BULLETIN 1724E-200 

DESIGN MANUAL FOR

HIGH VOLTAGE TRANSMISSION LINES 

U.S. DEPARTMENT OF AGRICULTURE 

RURAL UTILITIES SERVICE 

ELECTRIC STAFF DIVISION 

Revised May 2009 
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TABLE OF CONTENTS

CHAPTER 1 - GENERAL 

CHAPTER 2 - TRANSMISSION LINE DOCUMENTATION 

CHAPTER 3 - TRANSMISSION LINE LOCATION, ENGINEERING SURVEY AND 

 RIGHT-OF-WAY ACTIVITIES 

CHAPTER 4 - CLEARANCES TO GROUND, TO OBJECTS UNDER THE LINE AND 

 AT CROSSINGS 

CHAPTER 5 - HORIZONTAL CLEARANCES FROM LINE CONDUCTORS 

 TO OBJECTS AND RIGHT-OF-WAY WIDTH 

CHAPTER 6 - CLEARANCES BETWEEN CONDUCTORS AND BETWEEN 

 CONDUCTORS AND OVERHEAD GROUND WIRES 

CHAPTER 7 - INSULATOR SWING AND CLEARANCES OF CONDUCTORS 

 FROM SUPPORTING STRUCTURES 

CHAPTER 8 - INSULATION AND INSULATORS 

CHAPTER 9 - CONDUCTORS AND OVERHEAD GROUND WIRES 

CHAPTER 10 - PLAN-PROFILE DRAWINGS 

CHAPTER 11 - LOADINGS AND LOAD FACTORS 

CHAPTER 12 - FOUNDATION STABILITY OF DIRECT-EMBEDDED POLES 

CHAPTER 13 - STRUCTURES 

CHAPTER 14 - GUYED STRUCTURES 

CHAPTER 15 - HARDWARE 

CHAPTER 16 - UNDERBUILD 

APPENDIX A - TRANSMISSION LINE DESIGN DATA SUMMARY SHEET 

 AND SUPPORTING INFORMATION 

APPENDIX B - CONDUCTOR TABLES 

APPENDIX C - INSULATION TABLES 

APPENDIX D - AMPACITY, MVA, SURFACE GRADIENT TABLES

APPENDIX E - WEATHER DATA 
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TABLE OF CONTENTS (CONT)

APPENDIX F - POLE DATA 

APPENDIX G - CROSSARM DATA 

APPENDIX H - MISCELLANEOUS STRUCTURAL DATA 

APPENDIX I - RI AND TVI 

APPENDIX J - INSULATOR SWING TABLES

APPENDIX K - SYMBOLS AND ABBREVIATIONS 

APPENDIX L - SELECTED SI-METRIC CONVERSIONS 

APPENDIX M- INDEX 

INDEX OF BULLETINS: Design, System 

 Transmission Facilities, Line Manual 

ABBREVIATIONS

(See Appendix L for Engineering Symbols and Abbreviations) 

AAAC 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 Guage 

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 

EPA Environmental Protection Agency 

EHV Extra High Voltage 

EIS Environmental Impact Statement 

EI&W Extreme Ice & Concurrent Wind 

EPRI Electric Power Research Institute 
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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 

MOR Modulus of Rupture 

MOV Metal Oxide Varistor 

NEPA National Environmental Protection Act 

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 
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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. 

ACKNOWLEDGEMENTS

Figures 9-6 and 9-7 of this bulletin are reprinted from IEEE Std 524-1992, “IEEE Guide to the 

Installation of Overhead Transmission Line Conductors, Copyright 1992 by IEEE. The IEEE 

disclaims any responsibility or liability resulting from the placement and use in the described 

manner. 

Figures 4-2, 4-4, 5-2, 5-5 and 11-1 and the table on reference heights (page 4-3) of this bulletin 

are reprinted from IEEE/ANSI C2-2007, National Electrical Safety Code, Copyright 2007 by 

IEEE. The IEEE disclaims any responsibility or liability resulting from the placement and use in 

the described manner. 

Figures 11-2a to 11-2e, 11-3a to 11-3f, and Tables E-2 and E-3 of this bulletin are reprinted from 

ASCE7-05, “Minimum Design Loads for Buildings and Other Structures,” American Society of 

Civil Engineers, Copyright 2005. For further information, refer to the complete rest of the 

manual (http://www.pubs.asce.org/ASCE7.html?99991330). 
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LIST OF TABLES

Table 

Number Table Name Brief Comment Page

 

3-1 Line Routing Considerations Routing 3-2 

 

3-2 Summary of Potential Major Federal Permits 

or Licenses That May Be Required 

Federal permits 3-6 

 

4-1 Recommended Design Vertical Clearances 

of Conductors Above Ground, Roadways, 

Rails, or Water Surface 

Vertical clearance 4-6 

 

4-2 Recommended Design Vertical Clearances 

from Other Supporting Structures, Buildings 

and Other Installations 

Vertical clearance 4-8 

 

4-3 Recommended Design Vertical Clearances 

in Feet Between Conductors Where the 

Conductors of One Line Cross Over the 

Conductors of Another and Where the 

Upper and Lower Conductor Have Ground 

Fault Relaying 

Vertical clearance 4-12 

 

5-1 Recommended Design Horizontal 

Clearances (In Feet) From Conductors At 

Rest And Displaced By 6 Psf Wind To 

Other Supporting Structures, Buildings And 

Other Installations 

Horizontal clearanceno wind and 6psf wind 5-2 

 

5-2 Recommended Design Horizontal 

Clearances (In Feet) From Conductors 

Displaced By Extreme Winds To Other 

Supporting Structures, Buildings And Other 

Installations Or Vegetation 

Horizontal clearanceextreme wind 5-5 

 

5-3 Typical Right-of-Way Widths Right-of-way 5-9 

 

6-1 Recommended Vertical Separation in Feet 

Between Phases of the Same or Different 

Circuits Attached to the Same Structure 

Vertical separation of 

conductors 

6-3 

 

7-1 Recommended Minimum Clearances in 

Inches at Conductor to Surface of Structure 

or Guy Wires 

Clearances for insulator 

swing 

7-4 

 
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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 7-6 

8-1 Recommended Insulation Levels at Sea 

Level (Suspension at Tangent and Small 

Angle Structures) 

Insulation 8-2 

8-2 Recommended Insulation Levels at Sea 

Level (Posts at Tangent and Small Angle 

Structures) 

Insulation 8-3 

8-3 Reduced Shielding Angle Values Shield angles 8-5 

8-4 Suggested Leakage Distances for 

Contaminated Areas 

Leakage distances 8-10 

8-5 Summary of Recommended Insulator 

Loading Limits 

Insulator load limits 8-11 

9-1 Recommended Minimum Conductor Sizes Min. conductor sizes 9-6 

9-2 Constants to be Added to the Total 

Load on a Wire for NESC District Loads 

Constants 9-9 

9-3 Recommended Conductor and 

Overhead Ground Wire Tension and 

Temperature Limits 

Tension and temp. 

limits 

9-10 

 

9-4 Direction of Deviation of Sags from 

Predicted Values when Actual and Assumed 

(Design) Ruling Span Values are 

Significantly Different 

Ruling span and sags 9-13 

 

11-1 Ice, Wind, Temperature,and Constants Loading Districts 11-2 

 

11-2 Wire Velocity Pressure Exposure 

Coefficient (kZ) 

Wire kZ 11-3 

 

11-3 Wire Gust Response Factor, GRF Wire GRF 11-3 

 

11-4 Combined Factor kZ*GRF for Common Wire 

Heights 

Wire kZ*GRF 11-4 

 

11-5 Structure kZ, GRF , and Combined kZ GRF

Factor 

kZ, and GRF for 

structures 

11-4 

 

11-6 Recommended Load Factors and Strength 

Factors to be Applied to NESC District 

Loads 

Load factors and 

strength factors 

11-17 

 
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LIST OF TABLES 

(Continued from previous page)

Table 

Number Table Name Brief Comment Page 

11-7 Recommended Load Factors and Strength 

Factors to be Applied to Extreme Wind 

Loads and Extreme Ice with Concurrent 

Wind 

Load factors and 

strength factors 

11-18 

 12-1 Classification of Soils Based Soil description 12-2 

on Field Tests 12-2 Presumptive Allowable Bearing Bearing capacity 12-7 

 Capacities, ksf 12-3 Suggested Ranges of Presumptive Bearing capacity 12-7 

Ultimate Bearing Capacities, psf 13-1 Designated Stresses for Poles Wood characteristics 13-3 13-2 Designated Stresses for Crossarms Wood characteristics 13-3 13-3 Crossbrace Capacities X-brace 13-15 14-1 Application of Load and Strength Factors 

for Guyed Structures (Guys and Anchors) 

Load factors 14-2 

 14-2 Recommended Minimum Clearances in 

Inches from Conductor to Surface of 

Structure or to Guy Wires 

Clearance to guys 14-3 

 

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

Double Arming Bolts and Double End Bolts 

Bolt strengths 15-9 

 

15-2 Strengths of ASTM A325 Heat Treated, 

High Strength Bolts 

Bolt strengths 15-11 

 

15-3 Galvanic Table of Various Metals Galvanic table 15-12 

 

16-1 Recommended Minimum Vertical 

Clearances to Distribution or 

Communication Underbuild on 

Transmission Lines in Feet 

Clearance to 

underbuild 

16-3 

 C-1 Flashover Data for Porcelain String 

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

 C-2 

 C-2 Flashover Data For Suspension Polymers 

(ANSI C29.12-1997) 

 C-3 

 C-3 Approximate Weights and Lengths of 

Insulator Strings Using Standard 5-3/4” x 10”

Suspension Bells with a Ball Hook 

 C-4 
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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 4-1 

 

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

4-3 Simplified Clearance Envelope Clearance to rail cars 4-5 

4-4 Swimming Pool Clearances Vertical clearances for 

swimming pools 

4-5 

 

5-1 Horizontal Clearance Requirement Horizontal clearances 5-1 

 

5-2 Radial Clearance Requirements to 

Vegetation 

Clearance to vegetation 5-4 

 

5-3 Clearance to Grain Bins, NESC 

 Figure 234-4a 

Clearance to grain bins 5-6 

 

5-4 Horizontal Clearance to Grain Bins, 

Conductors at Rest 

Clearance to grain bins 5-6 

 

5-5 Horizontal Clearance To Grain Bins, 

Conductors Displaced by 6 psf or Extreme 

Wind 

Clearance to grain bins 5-6 

 

5-6 NESC Clearance to Grain Bins with 

Portable Loading Equipment 

Clearance to grain bins 5-7 

 5-7 Simplified Recommendations for Clearances 

to Grain Bins with Portable Loading 

Equipment 

Clearance to grain bins 5-7 

 5-8 A Top View of a Line Showing Total 

Horizontal Clearance Requirements 

Horizontal clearance 5-8 

 5-9 ROW Width for Single Line of Structures 

(First Method) 

ROW width 5-10 

 5-10 Clearance Between Conductors of One Line 

to Conductor of Another Line 

Clearance between 

lines 

5-11 

 5-11 Clearance Between Conductors of One Line 

and Structure of Another 

Clearance between 

lines 

5-12 

 

6-1 Example of Vertical and Horizontal 

Separation Values 

Separation of 

conductors 

6-1 

 

 
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Page-xiv

LIST OF FIGURES

(Continued from previous page)

Figure 

Number Figure Name Brief Comment Page 

6-2 Minimum Distance Between Conductors Distance Between 

Conductors 

6-6 

 6-3 Guide for Preparation of Lissajous Ellipses Galloping ellipses 6-8 

 6-4 Single Loop Galloping Analysis Galloping 6-9 6-5 Proper Phase Arrangements for Crossarm to 

Vertical Construction 

Vertical transition of 

conductors 

6-9 

 7-1 Illustration of Structure Insulator Swing 

Angle Limits and Conditions Under Which 

They Apply (Excludes Backswing) 

Insulator swing 7-3 

 7-2 Forward and Backward Swing Angles Insulator swing 7-5 

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

Tangent Structure 

Example swing chart 7-6 

 7-4 Horizontal and Vertical Spans Span definitions 7-7 7-5 Typical Insulator Swing Chart for a 

TH-233 Medium Angle Structure 

Example swing chart 7-8 

 

7-6 Insulator Swing Chart for Example 7-9 Example swing chart 7-11 

 

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

 

8-2 A Typical Porcelain Horizontal Post 

Insulator 

Horizontal post 8-1 

 

8-3 Insulation Derating Factor vs. Altitude in 

1,000's of Feet 

Derating factor 8-3 

 

8-4 Shielding Angle, Pole and Overhead Ground 

Wires 

Shielding angle 8-6 

 

8-5 Contamination Breakdown Process of a 

Single Porcelain Insulator Unit 

Insulator contamination 8-8 

 9-1 Typical ACSR Strandings ACSR conductor 9-1 9-2 1350 Aluminum Conductor Strandings 1350 conductor 9-2 

 9-3 Typical ACAR Strandings ACAR conductor 9-3 9-4 Typical ACSR/SD Strandings ACSR/SD conductor 9-3 

 
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Page-xv

LIST OF FIGURES

(Continued from previous page)

Figure 

Number Figure Name Brief Comment Page 

9-5 Results of a Typical Economical Conductor 

Analysis - 230 kV, 795 vs. 954 vs. 1272 

kcmil ACSR 

Economic conductor 

analysis 

9-7 

 9-6 Nomograph for Determining Level Span 

Equivalents of Non-Level Spans 

Level span equivalents 9-17 

 9-7 Analysis for Application of Clipping Offsets Offset clipping 9-20 9-8 Line Section for Example 9-1 Example of ruling span 9-21 10-1 Sample of a Plan and Profile P&P sample 10-2 10-2 Conventional Symbols for Plan-Profile Symbols 10-3 10-3 Specimen Sag Template for Conductor Sag template 10-6 10-4 Application of Sag Template - Level Ground 

Span. 

Level ground span 10-9 

 10-5 Check for Uplift Uplift 10-11 10-6 Sag Low Point, Vertical Spans and Uplift Vertical spans and uplift 10-12 10-7 Sample Check List for Review of Plan and 

Profile 

Checklist 10-15 

 11-1 NESC Loading Districts NESC districts 11-1 11-2a Extreme Wind Speed in Miles per Hour at 

33 Ft. Above Ground (50-Year Mean 

Recurrence Interval) 

Western states extreme 

wind loads 

11-5 

 11-2b Extreme Wind Speed in Miles per Hour At 

33 Ft. Above Ground (50-Year Mean 

Recurrence Interval) 

Midwest and Eastern 

states extreme wind 

loads 

11-6 

 11-2c, 

11-2d 

Extreme Wind Speed in Miles per Hour at 

33 Ft. Above Ground for the Northeast and 

Southeast (50-Year Mean Recurrence Int) 

Northeast and 

Southeast extreme 

wind loads 

11-7 

 

11-2e Extreme Wind Speed in Miles per Hour at 

33 Ft. Above Ground for the Texas, 

Louisiana, and Mississippi (50-Year Mean 

Recurrence Interval) 

Texas, Louisiana, and 

Mississippi extreme 

wind loads 

11-8 

 

11-3a Uniform Ice Thickness Due To Freezing 

Rain With Concurrent 3-Second Gust Wind 

Speeds (50 Yr. Mean Recurrence) 

Extreme ice with 

concurrent wind loads 

for Western US 

11-9 
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Page-xvi

LIST OF FIGURES

(Continued from previous page)

Figure 

Number Figure Name Brief Comment Page 

11-3b Uniform Ice Thickness Due To Freezing 

Rain With Concurrent 3-Second Gust Wind 

Speeds (50 Yr. Mean Recurrence) 

Extreme ice with 

concurrent wind loads 

for Central and eastern 

11-10 

 11-3c Uniform Ice Thickness Due To Freezing 

Rain With Concurrent 3-Second Gust Wind 

Speeds For Alaska (50 Year Mean 

Recurrence Interval) 

Extreme ice with 

concurrent wind loads 

for Alaska 

11-11 

 11-3d Uniform Ice Thickness Due To Freezing 

Rain With Concurrent 3-Second Gust Wind 

Speeds For Lake Superior (50 Yr. Mean 

Recurrence) 

Extreme ice with 

concurrent wind loads 

for Lake Superior 

11-12 

 11-3e Uniform Ice Thickness Due To Freezing 

Rain With Concurrent 3-Second Gust Wind 

Speeds For Fraser Valley Detail (50 Yr. 

Mean Recurrence) 

Fraser Valley extreme 

ice with concurrent 

wind loads 

11-12 

 11-3f Uniform Ice Thickness Due To Freezing 

Rain With Concurrent 3-Second Gust Wind 

Speeds For Columbia River Gouge (50 Yr. 

Mean Recurrence) 

Extreme ice with 

concurrent wind loads 

for Columbia River 

Gouge 

11-13 

 

12-1 Embedment Depths in Poor Soil Embedment depths 12-3 

 

12-2 Embedment Depths in Average Soil Embedment depths 12-4 

 

12-3 Embedment Depths in Good Soil Embedment depths 12-4 

 

12-4 Embedment Chart for Medium Dry Sand 

Bulletin 1724e-205 “Embedment Depths for 

Concrete and Steel Poles” 

Embedment depths 12-5 

 

13-1 Selection of Level Ground Span Level ground span 13-2 

 

13-2 Structure Cost per Mile Related to Pole Height Economic pole height 13-2 

 

13-3 TS Type Structure 13-5 

 13-4 TSS-1 Structure 13-7 13-5 Application of Forces (Heavy Loading) 13-7 13-6 TSZ-1 Pole Top Assembly 13-10 13-7 TSZ-1 Example 13-10 
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Page-xvii

LIST OF FIGURES

(Continued from previous page)

Figure 

Number Figure Name Brief Comment Page 

13-8 HS vs. VS for TSZ-1 13-10 

13-9 TU-1 Structure 13-11 

13-9a Davit Arm 13-12 

13-10 VS vs. HS for TUS-1 Structure of Ex.13-3 13-12 

13-11 Assumed H-Frame Behavior H-frame behavior 13-13 

13-12 Location of Point of Contraflexure Pt. of contraflexure 13-13 

13-13 Crossbrace X-brace 13-14 

13-14 Pole Top Bracing Arrangements Pole top for H-frames 13-15 13-15 Pole Top Assembly with Two Outside Braces Two outside braces 13-16 

13-16 Pole Top Assembly with Inside Braces Inside braces 13-17 

13-17 Structure 1 13-19 

13-18 Structure 2 13-20 

13-19 Structure 3 13-21 

13-20 Structure 4 13-21 

13-21 Structure 5 13-22 

13-22 Structure 6 13-22 

13-23 Example of an H-Frame 13-23 

14-1 Deadend Structure 14-1 

14-2 Comparison of Rods to Show Stability Concept Stability concept 14-4 

 

14-3 Effective Unbraced Length for Various End 

Conditions 

Unbraced lengths 14-5 

 

14-4a, 

14-4b 

End Conditions for Bisector and In-Line 

Guyed Structures 

End conditions for 

guyed poles 

14-7 

 

14-5 Axial Loads Induced in a Pole 14-8 

 

14-6 Representation of Axial Loads and Double 

Accounting Loads 

 14-8 

 

 
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LIST OF FIGURES

(Continued from previous page)

Figure 

Number Figure Name Brief Comment Page 

15-1 Suspension Clamp with Clevis or Ball and 

Socket Type of Connection 

 15-1 

15-2 Post Type Insulator with Straight Line 

Trunion Clamps 

 15-2 

15-3 Top Groove Hand Tie 15-2 

15-4a Typical Bolted Deadend Clamp 15-3 

15-4b Typical Compression Deadend 15-3 

15-5 Suspension Insulators 15-5 15-6 Different Types of Hooks 15-5 

 

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

Connections 

 15-5 

15-8 Anchor Shackle; Chain Shackle 15-5 

15-9 Armor Rods Used with Suspension 

Insulators 

 15-6 

15-10a Cushioned Suspension Unit 15-6 

15-10b Double Cushioned Suspension (for Line 

Angles Greater than 30o

) 

 15-6 

 

15-11 Typical Suspension Damper 15-7 

15-12 Spiral Vibration Damper for Small 

Conductors 

 15-7 

15-13 Disc Weights, Ball Weights 15-8 

15-14 Fasteners 15-9 

15-15 Lag Screw 15-9 

15-16 Grid Gains 15-10 

15-17 Spacer Fitting, Reinforcing Plate 

and Gain Plate 

 15-10 

15-18 Small Angle Structure with Swing Angle 

Brackets 

 15-11 

16-1 Horizontal Separation Requirements 

Between Transmission and Underbuild 

 16-2 
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Page-xix

LIST OF FIGURES

(Continued from previous page)

Figure 

Number Figure Name Brief Comment Page 

16-2 Vertical Separation Requirements at 

Structure for Underbuild 

 16-2 

16-3 Transference of the Distribution Circuit to a 

Separate Pole at a Large Angle 

 16-5 

16-4 Use of a Separate Pole to Mount a 

Distribution Transformer 

 16-5 

 

16-5 Guying Distribution Underbuild 16-5 

E-1 Isokeraunic Levels for the United States E-4 

G-1 Crossarm Loading Chart-Maximum 

Permitted Vertical Loads of Various Sizes of 

Douglas Fir Crossarms 

 G-3 

H-1 Curve for Locating Plane of Contraflexure in 

X-Braced H-Frame Structures 

 H-3 
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Page 1-1 

1. GENERAL

1.1 Purpose: The primary purpose of this bulletin is to furnish engineering information for use 

in designing transmission lines. Good line design should result in high continuity of service, 

long life of physical equipment, low maintenance costs, and safe operation. 

1.2 Scope: The engineering information in this bulletin is for use in design of transmission lines 

for voltages 230 kV and below. Much of this document makes use of standard Rural Utilities 

Service (referred to as the agency) structures and assemblies in conjunction with data provided in 

this bulletin. Where nonstandard construction is used, factors not covered in this bulletin may 

have to be considered and modification to the design criteria given in this bulletin may be 

appropriate. 

Since the agency program is national in scope, it is necessary that designs be adaptable to various 

conditions and local requirements. Engineers should investigate local weather information, soil 

conditions, operation of existing lines, local regulations, and environmental requirements and 

evaluate known pertinent factors in arriving at design recommendations. 

1.3 National Electrical Safety Code (NESC): This bulletin is based on the requirements of the 

2007 edition of the National Electrical Safety Code. In accordance with the Code of Federal 

Regulations 7 CFR Part 1724, agency financed lines are to be a minimum of Grade B 

construction as defined in the NESC. However, since the NESC is a safety code and not a design 

guide, additional information and design criteria are provided in this bulletin as guidance to the 

engineer. 

The NESC may be purchased from the Institute of Electrical and Electronics Engineers (IEEE) 

Operations Center, 445 Hoes Lane, P.O. Box 1331, Piscataway, NJ 08855-1331 or at the 

following website: 

http://standards.ieee.org/nesc 

1.4 Responsibility: The borrower is to provide or obtain all engineering services necessary for 

sound and economical design. Due concern for the environment in all phases of construction and 

cleanup should be exercised. 

1.5 Environmental Regulations: Agency environmental regulations are codified in 

7 CFR Part 1794, "Environmental Policies and Procedures." These regulations reference 

additional laws, regulations and Executive Orders relative to the protection of the environment. 

The Code of Federal Regulations may be purchased from the Superintendent of Documents, U.S. 

Government Printing Office, Washington, DC 20402. 

Agency environmental regulations may be found on the following website: 

http://www.usda.gov/rus/electric/regs/index.htm 
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2. TRANSMISSION LINE DOCUMENTATION

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

documentation for transmission lines financed by the Rural Utilities Service. 

2.2 General: Policy and procedures pertaining to construction of transmission lines by agency 

electric borrowers are codified in 7 CFR 1724, “Electric Engineering, Architectural Services and 

Design Policies and Procedures” and 7 CFR 1726, "Electric System Construction Policies and 

Procedures" (http://www.usda.gov/rus/electric/regs/index.htm). The requirements of 

7 CFR 1726 apply to the procurement of materials and equipment for use by electric borrowers 

and to construction of the electric system if the material, equipment, and construction are 

financed, in whole or in part, with loans made or guaranteed by the Rural Utilities Service. 

2.3 Design Data Summary: When design data is required by the agency, a design data 

summary (or its equivalent) should be submitted. Engineering design information includes 

design data, sample calculations, and plan-profile drawings. A ‘Transmission Line Design Data 

Summary Form’, which is included in Appendix A of this bulletin, has been prepared to aid in 

the presentation of the design data summary. A suggested outline in Appendix A indicates 

information that should be considered when preparing a design data summary. Appendix A also 

highlights information which should be included in the design data submitted to the agency when 

computer software has been used in the design. 
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Page 3-1 

3. TRANSMISSION LINE LOCATION, ENGINEERING SURVEY AND RIGHT-OFWAY ACTIVITIES

3.1 Route Selection: Transmission line routing requires a thorough investigation and study of 

several different alternate routes to assure that the most practical route is selected, taking into 

consideration the environmental criteria, cost of construction, land use, impact to public, 

maintenance and engineering considerations. 

To select and identify environmentally acceptable transmission line routes, it is necessary to 

identify all requirements imposed by State and Federal legislation. Environmental 

considerations are generally outlined in agency Bulletin 1794A-601, “Guide for Preparing 

Environmental Reports for Electric Projects That Require Environmental Assessments.” State 

public utility commissions and departments of natural resources may also designate avoidance 

and exclusion areas which have to be considered in the routing process. 

Maps are developed in order to identify avoidance and exclusion areas and other requirements 

which might impinge on the line route. Ideally, all physical and environmental considerations 

should be plotted on one map so this information can be used for route evaluation. However, 

when there are a large number of areas to be identified or many relevant environmental concerns, 

more than one map may have to be prepared for clarity. The number of maps engineers need to 

refer to in order to analyze routing alternatives should be kept to a minimum. 

Typical physical, biological and human environmental routing considerations are listed in 

Table 3-1. The order in which considerations are listed is not intended to imply any priority. In 

specific situations, environmental concerns other than those listed may be relevant. Suggested 

sources for such information are also included in the table. Sources of information include the 

United States Geological Service (USGS), Federal Emergency Management Agency (FEMA), 

United States Department of the Interior (USDI), United States Department of Agriculture 

(USDA), Natural Resource Conservation Service (NRCS) and numerous local and state 

agencies. 

For large projects, photogrammetry is contributing substantially to route selection and design of 

lines. Preliminary corridor location is improved when high altitude aerial photographs or 

satellite imagery are used to rapidly and accurately inventory existing land use. Once the 

preferred and alternative corridors have been identified, the engineer should consult USGS maps, 

county soil maps, and plat and road maps in order to produce small scale maps to be used to 

identify additional obstructions and considerations for the preferred transmission line. 

On smaller projects, the line lengths are often short and high altitude photograph and satellite 

imagery offer fewer benefits. For such projects, engineers should seek existing aerial 

photographs. Sources for such photographs include county planning agencies, pipeline 

companies, county highway departments, and land development corporations. A preliminary 

field survey should also be made to locate possible new features which do not appear on USGS 

maps or aerial photographs. 

As computer information systems become less expensive and easier to use, electric transmission 

utilities are using Geographic Information Systems(GIS) to automate the route identification 

process. GIS technology enables users to easily consolidate maps and attribute information from 

various sources and to efficiently analyze what has been collected. When used by routing 

experts, automated computer processes help standardize the route evaluation and selection 

process, promote objective quantitative analysis and help users select defendable routes. GIS 

tools have proven very beneficial to utilities whose goals are to minimize impact on people and 

the natural environment while selecting a constructible, maintainable and cost effective route. 
Bulletin 1724E-200 

Page 3-2 

Final route selection, whether for a large or small project, is a matter of judgment and requires 

sound evaluation of divergent requirements, including costs of easements, cost of clearing, and 

ease of maintenance as well as the effect a line may have on the environment. Public relations 

and public input are necessary in the corridor selection and preliminary survey stages. 

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 

• Cropland 

• Urban development 

• Industrial development 

USGS aerial survey, satellite mapping, county planning 

agencies, state planning agencies, state soil conservation 

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

NRCS 

• 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. 
Bulletin 1724E-200

Page 3-3 

3.2 Reconnaissance and Preliminary Survey: Once the best route has been selected and a 

field examination made, aerial photos of the corridor should be reexamined to determine what 

corrections will be necessary for practical line location. Certain carefully located control points 

should then be established from an aerial reconnaissance. Once these control points have been 

made, a transit line using stakes with tack points should be laid in order to fix the alignment of 

the line. A considerable portion of this preliminary survey usually turns out to be the final 

location of the line. 

In many instances, after route has been selected and a field examination made, digital design data 

on a known coordinate system like State Plane is used for centerline alignment and profile. This 

alignment is provided to surveyors in a universal drawing file format. The surveyors then 

convert it to a format used by their field recording equipment. Once the project location is 

known, base control monuments are established along the route at 2 to 5 mile intervals, 

depending on topography, with static Global Positioning System (GPS) sessions from known 

horizontal and vertical control monuments. GPS equipment and radio transmitter equipment 

occupying the base monuments broadcast a corrected signal to roving GPS unit(s). These GPS 

units, with the use of an on-board field computer, allow any point or any line segment along the 

route to be reproduced in the field. The roving unit can be used to locate and verify wire heights 

at crossings, unmarked property lines or any routing concerns that may come up locally. The 

equipment can also be used to establish centerline points in open areas so that conventional 

survey equipment can be used to mark the line in wooded areas for clearing purposes. Once the 

right-of-way (ROW) has been cleared, all structures can be staked with the Real Time 

Kinematic-Global Positioning System (RTK-GPS) equipment. Since this entire process uses 

data of a known mapping plane, any position along the route can be converted to various formats 

and used within databases. 

3.3 Right-of-Way: A right-of-way agent (or borrower's representative) should precede the 

preliminary survey party in order to acquaint property owners with the purpose of the project, the 

survey, and to secure permission to run the survey line. The agent or surveyor should also be 

responsible for determining property boundaries crossed and for maintaining good public 

relations. The agent should avoid making any commitments for individual pole locations before 

structures are spotted on the plan and profile sheets. However, if the landowner feels particularly 

sensitive about placing a pole in a particular location along the alignment, then the agent should 

deliver that information to the engineer, and every reasonable effort should be made by the 

engineer to accommodate the landowner. 

As the survey proceeds, a right-of-way agent should begin a check of the records (for faulty 

titles, transfers, joint owners, foreclosed mortgages, etc.) against the ownership information 

ascertained from the residents. This phase of the work requires close coordination between the 

engineer and the right-of-way agent. At this time, the right-of-way agent also has to consider 

any access easements necessary to construct or maintain the line. 

Permission may also have to be obtained to cut danger trees located outside inside the 

right-of-way. Costly details, misuse of survey time and effort, and misunderstanding on the part 

of the landowners should be avoided. 

3.4 Line Survey: Immediately after the alignment of a line has been finalized to the satisfaction 

of both the engineer and the borrower, a survey should be made to map the route of the line. 

Based on this survey, plan-profile drawings will be produced and used to spot structures. 

Long corridors can usually be mapped by photogrammetry at less cost than equivalent ground 

surveys. The photographs will also contain information and details which could not otherwise be 

discovered or recorded. Aerial survey of the corridor can be accomplished rapidly, but proper 

conditions for photography occur only on a comparatively few days during the year. In certain 
Bulletin 1724E-200 

Page 3-4 

areas, photogrammetry is impossible. It cannot be used where high conifers conceal the ground 

or in areas such as grass-covered plains that contain no discernible objects. Necessary delays 

and overhead costs inherent in air mapping usually prevent their use for short lines. 

When using photogrammetry to develop plan-profile drawings, proper horizontal and vertical 

controls should first be established in accordance with accepted surveying methods. From a 

series of overlapping aerial photographs, a plan of the transmission line route can be made. The 

plan may be in the form of an orthophoto or it may be a planimetric map (see Chapter 10). The 

overlapping photos also enable the development of profile drawings. The tolerance of plotted 

ground elevations to the actual ground profile will depend on photogrammetric equipment, flying 

height, and accuracy of control points. 

Survey data can be gathered using a helicopter-mounted laser to scan existing lines and/or 

topography. Three dimensional coordinates of millions of points can be gathered while also 

taking forward and downward looking videos. These points can be classified into ground points, 

structure points and wire points. 

If use of photogrammetry or laser-derived survey information for topographic mapping is not 

applicable for a particular line, then transit and tape or various electronic instruments for 

measuring distance should be used to make the route survey. This survey will generally consist 

of placing stakes at 100 foot intervals with the station measurement suitably marked on the 

stakes. It will also include the placement of intermediate stakes to note the station at property 

lines and reference points as required. The stakes should be aligned by transit between the hub 

stakes set on the preliminary survey. The survey party needs to keep notes showing property 

lines and topographic features of obstructions that would influence structure spotting. To 

facilitate the location of the route by others, colored ribbon or strips of cloth should be attached 

at all fence crossings and to trees at regular intervals along the route (wherever possible). 

As soon as the horizontal control survey is sufficiently advanced, a level party should start taking 

ground elevations along the center line of the survey. Levels should be taken at every 100 foot 

stations and at all intermediate points where breaks in the ground contour appear. Wherever the 

ground slopes more than 10 percent across the line of survey, side shots should be taken for a 

distance of at least 10 feet beyond the outside conductor's normal position. These elevations to 

the right and left of the center line should be plotted as broken lines. The broken lines represent 

side hill profiles and are needed, when spotting structures, to assure proper ground clearance 

under all conductors, and proper pole lengths and setting depths for multiple-pole structures. 

3.5 Drawings: As soon as the route survey has been obtained, the plan and profile should be 

prepared. Information on the plan and profile should include alignment, stationing, calculated 

courses, fences, trees, roads, ditches, streams, and swamps. The vertical and plan location of 

telecommunications, transmission and other electric lines should be included since they affect 

the proposed line. The drawings should also show railroads and river crossings, property lines, 

with the names of the property owners, along with any other features which may be of value in 

the right-of-way acquisition, design, construction, and operation of the line. Chapter 10 

discusses structure spotting on the plan-profile drawings. 

Structure spotting should begin after all of the topographic and level notes are plotted on the plan 

and profile sheets. Prints of the drawings should be furnished to the right-of-way agent for 

checking property lines and for recording easements. One set of prints certified as to the extent 

of permits, easements, etc. that has been secured by the borrower should be returned to the 

engineer. 

3.6 Rerouting: During the final survey, it may be necessary to consider routing small segments 

of the line due to the inability of the right-of-way agent to satisfy the demands of property 
Bulletin 1724E-200

Page 3-5 

owners. In such instances, the engineer should ascertain the costs and public attitudes towards 

all reasonable alternatives. The engineer should then decide to either satisfy the property owner's 

demands, relocate the line, initiate condemnation proceedings, or take other action as 

appropriate. Additional environmental review may also be required. 

3.7 Clearing Right-of-Way: The first actual work to be done on a transmission line is usually 

clearing the right-of-way. When clearing, it is important that the environment be considered. 

Environmental commitments/mitigations should be included in the construction contracts. It is 

also important that the clearing be done in such a manner that will not interfere with the 

construction, operation or maintenance of the line. In terrain having heavy timber, prior partial 

clearing may be desirable to facilitate surveying. All right-of-way for a given line should be 

secured before starting construction. See Chapter 5 for a discussion of right-of-way width. 

3.8 Permits, Easements, Licenses, Franchises, and Authorizations: The following list of 

permits, easements, licenses, franchises, and authorizations that commonly need to be obtained is 

not meant to be exhaustive. 

Private property 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 

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 

Page 3-6 

TABLE 3-2 

SUMMARY OF POTENTIAL MAJOR FEDERAL PERMITS OR LICENSES 

THAT MAY BE REQUIRED 

 And other environmental review requirements for transmission line construction and operation 

Issue 

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) 

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 

Preconstruction 

surveys; construction, 

operation, 

maintenance, and 

abandonment 

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) 

Right-of-Way 

Across Land 

Under Federal 

Management 

Construction, 

operation, 

maintenance, and 

abandonment of 

transmission line 

across or within 

highway rights-of-way 

Federal Highway 

Administration (FHA) 

Permits to cross 

Federal Aid Highway; 

4 (f) compliance 

Department of 

Transportation Act 

23 CFR 1.23 and 1.27 

23 USC 116, 123, and 315 

23 CFR 645 

23 CFR 771 

Grant right-of-way by 

federal land-managing 

agency 

FWS Endangered Species 

Act compliance by 

federal land-managing 

agency and lead 

agency 

Endangered Species Act 

of 1973 as amended (16 

USC 1531 et seq) 

Protection of migratory 

birds 

FWS Compliance Migratory Bird Treaty Act 

of 1918 

16 USC 703-712 

50 CFR Ch 1 

Biological 

Resources 

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 3-7 

TABLE 3-2 (Continued) 

SUMMARY OF POTENTIAL MAJOR FEDERAL PERMITS OR LICENSES 

THAT MAY BE REQUIRED 

And other environmental review requirements for transmission line construction and operation 

Issue 

Action Requiring 

Permit, Approval, 

or Review 

Agency 

Permit, License, 

Compliance or 

Review 

Relevant Laws and 

Regulations 

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 agencies Review by permitting 

agencies 

Wild and Scenic Rivers Act 

(PL 90- 542) 

(43 CFR 83.50) 

Ground 

Disturbance 

and Water 

Quality 

Degradation 

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) 

A “No-hazard 

Declaration” required if 

structure is more than 

200 feet in height 

FAA Act of 1958 

(49 USC 1501) 

(14 CFR 77) 

Air Traffic Location of towers in 

regards to airport 

facilities and airspace 

Federal Aviation 

Administration (FAA) 

Section 1101 Air 

Space Permit for air 

space construction 

clearance 

FAA Act of 1958 

(49 USC 1501) 

(14 CFR 77) 
Bulletin 1724E-200 

Page 3-8 

TABLE 3-2 (Continued) 

SUMMARY OF POTENTIAL MAJOR FEDERAL PERMITS OR LICENSES 

THAT MAY BE REQUIRED 

And other environmental review requirements for transmission line construction and operation 

Issue 

Action Requiring 

Permit, Approval, 

or Review 

Agency 

Permit, License, 

Compliance or 

Review 

Relevant Laws and 

Regulations 

Disturbance of historic 

properties 

Federal lead agency, 

State Historical 

Preservation Officers 

(SHPO), Advisory 

Council on Historic 

Preservation 

Section 106 

consultation 

National Historic 

Preservation Act of 1966 

(16 USC 470) 

(36 CFR Part 800) 

Excavation of 

archaeological 

resources 

Federal landmanaging agency Permits to excavate Archaeological Resources 

Protection Act of 1979 

(16 USC 470aa to 470ee) 

Potential conflicts with 

freedom to practice 

traditional American 

Indian religions 

Federal lead agency, 

Federal landmanaging agency 

Consultation with 

affected American 

Indians 

American Indian Religious 

Freedom Act 

(42 USC 1996) 

Disturbance of graves, 

associated funerary 

objects, sacred 

objects, and items of 

cultural patrimony 

Federal landmanaging agency Consultation with 

affected Native 

American group 

regarding treatment of 

remains and objects 

Native American Graves 

Protection and 

Repatriation Act of 1990 

(25 USC 3001) 

Investigation of cultural 

and paleontological 

resources 

Affected landmanaging agencies Permit for study of 

historical, 

archaeological, and 

paleontological 

resources 

Antiquities Act of 1906 

(16 USC 432-433) 

Investigation of cultural 

resources 

Affected landmanaging agencies Permits to excavate 

and remove 

archaeological 

resources on Federal 

lands; American Indian 

tribes with interests in 

resources must be 

consulted prior to 

issuance of permits 

Archaeological Resources 

Protection Act of 1979 

(16 USC 470aa to 470ee) 

(43 CFR 7) 

Cultural 

Resources 

Protection of 

segments, sites, and 

features related to 

national trails 

Affected landmanaging agencies National 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. 
Bulletin 1724E-200

Page 4-1

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

CROSSINGS

4.1 General: Recommended design vertical clearances for agency financed transmission lines 

of 230 kV and below are listed in the Tables 4-1 through 4-3. These clearances exceed the 

minimum clearances calculated in accordance with the 2007 edition of the NESC. If the 2007 

edition has not been adopted in a particular locale, clearances and the conditions found in this 

chapter should be reviewed to ensure that they meet the more stringent of the applicable 

requirements. 

Clearance values provided in the following tables are recommended design values. In order to 

provide an additional cushion of safety, recommended design values exceed the minimum 

clearances in the 2007 NESC. 

4.2 Assumptions 

4.2.1 Fault Clearing and Switching Surges: Clearances in tables 4-1, 4-2, 4-3, and 5-1 are 

recommended for transmission lines capable of clearing line-to-ground faults and voltages up to 

230 kV. For 230 kV, the tables apply for switching surges less than or equal to 2.0; for higher 

switching surges on 230 kV transmission lines see the alternate clearance recommendations in 

the NESC. 

4.2.2 Voltage: Listed in the chart that follows are nominal transmission line voltages and the 

assumed maximum allowable operating voltage for these nominal voltages. If the expected 

operating voltage is greater than the value given below, the clearances in this bulletin may be 

inadequate. Refer to the 2007 edition of the NESC for guidance. 

Nominal Line-to-Line 

Voltage (kV) 

Maximum Line-to Line 

Operating Voltage (kV) 

34.5 * 

46 * 

69 72.5 

115 121 

138 145 

161 169 

230 242 

 *Maximum operating voltage has no effect on clearance 

 requirements for these nominal voltages. 

 FIGURE 4-1: CLEARANCE SITUATIONS COVERED IN THIS CHAPTER 

Table 4-2

 Table 4-2

Table 4-1

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

Page 4-2 

4.3 Design Vertical Clearance of Conductors: The recommended design vertical clearances 

under various conditions are provided in Table 4-1. 

4.3.1 Conditions Under Which Clearances Apply: The clearances apply to a conductor at 

final sag for the conditions ‘a’ through ‘c’ listed below. The condition that produces the greatest 

sag for the line is the one that applies. 

a. Conductor temperature of 32°F, no wind, with the radial thickness of ice for the applicable 

NESC loading district. 

b. Conductor temperature of 167°F. A lower temperature may be considered where justified by 

a qualified engineering study. Under no circumstances should a design temperature be less 

than 120°F. 

c. Maximum design conductor temperature, no wind. For high voltage bulk transmission lines 

of major importance to the system, consideration should be given to the use of 212°F as the 

maximum design conductor temperature. 

According to the National Electric Reliability Council Criteria, emergency loading for lines of a 

system would be the line loads sustained when the worst combination of one line and one 

generator outage occurs. The loads used for condition "c" should be based on long range load 

forecasts. 

Sags of overhead transmission conductors are predicted fairly accurately for normal operating 

temperatures. However, it has consistently been observed that sags for ACSR (Aluminum 

Conductor Steel Reinforced) conductors can be greater than predicted at elevated temperatures. 

If conductors are to be regularly operated at elevated temperatures, it is important that sag 

behavior be well understood. Current knowledge of the effects of high temperature operation on 

the long term behavior of conductors and associated hardware (splices, etc.) is probably limited; 

however, and a clear understanding of the issues involved is essential. The Electric Power 

Research Institute (EPRI) has prepared a report on the effects of high temperature conductor and 

associated hardware. 1

The traditional approach in predicting ACSR conductor sag has been to assume that the 

aluminum and steel share only tension loads. But as conductor temperature rises, aluminum 

expands more rapidly than steel. Eventually the aluminum tension will reduce to zero and then 

go into compression. Beyond this point the steel carries the total conductor tension. These 

compressive stresses generally occur when conductors are operated above 176 °F to 200 °F. Greater sags than predicted at these elevated temperatures may be attributed to aluminum being 

in compression which is normally neglected by traditional sag and tension methods. AAC (All 

Aluminum Conductors) and AAAC (All Aluminum Alloy Conductor) or ACSR conductors 

having only one layer of aluminum or ACSR with less than 7 percent steel should not have 

significantly larger sags than predicted by these traditional methods at higher operating 

temperatures. 2

 

1 Conductor and Associated Hardware Impacts During High Temperature Operations – Issues and Problems, L. 

Shan and D. Douglass, Final Report, EPRI TR-109044, Electric Power Research Institute, Palo Alto, California, 

December, 1997. 

2

Conductor Sag and Tension Characteristics at High Temperatures, Tapani O. Seppa and Timo Seppa, The Valley 

Group, Inc., presented at the Southeastern Exchange Annual E/O Meeting, May 22, 1996, in Atlanta, GA. 
Bulletin 1724E-200

Page 4-3

4.3.2 Altitude Greater than 3300 Feet: If the altitude of a transmission line (or a portion 

thereof) is greater than 3300 feet, an additional clearance as indicated in Table 4-1 must be 

added to the base clearances given. 

4.3.3 Spaces and Ways Accessible to Pedestrians Only: Pedestrian-only clearances should be 

applied carefully. If it is possible for anything other than a person on foot to get under the line, 

such as a person riding a horse, the line should not be considered to be accessible to pedestriansonly and another clearance category should be used. It is expected that this type of clearance 

will be used rarely and only in the most unusual circumstances. 

