788026 E + 04

newton per square 

 meter (N/m2) pascal (Pa) *1.000

pound per square 

 foot (lb/ft2) pascal (Pa) 4.788026 E + 04

pound per square 

 inch (lb/in2) pascal (Pa) 6.894757 E + 03

BENDING MOMENT

To Convert From To Multiply by

kilogram force 

meter (kgf-m) newton meter (N-m) *9.806650

kip-foot (kip-ft) newton meter (N-m) 1.355818

pound-foot (lb-ft) newton meter (N-m) 1.355818

*Exact Conversion.
Bulletin 1724E-200

Page L-3

SELECTED SI-METRIC CONVERSIONS (Continued)

VELOCITY

To Convert From To Multiply by

foot per second (ft/s) meter per second (m/s) *3.048 E - 01

kilometer per hour (km/h) meter per second (m/s) 2.777778 E - 01

mile per hour (mi/h or mph) meter per second (m/s) 4.470400 E - 01

meter per hour (m/h) meter per second (m/s) 2.777778 E - 04

VOLUME

To Convert From To Multiply by

cubic foot (ft3) cubic meter (m3) 2.831685 E - 02.

cubic inch (in3) cubic meter (m3) 1.638706 E - 05

cubic kilometer (km3) cubic meter (m3) *1.000 E + 09

cubic millimeter (mm3) cubic meter (m3) *1.000 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