4.3.4 Clearance for Lines Along Roads in Rural Districts: If a line along a road in a rural 

district is adjacent to a cultivated field or other land falling into Category 3 of Table 4-1, the 

clearance-to-ground should be based on the clearance requirements of Category 3 unless the line 

is located entirely within the road right-of-way and is inaccessible to vehicular traffic, including 

highway right-of-way maintenance equipment. If a line meets these two requirements, its 

clearance may be based on the "along road in rural district" requirement. To avoid the need for 

future line changes, it is strongly recommended that the ground clearance for the line should be 

based on clearance over driveways. This should be done whenever it is considered likely a 

driveway will be built somewhere under the line. Heavily traveled rural roads should be 

considered as being in urban areas. 

4.3.5 Reference Component and Tall Vehicles/Boats: There may be areas where it can be 

normally expected that tall vehicles/boats will pass under the line. In such areas, it is 

recommended that consideration be given to increasing the clearances given in Table 4-1 by the 

amount by which the operating height of the vehicle/boat exceeds the reference component. The 

reference component is that part of the clearance component which covers the activity in the area 

which the overhead line crosses. 

For example, truck height is limited to 14 feet by state regulation, thus the reference component 

for roads is 14 feet. However, in northern climates sanding trucks typically operate with their 

box in an elevated position to distribute the sand and salt to icy roadways. The clearances in 

Table 4-1 are to be increased by the amount the sanding truck operating height exceeds 14 feet. 

In another example, the height of farm equipment may be 14 feet or more. In these cases, these 

clearances should be increased by the difference between the known height of the oversized 

vehicle and the reference height of 14 feet. 

Reference heights for Table 4-1 are given below: 

Item Description Reference height 

 (feet) 

1.0 Track rails 22.0 

2.0 Roads, streets, alleys, etc 14.0 

3.0 Residential driveways 14.0 

4.0 Other lands traversed by vehicles 14.0 

5.0 Spaces and ways--pedestrians only 8.0/10.0 

6.0 Water areas--no sail boating 12.5 

7.0 Water areas—sail boating 

 Less than 20 acres 16.0 

 20 to 200 acres 30.0 

 200 to 2000 acres 30.0 

 Over 2000 acres 36.0 

8.0 Areas posted for rigging or launching 

sailboats 

See item 7.0 

From IEEE/ANSI C2-2007, National Electrical Safety Code, Copyright 2006. All rights reserved. 
Bulletin 1724E-200 

Page 4-4 

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

4.3.6 Clearances Over Water: Clearances over navigable waterways are governed by the 

U.S. Army Corps of Engineers and therefore the clearances over water provided in Table 4-1 

apply only where the Corps does not have jurisdiction. 

4.3.7 Clearances for Sag Templates: Sag templates used for spotting structures on a plan and 

profile sheet should be cut to allow at least one foot extra clearance than given in Table 4-1, in 

order to compensate for minor errors and to provide flexibility for minor shifts in structure 

location. 

Where the terrain or survey method used in obtaining the ground profile for the plan and profile 

sheets is subject to greater unknowns or tolerances than the one foot allowed, appropriate 

additional clearance should be provided. 

4.4 Design Vertical Clearance of Conductors to Objects Under the Line (not including 

conductors of other lines): The recommended design vertical clearances to various objects 

under a transmission line are given in Table 4-2. 

4.4.1 Conditions Under Which Clearances Apply: The clearances in Table 4-2 apply under 

the same loading and temperature conditions as outlined in section 4.3.1 of this chapter. See 

NESC Figures 234-1(a) and 234-1(b) and 234-1(c) for transition zones between horizontal and 

vertical clearance planes. See Chapter 5 for horizontal clearances. 

4.4.2 Lines Over Buildings: Although clearances for lines passing over buildings are shown in 

Table 4-2, it is recommended that lines not pass directly over a building if it can be avoided. 

4.4.3 Clearances to Rail Cars: The NESC has defined the clearance envelope around rail cars 

as shown in Figure 4-2 (NESC Figure 234-5): 

FIGURE 4-2: NESC FIGURE 234-5 

From IEEE/ANSI C2-2007, National Electrical Safety Code, Copyright 2006. 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 4-5

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. 

4.4.4 Lines Over Swimming Pools: Clearances over swimming pools are for reference 

purposes only. Lines should not pass over or within clearance ‘A’ of the edge of a swimming 

pool or the base of the diving platform. Clearance ‘B’ should be maintained in any direction to 

the diving platform or tower. 

FIGURE 4-4: SWIMMING POOL CLEARANCES (See TABLE 4-2) 

From IEEE/ANSI C2-2007, National Electrical Safety Code, Copyright 2006. All rights reserved. 

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

Item 1.0

Table 4-1

Item 1.0

Table 4-1
Bulletin 1724E-200 

Page 4-6 

TABLE 4-1 

RECOMMENDED DESIGN VERTICAL CLEARANCES OF CONDUCTORS ABOVE 

GROUND, ROADWAYS, RAILS, OR WATER SURFACE (in feet) (See Notes A, F & G) 

(Applicable NESC Rules 232A, 232B, and Table 232-1) 

Line conditions under which the NESC states vertical clearances shall be met (Calculations are 

based on Maximum Operating Voltage): 

 - 32°F, no wind, with radial thickness of ice, if any, specified in Rule 250B of the NESC for the 

 loading district concerned. 

 - Maximum conductor temperature for which the line is designed to operate, with no horizontal 

 displacement 

Nominal Voltage, Phase to Phase (kVLL) 34.5 

& 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 (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 4-7

TABLE 4-1 

(continued from previous page) 

RECOMMENDED DESIGN VERTICAL CLEARANCE OF CONDUCTORS ABOVE 

 GROUND, ROADWAYS, RAILS, OR WATER SURFACE (in feet) (See Notes A, F & G) 

(Applicable NESC Rules 232A, 232B, and Table 232-1 

Notes: 

(A) For voltages exceeding 98 kV alternating current to ground, or 139 kV direct current to ground, the NESC states 

that either the clearance shall be increased or the electric field, or the effects thereof, shall be reduced by other 

means, as required, to limit the current due to electrostatic effects to 5.0 milliampere (mA), rms, if the largest 

anticipated truck, vehicle or equipment under the line were short circuited to ground. The size of the anticipated 

truck, vehicle, or equipment used to determine these clearances may be less than but need not be greater than that 

limited by Federal, State, or local regulations governing the area under the line. For this determination, the 

conductors shall be at final unloaded sag at 120° F. 

Fences and large permanent metallic structures in the vicinity of the line will be grounded in accordance with the 

owner’s grounding units for the structure concerned to meet the 5.0 milliampere requirement. There should be 

adequate ground clearance at crossings and along the right-of-way to meet the minimum requirement of 5 mA due to 

the electrostatic field effects on the anticipated vehicles under the transmission line. 

Consideration should be given to using the 5.0 mA rule to the conductor under maximum sag condition of the 

conductor. 

(B) These clearances are for land traversed by vehicles and equipment whose overall operating height is less than 

14 feet. 

(C) Areas accessible to pedestrians only are areas where riders on horses or other large animals, vehicles or other 

mobile units exceeding 8 feet in height are prohibited by regulation or permanent terrain configurations or are not 

normally encountered nor reasonably anticipated. Land subject to highway right-of-way maintenance equipment is 

not to be considered as being accessible to pedestrians only. 

(D) The NESC states that “for uncontrolled water flow areas, the surface area shall be that enclosed by its annual 

high-water mark. Clearances shall be based on the normal flood level; if available, the 10 year flood level may be 

assumed as the normal flood level. The clearance over rivers, streams, and canals shall be based upon the largest 

surface area of any one mile-long segment which includes the crossing. The clearance over a canal, river, or stream 

normally used to provide access for sailboats to a larger body of water shall be the same as that required for the 

larger body of water.” 

(E) Where the U.S. Army Corps of Engineers or the state, has issued a crossing permit, the clearances of that permit 

shall govern. 

(F) The NESC basic clearance is defined as the reference height plus the electrical component for open supply 

conductors up to 22 kVL-G. 

(G) An additional 2.5 feet of clearance is added to the NESC clearance to obtain the recommended design 

clearances. Greater values should be used where survey methods to develop the ground profile are subject to 

greater unknowns. See Chapter 10, paragraph 10.3 of this bulletin. 
Bulletin 1724E-200 

Page 4-8 

TABLE 4-2 

RECOMMENDED DESIGN VERTICAL CLEARANCES FROM OTHER SUPPORTING 

STRUCTURES (See Note B), BUILDINGS AND OTHER INSTALLATIONS (in feet) 

(Applicable NESC Rules: 234A, 234B, 234C, 234D, 234E, 234F, 234I, Tables 234-1, 234-2, 234-3) 

Line conditions under which the NESC vertical clearances shall be met (Calculations are based on 

Maximum Operating Voltage.): 

• 32°F, no wind, with radial thickness of ice, if any, specified in Rule 250B of the NESC for the loading 

district concerned.

• Maximum conductor temperature for which the line is designed to operate, with no horizontal displacement

Nominal Voltage, Phase to Phase (kVLL) 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 accessible to truck 

 traffic 

18.5 20.7 21.2 22.1 22.6 23.0 24.4 

 

5.0 From signs, chimneys, billboards, radio & TV 

 antennas, tanks & other installations 

 not accessible to personnel. 

8.0 10.2 10.7 11.6 12.1 12.5 13.9 

 

6.0 From bridges – not attached (Note C ) 12.5 14.7 15.2 16.1 16.6 17.0 18.4 

 

7.0 From grain bins probe ports 18.0 20.2 20.7 21.6 22.1 22.5 23.9 

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, or a supporting structure of another 

line. 

(C) If the line crosses a roadway, then Table 4-1, line 2.0 clearances are required. 

(D) The NESC basic clearance is defined as the reference height plus the electrical component for open supply 

conductors up to 22 kVLG except row ‘1.0’ where voltage referenc is 50 kVLG

(E) For 230 kV, clearances may be required to be higher if switching surges are greater than 2.0 per unit. See NESC 

Tables 234-4 and 234-5. 
Bulletin 1724E-200

Page 4-9

4.4.5 Examples of Clearance Calculations: The following examples demonstrate the 

derivation of the vertical clearances shown in Tables 4-1 and 4-2. 

To determine the vertical clearance of a 161 kV line crossing a road (category 2.0 of Table 4-1), 

the clearance is based on NESC Table 232-1 and NESC Rule 232. 

NESC Vertical Clearance = NESC Basic Clearance(Table 232-1) + .4(kVL-G – 22)/12 

 = 18.5 feet + .4(97.6-22)/12 feet 

 = 18.5 feet + 2.52 feet 

NESC Vertical Clearance = 21.02 feet 

Recommended Clearance = NESC Vertical Clearance + Agency Adder 

 = 21.02 feet + 2.5 feet 

 = 23.52 feet (23.5 feet in Table 4-1) 

To determine the vertical clearance of a 230 kV line over a building roof not accessible to 

pedestrians (category 2.0 of Table 4-2), the clearance is based on NESC Table 234-1 and NESC 

Rule 234. 

NESC Vertical Clearance = NESC Basic Clearance(Table 234-1) + .4(kVL-G – 22)/12 

 = 12.5 feet + .4(139-22)/12 feet 

 = 12.5 feet + 3.9 feet 

NESC Vertical Clearance = 16.4 feet 

Recommended Clearance = NESC Vertical Clearance + Agency Adder 

 = 16.4 feet + 2.0 feet 

 = 18.4 feet (18.4 feet in Table 4-2) 

4.5 Design Vertical Clearance Between Conductors Where One Line Crosses Over or 

Under Another: Recommended design vertical clearances between conductors when one line 

crosses another are provided in Table 4-3. The clearance values in Table 4-3 are for 

transmission lines which are known to have ground fault relaying. The clearances should be 

maintained at the point where the conductors cross, regardless of where the point of crossing is 

located on the span. 

4.5.1 Conditions Under Which Clearances Apply: The clearances apply for an upper 

conductor at final sag for the conditions ‘a’ through ‘c’. The condition that produces the greatest 

sag for the line is the one that applies. 

a. A conductor temperature of 32°F, no wind, with a radial thickness of ice for the loading 

district concerned. 

b. A conductor temperature of 167°F. A lower temperature may be considered where justified 

by a qualified engineering study. Under no circumstances should a design temperature be less 

than 120°F. 

c. Maximum conductor temperature, no wind. See paragraph 4.3.1. The same maximum 

temperature used for vertical clearance to ground should be used. 
Bulletin 1724E-200 

Page 4-10 

At a minimum the NESC requires that (1) the upper and lower conductors are simultaneously 

subjected to the same ambient air temperature and wind loading conditions and (2) each is 

subjected individually to the full range of its icing conditions and applicable design electrical 

loading. 

4.5.2 Altitude Greater than 3300 Feet: If the altitude of the crossing point of the two lines is 

greater than 3300 feet, additional clearance as indicated in Table 4-3 is added to the base 

clearance given. 

4.5.3 Differences in Sag Conditions Between Lower and Upper Conductors: The reason for 

the differences in sag conditions between the upper and lower conductor at which the clearances 

apply is to cover situations where the lower conductor has lost its ice while the upper conductor 

has not, or where the upper conductor is loaded to its thermal limit while the lower conductor is 

only lightly loaded. 

4.5.4 Examples of Clearance Calculations: The following example demonstrates the 

derivation of the vertical clearance of a category in Tables 4-3 of this bulletin. 

To determine the vertical clearance of a 161 kV line crossing a distribution conductor (item 3 of 

Table 4-3), the clearance is based on NESC Table 233-1 and NESC Rule 233. 

NESC Vertical Clearance= NESC Basic Clearance(Table 233-1) + .4(kVL-G – 22)/12 

 = 2.0 feet + .4(97.6-22)/12 feet 

 = 2.0 feet + 2.5 feet 

NESC Vertical Clearance = 4.5 feet 

Recommended Clearance = NESC Vertical Clearance + Agency Adder 

 = 4.5 feet + 1.5 feet 

 = 6.0 feet (6.0 feet in Table 4-3) 

4.6 Design Vertical Clearance Between Conductors of Different Lines at Noncrossing 

Situations: If the horizontal separation between conductors as set forth in Chapter 5 cannot be 

achieved, then the clearance requirements in section 4.5 should be attained. 

4.7 Example of Line-to-Ground Clearance: A portion of a 161 kV line is to be built over a 

field of oats that is at an elevation of 7200 feet. Determine the design line-to-ground clearance. 

4.7.1 Solution of the Additional Clearance for Altitude: Because the altitude of the 161 kV 

line is greater than 3300 feet, the basic clearance is to be increased by the amount indicated in 

Table 4-1. The calculation follows: 

(7200-3300)(.08)/1000 = 0.32 feet 
Bulletin 1724E-200

Page 4-11

4.7.2 Total Clearance: Assuming the line meets the assumptions given in section 4.2 and 

Table 4-1, the recommended design clearance over cultivated fields for a 161 kV line is 

23.5 feet. Therefore, the recommended clearance, taking altitude into account, is 23.8 feet. 

0.32 feet + 23.5 feet = 23.8 feet 

An additional one foot of clearance should be added for survey, construction and design 

tolerance. 

4.8 Example of Conductor Crossing Clearances: A 230 kV line crosses over a 115 kV line in 

two locations. At one location the 115 kV line has an overhead ground wire which, at the point 

of crossing, is 10 feet above its phase conductors. At the other location the lower voltage line 

does not have an overhead ground wire. Determine the required clearance between the 230 kV 

conductors and the 115 kV conductors at both crossing locations. Assume that the altitude of the 

line is below 3300 feet. Also assume that the sag of the overhead ground wire is the same as or 

less than the sag of the 115 kV phase conductors. The 230 kV line has ground fault relaying. 

Solution: The first step in the solution is to determine if the line being crossed over has 

automatic ground fault relaying. We are able to determine that the lower line has automatic 

ground fault relaying. 

From Table 4-3, (item 4), the required clearance from a 230 kV conductor to a 115 kV conductor 

is 9.0 feet. From Table 4-3, (item 2), the required clearance from the 230 kV conductor to the 

overhead ground wire is 7.4 feet; adding 10 feet for the distance between the overhead ground 

wire (OHGW) and the 115 kV phase conductors, the total required clearance is 17.4 feet. 

When the lower circuit has an overhead ground wire, clearance requirements to the overhead 

ground wire govern and the required clearance between the upper and lower phase conductor is 

17.4 feet. 

Where there is no overhead ground wire for the 115 kV circuit, the required clearance between 

the phase conductors is 9.0 feet. 

It is important to note that the above clearances are to be maintained where the upper conductor 

is at its maximum sag condition, as defined in section 4.5.1b or 4.5.1c above, and the lower 

conductor is at 60°F initial sag. 

4.9 Vertical Clearances to Vegetation: The best practice is usually to remove all substantive 

vegetation (such as trees and vines) under and adjacent to the line. In certain areas, such as 

canyons, river crossings, or endangered species habitat, vegetation can be spanned. For vertical 

clearances (intended to meet NERC FAC 003), refer to radial clearances discussed in Section 

5.2.2 of this bulletin. 
Bulletin 1724E-200 

Page 4-12 

TABLE 4-3 

RECOMMENDED DESIGN VERTICAL CLEARANCES IN FEET 

BETWEEN CONDUCTORS WHERE THE CONDUCTORS OF ONE LINE 

CROSS OVER THE CONDUCTORS OF ANOTHER AND WHERE THE UPPER AND 

LOWER CONDUCTORS HAVE GROUND FAULT RELAYING 

Voltage between circuits = Voltage line to ground Top Circuit + Voltage line to ground Bottom Circuit (Calculations are 

based on the maximum operating voltage.) 

The NESC requires that clearances not be less than that required by application of a clearance envelope developed 

under NESC Rules 233A1 & 233A2. Structure deflection shall also be taken into account. Agency recommended 

values in this table are to be adders applied for the movement of the conductor and deflection of structures, if any. 

UPPER LEVEL CONDUCTOR (Note F) 

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 4-13

TABLE 4-3 (continued) 

RECOMMENDED DESIGN VERTICAL CLEARANCES IN FEET 

BETWEEN CONDUCTORS WHERE THE CONDUCTORS OF ONE LINE 

CROSS OVER THE CONDUCTORS OF ANOTHER AND WHERE THE UPPER AND 

LOWER CONDUCTORS HAVE GROUND FAULT RELAYING 

(D) An additional 1.5 feet of clearance is added to NESC clearance to obtain the recommended design clearances. 

Greater values should be used where the survey method used to develop the ground profile is subject to greater 

unknowns. 

(E) ALTITUDE CORRECTION TO BE ADDED TO VALUES ABOVE

Total altitude = Correction for + Correction 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 4-14 

Blank Page
Bulletin 1724E-200 

Page 5-1 

5. HORIZONTAL CLEARANCES FROM LINE CONDUCTORS TO OBJECTS AND

RIGHT-OF-WAY WIDTH

5.1 General: The preliminary comments and assumptions in Chapter 4 of this bulletin also 

apply to this chapter. 

5.2 Minimum Horizontal Clearance of Conductor to Objects: Recommended design 

horizontal clearances of conductors to various objects are provided in Table 5-1 and minimum 

radial operating clearances of conductors to vegetation in Table 5-2. The clearances apply only 

for lines that are capable of automatically clearing line-to-ground faults. 

Clearance values provided in Table 5-1are recommended design values. In order to provide an 

additional margin of safety, the recommended design values exceed the minimum clearances in 

the 2007 NESC. Clearance values provided in Table 5-2 are minimum operating clearances to be 

used by the designer to determine appropriate design clearances for vegetation maintenance 

management. 

5.2.1 Conditions Under Which Horizontal Clearances to Other Supporting Structures, 

Buildings and Other Installations Apply: 

Conductors at Rest (No Wind Displacement): When conductors are at rest the clearances apply 

for the following conditions: (a) 167°F but not less than 120°F, final sag, (b) the maximum 

operating temperature the line is designed to operate, final sag, (c) 32°F, final sag with radial 

thickness of ice for the loading district (0 in., 1⁄4 in., or 1⁄2 in.). 

Conductors Displaced by 6 psf Wind: The clearances apply when the conductor is displaced by 

6 lbs. per sq. ft. at final sag at 60°F. See Figure 5-1. 

 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 4.4.3 of 

 Chapter 4 and item 9 of Table 4–2. 

 (NESC Rule 234E) 

 

Clearance in any direction from swimming 

 pool edge (Clearance A, Figure 4-2 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 4-2 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 ‘V’ of highest filling or probing port on bin 

must be added to clearance shown. Clearances for ‘at 

rest’ and not displaced by the wind. See NESC 

Figure 234-4 for other requirements. 

 

Horizontal clearance envelope (includes area of 

sloped clearance per NESC Figure 234-4b) (24+V) + 1.5V (Note 3) 

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. “V” is the height of the highest filling or probing port on a grain bin. Clearance is for the highest voltage of 230 kV.
Bulletin 1724E-200 

Page 5-4 

5.2.2 Considerations in Establishing Radial and Horizontal Clearances to Vegetation: 

The designer should identify and document clearances between vegetation and any overhead, 

ungrounded supply conductors, taking into consideration transmission line voltage, the effects of 

ambient temperature on conductor sag under maximum design loading, and the effects of wind 

velocities on conductor sway. Specifically, the designer should establish clearances to be 

achieved at the time of vegetation management work and should also establish and maintain a set 

of clearances to prevent flashover between vegetation and overhead ungrounded supply 

conductors. As a mimimum, these clearances should apply to all transmission lines operated at 

200 kV phase-to-phase and above and to any lower voltage lines designated as critical (refer to 

NERC FAC 003). 

The designer should determine and document appropriate clearance distances to be achieved at 

the time of transmission vegetation management work based upon local conditions and the 

expected time frame in which the Transmission Owner plans to return for future vegetation 

management work. Local conditions may include, but are not limited to: operating voltage, 

appropriate vegetation management techniques, fire risk, reasonably anticipated tree and 

conductor movement, species types and growth rates, species failure characteristics, local 

climate and rainfall patterns, line terrain and elevation, location of the vegetation within the 

span, and worker approach distance requirements. 

The designer should determine and document specific radial clearances to be maintained 

between vegetation and conductors under all rated electrical operating conditions. These 

minimum clearance distances are necessary to prevent flashover between vegetation and 

conductors and will vary due to such factors as altitude and operating voltage. These specific 

minimum clearance distances should be no less than those set forth in the Institute of Electrical 

and Electronics Engineers (IEEE) Standard 516-2003 (Guide for Maintenance Methods on 

Energized Power Lines) and as specified in its Section 4.2.2.3, Minimum Air Insulation 

Distances without Tools in the Air Gap. Where transmission system transient overvoltage factors 

are not known, clearances shall be derived from Table 5, IEEE 516-2003, phase-to-ground 

distances, with appropriate altitude correction factors applied.Where transmission system 

transient overvoltage factors are known, clearances shall be derived from Table 7, IEEE 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. 

FIGURE 5-2: RADIAL CLEARANCE REQUIREMENT TO VEGETATION 

yv

Ø

Sf

xv

i
Bulletin 1724E-200 

Page 5-5 

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 

TABLE 5-2 

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

DETERMINING CLEARANCES TO VEGETATION FROM CONDUCTORS 

(NERC Standard FAC-003.1 Transmission Vegetation Management Program, IEEE 516, 

Guideline For Maintenance Methods Of Energized Power Lines) 

Conditions under which clearances apply: 

Displaced by Wind: Radial operating clearances are to be applied at all rated operating conditions.The designer should 

determine applicable conductor temperature and wind conditions for all rated operating conditions. The displacement of the 

conductor is to include deflection of suspension insulators and deflection of flexible structures. 

The operating clearances shown are for the displaced conductors and do not provide for the horizontal distance required to 

account for blowout of the conductor and the insulator string. This distance is to be added to the required clearance. See 

Equation 5-1. 

Clearances are based on the Maximum Operating Voltage. 

Nominal voltage, Phase to Phase, kVL-L 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 5-6 

5.2.3 Clearances to Grain Bins: The NESC has defined clearances from grain bins based on 

grain bins that are loaded by permanent or by portable augers, conveyers, or elevator systems. 

In NESC Figure 234-4(a), the horizontal clearance envelope for permanent loading equipment is 

graphically displayed and shown Figure 5-2. 

P = probe clearance, item 7, Table 4-2 

H = horizontal clearance, item 7, Table 5-1 

T = transition clearance 

V1 = vertical clearance, item 2&3, 

Table 4-2 

V2 = vertical clearance, Table 4-1 

FIGURE 5-3: CLEARANCE TO 

GRAIN BINS 

NESC FIGURE 234-4a 

From IEEE/ANSI C2-2007, National Electrical Safety Code, Copyright 2006. All rights reserved. 

Because the vertical distance from the probe in Table 4-2, item 7.0, is greater than the horizontal 

distance, (see Table 5-1, item 7.0), the user may want to simplify design and use this distance as 

the horizontal clearance distance as shown below: 

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

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

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

or Table 5-2
Bulletin 1724E-200 

Page 5-7 

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/ANSI C2-2007, National Electrical Safety Code, Copyright 2006. All rights reserved. 

In order to simplify the clearance envelope, the horizontal clearances in category 8 of Table 5-1 

is shown as ‘H’ in the drawing below: 

FIGURE 5-7: SIMPLIFIED RECOMMENDATIONS FOR CLEARANCES 

TO GRAIN BINS WITH PORTABLE LOADING EQUIPMENT 

5.2.4 Altitude Greater Than 3300 Feet: If the altitude of the transmission line or portion 

thereof is greater than 3300 feet, an additional clearance as indicated in Table 5-1 and 5-2 has to 

be added to the base clearance given. 

See NESC Rule 232 

V=Height of highest filling or probing port on grain bin

H=V- 18'

See NESC Rule 232 

1

H

18'

V

1.5

15'

H

NESC 

RULE 232 

AREA

LOADING 

SIDE

Flat top of 

clearance 

envelope

1.5:1 

slope

NON-LOADING 

SIDE

1.5:1 

slope

1.5:1 

slope

1.5:1 

slope

AREA OF SLOPED 

CLEARANCE

1.5

15' 

1.5:1 

slope

1

15'

LOADING SIDE NON-LOADING

No Overhead

Lines

H
Bulletin 1724E-200 

Page 5-8 

5.2.5 Total Horizontal Clearance to Point of Insulator Suspension to Object: As can be 

seen from Figure 5-1, the total horizontal clearance (y) is: 

y = (l i + S f )sinφ + x + δ Eq. 5-1

Symbols are defined in Section 5.2.1 and figure 5-1. The factor "δ" indicates that structure 

deflection should be taken into account. 

For the sake of simplicity when determining horizontal clearances, the insulator string should be 

assumed to have the same swing angle as the conductor. This assumption should be made only 

in this chapter as its use in calculations elsewhere may not be appropriate. 

The conductor swing angle (φ ) under wind can be determined from the formula. 

( )( )

⎟

⎟

⎠

⎞

⎜

⎜

⎝

⎛ = −

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 5-7. 

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 5-9 

5.2.6 Examples of Horizontal Clearance Calculations: The following examples demonstrate 

the derivation of the horizontal clearance in Table 5-1 of this bulletin. 

To determine the horizontal clearance of a 115 kV line to a building (category 2.0 of Table 5-1), 

the clearance is based on NESC Table 234-1 and NESC Rule 234. 

At rest: 

NESC Horizontal Clear. = NESC 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) 

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

environment allows the line to be operated and maintained safely and reliably. Determination of 

the right-of-way width is a task that requires the consideration of a variety of judgmental, 

technical, and economic factors. 

Typical right-of-way widths (predominantly H-frames) that have been used by agency borrowers 

in the past are shown in Table 5-2. In many cases a range of widths is provided. The actual 

width used will depend upon the particulars of the line design. 

TABLE 5-3 

TYPICAL RIGHT-OF-WAY WIDTHS 

Nominal Line-to-Line Voltage in kV 

69 115 138 161 230 

ROW Width, ft. 75-100 100 100-150 100-150 125-200 

5.4 Calculation of Right-of-Way Width for a Single Line of Structures on a Right-of-Way: Right-of-way widths can be calculated using the method described below. The calculated values 

for right-of-way widths are directly related to the particular parameters of the line design. This 

method provides sufficient width to meet clearance requirements to buildings of undetermined 

height or vegetation located directly on the edge of the right-of-way. See Figures 5-8 and 5-9. 
Bulletin 1724E-200 

Page 5-10 

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

W A ( S )sin x = + 2 li + f φ + 2δ + 2 Eq. 5-3

where: 

W = total right-of-way width required 

A = separation between points of suspension of insulator 

strings for outer two phases 

x = clearance required per Table 5-1 and appropriate 

clearance derived from Table 5-2 of this bulletin 

(include altitude correction if necessary) 

y = clearance required per Section 5.2.1 and Table 5-1 and 

appropriate clearance derived from Section 5.2.2. and 

Table 5-2 of this bulletin (include altitude correction if 

necessary) 

Other symbols are as previously defined. In some instances, clearance “x” 

may control. In other instances, clearance “y” may control. 

There are two ways of choosing the length (and thus the sag) on which the right-of-way width is 

based. One is to use a width based on the maximum span length in the line. The other way is to 

base the width on a relatively long span, (the ruling span, for instance), but not the longest span. 

For those spans that exceed this base span, additional width is added as appropriate. 

5.5 Right-of-Way Width for a Line Directly Next to a Road: The right-of-way width for a 

line next to a road can be calculated based on the two previous sections with one exception. No 

ROW is needed on the road side of the line as long as the appropriate clearances to existing or 

possible future structures on the road side of the line are met. 

If a line is to be placed next to a roadway, consideration should be given to the possibility that 

the road may be widened. If the line is on the road right-of-way, the borrower would generally 

be expected to pay for moving the line. If the right-of-way is on private land, the highway 

W

A y

x

Ø

i

S

f
Bulletin 1724E-200 

Page 5-11 

department should pay. Considerations involved in placing a line on a road right-of-way should 

also include evaluation of local ordinances and requirements. 

5.6 Right-of-Way Width for Two or More Lines of Structures on a Single Right-of-Way: To determine the right-of-way width when the right ROW contains two parallel lines, start by 

calculating the distance from the outside phases of the lines to the ROW edge (see Section 5.4). 

The distance between the two lines is governed by the two criteria provided in section 5.6.1. If 

one of the lines involved is an extra high voltage (EHV) line (345 kV and above), the NESC 

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

5.6.1 Separation Between Lines as Dictated by Minimum Clearance Between Conductors 

Carried on Different Supports: The horizontal clearance between a phase conductor of one 

line to a phase conductor of another line shall meet the larger of C1, or C2 below, under the 

following conditions: (a) both phase conductors displaced by a 6 psf wind at 60°F, final sag; (b) 

if insulators are free to swing, one should be assumed to be displaced by a 6 lbs/sq. ft. wind 

while the other should be assumed to be unaffected by the wind (see Figure 5-10). The assumed 

wind direction should be that which results in the greatest separation requirement. It should be 

noted that in the Equations 5-5, and 5-6, the ‘δ1-δ2’ term, (the differential structure deflection 

between the two lines of structures involved), is to be taken into account. An additional 1.5 feet 

have been added to the NESC clearance to obtain design clearances ‘C1’and ‘C2’. Note Equation 

5-6 has been revised from previous versions due to the voltage adder change in the 2007 NESC 

edition. 

( ) 1 21 C 5.6 δ −+= δ (NESC Rule 233B1) Eq. 5-5

[ ] ( ) ( ) 2 1 2 22 21 12

4. C 5.6 += LG kVkV LG −+−+ δδ (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 

FIGURE 5-10: CLEARANCE BETWEEN CONDUCTORS OF ONE LINE 

TO CONDUCTOR OF ANOTHER LINE 

C1 2 ,C

δ

1 δ2
Bulletin 1724E-200 

Page 5-12 

5.6.2 Separation Between Lines as Dictated by Minimum Clearance of Conductors From 

One Line to the Supporting Structure of Another: The horizontal clearance of a phase 

conductor of one line to the supporting structure of another when the conductor and insulator are 

displaced by a 6 psf wind at 60°F final sag should meet Equation 5-7. 

( )( ) 3 22 1 2 12

.4 C = 6'+ kVLG − + δ −δ Eq. 5-7

where: 

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

C3 = the clearance of conductors of one line to structure of 

another in feet 

Other symbols are defined in Figure 5-1. 

Additional 1.5 feet have been added to the NESC clearance and included in equation 5-7 to 

obtain the design clearance ‘C3’. . 

FIGURE 5-11: CLEARANCE BETWEEN CONDUCTORS OF ONE LINE 

AND STRUCTURE OF ANOTHER 

The separation between lines will depend upon the spans and sags of the lines as well as how 

structures of one line match up with structures of another. In order to avoid the unreasonable 

task of determining separation of structures span-by-span, a standard separation value should be 

used, based on a worst case analysis. Thus if structures of one line do not always line up with 

those of the other, the separation determined in section 5.6.2 should be based on the assumption 

that the structure of one line is located next to the mid-span point of the line that has the most 

sag. 

5.6.3 Other Factors: Galloping should be taken into account in determining line separation. In 

fact, it may be the determining factor in line separation. See Chapter 6 for a discussion of 

galloping. 

C3

δ

1 δ2
Bulletin 1724E-200 

Page 5-13 

Standard phase spacing should also be taken into account. For example, if two lines of the same 

voltage using the same type structures and phase conductors are on a single ROW, a logical 

separation of the two closest phases of the two lines should be at least the standard phase 

separation of the structure. 

5.6.4 Altitude Greater than 3300 Feet: If the altitude at which the lines included in the design 

are installed greater than 3300 feet, NESC Section 23 rules provide additional separation 

requirements. 
Bulletin 1724E-200 

Page 5-14 

BLANK PAGE 
Bulletin 1724E-200 

Page 6-1

6. CLEARANCES BETWEEN CONDUCTORS AND BETWEEN CONDUCTORS AND 

OVERHEAD GROUND WIRES

6.1 General: The preliminary comments and assumptions of Chapter 4, section 4.2, also apply 

to this chapter. 

This chapter considers design limits related to conductor separation. It is assumed that only 

standard agency structures will be used, thus making it unnecessary to check conductor 

separation at structures. Therefore, the only separation values left to consider are those related to 

span length and conductor sags. 

Maximum span lengths may be controlled by conductor separation. Other factors which may 

limit span length, but are not covered in this chapter, are structure strength, insulator strength, 

and ground clearance. 

6.2 Maximum Span as Limited by Horizontal Conductor Separation: Sufficient horizontal 

separation between phases is necessary to prevent swinging contacts and flashovers between 

conductors where there is insufficient vertical separation. 

6.2.1 Situations Under Which Maximum Span as Limited by Horizontal Separation are to 

be Met:

If the vertical separation 

(regardless of horizontal 

displacement) of phase 

conductors of the same or 

different circuit(s) at the 

structure is less than the 

appropriate values provided in 

Table 6-1,then the 

recommendations in sections 

6.2.2, 6.2.3, and 6.2.4 of this 

section should be met. 

FIGURE 6-1: EXAMPLE OF VERTICAL AND HORIZONTAL 

SEPARATION VALUES 

6.2.2 Horizontal Separation Recommendations: Equation 6-1 gives an horizontal phase 

spacing (relative to conductor sag, and thus indirectly to span length) that should be sufficient to 

prevent swinging contacts or flashovers between phases of the same or different circuits. 

( ) ( ) max H = 025.0 SFkV ++ lifc 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-toground voltage in 1000's of volts of the higher voltage circuit 

involved regardless of how the voltage vectors add up. The 

voltage between the phases should be taken as the sum of the 

two line-to-ground voltages, based on 1.05 times nominal 

voltage. 

Fc = experience factor 

Ømax = maximum 6 psf insulator swing angle for the structure in 

question. See Chapter 7 of this bulletin. 

Sf = final sag of the conductor at 60°F, no load, in feet 

i l = length of the insulator string in feet, i l = 0 for post or 

restrained suspension insulators 

V = vertical separation between phase conductors 

at the structure in feet 

The experience factor (Fc) may vary from a minimum of 0.67 to a maximum of 1.4, depending 

upon how severe the wind and ice conditions are judged to be. The following are values of Fc

that have proved to be satisfactory in the past. 

Fc = 1.15 for the light loading zone 

Fc = 1.2 for the medium loading zone 

Fc = 1.25 for the heavy loading zone 

Any value of Fc in the 0.67 to 1.4 range may be used if it is thought to be reasonable and 

prudent. There has been significant favorable experience with larger conductor sizes that have 

horizontal spacing based on an Fc factor of 0.67. Therefore, Fc factor values significantly less 

than the values listed above may be appropriate. If Fc values less than those given above are 

used, careful attention should be paid to galloping as a possible limiting condition on the 

maximum span length. 
Bulletin 1724E-200 

Page 6-3

TABLE 6-1 

RECOMMENDED VERTICAL SEPARATION IN FEET BETWEEN PHASES 

OF THE SAME OR DIFFERENT CIRCUITS ATTACHED TO THE SAME STRUCTURE 

(For separations less than those shown, Equation 6-1 applies) (See Notes E & F) 

Nominal voltage, Line-to-Line Voltage in kV 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), 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 

1.5 2.1 3.0 3.6 4.0 5.4 

ALTITUDE CORRECTION TO BE ADDED TO VALUES IN CATEGORY ‘2’ ABOVE (NONE 

REQUIRED FOR CATEGORY ‘1’): 

Additional feet of clearance per 1000 feet of 

altitude above 3300 feet 

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

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 ( ) LG kVkV LG ( ) NoteD

12

6 7.8

12

4.

12

40

+= 1 2 +−+ Eq. 6-2 

where: 

LG1 kV = Line to ground voltage circuit one, kilovolts. 

LG2 kV = Line to ground voltage circuit two, kilovolts. 
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 ( ) LG kVkV LG ( ) NoteD

12

6 50

12

4. )7.850( 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 6.3 of this bulletin. 

6.2.3 Additional Horizontal Separation Equation: Equation 6-3 below, commonly known as 

the Percy Thomas formula, may be used in addition to (but not instead of) equation 6-1 for 

determining the horizontal separation between the phases at the structure. Equation 6-3 takes 

into account the weight, diameter, sag, and span length of the conductor. 

( ) ( )( )( )

2

025. i

c

pcc

w

SdE

H kV l = + + Eq. 6-3

where: 

dc = conductor diameter in inches 

wc = weight of conductor in lbs/ft. 

Ec = an experience factor. It is generally recommended that (Ec) 

be larger than 1.25. 

Sp = sag of conductor at 60°F, expressed as a percent of span 

length 

All other symbols are as previously defined. 

By using the Thomas formula to determine values of Ec, the spacing of conductors on lines 

which have operated successfully in a locality can be examined. These values of Ec may be 

helpful in determining other safe spacings. 

6.2.4 Maximum Span Based on Horizontal Separation at the Structure: Equation 6-1 can 

be rewritten and combined with Equation 10-1 (Chapter 10) to yield the maximum allowable 
Bulletin 1724E-200 

Page 6-5

span, given the horizontal separation at the structure and the sag and length of the ruling span. 

See Chapter 9 for a discussion of ruling span. 

( ) ( ) ⎟

⎟

⎠

⎞

⎜

⎜

⎝

⎛ −− =

RSc

i

SF

H kV RSL max

max

025. l 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. 

6.2.5 Maximum Span Based on Vertical Separation: Since vertical separation is related to 

the relative sags of the phase conductors involved, and since sags are related to span length, a 

maximum span as limited by vertical separation can be determined. The formula for the 

maximum span as limited by vertical separation is: 

( ) u

v

SS

BD RSL −

− =

l

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 

 

6.2.6 Example of Clearance Calculations: The following example demonstrates the derivation 

of the vertical separation at a support for phases of different circuits in Tables 6-1 of this bulletin. 

To determine the vertical separation of a 115 kV line to another 115 kV circuit, the clearance is 

based on NESC Table 235-5 and NESC Rule 235. 

At the support, phases of different circuits: 

NESC Vertical Separation = 40 inches/12 in./ft + .4(kVL-G + kVL-G – 8.7)/12 ft. 

 = 3.333 ft. + .4(69.7+69.7-8.7)/12 ft. 

 = 3.33 ft.+ 4.36 ft. 

NESC Vertical Separation = 7.69 feet 

Recommended 

Vertical Separation = NESC Vertical Separation + suggested Adder 

 = 7.69 feet + 0.5 feet 

 = 8.19 feet (8.2 feet in Table 6-1) 
Bulletin 1724E-200 

Page 6-6 

In the span, phases of different circuits: 

NESC Vertical Separation ( ) 50

12

4. )7.850( 12

4.

12

40 75.0 + 1 2 −+ ⎥

⎦

⎤ ⎢

⎣

⎡ −+= LG LG kVkV

 = 0.75(3.33+1.37) ft + (.4/12)(69.7+69.7-50) feet 

 = 3.53 ft. + 2.98 feet 

NESC Vertical 

Separation in the Span = 6.51 feet 

Recommended 

Clearance = NESC Vertical Separation + suggested Adder 

 = 6.51 feet + .5 feet 

 = 7.01 feet (7.0 feet in Table 6-1) 

6.3 Maximum Span as Limited by Conductor Separation Under Differential Ice Loading 

Conditions

6.3.1 General: There is a tendency among conductors covered with ice, for the conductor 

closest to the ground to drop its ice first. Upon unloading its ice the lower conductor may jump 

up toward the upper conductor, possibly resulting in a temporary short circuit. After the lower 

conductor recovers from its initial ice-jump it may settle into a position with less sag than before, 

which may persist for long periods of time. If the upper conductor has not dropped its ice, the 

reduced separation may result in a flashover between phases. 

The clearance recommendations provided in paragraph 6.3.2 of this section are intended to 

insure that sufficient separation will be maintained during differential ice loading conditions with 

an approach towards providing clearance for the ice-jump. 

6.3.2 Clearance Recommendations: The minimum vertical distance (Dv) in span between 

phase conductors, and between phase conductors and overhead ground wires under differential 

ice loading conditions, are provided in Table 6-1. These vertical separations in span are 

recommended in cases where the horizontal separation between conductors (H) is greater than 

one foot (H ≥1.0 ft). When conductors or wires are directly over one another or have less than a 

1 foot horizontal offset, it is recommended that an additional 2 feet of clearance be added to the 

values given in Table 6-1. The purpose of this requirement is to improve the performance of the 

line under ice-jump conditions. It has been found that a horizontal offset of as little as 1 foot 

significantly lessens the ice-jump problem. Figure 6-4 indicates the horizontal and vertical 

components of clearance and their relationship. 

FIGURE 6-2: MINIMUM DISTANCE BETWEEN CONDUCTORS 

Lower conductor at 32° F, 

final sag, no ice.

Upper conductor at 32° F 

final sag, maximum ice

H

v D

Upper conductor at 32oF, final sag, 

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

Page 6-7

6.3.3 Conditions Under Which Clearances Apply: Lines should be designed so that 

clearances are considered with the upper conductor at 32°F, final sag, and a radial thickness of 

ice equal to the ice thickness from either the medium loading district or the heavy loading 

district. The lower conductor should be at 32°F, final sag, no ice. The designer is reminded to 

check clearances for the upper conductor at the maximum operating temperature (no wind) and 

the lower conductor at ambient temperature (see Note F of Table 6-1). 

6.4 Overhead Ground Wire Sags and Clearances: In addition to checking clearances 

between the overhead ground wire (OHGW) and phase conductors under differential ice loading 

conditions, it is also important that the relative sags of the phase conductors and the OHGW be 

coordinated so that under more commonly occurring conditions, there will be a reasonably low 

chance of a mid-span flashover. Adequate midspan separation is usually assured for standard 

agency structures by keeping the sag of the OHGW at 60°F initial sag, no load conditions to 

80 percent of the phase conductors under the same conditions. 

6.5 Maximum Span as Limited by Galloping

6.5.1 The Galloping Phenomenon: Galloping, sometimes called dancing, is a phenomenon 

where the transmission line conductors vibrate with very large amplitudes. This movement of 

conductors may result in: (1) contact between phase conductors or between phase conductors 

and overhead ground wires, resulting in electrical outages and conductor burning, (2) conductor 

failure at support point due to the violent stress caused by galloping, (3) possible structure 

damage, and (4) excessive conductor sag due to the overstressing of conductors. 

Galloping usually occurs only when a steady, moderate wind blows over a conductor covered by 

a layer of ice deposited by freezing rain, mist or sleet. The coating may vary from a very thin 

glaze on one side to a solid three-inch cover and may give the conductor a slightly out-of-round, 

elliptical, or quasi-airfoil shape. The wind blowing over this irregular shape results in 

aerodynamic lift which causes the conductor to gallop. The driving wind can be anything 

between 5 to 45 miles per hour at an angle to the line of 10 to 90 degrees and may be unsteady in 

velocity or direction. 

During galloping, the conductors oscillate elliptically at frequencies on the order of 1-Hz or less 

with vertical amplitudes of several feet. Sometimes two loops appear, superimposed on one 

basic loop. Single-loop galloping rarely occurs in spans over 600 to 700 feet. This is fortunate 

since it would be impractical to provide clearances large enough in long spans to prevent the 

possibility of contact between phases. In double-loop galloping, the maximum amplitude usually 

occurs at the quarter span points and is smaller than that resulting from single-loop galloping. 

There are several measures that can be incorporated at the design stage of a line to reduce 

potential conductor contacts caused by galloping, such as designing the line to have shorter 

spans, or increased phase separation. The H-frame structures provide very good phase spacing 

for reducing galloping contacts. 

6.5.2 Galloping Considerations in the Design of Transmission Lines: In areas where 

galloping is either historically known to occur or is expected, designers should indicate design 

measures that will minimize galloping and galloping problems, especially conductor contacts. 

The primary tool for assuring absence of conductor contacts is to superimpose Lissajous ellipses 

over a scaled diagram of the structure to indicate the theoretical path of a galloping conductor. 

See Figures 6-3 and 6-4. To avoid contact between phase conductors or between phase 

conductors and overhead ground wires, none of the conductor ellipses should touch one another. 

However, if galloping is expected to be infrequent and of minimal severity, there may be 

situations where allowing ellipses to overlap may be the favored design choice when economics 

are considered. 
Bulletin 1724E-200 

Page 6-8 

FIGURE 6-3: GUIDE FOR PREPARATION 

 OF LISSAJOUS ELLIPSES 

⎟

⎟

⎠

⎞

⎜

⎜

⎝

⎛ = −

c

c

w

1 p φ tan Eq. 6-6

Single Loop Double Loop 

Major Axis 

‘M’ 

M = 1.25 Si + 1.0 Eq. 6-7 

8

2

3

8 3

0.1

2

⎟

⎟

⎠

⎞

⎜

⎜

⎝

⎛

−+

+=

a

L

S La

M

i

Eq. 6-8

where 2

2

2

Si

L

a ⎟ + ⎠

⎞ ⎜

⎝

⎛ =

Distance ‘B’ B = 0.25 Si Eq. 6-9 = 2.0 MB Eq. 6-10

Minor Axis 

‘D’ 

D = 0.4M Eq. 6-11 MD −= 0.12 Eq. 6-12

Where: 

pc = wind load per unit length on iced conductor in lbs/ft. 

Assume a 2 psf wind. 

wc = weight per unit length of conductor plus 1/2 in. of radial ice, 

lbs/ft 

L = span length in feet. 

M = major axis of Lissajous ellipses in feet. 

Si = final sag of conductor with 1/2 in. of radial ice, 

no wind, at 32°F, in feet. 

D = minor axis of Lissajous ellipses in feet. 

B,Ø = as defined in figure above 

Ø

i

Si M

B

D

POINT OF CONDUCTOR 

ATTACHMENT

POINT OF SUSPENSION 

INSULATOR SUPPORT

Ø+Ø

2
Bulletin 1724E-200 

Page 6-9

FIGURE 6-4: SINGLE LOOP GALLOPING ANALYSIS 

6.6 Clearance Between Conductors in a Crossarm to Vertical Construction Span: 

Conductor contacts in spans changing from crossarm to vertical type construction may be 

reduced by proper phase arrangement and by limiting span lengths. Limiting span lengths well 

below the average span lengths is particularly important in areas where ice and sleet conditions 

can be expected to occur. See Figure 6-5. 

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 6-10 

Blank Page 
 Bulletin 1724E-200 

Page 7-1

7. INSULATOR SWING AND CLEARANCES OF CONDUCTORS FROM 

SUPPORTING STRUCTURES

7.1 Introduction: Suspension insulator strings supporting transmission conductors, either at 

tangent or angle structures, are usually free to swing about their points of support. Therefore, it 

is necessary to ensure that when the insulators do swing, clearances are maintained to structures 

and guy wires. The amount of swing varies with such factors as: conductor tension, 

temperature, wind velocity, insulator weight, ratio of weight span to wind span, and line angle. 

The force due to line angle will cause suspension strings to swing in the direction of the line 

angle of the structure. Wind blowing on the conductor span will exert a force in the direction of 

the wind. These two forces may act either in the same direction or in opposite, the algebraic sum 

thereby determining the net swing direction. Line angle forces and wind forces also interact with 

the vertical forces of the conductor weight and insulator string weight. The vector sum of these 

forces determines the net angle from the vertical axis to which the insulator string will swing. 

This net insulator swing angle should be calculated for several key weather conditions so that 

corresponding phase-to-ground clearances may be checked on a particular pole-top arrangement. 

The purpose of this chapter is to explain how insulator swing application guides called swing 

charts are prepared. Chapter 10 explains how these charts are used in laying out a line. 

7.2 Clearances and Their Application: Table 7-1 provides information on three sets of 

clearances that can ensure proper separation between conductors and structures or guys under 

various weather conditions. Figure 7-1 illustrates the various situations in which the clearances 

are to be applied. 

7.2.1 No-Wind Clearance: The no wind clearance provides a balanced insulation system in 

which the insulating value of the air gap is approximately the same as that of the insulator string 

for a tangent structure. (See Table 8-1 for insulation levels. Note that tangent structures do not 

include the extra insulators used with angle structures). 

Conditions at which no-wind clearances are to be maintained follow: 

• Wind: Assume no wind. 

• Temperature: Assume a temperature of 60°F. See Figure 7-1 for conductor condition. 

The engineer may also want to evaluate clearances at cold conditions (such as -20°F 

initial sag) and hot conditions (such as 167°F final sag). 

7.2.2 Moderate Wind Clearance: This clearance is the minimum clearance that should be 

maintained under conditions that are expected to occur occasionally. A typical condition may be 

the wind that reoccurs no less than once every two years (probability of occurrence no more than 

50 percent). Clearance values for moderate wind clearance conditions will have a lower 

flashover value than clearance values for the no-wind condition. These lower clearance values 

are acceptable because under moderate wind conditions, the specified clearance will be sufficient 

to withstand most of the severe voltage stress situations for wind conditions that are not expected 

to occur often. 

There are different clearance requirements to the structure than to anchor guys. See Table 7-1, 

moderate wind, for differences. Also, note that Table 7-1 requires that additional clearance must 

be provided if the altitude is above 3300 feet. 

Conditions at which moderate wind clearances are to be maintained follow: 
Bulletin 1724E-200 

Page 7-2 

• Wind: Assume a wind of at least 6 psf blowing in the direction shown in Figure 7-1. 

Higher wind pressures can be used if judgment and experience deem them to be 

necessary. However, the use of excessively high wind values could result in a design that 

is overly restrictive and costly. It is recommended that wind pressure values of no higher 

than 9 psf (60 mph) be used for the moderate wind clearance design unless special 

circumstances exist. 

• Temperature: Temperature conditions under which the clearances are to be maintained 

depend upon the type of structure. A temperature of no more than 32°F should be used 

for tangent and small angle structures where the insulator string is suspended from a 

crossarm. A lower temperature value should be used where such a temperature can be 

reasonably expected to occur in conjunction with the wind value assumed. It should be 

borne in mind, however, the insulator swing will increase at lower temperatures because 

conductor tensions increase. Therefore, in choosing a temperature lower than 32°F, one 

should weigh the increase in conservatism of line design against the increase or decrease 

in line cost. NESC Rule235 requires a temperature no higher than 60°F final tension. 

A temperature of 60°F should be used for angle structures where the force due to change 

in direction of the conductor holds the insulator string away from the structure. Even if 

the maximum conductor temperature is significantly greater than 60°F, a higher 

temperature need not be used as an assumed wind value of 40 mph (6 psf)) has quite a 

cooling effect. 

Assume final sag conditions for 60°F temperature and initial sag conditions for 32°F. 

7.2.3 High Wind Clearance: This is the minimum clearance that should be maintained under 

high wind conditions that are expected to occur very rarely. The clearances provide enough of 

an air gap to withstand a 60 Hz flashover but not much more. Choice of such values is based on 

the philosophy that under very rare high wind conditions, the line should not flashover due to the 

60 Hz voltage. 

Conditions under which high wind clearances are to be maintained are: 

• Wind: The minimum assumed wind value should be at least the 10-year mean recurrence 

interval wind blowing in the direction shown in Figure 7-1. More wind may be assumed 

if deemed appropriate. 

• Temperature: The temperature assumed should be that temperature at which the wind is 

expected to occur. The conductor should be assumed to be at final tension conditions. 

To determine the velocity of the wind for a 10 year return period, the following factors should be 

applied to the 50 year peak gust wind speed (See Figures 11-2a, b, c and d in Chapter 11). 

V = 85 to100 mph,

Continental U.S. Alaska V > 100 mph (hurricane) 

0.84 0.87 0.74 
 Bulletin 1724E-200 

Page 7-3

FIGURE 7-1: ILLUSTRATION OF STRUCTURE INSULATOR SWING ANGLE LIMITS 

AND CONDITIONS* UNDER WHICH THEY APPLY (EXCLUDES 

BACKSWING) 

TANGENT AND 

SMALL ANGLE 

STRUCTURES

No Wind 

Insulator Swing 

Moderate Wind 

Insulator Swing 

High Wind 

Insulator Swing 

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 7-4 

TABLE 7-1 

 RECOMMENDED MINIMUM CLEARANCES IN INCHES AT 

CONDUCTOR TO SURFACE OF STRUCTURE OR GUY WIRES 

Nominal voltage, Phase to Phase, 

kV

34.5 46 69 115 138 161 230 

Standard Number of 5-3/4”x10” 

Insulators on Tangent Structures 

3 3 4 7 8 10 12 

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. 

(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 7-5

7.2.4 Example of Clearance Calculations: The following examples demonstrate the 

derivation of the minimum clearance to anchor guys at 6 psf. 

To determine the minimum clearance of a 115 kV line to an anchor guy (Table 7-1) at 6 psf, the 

clearance is based on NESC Table 235-6 and NESC Rule 235E. 

NESC Clear. in any direction. = NESC 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) 

7.3 Backswing: Insulator swing considerations are illustrated in Figure 7-1. For angle 

structures where the insulator string is attached to the crossarm, the most severe condition is 

usually where the force of the wind and the force of the line angle are acting in the same 

direction. However, for small angle structures, it is possible that the limiting swing condition 

may be when the wind force is in a direction opposite of that due to the force of the line angle. 

This situation is called backswing, as it is a swing in a direction opposite of that in which the 

insulator is pulled by the line angle force. Figure 7-2 illustrates backswing. 

When calculating backswing, it is necessary to assume those conditions that would tend to make 

the swing worse, which usually is low conductor tension or small line angles. It is recommended 

that the temperature conditions for large angle structures in Figure 7-1 be used, as they result in 

lower conductor tensions. 

FIGURE 7-2: FORWARD AND BACKWARD SWING ANGLES 

7.4 Structure Insulator Swing Values: Table 7-2 provides the allowable insulator swing angle 

values for some of the most often used standard agency tangent structures. These values 

represent the maximum angle from the vertical that an insulator string of the indicated number of 

standard bells may swing in toward the structure without violating the clearance category 

recommendation indicated at the top of each column. For tangent structures, the most restrictive 

angle for the particular clearance category for the entire structure is given. Thus, for 

an asymmetrical tangent structure (TS-1 for instance) where the allowable swing angle depends 

upon whether the insulators are assumed to be displaced to the right or left, the use of the most 

restrictive value means that the orientation of the structures with respect to the line angle need 

not be considered. For certain angle structures the insulator string has to be swung away from 

the structure in order to maintain the necessary clearance. These situations usually occur for 

large angle structures where the insulator string is attached directly to the pole or to a bracket on 

the pole and where the force due to the change in direction of the conductors is relied upon to 

hold the conductors away from the structure. 

forward

swing

back 

swing

direction of line angle

normal position of 

insulators (no wind, 

no ice)
Bulletin 1724E-200 

Page 7-6 

TABLE 7-2 

INSULATOR SWING ANGLE VALUES IN DEGREES 

(For insulator string with ball hooks) 

(For insulator swing of other structures, see Appendix J) 

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 20.0 38.5 74.0 

 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 

7.5 Line Design and Structure Clearances: Insulator swing has a key effect on acceptable 

horizontal to vertical span ratios. Under a given set of wind and temperature conditions, an 

insulator string on a structure will swing at an angle toward the structure a given number of 

degrees. The angle of this swing is related to a ratio of horizontal to vertical forces on the 

insulator string. A relationship between the horizontal span, the vertical span, and if applicable, 

the line angle can then be developed for the structure, conductor, and weather. Horizontal and 

vertical spans are explained in Figure 7-4. 

The acceptable limits of horizontal to vertical span ratios are plotted on a chart called an 

insulator swing chart. Such a chart can be easily used for checking or plotting out plan and 

profile sheets. Figures 7-3 and 7-5 show simplified insulator swing charts for the moderate wind 

condition only. There is one significant difference between the chart for tangent structures, and 

the chart for angle (running corner) structures. In Figure 7-3 for a typical tangent structure, the 

greater the vertical span for a fixed horizontal span the less swing occurs. The reverse is true for 

chart of Figure 7-5 for a typical angle structure. This occurs because the swing chart in Figure 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. 

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

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 7-7

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 7-8 

The ‘no wind’ insulator swing criteria will not be a limiting condition on tangent structures as 

long as the line direction does not change and create an angle in the line. If an angle is turned, it 

is possible that the ‘no wind’ condition might control. The other two criteria may control under 

any circumstance. However, the high wind criteria will be significant in those areas where 

unusually high winds can be expected. Thus, all three conditions specified need to be checked. 

FIGURE 7-5: TYPICAL INSULATOR SWING CHART FOR A TH-233 MEDIUM ANGLE 

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

minimum NESC 6 psf) 

7.6 Formulas for Insulator Swing: The formulas in equations 7-1 and 7-2, can be used to 

determine the angle of insulator swing that will occur under a given set of conditions for either 

tangent or angle structures. 

( )( )( ) ( )( )

( )( ) ( )( ) c i

c

wVS W

T pHS

2/1

sin 2 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

1

)

1°

12°

14°

15°

16°

17°

18°

SWING

EXCESSIVE

SWING

ALLOWABLE

LINE ANGLE
 Bulletin 1724E-200 

Page 7-9

where: 

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 - 

7.7 Insulator Swing Charts: Insulator swing charts similar to those in Figures 7-4 and 7-5 can 

be developed by using equation 7-3 and the maximum angle of insulator swing values as limited 

by clearance to structure. 

( )( )( ) ( )( )

( )( ) ( )( ) c

i

c

c

w

W

w

T pHS VS

tan 2

sin 2 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. 

7.8 Excessive Angles of Insulator Swing: If upon spotting a line, calculations shown a 

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

Section 10.4 of Chapter 10 of this bulletin may be required to alleviate the problem. 
Bulletin 1724E-200 

Page 7-10 

7.9 Example: For the TH-10 tangent structure, develop the insulator swing chart. Assume that 

it is desired to turn slight angles with the tangent structure and the insulator string assembly uses 

the ball hook. 

7.9.1 Given:

 a. Voltage: 161 kV 

 Structure: TH-10 

 Conductor: 795 kcmil 26/7 ACSR 

 Insulation: Standard (10 bells) 

 b. NESC heavy loading district 

 High winds: 14 psf 

 Ruling Span: 800 ft. 

 c. Conductor Tensions 

 6 psf wind 

 0°F 

 6,244 lbs. initial tension 

 No wind 

 60°F 

 4,633 lbs. final tension 

 12.5 psf wind 

 32°F 

 10,400 lbs. final tension 

7.9.2 Solution: Using the information on conductor sizes and weights, allowable swing angles, 

insulator string weights from the appendices of this bulletin and using equation 7-3, the 

following calculation tables and the swing chart in Figure 7-6 are created. 

7.10 Example: On the plan and profile drawings, the engineering is checking insulator swing 

for the TH-10 structure in example 7-9. For a certain TH-10 structure with no line angle, the 

horizontal span is 800 feet. Determine the minimum vertical span. 

7.10.1 Same Information as 7.9.1

7.10.2 Solution: From Figure 7-6, for a horizontal span of 800 feet, the vertical span must be 

greater than 241 feet (see also tables for Figure 7-6). Many programs which are used to develop 

plan-profile drawings will automatically check insulator swing or will use insulator swing as a 

parameter in the spotting of structures. 
 Bulletin 1724E-200 

Page 7-11 HORIZONTAL SPAN NI FEET

TH-10 161kV 800' Ruling Span

795 Kcmil 26/7 ACSR

6244 bl s. Tension At 0° Initial, 6 psf W ni d

4633 bl s. Tension At 60° Final, No W ni d

0 400 800 1200

0

400

800

1000

600

200

200 600 1000 1400

60°F Final

No Wind Insulator

Swing L mi it

60°F Final

1° Line Angle

0° Line Angle

2° Line Angle

Moderate Wind

Insulator Swing

L mi it

0°F Initial

High Wind Condition Does Not Contro

U

l

nacceptable

Acceptable

VERTICAL SPAN IN FEET

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

Page 7-12 

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

( )( )( ) ( )( )

( )( ) ( )( ) c

i

c

c

w

W

w

T pHS VS

tan 2

sin 2 θ 2

−

+

=

φ

Note: for the no wind case, verticaof horizontal span. It is only depen

θ 1° 2° Ø = 

 sin θ/2 .00872 .01745 

angle with the vertical thrstring swings. 

 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________ Ruli

 sin θ/2 Conductor: 795 26/7 ACSR Loa a) (2)(T)(sin θ/2) Voltage: 161 kV_______ No o b) (HS)(pc) Insulator Swing Condition: No w a + b (F=0  c) (wc)(tan Ø) Ø = 16.4°_______ d) (a + b)/c pc = 0 lbs./ft____ Con e) Wi/(2)(wc) wc= 1.0940 lbs./ft d – e = VS T= 4,633 lbs___

Wi= 135 lbs

Ø = 16.4°
FIGURE 7-6: INSULATOR SWING CHART FOR EXAMPLE 7-9 (continued) 

( )( )( ) ( )( )

( )( ) ( )( ) c

i

c

c

w

W

w

T pHS VS

tan 2

sin 2 θ 2

−

+

=

φ

θ = 0° HS=200 HS=400 HS=800 HS=1000 Ø = 

 sin θ/2 0 0 0 0 

angle with the vertical thinsulator string swings. 

 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________ Ru

 sin θ/2 .017452 .017452 .017452 .017452 Conductor: 795 26/7 ACSR Lo a) (2)(T)(sin θ/2) 217.95 217.95 217.95 217.95 Voltage: 161 kV_______ No  b) (HS)(pc) 110.80 221.60 443.20 554.00 Insulator Swing Condition: Mo a + b 328.75 439.55 661.15 771.95 (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____ Co e) Wi/(2)(wc) 61.70 61.70 61.70 61.70 wc= 1.0940 lbs./ft d – e = VS 163.10 238.87 390.40 466.17 T= 6,244 lbs___

Wi= 135 lbs

Ø = 53.2°
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 pHS VS

tan 2

sin 2 θ 2

−

+

=

φ

θ = 0° HS=200 HS=400 HS=800 HS=1000 Ø = 

 sin θ/2 0 0 0 0 

angle with the vertical thinsulator string swings. 

 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________ Ru

 sin θ/2 .017452 .017452 .017452 .017452 Conductor: 795 26/7 ACSR Lo a) (2)(T)(sin θ/2) 363.01 363.01 363.01 363.01 Voltage: 161 kV_______ No  b) (HS)(pc) 230.80 461.60 923.01 1154.00 Insulator Swing Condition: Hig a + b 593.81 824.61 1286.21 1517.01 (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____ Co e) Wi/(2)(wc) 61.70 61.70 61.70 61.70 wc= 1.0940 lbs./ft d – e = VS 56.65 102.65 194.64 240.64 T= 10,400 lbs___

Wi= 135 lbs

Ø = 77.7°
Bulletin 1724E-200 

Page 8-1 

8. INSULATION AND INSULATORS

8.1 Insulator Types: Insulation is defined as the separation between conducting surfaces by 

means of a non-conducting (dielectric) material that would economically offer a high resistance 

to current. Insulators may be fabricated from porcelain, toughened glass, fiberglass rods and 

sheds of polymer or silicone construction. 

The main types of insulators used on transmission lines are suspension insulators using bells or 

polymer strings, pin insulators, and vertical and horizontal posts. Several suspension bell units 

are connected in a string to achieve the insulation level desired. The polymer suspension is one 

unit with an insulation level determined largely by its length. Horizontal post units are made of 

porcelain or polymer and are single units with a desired rating. See Figures 8-1 and 8-2. 

FIGURE 8-1: A STANDARD PORCELAIN SUSPENSION BELL 

FIGURE 8-2: A TYPICAL PORCELAIN HORIZONTAL POST INSULATOR 

8.2 Insulator Materials 

8.2.1 Porcelain insulators have been the industry standard as specified by ANSI requirements 

for electrical and mechanical capacities. Although porcelain insulators have a history of long, 

useful lives, the strings are heavy and subject to breakage from gunshots. The connecting 

portions of porcelain insulators are metal components which are embedded in high strength 

cement as specified by ANSI standards. Strength ratings for porcelain insulators are verified by 

proof loading requirements of each manufactured unit, and stamped accordingly. 

8.2.2 Toughened glass insulators are similar in construction to the porcelain insulator. They 

are heavy, and are also subject to vandalism exposure. ANSI fabrication standards are also 

available for toughened glass. 

8.2.3 Non-ceramic (polymer) insulators typically consist of a fiberglass rod that is sheathed 

with weathershed ‘bells’ made of either rubber-based or silicone-based polymers. The 

connecting ends are typically compressed metal fittings. ANSI standards have been developed 

for suspension units. 
Bulletin 1724E-200 

Page 8-2 

Non-ceramic assemblies offer varieties of end fittings, lengths and strength capacities. They are 

much lighter in weight than their porcelain and glass counterparts. Polymers may be subject to 

damage by corona voltage, ultraviolet radiation, or physical deterioration which may not be 

apparent. Deterioration of a fiberglass rod may result in a reduction in strength of the unit. 

8.3 Insulation Levels Using Suspension Bells: Table 8-1 provides suggested insulation levels. 

However, circumstances such as high altitude, contamination, high isokeraunic levels, or high 

footing resistance, may warrant additional insulation. If wood structures with steel arms, steel 

structures, or concrete pole structures are used in areas where there is a high isokeraunic level, 

consideration should be given to using one additional suspension bell beyond the standard 

agency recommended insulation levels. 

8.3.1 Tangent and Small Angles: Table 8-1 indicates the recommended number of 

5-3/4 x 10 in. suspension insulators to be used per phase on wood tangent and small angle 

structures. Also given are the electrical characteristics of the insulator strings. 

8.3.2 Angles: For angle structures where the conductor tension is depended upon to pull the 

insulator string away from the structure, one more insulator bell should be added to the number 

of bells recommended for tangent structures. The sole exception to this is 34.5 kV where no 

additional bells are needed. 

TABLE 8-1 

RECOMMENDED ISULATION LEVELS*AT SEA LEVEL 

(SUSPENSION AT TANGENT AND SMALL ANGLE STRUCTURES) 

Flashover Characteristics in kV 

Nominal L-L 

Voltage in kV 

No. of 

5-3/4x10” 

Bells 

60 Hz 

Low Freq

Dry* 

60 Hz 

Low Freq 

Wet 

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 

8.3.3 Deadends: In situations where the insulator string is in line with the conductor, the 

number of bells should be two more than is used for tangent structures. These situations occur at 

large angles, and tangent deadends where the conductor is deadended onto an insulator string. 

The sole exception to this is 34.5 kV where one additional bell is used. 

8.4 Insulation Levels Using Post Insulators: Agency recommended electrical characteristics 

for horizontal post insulators are given in Table 8-2. 
Bulletin 1724E-200 

Page 8-3 

TABLE 8-2 

RECOMMENDED INSULATION LEVELS AT SEA LEVEL 

(POSTS AT TANGENT AND SMALL ANGLE STRUCTURES) 

Flashover Characteristics in kV 

Nominal L-L 

Voltage in kV 

60 Hz 

Low Freq 

Dry 

60 Hz 

Low Freq 

Wet 

Impulse 

Positive Negative 

Total Leakage 

Distance 

inches 

34.5 125 115 210 260 29 

46 150 135 255 344 40 

69 200 180 330 425 53 

115 380 330 610 780 100 

138 430 390 690 870 110 

8.5 Electrical Characteristics of Insulators: Because low frequency dry flashover ratings can 

be tested easily and accurately, these ratings are generally the most common flashover values 

referred to when comparing insulators. However, flashover (60 Hz) of an insulator in service 

almost never occurs under normal dry operating conditions, so these ratings are probably the 

least significant of insulator electrical characteristics. When comparing different types of 

insulators (e.g., post vs. suspension) characteristics such as impulse and wet flashover do not 

necessarily follow the same pattern as the low frequency dry flashover ratings. For these 

reasons, Tables 8-1 and 8-2 are developed and provide both impulse and wet flashover values. 

For voltages up to 230 kV the most severe stress on the insulation is usually caused by lightning, 

and the most important flashover characteristic is the impulse flashover values. 

8.6 High Altitude Considerations

8.6.1 General: As altitude increases, the insulation value of air decreases and an insulator at a 

high elevation will flash over at a lower voltage than the same insulator at sea level. Figure 8-3 

gives the derating factors for insulator flashover values as a function of altitude. These derating 

factors apply to both low frequency flashover values and impulse flashover values. 

FIGURE 8-3: INSULATION DERATING FACTOR vs. ALTITUDE 

IN 1,000's OF FEET (230 kV and below) 

ALTITUDE NI 1000 S' OF FEET 7

 pressure at 

 atmospheric 

 B is standard

Where T = 60° F

0.92

INSULATION DERATING FACTOR (F)

0

0.08 0.72 0.75 0.80 0.84 0.88

2

1

3

4

5

6

0.96 1.00

Curve is a plot of the equation:

Flashover Values at Altitude desired.

Flashover Values at Sea Level to Get

Multiply Derating Factor by Insulator

8

9

 various altitudes

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

in inches of Hg.
Bulletin 1724E-200 

Page 8-4 

In addition to increasing the number of insulators for high altitude, it is also necessary to 

increase the structure air gap clearances. This could result in a decreased allowable insulator 

swing angle or a longer crossarm (see Chapter 7 for details). 

8.6.2 Example of Insulation Needed at High Altitudes: A line is located at 6000 feet 

elevation. The derating factor (from Figure 8-3) is .827. At 138 kV, using the sea-level 

requirement for low frequency dry flashover of 435 kV from Table 8-1, the line would require 

526 kV (435/.827) at 6000 feet. A 10 bell string should be used instead of 7 bells. The 

clearance to structure and clearance to guy wire should be increased (see Table 7-1 for 

guidance). 

8.6.3 Insulation for Lines with Relatively Small Changes in Altitude: When the insulation 

derating factor for the line altitude is at a value less than approximately 90 percent of the 

insulation value at sea level (see Figure 8-3), then additional insulation should be added to bring 

the insulation level up to at least 90 percent of the sea level value. 

8.6.4 Insulation for Lines with Significant Elevation Changes but Less than 5000 Feet: If 

the elevation change in a line from its low point to its highest point is less than 5000 feet, it is 

recommended that insulation for the entire length of the line be based on the weighted average 

altitude of the line. This can be achieved by applying the procedure given in paragraph 8.6.2 to 

that weighted average altitude. 

8.6.5 Insulation for Line with Elevation Changes Greater than 5000 Feet: Where the 

elevation change is greater than 5000 feet, the following two steps should be taken: 

a. The entire line insulation should be upgraded for the minimum altitude of the line using 

the procedure in paragraph 8.6.2 above. 

b. Additional insulation should be added in sections of line where it is needed. This need 

arises where the altitude of the line increases to the point where the insulation value is less 

than approximately 90 percent of the insulation value at the minimum line altitude. This 

means there may be different numbers of insulator bells at different points along the same 

line. 

8.6.6 Example of Additional Insulation for High Altitudes and Line Elevation Changes 

Less than 5000 feet: A 161 kV line is to be built in an area where altitude ranges from 5430 ft. 

to 7580 ft. Determine how much additional insulation, if any, is necessary. 

Solution: The elevation change for the line from its lowest point to its highest point is less than 

5000 ft. Therefore, the insulation should be based on the weighted average altitude. Since we 

do not know the distribution of the line at the various altitudes, we will assume a uniform 

distribution. Thus: 

 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 paragraph 

8.6.2 indicates that additional insulation is needed if the derating factor is less than 0.90, 

additional insulation will be needed. 

According to paragraph 8.6.5, the insulation value should be brought up to approximately 

90 percent of the sea level value, which for 161 kV is: 
Bulletin 1724E-200 

Page 8-5 

 (0.9)(590) kV) = 531 kV 

(590 kV is the low frequency dry flashover value of 10 bells at sea level). 

The 531 kV requirement for low frequency dry flashover at sea level needs to be increased to 

account for the higher elevation. Applying the derating factor to the 531 kV, the low frequency 

dry flashover value of the string needs to be: 

 531/.81 = 655 kV 

From Appendix C, the low frequency dry flashover of 11 bells is 640 kV. For 12 bells it is 

690 kV. Therefore, the addition of one extra bell will not quite bring the insulation level up to 

the 90 percent of sea level. The above calculations seem to indicate the need to add two extra 

bells. However, some judgment should be exercised as to whether the second additional bell is 

used. Even though one bell extra does not quite provide enough additional insulation, it comes 

close. If the expected frequency and severity of lightning storms is not particularly high, one 

extra bell might be sufficient. Depending on experience and judgement, at least one and 

possibly two extra bells should be used. 

8.7 Lightning Considerations

8.7.1 General: Transmission lines are subjected to three types of voltage stress that may cause 

flashover of the insulation: power frequency voltage, switching surges and lightning surges. 

Flashovers due to power frequency voltages are primarily a problem in contaminated conditions 

and are discussed in section 8.8. Of the remaining two causes of flashovers, lightning is the 

more severe for lines of 230 kV and below. 

8.7.2 Lightning Flashover Mechanism: When lightning strikes a transmission line, it may hit 

either the overhead ground wire or a phase conductor. If a phase conductor is hit, there will 

almost certainly be a flashover of the insulation. To minimize this near certainty of a flashover, 

an overhead ground wire is used to intercept the lightning strokes. To reduce the possibility of a 

shielding failure, the shielding angle should be kept at 30° or less. (The shielding angle is the 

angle measured from the vertical between the OHGW and the phase conductors, as shown in 

Figure 8-4). On H-frame structures where two overhead ground wires are used, the center phase 

may be considered to be properly shielded even if the shielding angle to it is greater than 30°. 

For structures whose height is in excess of 92 feet, shielding angles of less than 30° as indicated 

in Table 8-3, should be used. Where there is an unusually high exposure to lightning, such as at 

river crossings, an even smaller shielding angle may be warranted. 

TABLE 8-3 

REDUCED SHIELDING ANGLE VALUES 

Structure Height, 

feet 

Recommended 

Shielding Angle, 

degrees 

92 30 

99 26 

116 21 
Bulletin 1724E-200 

Page 8-6 

If lightning strikes an overhead ground wire, a traveling current wave will be set up which will 

induce a traveling voltage wave. This voltage wave will generally increase in magnitude as it 

travels down the wire, until it reaches a structure where the reflection of the traveling wave from 

the ground prevents the voltage from further increasing. (The overhead ground wire is grounded 

at every structure). If the traveling voltage wave at the structure is sufficiently high, a "back 

flashover" across the insulation from the structure ground wire or from the overhead ground wire 

to the phase conductor will occur. The factors that determine if a back flashover will occur are: 

the amount of insulation, the footing resistance (the higher the footing resistance, the higher the 

voltage rise at the structure) and the span length. 

FIGURE 8-4: SHIELDING ANGLE, POLE AND 

 OVERHEAD GROUND WIRES 

8.7.3 Designing for Lightning: An overhead ground wire should be used in all locations where 

the isokeraunic level is above 20. The overhead ground wire should be grounded at every 

structure by way of a structure ground wire. At H-frame structures, the OHGW's should each be 

connected to a structure ground wire and to one another so that if one structure ground wire 

breaks, both overhead ground wires will still be grounded. 

In areas where the isokeraunic level is 20 or less, an overhead ground wire should still be used 

for a distance of 1/2 mile from a substation. A map of isokeraunic levels is given in Appendix E. 

8.7.4 Footing Resistance: For satisfactory lightning performance of a line, low footing 

resistance is essential. Exactly what value of footing resistance is acceptable or unacceptable is 

not a simple matter as it depends upon several variables. Previous successful experience with a 

similar line in similar circumstances can be one guide. The following references may be useful 

in determining what lightning outage rate a given footing resistance would yield. 

(a) “Transmission Line Reference Book, 115 kV and Below,” Palo Alto, Calif., Electric 

Power Research Institute, 1975. 

(b) “Estimating Lightning Performance of Transmission Lines,” J. M. Clayton and F. S. 

Young. IEEE Transactions on Power Apparatus and Systems, November 1964, pp. 1102-

1110. 

Pole 

ground

wires

Shield

angle

Cross

connection

Overhead

ground wire
Bulletin 1724E-200 

Page 8-7 

A grounded structure has a good chance to withstand a lightning flashover provided that 

conductor insulation and ground resistance have been properly analyzed and coordinated. 

A lightning outage rate of 1 to 4 per 100 miles per year is acceptable with the lower number 

more appropriate for lines in the 161 to 230 kV range. 

Generally, experience has shown that the footing resistance of individual structures of the line 

especially within 1/2 mile of the substation should be less than 25 ohms in high isokeraunic 

areas. 

When a line is being built, it is recommended that the footing resistance of the ground 

connection be measured and recorded on a spot check basis. If footing resistance problems are 

expected, more frequent measurements should be made and recorded. If experience indicates 

that the lightning outage rate is not acceptable, these measurements readings can be useful when 

taking remedial measures. 

Footing resistance should not be measured immediately after a rain when the soil is moist. If the 

footing resistance is higher than desired, additional driven rods may be used to reduce it. If the 

earth's resistivity is very high, counterpoise rather than driven rods may be required. Reference 

(b) this section gives guidance in the selection of counterpoise. 

8.7.5 Lightning Arresters: In areas where structure grounding is difficult to achieve, or the 

lightning performance of an existing transmission line needs to be improved, Metal Oxide 

Varistor (MOV) line arresters can be installed. These arresters should be coordinated with the 

substation station class arresters for proper performance. The engineer should determine the size 

of the substation arresters and choose a slightly higher Maximum Continuous Over Voltage 

(MCOV) rating on the transmission line to prevent the line arresters from taking all of the 

flashover duty. 

On a triangular three wire designs, adding an arrester to the top phase of every structure will 

typically give some shield angle protection to the other phases. For best performance, the 

arrester should be tied to a ground system with 10 ohms or less of resistance. If good grounding 

is not available, the borrower should consider adding lightning arresters to all three phases. 

Lightning arresters can also be installed on shielded lines to minimize back flashover where 

good grounding is difficult. The engineer should design for phase-to-phase clearances between 

the failed arrester, open position, and other phase wires since the arrester may drop near the other 

energized phase position. 

8.8 Contamination Considerations: The problem of contamination induced flashovers should 

be considered if a line is to be built near a seacoast, an industrial district, or at other locales 

where airborne contaminants may accumulate on insulators. 

8.8.1 Contamination Flashover Mechanism: When a layer of contaminants on an insulator is 

moistened by fog, dew, light rain or snow, it will become more conductive and the leakage 

current along the surface of the insulator will greatly increase. Where the current density is the 

greatest (for suspension insulators near the pin, and for post insulators at the points of least 

diameter), heat caused by the increased leakage current will evaporate the moisture causing the 

formation of a dry band. This band usually has an higher resistance than the adjacent moistened 

area which means that the band will support almost all the voltage across it. This will result in 

the breakdown of the air and the formation of an arc across the dry band. The arc will cause the 

moisture film at the dry band edges to dry out, enlarging the dry band, eventually to the point 

where the voltage across the band is just below the air breakdown value. If an increase in 

precipitation occurs causing a lowering of contaminant resistance, a second breakdown can 

occur. If conditions are right, a cycle of repeated and ever-increasing surges will be set up which 
Bulletin 1724E-200 

Page 8-8 

will result in several discharges joining, elongating and bridging the entire insulator and 

resulting in a power arc. See Figure 8-5 for a graphic description. 

FIGURE 8-5: CONTAMINATION BREAKDOWN PROCESS 

 OF A SINGLE PORCELAIN INSULATOR UNIT 

8.8.2 Effect of Insulator Orientation: The orientation of insulators has an effect on 

contamination performance. Vertical strings of suspension insulators or vertical post insulators 

do not wash well in the rain because of the sheltering effects of the insulator skirts. 

Contaminants will tend to remain on the underside of the insulator which is not immune from the 

moistening effects of fog or wind blown rain and snow. Horizontally oriented suspension 

insulators and post insulators have their undersides more thoroughly washed by the rain and 

therefore tend to fare better than vertical insulators in contaminated areas. Another advantage of 

insulators in nonvertical positions is that any ionized gases caused by arcing will not contribute 

to setting up conditions where an arc could jump from one bell to another or along the skirts of a 

vertical post. 

M OISTURE LAYER

FORMS ON

C ON DU CTING

M ATER IAL

(A)

IN IT IA L C O N D UCTING STATE

(B)

LEAKAGE CURRENT DRIES OUT

M OIST UR E NEAR PIN

(C)

ARC BRIDGES OVER DRY AREA

H E A T IN G A N D E NLARGING IT

(D)

E NL AR GE D DR Y AR EA H OL DS E NT IR E 

UNIT VOLTAGE AND ARC EXTINGUISHES

A RC R ES TR IK ES A S M O R E M OISTUR E

APPEARS ON DRY AREA

(E)

A RC B RIDG ES E NT IR E 

INSULATOR

(F)

DRY AREA

DRY AREA

C O N T A M INATION 

LAYER

ARC

ARC
Bulletin 1724E-200 

Page 8-9 

8.8.3 Designing for Adverse Contamination Conditions: There are several means available 

for improving line insulation performance in a contaminated atmosphere. 

One way to compensate for contaminated conditions is to increase the leakage distance of the 

insulation. The leakage distance is the distance along the surface of the insulators from the top 

of the string (or post) to the energized hardware, not including any metal such as insulator caps 

and pins. 

Table 8-4 gives recommended leakage distances for various levels of contamination. The 

increased leakage distance can be obtained by adding additional standard insulator bells (using a 

longer post insulator) or by using fog insulators, which have more leakage distance for the same 

overall insulator length. The additional leakage distance on fog insulators is obtained by having 

more and/or deeper skirts on the underside of the insulator bell. In addition to the leakage 

distance, the shape of the insulator has an effect on contamination performance, especially when 

fog units are being used. 

Research into the performance of existing lines with similar contamination should play an 

important part in the final determination of insulating for atmospheric contamination. 

An alternative to increasing the total leakage distance of the insulator string is to use a resistance 

graded insulators. These insulators have a glaze that permits a small but steady leakage current 

to flow over their surface. This leakage current gives the insulator much better contamination 

performance without having to increase leakage distance. The base of a resistance graded 

insulator should be solidly bonded to the structure ground wire to permit the leakage current to 

flow easily to the ground. To aid in determining whether to use this type of insulator, its 

advantages and disadvantages are listed below. 

Advantages and Disadvantages of Resistance Graded Insulators 

Advantages 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 8-10 

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 8-11 

8.9 Mechanical Considerations (Porcelain and Non-ceramic)

8.9.1 Suspension Insulators: Strength rating methods and nomenclature vary depending on the 

insulator material. 

For porcelain, ANSI C29.1 specifies Mechanical and Electrical (M&E) procedures. The M&E 

value is determined by a combined mechanical and electrical test. The insulator has a voltage 

(75 percent of its rated dry flashover) impressed across it while a mechanical load is gradually 

applied to the insulator. For non-ceramics, most manufacturers conduct specified mechanical 

loading (SML) procedures to determine a polymer insulator’s failure rating. These procedures 

are similar to the M&E for porcelain, but no electrical test is applied. 

ANSI C 29.2 defines standard mechanical ratings for porcelain as: 15,000 lbs., 25,000 lbs., 

36,000 lbs. and 50,000 lbs. ANSI C29.12 defines standard SML’s for non-ceramic transmission 

insulators as: 20,000 lbs., 25,000 lbs., 36,000 lbs. and 40,000 lbs. 

For recommended insulator loading limits, refer to Table 8-5. Under NESC district loading 

conditions, suspension insulators should not be loaded to more than 40 percent of their standard 

ANSI M&E rating for porcelain insulators or 40 percent of their ANSI SML for non-ceramics. 

If a heavier loading than the NESC district loading can be expected to occur with reasonable 

regularity, then the 40 percent loading limit should be maintained at the higher loading limit. 

Under extreme ice or high wind (50-year mean recurrence interval wind conditions) the load on 

the insulator should not exceed 65 percent of the M&E strength of the insulator for porcelain and 

50 percent of the M&E strength for non-ceramics. 

Generally, porcelain insulators with a 15,000 pound M&E rating will be satisfactory for tangent 

structures. However, stronger insulators may be needed on long spans with large conductors and 

at deadends and angles where the insulators carry the resultant conductor tension. 

TABLE 8-5 

SUMMARY OF RECOMMENDED INSULATOR LOADING LIMITS 

Insulator Type NESC District Loading Extreme Loading 

Non-ceramic Porcelain 

Suspension 40% 50% 65% 

 (% of ANSI standard 

SML or M&E strength) 

(% of ANSI standard 

SML strength) 

(% of ANSI standard 

M&E strength) 

Horizontal Post 

Cantilever 40% 50% 65% 

Tension, Compression 50% 

(% of appropriate rated

 ultimate strength value) 

50% 

(% of appropriate rated

 ultimate strength value) 

65% 

(% of appropriate rated

 ultimate strength value) 

Vertical Post (Porcelain) 750 lbs. ----- 

 

Vertical Pin Insulator 

(Porcelain, Mounted on 

the Crossarm) 

500 lbs. ----- 
Bulletin 1724E-200 

Page 8-12 

When suspension non-ceramic insulators are used, the designer must be aware of the effects on 

insulator swing calculations due to increased length and reduced weight. Agency Bulletin 

1724E-220, “Procurement and Application Guide for Non-Ceramic Composite Insulators,” 

provides additional information on non-ceramic insulators. When used as a jumper, polymer 

suspension insulators may be pulled towards the structure because of their lightweight. 

8.9.2 Horizontal Post Insulators (Porcelain and Non-ceramic): Under NESC loading district 

conditions, horizontal post insulators must not be loaded to more than 40 percent of their 

ultimate cantilever strength. As with suspension insulators, if a loading more severe than the 

NESC loading can be expected to occur with reasonable regularity, then the limit recommended 

for the more severe loading should be used. Under extreme ice conditions, the cantilever load on 

horizontal post insulators should not exceed 65 percent of the ultimate strength for porcelain and 

50 percent of the ultimate strength for non-ceramics. 

When a line angle is turned at a horizontal post structure, some or all of the insulators will be 

in tension. Under standard NESC loading conditions, the tension or compression load on the 

insulator must not exceed 50 percent of the ultimate tension or compression strength of the 

insulator. Under extreme loading conditions, the tension load on the insulator must not exceed 

65 percent of the ultimate tension strength for porcelain and 50 percent of the ultimate tension 

strength of non-ceramic insulators. 

Line post insulators are actually subjected to vertical, transverse and longitudinal loads 

simultaneously. These loads represent the actual applied stresses to the line post insulator core 

that are experienced in the field. Vertical, transverse and longitudinal loads each contribute to 

the total bending moment, or total stress on the rod. Non-ceramic manufacturers provide 

combined loading application curves, which represent the mechanical strength limits of a nonceramic line post insulator when subjected to simultaneous loads. These curves are used to 

determine how the insulator’s combined loading requirements compare with its cantilever 

(bending) strength. The combined loading application curves are used during the engineering 

stage to evaluate the mechanical strength of the insulator for specific line loading criteria. 

There are three special considerations that must be mentioned in relation to horizontal post 

insulators: 

Insulator Grounding: Where the structure ground wire passes near horizontal post insulators, it 

either should be stood off from the pole by means of a non-conducting strut or must be solidly 

bonded to the base of the insulator. This grounding is necessary to avoid radio noise problems. 

Mechanical Impact Failures: Porcelain post insulators mounted on steel, concrete, or (in some 

cases) on wood structures using H-class poles, have experienced cascading mechanical failures 

due to impact loads because of the relative rigidity of the structures. To minimize the affects of 

impact loads, it is recommended that on rigid structures, non-ceramic insulators be used, or that 

porcelain post insulators be equipped with deformable bases, shear pin devices, or other means 

of relieving mechanical overloads. 

Live Line Maintenance Issues: Many compact designs restrict the lineman for working on 

transmission lines while energized. Rule 441 of the NESC provides Table 441-1 which gives the 

recommended AC live work minimum approach distance for various voltages. 

8.9.3 Porcelain Vertical Post and Pin Insulators Mounted on Crossarms: The maximum 

transverse load should be limited to 500 lbs. for standard single pin type agency standard 

structures and 750 lbs for standard vertical post type structures. The 500 lb. limit applies 

whether the load is from standard NESC loading district loadings alone or from a combination of 

loading district loading 
Bulletin 1724E-200 

Page 8-13 

and the resultant of conductor tension on line angles. These limit will prevent excessive stress 

on the insulator, the tie wires (if used), insulator pin (if used), and the wood crossarm. The 

transverse load can be doubled by using double pin or post construction. See Table 8-5 for a 

summary of recommended insulator loading limits. 