APPENDIX M Page M-1

INDEX

Subject Page Numbers

A

AAC Aluminum conductor (1350 H-19) 4-3, 9-2

AAAC (6201 conductor) 4-3, 9-2, 9-6, 9-9, 9-11, 9-16

AACSR conductor 9-4

ACAR conductor 9-3

ACSR conductor 4-2, 4-3, 9-1 to 9-6, 9-9, 9-11

ACSR/AW conductor 9-2

ACSR/SD conductor 9-3, 9-4

ACSS 9-4

ACSS 9-4, 9-5

Aeolian vibration 9-3, 9-15, 9-16, 15-7, 15-8

Ampacity, conductor 9-7, D-2, D-3

Anchors

logs

plate

power screw

14-1 to 14-3, 14-11, 14-16

14-11

14-11

14-11

Armor rods 9-16, 9-17, 15-1 to 15-9, 

Authorizations 3-6

AWAC conductor 9-3

Axial loading, for guyed structures 14-5 to 14-10

B

Backfill 12-7, 12-9

Backswing 7-6

Bearing capacity 12-7, 12-8

Bisector guys 14-1, 14-5, 14-8, 14-9

Bolt hole, moment reduction due to F-20, F-21

Buckling 14-5 to 14-9, 14-12, 14-17

Buckling, calculation of buckling loads 14-5 to 14-7, 14-12

Building, clearance over 4-4, 4-6 to 4-8

Bundled conductors 15-9

C

Calculation of a ruling span 9-12 to 9-14

Checklist, review of plan and profile 10-17

Clamp top clamps 15-2

Clearance

at crossings 4-10 to 4-14

between transmission and underbuild

distribution conductors

16-1 to 16-4

examples of, calculations 4-10 to 4-13, 5-10, 6-5, 6-6, 7-6
Bulletin 1724E-200

Page M-2 

INDEX

Subject Page Numbers

for lines along roads in rural districts 4-3

for lines over buildings 4-5, 4-9

for lines over railroads 4-5 to 4-8

for lines over swimming pools 4-6, 4-9

for sag template 4-4

horizontal Chapter 5

insulator swing Chapter 7, 13-1

minimum horizontal clearance of conductors to 

objects

5-1 to 5-8

over water 4-3, 4-4, 4-7, 4-8

side hill 10-13

to grain bins 4-9, 5-3, 5-7 to 5-9

to guys 14-4, 7-1, 7-5, 7-6

to objects under line Chapter 4

to rail cars 4-5 to 4-8

to swimming pools 4-6 to 4-9

to tall vehicles 4-3, 4-4

under differential ice loading 6-6, 6-7

vertical, between conductors of different lines at 

noncrossing situations

4-11, 4-12

vertical, between conductors where one line crosses 

over another

4-10 to 4-14

vertical, conductors to ground 4-1, 4-2, 4-7, 4-8

vertical, conductors to ground (underbuild 

distribution), Chapter 16

vertical clearance to underbuild Chapter 16

Climbing space 16-5

Communication underbuild 16-1, 16-3

Conductor

AAC (1350 H-19 aluminum) 9-2

AAAC-6201 9-2

AACSR 9-4

ACAR 9-3

ACSR

ACSR/AW

ACSR/SD (self-damping)