8.9.4 Coordination of Insulator Strength with Strength of Associated Hardware: Care 

should be taken to coordinate the strength of the hardware associated with the insulator with the 

strength of the insulator itself. 

8.9.5 Example of Maximum Vertical Span Due to Horizontal Post Insulator Strength: A 115 kV line is to be built using horizontal post insulators with a cantilever strength of 

2,800 lbs. The conductor to be used is 477 kcmil 26/7 ACSR. Determine the maximum vertical 

span under: 

1.Heavy loading district conditions; and 

2.Under an extreme ice load, no wind, and 1.5 in. of radial ice 

(See Chapter 11 for definitions of heavy loading and Chapter 9 for information on conductors). 

Solution: From Appendix B, Conductors, the weights per unit length for the two conditions of 

the conductor are: 

Heavy Loading District of 1/2 inch radial ice = 1.5014 lbs./ft. 

Extreme radial ice of 1.5 inch =5.0554 lbs./ft. 

Span Limits for Heavy Loading District: 

2800 lbs.(0.40) = 746 ft. 

1.5014 lbs./ft. 

Span Limits for Extreme Ice Condition: 

 2800 lbs.(0.65) = 360 ft. 

5.0554 lbs./ft. 

The maximum vertical span is therefore 360 ft. 

8.9.6 Example of Determining Minimum Suspension Insulator M&E Rating: A conductor 

has a maximum tension under heavy loading district conditions of 10,000 1bs. Under extreme 

radial ice of 1.5 in, it has a maximum tension of 16,000 lbs. Determine the minimum M&E 

rating of suspension bell insulators to be used in tension strings. (Tension strings are those 

insulator strings that are in line with the conductor and bear its full tension). 

Solution:

Under NESC loading district conditions, the insulator can be loaded up to 40 percent of its M&E 

rating. Therefore: 

(M&E rating)(0.4) = 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: 
Bulletin 1724E-200 

Page 8-14 

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

M&E rating = load/(0.65) 

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

c. Based on ANSI standard M&E ratings, the insulators to be used should have a minimum 

standard rating of 25,000 lbs. 
Bulletin 1724E-200

Page 9-1 

9. CONDUCTORS AND OVERHEAD GROUND WIRES

9.1 Introduction: Of all the components that go into making up a transmission system, nothing 

is more important than the conductors. There are a surprising number of variables and factors 

that are to be considered when dealing with conductors. These include: 

• Conductor type • Conductor size • Conductor ampacity • Conductor thermal capacity • Conductor tensions • Corrosive atmosphere considerations • Radio noise • Conductor motion considerations • Economic considerations 

9.2 Types of Conductors: Of the currently available types of conductors, some are used much 

more extensively than others. Sections 9.2.1 through 9.2.11 provide descriptions of many of the 

conductor types. 

9.2.1 ACSR (Aluminum Conductor Steel-Reinforced): ACSR is the most common type of 

conductor used today. It is composed of one or more layers of hard-drawn concentricallystranded 1350 aluminum wire with a high-strength galvanized steel core. The core may be a 

single wire or stranded depending on the size. Because numerous stranding combinations of 

aluminum and steel wires may be used, it is possible to vary the proportions of aluminum and 

steel to obtain a wide range of current carrying capacities and mechanical strength 

characteristics. 

The steel core may be furnished with three different coating weights of zinc. The "A" coating is 

the standard weight zinc coating. To provide better protection where corrosive conditions are 

present, heavier class "B" or "C" zinc coatings may be specified where "C" is the heaviest 

coating. 

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. 

9.2.2 ACSR/AW (Aluminum Conductor, Aluminum-Clad Steel Reinforced): ACSR/AW 

conductor is similar to conventional ACSR except the core wires are high strength aluminumclad steel instead of galvanized steel. Aluminum-clad core wire has a minimum aluminum 

thickness of 20 percent of its nominal wire radius. This cladding provides greater protection 

against corrosion than any of the other types of steel core wire, and it is applicable for use where 

corrosive conditions are severe. ACSR/AW also has a significantly lower resistivity than 

galvanized steel core wire and may provide somewhat lower losses. 

9.2.3 AAC (All Aluminum Conductors – 1350 H19): AAC conductor is made up entirely of 

hard-drawn 1350 aluminum strands. With a minimum aluminum content of 99.5%, 1350 

aluminum is essentially pure aluminum. It is usually less expensive than other conductors, but is 

not as strong and tends to sag more. AAC conductors are most useful where electrical loads are 

heavy and where spans are short and mechanical loads are low. 

FIGURE 9-2: 1350 ALUMINUM CONDUCTOR STRANDINGS 

9.2.4 AAAC-6201 (All Aluminum Alloy Conductor - 6201 Alloy): AAAC conductor is 

composed entirely of 6201-T81 high strength aluminum alloy wires, concentrically stranded and 

similar in construction and appearance to 1350 aluminum conductors. Its strength is comparable 

with that of ACSR. It was developed to fill the need for a conductor with higher strength than 

that obtainable with 1350 aluminum conductors, but without a steel core. 

AAAC conductors were designed to have diameters the same as those of standard sizes and 

strandings of ACSR. The DC resistance of 6201 conductor is approximately equivalent to that 

of standard ACSR conductor with the same diameter. AAAC conductor may be used where 

contamination and corrosion of the steel wires is a problem. It has proven to be somewhat more 

susceptible to vibration problems than standard ACSR conductor strung at the same tension. 

The use of conductor sizes smaller than 3/0 ACSR equivalent on suspension type constructions 

should be avoided because the light weight of the conductor may result in inadequate downward 

force on the suspension insulators causing radio noise and insulator swing problems. 

9.2.5 ACAR (Aluminum Conductor Alloy Reinforced): ACAR conductor consists of 1350 

aluminum strands reinforced by a core of higher strength 6201 alloy. These 6201 reinforcement 

wires may be used in varying amounts allowing almost any desired property of 

strength/conductivity (between conductors using all 1350 wires and those using all 6201 wires) 

to be achieved. Strength and conductivity characteristics of ACAR are somewhere between 

those of a 1350 aluminum conductor and a 6201 conductor. 

7 STRAND 19 STRAND 37 STRAND

37 STRAND 91 STRAND
Bulletin 1724E-200

Page 9-3 

FIGURE 9-3: TYPICAL ACAR STRANDINGS 

9.2.6 AWAC (Aluminum-Clad Steel Conductor): AWAC conductor is made up of 

aluminum-clad steel and 1350 aluminum strands. The corrosion resistant aluminum clad wires 

of the AWAC conductor act as strength members as well as conductivity members, thereby 

reducing the weight of the conductor without reducing strength. For the same designated size 

and stranding, the AWAC conductors have a slightly smaller diameter than standard ACSR. For 

smaller AWAC sizes, the ratio of aluminum-clad to aluminum strands is varied to provide a wide 

range of rated strengths. 

9.2.7 ACSR/SD (Aluminum Conductor Steel Reinforced - Self Damping): ACSR/SD 

conductor may use either two layers of trapezoidal-shaped aluminum wires or two layers of 

trapezoidal-shaped aluminum wires and one layer of stranded round wires of hard-drawn 1350 

aluminum. The steel core may be a single wire or stranded depending on the size of the 

conductor. 

From a performance point of view, ACSR/SD conductor is similar to conventional ACSR except 

that it has self damping characteristics. That is, the conductor is designed to reduce aeolian 

vibration. The damping occurs because of the interaction between the two trapezoidal layers and 

between the trapezoidal layers and the core. Some special considerations associated with this 

conductor are that: 

• During stringing, special precautions are taken and procedures followed to avoid difficulties. • It may be more expensive than conventional ACSR, but its ability to be strung at higher 

tensions to reduce sag, which may result in economic advantages that offset its extra cost. 

FIGURE 9-4: TYPICAL ACSR/SD STRANDINGS 

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 

9.2.8 ACSR/TW (Trapezoidal Shaped Strand Concentric - Lay Stranded Aluminum 

Conductors, Steel Reinforced): As with ACSR/SD, the conductor layers of ACSR/TW are 

trapezoidal-shaped aluminum wires. However, unlike ACSR/SD conductor, no gaps exist 

between layers ACSR/TW strands. The compact trapezoidal-shaped wires result in an increased 

capacity for an equivalent standard range of ACSR conductor diameters. Also, for a given 

aluminum area, a smaller conductor diameter can be designed for ACSR/TW than for equivalent 

round-wire ACSR which results in reduced wind-on-wire load on the structure. These are 

important advantages when existing transmission lines are considered for uprating or 

reconductoring. Other advantages and improvements of ACSR/TW include corrosion resistance 

and lower temperature gradient. 

Use of ACSR/TW should be based on an economic evaluation to determine whether savings will 

be achieved in comparison with the use of conventional ACSR conductor. 

9.2.9 AACSR (Aluminum Alloy Conductor, Steel Reinforced): AACSR conductor is the 

same as a conventional ACSR conductor except that the 1350 strands are replaced with higher 

strength 6201 alloy strands. The resulting greater strength of the conductor allows the sags to be 

decreased without exceeding the standard conductor percent tension limits. AACSR type of 

conductor is primarily used at river crossings where sag limitations are important. The higher 

tensions associated with this type of conductor require that special attention be paid to the 

possibility of aeolian vibration. 

9.2.10 T2 (Twisted Pair Aluminum Conductor): When designing transmission lines with 

twisted pair (T2) type conductor, the designer should be aware of Rule 251 of NESC on 

conductor wind loading. The rule states for multiconductor cable an equivalent diameter of two 

times the single conductor diameter should be assumed for wind loading unless there is a 

qualified engineering study to reduce the overall cable diameter. 

 

9.2.11 High Temperature Conductors: Three types of conductors are considered high 

temperature, ACCR (aluminum conductor composite reinforced), ACCCTM (aluminum 

conductor composite core) and ACSS (aluminum conductor steel supported). For sizes 

equivalent to other types of conductor (i.e., ACSR), higher ampacities can be achieved at similar 

overall sag levels while operating the conductors a much higher temperatures. One benefit of 

these types of conductors can be the avoided cost of replacing existing structures. The 

temperature ratings for these conductors can be limited by hardware, so extreme care should be 

used when specifying hardware and establishing operating temperature limits. Also, the unique 

natures of these conductors result in the use of special precautins during stringing, such as 

special stringing blocks in certain locations and multiple grips when installing conductors with 

multi-layer annealed aluminum conductor strands. 

ACCR conductors are composed of heat resistant aluminum-zirconium alloy outer strands and 

aluminum oxide matrix core strands. . The core of the ACCR is composed of stranded fiber 

reinforced metal matrix, an aluminum oxide fiber embedded in high-purity aluminum. The fiber 

reinforced metal matrix has strength similar to steel and weight similar to aluminum. The outer 

strands may be round or trapezoidal in shape and are similar to 1350 aluminum ultimate strength 

but may be heated to high temperatures without softening (annealing) and without losing 

strength. Additionally, the thermal expansion of the metal matrix core has less thermal 

expansion than steel and retains its strength at high temperatures. ACCR conductors use similar 

stranding as ACSR. Because of the lightweight core, heat resistant outer and core strands, higher 

electrical conductivity, and lower thermal expansion for less sag, higher operating temperatures 

may be used with this conductor which leads to higher ampacities. ACCR conductors and 

hardware are usually rated up to 210 C continuous operating temperature with 240 C for short 

term maximum operating temperature. 
Bulletin 1724E-200

Page 9-5 

ACCCTM (Aluminum Conductor, Composite Core) are composed of trapezoidal wire of 1350 

aluminum stranded around the composite core. The core of the ACCC conductor is a solid with 

no voids and is a carbon/glass fiber polymer matrix core. This solid polymer matrix core is 

composed of carbon fibers surrounded by an outer shell of boron-free E-glass fibers that 

insulates the carbon from the aluminum conductor. The 1350 aluminum trapezoidal wires are 

fully annealed which make them softer compared to the hardened aluminum wires used in some 

other conductors. The aluminum strands are tempered because the composite core of the ACCC 

is designed to carry the entire load Because the core exhibits a very low coefficient of thermal 

expansion, the amount of sag the ACCC will experience when operating at high temperatures is 

considerably less than other types of conductor (i.e., ACSR). ACCC TM conductors and hardware 

are usually rated up to 180 C continuous operating temperature with 200 C for short term 

maximum operating temperature. However, because of the softer temper of the aluminum wires, 

the outer wires can be more susceptible to damage from improper installation and handling. 

ACSS (Aluminum Conductor, Steel Supported) can be considered as another type of high 

temperature conductor which can be supplied with round or trapezoidal aluminum strands. 

ACSS conductor is similar to ACSR; however, the aluminum strands in ACSS are fully annealed 

and depends on the steel for its strength and sag characteristics. ACSS conductors and hardware 

are usually rated up to 250 C or more continuous operating temperature, depending upon the 

coating on the steel core, without loss of strength. However, because of the softer temper of the 

aluminum wires, the outer wires can be more susceptible to damage from improper installation 

and handling. 

9.3 Selecting a Conductor Type

9.3.1 Agency Standards: The conductor selected should generally be of a type and stranding 

listed as being acceptable for use borrower systems of the Rural Utilities Service. See 

Informational Publication 202-1, “List of Materials Acceptable for Use on Systems of USDA 

Rural Development Electrification Borrowers”. 

9.3.2 Corrosion Considerations: Conductors with galvanized steel cores should not be used in 

areas of severe corrosion. Rather, a conductor with other types of core wire, such as mischmetal 

or aluminum-clad core wire should be used. A conductor with a steel core wire coated with 

aluminum or with a heavier weight zinc may be considered, if such materials have been 

successfully (i.e., reliably operated without core deterioration) used in similar locations or 

corrosive environments.. 

9.3.3 Economics: The relative cost of one conductor type versus another is very important. 

When comparing costs, one should take overall line costs into consideration. However, a less 

expensive conductor with greater sags may not be a more economical selection than a more 

expensive conductor with lesser sag. When overall line costs are considered, the conductor that 

allows longer spans and shorter structures may prove to be the better choice. 

9.3.4 Strength: The strength of the conductor and its ability to sustain mechanical loads 

without unreasonable sags must be evaluated. 
Bulletin 1724E-200 

Page 9-6 

9.4 Selection of Conductor Size 

9.4.1 Minimum Conductor Size: Table 9-1 provides a list of minimum allowable conductor 

sizes for each standard agency transmission voltage. The minimums are based on a combination 

of radio noise, corona, and mechanical sag and strength considerations. (See Appendix I for 

additional details on radio noise and corona). If a conductor type other than ACSR or 6201 

AAAC is used, the conductor diameter should not be less than the diameter of the ACSR 

specified for the particular given voltage. 

TABLE 9-1 

RECOMMENDED MINIMUM CONDUCTOR SIZES 

kVLL ACSR AAAC - 6201 

34.5 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 

9.4.2 Voltage Drop Considerations: Not only should the conductor be sufficiently large to 

meet the requirements of paragraph 9.4.1 of this section, but it should also meet the system 

voltage drop requirements. Typically, the conductor impedance would have to be sufficiently 

low so that, under a given set of electrical loading conditions, the voltage drop would not exceed 

approximately 5 percent. In general, voltage drop becomes a factor for longer lines. Voltage 

drop can be evaluated by either running a load flow computer program or by using the estimating 

tables in Bulletin 1724E-201, “Electrical Characteristics of Agency Alternating Current 

Transmission Line Designs.” 

9.4.3 Thermal Capability Considerations: When sizing a phase conductor, the thermal 

capability of the conductor (ampacity) should also be considered. The conductor should be able 

to carry the maximum expected long-term load current without overheating. Generally, a 

conductor is assumed to be able to heat up to 167°F without any long-term decrease in strength. 

Above that temperature, there may be a decrease in strength depending on how long the 

conductor remains at the elevated temperature. A conductor's ampacity depends not only upon 

its assumed maximum temperature, but also on the wind and sun conditions that are assumed. 

See Appendix D of this bulletin for ampacity tables. 

9.4.4 Economic Considerations: Economics is an important factor in determining conductor 

size. The minimum conductor sizes given in Table 9-1 will rarely be the most economical in the 

long run. The added cost of a larger conductor may be more than offset by the present worth of 

the savings from the lower line losses during the entire life of the conductor. A proper economic 

analysis should at a minimum consider the following factors for each of the conductor sizes 

considered: 

• The total per mile cost of building the line with the particular conductor being 

considered; 

• The present worth of the energy losses associated with the conductor; 

• The capital cost per kilowatt of loss of the generation, substation and transmission 

facilities necessary to supply the line losses; 

• Load growth. 
Bulletin 1724E-200

Page 9-7 

The results of an economic conductor analysis can often be best understood when presented in a 

graphical form as shown in Figure 9-5. At an initial load of approximately 200 MW, 1272 kcmil 

becomes more economical than 795 kcmil. 954 kcmil is not economical at any load level 

included on the graph. 

9.4.5 Standardization and Stocking Considerations: In addition to the above factors, the 

problem of standardization and stocking should be considered. When a conductor is electrically 

and economically optimum, but is not a standard size already in use on the system, the additional 

cost and complications of having one more conductor size to stock should be weighed against 

the advantages of using the optimum conductor. A proliferation of conductor sizes in use on a 

power system is undesirable because of the expense of stocking many sizes. In addition, if a 

power system does not standardize on conductors then there may be a need for additional 

associated hardware such as end fittings and splices. 

FIGURE 9-5: RESULTS OF A TYPICAL ECONOMICAL CONDUCTOR 

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

9.5 Overhead Ground Wires (OHGW)

9.5.1 High Strength or Extra High Strength Galvanized Steel Wires: High strength OHGW 

included in Informational Publication 202-1 are 3/8" and 7/16", while extra high strength listed 

sizes include 5/16", 3/8", and 7/16". Siemens Martin grade wires of any size and 1/4" steel strand 

are not accepted by the agency for use as overhead ground wires. Overhead ground wires are 

required to be in full compliance with ASTM A-363, “Standard Specification for Zinc-Coated 

(Galvanized) Steel Overhead Ground Wire Strand,” ASTM A-363 does not allow steel wires to 

have brazed or welded joints. Steel wires for overhead ground wires are available in three 

weights of zinc coating. The standard weight zinc coating is designated as ‘A’. The heavier zinc 

coating is designated ‘B’ and ‘C’, with ‘C’ having the heaviest weight of zinc. 

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 9-8 

9.5.2 Aluminum-Clad Steel Strand: A thick cladding of aluminum which makes aluminumclad steel strand more resistant to corrosion than strands with a thin coating of zinc. In addition, 

the aluminum clad material has greater conductivity. 

The sizes of this material that may be used as overhead ground wires are 7 No. 10AWG, 

7 No. 9AWG, 7 No. 8AWG, and 7 No. 7AWG. The material is in accordance with ASTM B416, 

“Standard Specification for Concentric-Lay-Stranded Aluminum-Clad Steel Conductors.” 

9.5.3 Selecting a Size and Type: Selecting an overhead ground wire size and type is dependent 

upon only a few factors, the most important of which is how the sag of the OHGW coordinates 

with that of the phase conductors. Other factors that may have to be considered are corrosion 

resistance and conductivity. 

If a line is to be built in a seacoast region or in another location where there is a highly corrosive 

atmosphere, aluminum-clad steel wire should be considered. If the OHGW is to be used to carry 

any type of communications signal, or if large magnitudes of lightning stroke currents are 

expected, a higher conductivity than normal may be desirable. 

9.6 Conductor and Overhead Ground Wire Design Tensions 

9.6.1 General: Throughout the life of a transmission line, the conductor tensions may vary 

between 10 and 60 percent, or more, of rated conductor strength due to change in loading and 

temperature. Most of the time, however, the tension will vary within relatively narrow limits, 

since ice, high winds, and extreme temperatures are relatively infrequent in many areas. Such 

normal tensions may actually be more important in determining the life of the conductor than 

higher tensions which are experienced infrequently. 

9.6.2 Conductor Design Tensions: In Table 9-3 provides recommended maximum conductor 

tension values for ACSR and 6201 AAAC conductors that should be observed for the ruling 

span. Note that the values given are maximum design values. If deemed prudent, tensions less 

than those specified or loadings greater than the standard loading condition (tension limit for 

condition 3 of Table 9-3) may be used. However, it is unwise to base the selection of a 

"maximum loading" condition on a single or very infrequent case of excessive loading. 

Mountainous areas above 4000 feet in which ice is expected, should be treated as being in heavy 

loading district even if they are not. 

In open areas where steady winds are encountered, aeolian vibration can be a problem, especially 

if conductor tensions are high. Generally, lower tensions at conditions at which aeolian 

vibration is likely to occur, can reduce vibration problems (see paragraph 9.9.2 for further 

discussion). 

Explained below are the several conditions at which maximum conductor tension limits are 

specified. 

1. Initial Unloaded Tension: Initial unloaded tension refers to the state of the conductor 

when it is initially strung and is under no ice or wind load. 

2. Final Unloaded Tension: After a conductor has been subjected to the assumed ice and 

wind loads, and/or long time creep, it receives a permanent or inelastic stretch. The tension 

of the conductor in this state, when it is again unloaded, is called the final unloaded tension. 
Bulletin 1724E-200

Page 9-9 

3. Standard Loaded Tension: The standard loaded tension refers to the state of a conductor 

when it is loaded to the assumed simultaneous ice and wind loading for the NESC loading 

district concerned (see Table 11-1, Chapter 11 for the loads associated with each loading 

districts). The constants in Table 9-2 are to be added to the vector resultant of the transverse 

and vertical loads to get the total load on the conductor: 

TABLE 9-2 

CONSTANTS TO BE ADDED TO THE TOTAL 

LOAD ON A WIRE FOR NESC DISTRICT LOADS 

Heavy Medium Light 

 

0.30 lbs/ft. 0.20 lbs/ft. 0.05 lbs/ft. 

 

In cases where the standard loaded condition is the maximum mechanical load used in the 

calculations, the initial and final sags and tensions for the standard loaded condition will be 

the same unless creep is the governing factor. If another condition, such as extreme ice, is 

the maximum mechanical load, then the initial and final sags and tensions for the standard 

loaded condition can be significantly different from one another. In this case, it is important 

that the loaded tension limits be set for initial conditions. 

4. Extreme Wind Tension: The extreme wind tension refers to the state of the conductor 

when a wind is blowing on it with a value not less than the 50-year mean recurrence interval 

(see Figure 11-3 in Chapter 11 of this bulletin). No ice should be assumed to be on the 

conductor. 

5. Extreme Ice Tension: The tension in a conductor when it is loaded with an extreme 

amount of ice for the area concerned is called the extreme ice tension. It should be assumed 

that there is no wind blowing when the ice is on the conductor. Values of 1 to 2 in. of radial 

ice are commonly used as extreme ice loads. 

6. Extreme Ice with Concurrent Wind: The tension in a conductor when it is loaded with an 

extreme ice with a concurrent wind (see Figure 11-3 in Chapter 11 of this bulletin). 

9.6.3 Controlling Conditions: For a given ruling span, usually only one of the tension limit 

conditions will control the design of the line and the others will have relatively little significance 

as far as line tensions are concerned. 

If the conductor loading under extreme ice or wind loads is greater than under the standard 

loaded condition, calculated sag and tension values at other conditions could be somewhat 

different from what they would be if the standard loaded condition were the maximum case. In 

these situations, stringing sags should be based upon tension limits for tension 

conditions 1, 2, and 3 only, as tensions at conditions 4 and 5 are satisfactory. 

9.6.4 Overhead Ground Wire (OHGW): To avoid unnecessarily high mechanical stresses in 

the OHGW, supporting structures, and guys, the OHGW should not be strung with any more 

tension than is necessary to coordinate its sags at different conditions with the phase conductors. 

See Chapters 6 and 8. 
Bulletin 1724E-200 

Page 9-10 

TABLE 9-3 

RECOMMENDED CONDUCTOR AND OVERHEAD 

 GROUND WIRE TENSION AND TEMPERATURE LIMITS (Note B) 

 Temperatures 

• Tension limits for conditions 1, 2 and 3 below are to be met at the following temperatures: 

Heavy loading district 0o F 

Medium loading district 15o F 

Light loading district 30o F 

 

• Tension limits for condition 4 are to be met at the temperature at which the extreme wind is 

expected. 

• Tension limits for condition 5 & 6 are to be met at 32o F 

Tension Limits 

Tension Condition (percentage of rated breaking strength) 

(See section 9.6.2 for explanation)

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 9.9 for further details).

(D) For 6201 AAAC, a value of 20 percent is recommended. 

(E) For ACSR only. For 6201 Aluminum, use 60 percent. 
Bulletin 1724E-200

Page 9-11 

9.7 Ruling Span

9.7.1 Why a Ruling Span? If all spans in a section of line between deadends are of the same 

length, uniform ice and wind loads will result in equal conductor tension in all spans. But span 

lengths usually vary in any section of line, with the result that temperature change and ice and 

wind loads will cause conductor tensions to become greater in the longer spans and less in the 

shorter spans when compared to the tensions of loaded uniform spans. Movement of insulator 

strings and/or flexing of the structures will tend to reduce this unequal tension. It is possible, 

however, for conductor tension in long spans to reach a value greater than desired unless the line 

is spotted and the conductor strung to limit this undesirable condition. 

A ruling span is an assumed uniform design span which approximately portrays the mechanical 

performance of a section of line between its deadend supports. The ruling span is used in the 

design and construction of a line to provide a uniform span length which is representative of the 

various lengths of spans between deadends. This uniform span length allows sags and 

clearances to be readily calculated for structure spotting and conductor stringing. 

Use of a ruling span in the design of a line assumes that flexing of the structure and/or insulator 

string deflection at the intermediate supporting structures will allow for the equalization of 

tension in the conductor between adjacent spans to the ruling span tension. 

9.7.2 Calculations of the Ruling Span: On a line where all spans are equal, the ruling span is 

the same length as the line spans. Where spans vary in length, the ruling span is between the 

shortest and the longest span lengths on the line, but is mainly determined by the longer spans. 

• Approximate Method. Some judgment should be exercised in using this method since a 

large difference between the average and maximum span may cause a substantial error in 

the ruling span value. 

( ) = avg + 3/2 max − LLLRS 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

++++

++++ = K

K

321

3 3

3

3

2

3

1 Eq. 9-2

where: 

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

Other symbols are as previously defined. 
Bulletin 1724E-200 

Page 9-12 

9.7.3 Establishing a Ruling Span: As can be seen from Equation 9-2, the exact value of the 

ruling span can only be calculated after the structures have been spotted and all the span lengths 

determined. However, the ruling span has to be known in advance of structure spotting. Thus 

the ruling span needs to be estimated before spotting structures on the plan-profile drawings. 

When following any procedure for estimating ruling span, keep in mind that estimation of a 

ruling span is an intuitive process based on experience, judgment, and trial and error. A good 

starting point for estimating ruling span is the height of the base structure. The base structure is 

the structure that is expected to occur most often throughout the line. After assuming a base 

structure height, subtract the minimum ground clearance value from the height of the lowest 

phase conductor above ground at the structure. The allowable sag as limited by ground 

clearance is the result. Using this sag value and tables of sags for various ruling span lengths, a 

ruling span length can be chosen whose sag is approximately equal to the allowable sag for the 

base structure height. In other words, a ruling span is chosen to be approximately equal to the 

level ground span -- the maximum span limited by line-to-ground conductor clearance for a 

particular height structure. This method of choosing a ruling span is useful if the terrain is flat or 

rolling. However, if it is rough, the ruling span should be somewhat greater than the level 

ground span. 

The ruling span value initially chosen should be checked to see that it coordinates reasonably 

well with the minimum span values as limited by such factors as structure strength, conductor 

separation, galloping, etc. Also, Equation 9-1 should be used in conjunction with estimated 

maximum and average span values to further check the reasonableness of the estimated ruling 

span. If the initial estimate does not check out, the value should be changed and the procedure 

repeated. 

In cases where the spans in one extended section of line are consistently and considerably longer 

or shorter than in another section of line, use of more than one ruling span may be unavoidable. 

It is a common practice to permit long spans to double the average span without deadends, 

provided conductor tension limits are satisfactory. In addition, short spans should not be less 

than approximately one-half of the ruling span. After the plan and profile sheets are plotted, the 

validity of the estimated ruling span value should be checked by comparing it to the actual value 

obtained. It is not essential that the estimated ruling span value be equal to the actual value, 

provided the estimated ruling span results in satisfactory ground clearance and economical 

structure spotting without excessive conductor tensions. However, if the difference between the 

estimated and actual ruling span is more than approximately 15 percent, the effects resulting 

from the difference should be carefully checked. 

9.7.4 Effects of the "Wrong" Ruling Span: It is important that the actual ruling span be 

reasonably close to the ruling span value that is used to spot the line. If this is not the case, there 

may be significant differences between the predicted conductor tensions and clearances and the 

actual values. There have been instances where sags were greater than predicted, resulting in 

clearance problems, because the wrong ruling span was assumed. Table 9-4 will be of use in 

determining how conductor sags differ from the predicted value when there are differences 

between actual and assumed ruling span. Note that tension variation is opposite of that of the 

sags. Thus, increased sags mean decreased tension and vice versa. 
Bulletin 1724E-200

Page 9-13 

TABLE 9-4 

DIRECTION OF DEVIATION OF SAGS FROM 

PREDICTED VALUES WHEN ACTUAL AND ASSUMED (DESIGN) 

RULING SPAN VALUES ARE SIGNIFICANTLY DIFFERENT 

(Applies to Unloaded Condition) 

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 

9.8 Determining Conductor Sags and Tensions: Determination of conductor sags and 

tensions, given a set of tension limits as outlined in section 9.6, is a complex and difficult task. 

This is true because only one of the tension limits may control, and it is not always predictable 

which limit it will be. In addition, it is necessary to work with conductor stress strain curves 

which for a compound conductor such as ACSR can be rather complex. 

The best method of obtaining conductor sag and tension values is to use one of the numerous 

computer programs written for that purpose. When using a computer program, several factors 

should be checked: 

• The program should be written so that a check is made of all the limiting conditions 

simultaneously and the governing condition noted. 

• The program should take conductor creep into account. 

• The tension values given should be average tension values and not tension at support 

or horizontal tension values. 

• The source of the stress stain data used should be indicated. 

If computerized sag tension values are not available from the software, values can be generated 

using the graphical method given in the publication, "Graphic Method for Sag Tension 

Calculations for ACSR and Other Conductors," Publication No. 8, Aluminum Company of 

America, 1961. 
Bulletin 1724E-200 

Page 9-14 

9.9 Aeolian Vibration

9.9.1 General: Overhead conductors of transmission lines are subject to aeolian and galloping, 

both of which are produced by wind. Galloping is discussed in section 6.3. Aeolian vibration is 

a high-frequency low-amplitude oscillation generated by a low velocity, comparatively steady 

wind blowing across the conductors. This steady wind will create air vortices or eddies on the 

lee side of the conductor. These vortices or eddies will detach at regular intervals from the top 

and bottom area of the conductor creating a force on the conductor that is alternately impressed 

from above and below. If the frequency of the forces approximately corresponds to a frequency 

of a mode of resonant vibration of the span, the conductor will tend to vibrate in many loops in a 

vertical plane. The frequency of vibration depends mainly on conductor size and wind velocity 

and is generally between 5 and 100 Hz for wind speeds within the range of 0 to 15 miles per 

hour. The peak-to-peak amplitudes of vibration will cause alternating bending stresses great 

enough to produce fatigue failure in the strands of the conductor or OHGW at the points of 

attachment. Highly tensioned conductors in long spans are particularly subject to vibration 

fatigue. This vibration is generally more severe in flat open terrain where steady winds are more 

often encountered. 

The frequency and loop length of the vibration can be determined using equation 9-3. 

Frequency of the vibration: 

dc

V f = 26.3 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

gT

f

LL

2

1 Eq. 9-4

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. 

9.9.2 Designing for Vibration Problems: If an area is expected to have aeolian vibration 

problems, measures ‘a’ through ‘d’ may be taken to mitigate possible problems with damage to 

conductors, shield wire, and hardware. It is also important to note that structures, not just 

conductors, shield wires, and hardware, may be adversely affected by vibration. The measures 

are not necessarily mutually exclusive; more than one measure may be used simultaneously. 
Bulletin 1724E-200

Page 9-15 

a. Reduced Tension: The two line design variables that have the greatest effect upon a 

line's vibration characteristics are conductor tension and span length. Singly or in 

combination, these two variables can be reduced to the point where the level of vibration, 

without any vibration damping devices, will not be damaging. For similar sag 

characteristics, conductors of different types, with their different characteristics, may 

require a different degree of vibration protection. 

A rule of thumb that has proved generally successful in eliminating vibration problems is 

to keep the conductor tension for short and medium length spans under initial unloaded 

conditions at the average annual minimum temperature to approximately 20 percent or 

less of the conductor's rated strength. For long spans, a somewhat lower percent tension 

limit should be used. Due to their vibration characteristics, 6201 AAAC and 1350 

aluminum conductors should be held to tensions somewhat lower than the 20 percent 

value, even for relatively short spans. 

b. Armor Rods: In addition to reinforcing the conductor at the support points, armor rods 

provide a small amount of damping of aeolian vibration. In lines with lower conductor 

tension and shorter spans, this damping may provide adequate protection against 

conductor strand fatigue. 

c. Cushioned Suspensions: Cushioned suspensions combine armor rods with a resilient 

cushioning of the conductor. These suspension clamps provide somewhat more damping 

than armor rods, but the degree of damping is still relatively small compared to vibration 

dampers. 

d. Dampers: Stockbridge and other types of dampers are effective devices for controlling 

vibration. The selection of damper sizes and the best placement of them in the spans 

should be determined by the damper or conductor manufacturer on the basis of the 

tension, weight, and diameter of the conductor and the expected range of wind velocities. 

The length of the suspension clamp and the effect of the armor rods or cushioned 

suspensions should also be considered. With new efficient damper designs and usual 

conductor tensions and span lengths, one damper is installed near one span support joint. 

For long spans, additional dampers may be required. 

9.10 Galloping: See Chapter 6 for details. 

9.11 Maximum Possible Single Span: For a given span length, as the sag is increased, the 

tension at the support will decrease, until a point is reached where the tension will begin to 

increase due to the weight of the conductor. This point occurs when the sag is equal to 0.337 

times the span length. 

The relationship between span length and tension can be expressed as: 

wc

T Lmax = 33.1 Eq. 9-5

where: 

wc = unit weight of conductor in pounds per foot 

T = resultant tension at support, pounds 

Lmax = maximum span, feet 
Bulletin 1724E-200 

Page 9-16 

The above formula can be used to determine the maximum possible span given a maximum 

tension at supports. This is most useful when dealing with river crossings, etc. 

9.12 Sag and Tension Relationships: The relationships in paragraphs 9.12.1 through 9.12.3 

are useful for understanding the sag-tension relationships for conductors: 

9.12.1 Level Span Sags: Equation 9-6, the approximate "parabola method", is helpful in 

solving some sag and tension problems in span lengths below 1,000 feet, or where sag is less 

than 5 percent of the span length. 

h

c

T

Lw 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

Lw

w

T S Eq. 9-7

9.12.2 Inclined Span Sags: See Figure 9-6 for method of determining inclined span sags. 

9.12.3 Tension: The conductor tension in a level span varies from a maximum value at the 

point of support to a minimum value at mid-span point. 

The tension at the point of support is: 

h

c

hch T

Lw TSwTT

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

Sw TTT

T c

h

h

avg +=

+ = Eq. 9-9

where: 

Tavg = average tension in pounds 
Bulletin 1724E-200

Page 9-17 

FIGURE 9-6: NOMOGRAPH FOR DETERMINING LEVEL SPAN 

 EQUIVALENTS OF NON-LEVEL SPANS 

From IEEE Standard 524-1992, “IEEE Guide to the Installation of Overhead Transmission Line 

Conductors,” copyright 1992 IEEE. All rights reserved. 

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

H

O

RIZ

O

N

T

A

L

S

P

A

C

NI G

O

F

S

U

P

P

O

R

T

S

L( .)

V

E

R

TIC

A

L

S

P

A

C

NI G

O

F

S

U

P

P

O

R

T

S

(B.)

S

A

G

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

E

Q

U

VI A

L

E

N

T

S

P

A

N

C

O

R

R

E

C

T

OI N

(A

d

d to

h

orizo

ntal spacin

g to

o

btain

eq

uivalent span len

gth)

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 9-18 

9.13 Stringing Conductors

9.13.1 Tension Method (Preferred) for Stringing Conductors: Using this method, the 

conductor is kept under tension during the stringing process. Normally, the tension method is 

used to keep the conductor clear of the ground and of obstacles which might cause conductor 

surface damage and clear of energized circuits. The method requires pulling a light pilot line 

into the sheaves. The pilot line is then used to pull a heavier line. The heavier pulling line is 

used to pull conductors from reel stands using specially designed tensioners and pullers. For 

lighter conductors, a lightweight pulling line may be used in place of the pilot line to directly 

pull the conductor. A helicopter or ground vehicle can be used to pull or lay out a pilot line or 

pulling line. When a helicopter is used to pull a line, synthetic rope is normally used to attach 

the line to the helicopter and prevent the ‘pilot line’ or pulling line from flipping into the rotor 

blades upon release. With the tension method, the amount of right-of-way travel by heavy 

equipment can be minimized. Usually, this tension method provides the most economical means 

of stringing conductor. Use of a helicopter is particularly advantageous in rugged or poorly 

accessible terrain. 

Major equipment required for tension stringing includes reel stands, tensioner, puller, reel 

winder, pilot line winder, splicing cart and helicopter or pulling vehicle. 

9.13.2 Slack or Layout Method: Using this method, the conductor is dragged along the 

ground by means of a pulling vehicle, or the reel is carried along the line on a vehicle and the 

conductor is deposited on the ground. Conductor reels are positioned on reel stands or "jacks," 

either placed on the ground or mounted on a transport vehicle. These stands are designed to 

support the reel on an arbor, permitting the reel to turn as the conductor is pulled. Usually a 

braking device is provided to prevent overrunning and backlash. When the conductor is dragged 

past a supporting structure, pulling is stopped and the conductor placed in sheaves attached to 

the structure before proceeding to the next structure. 

This method is chiefly applicable to the construction of new lines where maintenance of 

conductor surface condition is not critical and where terrain is easily accessible to a pulling 

vehicle. The method is not usually economically applicable in urban locations where hazards 

exist from traffic or where there is danger of contact with energized circuits, nor is it practical in 

mountainous regions inaccessible to pulling vehicles. 

Major equipment required to perform slack stringing includes reel stands, pulling vehicle(s) and 

a splicing cart. 

9.13.3 Stringing Conductors During Temperature Changes: An examination of conductor 

sag and tension tables will generally indicate the changes that take place in various span lengths 

with a change of conditions. For a given set of conditions, spans of various lengths may have a 

different rate of tension change with a change of loading or temperature. The ruling span tension 

of an unloaded conductor matches the tension of any other span only at one temperature. Large 

changes in temperature during stringing require care in matching average tensions in any section. 

It is desirable to complete stringing between deadends during periods of minimum temperature 

change and at zero wind load. Where spans are supported by suspension insulators, each span 

will have an influence on adjacent spans such that no span can be considered independently 

of the remainder of spans in the same section between anchor structures. Change in temperature 

has a greater effect on short spans than loading does, while long spans are affected more by 

loading. In short spans a slight movement of supports results in substantial changes in tension 

while in longer spans, relatively greater movement is required. The relation between adjacent 

span lengths therefore determines the movement required to equalize tension. 
Bulletin 1724E-200

Page 9-19 

9.14 The Sagging of Conductors: It is important that the conductors be properly sagged in at 

the right stringing tension for the ruling span used. When installing conductors, a series of 

several spans is usually sagged in one operation by pulling the conductors to proper tension 

while they are supported on free rolling sheaves. To obtain the correct sags and to ensure that 

the suspension insulators will hang vertically, the horizontal components of tension must be the 

same in all spans for a selected condition. In a series of spans of varying length, greater sag 

tends to form in the long spans. On steep inclines the sheaves will deflect in the uphill direction 

and there will be a horizontal component of tension in the sheave itself. The horizontal 

component of tension in the conductor will therefore increase from one span to the next, as the 

elevation increases, by an amount equal to the horizontal component in the sheave. As a result, 

sags will proportionally decrease. In order to avoid this effect, it may be necessary to use a 

procedure called offset clipping. In this procedure, the point along the conductor at which it is 

attached to the insulator string is moved a specific distance down span from the point at which 

the conductor sits in the stringing block. See Figure 9-7 for further details on offset clipping. 

It is important that the sags of the conductor be properly checked. It is best to do this in a series 

of level spans as nearly equal to the ruling span as possible. 

For additional information, see: 

“A Guide to the Installation of Overhead Transmission Line Conductors,” IEEE 

Standard 524-1992, IEEE, 1992. 
Bulletin 1724E-200 

Page 9-20 

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

FIGURE 9-7: ANALYSIS FOR APPLICATION OF CLIPPING OFFSETS 

From IEEE Standard 524-1992, “IEEE Guide to the Installation of Overhead Transmission Line 

Conductors,” copyright 1992 IEEE. All rights reserved. 
Bulletin 1724E-200

Page 9-21 

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

segment given below using both the exact and approximate method. 

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. 

9.16 Example 9-2, Maximum Span Determination: Determine the maximum span (for river 

crossings, etc.) for a 795 kcmil 26/7 ACSR conductor. Assume that under heavy loading district 

conditions, the conductor can be loaded up to 40 percent of its rated strength. 

925 ft 1380 ft 495 ft 1005 ft

n

n

LLLL

LLLL RS

++++

++++ = K

K

321

3 3

3

3

2

3

1

10054951380925

10054951380925 RS

3 33 3

+++

+++ =
Bulletin 1724E-200 

Page 9-22 

Solution: From the conductor tables in Appendix B, the rated strength of the conductor is 

31,500 lbs. and the weight of the conductor with 1/2 in. of radial ice is 2.0930 lbs/ft.. 

 T = 31500(0.4) = 12600 lbs. 

wc

T Lmax = 33.1 See Eq. 9-5

Lmax = 1.33 12600 lbs. = 8007 ft. 

 2.0930 lbs/ft. 

9.17 Example 9-3, Determination of Tensions at the Mid Span Point and at the Point of 

Support: A level 800 ft. span of 795 kcmil 26/7 ACSR conductor has a sag of 21.95 ft. The 

average tension value is 9,185 lbs. and there is no ice or wind on the conductor. Determine the 

actual tension values at the mid span point and at the point of conductor support. 

 Solution for the Tension at Mid Span Point: 

2 2

Sw TTT

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

hch T

Lw TSwTT

2

=+= cosh See Eq. 9-8 

T = Th + wcS 

T = 9173 + (1.094)(21.95) 

T = 9197 lbs. 

2

Sw TT c avgh −=
Bulletin 1724E-200 

Page 10-1 

10. PLAN-PROFILE DRAWINGS

10.1 General: Transmission line plan-profile drawings serve an important function in linking 

together the various stages involved in the design and construction of the line. Initially, the 

drawings are prepared based on a route survey. These drawings show the location and elevation 

of all natural and man-made features to be traversed by, or which are adjacent to, the proposed 

line which may affect right-of-way, line design and construction. They also indicate ownership 

of lands near the line. The drawings are then used to complete line design work such as structure 

spotting. During material procurement and construction, the drawings are used to control 

purchase of materials and they serve as construction specification drawings. After construction, 

the final plan-profile drawings become the permanent record and right-of-way data, useful in line 

operation and maintenance or future modifications. 

Accuracy, clarity, and completeness of the drawings should be maintained, beginning with initial 

preparation, to ensure economical design and correct construction. All revisions made 

subsequent to initial preparation and transmittal of drawings should be noted in the revision 

block by date and brief description of revision. Originals of the plan-profile drawings, revised 

for as-built conditions, should be filed by the borrower for future reference. 

10.2 Drawing Preparation: Adequate control of field survey, including ground check of aerial 

survey, and proper translation of data to the plan-profile drawings are of utmost importance. 

Errors which occur during this initial stage will affect line design because a graphical method is 

used to locate the structures and conductor. Normally, plan-profile sheets are prepared using a 

scale of 200 feet to the inch horizontally and 20 feet to the inch vertically. On this scale, each 

sheet of plan-profile can conveniently accommodate about 1 mile of line with overlap to connect 

the end span on adjacent sheets. On lines with abrupt ground terrain changes and on lines where 

there is need to minimize breaks in elevation view, plan-profile sheets may use a scale of one 

inch equal to 400 feet horizontally and one inch equal to 40 feet vertically may be used. 

A sample format for plan-profile drawing, detailing dimensions and stationings in U.S. 

customary (English) units, is shown in Figure 10-1. Stationing and structure numbering 

increases from left to right and the profile and corresponding plan view are included on the same 

sheet. Drawings prepared in ink on Mylar or tracing cloth will provide a better permanent record 

than on paper. However, structure spotting initially should be marked in pencil on plan-profile 

drawing paper and transferred to the base tracings in ink after the drawings are approved and the 

line is released for construction. 

Conventional symbols used to denote features on the drawings are shown in Figure 10-2. 

Features of existing obstacles, structures, etc. to be crossed by the transmission line, including 

the height and position of power and telecommunication lines, should be shown and noted by 

station and description in both the plan and profile views. The magnitude and direction of all 

deflection angles in the line should be included and referenced by “P.I. Station No. XX” in plan 

and elevation views. (P.I. refers to point of intersection). In rough terrain, broken lines 

representing side-hill profiles should be accurately plotted to assure final designs will provide for 

adequate conductor-to-ground clearances and pole heights. A drawing title block should be 

included. The block should identify the line and include the station numbers that are covered on 

the drawing sheet. The block should also include space for recording the names of personnel 

and the dates involved in various stages of drawing preparation, line design, checking, approval, 

and revisions. 

Line design computer software may be used to import survey data and develop the land profile 

for the transmission line. Developments in surveying technologies have allowed the industry to 

go beyond the station-elevation-offset formats that have traditionally been used for transmission 

profile 
Bulletin 1724E-200 

Page 10-2 

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

Page 10-3 

FIGURE 10-2: CONVENTIONAL SYMBOLS FOR PLAN-PROFILE 

PLAN

Transmission Line CL

Telephone Lines TTTTT

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)

Point of 

Intersection 

(P.I.)
Bulletin 1724E-200 

Page 10-4 

modeling. Use of three-dimensional Geographical Information System (GIS) modeling is 

becoming more common. Total station, geographical positioning system, photogrammetry, and 

electronic topographical maps (United States Geological Survey, USGS, maps) have been 

employed to collect data in electronic format and to develop quick and accurate terrain plan and 

profile for transmission lines. 

Design software can use a three-dimensional survey format and develop profile drawings of the 

terrain along the centerline of the line. Some software can create interpolated points on profiles 

by creating a Triangular Irregular Network (TIN). The TIN can be used to develop a threedimensional rendering of a transmission line. 

Once the alignment and profile have been developed, computer programs are then used to spot 

structures along the profile. For an established family of structures, the computer can be used to 

automatically spot structures for the most economical line cost or the user may manually spot 

structures. Programs have been developed to automatically plot the sag curve of the conductor 

and to check insulator swing, structure strength, and clearances. A material list is often 

developed from computer generated plan-profile drawings. 

Computer aided drafting and design software may provide all or part of the following: 

• Importing survey data, to model terrain, and to create a profile; 

• Modeling of structure, including strength, geometry, insulator swing and complete bill of 

material; 

• Calculating conductor sag and tension; 

• Locating structures (spotting) on the profile drawing; 

• Calculating conductor stringing and sagging, at almost any temperature, to check design 

conditions such as uplift, ground clearance or insulator swing; 

• Checking the line plan-profile against specific design criteria; 

• Displaying the plan-profile or structure analysis in three dimensions; and 

• Preparing reports and construction documents showing all construction material units on the 

plan and profile, as well as developing material reports, staking tables, offset clipping 

reports, etc. 

Some design programs provide more custom drafting capabilities. Some are AutoCAD based; 

others are MICRO STATION based. Traditional methods used to spot structures can be as much 

as 70-80 percent more conservative than the computer aided design and drafting approach. 

10.3 Sag Template: When computers are not used to spot structures and draw the conductor 

sag curve, manual techniques are used. Once the profile of the line has been drawn, the next step 

is to develop a sag template. The sag template is a scaling device used for structure spotting and 

for showing the vertical position of conductor (or ground wire) for specified design conditions . 

A sample conductor sag template is shown by Figure 10-3. The template is used on plan-profile 

drawings to graphically determine the location and height of supporting structures required to 

meet line design criteria for vertical clearances, insulator swing, and span limitations. The sag 

template permits alternate layout for portions of the line to be investigated and thereby aids in 

optimizing line design for economy. 

Generally, the conductor sag curves control the line design. The sag template for the overhead 

ground wire is used to show the position of the wire in relationship to the conductors for special 

spans or change in conductor configuration. An uplift condition at the overhead ground wire 

may be checked by using the template cold curve. 
Bulletin 1724E-200 

Page 10-5 

10.3.1 Sag Template Curves: The sag template should include the following sag curves based 

on the design ruling span: 

a. Hot (Maximum Sag) Curve: At maximum operating temperature, no ice, no wind, final sag 

curve, the hot curve is used to check for minimum vertical clearances. However, if the 

maximum sag occurs under an icing condition, this sag curve should be used for the sag 

template. 

b. Cold Curve: At minimum temperature, no ice, no wind, initial sag curve, the cold curve is 

used to check for uplift and insulator swing. 

c. Normal Curve: At 60°F, no ice, no wind, final sag curve, the normal curve is used to check 

normal clearances and insulator swing. 

Sag curves are also used to locate the low point of sags and determine the vertical span lengths 

as illustrated by Figure 10-6. The curve intersection with the vertical axis line represents the low 

point position of sag. 

Conductors of underbuild lines may be of different types or sizes than the transmission 

conductor. The hot curve of the lowest distribution conductor should be used for checking 

ground clearance. Cold curves may be required for each size of conductor to check for uplift or 

insulator swing. 

10.3.2 Sag Template Design: Sag templates may be developed from information provided by 

the manufacturer of the conductor or from a graphical calculation method. Sag values needed to 

construct the template are available from the conductor manufacturer for a given conductor, 

ruling span, design condition and temperature. Sag values may also be determined using the 

graphic method referred to in Section 9.8 of Chapter 9. The template should be made to include 

spans three or four times as long as the normal level ground span to allow for spotting structures 

on steep terrain. 

The form of the template is based on the fact that, at the time when the conductors are installed, 

horizontal tensions have to be equal in all level and inclined spans if the suspension insulators 

are plumb in profile. This is also approximately true at maximum temperature. To obtain values 

for plotting the sag curves, sag values for the ruling span are extended for spans shorter and 

longer than the ruling span. Generally for spans up to 1000 feet, it is sufficiently accurate to 

assume that the sag is proportional to the square of the spans (unless more accurate computed 

sag values are unavailable). The sag values used for the template may be determined as follows: 

a. For the ruling span and its sag under each appropriate design condition and temperature, 

calculate other sags by the relationship: 

( ) 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. 
Bulletin 1724E-200 

Page 10-6 

The template should be cut to include a minimum of one foot additional clearance than given in 

Table 4-1 (Chapter 4), to account for possible minor shifts in structure location and error in the 

plotted profile. Where the terrain or the surveying method used in obtaining ground profile is 

subject to greater unknowns or tolerances, the one foot additional clearance should be increased. 

The vertical offset between the upper two maximum temperature (hot) curves is equal to the total 

required clearance, including the specified additional clearance. It is shown as dimension "C" in 

Figures 10-3 and 10-4. The minimum temperature and the 60°F curves may be placed in any 

convenient location on the template. 

A sag template drawing similar to Figure 10-3, made to the same scales as the plan-profile 

sheets, should be prepared as a guide for cutting the template. This template is made for a 

specified conductor, ruling span, and loading condition. A new template should be prepared for 

each line where there is any variation in voltage, conductor size, loading condition, design 

tension, or ruling span. A change in any one of these factors may affect the design 

characteristics of the template. 

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 

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

5

5

0

5

6

6

0

5

7

7

0

5

8

8

0

5

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

5

5

0

5

6

6

0

5

7

7

0

5

8

8

0

5

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 10-7 

10.3.3 Sag Template Construction: The sag template should be made of dimensionally-stable 

transparent plastic material. A contrasting colored material (for example, red) is very helpful 

when the template is used to check plan-profile blueprint drawings. 

Curves are first plotted on paper using the correct scales and then reproduced or copied on the 

plastic material. To cut a template, the transparent material is fastened securely over the curves 

drawn on paper and the centerline and upper curves are etched lightly by a sharp-pointed steel 

scriber. The outside edges of the template should be etched deeply so that the template can be 

easily broken out and the edges sanded smooth. Structure height scales may also be drawn or 

etched on the sag template, or a separate template, for determining the pole height required for 

each type of structure used. Etched lines should be filled with ink to make them easier to see 

when the template is used. 

Conductor size, design tension and loading condition as well as ruling span and descriptive data 

for each curve should be shown on the template. 

10.4 Structure Spotting

10.4.1 General: Structure spotting is the design process which determines the height, location, 

and type of consecutive structures on the plan-profile sheets. Actual economy and safety of the 

transmission line depends on how well this final step in the design is performed. Structure 

spotting should closely conform to the design criteria established for the line. Constraints on 

structure locations and other physical limitations encountered may prevent spotting of structures 

at optimum locations. Success of the effort to minimize or overcome these special conditions 

can be judged by how closely the final line layout follows the original design parameters. 

Desired objectives of a well-designed and economical line layout are: 

a. Spans should be approximately uniform in length, equal to or slightly less than the design 

ruling span. Generally, differential conductor tensions are minimized and may be ignored if 

adjacent span lengths are kept below a ratio of 1.5 to 1. 

b. Maximum use should be made of the basic structure of equal height and type. The basic 

structure is the pole height and class which has been selected as the most economical structure 

for the given design condition. 

c. The shape of the running conductor profile, also referred to as the grading of the line, should 

be smooth. If the conductor attachment points at the structures lie in a smooth-flowing curve, 

the loadings are equalized on successive structures. 

For a generally level and straight line, with few constraints on structure locations, there is no 

conflict between these objectives. They can be readily achieved. Greater skill and effort are 

needed for lines with abrupt or undulating ground profile and for those where constraints on 

structure location exist. For example, there may be high or low points in the profile or features 

such as line angle points, crossings over highway, railroad, water, power and telecommunication 

lines, and ground with poor soil conditions. Structure locations and heights are often controlled 

or fixed by these special considerations. Alternative layouts between fixed locations may then 

be required to determine the best arrangement based on factors of cost and effective design. 

10.4.2 Design Factors for Structure Spotting: The following design factors are involved in 

structure spotting and are covered in the identified chapters of this bulletin: 
Bulletin 1724E-200 

Page 10-8 

a. Vertical Clearances (Chapter 4)

• Basic, level ground 

• Crossings 

• Side hill • Underbuild 

b. Horizontal Clearances • For insulator side swing condition (Chapter 7) • To edge of right-of-way, vertical obstructions and steep side hills (Chapter 5) 

c. Uplift (Chapter 12) 

d. Horizontal or Vertical Span Limitations Due to: • Vertical sag - clearance requirement (Chapters 4, 6) • Conductor separation (Chapter 6) • Galloping (Chapter 6) • Structure strength (Chapters 13, 14) • Crossarm strength (Chapter 13) 

e. Angle and Deadend (Chapter 14)

• Guying arrangements • Guy anchors 

10.4.3 Preparation: The following are necessary for structure spotting: 

• Plan-profile drawings of the transmission line, • Sag template of the same scale as the plan-profile prepared for the design temperatures, 

loading condition, and ruling span of the specified conductor and overhead ground wire, • Table of minimum conductor clearances over ground features and other overhead lines 

(Chapter 4), • Insulator swing charts (Chapter 7), • Horizontal and vertical span limitations due to clearance or strength requirements 

(Chapters 8, 9, and 13), and • Guy arrangement and anchor requirements for angle and deadend structures (Chapter 14). 

A height scale prepared for each structure type will aid in structure height determination. 

Supporting calculations should be summarized in chart or tabular form to facilitate application 

during structure spotting. This is especially advisable for the standard suspension structure 

which has a greater range of pole height and class, as well as bracing variations for H-frame 

structures. Selection of the proper pole may be affected by various criteria, such as spancontrolled-by-clearance or span-limited-by-pole-strength, for a given pole height and class or 

bracing. 

10.4.4 Process of Spotting: The process of spotting begins at a known or established conductor 

attachment point such as a substation take-off structure. For level terrain, the profile is 

essentially a straight line. When a sag template is held vertically and the ground clearance curve 

is held tangent to the ground profile, the edge of the template will intersect the ground line at 

points where structures of the basic height should be set. This relation is illustrated for a level 

span in Figure 10-4. Curve 1 (lowest conductor sag position) represents the actual sag of the 

conductor. Curve 2 (basic ground clearance curve) represents the actual position of the lowest 

conductor plus the required total ground clearance, "C." 
Bulletin 1724E-200 

Page 10-9 

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 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. 

F

 E

D

C

B

A

G

B

5

3 2 1

GROUND LINE G

C

D

 E

5

B

F

3 12

A

B

GROUND LINE G

C

D

 E

5

B

F

3 12

A

B

GROUND LINE G

C

D

 E

5

B

F

3 12

A

B

GROUND LINE G

C

D

 E

4 5

B

F

3 12

A

B

GROUND LINE
Bulletin 1724E-200 

Page 10-10 

10.4.5 Crossings: For spans-crossing features such as highway and power lines, with different 

clearance requirements than the normal clearance, the ground clearance curve should be adjusted 

accordingly. In California, adequate ground clearance has to be maintained over all railroads, 

major highways, major telecommunication and power lines when a broken conductor condition 

in either of the spans adjacent to the crossing span. Other states are governed by the NESC, 

which does not require the broken conductor condition. The increase in sag due to a broken 

conductor in an adjacent span is usually significant only where suspension-type structures are 

used at crossings and for voltage at 230 kV or above. For tension structures, and for suspension 

structures at lower voltages, the sag increase normally will not seriously affect the clearance. 

10.4.6 Insulator Side Swing - Vertical Span: Horizontal conductor clearances to supporting 

structures are reduced by insulator side swing under transverse wind pressure. This condition 

occurs where the conductor is supported by suspension-type insulators. Conductors supported 

by pin-type, post, or tension insulators are not affected and horizontal clearance of the deflected 

conductor position within the span becomes the controlling factor (see Chapter 5 of this 

bulletin). Suspension insulators also deflect laterally at line angle locations due to the transverse 

component of conductor tension. 

Chapter 7 covers the preparation of insulator swing charts. At each structure location the charts 

are used to determine if insulator swing is within the allowed limit for the vertical and horizontal 

spans and line angle conditions. For suspension insulators supported on horizontal crossarms, a 

minimum vertical span has to be maintained to avoid excessive side swing. To maintain 

adequate clearance for insulators attached directly to the pole, and for some types of angle 

structures, the vertical span cannot exceed a maximum value (as indicated by the insulator swing 

chart). See Figure 7-5 of this bulletin for an example swing angle chart for the TH-233 large 

angle structure. 

The vertical span is the distance between the conductor low points in spans adjacent to the 

structure. The horizontal span is the average value of the two adjacent spans to a structure. 

Where conductor attachments are at different elevations on adjacent structures, the low point is 

not at mid-span and will shift its position as the temperature changes. This shift can be readily 

seen by comparing the low point for the hot curve with its position for the cold curve. The 

vertical span value used to check the insulator swing should be based on the low point position 

which yields the most critical condition for the structure type. (See Chapter 7 for details on 

insulator swing) 

Where minimum vertical span or uplift is the concern, the cold curve should be used. The 

normal temperature is more critical and should be used if the vertical span is limited by a 

maximum value. Figure 10-6 shows some examples of the relationship of conductor low points 

and vertical spans which may occur in a line profile. 

If insulator swing is unacceptable, one of the following corrective steps, in order of preference, is 

recommended: 

a. 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. 

10.4.7 Uplift: Uplift is defined as negative vertical span and is determined by the same 

procedure as vertical span. On steeply inclined spans when the cold sag curve shows the low 

point to be above the lower support structure, the conductors in the uphill span exert upward 

forces on the lower structure. The amount of this force at each attachment point is related to the 
Bulletin 1724E-200 

Page 10-11 

weight of the loaded conductor from the lower support to the low point of sag. Uplift exists at a 

structure (see Structure No. 4 in Figure 10-6) when the total vertical span from the ahead and 

back spans is negative. Uplift has to be avoided for suspension, pin-type, and post insulator 

construction. For structures with suspension insulators, the check for allowable insulator swing 

is usually the controlling criteria on vertical span. A rapid method to check for uplift is shown 

by Figure 10-5. There is no danger of uplift if the cold curve passes below the point of 

conductor support on a given structure with the curve on the point of conductor support at the 

two adjacent structures. 

Designing for uplift, or minimizing its effects, is similar to the corrective measures listed for 

excessive insulator swing, except that adding of excessive weights should be avoided. Double 

deadends and certain angle structures can have uplift as long as the total force of uplift does not 

approach the structure weight. If it does, hold-down guys are necessary. 

Care should be exercised to avoid locating structures that result in poor line grading (see 

Paragraph 10.1.4a of this chapter). 

FIGURE 10-5: CHECK FOR UPLIFT 

10.4.8 Other Considerations: If maximum conductor tension or other limits are not exceeded, 

it may be preferable to use one long span with adequate conductor separation over a depression 

in the profile rather than use two short spans with a deadend structure at the bottom of the 

depression. A structure at the bottom of the depression may be subjected to considerable uplift 

at minimum conductor temperature. Also, poorer soil foundation conditions usually exist in the 

depression. 

Care has to be exercised at locations where the profile falls sharply away from the structure to 

see that the maximum allowable vertical span as limited by the strength of the crossarm or 

insulator is not exceeded. Structure No. 2 in Figure 10-6 illustrates this condition. For 

maximum accuracy in the heavy or medium loading zone, the vertical span for this purpose 

should be determined with a curve made for the sag under ice load, no wind, at 32°F. For most 

conductors, however, the maximum temperature final sag curve will closely approximate the 

Cold Curve

Cold Curve Uplift Exists at 

Center 

Structure

No Uplift at 

Center Structure, 

Check for Allowable 

Insulator Swing
Bulletin 1724E-200 

Page 10-12 

FIGURE 10-6: SAG LOW POINT, VERTICAL SPANS AND UPLIFT 

Structure N

o. 2

Vertical S

pan

1 2

3

5

7 Structure N

o. 4

U

plift

Structure N

o. 5 Vertical S

pan

4

6

Structure N

o. 1

Vertical S

pan

Structure N

o. 4

U

plift

Structure N

o. 5 Vertical S

pan

4

6

Structure N

o. 3

Vertical S

pan

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

Page 10-13 

curve for the ice-loaded conductor, and it may be used when checking for maximum vertical 

span. For guyed structures, the maximum vertical loads added to the vertical components from 

guy loads should be checked against the buckling strength of the pole 

The profile in rough country where side hills are encountered should be prepared so that the 

actual clearances under the uphill and downhill conductor may be checked. For some long spans 

it may be necessary to check side hill clearance with the conductors in their maximum transverse 

swing position. H-frame type structures installed on side hills may require different pole heights 

to keep the crossarm level or one pole may be set a greater than normal setting depth. 

Structures with adequate longitudinal strength (guyed deadends usually) are required at locations 

where longitudinal loading results from unequal line tensions in adjacent spans. For lines 

subject to heavy ice and high wind conditions and with long, uninterrupted section of standard 

suspension structures, consideration should be given to include some structures with in-line guys 

or other means to contain and prevent progressive, cascading-type failure. This is especially 

important for H-frame type structures with lower strength in the longitudinal direction when 

compared with its transverse strength. Measures to prevent cascading failures are also important 

for lines without overhead ground wire which tends to restrain the structure from collapsing 

longitudinally. A maximum interval of 5 to 10 miles is suggested between structures with 

adequate longitudinal capacity (guyed deadends usually), depending on the importance of the 

line and the degree of reliability sought. 

10.5 Other Design Data: Conductor and ground wire sizes, design tensions, ruling span, and 

the design loading condition should be shown on the first sheet of the plan-profile drawings. For 

completeness, it is preferable that these design data be shown on all sheets. A copy of the sag 

template reproduced on the first sheet could serve as a record of design in case the template is 

misplaced or lost. Design data for underbuild and portions of the line where a change in design 

parameters occurs should similarly be indicated. The actual ruling spans between deadends 

should be calculated and noted on the sheets. This serves as a check that the actual ruling span 

has not deviated greatly from the design ruling span. The significance of this deviation is also 

covered in the ruling span section of Chapter 9. Where spans are spotted at lengths less than 

one-half or over twice the ruling span, deadending may be required. 

As conductor sags and structures are spotted on each profile sheet, the structure locations are 

marked on the plan view and examined to insure that the locations are satisfactory and do not 

conflict with existing features or obstructions. To facilitate preparation of a structure list and the 

tabulation of the number of construction units, the following items, where required, should be 

indicated at each structure station in the profile view: 

• Structure type designation, 

• Pole height and class, 

• Pole top, crossarm, and brace assemblies, 

• Pole grounding units, 

• Miscellaneous hardware units (vibration dampers at span locations), and 

• Guying assemblies and anchors. 

The required number of units or items required should be shown in parenthesis if greater than 

one. Successive plan-profile sheets should overlap. For continuity, and to avoid duplicate count, 

the end structure on a sheet should be shown as a broken line on the following sheet. The 

number and type of guying assemblies and guy anchors required at angle or deadend locations, 

based on guying calculations or application charts, should also be indicated. Design check, line 

construction, and inspection are facilitated if an enlarged guying arrangement, showing 

attachments and leads in plan and elevation, is added on the plan-profile sheet adjacent to each 
Bulletin 1724E-200 

Page 10-14 

guyed structure. Any special notes or large-scale diagrams necessary to guide the construction 

should be inserted on the plan-profile sheet. This is important at locations where changes in line 

design or construction occur, such as a slack span adjacent to a substation, line transposition, or 

change in transmission and underbuild circuits. 

10.6 Drawing Check and Review: The completed plan-profile drawings should be checked to 

ensure that: 

• The line meets the design requirements and criteria originally specified, • Adequate clearances and computed limitations have been maintained, and • Required strength capacities have been satisfied. 

The sheets should be checked for accuracy, completeness, and clarity. Figure 10-7 is a Sample 

Check List for review of plan and profile sheets.
Bulletin 1724E-200 

Page 10-15 

Profile: ____________________________ Date: _______________________________ 

Line: ______________________________ Voltage: ______________ 

Plan and Profile Drawing Nos.___________ 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 10-16 

Blank Page 
Bulletin 1724E-200 

Page 11-1 

11. LOADINGS AND LOAD FACTORS

11.1 General: The strength to be designed into a transmission line depends to a large extent on 

wind and ice loads that may be imposed on the conductor, overhead ground wire and supporting 

structure. These loadings are related generally to the geographical location of the line. 

When selecting appropriate design loads, the engineer should evaluate climatic conditions, 

previous line operation experience and the importance of the line to the system. Conservative 

load assumptions should be made for a transmission line which is the only tie to important load 

centers. 

The 2007 NESC indicates that structure and component strength should take into account 

temporary loads. Temporary loads imposed on a structure or component may include lifting of 

equipment, stringing operations, or a worker on a structure or component. This design manual 

does not address temporary loads. 

The alternate method in the 2007 NESC has not been included in this design manual. The 

alternate method will not be used after July 31, 2010. 

11.2 Loads

11.2.1 NESC Loading Districts: The NESC divides the country into three weather or loading 

districts, as shown in Figure 11-1. 

FIGURE 11-1: NESC LOADING DISTRICTS 

Reproduced from IEEE/ANSI C2, 2007, “National Electrical Safety Code,”Copyright 2001 by the 

Institute of Electrical and Electronic Engineers, Inc., with permission of the IEEE. 
Bulletin 1724E-200 

Page 11-2 

The minimum design conditions associated with each loading district are given in Table 11-1. 

Constants in this table are to be added to the vector resultant for tension calculations only. 

TABLE 11-1 

ICE, WIND, TEMPERATURE, AND CONSTANTS 

NESC Loading Design 

Temp. 

(Fo) 

Radial Ice 

Thickness

(inches) 

Wind 

Loading 

Constants

(lbs/ft) 

Heavy 0° 0.50 4 psf 0.30 

Loading District Medium 15° 0.25 4 psf 0.20 

Light 30° 0 9 psf 0.05 

Extreme Wind 60° 0 See 

Figure 11-2 NA 

Extreme Ice with Concurrent Wind 15° See Figure 

11-3 

See Figure 

11-3 NA 

Designing to these minimum requirements may not be sufficient. Extreme winds and special ice 

conditions should be investigated. Determination of an appropriate design load to account for 

extreme winds is easier than determining a heavy ice design load. Meteorological data may be 

available on high winds, but little data is available on extreme ice loads. Heavy ice combined 

with a relatively high wind should also be considered. 

11.2.2 Extreme Ice: In certain areas of the country heavy ice may be predominant. The 

engineer should review the experience of utilities or cooperatives in the area of the line 

concerning ice conditions. The number and frequency of outages in the area due to ice storms, 

and the design assumptions used for existing lines in the area should be examined. From this 

data, the engineer can reasonably decide if a heavy ice condition greater than what is required by 

the NESC needs to be included in the design. 

If historical data on icing conditions is lacking, the engineer should consider designing the line 

for extreme wind conditions without ice, and for loading zone conditions. The engineer would 

then calculate the maximum ice load the structure could sustain without wind and evaluate this 

specific ice condition. 

11.2.3 Extreme Winds: Although the NESC requires that structures over 60 ft. sustain high 

winds, Rural Utilities Programs recommends that all transmission lines meet extreme wind 

requirements. Required values for temperature and wind are listed in Table 11-1 and Figure 11-

2. The NESC allows linear interpolation when considering locations between isotachs. Local 

meteorological data should also be evaluated in determining a design high wind speed. For wind 

speeds other than a 50 year recurrence interval, refer to Appendix E. 

Equations in Tables 250-2 and 250-3 of the NESC have been incorporated in computer programs 

as part of the structure analysis. These equations are included in the definitions for the variables 

in Equations 11-1 and 11-2 of this bulletin. Tables 11-2, 11-3, 11-4 and 11-5 provide calculated 

values for the parameters in these equations. 
Bulletin 1724E-200 

Page 11-3 

Equation 11-1 should be used to calculate the load in the unit wind load on a circular wire in 

pounds per linear foot. 

p = 0.00256 * V2 * kz * GRF * d / 12 Eq. 11-1 

 p = unit load per unit foot, lbs./ft. 

V = Basic Wind Speed, 3 –second gust wind speed in miles 

per hour at 33 ft. above ground with an annual 

probability of .02 (50 year return period), Figure 11-2 

kZ = Velocity Pressure Exposure Coefficient, shown in 

Table 11-2 or by the equation: 

kz = 2.01(h/900)(2/9.5) where h = height of the wire at 

the structure and is between 33 feet and 900 feet 

GRF = Gust Response Factor, shown in Table 11-3 or by the 

equation: GRF = [1+(2.7Ew 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 

TABLE 11-3 

WIRE GUST RESPONSE FACTOR, GRF

Height of Wire At Wire, GRF, for Various Span Lengths in feet 

the Structure 

h (ft.) 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 
Bulletin 1724E-200 

Page 11-4 

TABLE 11-4 

COMBINED FACTOR kZ*GRF 

FOR COMMON WIRE HEIGHTS 

Height of Wire At Wire, GRF, for Various Span Lengths in feet) 

the Structure 

h (ft.) 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 

 

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/(0.67-h)1/7 and 

Bs = 1/(1+0.8L/220) 

kv = 1.43 

h = height of the structure above groundline 

L = design wind span (also known as HS) 

Cf = drag coefficient 

A = projected wind area in square feet 

TABLE 11-5 

 STRUCTURE kZ, GRF , and COMBINED kZ GRF Factor 

Height of 

Structure, ft kZ GRF

Combined 

’kZ GRF’ 

factor 

≤ 33 0.92 1.02 0.94 

34 – 50 1.00 0.97 0.97 

51 – 80 1.10 0.93 1.02 

81 – 115 1.20 0.89 1.07 

116 – 165 1.30 0.86 1.12 
Bulletin 1724E-200 

Page 11-5 

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

 GROUND (50-year mean recurrence interval) 

Reproduced with permission from ASCE 7-05, “Minimum Design Loads for Buildings and Other Structures,” 

American Society of Civil Engineers, copyright 2005. For further information, refer to the complete text of the 

manual (http://www.pubs.asce.org/ASCE7html?999913330).
Bulletin 1724E-200 

Page 11-6 

FIGURE 11-2b: EXTREME WIND SPEED IN MILES PER HOUR 

 AT 33 FT. ABOVE GROUND 

(50-year mean recurrence interval) 

Reproduced with permission from ASCE 7-05, “Minimum Design Loads for Buildings and Other Structures,” 

American Society of Civil Engineers, copyright 2005. For further information, refer to the complete text of the 

manual (http://www.pubs.asce.org/ASCE7html?999913330).

Notes: 

1. Values are nominal design 3-second gust wind speeds in miles per hour at 33 ft. 

above gound for Exposure C category. 

2. Linear interpolation between wind contours is permitted. 

3. Islands and coastal area outside the last contour shall use the last wind speed 

contour of the coastal area. 

4. Mountainous terrain, gorges, ocean promontories, and special wind regions shall be 

examined for unusual wind conditions.

Special Wind LocationRegion V mph

Hawaii 105 

Puerto Rico 145 

Guam 170 

Virgin Islands 145 

American Samoa 125 
Bulletin 1724E-200 

Page 11-7 

FIGURES 11-2c,11-2d: EXTREME WIND SPEED IN MILES PER HOUR AT 33 FT.ABOVE 

GROUND FOR THE NORTHEAST AND SOUTHEAST 

(50-year mean recurrence interval) 

Reproduced with permission from ASCE 7-05, “Minimum Design Loads for Buildings and Other Structures,” 

American Society of Civil Engineers, copyright 2005. For further information, refer to the complete text of the 

manual (http://www.pubs.asce.org/ASCE7html?999913330).

Figure 11-2d

Notes: 

1. Values are nominal design 3-second gust wind 

speeds in mph at 33 ft above ground for 

Exposure C category. 

2. Linear interpolation between wind contours is 

permitted. 

3. Islands and coastal area outside the last contour 

shall use the last wind speed contour of the 

coastal area. 

4. Mountainous terrain, gorges, ocean 

promontories, and special wind regions shall be 

examined for unusual wind conditions. 

Figure 11-2c 
Bulletin 1724E-200 

Page 11-8 

FIGURES 11-2e: EXTREME WIND SPEED IN MILES PER HOUR AT 33 FT ABOVE 

GROUND FOR TEXAS, LOUISIANA AND MISSISSIPPI 

(50-year mean recurrence interval) 

Reproduced with permission from ASCE 7-05, “Minimum Design Loads for Buildings and Other Structures,” 

American Society of Civil Engineers, copyright 2005. For further information, refer to the complete text of the 

manual (http://www.pubs.asce.org/ASCE7html?999913330).

11.2.4 Extreme Ice with Concurrent Wind Loads: The NESC requires that structures over 60 

ft. be designed to withstand the ice and wind loads associated with the Uniform Ice Thickness 

and Concurrent Wind Speed specified in NESC Figure 250-3 and in Figures 11-3a to 11-3d of 

this bulletin; however, it is recommended that all transmission lines meet these requirements. 

Required values for temperature, ice and wind are listed in Table 11-1. 

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 11-9 

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

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

Reproduced with permission from ASCE 7-05, “Minimum Design Loads for Buildings and Other Structures,” 

American Society of Civil Engineers, copyright 2005. For further information, refer to the complete text of the 

manual (http://www.pubs.asce.org/ASCE7html?999913330).

Fig 11-3f 

Fig 11-3e 
Bulletin 1724E-200 

Page 11-10 

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

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

Reproduced with permission from ASCE 7-05, “Minimum Design Loads for Buildings and Other Structures,” 

American Society of Civil Engineers, copyright 2005. For further information, refer to the complete text of the 

manual (http://www.pubs.asce.org/ASCE7html?999913330).

Figure 11-3d 
Bulletin 1724E-200 

Page 11-11 

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

CONCURRENT 3-SECOND GUST WIND SPEEDS FOR ALASKA 

(50 year mean recurrence interval) 

Reproduced with permission from ASCE 7-05, “Minimum Design Loads for Buildings and Other Structures,” 

American Society of Civil Engineers, copyright 2005. For further information, refer to the complete text of the 

manual (http://www.pubs.asce.org/ASCE7html?999913330).
Bulletin 1724E-200 

Page 11-12 

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

CONCURRENT 3-SECOND GUST WIND SPEEDS FOR LAKE SUPERIOR 

(50 yr. mean recurrence) 

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

CONCURRENT 3-SECOND GUST WIND SPEEDS FOR FRASER VALLEY DETAIL 

(50 yr. mean recurrence) 

Reproduced with permission from ASCE 7-05, “Minimum Design Loads for Buildings and Other Structures,” 

American Society of Civil Engineers, copyright 2005. For further information, refer to the complete text of the 

manual (http://www.pubs.asce.org/ASCE7html?999913330).
Bulletin 1724E-200 

Page 11-13 

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

CONCURRENT 3-SECOND GUST WIND SPEEDS FOR COLUMBIA RIVER GOUGE 

(50 yr. mean recurrence) 

11.2.5 Longitudinal Loads: Unbalanced longitudinal loads on a line may occur because of: 

• Unequal wind load and/or differential ice • A broken wire 

conditions on equal or unequal spans • 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 2002 

edition of the NESC recommends that structures having a longitudinal strength capability be 

provided at reasonable intervals along the line. 

Several methods to reduce the risk of cascading transmission line structures due to broken wires 

have been recommended in the American Society of Civil Engineers (ASCE) Manual and 

Report on Engineering Practice No. 74 “Guidelines for Electrical Transmission Line Structural 

Loading,” copyright 1991. They are summarized below. 

Method 1, Install “Stop” Structures at Specified Intervals: This method consists of placing 

deadend structures, longitudinal guys, or regular tangent structures designed to resist deadend 

loads at intervals along the line to limit the number of cascading structures to a manageable 

number. This method is most practical for H-frames or narrow-based lattice towers which do 

not possess enough inherent longitudinal capacity to resist longitudinal loads. In these cases, 

stop structures are used because the cost to strengthen each structure to resist cascading may be 

high and the addition of guys at each structure may not be desirable. 

Reproduced with permission from ASCE 7-05, “Minimum Design Loads for Buildings and Other Structures,” 

American Society of Civil Engineers, copyright 2005. For further information, refer to the complete text of the 

manual (http://www.pubs.asce.org/ASCE7html?999913330).
Bulletin 1724E-200 

Page 11-14 

Method 2, Install Release Mechanisms: Slip or release-type suspension clamps may be used as 

“fuses” to limit the longitudinal loads applied by broken wires. This is actually very similar to 

Method 1. The major difference between Method 1 and this Method is that “fuses” are used to 

minimize the unbalanced loads used to design each structure. The structures also have to be 

capable of withstanding construction and maintenance loads without endangering line crew 

personnel. Where heavy ice buildups are frequent, this could be an insurmountable problem. 

As such, this method is not recommended in areas of heavy ice, since unbalanced ice loads 

could result in unexpected failures. 

Method 3, Design All Structures for Broken Wire Loads: Rigid lattice towers, guyed tangents 

(guyed in four directions) and single-shaft pole structures have an inherent longitudinal capacity. 

In many instances, such structures can be economically designed to resist longitudinal loads. 

The loads are typically based on the “residual static load” (RSL). The RSL is a load at a wire 

support after breaking one phase or a ground wire under every day conditions (no ice, no wind, 

60oF). Considerations in determining the RSL include insulator swing, structure deflection and 

suspension clamp slippage. Some designers have used 60 percent to 70 percent of the every day 

tension for conductors and 100 percent of the every day tension for ground wires. The suggested 

longitudinal loading consists of applying RSLs in one direction to a nominal one-third of 

conductor support points or to one (or both) ground wire support point(s). The suggested 

vertical loading consists of one-half or more of the vertical load(s) imposed by the broken 

wire(s) along with all of the vertical loads imposed by the other intact wires. Although every 

structure is designed to resist cascading, in the event of the catastrophic loss of a single structure, 

localized failures in adjacent structures should be expected. 

A blend of Methods 2 and 3 would involve designing the main body of the structure (or pole) for 

slightly larger longitudinal loads than those used for the design of the support arms and/or 

ground wire peak. The idea is to limit the loads applied to the body of the structure (or pole) by 

“sacrificing” the arms or ground wire peak, thereby reducing the number of poles damaged from 

a broken wire event and decrease the likelihood of an unmanageable cascade. If such a event 

occurred, it could result in damage to several (perhaps numerous) support arms and/or ground 

wire peaks. 

11.2.6 Example of Extreme Wind Calculations: A proposed 161 kV line using the TH-10 

structure is expected to have spans ranging from 501 to 900 feet and to be composed of 

structures with wood poles 60 to 90 feet high. The line is expected to be located in northern 

Mississippi and will have a 795 26/7 ACSR conductor. Calculate the extreme wind load to be 

used in the design. 

Extreme wind calculations are made for wind on the wires and wind on the structure. For wind 

on the wires, the engineer should calculate the wind on the overhead groundwires and the wind 

on the conductors. For wind on the overhead groundwires, a review of Table 11-4 indicates that 

0.9 to 0.85 is to be used for the combined factor of kZ*GRF’ for spans 501 to 1000 feet and for 

wire heights 52 feet to 79 feet above ground (for structures using 60 to 90 foot poles). The 

conductors on the TH-10 are located approximately 13 feet from the top of the pole. The height 

from the ground to the conductors at the structure will range from 39 to 63 feet above ground. . 

For wind on the conductors, review of Table 11-4 indicates that values of 0.9 to 0.79 may be 

used as the combined factor of ‘kZ*GRF’ for spans 501 to 900 and for wire heights 39 to 63. 

(Poles are 52 feet to 79 feet above ground). 

For wind on the structures, use Table 11-5. For structures of heights 52 to 79 feet above ground, 

Table 11-5 indicates that the combined ‘kZ*GRF’ factor for the structure is 1.02. 

Wind pressure (psf) on the overhead groundwires: 
Bulletin 1724E-200 

Page 11-15 

p = 0.00256 * V2 * kz * GRF 

p = 0.00256 * 902 * 0.9 

p = 18.66 psf; use 19 psf in design 

Wind pressure (psf) on the conductors: 

p = 0.00256 * V2 * kz * GRF 

p = 0.00256 * 902 * 0.9 

p = 18.66 psf; use 19 psf in design 

Wind pressure (psf) on the structure: 

 p = 0.00256 * V2

 * kz * GRF 

 p = 0.00256 * 902 * 1.02 

 p = 21.15 psf; use 22 psf in design 

For 21 psf, the unit trnasverse load on the conductor pt = 1.9390 lbs/ft (Appendix B) 

Therefore, for 19 psf, the unit load will be 1.7543 lbs/ft (or 1.9390x19/21) 

11.2.7 Example of Extreme Ice/Wind Calculations: 

Using the same example line in the previous paragraph (11.2.6), the line located in northern 

Mississppi has a combined ice and wind load of .75inch of ice and a 30 psf wind. Calculate the 

transverse and vertical unit loads on the conductor. 

For the transverse unit load: 

The diameter of the conductor including ice = 1.108 in (Appendix B) + (.75x2) = 2.608 in.. 

The unit wind load on the conductor pt = 30 lbs/ft2

 x 2.608 inches/12in/ft x 1ft = 6.520 lbs/ft 

For the vertical unit load: 

The vertical unit load, wc, is the dead weight of the conductor plus the ice load per foot of 

conductor = 1.0940 lbs/ft + [3.1416((1.108+(2x.75))2 – (1.108) 2)/4/144 x 1 ft] x 57 lbs/ft3 = 

2.8269 lbs/ft 

11.3 Load Factors for New Construction: Agency transmission lines are to be built to 

Grade B construction. In Table 11-6, the columns under the Rural Utilities Service headings 

give the recommended minimum load factors to be applied to the light, medium, and heavy 

loading districts of the NESC and also the recommended strength factors to be applied in the 

design of guys, anchors, crossarms, and structures. 

Recommended load factors and strength factors to be applied to extreme wind loadings are in 

Table 11-7. The factors are intended to take into account approximations made in the design and 

analysis. 
Bulletin 1724E-200 

Page 11-16 

11.4 Application of Load Factors and Strength Factors: In the application of the load factors 

and strength factors, the objective is to design a structure with resistance greater than the 

maximum load expected during the lifetime of the structure and to design the structure with an 

acceptable level of safety and reliability. The use of load factors and strength factors can be 

expressed as follow: 

ØR > (LF)Q Eq. 11-3

where: 

R = 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. 

11.4.1 Example Calculation Showing the Use of Strength and Load Factors: 

A Douglas fir, 80 ft. tangent pole is to sustain a 750 lbs. transverse load two feet from the top. 

Assume this load is based on NESC heavy loading district loads. What class pole should be used 

for this construction? The pole is embedded 10 feet. The length of the moment arm used to 

calculate the induced moment at groundline is 68 feet. 

In this case, R is the moment capacity of the pole at groundline and ‘Q’ is the horizontal load 

(750 lbs.). Using the strength factors (Ø) and load factors (LF) from Table 11-6, Equation 11-3 

becomes: 

ØR > (LF)Q 

0.65MMoment capacity at the groundline > 2.50(750 lbs)(68 feet) 

 MMoment capacity at the groundline > 196,154 ft.-lbs 

The pole should have a moment capacity of 196 ft-kips at the groundline. A class 3 Douglas fir 

pole would provide this moment capacity at the groundline. 

11.4.2 Additional Examples Showing the Application of Loads and the Use of Strength and 

Load Factors: Chapters 13 and 14 demonstrate the application of strength and load factors in 

the structural analyses examples. 
Bulletin 1724E-200 

Page 11-17 

TABLE 11-6 

RECOMMENDED LOAD FACTORS AND STRENGTH FACTORS 

TO BE APPLIED TO NESC DISTRICT LOADS 

(Grade B New Construction) 

(NESC Tables 253-1 and 261-1A) (Note 5) 

FACTORS NESC RUS

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 Poles (Note 4) 0.65 0.65 

Wood Crossarms (Note 4) 0.65 0.50 

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 that 2/3 of that required when installed for the life of the line. 

5. When calculating the additional moment due to deflection, deflections should be calculated 

using loads prior to application of the load factor. 

6. Conductor Support Hardware is any hardware not a part of the structure, guy assembly, or 

guy attachment. Conductor support hardware may be splices, extension links, insulator 

string yokes, y-clevis balls, ball hooks, deadend clamps, etc. 
Bulletin 1724E-200 

Page 11-18 

TABLE 11-7 

RECOMMENDED LOAD FACTORS AND STRENGTH FACTORS 

TO BE APPLIED TO EXTREME WIND LOADS (Rule 250C of the NESC) 

AND TO EXTREME WIND/ICE LOADS (Rule 250D of the NESC) 

(Grade B New Construction) 

(NESC Tables 253-1 and 261-1A) (Note 5) 

FACTORS NESC RUS

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 Poles (Note 4) 0.75 0.75 

Wood Crossarms (Note 4) 0.75 0.65 

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 that 2/3 of that required when installed for the life of the line. 

5. When calculating the additional moment due to deflection, deflections should be calculated 

using loads prior to application of the load factor. 

6. Conductor Support Hardware is any hardware not a part of the structure, guy assembly, or 

guy attachment. Conductor support hardware may be splices, extension links, insulator 

string yokes, y-clevis balls, ball hooks, deadend clamps, etc. 
Bulletin 1724E-200 

Page 12-1 

12. FOUNDATION STABILITY OF DIRECT-EMBEDDED POLES

12.1 General: Every structure standing above ground is subjected to lateral forces. In the case 

of direct-embedded wood, steel or prestressed concrete transmission structures, it is desirable to 

depend on the earth to resist lateral forces. The embedded portion of a pole provides this 

resistance by distributing the lateral load over a sufficient area of soil. A properly selected 

embedment depth should prevent poles from kicking out. With time, single poles may not 

remain plumb. Leaning of single pole structures is sometimes permitted, provided excessive 

angular displacements are avoided, pole strength is adequate considering additional loads from 

the pole being out of plum and adequate clearances are maintained. 

The lateral forces to which wood transmission structures are subjected are primarily forces due 

to wind and wire tension loads due to line angles. Longitudinal loads due to deadending or 

uniform ice on unequal spans should be examined to see how they affect embedment depths. 

Normally, flexible transmission structures are stabilized longitudinally by the overhead ground 

wire and phase conductors. 

Bearing and lateral earth capacity of soils depend on soil types and soil characteristics such as 

internal friction, cohesion, unit weight, moisture content, gradation of fines, consolidation and 

plasticity. Most soils are a combination of a cohesive soil (clay) and cohesionless soil (sand). 

12.2 Site Survey 

12.2.1 Soil Borings: Depending on the transmission line and knowledge of the soil conditions 

along the corridor, soil borings may or may not be taken. If the line is composed of H2 or higher 

class wood poles, or equivalent strength steel or concrete poles, the engineer may elect to take 

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

Variation of the soil will determine the frequency of the borings. Borings might also be 

considered at unguyed angle structures and deadend structures composed of steel or concrete 

poles. 

12.2.2 Embedment Depths: In deciding embedment depths for many typical agency borrower 

wood pole construction, economics dictate that few, if any, soil borings be taken when data and 

experience from previous lines are available. Numerous soil conditions will be encountered in 

the field. Although the soil conditions may closely resemble each other, the soils may have a 

wide range of strengths. The engineer, therefore, has to identify areas or conditions where pole 

embedment depths in soil may have to be greater than the minimum depth of 10 percent, plus 2 

feet. 