ACSR/TW

ACSS

ampacity tables

AWAC

bundled

corrosion considerations

design for vibration

design tensions

4-2, 4-3, 9-1 to 9-11 

9-2 

9-3, 9-4 

9-4 

9-4, 9-5 

D-2, D-3

9-3 

15-8 

9-6 

9-15, 9-16 

9-9 to 9-11 
Bulletin 1724E-200

Page M-3 

INDEX

Subject Page Numbers

determination of conductor sags and tensions 9-14 to 9-18

economic considerations 9-6, 9-7

extreme ice tension 9-10 to 9-11

extreme wind tension 9-10 to 9-11

final unloaded tension 9-9, 9-11

initial unloaded tension 9-9, 9-11

mechanical loading tables B-2 to B-9

minimum size 9-6

motion hardware 15-7 to 15-10

ruling span of 9-12 to 9-14

related hardware Chapter 15

sagging of 9-21

selection of size 9-6, 9-7

selection of type 9-6

standard loaded tension 9-9 to 9-11

stringing of 9-20

swing angle 5-1, 5-5, Chapter 7

temperature 4-2, 4-3, 4-10, 5-1, 16-2

thermal consideration 9-7

twisted pair (T-2) 9-4

vibration 9-15, 9-16

voltage drop considerations of 9-7

Contamination, insulation 8-8 to 8-11

Contraflexure for H-frames 13-28, 13-29, H-3

Corrosion of hardware 15-14

Corrosion considerations, conductor 9-6

Crossarm braces 13-31 to 13-35

Crossarm data

moment capacities

crossarm loading chart

Crossarm fittings

Crossarm, wood, designated stresses

Crossbraces

Cushioned suspension unit

G-2 

G-3 

15-10 to 15-14 

13-4 

13-27 to 13-32 

9-16, 9-17, 15-2, 15-7, 15-8 

D

Dampers 9-16, 15-8

Deadend clamps 15-3 to 15-4

Deflection, structure 5-1, 5-5, 5-8 to 5-14

13-6 to 13-13

Design data summary 2-1

Design data summary book, suggested outline A-10, A-11

Design data summary form A-3, A-4
Bulletin 1724E-200

Page M-4 

INDEX

Subject Page Numbers

Design data summary form, instructions for filling out A-5 to A-11

Determining conductor sags and tensions 9-14 to 9-19

E

Easements 3-1 to 3-10

Embedment depths 12-1 to 12-6

Embedment depths of wood poles 12-1 to 12-6

Embedment depths of steel/concrete poles 12-7, 12-8

Environmental criteria 3-1 to 3-8

Establishing a ruling span 9-12 to 9-14

Excessive insulator swing 7-11, 10-12

Extreme ice 11-2

Extreme ice and wind 11-2, 11-9 to 11-14

Extreme ice, conductor tension 9-10, 9-11

Extreme winds, 11-2 to 11-9, 11-15

velocity pressure exposure coefficients 11-3

gust response factors for 11-4

F

Fasteners 15-10, 15-11

Fault clearing 4-1

Field survey, soil 12-2

Final unloaded conductor tension 9-9, 9-11

Fittings 15-5, 15-11 to 15-13

Footing resistance 8-7, 8-8

Foundation stability Chapter 12

G

Gain plate 15-12, 15-13

Galloping 6-7 to 6-10, 15-9

Grid gains 15-11

Gust response factor

wire 11-3, 11-4

structure 11-5

Guy attachments 15-13

Guy strands, strength H-4

Guyed structures 10-15, Chapter 14, 16-6, 16-7

Guys

bisector 14-1, 14-5, 14-8

clearance to 14-3, 7-5

for steel and concrete poles 14-6, 14-10, 14-11
Bulletin 1724E-200

Page M-5 

INDEX

Subject Page Numbers

for wood poles 14-7 to 14-10

force in 14-2

head and back 14-1

hold-down (uplift) 10-12

in-line 14-8, 14-9, 10-15

rated breaking strength of H-4

strength factors 14-2, 11-19, 11-20

H

Hardware

armor rods 9-16, 9-17, 15-1 to 15-9

Bolts, stepbolts 15-10, 15-11, 15-12, 15-14, H-4

clamp top clamps 15-2

conductor motion 9-15, 9-16, 15-7 to 15-10

conductor-related hardware 15-1 to 15-10

corrosion of 15-14

crossarm fittings 15-11, 15-12

cushioned suspension units 9-17, 15-2, 15-7, 15-8

dampers 9-16, 15-8

deadend clamps 15-3, 15-4

fasteners 15-10, 15-11

fittings 15-5, 15-11 to 15-13

gain plate 15-12, 15-13

grid gains 15-11

guy attachment 15-13

reinforcing plate 15-12

spacer fitting 15-12

splices 15-4

strain yokes 15-5

structure-related 15-10 to 15-14

suspension clamps 15-1, 15-2, 15-4

swing angle brackets 15-12

tied supports 15-3

Head and back guys 14-1, 14-5

High wind (insulator swing) clearance 7-2 to 7-4

Hold down guys (uplift) 10-12

Horizontal clearance recommendations Chapter 5

Horizontal separation 6-1 to 6-4