Areas where the designer needs to consider additional embedment depths include (but are not 

limited to): 

• Low areas near streams, rivers, or other bodies of water where a high water table or a 

fluctuating water table is probable. Poles in a sandy soil with a high water table may 

"kick" out. Due to the lubricating action of water, frictional forces along the surface area 

of embedded poles are reduced. The legs of H-frames may "walk" out of the ground if 

neither sufficient depth nor bog shoes are provided to resist uplift. Guy anchors may fail 

if the design capacity does not consider the submerged weight of the soil. 

• Areas where the soil is loose such as soft clay, poorly compacted sand, pliable soil, or 

soil which is highly organic in nature. 
Bulletin 1724E-200 

Page 12-2 

• Locations where higher safety is desired. This may be at locations of unguyed small 

angle structures where a portion of the load is relatively permanent in nature, or at river, 

line, or road crossings. 

• Locations where poles are set adjacent to or on steep grades. 

• Locations where more heavily loaded poles are used. 

• Locations where underground utilities such as water or sewer will be located next to the 

pole. 

12.2.3 Field Survey: A field survey is necessary in order to judge whether a soil is "good," 

"average," or "poor." There are several economical methods to make a field survey for wood 

transmission lines. The engineer may use a hand auger, light penetrometer, or torque probe. The 

meaning of terms such as firm, stiff, soft, dense, and loose may not always be clear. Table 12-1 

will help to clarify these terms: 

TABLE 12-1 

CLASSIFICATION OF SOILS BASED ON FIELD TESTS 

Term 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 

 

12.3 Pole Stability

12.3.1 Wood Poles: In addition to local experience with wood poles, the graphs in Figures 12-1 

through 12-3 may be used to approximate embedment depths. To use the charts, good, average, 

and poor soils have to be defined. The following are proposed as descriptions of good, average, 

and poor soils: 

Good: Very dense, well graded sand and gravel, hard clay, dense, well graded, fine and coarse 

sand. 

Average: Firm clay, firm sand and gravel, compact sandy loam. 

Poor: Soft clay, poorly compacted sands (loose, coarse, or fine sand), wet clays and soft clayey 

silt 
Bulletin 1724E-200 

Page 12-3 

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

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. 

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 ( bl s.)

40'

60'

90'

Embedment Depth (ft.)

POOR SOIL

0
Bulletin 1724E-200 

Page 12-4 

FIGURE 12-2: EMBEDMENT DEPTHS IN AVERAGE SOIL 

FIGURE 12-3: EMBEDMENT DEPTHS IN GOOD SOIL 

AVERAGE SOIL

7 10 8 9

Embedment Depth (ft.)

L

o

a

d

2' fr

o

m th

e to

p ( bl s.)

10,000

40'

60'

90'

8,000

6,000

4,000

2,000

0

5 6

L

o

a

d

2' fr

o

m th

e to

p (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 12-5 

FIGURE 12-4: EMBEDMENT CHART FOR MEDIUM DRY SAND 

 AGENCY BULLETIN 1724E-205 “EMBEDMENT DEPTHS 

 FOR CONCRETE AND STEEL POLES” 
Bulletin 1724E-200 

Page 12-6 

12.3.2 Direct Embedded Steel and Concrete Poles: In agency Bulletin 1724E-205, 

“Embedment Depths for Concrete and Steel Poles,” embedment charts are provided for concrete 

and steel transmission poles sustaining relatively large overturning moments. The information in 

Bulletin 1724E-205 may be used to approximate embedment depths for cost estimates, to make 

preliminary selection of embedment depths and to verify or check selection of embedment 

depths based on other or more exact methods. Sample calculations illustrating the use of the 

embedment charts and illustrating the use of design methods for those occasions when the charts 

cannot be used, are also provided in Bulletin 1724E-205. 

In that bulletin, nine embedment charts have been developed for nine soil types. These charts 

show embedment depths for pole diameters ranging from 1.0 to 4.0 feet and ultimate moments at 

groundline up to 3500 ft-kips. A sample chart for medium sand is shown in Figure 12-4 of this 

bulletin. 

Several computer programs exist for determining embedment depths for steel and concrete poles.

Such programs may provide a more efficient selection of embedment depths in preliminary 

design and their use should be considered in any final design. 

12.3.3 Replumbing: If a search of previous experience in an area indicates that single pole 

lines have had to be replumbed, there are several methods which should be considered in order 

to reduce the frequency of replumbing of a new line to be located in the same area. These 

methods are as follows: 

• Use a lower grade species of wood in order to increase embedment diameters. For 

instance, embedment diameters for Class 1 Western red cedar poles will be greater than 

embedment diameters for Douglas fir. • Use aggregate backfill. • Install a pole key with or without a pole toe of crushed stone, gravel, or concrete. • Embed one foot deeper (or more). • In the case of more heavily loaded steel and prestressed concrete poles, consideration 

should be given to the use of concrete backfill. 

12.4 Bearing Capacity: To prevent a guyed pole from continually sinking into the ground due 

to induced vertical loads, the pole butt should provide sufficient bearing surface area. If little 

soil information is available, local building codes (Table 12-2) might be helpful in determining 

allowable bearing capacities. These values are usually conservative and reflect the hazards 

associated with differential deflection in a building. Fortunately, transmission lines can sustain 

deflections on the order of several times that of buildings without detrimentally affecting their 

performance. The bearing capacity of guyed poles is not as critical as that for buildings. Good 

engineering judgment and local experience should be used in determining if bearing capacities of 

a certain soil will be exceeded by guyed poles. Table 12-3 suggests ranges of ultimate bearing 

capacities. 
Bulletin 1724E-200 

Page 12-7 

TABLE 12-2 

PRESUMPTIVE ALLOWABLE BEARING CAPACITIES, ksf 

Soil Description 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 

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.
Bulletin 1724E-200 

Page 12-8 

12.5 Uplift: When H-frame structures with X-braces are subject to overturning forces, one leg 

will be in compression and one leg in tension. The skin friction assumed in design should be 

based on past experience encountered by the engineer, experience of nearby lines, and the results 

of the field survey. The following may be appropriate for average soil: 

• If the soil is wet or subject to frequent wettings, an ultimate skin friction not greater than 

100 psf should probably be assumed; 

• If native soil is used as backfill, an ultimate skin friction between 100 and 500 psf should 

be assumed, provided the soil is not subject to frequent wettings; 

• If an aggregate backfill is used, an ultimate skin friction between 250 and 1000 psf may 

be possible; 

• Pole "bearing" shoes increase uplift capacity of a dry hole with natural backfill on the 

order of 2 to 2.5 times. The use of aggregate backfill with bearing shoes is usually not 

necessary provided the native backfill material is of relatively good material; and 

• In many cases, double cross-braced H-frame structures may require uplift shoes. 

12.6 Construction - Backfill: Lateral and uplift resistance of wood poles will depend not only 

on type of soil, moisture content of the soil, depth of setting, but also on how well the backfill 

has been tamped. 

All water should be removed before backfilling. If native backfill material is to be used, it 

should be free of grass, weeds, and other organic materials. If the dirt removed from the hole is 

too wet or has frozen, dry, unfrozen material should be obtained for the backfill. Where the 

earth removed from the hole is unsuitable as backfill, special backfill should be specified by the 

engineer. Drawing TM-101 included in agency Bulletins 1728F-810 and 811 suggests a 

gradation of aggregate to be used as backfill material. 

When backfilling, the soil should be placed and compacted in shallow layers (approximately 6 

inch layers). Each layer should be compacted until the tamp makes a solid sound as the earth is 

struck. Power tamping is preferred using two power tampers and one shoveler. The importance 

of proper compaction of the backfill cannot be overemphasized. Insufficient tamping is a 

common source of trouble and has been the cause of some failures. 
Bulletin 1724E-200

Page 13-1 

13. STRUCTURES

13.1 Economic Study: During preliminary planning stages of lines above 161 kV, studies 

should be made to evaluate the economics of different types of structures as related to conductor 

size. In most instances, for lines of 230 kV and below, wood structures have historically been 

the economical choice. However, in more heavily loaded situations (larger wires, longer spans) 

steel and prestressed concrete structures may be more economical than wood, especially 

considering the long-term maintenance costs associated with wood structures. In some instances, 

other types of material have been used because of environmental or meteorological constraints. 

For voltages 345 kV and above, it may be difficult to obtain long span construction utilizing 

wood, due to height or strength reasons. 

In most instances, for lines 230 kV and below, an economic study can help to determine 

structure configuration, base pole class (wood, steel or prestressed concrete) and height. 

Factors which limit structure spans include: 

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

crossarms, structure strength. For H-frame structures, horizontal and vertical spans are also 

limited by pullout resistance for H-frame structures. 

b. Conductor Separation: Conductor separation is intended to provide adequate space for line 

crew personnel on poles, prevention of contact and flashover between conductors. 

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

d. Insulator Swing: The ratio of horizontal to vertical span will be limited by insulator swing and 

clearance to structure. 

Historically, preliminary cost estimates have been usually based on level ground spans. With the 

advent of computer-automated line design and optimization software, preliminary cost estimates 

can now be performed using a preliminary profile digitized from the United States Geological 

Survey (USGS) topographic maps or from other sources. An economic study should consider 

material costs, cost of foundations and erection, different structure heights, hardware costs, and 

right-of-way costs. The estimates are intended to give borrowers an idea as to relative rankings 

of various structure types and configurations such as steel lattice, steel pole, prestressed concrete 

pole, and wood H-frame or single pole. However, in the decision-making process, the manager 

may want to consider as part of the evaluation such intangibles as importance of the line to the 

power system, appearance, material availability, and susceptibility to environmental attack. In 

some areas, State or local constraints may ignore economics and specify the type of structure to 

be used. 

The level ground span used to develop preliminary cost estimates in the economic study is 

determined from clearance-to-ground and structure strength. Developing a graph, as shown in 

Figure 13-1, is one means of determining the level ground span (points A and B). Structure cost 

per mile can be related to pole height and class of poles as shown in Figure 13-2. To keep the 

cost down, the line design should be based on one tangent structure type and one or two pole 

classes for the majority of the line. For H-frame structures, the engineer should consider double 

crossbraced structures, as well as single crossbraced structures. 

With the help of computer automated line design and optimization software, an economic study 

can be accomplished almost concurrently with the line design. If a land profile is available, or 

developed from USGS maps, the line designer may want to use optimization software to help 
Bulletin 1724E-200 

Page 13-2 

determine the most economic line design. With such software, different structure types and 

materials and different conductor types can be evaluated. An advantage of optimization software 

is the use of the actual terrain (rather than level ground span) or a good approximation of the 

terrain. Optimization algorithms can fit structure height and type to the terrain, and can make 

use of different structure heights and configurations. The major disadvantage of optimization 

software is that it requires input and analysis of large amounts of data. 

FIGURE 13-1: SELECTION OF LEVEL GROUND SPAN 

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

13.2 Steel and Concrete Structures - General Design Considerations: Rural Utilities Service 

provides several bulletins on design considerations for steel and concrete pole structures. 

• 1724E-204, “Guide Specifications for Steel Single Pole and H-Frame Structures,” 

• 1724E-214, “Guide Specification for Standard Class Steel Transmission Poles,” 

• 1724E-206, “Guide Specification for Spun, Prestressed Concrete Poles and Concrete Pole 

Structures,” 

• 1724E-216, “Guide Specification for Standard Class Spun, Prestressed Concrete 

Transmission Poles.” 

The bulletins include sample purchase specifications, design considerations, and suggested 

drawings and example design calculations. 

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 

13.3 Wood Structures - General Design Considerations

13.3.1 Stress Limitations: The structural stress limitations set forth in Table 13-1 are 

recommended for transmission lines using agency standard wood pole construction. These 

values assume that the wood has not deteriorated due to decay occurring in the manufacturing 

process. 

TABLE 13-1 

DESIGNATED STRESSES FOR POLES 

Kind of Wood 

Modulus of 

Elasticity x 1000 

(psi) 

Designated Ultimate 

Bending Stress 

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

Western larch 1710 8400 

Southern yellow pine 1800 8000 

Douglas fir 1920 8000 

Lodgepole pine 1340 6600 

Jack pine 1220 6600 

Red (Norway) pine 1800 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

13.3.2 Preservative Treatment: The decay of poles results from fungi and other low forms of 

plant life which attack untreated poles or poles with insufficient preservative. Damage by insect 

attack (termites, ants, and wood borers) is also associated with decay. When preservative 

retention is low, wood cannot resist attacks by fungi and insects. There are two general classes 

of preservative treatment. 

Oil-Borne Using Creosote, Penta and Copper Naphthenate in Petroleum: Creosote oil was the 

predominant preservative for poles on rural systems until about 1947. Post-war shortages 

prompted the introduction of pentachlorophenol (penta) and copper naphthenate dissolved in the 

fuel oils, and other preservatives. 

Waterborne Using Arsenates of Copper: Poles using waterborne arsenates of copper (CCA, 

ACA and ACZA) are green in appearance. These preservatives were developed before 

World War II and have proven very effective as wood preservatives around the world. For 
Bulletin 1724E-200 

Page 13-4 

species and amounts of treatment, refer to agency Bulletin 1728F-700, “Specification for Wood 

Poles, Stubs, and Anchor Logs.” 

13.3.3 Structure Designations for Single Wood Pole Structures: Single pole wood structures 

are mainly limited in use to 115 kV and below. The six primary standard single pole structures 

utilized by Rural Utilities Service borrowers are designated as: 

• TP - pin or post insulators • TPD - pin or post insulators, double circuit • TS - suspension insulators, crossarm construction • TSD - suspension insulators, crossarms, double circuit • TSZ - suspension insulators, "wishbone" arm construction • TU - suspension insulators, steel upswept arm construction 

13.4 Design Calculations for Single Wood Pole Structures

13.4.1 Maximum Horizontal Span Limits of Single Wood Pole Structures: The following 

conditions should be taken into account when determining horizontal spans as limited by pole 

strength for tangent structures: 

• Wind on the conductors and OHGW is the primary load. 75 to 90 percent of the 

horizontal span will be determined by this load. 

• Wind on the structure will affect the horizontal span by 5 to 15 percent. 

• Unbalanced vertical load will increase ground-line moments. For single circuit 

structures, one phase is usually left unbalanced. The vertical load from the conductor 

will induce moments at the groundline and will affect horizontal span lengths by 2 to 

10 percent. 

• P-delta (P-δ) moments will also increase induced ground line moments. As a transverse 

load is applied to a structure, the structure will deflect. This deflection will offset the 

vertical load an additional amount " δ " causing an additional moment of the vertical 

weight times this deflection. This additional moment due to deflection is a secondary 

effect. An approximate method for taking into account the p-δ moments is given in 

section 13.4.2. 

For wood structures, depending on the taper of the pole, the maximum stress may theoretically 

occur above the ground level. The general rule of thumb is that if the diameter at ground level is 

greater than one and a half times the diameter where the net pull is applied, the maximum stress 

occurs above the ground level. Even if the point of maximum stress occurs above the groundline 

for single base wood pole structures, one can assume that spans are based on groundline 

moments in accordance with Exception 1 in NESC Rule 261A.2. Exception 1 states: “When 

installed, naturally grown wood poles acting as single-based structures or unbraced multiple-pole 

structures, shall meet the requirements of Rule 261A.2a without exceeding the permitted stress 

level at the ground line for unguyed poles or at the points of attachment for guyed poles.” 

The strength of the crossarm has to be checked to determine its ability to withstand all expected 

vertical and longitudinal loads. When determining bending stress in crossarms, moments are 

calculated at the through bolt, without considering the strength of the brace. The vertical force is 

determined by the vertical span under those conditions which yield the maximum vertical 

weight. The strength of two crossarms will be twice the strength of one crossarm. When 

considering the strength of the crossarm to withstand longitudinal loadings, reduction in the 

moment capacity due to bolt holes should be taken into account. 
Bulletin 1724E-200

Page 13-5 

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

applied loads represented in Figure 13-3. This equation may be used to determine the maximum 

horizontal span as demonstrated in the example in Paragraph 13.4.2. 

( ) ( ) ( ) ( ) φ gA == wp + wc + vo + MLFMLFMLFMLFMM p−δ Eq. 13-1 

where: 

φ = strength factor, see Chapter 11 

MA = FbS, the ultimate groundline moment capacity of the 

pole, ft-lbs. For moment capacities of wood poles at 

the groundline, (see Appendix F); 

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

S = section modulus of the pole at the groundline (see 

Appendix H). 

LF = load factor associated with the particular load 

Mg = induced moment at the ground line 

Other symbols are defined by Equations 13-2, 13-3, 13-4, 13-5. 

When estimating the load carrying capacity of a pole using manual methods, it is difficult to 

assess the additional moment due to deflection. Equations 13-5 and 13-6 provide an 

approximate way to calculate the additional moment due to defection. Because Mp-δ is a 

function of the vertical span (VS), the engineer should make an assumption about the 

relationship between the vertical and horizontal span (HS). In Equations 13-4 and 13-5, the 

relationship used is: VS = 1.25HS. 

FIGURE 13-3: TS TYPE STRUCTURE 

Refer to Figure 13-3 when considering the equations and symbols that follow. 

 a. 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 

h

h

h

h

S

Pg g

aS bS

A

Sc

c

g

l

h , a bh

Pc

tP
Bulletin 1724E-200 

Page 13-6 

b. Mwc = groundline moment due to wind on the wires 

Mwc = pt(h1 )HS Eq. 13-3 

where: 

HS = horizontal span, feet 

h1 = moment arm of pt, feet; in the example, 

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

t

a c b c c c g g

P

h p h p h p h p h

+ + +

1 = Eq. 13-3a

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

 pt = 3 pc + pg single circuit, single pole structures 

c. Mvo = groundline moment due to unbalanced vertical load 

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

where: 

sg = Horizontal distance from center of pole to ground wire 

(positive value on one side of the pole, negative on the 

other), feet 

st = sa + sb + sc , where sa , sb ,and sc are horizontal 

distances from center of pole to conductors (positive 

value on one side of the pole, negative on the other), 

feet

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

wg = weight of overhead groundwire per unit length, lbs./ft. 

Wi = weight of insulators, lbs. 

d. Mp-δ = groundline moment due to pole deflection 

Mp -δ = 1.25HS(wt)δimp Eq. 13-5 

where: 

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

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

( ( )( )( ) )

( )( ) mag

a

t c

imp E d d

p HS h δ δ

⎟

⎟

⎠

⎞

⎜

⎜

⎝

⎛

=

1

3

3 6.78 144 Eq. 13-6

E = modulus of elasticity, psi 

da = diameter of pole at location "A" (groundline), inches 

d1 = diameter of pole at height "h1" inches 

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

hc = effective height to the conductors, feet 

HS = horizontal span, feet 

pt = total transverse load per unit length of all wires, lbs./ft. 
Bulletin 1724E-200

Page 13-7 

After substitutions of Mwp, Mwc, Mvo, and Mpδ have been made into Eq.13-1, the equation 

can be reduced to a quadratic equation (below) and solved for the horizontal span. (See 

Paragraph 13.4.2 for an example of how the calculation of HS is carried out.) 

( ) ( )

a

b b ac 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: 

( )

P

HS W

cr

t

mag 1.25 1

1

−

δ =

 Eq. 13-8

(See Chapter 14 for calculations of Pcr) 

13.4.2 Example of Maximum Horizontal Spans: Determine the maximum horizontal span for the 69 

kV TSS-1 wood structure (Figure 13-4). Terrain is predominantly level, flat, and open. ("sg" is 

negligible; see Equation 13-4). Location and magnitude of resultant loads are indicated in Figure 13-5. 

Given: 

NESC Heavy Loading 

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: Western red cedar 

Conductor: 266.8 kcmil, 

26/7 ACSR (Partridge) 

Ground wire: 3/8" 

H.S.S. 

Conductor loads, lbs./ft: 

 Heavy High Wind EI&W

Transverse 0.5473 1.0165 .8808

Vertical 1.0776 0.3673 2.402

Ground wire loads, lbs./ft: FIGURE 13-4: TSS-1 STRUCTURE 

 Heavy High Wind EI&W

Transverse 0.4533 0.5700 .7868

Vertical 0.8079 0.2730 1.9667

Other information: 

Fb(pole) = 6000 psi 

Fb (crossarm) = 7400 psi 

S(groundline) = 458 in3

S(crossarm) = 22.7 in3

Wt. of insulator = 58 lbs. 

Dia. (top) = 8.59 in. 

Dia. (groundline) = 16.72 in. 

pt(total unit load) = 3(0.5473)+.4533 = 2.10 lbs./ft. 

wt(total unit load) = 3(1.0776)+0.8079 = 4.41 lbs./ft 

Pcr(critical 

 buckling load) = 

17,900 lbs. (see chapter 14 for fix–free 

 condition) , l =44.6 ft., E=1.12 E 06 psi 

 da = 9.63 in., dg = 16.72 in., Ia=422 in4

 

h = 44.6 ' l p = 2.10 lb/ft t

wt w = 4.041 lb/ft t

FIGURE 13-5: 

APPLICATION OF FORCES 

(HEAVY LOADING)

3.75 

60'

51.25'

47.5'

40.5'

7.0' 40.5'

5.5' 

4.5'
Bulletin 1724E-200 

Page 13-8 

Solution for Maximum Horizontal Span Considering P-δ moments: A comparison of unit loads 

with load factors indicates that the Heavy Loading District Loads control design. Therefore, for 

Heavy Loading, the moments for Equation 13-1 are calculated. 

[ ] ( )( ) ( )

( )

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

[ ] ( )( ) ( )

( )( )( )

( )( )( ) ( )

( )( ) ( )

( )

( )( )( )( )( )

( )

() ()

() ()

( )( )

( )

( )

( )( )

 1.175 Recalculate assuming 1.17 as the deflection magnifier, HS 529 feet.

.

17,900 

1- 4.0407 1.25 (525)

1

mag

1.15

 

1- W 1.25

1

mag

 should be checked. Pcr 17,900 assuming fixed free conditions (See Chapter 14).

g. Once the HS has been calculated, the assumption of 1.15 as the magnifier

 527feet

2 .0311

241.32 241.32 4 .0311 135,775 

 .0311 241.32 135,775 0

f. 0

 .0311 241.32 135,820 0

 148,524 (2.5)(5,100) (1.5)(187) (2.5)(93.5) 1.5(5.56) 1.5(.0207)

 (.65)(229, 000) (2.5)(5,100) (2.5)(93.5) 1.5(4.45) 1.5(217) 1.5(.0207)

e. ( ) ( ) ( ) ( )

.0207

1.25 4.041 .0041

.0041

.003558 1.15

1.12 06 16.72 9.63

6.78 2.095 44.6 144 

d 1.25 4.041

 4.45 217

c. 3.75 1.0776 .8075(.5) 1.25

 93.5

b. 2 0.5473 40.5 0.5473 47.5 0.4533 51.25

 5,100 .

6 12

4 2 8.59 16.72 52

a. 

t

2

2

2

2

2

2

2

3

3

2

= =

=

= =

=

=

− + − − =

+ − =

+ + =

+ − =

= + + + +

= + + + +

= + + +

=

=

=

=

=

=

= +

= − +

=

= + +

= −

+ =

δ

δ

φ

δ

δ

δ

δ

δ

δ

δ

cr

a wp wc vo p

mag

p

imp

imp

imp

p imp

vo i t

wc

wp

P

HS

HS

HS

HS HS

a HS b HS c

HS HS

HS HS HS

HS HS HS

M LF M LF M LF M LF M

HS

M HS HS

HS

HS

E

HS δ

M HS

HS

M HS W s

HS

M HS HS HS

ft lbs

M
Bulletin 1724E-200

Page 13-9 

h. Lateral Stability: The Equivalent load 2 feet from the top is approximately 4400 lbs. 

From Figure 12-2 (average soil), the embedment depth for a 4400 lb. load 2 feet from the top 

is between 8 and 8.5 feet. Lines nearby have performed well with the standard embedment 

depths. Engineering judgment dictates that an 8 foot embedment depth for the 60 foot pole 

will be sufficient. 

13.4.3 Maximum Vertical Span for TP and TS Pole Top Assemblies: To determine the 

vertical span, the moment capacity of the arm at the pole is calculated. 

Calculations for these structures are: 

( )( )( )

( )( )( ) c c

x arm i c

LF w s

M LF W s VS − = φ − Eq. 13-9

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, meters (feet). 

Wi = insulator weight, lbs. 

VS = vertical span, meters (feet). 

Example of Vertical Span Calculations for TS Pole Top Assembly (Heavy Loading):

wc = 1.0776 lbs./ft., see Figure 13-4, S = 22.7 in3

, φ = .50 and LF = 1.5 Heavy 

Loading District, 

( )( )( )

( )( )( )

( )

( )( )( )

( )( )( )

741 .

1.5 1.0776 5.5

(0.50)(14,000) 1.5 50 5.5

b. 50 .

14,000

7400 22.7 /12

a.

0.50

ft

VS

W lbs

ft lbs

M

M F S

LF w s

M LF W s VS

i

a

a b

c c

a i c

=

− =

=

= −

=

=

− =

 

Check vertical span for extreme ice with concurrent wind, wc = 2.4092 lbs./ft., φ = 1.0 and LF = 1.1 for extreme ice with concurrent wind 

( )( )( )

( )( )( )

939 .

1.1 2.4092 5.5

(1.0)(14,000) 1.1 50 5.5

ft

VS

=

− =
Bulletin 1724E-200 

Page 13-10 

13.4.4 Span Calculations for TSZ Pole Top Assembly: The TSZ structure is a wishbone-type 

crossarm assembly. It is intended for use on transmission lines where conductor jumping due to 

ice unloading and/or conductor galloping are problems. The wishbone provides additional 

vertical and horizontal offset between phases in order to reduce the possibilities of phase-tophase faulting due to ice unloading or galloping. 

FIGURE 13-6: TSZ-1 POLE TOP ASSEMBLY 

Since the crossarms of the wishbone are not horizontal, the vertical span is related to the 

horizontal span. The maximum vertical load (Wc) the TSZ-1single crossarm assembly can 

withstand is 3,400 lbs. at any conductor position. By calculating moments at point "a" 

on the assembly, horizontal and vertical spans are related. Span limited by pole strength are 

calculated in the same manner as the TP and TS structures. 

Example of Span Calculations for Wishbone Pole Top Assemblies: Determine the maximum 

horizontal and vertical spans for the pole top assembly of the 69 kV TSZ-1 pole top assembly 

(Figure 13-7). 

Given: Loadings: 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 13-7: TSZ-1 EXAMPLE FIGURE 13-8: HS vs. VS FOR TSZ-1 

S

"a"

1.5ft

3.22 ft

"a"

VERTICAL SPAN (FT.)

HORIZONTAL SPAN (FT.)

1200

1100

1000

900

800

400 600 800 1000
Bulletin 1724E-200

Page 13-11 

Solution:

Moment capacity of crossarm at “a”: 

 Ma = Wc(s) 

 Ma = 3,400(3.22) 

 = 10,950 ft-lbs. 

Horizontal and vertical span: 

The relationship between the horizontal and vertical spans is obtained by summing moments 

about point ‘a’. 

 2.5(.5473)(1.5)HS+1.5(1.0776)(3.22)VS+1.5(50)(3.22) = (0.50)(10,950) ft-lbs. 

 2.05HS+5.21VS = 5234 ft-lbs. 

For HS = VS, Span = 720 ft. See Figure 13-8 for application chart. 

13.4.5 Span Calculations for TU-1 Pole Top Assembly: These assemblies have steel upswept 

arms. With these arms, vertical spans are related to horizontal spans and a graph can be made to 

relate horizontal and vertical spans. Spans limited by pole strength are calculated in the same 

manner as the TP and TS structures. 

Example of Span Calculations for Steel Davit Arm Construction: For the 138 kV structure in 

Figure 13-9, plot the horizontal versus vertical span for steel davit arms. 

Given: 

Loadings: NESC Heavy Loading 

 High 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 High 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 13-9: TU-1 STRUCTURE 

7.0'

8.0'

14'

14'

14'
Bulletin 1724E-200 

Page 13-12 

Solution:

For the 8.0' davit arm, the moment capacity 

of the arm at the pole (Figure 13-9a): 

Ma = Wc(s) 

= (3000)(8.0) 

= 24,000 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. 

 2.5(0.6193)(2.7)HS+1.5(1.5014)(8.0)VS+1.5(102)(8.0) = (1.0)(24,000) ft-lbs. 

 4.1803HS+18.017VS = 22,776 ft-lbs. 

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

Ma = Wc(s) 

= (3000)(7.0) 

= 21,000 ft-lbs 

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

 2.5(0.6193)(2.5)HS+1.5(1.5014)(7.0)VS+1.5(102)(7.0) = (1.0)(21,000) ft-lbs. 

 3.87HS+15.77VS = 19,929 ft-lbs. 

In this example for the NESC heavy loading district loads, the magnitude of the vertical span is 

not sensitive to the horizontal span (as shown in Figure 13-10). For horizontal spans between 

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

to 1018 feet (for design purposes, use 1000 feet). Spans limited by the extreme winds are not a 

factor in this example. 

FIGURE 13-10: VS vs. HS FOR TUS-1 STRUCTURE OF EXAMPLE 13-3 

R

s

.5'

Wc

HORIZONTAL SPAN (FT.)

VERTICAL SPAN (FT.)

1200

1100

1000

900

800

400 600 800 1000

8.0 ft. arm

7.0 ft. arm

FIGURE 13-9a: DAVIT 
Bulletin 1724E-200

Page 13-13 

13.5 Design Calculations for Wood H-Frame Structures 

13.5.1 General: There are various techniques available for analysis of H-frame structures: 

• Classical indeterminate structural analysis. • Matrix methods of structural analysis. • Approximate methods (explained in this section and subsequent sections). 

In analyzing a statically indeterminate structure by approximate procedures, one assumption is 

made for each degree of indeterminacy. These assumptions are based on logical interpretations 

of how the structure will react to a given loading. For the H-frame with knee and V-braces, we 

can assume that the structure will behave as shown in Figure 13-11. 

FIGURE 13-11: ASSUMED H-FRAME BEHAVIOR 

At some point in the poles, there will be an inflection point (a point of zero moment). If the pole 

or column is uniform in cross section, it is common to assume that the inflection point is located 

midway between points of bracing, shown as a dotted line in Figure 13-11. However, since the 

pole is tapered, the following relationship may be used to determine the location of the inflection 

point (see Figure 13-12, Equation 13-10 and Appendix H for application chart). 

( )

( ) 2 2 2

2

A A D D

o A A D

C C C C

C C C

x

x

+ +

+ = Eq. 13-10 

where: 

CA = circumference at base 

CD = circumference at top

FIGURE 13-12: LOCATION OF POINT 

OF CONTRAFLEXURE 

By applying the same reasoning, the inflection point can be located on the other column. 

Locating the inflection point on each column, and hence the point of zero moment, entails 

two assumptions for the frame. Since the frame is statically indeterminate to the third degree, a 

third assumption has to be made. A common third assumption is that the shear in the columns is 

Outside

Kneebraces

Crossbraces

B F

C

A

D

E

X

o

CA

CD

X
Bulletin 1724E-200 

Page 13-14 

distributed equally at the inflection points. The shear in the columns is equal to the horizontal 

force on the structure above the level under consideration. 

For a less rigid support, the inflection point moves toward the less rigid support. Two 

conclusions can be made: 

• For a pole rotating in the ground, the inflection point "C" below the crossbraces, is 

lowered. The lowering of the inflection point inreasing the moment induced in the 

pole at the connection of the lower crossbrace. Since the amount of rotation of a base 

is difficult to determine, the usual design approach is to always assume a rigid base. 

• For H-frames with outside kneebraces only, the point of inflection ‘F’above the 

crossbrace (shown in Figure 13-11) is higher than the point of inflection for four 

kneebraces. This higher point of inflection increases the moment in the pole at the 

upper crossbrace-pole connection. For the H-frame with outside kneebraces only, the 

designer may make one of two assumptions: 

(1) When determining induced moments in the poles, the outside kneebraces are 

ignored and no point of inflection exists between the crossbrace and the crossarm. 

This is a conservative assumption and assumes that the purpose of outside braces 

is to increase vertical spans only. 

(2) It can be assumed that the point of inflection occurs at the crossarm. This 

assumption will be used in the equations and examples which follow. 

13.5.2 Crossbraces: The primary purpose of wood X-bracing for H-frame type structures is to 

increase horizontal spans by increasing structure strength. Additional benefits achieved by 

crossbracing include possible reduction of right-of-way costs by eliminating some guys and 

reduction of lateral earth pressures. For an efficient design, several calculations should be made 

in order to correctly locate the crossbrace. 

The theoretical maximum tensile or compressive load which the wood crossbrace will be able to 

sustain will largely be dependent on the capacity of the wood brace to sustain a compressive 

load. Drawing TM-110, X-brace Assembly of Bulletins 1728F-810 and 811, is to be used for the 

115, 138, 161 kV, and 230 kV tangent structures. The crossbrace dimension is 3-3/8" x 4-3/8" 

for the 115 kV structure, 3-3/8" x 5-3/8" for 138 kV and 161 kV structures. The dimensions of 

this X-brace for the TH-230 structure are 3-5/8" x 7-1/2" (minimum). 

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

( )

2

2

⎟

⎠

⎞ ⎜

⎝

⎛ =

r

k

A E Pcr l

π Eq. 13-11

where: 

Pcr = maximum compressive load, lbs. 

A = area, in2

E = modulus of elasticity, psi. 

kl = effective unbraced length, in. 

r = radius of gyration, in. which will give you the 

maximum kl/r ratio; kl and r must be 

compatible for the same axis 

FIGURE 13-13: CROSSBRACE 

45
Bulletin 1724E-200

Page 13-15 

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. RUS 

Specifications for Double Armed and Braced Type Crossarm Assemblies (138 kV and 161 kV), 

and RUS Specifications for Double Armed and Braced Type Crossarm Assemblies (230 kV) 

require X-braces to withstand a tension or compression loading of 20,000 lbs. This ultimate 

value correlates with the above theoretical ultimate loads in the table. It is recommended that 

20,000 lbs. (ultimate) be used for design purposes, since this value assures one that the 

crossbrace will sustain the indicated load. 

For the 115 kV structure (TH-1AA) it is recommended that 20,000 lbs. be used as the ultimate 

load the crossbrace is able to sustain. The hardware for the crossbrace is the same as 

the hardware used with 138 kV and 161 kV structures. 

13.5.3 V-Braces: The primary purpose of two V-braces on the outside of the poles is to 

increase vertical spans. Two V-braces on the inside will increase horizontal spans. Four Vbraces increase both horizontal and vertical spans. The various bracing arrangements and their 

designations for 161 kV structures are shown in Figure 13-14. 

FIGURE 13-14: POLE TOP BRACING ARRANGEMENTS 

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

RUS Specifications for Double Armed and Braced Type Crossarm Assemblies (138 kV and 

161 kV) specifies the following minimum strength requirements for the various pole top 

assemblies: 

Maximum vertical load (at any conductor position)

TH-10 8,000 lbs. 

TH-10VO 14,000 lbs. 

TH-10V4 14,000 lbs. 

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

Page 13-16 

Maximum transverse conductor load (total)

TH-10VO 15,000 lbs. 

TH-10V4 15,000 lbs. 

Maximum tension or compression in V-brace

20,000 lbs. 

RUS Specifications for Double Armed and Braced Type Crossarm Assemblies (230 kV) 

specifies the following minimum strength requirements for the TH-230 pole top assembly: 

Maximum vertical load (at any conductor position)

TH-230 10,000 lbs. 

Maximum transverse conductor load (total)

TH-230 15,000 lbs. 

Maximum tension or compression in V-brace

TH-230 20,000 lbs. 

When determining maximum vertical and horizontal spans as limited by H-frame top assemblies, 

the above minimum strengths may be used as guidance. 

13.5.4 Structure Analysis of H-frames: Equations 13-16 to 13-22 are used for calculating 

forces in the various members of H-frame structures. As part of the structural analysis, span 

limitations due to strength of the pole top assembly (Equations 13-12 to 13-15) should be 

considered and suggested methods follow. Appropriate load factors and strength factors should 

be applied in the respective equations. 

Outside V-Braces: An H-frame structure with two outside V-braces in figure 13-14 (and shown 

in greater detail in Figure 13-19) needs further explanation. A structure with two outside Vbraces has less rigidity above the crossbrace than a structure with than four V-braces. The 

location of the point of contraflexure is difficult to determine. Equation 13-10, which calculates 

the moment (ME) at the top of the crossbrace assumes that the point of contraflexure exists at the 

crossarm. However, when using Equation 13-12 to determining span limitations due to strength 

of the pole top assembly, a point of contraflexure is assumed between the top of the crossbrace 

and the crossarm. 

The maximum vertical span is determined for the maximum horizontal span. 

FIGURE 13-15: POLE TOP ASSEMBLY WITH TWO OUTSIDE BRACES 

Wt

Pt o

a

b
Bulletin 1724E-200

Page 13-17 

Ultimate force in the brace is: 

( )

( ) lbs

b

LF Wt LF Pt a

+ ≤ ( )20,000 ⋅ sin

( )

sin

( ) φ

α α 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 X-brace may be calculated 

in the same manner as when four braces are used. Crossarm strength controls the maximum 

vertical span. 

Force in the braces is: 

( )

( ) lbs

b

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

2sin

( ) φ

α α

+ ≤ Eq. 13-13

Crossarm bending moment, Mo (φ) is: 

( )

2

( ) ( ) LF W b M t φ o = Eq. 13-14

FIGURE 13-16: POLE TOP ASSEMBLY WITH INSIDE BRACES 

Wt

t P

o

a

b
Bulletin 1724E-200 

Page 13-18 

Four V-Braces: The following equations can be used to determine the maximum vertical span as 

limited by four V-braces, given the maximum horizontal span: 

For four V-braces, force in the outside braces is: 

lbs LF Wt ( )20,000

sin

( ) φ

α

≤ Eq. 13-15

Force in the inside braces is: 

( )

( ) lbs

b

LF Wt LF Pt a ( )20,000

sin

( )

2sin

( ) φ

α α

+ ≤ from Eq. 13-13

13.5.5 Abbreviations: In Equations 13-16 to 13-23, all units should be consistent. The 

following abbreviations apply: 

De = 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. 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. 
Bulletin 1724E-200

Page 13-19 

fs = calculated skin friction value, psf 

hn = length as indicated, ft. 

Pt = total horizontal force per unit length due to wind on the 

conductors and overhead ground wire, lbs./ft. 

sn = distance as shown, ft. 

wc = weight per unit length of the conductors (plus ice, if 

any), lbs./ft. 

wg = weight per unit length of overhead ground wire (plus 

ice, if any), lbs./ft. 

φ = strength factor (see Chapter 11 of this bulletin) 

13.5.6 Equations for Structure 1 (Figure 13-17): For this structure, the horizontal span is 

reduced by 10 % to take into account P-delta (P-δ)moments (i.e. 0.90 in Equation 13-16). For a 

more detailed analysis, see Equation 13-1 for single poles. 

( )( )( ) ( ) ( )( )( ) (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 13-17: STRUCTURE 1 

b

Wt Wt t W

h

t P

S

B B

A A

l h
Bulletin 1724E-200 

Page 13-20 

13.5.7 Equations for Structure 2 (Figure 13-18): 

( )( )( ) ( ) ( )( )( ) 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( )( ) pt h2 +VS(wg )( ) b +1.5VS(wc )(b) = W2 (b) −Wp (b) ( )( ) + X −Y + w1 b 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 13-18: 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 13-21 

13.5.8 Equations for Structure 3 (Figure 13-19): 

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

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 13-19: STRUCTURE 3 FIGURE 13-20: STRUCTURE 4 

13.5.9 Equations for Structure 4 (Figure 13-20): 

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

2

/

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

B B ⎟

⎟

⎠

⎞

⎜

⎜

⎝

⎛ − + = φ − Eq. 13-21a

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

2

/

2 ( ) o t f o t o

E E

LF F y z d d z LF p z HS M ⎟

⎟

⎠

⎞

⎜

⎜

⎝

⎛ − + = φ − Eq. 13-21b

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 dt d f V = LF F y − z + Eq. 13-21e 

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 13-22 

13.5.10 Equations for Structure 5 (Figure 13-21): 

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 13-21: STRUCTURE 5 FIGURE 13-22: STRUCTURE 6 

13.5.11 Equations for Structure 6 (Figure 13-22): 

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 13-23 

13.6 Example of an H-frame Analysis: For the 161 kV structure shown in Figure 13-23, 

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

versus vertical span for the pole top assembly. 

FIGURE 13-23: EXAMPLE OF AN H-FRAME 

13.6.1 Given: 

 NESC heavy loading 

 High winds - 19 psf on the wires and 

22 psf on the structure 

 Heavy ice - 1" radial ice 

 Extreme ice with 

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 High 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 

 OHGW Loads Heavy Ldg District High 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. 

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 13-24 

13.6.2 Solution for Heavy Loading District Loads: Maximum horizontal span based on structure 

strength: 

( )( )

() ()

( )

( )

d . in.

z ft

z ft

z

z

z

d

d

z , z

d . in

x ft

x ft

x

x

x

d

d

x , x

d x /x z /z

x x , z

ft

p

p p

p

lbs ft

p p p

p

f

o

o

o

e

d

o

c

o

o

o

a

d

o

n o o

o, 

t

c

t

t g c

t

and 919

3.52 .

3.98 .

0.53 7.5

0.53

.91

9.65

8.81

For :

and 130 .

15.3 .

23.9 .

0.6139.25

0.61

0.72

15.64

11.33

For :

All diameters, , determined by Appendix F, and ratio or determined by Appendix H.

c. Determine location of andz for theX- brace location shown.

5.56 .

2 0.75 3 7.75

Distance fromtop

b. Determine location of equivalent load :

3.065 / .

2 0.4783 3 0.7027

2 3

a. Equivalent load :

1

1

1

1

1

1 0 1

g

=

=

=

=

∴ =

= =

=

=

=

=

∴ =

= =

=

+ =

=

= +

= +
Bulletin 1724E-200

Page 13-25 

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

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

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

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

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

( )( )( ) ( )

( )( )( ) ( )

( )( )( ) ( ) ( )

( )( )( ) ( ) ( )

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

 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 /

g. For horizontalspan limited by strength of the crossbrace :

1664 .

811 .

 similar calculations can be made. The results are asfollows:

f. For horizontalspan limited by pole strength at locations D and A,

 2,127 .

2

2.5 3.065 3.98 /

2

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

 ( from Appendix F)

 50,400 .

 58,800 8,400 . .

 a. 

2

/

2 ( )

e. Horizontalspan limited by pole strength at E :

 2,133 .

2

2.5 3.065 3.52 /

2

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

 a. 44,700 .

2

/

2 ( )

d. Find the horizontalspan limited by pole strength at B (see Figure13 - 23) using Equation 13 - 21a :

2

2

2

2

2

1 1

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

HS ft

HS ft

ft

HS

M

M ft lbs

M ft lbs

M M M

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

ft

HS

M ft lbs

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

X

o t f

o t c

X t

A

D

E

bh

E

E

E cap bh

o t f o t o

E E

B

B

t o t f

B B

=

= − +

= −

= − +

= −

= − +

= − +

= − +

= − + −

=

=

=

⎟

⎟

⎠

⎞ ⎜

⎜

⎝

⎛ ⎜

⎝

⎛ ⎟

⎠

− + ⎞ = −

= −

= − −

= −

− + = −

=

⎟

⎠

⎞ ⎜

⎝

⎛ ⎟

⎠

⎞ ⎜

⎝

⎛ − + = −

= −

− + = −

φ

φ

φ
Bulletin 1724E-200 

Page 13-26 

13.6.3 Solution for Heavy Loading District Loads - Maximum span limited by pole top 

assembly follows: 

( )

( )

( )

( ) ( )( )

( )( ) ( )( )( )

(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

( )

b. From Equation 13 -13 :

1938 .

2.0938 1.5

10,000sin 39 1.5 135

( )20,000. sin

( )

a. From Equation 13 -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

α α

φ

α

 

13.6.4 Solution for Heavy Loading District Loads - Maximum span limited by uplift follows: 

Assume dry native backfill, safety factor of 4. 

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

( )( )

( )( )( )

( )( )( )

(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 13-27 

13.6.5 Check for extreme ice and concurrent wind: Span limitations based on pole strength and 

crossbrace strength is controlled by NESC Heavy Loading conditions. The unit conductor loads when 

load factors and strength factors accounted for, are greater for the Heavy Loading District load than for 

the EI&W as shown below: 

 NESC > EI&W 

Transverse load: 7027(2.5)/.65 > 1.0360/.65 lbs/ft 

2.7027 > 1.5938 lbs/ft. 

 NESC > EI&W 

Vertical load: 2.0938(1.5)/.65 > 3.7154 lbs/ft 

 4.8318 > 3.7154 lbs/ft 

13.6.6 Check for Extreme Wind Conditions: Although span limitations based on pole strength and 

crossbrace strength is controlled by NESC Heavy Loading conditions, span limitations based on uplift is 

controlled by the extreme wind condition. 

For Dry Native Backfill: For an assumed safety factor of 1.5, the following equation result: 

 222.2HS - 25.4VS = 142,862 

 (For VS=0, maximum HS=640 ft.) 

For Aggregate Backfill: For an assumed safety factor of 1.5, the following equation results: 

 222.2HS - 25.4VS = 252,400 

 (For VS=0, maximum HS=1,135 ft.) 

When considering uplift, it may be prudent to base calculations on the minimum vertical span as 

limited by insulator swing. 

13.6.7 Summary of Span Limitations: 

Horizontal Span limits: 

 HSA = 1664 ft. 

 HSD = 811 ft. 

 HSE = 2127 ft. 

 HSB = 2133 ft. 

 HSx = 1009 ft. 

 Dry native backfill: 

 For a VS = 0, the HS (limited by uplift) = 640 ft. 

 

 Aggregate backfill: 

 For a VS = 0, the HS (limited by uplift) = 1,135 ft. 

Vertical Span limited by Heavy District Loads: 

 VSpoletop = 1,435 ft., max. (For VS =HS) 

A more efficient design could be achieved by moving the crossbrace. 
Bulletin 1724E-200 

Page 13-28 

Blank Page 
Bulletin 1724E-200 

Page 14-1

14. GUYED STRUCTURES

14.1 Introduction: When a pole structure is guyed, loading on the poles is due to the combined 

action of vertical and horizontal forces. Vertical forces on the pole include the vertical 

component of the tension on the guy(s) and the weight of the conductors and insulators. 

Horizontal forces include transverse due to wire tension at angle structures, horizontal wind 

forces, and vertical and longitudinal forces from deadending. 

Bisector guys are used on small angle structures, whereas head and back guys are used on large 

angle structures and double deadends. Angles between 10 and 45 degrees may be turned on 

what is called a “running” angle structure, utilizing bisector guys. Above 45 degrees, unequal 

stresses will be set up in the conductor where it attaches to the suspension insulator clamp. The 

sharper the angle or bend in the conductor at the clamp, the more unequal the stresses will be. 

Any unbalanced longitudinal wire tensions loads on double deadend and large angle structures 

can be more effectively carried by head and back guys. For large angle structures, the transverse 

load due to wire tension loads will be a heavy and permanent. Therefore, head and back guys 

will be more effective in carrying this load. 

Figure 14-1 shows a deadend structure in which the conductors are connected to the structure by 

strain insulators. 

FIGURE 14-1: DEADEND STRUCTURE 

 (Head and back guys shown) 

Deadend structures include: 

• Ordinary deadend structures that need only be designed to withstand the load resulting 

from the difference in tensions of the conductor for the forward and back spans. This 

condition occurs where there is a change in ruling spans. 

• Full deadend structures in which guys and anchors are designed to withstand the resultant 

load when the conductors are assumed to be broken or slack on one side of the structure. 

As mentioned in Chapter 10, it is suggested that full deadend structures be located at 

intervals of five to ten miles to prevent progressive cascading-type failures. 

In general for wood structures, guys and anchors should be installed at deadends, angles, long 

spans where pole strength is exceeded, and at points of excess unbalanced conductor tension. 

The holding power and condition of the soil (whether wet or dry, packed or loose, disturbed or 

undisturbed, etc.) and the ability of the pole to resist buckling and deflection should be 

considered. Unguyed steel and concrete pole structures are sometimes used at angles and 

deadends to avoid the use of guys. In these cases, careful consideration needs to be made of the 

structure and foundation design and deflection. 
Bulletin 1724E-200 

Page 14-2 

14.2 Load Factors: In Chapter 11, Tables 11-6 and 11-7 give recommended minimum load 

factors (LF) associated with the design guys and anchors. Table 14-1 summarizes the 

application of the load factors and strength factors for guys and anchors. 

TABLE 14-1 

APPLICATION OF LOAD AND STRENGTH FACTORS FOR GUYED STRUCTURES 

(GUYS AND ANCHORS) 

Loading Districts: 

NESC (2.50)(a+b) + 1.65c = G cosβ ≤ (0.9)Gu cosβ 

 

Recommended (2.50)(a+b) + 1.65c = G cosβ ≤ (φ )Gu cosβ (See table 11-6 of 

this bulletin for φ ) 

Extreme Winds and Extreme Ice with Concurrent Winds:

NESC (1.00)(a+b) + 1.00c = G cosβ ≤ (0.9)Gu cosβ

 

Recommended (1.10)(a+b) + 1.100c = G cosβ ≤ (φ )Gu cosβ (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 11-7 of this bulletin 

cosβ = Guy slope with horizontal groundline 

14.2.1 Longitudinal Strength: Longitudinal strength is applicable to crossings and locations 

where unequal spans and unequal vertical loadings may occur. Required longitudinal strength of 

wood tangent structures at crossings is defined by NESC Rule 261A2. The rule states that wood 

tangent structures which meet transverse strength requirements without guys, shall be considered 

as having the required longitudinal strength, provided that the longitudinal strength of the 

structure is comparable to the transverse strength of the structure. If there is an angle in the line, 

the wood structure will have the required longitudinal strength provided: 

• The angle is not over 20 degrees, • The angle structure is guyed in the plane of the resultant conductor tensions, and • The angle structure has sufficient strength to withstand, without guys, the transverse 

loading which would exist if there were no angle at that structure (with the appropriate 

load factors and strength factors applied). 

14.2.2 Distribution Underbuild: Guying and anchors for distribution underbuild are to comply 

with NESC Grade B provisions. Refer to Chapter 16 for additional information concerning 

underbuild. 

14.3 Clearances: Recommended clearances to be maintained between any phase conductor and 

guy wires are indicated in Table 14-2. Refer to Chapter 7 for further details. 
Bulletin 1724E-200 

Page 14-3

TABLE 14-2 

RECOMMENDED MINIMUM CLEARANCES IN INCHES 

FROM CONDUCTOR TO SURFACE OF STRUCTURE OR TO GUY WIRES (Note A) 

Nominal Voltage, Phase to Phase,kV 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 14-4 

14.4 Design

14.4.1 Bisector Guys: For structures utilizing bisector guys, the guys have to be designed to 

sustain the resultant transverse load due to longitudinal wire tension loads in Table 14-1: 

c =2 (T) (Sin θ/2) 

where: 

T = maximum design tension, lbs. 

θ = line angle The transverse load (a) due to wind on the conductors for an angle structure is given as: 

a = (p) (HS) (cos θ/2) 

where: 

p = wind load in lbs./ft. 

HS = horizontal span, ft. 

θ = line angle; cos θ/2 is usually set equal to one 

Wind on the structure may be converted to a horizontal force (b) at the point of guy attachment. 

14.4.2 Head and Back Guys: Wood pole deadends, double deadends, and large angle 

structures will normally require head and back guys. For tangent deadends and double deadends, 

the transverse strength of the structure must be sufficient to carry the appropriate wind load. In 

some cases, bisector guys or crossbraces may have to be used to meet transverse strength 

requirements. The tension in the guy should take into account the slope of the guy. 

14.5 Pole Strength: Once the tension in the guy wire has been calculated, the compressive 

strength of the pole should be calculated and checked to see if the pole selected will be adequate 

for the intended use. 

14.5.1 Stability Concept: The selection of structural members is based on three characteristics: 

strength, stiffness, and stability. When considering a guyed wood, steel or concrete pole, it is 

important that the designer check the stability of the structure for the expected loadings. 

For an example of stability, consider the axial load carrying capabilities of the rods in 

Figure 14-2. The rod on the left is unquestionably “more stable” to axial loads than the rod on 

the right. Consideration of material strength alone is not sufficient to predict the behavior of a 

long slender member. As an example, the rod on the right might be able to sustain 1000 lbs axial 

load when considering strength (ultimate compressive stress times area), but could only sustain 

750 lbs. when considering stability of the system. The rod on the right is more likely to become 

laterally unstable through sidewise buckling. 

FIGURE 14-2: COMPARISON OF RODS TO SHOW 

STABILITY CONCEPT 

a b
Bulletin 1724E-200 

Page 14-5

14.5.2 Critical Column Loads: In transmission structures, the guyed pole acts as a column, 

sustaining axial loads induced in the pole from vertical guy components. The taller the pole, the 

less load the guyed pole can sustain in compression before the structure becomes “unstable”. 

Stability of a column can be thought of in one of two ways: 

a. The column is unstable when the axial force would cause large lateral defections even 

when the lateral load was very small. 

b. When a column subjected to an axial force, a small deflection may be produced. The 

column is considered stable if the deflection disappears when the lateral force is removed, 

and the bar returns to its straight form. If the axial force (P) is gradually increased, a 

condition is reached in which the straight form of equilibrium becomes unstable and a 

small lateral force will produce a deflection which does not disappear when the lateral 

force is removed. The “critical” load is then the axial force which causes buckling or 

collapses due to any bowing or lateral disturbance. 

14.5.3 Calculation of Buckling Loads: For long slender columns, the critical buckling load is 

determined by the general equation: 

(Pcr is independent of the yield 

stress of the material). 

where: 

Pcr = critical buckling load, lbs. or kips 

E = modulus of elasticity, psi 

I = moment of inertia, in4 

k l = the effective unbraced length of the column; kl 

depends on restraint end conditions of the 

column. 

Where for the various end conditions of the column, Pcr is idealized in Figure 14-3 below: 

FIGURE 14-3: EFFECTIVE UNBRACED LENGTH FOR VARIOUS END CONDITIONS 

2

(kl)

EI P

2

cr

π

=

a

P

b

P

c

P
Bulletin 1724E-200 

Page 14-6 

Assumptions made in the above calculations: 

• The column is perfectly straight initially. 

• The axial load is concentrically applied at the end of the column. 

• The column is assumed to be perfectly elastic. 

• Stresses do not exceed the proportional limit. 

• The column is uniform in section properties. 

14.5.4 Buckling of Guyed Steel and Concrete Poles: For guyed steel and concrete poles, all 

the assumptions in paragraph 14.5.3 are violated. As such, the engineer will often ask the pole 

manufacturer to check the axial capacity of the pole. The engineer must give the pole 

manufacturer information concerning guy size and strength, yield stress, guy locations, and guy 

leads. In the case of steel poles, the pole manufacturer should also check the capacity of the guy 

attachments. It is recommended that in the case of concrete poles, the pole manufacturer should 

design the guy attachment or at least check the capacity of the pole and attachment when the 

owner has selected the hardware. 

14.5.5 Buckling of Guyed Wood Poles: For a guyed wood poles, all the assumptions in 

paragraph 14.5.3 are also violated. As such, the engineer must apply appropriate safety factors 

to account for realistic cases and the variability of wood. Equations for buckling of a wood 

column with no taper follow: 

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 

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: 

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. 

da = 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: 

2

2

4 l

EI Pcrπ = 2

2

cr

2 EI P

l

π = 2 l

EI P

2

cr π

=

∗ Pcr =PA P

α

⎟

⎟

⎠

⎞

⎜

⎜

⎝

⎛ =∗

a

g

d

d

P
Bulletin 1724E-200 

Page 14-7

Conditions Fixed – Free End Fixed – Pinned End Pinned – Pinned End

For a tapered column 

(circular cross section) 

 

When using the Gere and Carter method for the NESC district loads with load factors, strength 

factors between 0.65 to 0.5 respectively are recommended. The resulting safety factor will be 

between 2.5 and 3.0. For extreme wind loads, it is recommended that strength factors between 

0.65 and 0.5 be used, resulting in a safety factor between 1.5 and 2.0. For deadends, lower 

strength factors (or higher safety factor) should be used. 

14.5.6 General Application Notes: For unbraced guyed single poles at small and medium 

angles structures using bisector guys, certain assumptions are made as to the end constraints. In 

the direction of the bisector guy, the structure appears to be pinned at the point of the guy 

attachment and fixed at the base. However, 90° to the bisector guy, the structure appears to be a 

cantilevered column. Since the conductors and phase wires offer some constraint, the actual end 

conditions may be assumed to be between fixed-free and fixed-pinned (Figure 14-4a). When 

checking buckling, it is suggested that the end conditions of pinned-pinned be assumed. 

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. 

2.7

a

A g

cr d

d

4

EI P ⎟

⎟

⎠

⎞

⎜

⎜

⎝

⎛ = 2

2

l

π

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 Transversely

Longitudinally pinned-fixed pinned-fixedpinned-pinned pinned-fixed

Bisector Guyed In-Line Guyed Buckling Mode

End Conditions

Bisector Guyed Structure In-line Guyed Structure

Transversely

Longitudinally pinned-fixed pinned-fixedpinned-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

2.0

a

A g

cr d

EI d

P ⎟

⎟

⎠

⎞

⎜

⎜

⎝

⎛ = 2

2 2

l

π

2.0

a

A g

cr d

EI d

P ⎟

⎟

⎠

⎞

⎜

⎜

⎝

⎛ = 2

2

l

π
Bulletin 1724E-200 

Page 14-8 

In such instances, the usual engineering practice is to assume an unbraced length from the 

groundline to the lowest guy attachment and the induced axial load in the pole equal to the sum 

of all axial loads included by the vertical component of the guys. 

FIGURE 14-5: AXIAL LOADS INDUCED IN A POLE 

When the structure is considered to be a double deadend or large angle, the poles, guys, and 

anchors must sustain the full deadend load with an appropriate load factor. For the tangent 

double deadend shown in Figure 14-6, the poles must sustain the maximum axial load which 

might occur if all phase conductors on one side of the structure were removed (see Figure 14-6a 

and 14-6b). However, to “double account” the loads, as shown in Figure 14-6c would be too 

conservative. 

FIGURE 14-6: REPRESENTATION OF AXIAL LOADS (a & b) 

 AND DOUBLE ACCOUNTING LOADS (c) 

For wood pole lines, deadends and large angle structures will often require a higher class pole 

than that used as the base class pole for the line. Ways to control or reduce the pole class needed 

at deadends and large angles include: 

• Relocate and/or increase the height of tangent structures adjacent to guyed angle and 

deadends. This would allow the use of shorter poles with guyed structures, and as a 

result would allow use a lower class pole with no sacrifice in safety. 

• Decrease the guy slope. This will decrease the vertical load component pole. 

a b

a b

c

a b
Bulletin 1724E-200 

Page 14-9

As a note, angle and deadend structures usually comprise about 5 percent of the total structures 

of a line. Use of conservative safety factors for these critical structures results in a greater 

overload margin without significantly affecting the total cost of the transmission line. 

The engineer should consider guying single pole structures used for small angles, even if the 

pole has adequate strength to carry the load. Wood poles have a tendency to “creep” with time 

when subjected to a sustained load. For steel or concrete poles, the engineer should also 

consider the use of guyed poles at angles or deadend structures. Use of guys will prevent 

unguyed steel and concrete poles from having large diameters at the groundline and will reduce 

the cost of foundations. 

14.6 Anchors: The holding power of the anchor will largely depend on whether the soil is wet 

or dry, packed or loose, disturbed or undisturbed. Since soils vary considerably between 

locations, the holding power of an anchor will also vary considerably. 

In areas with a fluctuating water table, the capacity of the anchors should take into account the 

submerged unit weight of the soil. If at any time the holding power of an anchor is questionable 

due to variable soil conditions, the anchor should be tested. The primary types of anchors 

include log anchors, plate anchors, power screw anchors, and rock anchors. The selection of the 

appropriate anchor will largely depend on the type of soil condition. 

14.6.1 Log Anchor Assemblies: The two log anchors in the construction drawings (agency 

Bulletins 1728F-810 and 811, units TA-2L and 4L) are 8′′ x 5′ - 0′′ and 8′′ x 8′ - 0′′, and have an 

ultimate holding power of 16,000 lbs. and 32,000 lbs. These logs, using one or two anchor rods 

may be used in combination to provide sufficient holding power for guys. “Average” soil is 

considered to be medium dense, coarse sand and stiff to very stiff silts and clays. Log anchors 

should be derated or should not be used in soils of soft clay, organic material, saturated material, 

or loose sand or silt. 

14.6.2 Plate Anchors: The plate anchor assembly TA-3P in Bulletins 1728F-810 and 811, is 

rated at an ultimate holding power of 16,000 lbs and 24,000 lbs. In firm soils, where the 

engineer would like to minimize digging, plate anchors may prove economical. 

14.6.3 Power Screw Anchors: Screw anchors are being used more often because of their easy 

installation. They are most appropriate for locations where firm soils are at large depths. The 

screw anchor assembles TA-2H to TA-4H of Bulletins 1728F-810 and 811 should be installed 

per manufacturer’s recommendations. In addition to the anchor unit being shown on the plan 

and profile, the capacity of the screw anchor should also be shown. Screw anchors have a higher 

safety factor than other types of anchors. This higher safety factor is reflected in Information 

Bulletin 202-1, “List of Materials Acceptable for Use on Systems of USDA Rural Development 

Electrification,” by a reduced designated ultimate holding capacity (70 percent of the 

manufacturer’s suggested holding capacity). 

14.7 Drawings: A summary drawing should be prepared for each line, showing the 

arrangement of guys for each type of structure to be used. The drawing will greatly facilitate the 

review of the plan and profile, and simplify the construction of the line. 

Guys required for various line angles are based on certain spans. Since actual spans will vary, 

the guying requirements shown will not be suitable for all conditions. Sometimes, it is desirable 

to make a guying guide for each angle structure which relates horizontal span to the angle of the 

line (see the example, paragraph 14.8). 
Bulletin 1724E-200 

Page 14-10 

The Guying Guide drawing also shows (1) points of attachment of the guy to the pole, (2) slope 

of the guys, (3) type of structure, and (4) guys and anchors required. 

14.8 Example: Develop guying guides for TH-12 161 kV structure. 

14.8.1 Design Parameters

General Loading and Structure Information: 

NESC Heavy Loading 

Extreme Wind: 19 psf on wires, 22 psf on the structure 

Heavy Ice: 1” radial 

Extreme Ice with 

Concurrent winds 

1” radial 4 psf 

 

Pole: Douglas fir 80-2 

Conductor: 795 kcmil 26/7 ACSR 

Overhead ground wire: 7/16” E.H.S. 

Ruling Span: 800 ft. 

Guy Wire: 7/16” E.H.S. 

Conductor Loads, lbs/ft: 

 Heavy High Wind Heavy Ice EI&W

Transverse 0.7027 1.7543 0 1.0360 

Vertical 2.0938 1.0940 3.7154 3.7154 

Conductor 

 tensions 

10,400 lbs. NA 12940 lbs. 13240 lbs. 

Overhead Ground Wire loads, lbs/ft:

 Heavy High Wind Heavy Ice EI&W

Transverse 0.4783 0.6888 0 .8116 

Vertical 0.9804 0.3990 2.1835 2.1835 

OHGW 

 tensions 

5,900 lbs. NA 7,500 lbs. 7800 lbs. 

Guy wire: 7/16” E.H.S.

Ultimate tension (R.B.S.): 20,800 lbs. 

Horizontal strength with 1/1 lead: 14,700 lbs. 

Anchors: 8,000 lbs. and 16,000 lbs.

Ultimate Capacity: 16,000 lbs. and 32,000 lbs. 

Horizontal strength with 1/1 lead: 11,300 lbs. and 22,600 lbs. 

Soil: Average, presumptive ultimate bearing capacity approximately equal to 4000 psf. 
Bulletin 1724E-200 

Page 14-11

14.8.2 Solution for Heavy Loading District: 

a. Wind on the wires: 

Conductor: a = .7027 (HS) (cos θ/2) 

OHGW: a = .4783 (HS) (cos θ/2) 

b. Wind on the pole: b = 143 lbs. 

Here (b) is based on an 80-2 pole with the guy located 60 ft. from the ground. The 

equivalent horizontal load (b), at this location is determined by Mwp/lever arm. 

b = 8590 ft.-lbs./60 ft. 

c. Wire tension loads: 

Conductor: c = 2(10,400) sin θ/2 

OHGW: c = 2(5,900) sin θ/2 

d. Equations from Table 14-1 of this bulletin: 

General Equation: 

2.50(a+b) +1.65c = Gcosβ ≤ .65Gucosβ or 

2.50(a+b) +1.65c = Gcosβ ≤ .65Aucosβ 

For one conductor: 

2.50 [(.7027) (HS) (cos θ/2) + (143)] + 1.65 [2(10,400) (sin θ/2)] ≤ .65Gu (or Au) cosβ 358 + (1.757) (HS) (cos θ/2) + 34,320 (sin θ/2) ≤ .65Gu cosβ or ≤ .65Aucosβ

550 + (2.703) (HS) (cos θ/2) + 52,800 (sin θ/2) ≤ Gu cosβ or ≤ Aucosβ

For one OHGW:

2.50 [(.4783) (HS) (cos θ/2) + (neg.)] + 1.65 [2(5,900) (sin θ/2)] ≤ .65Gu (or Au) cosβ (1.196) (HS) (cos θ/2) +(19,470) (sin θ/2) ≤ .65Gu cosβ or ≤ .65Aucosβ (1.840) (HS) (cos θ/2) +(29,954) (sin θ/2) ≤ Gu cosβ or ≤ Aucosβ

Case 1: Using 1 guy wire and 1 anchor for the three conductors and 1 guy wire and 1 anchor for 

both OHGW, the following general equations result (1/1 leads). 

 For the 3 conductors: 

3(550) + 3(2.703)(HS)(cos θ/2) + 3(52800)(sin θ/2) ≤ Gu cosβ or ≤ Aucosβ 

1650 + 8.109 (HS)(cos θ/2) + (158,400)(sin θ/2) ≤ 14,700 lbs.(for guy) 

1650 + 8.109 (HS)(cos θ/2) + (158,400)(sin θ/2) ≤ 11,300 lbs. (for anchor) 

For the 2 OHGW’s: 

2(1.840)(HS)(cos θ/2) + 2(29,954)(sin θ/2) ≤ Gu cosβ or ≤ Aucosβ 

3.680(HS)(cos θ/2) + (59,908)(sin θ/2) ≤14,700 lbs. (for guy) 

3.680(HS)(cos θ/2) + (59,908)(sin θ/2) ≤11,300 lbs. (for anchor) 

Case 2: Using 2 guy wires and 2 anchors for the three conductors and 1 guy wire and 1 anchor 

for both OHGW, the following general equations result (1/1 leads). 

For the 3 conductors: 

1650 + (8.109)(HS)(cos θ/2) + (158,400)(sin θ/2) ≤ (2)14,700 lbs. (for guy) 
Bulletin 1724E-200 

Page 14-12 

1650 + (8.109)(HS)(cos θ/2) + (158,400)(sin θ/2) ≤ (2)11,300 lbs. (for anchor) 

For the OHGW: (same as above) 

See the Guying Guide at the end of this example for plots of controlling equations. 

e. Checking for buckling of the poles. Since the outside poles carry the maximum axial load, it 

is necessary only to examine this pole. Longitudinal buckling is considered since this condition 

is the critical case. Weight of the conductor and OHGW is included in the calculations. 

The following example calculations are for Case 1 above. 

The maximum axial load which various poles can sustain can be calculated for various heights of 

structures. The Gere and Carter method is used to calculate Pcr below: 

Pole 

Class & 

Height 

Unbraced Length, l

Ground to Lowest 

Guy Attachment, 

 ft. 

dg 

in. 

da 

in. 

IA 

At Point da 

(πd4/64) 

in4 pinned-pinned assumed 

lbs.

60-1 42 15.03 9.83 458 79935 

60-2 14.09 9.14 343 60733 

60-3 13.15 8.44 249 45108 

80-1 60 16.72 9.76 445 47784 

80-2 15.64 9.05 329 35948 

80-3 14.55 8.35 239 26485 

Assuming that horizontal spans are equal to the vertical span, the previous equations in item d 

above be revised to include the weight of the conductor and OHGW on the outside pole. The 

total axial load in the pole is the sum of the axial loads induced in the pole from guying the three 

conductors and two OHGW, and the vertical weight of the OHGW and conductor. Half of the 

vertical load from the outside phase is carried by the middle pole and other half is carried by the 

outside pole. For this example, since the guy leads are 1 to 1, the vertical axial load from the 

guy wire will be equal to the horizontal component of the guy wire. 

 Wire Weight + Induced Axial Load, Guying 3 conductors and 2 OHGW’s

Cond. 1.5(.5)(2.0938)HS+ 8.109(HS)(cos θ/2) +1652 +158,400(sinθ/2) 

OHGW 1.5(.9804)HS + 3.680(HS)(cos θ/2) + 59,908(sinθ/2) 

Total (3.0401)HS + 11.789(HS)(cos θ/2) +1652 +218,300(sinθ/2) ≤ .65Pcr

2.0

a

A g

cr d

EI d

P ⎟

⎟

⎠

⎞

⎜

⎜

⎝

⎛ = 2

2

l

π
Bulletin 1724E-200 

Page 14-13

GUYING GUIDE

Structure: TH – 12 Ruling Span 800 ft. 

Conductor Type: 795 26/7 Max. Tension (L, M, H): 10,400 lbs. OHGW Type: 7/16״ E. H. S. Max. Tension (L, M, H): 5,900 lbs. Guy Wire Type 7/16״ E. H. S Ultimate Strength 20.800 lbs. 

Heavy Loading District 

pC: 0.7027 lbs./ft. pg: 0.4783 lbs/ft. wC: 2.0938 lbs./ft. wg: 0.9804 lbs/ft. 

 

 

Line Angle chart/drawing 

Case 1 Case 2

For OHGW: TG - 11A, TA - 3P For OHGW: TG – 11A, TA-3P 

For conductor: TG - 11A, TA - 3P For conductor: TG – 11C, (2)TA - 3P 

 

Total guys and anchors: Total guys and anchors: 

 (2) TG - 11A 

(2) TA - 3P 

 1 - TG – 11A 

1 - TG – 11C 

3 - TA – 3P 

 

Limitation: TA-3P to conductor Limitation: TA - 3P to conductor 

200 400 600 800 1000 1200 1400 1600 1800 2000

5°

10°

15°

20°

0

Horizontal Span

Line Angle

Case 1

Case 2

60-3 DF

60-2 DF

80-3 DF

80-2 DF

80-1 DF

TG-11C

TG-11A

TA-3P

or

2-TA-3P

TA-3P

8 ft.

1

1

9ft.
Bulletin 1724E-200 

Page 14-14 

Blank Page
Bulletin 1724E-200 

Page 15-1

15. HARDWARE

15.1 General: Hardware for transmission lines can be separated into conductor-related 

hardware and structure-related hardware. 

Conductor-Related Hardware: For many transmission lines, the conductor may constitute the 

most expensive single component of investment. Yet, this is the one component which is most 

exposed to danger and most easily damaged. In the design of any line, appropriate emphasis 

should be given to mechanical and electrical demands on the design of conductor-related 

hardware used to support, join, separate, and reinforce the overhead conductor and overhead 

groundwire. Conductor motion hardware is used to diminish damage to the overhead conductors 

from vibration. Selection and proper installation of conductor accessories will have considerable 

influence on the operation and maintenance of a transmission line. Electrical, mechanical, and 

material design considerations are generally involved in the design of conductor support 

hardware and conductor motion hardware. 

Structure Related Hardware: This includes any hardware necessary to frame a structure, to 

accommodate guying and other types of pole attachments to the structure and to provide 

necessary conductor-to-structure clearances. As structure–related hardware items are the 

connecting pieces for structural members, proper selection of this hardware is necessary to 

assure structure strength. At the same time, proper selection of structure-related hardware 

includes use of designs that are static proof or incorporate static proof aids to help minimize 

possible radio and television interference emanations from the line (see Appendix I). 

Selection of conductor-related and structure-related hardware should consider corrosion and the 

damage and degradation of strength and visual esthetics that corrosion can cause. In addition to 

selecting hardware made of materials that are less likely to corrode, the designer should be 

certain that the materials selected are compatible with one another and will not corrode when in 

contact with each other. 

15.2 Conductor-Related Hardware 

15.2.1 Suspension Clamps: Contoured suspension clamps are designed to match the conductor 

diameter in order to guard against conductor ovaling and excessively high compressive stresses 

on the conductor. Suspension clamps may be made from galvanized malleable iron or forged 

steel. Aluminum liners are recommended for aluminum conductors. Copper liners are 

recommended for copper conductors only. The connector fitting will usually be either a socket 

or clevis (see Figure 15-1). When using clamps with liners on conductors covered by armor 

rods, designers should select clamps that have the proper seating diameter for the effective 

diameter of the conductor and armor rod. Liners can be expected to add 1/10 inch to the 

conductor diameter. There are a few clamps made for large line angles (up to 120o

). However, 

these clamps are available only for small conductor sizes. When a transmission line with large 

conductors has to make a turn along its route, strain clamps should be used. In the case of 

medium angles (greater than a 30 degree line angle) double suspension clamps connected to a 

yoke plate may be needed to make a gradual turn. 

FIGURE 15-1: SUSPENSION CLAMP WITH 

 CLEVIS OR BALL AND SOCKET 

 TYPE OF CONNECTION 

U bolt
Bulletin 1724E-200 

Page 15-2 

Cushioned suspension clamps are sometimes used to support the conductor and reduce the static 

and bending stresses in the conductor. Cushioned suspension clamps are further explained in the 

conductor motion hardware section (Section 15.3). 

15.2.2 Clamp Top Clamps: Clamp top clamps for vertical and horizontal post insulators are 

popular because of they are simple to install. The clamps, made of malleable iron or aluminum 

alloy, are mounted on a metal cap. The clamp itself is composed of a removable trunion cap 

screw (keeper piece) and a trunion saddle piece (Figure 15-2). 

FIGURE 15-2: POST TYPE INSULATOR WITH STRAIGHT LINE 

TRUNION CLAMPS 

Straight line clamps are designed to hold conductors without damage on tangent and line angles 

of up to approximately 15o

. The maximum acceptable vertical angle (each side of clamp) is 

considered to be approximately 15o with the horizontal. Since the keeper piece of the clamp is 

not designed to provide the support for upward loading, this clamp should not be used where 

uplift conditions could occur. Angle clamps are available which are designed to take up to a 60o

line angle. However, when line angles are greater than 15o to 20o, suspension insulators should 

be used. The designer should coordinate with the trunion clamp manufacturer concerning the 

compatibility of the clamp design for longitudinal loads on the line. 

15.2.3 Tied Supports: A large portion of lower voltage construction involves tying conductors 

to pin and post insulator supports. Hand ties (Figure 15-3) are occasionally vulnerable to 

loosening from various forces and motion from differential ice buildup, ice dropping, galloping, 

and vibration. Factory formed ties with secure fit, low stress concentration and uniformity of 

installation may eliminate mechanical difficulties and radio interference problems associated 

with loose tie wires. 

FIGURE 15-3: TOP GROOVE HAND TIE 
Bulletin 1724E-200 

Page 15-3

15.2.4 Deadend Clamps: Deadending a conductor may be accomplished by using formed type 

deadends, automatic deadends, bolted deadends or compression type deadends (See 

Figures 15-4a and 15-4b). Because of the strength limitations of formed and automatic 

deadends, these types are limited to primarily small conductor sizes and distribution line use. 

The two basic methods of deadending a transmission conductor are by use of bolted deadend 

clamps and by compression type deadend clamps. 

Deadend clamps, or strain clamps as they are sometimes called, are made from three basic types 

of material as follows: 

Aluminum Alloy Type: 

General Notes: This type is corrosion resistant. It minimizes power losses, minimizes 

hysteresis and eddy currents, minimizes excessive conductor heating in the conductor 

clamping area and is lightweight. This clamp is the most widely used. 

Application: No armor rods or tape are required. Clamps are to be used with ACSR or all 

aluminum conductors. These clamps are not to be used with copper or copperclad 

conductors. 

Malleable Iron: 

General Notes: This clamp is somewhat lightweight. The range of conductor sizes is limited. 

Application: Clamps are to have aluminum or copper liners. Clamps with copper liners are 

to be used for copper or copper-clad conductors. Clamps with aluminum liners are used for 

ACSR and other aluminum composite type conductors 

Forged Steel: 

General Notes: Forged steel clamps are heavy in weight. 

Application: Clamps may be used with all aluminum, copper or ACSR conductors. Clamps 

are to have aluminum or copper liners. Clamps with copper liners are to be used for copper or 

copper-clad conductors. Clamps with aluminum liners are used for ACSR and other 

aluminum composite type conductors. 

FIGURE 15-4a: TYPICAL BOLTED DEADEND CLAMP 

FIGURE 15-4b: TYPICAL COMPRESSION DEADEND 

30°

30°
Bulletin 1724E-200 

Page 15-4 

The ultimate strength of the body of the bolted clamps should meet or exceed the ultimate 

strength of the conductor the clamp is designed to hold. The holding power of a bolt type or 

compression type clamp should meet the following criteria: 

• Clamps have to be capable of holding at least 90 percent of the strength of the largest 

conductor for which the clamp is designed to hold in a short-time load. 

• Clamps have to hold a sustained load of 75 percent of the strength of the conductor for 3 

days. 

For bolted type clamps, the amount of torque to tighten the bolts depends on the size of the bolt. 

Torque will range from 300 in-lbs. for 3/8” bolts to 400 in.-lbs. for 5/8” bolts. Clamps should 

also meet certain corrosion resistance tests and heat cycling tests. 

Suspension and deadend clamps for use on high voltage transmission lines are specially designed 

to control corona. Designs usually involve providing smooth and rounded surfaces rather than 

sharp edges and by placing all the clamp nuts and studs within the protection of the electrical 

shield. 

Installation of compression splices, deadend clamps, and bolted deadend clamps should follow 

the manufacturer’s recommendations. 

15.2.5 Splices: Conductor splices may be automatic compression type splices, formed type 

splices, or crimp compression type splices. For most transmission conductors, the crimped 

compression type splice is used because of its high strength capabilities. Splices should meet the 

same strength, corrosion resistance and heat cycling requirements as the deadend clamps. 

15.2.6 Strain Yokes: Two or more insulator strings may be connected in parallel by using 

yokes to: 

• Provide the strength needed to sustain heavy loads at deadend structures; • Increase the safety factor for long-span river crossings; and • Make a gradual turn at large angles. 

Usually, it is more economical to supply higher strength rated insulators than to use yokes. One 

disadvantage to using higher strength rated insulators (36,000 lbs and higher) is that the ball and 

socket size changes for porcelain insulators which will require other related hardware to be 

coordinated. 

15.2.7 Insulators: Mechanical and electrical requirements of insulators are discussed in 

Chapter 8. Where suspension insulators are exposed to salt sprays or corrosive industrial 

emissions, insulators using enlarged pin shafts or corrosion intercepting sleeves are 

recommended to prolong the life of the insulator pins. Use of corroision intercepting sleeves 

provide an air space between the pin and the cement. With this design, corrosion can attack the 

expandable long-lived sleeve. Any increase in the volume of the rust line only distorts the 

sleeve. However, without the sleeve, bursting stresses would be imposed on the adjacent 

porcelain. Other types of insulators have enlarged shafts near the cement lines which provide 

additional sacrificial metal for corrosion. 

On lower voltage lines, pin and post type insulators are mounted on structure crossarms. 

The side and top wire grooves generally limit the size of the conductor with armor rods 

that can be installed to a maximum of 4/0 and 336.4 kcmil ACSR. 
Bulletin 1724E-200 

Page 15-5

FIGURE 15-5: SUSPENSION INSULATORS 

(Ball and Socket Type, Left, and Clevis-Eye Type, Right) 

15.2.8 Fittings: Fittings used to attach the insulator to the structure may include hooks, “Y” 

ball/clevis, ball eyes, ball clevises and chain, anchor or vee shackles. The “C” hooks suggested 

on agency standard construction drawings are the self locking hooks. With the insulator cap in 

place, the opening of the hook is sufficiently restricted so that accidental disconnection cannot 

occur. Fittings should meet or exceed the ANSI M&E ratings of the insulators. Various fitting 

types are shown in Figure 15-6, 15-7 and 15-8. 

FIGURE 15-6: DIFFERENT TYPES OF HOOKS 

(Self Locking “C” Hook, Left; Ball Hook, Middle, Clevis Type Hook, Right) 

FIGURE 15-7: VARIOUS TYPES OF BALL AND CLEVIS “Y” CONNECTIONS 

FIGURE 15-8: ANCHOR SHACKLE (Left); CHAIN SHAKLE (Right) 
Bulletin 1724E-200 

Page 15-6 

15.3 Conductor Motion Hardware

15.3.1 Aeolian Vibration: All conductors are in some state of vibration, varying from 

extremely slight to temporarily severe. Selection of the proper hardware to improve conductor 

life will depend on the degree of vibration. Suspension clamps do not restrict vibration, but 

these clamps should be designed to keep to a minimum the effect of such vibration on the 

conductor. Methods to reduce the effects that aeolian vibration has on lines include the 

following: 

Armor Rods: Armor rods (Figure 15-9) should be used on lines in areas where mild vibrations 

may occur. Armor rods, wrenched or preformed, are helical layers of round rods which are 

installed over the conductor at the points of attachment to the supporting structures. The primary 

purpose of armor rods is to provide additional rigidity to the conductor at its point of support. 

The use of armor rods accomplishes: 

• Alleviating changes of mechanical stress buildup at the point of support by providing a 

gentler slope of curvature for the incoming conductor, • Increasing conductor life from fatigue failure by increasing the flexural rigidity of the 

conductor, and reducing bending stresses in the conductor, • Protecting the conductor from flashover damage and mechanical wear at the points of 

support. 

In laboratory tests, the placement of armor rods on the conductor has allowed the conductor 

to withstand considerably more vibration cycles without fatigue failure. Tests such as these 

show that there is a significant reduction in stress afforded through the use of armor rods. 

FIGURE 15-9: ARMOR RODS USED WITH SUSPENSION INSULATORS 

Cushioned Suspension Units: These units use resilient cushioning in conjunction with armor 

rods to further reduce the static and dynamic bending stresses in the conductor (See 

Figures 15-10a and 15-10b). With this cushioning, the compressive clamping force is decreased, 

thereby reducing stress concentration notches. For line angles greater than 30o

, single support 

units should be replaced with double units. When considering longitudinal loads for a line using 

cushioned suspension units, the designer should consider that the units have a slip load of 

approximately 20 percent of the rated breaking strength of the conductor. A disadvantage to 

cushioned suspension units is that it is very difficult to remove or install these units with hot line 

tools. 

FIGURE 15-10a: 

CUSHIONED SUSPENSION 

UNIT 

FIGURE 15-10b: 

DOUBLE CUSHIONED SUSPENSION 

(For Line Angles Greater Than 30o) 

Armor Rod
Bulletin 1724E-200 

Page 15-7

Dampers: These are used in areas of severe vibration. They act to attenuate aeolian vibration 

amplitudes and thereby reduce the dynamic bending stress at hardware locations and extend 

conductor life. Suspension dampers (figure 15-11) make use of the connecting cables between 

weights to dissipate the energy supplied to the damper. Use of spiral dampers (Figure 15-12) is 

limited to small conductor sizes (Figure 15-12). 

When a vibration wave passes the damper location, the clamp of a suspension type damper 

oscillates up and down, causing flexure of the damper cable and creating relative motion 

between the damper clamp and damper weights. Stored energy from the vibration wave is 

dissipated to the damper in the form of heat. For a damper to be effective, its response 

characteristics should be consistent with the frequencies of the conductor on which it is installed. 

Dampers of various designs are available from a number of manufactures. The number of 

dampers required, as well as their location in the span should be determined by consultation with 

the damper manufacturer. 

FIGURE 15-11: TYPICAL SUSPENSION DAMPER 

FIGURE 15-12: SPIRAL VIBRATION DAMPER FOR SMALL CONDUCTORS 

Application of armor rods, cushion suspension or dampers or a combination thereof should be on 

a case-by-case basis. A certain item should not be used merely because it has given satisfactory 

performance in another location. 

If prevailing wind conditions and the terrain are such that vibration will occur most of the time, 

some form of vibration protection should be investigated. Dampers should be selected on the 

basis of the frequencies one expects to encounter in the terrain that must be traversed. The 

engineer should not specify a certain type of damper or armor rod simply because everyone else 

is using them. An improperly located damper can affect the amount of protection and ability of 

the damper to suppress the damaging effects of aeolian vibration. 

Armor rods are meant to be reinforcement items, not dampers. Vibrations are passed on through 

the conductor clamp basically without any attenuation, and then dissipated in the supporting 

structure. If the structure is made of steel and if fatigue can be a problem then use of dampers 

along with armor rods should be investigated. However, care should be exercised in selecting 

the distance between the ends of the armor rods and the dampers, if both are to be used. 

Damper Clamp Conductor

Damper Weight Damper Cable Drain Hole

Tapered Sleeve
Bulletin 1724E-200 

Page 15-8 

15.3.2 Galloping: Hazards associated with galloping conductors include: 

• Contact between phases or between phase conductors and ground wires, 

• Racking of the structure, 

• Possible mechanical damage at supports. 

Aerodynamic drag dampers and interphase spacers are used to limit the amplitude of the 

conductor during galloping. Historically, effectiveness of anti-galloping devices has been 

erratic. 

15.3.3 Bundled Conductors: Bundled connectors are not used very often on transmission lines 

under 230 kV but are often economically justified above 230 kV. Bundled conductors can 

experience aeolian vibration, galloping, corona vibration, and subconductor oscillation. For a 

bundled conductor with spacers, aeolian vibration may be reduced by a factor of 10. However, 

galloping of ice coated conductors will occur more readily and more severely on bundled lines 

than on single conductors in the same environment. 

Subconductor oscillation, though, has caused a major share of the problems to date. It is caused 

by one conductor lying in the wake of an upstream conductor and thereby being excited to 

vibrate in a nearly horizontal ellipse. Damage has consisted of conductor wear as well as spacer 

deterioration and breakage. To reduce subconductor oscillation, subspan length or the distance 

between spacers should be kept below 250 feet. 

The primary purpose of spacers is to reduce the probability of conductor contact and magnitude 

of vibration. Spacers may be rigid, articulated or flexible. They may be open-coil and closedcoil springs, and wire rope and steel strand connecting members. Spacers should grip bundled 

conductors securely to avoid abrasion of the subconductors and to prevent conductor 

entanglement during strong winds. 

15.3.4 Insulator Swing: Occasionally, tie-down weights are used to control conductor position 

by preventing excessive uplift and swinging. A line should not be designed to use tie-down 

weights as a means of preventing the conductor from swinging into the structure. Sometimes 

due to a low Vertical/Horizontal span ratio, weights may have to be used on an occasional 

structure. Two types of tie down weights are shown in Figure 15-13. 

FIGURE 15-13: DISC WEIGHTS (Left), BALL WEIGHTS (Right) 

15.4 Structure Related Hardware for Wood Structures

15.4.1 Fasteners: Threaded rods and machine bolts are frequently used on wood transmission 

structures (Figure 15-14). A static-proof bolt has a washer securely fixed to the head of the bolt 

and is furnished with washer nuts. Variations of the static-proof bolt include shoulder eye bolts 

with round or curved washers welded to the eye, forged shoulder eye bolts and forged eye bolts. 

MF type locknuts, used in conjunction with a regular nut or washer nut, form a solid unit which 

Attach to the suspension 

clamps via hold down 

shackles 
Bulletin 1724E-200 

Page 15-9

does not loosen from vibration and helps to maintain a static proof installation. The strengths 

and tensile stress areas of bolts conforming to ANSI C135.1 are shown in the Table 15-1. 

FIGURE 15-14: FASTENERS 

TABLE 15-1 

STRENGTHS OF ANSI C135.1 MACHINE BOLTS, DOUBLE ARMING 

BOLTS, AND DOUBLE END BOLTS 

Machine Bolt

Diameter 

in. 

Tensile 

Stress Area

sq. in. 

Minimum Tensile

Strength 

lbs. 

1/2 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 13-5) are sometimes used in lieu of bolts when shear loads are small. A lag 

screw with fettered edges is driven into the wood and maintains its holding power with cone 

shaped threads. When lag screws are used, the moment capacity of the wood pole is reduced in 

the same manner as a bolt hole reduces moment capacity. 

FIGURE 15-15: LAG SCREW 

Anti-split bolts help prevent the propagation of checking and splitting at the end of crossarms. A 

three inch edge distance should be provided between the anti-split bolt and the edge of the arm. 

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 

Static Proof Double End 

Bolts 
Bulletin 1724E-200 

Page 15-10 

15.4.2 Framing Fittings: The primary purpose for using grid gains is to reduce bolt hole 

slotting by distributing the shear load of the bolt over a large wood area. The specially shaped 

teeth of the grid gain press into the wood surface and offer maximum resistance to movement 

both with and across the grain of the wood. The use of grid gains will strengthen bolt 

connections and are recommended anytime a bolt must carry large shear loads. Two applications 

of grid gains are shown in Figure 15-16. 

FIGURE 15-16: GRID GAINS 

The gain plate (between a pole and a crossarm) and the reinforcing plate (on the outside of an 

arm) provide additional metal bearing surface for transfer of the vertical load from the crossarm 

to the crossarm mounting bolt. The gain plate eliminates a potential decay area between two 

wood contact areas. A reinforcing plate, also called a ribbed tie plate, will prevent the crossarm 

from splitting or checking when the nut is tightened. 