Horizontal separation recommendations 6-1, 6-2

Horizontal span, definition 7-7, 7-9

Horizontal span, max. as limited by structure strength 

single pole structures 13-5 to 13-27

H-frames 13-27 to 13-44
Bulletin 1724E-200

Page M-6 

INDEX

Subject Page Numbers

I

Ice loading 11-2 

Ice loading, differential 6-6, 6-7, 11-14

Initial unloaded conductor tension 9-9, 9-11

In-line guys 14-8, 14-9, 10-15

Insulation Chapter 8

footing resistance 8-7, 8-8

high altitude considerations 8-3 to 8-5

recommended agency levels 8-2, 8-3

tables for C-2, C-3, C-4

Insulation contamination 8-8 to 8-11

Insulator greasing 8-11

Insulator washing 8-11

Insulator lengths C-4

Insulator load limits

ceramic and non-ceramic 8-12 to 8-15

post, pin, suspension 8-12 to 8-15

Insulator orientation 8-9, 8-10

Insulator swing, Chap. 7, 10-11, 10-12, 15-9, 15-10

charts 7-8, 7-10, 7-11, 7-13 to 7-16

effect on design 7-9

excessive 7-11

formulae for 7-10, 7-11

Insulator string flashover data 8-2, 8-3, 8-5, C-2, C-3

Insulator swing clearance 7-1 to 7-7

Insulator swing values 7-7, 7-8, J-2 to J-3

Insulator weights, suspension C-4

Insulators,

electrical characteristics of 8-3, 8-4

horizontal post (porcelain and non-ceramic) 8-1, 8-3, 8-13

horizontal post (special considerations) 8-14

lengths, suspension C-4

load limits of 8-13

mechanical considerations of post and pin 8-13 to 8-15

mechanical considerations of suspension 8-12 to 8-15

porcelain vertical post and pin mounted on 

crossarms

8-14

post 8-1 to 8-3, 8-13, 8-14

suspension 8-1 to 8-3, 8-9, 8-11 to15

types 8-1

weights, suspension C-4
Bulletin 1724E-200

Page M-7 

INDEX

Subject Page Numbers

L

Licenses 3-6 to 3-10

Lightning 8-5 to 8-8

Lightning flashover mechanism 8-5, 8-6

Line routing considerations 3-1 to 3-3

Line survey 3-4, 3-5

Load factors Chapters 11 and 13, 14-2

Loading, axial (for guyed structures) 14-5 to 14-11

Loads

extreme wind 11-2 to 11-9, 11-15

combined ice and wind (NESC) 11-1, 11-2

combined ice with concurrent wind (50 yr) 11-2, 11-9 to 11-14

ice 11-2 

NESC district loads 11-1, 11-2

longitudinal loads 11-14

Longitudinal loads 11-14

Longitudinal structure strength 10-15, 11-14, 11-15

M

Meteorological data 

wind velocities and pressures E-2

annual extreme winds 11-2 to 11-9

annual extreme ice with concurrent wind maps 11-9 to 11-14

thunderstorm days per year E-4

Moderate wind (insulator swing) clearance 7-1 to 7-4

Moment capacities for wood poles F-3, F-5 to F-19

Moment reduction due to bolt hole F-20, F-21

N

NESC loading districts 11-1, 11-2

No wind (insulator swing) clearance 7-1, 7-4, 7-5

O

Offset clipping 9-21, 9-22

Overhead ground wire 8-6, 8-7, 9-8, 9-9, 9-11, 10-5

sags and clearances 6-3, 6-7

selection of type and size 9-8

tension limits 9-9, 9-11
Bulletin 1724E-200

Page M-8 

INDEX

Subject Page Numbers

P

Permits 3-6 to 3-10

Percy Thomas formula 6-4

Photogrammetry 3-1, 3-5

Plan-profile drawings, 3-5, 3-6, Chapter 10

preparation of 10-1 to 10-4

Pole, moment capacities F-5 to F-19

Pole classes F-4

Pole embedment depth Chapter 12

Pole stability

direct embedded, wood 12-2 to 12-5

direct embedded, steel and concrete 12-6 to 12-7

Pole top assembly, H-frame 13-31 to 13-34

Pole, weight F-22

Poles, wood, designated stresses 13-4

Post insulator 8-1 to 8-3, 8-13 to 8-15

Preservative treatment 13-4, 13-5

R

Rail cars, clearance to 4-5 to 4-8

Reconnaissance and preliminary survey 3-4

Reference component and tall Vehicles/boats 4-3, 4-4

Rerouting 3-6

RI and TVI I-2 to I-6

Right-of-way 3-4, 3-6

calculated width 5-1 to 5-14

clearing 3-6

typical width 5-10

width 5-10

width for a line directly next to a road 5-11, 5-12

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

5-12, 5-13 

4-3 

3-1 to 3-3 

3-4, 3-5, 10-1, 10-2 

9-12 to 9-14, 10-5 to -9, 10-15 

9-12, 9-13 

9-14 

9-13 
Bulletin 1724E-200

Page M-9 

INDEX

Subject Page Numbers

S

Sag, overhead ground wire 6-7

Sag and tension relationships 9-17, 9-18

Sag template, 10-5 to 10-7 

curves 10-5 to 10-7

Sagging of conductors 9-21

Section properties, (structural) H-2

Selection of conductor size 9-6, 9-7

Selection of conductor type 9-6

Self-damping conductor 9-3, 9-4

Separation, horizontal 6-1, 6-2

between transmission and underbuild 

distribution conductors

16-1 to 16-4

Separation, minimum vertical 6-1 to 6-4

Separation between lines as dictated by minimum 

clearance between conductors carried on different 

supports 5-12

Separation between lines as dictated by minimum 

clearance of conductors from one line to the 

supporting structure of another 5-13

Shielding angle 8-5 to 8-7

Side hill clearance 10-13

Single pole structures, a method of structural analysis 

of 

13-5 to 13-22

Site survey 12-1

Soil, 12-1 to 12-8

bearing capacity 12-7, 12-8

construction backfill 12-9

Soils, description of types 12-3

Spaces and ways accessible to pedestrians only 4-3, 4-4, 4-7 to 4-9

Span,

definition of 7-9, 10-10 to 10-14

horizontal, definition 7-9

maximum, as limited by structure strength for 

single pole structures 13-5 to 13-22

maximum, as limited by structure strength for 

H-frame structures 13-27 to 13-44

maximum, as limited by clearance to underbuild 16-5

maximum, as limited by conductor separation 6-1 to 6-6

maximum, as limited by conductor separation under 

differential ice loading

6-6, 6-7

maximum, as limited by galloping 6-7, 6-8

maximum possible 9-17

vertical 10-10 to 10-13, 13-22 to 13-26

Splices 15-4
Bulletin 1724E-200

Page M-10 

INDEX

Subject Page Numbers

Standard loaded conductor tension 9-9, 9-10

Strain yokes 15-5

Strength factors 11-17 to 11-20

Strength of pole top assembly, H-frames 13-31 to 13-35

Stringing of conductors 9-20

Structure, designated stresses, wood 13-4

Structure deflection 5-1, 5-5, 5-8 to 5-14, 13-6 to 13-13

Structure related hardware 15-10 to 15-14

Structure spotting 10-8 to 10-16

Structure strength, longitudinal 10-15, 11-14, 11-15

Structure uplift (H-frame) 12-9

Structures, Chapter 13

general design considerations for steel/concrete 13-2, 13-3

general design considerations for wood 13-4

guyed Chapter 14, 10-15

H-frames, a method of analysis of 13-27 to 13-44

single pole, a method of analysis of 13-5 to 13-22

Suspension clamps 15-1, 15-2, 15-4

Suspension insulators 8-1 to 8-3, 8-13, 8-14

Swimming pools, lines over 4-6, 4-9

Swing angle bracket 15-12

T

T2 Conductor 9-4

Temperature, conductor 4-2, 4-3, 4-10, 5-1, 16-2

Thermal considerations, conductor 9-7

Thunderstorm days, map E-4

Tied Supports 15-3

TVI and RI I-2 to I-6

U

Underbuild, Chapter 16

addition to existing transmission line 16-1

clearance between transmission and underbuild 

distribution conductor Chapter 16

distribution neutrals 16-5

horizontal separation from transmission conductor 16-1, 16-2

sag template curves 10-5 to 10-7

strength requirements Chapter 11, 16-1

vertical clearance to ground 16-2 to 16-4

Uplift 10-5, 10-12 to 10-14, 12-9, 13-33
Bulletin 1724E-200

Page M-11 

INDEX

Subject Page Numbers

V

V-braces 13-31 to 13-34

Vehicles, tall, clearance to 4-3, 4-4

Velocity pressure exposure coefficient

structure 11-4

wire 11-3,11-4

Vertical separation 6-3 to 6-6

minimum 6-3

Vertical span, 10-11, 10-12

definition 7-9, 10-11, 10-12

maximum vertical span limited by structure 

strength for single pole structures 13-9

maximum limited vertical span limited by structure 

strength for H-frames 13-31 to 13-35

Voltage, maximum operating 4-1

W

Wind, annual extreme winds 11-2 to 11-9

Wind, annual extreme ice with concurrent wind 11-9 to 11-14

Wind, velocities and pressures 11-3, 11-4, E-2

Wood, preservative treatment 13-4, 13-5

Wood, designated stresses for 13-4

Wood, stress limitations 13-4
Bulletin 1724E-200

Page M-12

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