When double crossarms are used to allow longer vertical spans or to increase longitudinal 

strength capabilities, spacer fittings Figure 15-17 are needed to separate the crossarms and to 

provide a point of attachment for suspension insulators. If fixed spacers are used, poles should 

be gained. Since the standard fixed spacing sizes are 7-1/2”, 9”, 10-1/2”, and 12”, the crossarm 

may be bowed +1/2 inch. The brand on the butt and face of the pole should include proper 

designation of the fixed spacer size. Adjustable spacers will fit a range of pole diameters. When 

they are used the pole need not be gained. 

FIGURE 15-17: SPACER FITTING, REINFORCING PLATE 

AND GAIN PLATE 

15.4.3 Swing Angle Brackets: Swing angle brackets are used to provide increased clearance 

between phase conductors and the structure to which the conductors are attached (Figure 15-18). 

These brackets cab be mounted horizontally or vertically. The two primary types of angle 

brackets are the rod type for light loads, and angle iron type for heavier loads. 

Grid Gains Application of Grid Gains

Spacer Fitting Reinforcing Plate

and Gain Plate
Bulletin 1724E-200 

Page 15-11

FIGURE 15-18: SMALL ANGLE 

 STRUCTURE WITH SWING 

ANGLE BRACKETS 

15.4.4 Guy Attachments: The primary types of guy attachments used on wood transmission 

line structures include the wrap guy, guying plates, pole eye plates, guying tees, and pole bands. 

Other types of guy attachments such as formed straps, angle bolt eyes, and goat hooks are used 

primarily on distribution lines. Guy attachments are used to attach the insulators to the structure 

as well as providing a means of guying the structure. 

15.5 Structure Related Hardware for Concrete and Steel Structures: Much of the structure 

related hardware used on wood construction may be appropriate to use on steel or concrete 

structures. However, hardware items with grid teeth, such as grid gains or guy attachments with 

grid teeth, are not appropriate for use on steel or concrete structures. Likewise, lag screws and 

gain plates are not used on steel and concrete poles. Since steel and concrete poles do not shrink 

and swell with age and weather, spring washers may not be needed to keep the hardware tight 

over time. 

In many instances, higher strength bolts are used with steel or concrete poles. Bolts such 

ASTM A325, Specification for High-Strength Bolts for Structural Steel Joints, may be 

specified instead of the ANSI C135 bolts. Table 15-2 gives the strength ratings for bolts 

conforming to ASTM Standard A325. 

TABLE 15-2 

STRENGTHS OF ASTM A325 

HEAT TREATED, HIGH STRENGTH BOLTS 

Machine Bolt 

Diameter 

in. 

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 
Bulletin 1724E-200 

Page 15-12 

steel pole supplier or concrete pole supplier to obtain the capacity and performance desired. 

Selection of hardware should also consider proper fit with other hardware. 

When using standard class concrete or steel poles, the owner should provide the pole 

manufacturer with the load capabilities, attachment method, and attachment location of all 

appurtenances. The pole manufacture should verify that the pole will not have a localized 

strength problem at the attachment point. Items to consider if standard class steel or 

concrete poles are guyed include: 

• Localized buckling at the guy attachment, 

• Field holes in the wrong locations, 

• Unexpected torsion on the pole due to the fact that the pole is not round and the correct 

guy plate location does not fall on one of the pole’s flat surfaces, and 

• Sliding of the slip joint under heavy conductor loads. 

In the use of concrete and steel structures, a means for climbing the structure should be provided. 

The NESC Rule 261N states the requirements for climbing devices and attachments to the 

structure. Based on this requirement, it is recommended that step bolts, removable steps, 

ladders, and each attachment to the pole be designed to support a minimum of a 300-pound 

worker and equipment multiplied by a 2.0 load factor. The load should be applied at the outer 

edge of the step or bolt and should be supported without permanent deformation. Refer to agency 

Bulletins 1724E-204, -206, -214, and -216, for additional guidelines on the use of concrete and 

steel structures. 

15.6 Corrosion of Hardware: Corrosion may be defined as the destruction of metal by a 

chemical or electro-chemical reaction with its environment. Certain industrial and sea coast 

environments accelerate the rate of corrosion. Parameters which stimulate corrosion include air 

(oxygen) dissolved in water, airborne acids, sulphur compounds (from cinders, coke, coal dust,) 

salt dissolved in water, corona, etc. 

Any two dissimilar metals when placed together in the presence of an electrolyte form a simple 

battery. One metal becomes an anode, sacrificing itself to the other metal which becomes the 

cathode. One method to reduce the rate of corrosion is to select metals which are compatible 

with one another. Table 15-3 details the galvanic voltage of various metals commonly used for 

transmission line hardware. The greater the algebraic difference between the metals selected, the 

more rapid the rate of corrosion will be of the more electronegative metal selected. 

TABLE 15-3 

GALVANIC TABLE OF VARIOUS METALS 

Silver +.79 

Copper +.34 

Lead -.13 

Tin -.15 

Iron -.35 

Chromium -.47 

Zinc -.77 

Aluminum -1.337 

As an example, when malleable iron suspension clamps are used, aluminum liners should be 

furnished in order to reduce the rate of corrosion of the aluminum conductor. As another 

example, the selection of staples to be used on the pole ground wire must be compatible material 

to the ground wire (see Drawing TM-9 in Bulletins 1728F-810 and 1728F-811). 
Bulletin 1724E-200 

Page 15-13

Other methods of reducing the rate of corrosion are to galvanize tin plate, paint or cover metals 

with corrosion inhibitors. The life of used metals can be prolonged by increasing metal 

thickness. 
Bulletin 1724E-200 

Page 15-14 

Blank Page 
Bulletin 1724E-200 

Page 16-1 

16. UNDERBUILD

16.1 General: Placing of underbuild distribution or communications circuits on transmission 

lines is a practice that is becoming more prevalent as available rights-of-way decrease. Although 

underbuild distribution lines increase the initial cost of a transmission line, common sharing of a 

right-of-way is sometimes necessary in order to build the line. 

The following factors should be considered in designing a common use line: hazards to 

personnel and property, costs, difficulties of construction, operation and maintenance. Adequate 

structure arrangement and conductor separation should be provided to minimize the possibility 

of conductor contacts, and to provide safe working conditions. Adequate electrical protection 

involves prompt and positive de-energization of power circuits in the event of conductor contact 

or flashover. Obtaining and maintaining a low ground resistance to earth is desirable to limit the 

magnitude of voltage rise, duration of hazardous voltage, and lightning damage. 

16.2 Addition of Distribution Underbuild to an Existing Transmission Line: Distribution 

circuits can be added to existing transmission structures only if the original transmission 

structure was designed for the new particular underbuild facilities or the total structure facilities 

meets the current edition of the NESC. 

16.3 Strength Requirements: Standard distribution construction is required to meet NESC 

Grade C construction in accordance with 7 CFR Part 1724. However, underbuild distribution on 

transmission circuits, with the exception of the crossarms, are to be built to meet all requirements 

of NESC Grade B construction. This means that the loading on the pole due to the distribution 

circuits has to be calculated using NESC Grade B overload capacity factor and strength factors, 

It also means that all guying for the underbuild must meet the guying requirements for 

transmission. Distribution crossarms on transmission structures may be designed for NESC 

Grade C construction, except at angles where they have to be designed for NESC Grade B 

construction. 

16.4 Line-to-Ground Clearances: Since the lowest conductors on a transmission line with 

underbuild will usually be those of the distribution circuits, the clearances to ground and 

clearances in crossing situations will in most instances be limited by the requirements stipulated 

in the NESC for distribution circuits. 

The problem of providing satisfactory clearance becomes more involved when multiple 

distribution circuits or conductors cross on the same structure. In these instances, very careful 

attention need to be given to the allowable clearance in Section 23 of the NESC. 

Particular attention should be given to the use of reduced size distribution neutrals since the 

clearance to ground for the neutral, by virtue of its increased sag and position on the pole or 

crossarm, may be the controlling factor for pole height. In some cases, it may be more 

economical to increase the size of the neutral to reduce its sag. 

16.5 Separation Between Transmission and Underbuild Distribution Circuits: The 

clearances discussed in this section are intended to provide not only operating clearances but 

also sufficient working clearances. A distribution line worker has to be able to access and work 

on the distribution underbuild without encroaching upon the required safety (zone) clearances of 

the transmission conductors. 

16.5.1 Horizontal Separation: The horizontal separation at the support between the lowest 

transmission conductor(s) and the highest distribution conductor(s) or neutral should be at least 

1 foot if possible as illustrated in Figure 16-1. 
Bulletin 1724E-200 

Page 16-2 

 

FIGURE 16-1: HORIZONTAL 

SEPARATION REQUIREMENTS 

BETWEEN TRANSMISSION AND 

UNDERBUILD 

FIGURE 16-2: VERTICAL 

SEPARATION REQUIREMENTS AT 

STRUCTURE FOR UNDERBUILD 

16.5.2 Vertical Clearance to Underbuild at Supports: Recommended minimum vertical 

clearances between the transmission conductors and the underbuild conductors at the support are 

shown in Table 16-1. These clearances apply regardless of the amount of horizontal separation 

between transmission and underbuild conductors (see Figure 16-2). 

16.5.3 Vertical Clearance to Underbuild at any Point in the Span: Recommended minimum 

vertical clearances at any point along the span are shown in Table 16.1. 

These clearances apply for the condition below which yields the least separation between the 

upper and lower conductor. 

a. An upper conductor final sag at a temperature of 32°, no wind, with radial thickness of ice 

for the applicable loading district; 

b. An upper conductor final sag at a temperature of 167oF; 

c. Upper conductor final sag at a maximum design temperature, no wind. For high voltage bulk 

transmission lines of major importance to the system, consideration should be given to the 

use of 212oF as the maximum design conductor temperature. 

The sag of the underbuild conductor to be used is the final sag, at the same ambient temperature 

as the upper conductor without electrical loading and without ice loading. 

If the transmission line or portion thereof is at an altitude which is greater than 3300 feet, an 

additional clearance (as indicated in Table 16-1) has to be added to both clearances at the 

structure (Category 1) and clearances at the midspan point (Category 2). 

16.5.4 Additional Clearance Requirements for Communication Underbuild: For 

communication underbuild, the low point of the transmission conductors at final sag, 

60 ̊ F, no wind, should not be lower than a straight line joining the points of support of the 

highest communication underbuild. 

1' min. if 

possible

1' min. if 

possible

Dv
Bulletin 1724E-200 

Page 16-3 

TABLE 16-1 

RECOMMENDED MINIMUM VERTICAL CLEARANCES TO DISTRIBUTION OR 

COMMUNICATION UNDERBUILD ON TRANSMISSION LINES IN FEET 

(Circuits may be of the same or different utilities) 

(Based on NESC Rule 235 and Table 235-5) 

Transmission Nominal voltage, Phase 

to Phase 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 .5 feet of clearance is added to the NESC clearance to obtain the recommended design 

clearances. 

16.5.5 Span Length and Clearance to Underbuild: The conditions of either Paragraph 16.5.2 

or Paragraph 16.5.3 above will dictate what the minimum clearance to underbuild at the structure 

should be. If the clearance to an underbuild is dictated by Paragraph 16.5.3 of this section, the 

clearance at the structure would have to be increased. Vertical separation at the structure may 

depend upon the relative sags of transmission and underbuild conductors. Since the span length 

has an effect on relative sags, the resulting maximum span as limited by vertical clearance to 

underbuild should be calculated to ensure that the vertical separation at the support is correct for 

each span. 
Bulletin 1724E-200 

Page 16-4 

The formula for maximum span as limited by clearance to underbuild is: 

 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 

16.6 Climbing Space: Climbing space through the lower circuits should be preserved on one 

side of the pole or in one quadrant from the ground to the top of the pole as required by the 

NESC. Working space should be provided in the vicinity of crossarms. Jumpers should be kept 

short enough to prevent their being displaced into the climbing space. 

16.7 Overhead Ground Wires and Distribution Neutrals: Standard distribution underbuild 

construction has its own neutral. This neutral may be tied to the transmission pole ground wire 

in order to improve its grounding. Depending on the characteristic of the circuits, a common 

ground or a separate ground is acceptable. If separate grounds are used, the pole ground wires 

should be located on opposite sides of the pole. Similar materials should be used for both the 

transmission pole ground wire and for the distribution pole ground wire and ground rod. For 

example, if copper is used for the transmission pole ground, then copper and/or copperclad 

should be used for the distribution ground rod and pole ground wire. Use of similar materials 

will reduce the possibility of galvanic corrosion. Likewise, the distribution anchors and 

transmission anchors should be of similar material as the ground rods and wire used for the pole 

butt wraps. 

For distribution underbuild on concrete transmission poles, the neutral may be tied to the 

external pole ground using a compression connector in locations where the neutral is to be 

grounded. A lead from the pole ground should then be tied to a separate ground rod via a 

compression connector six inches to one foot above the ground level. Similarly, in the case of 

steel poles, there may be situations where the neutral of the distribution underbuild is to be 

grounded. In these instances, the pole may be used as the ground path but not as a ground 

electrode. A grounding connector mounted on the pole needs to be specified just below the 

location of the neutral on the pole. The ground pad near the ground line should then be used to 

connect a driven ground rod to the pole. 

16.8 Addition of Poles for Underbuild: There may be structures where it is either desirable or 

necessary to transfer distribution circuits to separate poles. Such situations include: 

• Large Line Angles (Figure 16-3) • Substation Approaches 

• Deadends • Transformers or Regulators (Figure 16-4) 

• Tap-offs • Capacitors 

• Sectionalizing Structures 

( ) u

ma x S S

A B L RS −− =

l
Bulletin 1724E-200 

Page 16-5 

FIGURE 16-3: TRANSFERENCE OF THE DISTRIBUTION CIRCUIT 

TO A SEPARATE POLE AT A LARGE ANGLE 

Location of transformers on structures carrying both transmission and distribution lines should 

be avoided. Not only does the transformer create an unbalanced load on the structure, but the 

additional conductors necessary for service drops may make working on the structure hazardous 

to personnel. A ground rod should be installed at every pole location with a transformer and the 

transformer grounded per NESC requirements. 

FIGURE 16-4: USE OF A SEPARATE POLE TO MOUNT 

 A DISTRIBUTION TRANSFORMER 

16.9 Guying: The need to provide additional guys to compensate for the effect of underbuild 

on structures is readily apparent. However, there are locations where special attention has to be 

given to the guying being proposed. One example is a common use pole with a line tap. 

FIGURE 16-5: GUYING DISTRIBUTION UNDERBUILD 

M P

Tension due to

vertical loading

only

Guy

Sketch (b)

Transmission Line

Distribution

N

Sketch (a)

x

x

Transmission Distribution

Transformer 

Pole

(See Table 4-2 

for Clearance)

(See Table 4-2 

for Clearance)

Transformer 

(See Table 4-2 

for Clearance)

Transformer 
Bulletin 1724E-200 

Page 16-6 

For winds perpendicular to the transmission line, the guying described in Figure 16-5 may be 

insufficient. This will be true if consideration has been given only to underbuild deadend tension 

shown as forces (x) in the figure. The maximum transverse load acts on half the sum of adjacent 

spans, (MN+NP)/2, of the transmission and distribution circuits. 

These forces have to be added to the tensions of tap conductors in order to determine the proper 

amount of guying required. If winds are parallel to the transmission line, the deadend loading of 

the tap is larger and this load should be used. Guying of the distribution underbuild is to meet 

Grade B construction. 

A general rule is that where the transmission circuit or the distribution circuit requires guys, both 

circuits should be guyed. The guys should be designed to carry the entire transverse load on the 

structure at maximum loading conditions. All drawings should show location and slope of guys 

to assure adequate clearances when guys are required. Positions of guys should be clear from 

other hardware or electrical connections, such as connectors between neutral and pole ground 

wire. Where guys may pass close to conductors, minimum clearances in accordance with Table 

4-2 should be met. 

16.10 Example: Maximum Span as Limited by Clearance to Underbuild: A 69 kV single 

pole transmission is to be built with a 25 kV underbuild distribution circuit. Determine 

maximum span as limited by clearance between transmission conductors and underbuild. 

16.10.1 Given: 

• Vertical separation between transmission and distribution conductors at the structure is 

11.0 ft. • Ruling span: 300 ft. • NESC Heavy loading district • Conditions for the conductor: 

a. Transmission conductor is at 32°F with 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 

16.10.2 Solution: 

From Table 16-1 the required vertical clearance at midspan between the transmission and 

distribution conductors is 4.2 feet. 
Bulletin 1724E-200 

Page 16-7 

Next, calculate the separation between the upper and lower conductor for each loading condition 

given above: 

(a) 11’ - 4.40’ + 1.60’ = 8.20’ 

(b) 11’ - 6.73’ + 1.60’ = 5.87’ 

(c) 11’ - 6.73’ + 3.98’ = 8.25’ 

The condition (b) results in the least separation between the transmission and underbuild 

conductors; therefore, the condition (b) conductor sag values will be used in the following 

equation: 

 

 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 6.3 of this manual. 

( ) u

ma x S S

A B L RS −− =

l

( ) 1.60 6.73

4.2 11 300 −

− = ma x L
Bulletin 1724E-200 

Page 16-8 

Blank Page 
Bulletin 1724E-200 

Page A-1 

APPENDIX A 

TRANSMISSION LINE DESIGN DATA 

SUMMARY SHEET AND SUPPORTING INFORMATION 

• Sample Summary Sheet A-3 

• Instructions A-5 

• Suggested Outline for Design Data Summary Book A-10 
Bulletin 1724E-200 

Page A-2 

Blank Page 
Bulletin 1724E-200 

Page A-3 

I. GENERAL INFORMATION 

BORROWER: DATE: 

LINE IDENTIFICATION: 

VOLTAGE LENGTH 

TRANSMISSION UNDERBUILD TRANSMISSION UNDERBUILD 

___________kV ___________kV ___________mi

. 

___________mi. 

TYPE OF TANGENT STRUCTURE: BASE POLE: 

____________HT. ____________CL 

TRANSMISSION LINE DESIGN 

DATA SUMMARY 

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 HIGH WIND/ICE 

 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 32  ̊F 

HIGH WIND (NO ICE) _____ ̊F 

UNLOADED LOW TEMPERATURE _____ ̊F 

SAGS (FT)

NESC DISTRICT LOADED _____ ̊F 

UNLOADED HIGH TEMP(120 ̊FOR OHGW &U.B.)___ ̊F 

MAXIMUM ICE 32 ̊F 

LOADED 1/2” ICE, NO WIND 32 ̊F 

V. CLEARANCES 

 MINIMUM CLEARANCES TO BE MAINTAINED AT:_____________________________________________________________________ 

CLEARANCES 

IN FEET RAILROADS HIGHWAY 

CULTIVATED 

FIELDS ADDITIONAL . ALLOWANCE 

TRANSMISSION 

UNDERBUILD 

VI. RIGHT OF WAY 

 WIDTH _____________ FT. (MIN.) _____________ FT. (MAX.) 
Bulletin 1724E-200 

Page A-4 

VII. CONDUCTOR MOTION DATA 

 HISTORY OF CONDUCTOR GALLOPING: 

HISTORY OF AEOLIAN VIBRATION: 

a. TYPE OF VIBRATION DAMPERS USED (IF ANY)

b. TYPE OF ARMOR RODS USED (IF ANY) 

VIII. INSULATION 

NO. OF THUNDERSTORM DAYS/YR______________ELEV.ABOVE SEA LEVEL (MIN, MAX, ft.)____________________ 

CONTAMINATION EXPECTED?_____________MAX EST. FOOTING RESISTANCE___________Ω SHIELD ANGLE __________ ̊

STRUCTURE 

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.): 

CORROSIVENESS OF ATMOSPHERE: 

DESCRIBE TERRAIN AND CHARACTERISTICS OF SOIL 

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 ANCHORS: ____________________________ 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 appropriate) 

LENGTH – Self-explanatory. 

TYPE OF TANGENT STRUCTURE – Give agency designation for tangent structure 

type used (for example, “TH-10”). If the structure is not a standard agency structure, the 

word “special” should be filled in. 

BASE POLE – The height and class of pole used most widely in line. 

DESIGNED BY – Individual and/or firm doing the designing. 

II. CONDUCTOR DATA 

SIZE – For conductors, size in AWG numbers or kcmil. For steel wire, diameter in 

inches. 

STRANDING – Number of strands. For ACSR conductor, give aluminum first, steel 

second. For example: 26/7. 

MATERIAL – Indicate conductor or wire type. For example, ACSR, 6201;or EHS (extra 

high strength steel). 

DIAMETER – Diameter of conductor, in. 

WEIGHT – Weight per foot of bare conductor, lbs/ft. 

RATED STRENGTH – Standard rated strength of conductor. 

III. DESIGN LOADS 

NESC LOADING DISTRICT – Indicate the National Electrical Safety Code loading 

district on which design is based. Use “H” for heavy, “M” for medium, and “L” for light 

loading district. 
Bulletin 1724E-200 

Page A-6 

a. Ice – Radial in. of ice on conductor for loading district specified. 

b. Wind – Wind force in lbs. for loading district specified. 

c. Constant “K” – Constant from NESC to be added to resultant of horizontal and 

vertical load (at standard loading district condition) for determining conductor sags 

and tensions. 

HEAVY ICE – (no–wind, in.) – Radial thickness (in.) of ice conductor for the heavy 

icing condition for which line is designed (if any). 

HIGH WIND – (no ice – psf) – The high wind value in lbs/sq. ft. for which the line is 

designed. 

COMBINED EXTREME ICE/WIND – The loadings associated with the 50 yr extreme 

ice/wind from the figures in 11.3 of this bulletin. The radial thickness of ice and the unit 

loads should be given for the vertical loads. The high wind associated with the radial 

thickness of ice should be given for the tansverse loads as well as the unit loads. 

LOADING TABLE - Conductor or wire loads in lbs. per linear ft. for conditions 

indicated at left. 

IV. SAG & TENSION DATA 

SPANS – AVG., MAX., and RULING – Self-explanatory. 

SOURCE OF SAG-TENSION DATA – Self-explanatory. 

TENSION TABLE – Initial and final tension values in percent of rated strength at 

loading conditions indicated on the left should be given. In those boxes where there is a 

dotted line in the center, the specified tension limiting values (in percent) should be given 

above the line. The actual resulting tension value (in percent) should be given below the 

line. For all other boxes the tension value should be the actual resulting value (in 

percent). The details of loading condition should be filled in on the left as follows: 

a. Unloaded (0o, 15o, 30o) – Indicate appropriate temperature. Heavy loading district 

will be 0oF, medium will be 15oF, light will be, 30oF. 

b. NESC Loaded (0o, 15o, 30o) – Specify appropriate temperature. 

c. Maximum Ice – Use the same maximum radial ice as indicated in the 

DESIGN LOADS section. 

d. High Wind – Use the same value as in the DESIGN LOAD section. 

e. Unloaded Low Temperature – Specify lowest temperature that can be expected to 

occur every winter. 

SAG TABLE – Specify initial and/or final sags in ft. for conditions indicated. Specify 

maximum conductor operation temperature in the appropriate box on the left. Sags for 

the overhead ground wire and underbuild conductors are for a temperature of 120oF. 

Note: When sag and tension calculations are done, tension limits are usually specified at 

several conditions. However, only one of the conditions will usually control, resulting in 

tensions, at the other conditions, that are lower than the limit. 

V. CLEARANCES 

MINIMUM CLEARANCES TO BE MAINTAINED AT – Specify maximum sag 

condition at which minimum clearances are to be maintained. Generally, it will be at the 

high temperature condition but it may be possible for the sag at NESC loading (H, M, L) 

to be the controlling case. 
Bulletin 1724E-200 

Page A-7 

CLEARANCE TABLE – Indicate clearance which will be used for plan and profile and 

design. Extra boxes are for special situations. 

VI. RIGHT-OF-WAY WIDTH 

Indicate width value used. If more than one value is used, give largest and smallest 

value. 

VII. CONDUCTOR MOTION DATA 

HISTORY OF CONDUCTOR GALLOPING – Indicate if conductor galloping has ever 

occurred in the area and how often it can be expected. 

HISTORY OF AEOLIAN VIBRATION – Indicate whether or not the line is in an area 

prone to aeolian vibration. 

a. Type of Vibration Dampers Used (if any) – Self-explanatory. 

b. Type of Armor Rods Used (if any) – Indicate whether standard armor rods, cushioned 

suspension units or nothing is used. 

VIII. INSULATION 

NUMBER OF THUNDERSTORM DAYS/YEAR – Self -explanatory. 

ELEVATION ABOVE SEA LEVEL (min., max., ft.) – Give the altitude in ft. above sea 

level of the minimum and maximum elevation points of the line 

CONTAMINATION EXPECTED? – Indicate contamination problems which may affect 

the performance of the insulation. The following are recommended terms: None, Light, 

Medium, Heavy, Sea Coast Area. 

MAXIMUM ESTIMATED FOOTING RESISTANCE. – Give the estimated maximum 

electrical footing resistance (in ohms) expected to be encountered along the length of the 

line. Where the footing resistance is high, the value to which the footing resistance will 

be reduced, by using special measures, should be indicated by putting this value in 

parentheses. For example, 70(20). 

SHIELD ANGLE – If the basic tangent structure being used is not a standard structure, 

its shield angle should be given. 

INSULATION TABLE – For the structure type indicated, the structure numerical 

designation and the number of suspension bells should be given. If post insulators are 

used instead of suspension, the word “post” or “pin” should be put in the second column. 

If nonceramic insulators are used, indicate ‘susp-nci’ or ‘post-nci’. The 60 Hz dry 

flashover value for the entire string of insulators (or post) should be given. The column 

“insulator size” should contain the diameter and length of the insulator. For suspension 

bell, the M&E strength should be given. For post insulator, the ultimate cantilever 

strength should be entered. For nonceramic insulators suspension or posts, give the SML 

ratings. 
Bulletin 1724E-200 

Page A-8 

IX. INSULATOR SWING 

CRITERIA – Self-explanatory 

INSULATOR SWING TABLE – For the primary structures used in the line and the 

number of insulators used, the insulator swing angles under the 6 lb. minimum condition, 

the high wind condition and under the no wind condition should be given.. Angles 

measured from a vertical through the point of insulator string suspension away from 

structure should be indicated by following them with an asterisk (*). 

X. ENVIRONMENTAL & METEORLOGICAL DATA 

TEMPERATURE – The minimum, maximum, and average yearly low temperature 

recorded in the area of the line should be given. 

MAXIMUM HEIGHT OF SNOW ON GROUND UNDER CONDUCTOR 

(ft.) – Self-explanatory. 

CORROSIVENESS OF ATMOSPHERE – Indicate corrosiveness of the atmosphere by 

severe, moderate, or light. 

EXTREME 10 SEC WIND GUSTS – Give the annual extreme wind with mean 

recurrence intervals of 10, 50, and 100 years. For 50 year, see Figures 11-2a to 11-2d of 

Chapter 11. For 10 year, see paragraph 7.2.3 of Chapter 7. 

DESCRIBE TERRAIN & CHARACTER OF SOIL – A brief description should be given 

as to whether the terrain is flat, hilly, rolling piedmont, or mountainous. Indicate whether 

the soil firmness is good, average, or poor. Give approximate depth of ground water 

table. Describe corrosiveness of soil. 

XI. STRUCTURE DATA (For single poles and H-frames) 

POLE MATERIAL – Indicate wood, steel, or concrete. If wood, indicate species. 

ARM MATERIAL – If a crossarm is used, indicate wood, steel or fiberglass.. 

TYPE OF FOUNDATION – For tangent, angle, or deadend structures, indicate direct 

embedded or caisson for the majority of the structures within each type. For example, if 

most of the angle and deadends are unguyed, indicate the predominant foundation for 

each type. 

STRUCTURE TABLE The various maximum span values should be given for the base 

pole and structure configuration. Values should also be given for other pole heights, 

wood classes or standard steel/concrete pole classes, bracing and configurations that are 

expected to be commonly used. 

a. Level Ground Span – Give the maximum span for height of pole, limited by 

clearance to ground only. 

b. Maximum Horizontal Span Limited by Structure Strength – For single pole 

structures, give the maximum span as limited by pole strength. For H-frame 

structures, the effect of the bracing must be included. If vertical post insulators are 

used, their maximum horizontal span value should be included if it is less than that of 

the rest of the structure, and should be indicated as such by placing the term “ins” 

after the value. If underbuild is to be used on the line, its effect should be included. 
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. The outline is primarily 

intended for lines of 230 kV Generally, a well prepared design data book should include all the 

material indicated below. However, some judgment should be used in submitting more or less 

information as deemed appropriate. 

I. Transmission Line Design Data Summary 

II. General Information 

A. Line identification, description and role in system 

B. Description of terrain and weather 

C. Design criteria and applicable codes and standards 

D. Selection of conductor and OHGW 

1. Selection of conductor and OHGW type 

2. Selection of conductor and OHGW size/ 

Economic conductor analysis 

E. Determination of maximum conductor temperature 

F. Selection of structure type and average height 

1. Economic evaluation of alternate structures 

2. Selection of optimum structure height 

G. 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-7 
Bulletin 1724E-200 

Page B-2 

CONDUCTOR MECHANICAL 

LOADING TABLES 

The tables that follow give horizontal, vertical, and resultant vector loads on conductors and 

overhead ground wires under standard NESC loading district conditions, high wind conditions, 

and heavy ice conditions. 
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 

NAME SIZE STRAND LB/FT. LB/FT. LB/FT. LB/FT. LB/FT. LB/FT. LB/FT. LB/FT. LB/FT. 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 QUAIL 2/0 6/1 0.1831 0.3353 0.4320 0.3998 0.3157 0.7094 0.7719 0.4823 1.2102 5310 PIGEON 4/0 6/1 0.2309 0.3765 0.4917 0.4647 0.3340 0.7723 0.8539 0.5007 1.2899 6620 PENGUIN 266.8 6/1 0.2911 0.4223 0.5629 0.5439 0.3543 0.8491 0.9520 0.5210 1.3853 8350 WAXWING 266.8 18/1 0.2894 0.4568 0.5907 0.5565 0.3697 0.8681 0.9789 0.5363 1.4162 6880 PARTRIDGE 336.4 26/7 0.3673 0.4815 0.6556 0.6446 0.3807 0.9486 1.0774 0.5473 1.5084 11300 MERLIN 336.4 18/1 0.3653 0.5130 0.6798 0.6557 0.3947 0.9653 1.1015 0.5613 1.5363 8680 LINNET 336.4 26/7 0.4630 0.5408 0.7619 0.7649 0.4070 1.0664 1.2222 0.5737 1.6501 14100 ORIOLE 397.5 30/7 0.5271 0.5558 0.8160 0.8352 0.4137 1.1320 1.2987 0.5803 1.7225 17300 CHICKADEE 397.5 18/1 0.4316 0.5573 0.7548 0.7403 0.4143 1.0484 1.2045 0.5810 1.6373 9940 IBIS 397.5 26/7 0.5469 0.5873 0.8525 0.8680 0.4277 1.1677 1.3446 0.5943 1.7701 16300 LARK 397.5 30/7 0.6228 0.6045 0.9179 0.9511 0.4353 1.2460 1.4348 0.6020 1.8560 20300 PELICAN 477. 18/1 0.5180 0.6105 0.8506 0.8488 0.4380 1.1551 1.3350 0.6047 1.7656 11800 FLICKER 477. 24/7 0.6145 0.6345 0.9333 0.9552 0.4487 1.2554 1.4514 0.6153 1.8765 17200 HAWK 477. 26/7 0.6570 0.6435 0.9696 1.0015 0.4527 1.2990 1.5014 0.6193 1.9241 19500 HEN 477. 30/7 0.7470 0.6623 1.0483 1.0992 0.4610 1.3920 1.6069 0.6277 2.0251 23800 OSPREY 556.5 18/1 0.6040 0.6593 0.9441 0.9550 0.4597 1.2599 1.4614 0.6263 1.8900 13700 PARAKEET 556.5 24/7 0.7170 0.6855 1.0420 1.0789 0.4713 1.3773 1.5962 0.6380 2.0190 19800 DOVE 556.5 26/7 0.7660 0.6953 1.0845 1.1319 0.4757 1.4278 1.6533 0.6423 2.0737 22600 EAGLE 556.5 30/7 0.8720 0.7148 1.1775 1.2460 0.4843 1.5368 1.7754 0.6510 2.1910 27800 KINGBIRD 636. 18/1 0.6910 0.7050 1.0372 1.0610 0.4800 1.3645 1.5864 0.6467 2.0131 15700 ROOK 636. 24/7 0.8190 0.7478 1.1590 1.2067 0.4990 1.5058 1.7498 0.6657 2.1721 22000 GOSBEAK 636. 26/7 0.8750 0.7425 1.1976 1.2605 0.4967 1.5548 1.8014 0.6633 2.2197 25200 EGRET 636. 30/19 0.9880 0.7643 1.2991 1.3825 0.5063 1.6723 1.9325 0.6730 2.3463 31500 CUCKOO 795. 24/7 1.0240 0.8190 1.3612 1.4412 0.5307 1.7358 2.0139 0.6973 2.4312 27900 DRAKE 795. 26/7 1.0940 0.8310 1.4238 1.5162 0.5360 1.8081 2.0938 0.7027 2.5086 31500 MALLARD 795. 30/19 1.2350 0.8550 1.5521 1.6671 0.5467 1.9545 2.2547 0.7133 2.6649 38400 TERN 795. 45/7 0.8960 0.7973 1.2493 1.3042 0.5210 1.6044 1.8678 0.6877 2.2904 22100 CONDOR 795. 54/7 1.0240 0.8198 1.3617 1.4415 0.5310 1.7362 2.0145 0.6977 2.4319 28200 RAIL 954. 45/7 1.0750 0.8738 1.4353 1.5149 0.5550 1.8134 2.1103 0.7217 2.5302 25900 CARDINAL 954. 54/7 1.2290 0.8970 1.5715 1.6785 0.5653 1.9712 2.2835 0.7320 2.6980 33800 BUNTING 1192.5 45/7 1.3440 0.9765 1.7113 1.8265 0.6007 2.1227 2.4644 0.7673 2.8811 3200 GRACKLE 1192.5 54/19 1.5330 1.0035 1.8822 2.0267 0.6127 2.3173 2.6758 0.7793 3.0870 41900 BITTERN 1272. 45/7 1.4340 1.0088 1.8033 1.9299 0.6150 2.2255 2.5812 0.7817 2.9969 34100 PHEASANT 1272. 54/19 1.6350 1.0365 1.9859 2.1424 0.6273 2.4323 2.8052 0.7940 3.2154 43600 LAPWING 1590. 45/7 1.7920 1.1265 2.1667 2.3367 0.6673 2.6301 3.0368 0.8340 3.4492 42200 FALCON 1590. 54/19 2.0440 1.1588 2.3996 2.6020 0.6817 2.8898 3.3155 0.8483 3.7223 54500 CHUKAR 1780. 84/19 2.0740 1.2015 2.4469 2.6498 0.7007 2.9408 3.3810 0.8673 3.7904 51000 BLUEBIRD 2156. 84/19 2.5110 1.3215 2.8875 3.1365 0.7540 3.4259 3.9175 0.9207 4.3242 60300 

ACSR CONDUCTORS

NESC DISTRICT LOADINGS
Bulletin 1724E-200 

Page B-4 

13 psf 16 psf 21 psf 26 psf 31 p

WT./FT TRANS RESULTANT TRANS RESULTANT TRANS RESULTANT TRANS RESULTANT TRANS R

NAME SIZE STRAND LBS. LB/FT LB/FT LB/FT LB/FT LB/FT LB/FT LB/FT LB/FT LB/FT 

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 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 PIGEON 4/0 6/1 0.2309 0.5438 0.5908 0.6693 0.7080 0.8785 0.9083 1.0877 1.1119 1.2968 PENGUIN 266.8 6/1 0.2911 0.6099 0.6758 0.7507 0.8051 0.9853 1.0274 1.2198 1.2541 1.4544 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 PARTRIDGE 336.4 26/7 0.3673 0.6955 0.7865 0.8560 0.9315 1.1235 1.1820 1.3910 1.4387 1.6585 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 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 ORIOLE 397.5 30/7 0.5271 0.8028 0.9603 0.9880 1.1198 1.2968 1.3998 1.6055 1.6898 1.9143 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 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 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 PELICAN 477. 18/1 0.5180 0.8818 1.0227 1.0853 1.2026 1.4245 1.5158 1.7637 1.8382 2.1028 FLICKER 477. 24/7 0.6145 0.9165 1.1034 1.1280 1.2845 1.4805 1.6030 1.8330 1.9333 2.1855 HAWK 477. 26/7 0.6570 0.9295 1.1383 1.1440 1.3192 1.5015 1.6389 1.8590 1.9717 2.2165 HEN 477. 30/7 0.7470 0.9566 1.2137 1.1773 1.3943 1.5453 1.7163 1.9132 2.0538 2.2811 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 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 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 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 KINGBIRD 636. 18/1 0.6910 1.0183 1.2306 1.2533 1.4312 1.6450 1.7842 2.0367 2.1507 2.4283 ROOK 636. 24/7 0.8190 1.0801 1.3555 1.3293 1.5614 1.7448 1.9274 2.1602 2.3102 2.5756 GOSBEAK 636. 26/7 0.8750 1.0725 1.3842 1.3200 1.5837 1.7325 1.9409 2.1450 2.3166 2.5575 EGRET 636. 30/19 0.9880 1.1039 1.4815 1.3587 1.6799 1.7833 2.0387 2.2078 2.4188 2.6324 CUCKOO 795. 24/7 1.0240 1.1830 1.5646 1.4560 1.7800 1.9110 2.1681 2.3660 2.5781 2.8210 DRAKE 795. 26/7 1.0940 1.2003 1.6241 1.4773 1.8383 1.9390 2.2263 2.4007 2.6382 2.8623 MALLARD 795. 30/19 1.2350 1.2350 1.7466 1.5200 1.9585 1.9950 2.3463 2.4700 2.7615 2.9450 TERN 795. 45/7 0.8960 1.1516 1.4591 1.4173 1.6768 1.8603 2.0648 2.3032 2.4713 2.7461 CONDOR 795. 54/7 1.0240 1.1841 1.5654 1.4573 1.7811 1.9128 2.1696 2.3682 2.5801 2.8236 RAIL 954. 45/7 1.0750 1.2621 1.6579 1.5533 1.8890 2.0388 2.3048 2.5242 2.7435 3.0096 CARDINAL 954. 54/7 1.2290 1.2957 1.7858 1.5947 2.0133 2.0930 2.4272 2.5913 2.8680 3.0897 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 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 BITTERN 1272. 45/7 1.4340 1.4571 2.0444 1.7933 2.2962 2.3538 2.7562 2.9142 3.2479 3.4746 PHEASANT 1272. 54/19 1.6350 1.4972 2.2169 1.8427 2.4635 2.4185 2.9193 2.9943 3.4116 3.5702 LAPWING 1590. 45/7 1.7920 1.6272 2.4205 2.0027 2.6874 2.6285 3.1812 3.2543 3.7151 3.8802 FALCON 1590. 54/19 2.0440 1.6738 2.6419 2.0600 2.9020 2.7038 3.3894 3.3475 3.9222 3.9913 CHUKAR 1780. 84/19 2.0740 1.7355 2.7043 2.1360 2.9772 2.8035 3.4873 3.4710 4.0434 4.1385 BLUEBIRD 2156. 84/19 2.5110 1.9088 3.1542 2.3493 3.4387 3.0835 3.9766 3.8177 4.5694 4.5518 

ACSR CONDUCTORS

HIGH WIND LOADINGS
0.75 INCH ICE 1PSF 1 INCH ICE 1PSF 1.25 INCH ICE 1PSF

DIAM. WT./FT WT./FT TRANS WT./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 4/0 6/1 0.502 0.2309 1.3986 0.1668 2.0987 0.2085 2.9543 0.2502PENGUIN 266.8 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 0.2591

PARTRIDG 336.4 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 0.2653

LINNET 336.4 26/7 0.721 0.4630 1.8349 0.1851 2.6031 0.2268 3.5268 0.2684ORIOLE 397.5 30/7 0.741 0.5271 1.9177 0.1868 2.6921 0.2284 3.6220 0.2701CHICKADE 397.5 18/1 0.743 0.4316 1.8241 0.1869 2.5991 0.2286 3.5296 0.2703

IBIS 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 0.2788HAWK 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 0.2816PARAKEE 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 0.2856

EAGLE 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 0.2867

ROOK 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 0.3198

BITTERN 1272. 45/7 1.345 1.4340 3.3879 0.2371 4.3501 0.2788 5.4678 0.3204PHEASAN 1272. 54/19 1.382 1.6350 3.6234 0.2402 4.5971 0.2818 5.7263 0.3235

LAPWING 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 loadings are bathe indicated ice condition. loadings other than 1psf camultiplying the transverse lotable by the amount of the For example, the transvers6 psf wind on a 477 kcmil 2covered by 1 inch of radial .2382(6) = 1.4292 lb/ft.
Bulletin 1724E-200 

Page B-6 

LIGHT M EDIUM HEAVY

.00" ICE, 9 LB., K=.05 .25" ICE, 4 LB W IND, K=.20 .5" ICE, 4 LB W IND, K=

VERT. TRANS RESULTANT VERT. TRANS RESULTANT VERT. TRANS RE

NAME SIZE STRAND LB/FT LB/FT LB/FT LB/FT LB/FT LB/FT LB/FT LB/FT 

AZUSA 123.3 7 0.1157 0.2985 0.3701 0.3172 0.2993 0.6361 0.6741 0.4660 ANAHEIM 155.4 7 0.1459 0.3353 0.4156 0.3626 0.3157 0.6807 0.7347 0.4823 AMHERST 195.7 7 0.1837 0.3765 0.4689 0.4175 0.3340 0.7347 0.8067 0.5007 

ALLIANCE 246.9 7 0.2318 0.4223 0.5317 0.4846 0.3543 0.8003 0.8927 0.5210 BUTTE 312.8 19 0.2936 0.4815 0.6140 0.5709 0.3807 0.8862 1.0037 0.5473 CANTON 394.5 19 0.3703 0.5408 0.7054 0.6722 0.4070 0.9858 1.1295 0.5737 CAIRO 465.4 19 0.4369 0.5873 0.7819 0.7580 0.4277 1.0704 1.2346 0.5943 DARIEN 559.5 19 0.5252 0.6435 0.8806 0.8697 0.4527 1.1804 1.3696 0.6193 ELOIN 652.4 19 0.6124 0.6953 0.9765 0.9783 0.4757 1.2878 1.4997 0.6423 FLINT 740.8 37 0.6954 0.7433 1.0678 1.0812 0.4970 1.3900 1.6225 0.6637 GREELEY 927.2 37 0.8704 0.8310 1.2534 1.2926 0.5360 1.5993 1.8702 0.7027 

13 psf 16 psf 21 psf 26 psf 31 ps

W T./FT TRANS RESULTANT TRANS RESULTANT TRANS RESULTANT TRANS RESULTANT TRANS RE

NAME SIZE STRAND LBS. LB/FT LB/FT LB/FT LB/FT LB/FT LB/FT LB/FT LB/FT LB/FT 

AZUSA 123.3 7 0.1157 0.4312 0.4464 0.5307 0.5431 0.6965 0.7060 0.8623 0.8701 1.0282 ANAHEIM 155.4 7 0.1459 0.4843 0.5058 0.5960 0.6136 0.7823 0.7957 0.9685 0.9794 1.1548 AMHERST 195.7 7 0.1837 0.5438 0.5740 0.6693 0.6941 0.8785 0.8975 1.0877 1.1031 1.2968 

ALLIANCE 246.9 7 0.2318 0.6099 0.6525 0.7507 0.7856 0.9853 1.0122 1.2198 1.2417 1.4544 BUTTE 312.8 19 0.2936 0.6955 0.7549 0.8560 0.9050 1.1235 1.1612 1.3910 1.4216 1.6585 CANTON 394.5 19 0.3703 0.7811 0.8644 0.9613 1.0302 1.2618 1.3150 1.5622 1.6055 1.8626 CAIRO 465.4 19 0.4369 0.8483 0.9542 1.0440 1.1317 1.3703 1.4382 1.6965 1.7519 2.0228 DARIEN 559.5 19 0.5252 0.9295 1.0676 1.1440 1.2588 1.5015 1.5907 1.8590 1.9318 2.2165 ELOIN 652.4 19 0.6124 1.0043 1.1762 1.2360 1.3794 1.6223 1.7340 2.0085 2.0998 2.3948 FLINT 740.8 37 0.6954 1.0736 1.2791 1.3213 1.4932 1.7343 1.8685 2.1472 2.2570 2.5601 GREELEY 927.2 37 0.8704 1.2003 1.4827 1.4773 1.7147 1.9390 2.1254 2.4007 2.5536 2.8623 

0.75 " ICE 1.0 " ICE 1.25 " ICE

W T./FT TRANS W T./FT TRANS W T./FT TRANS

NAME SIZE STRAND LBS. for 1psf LBS. for 1psf LBS. for 1psf Transverse Loadings other than 1 psf on the ind

LB/FT LB/FT LB/FT

AZUSA 123.3 7 1.1864 0.1582 1.8542 0.1998 2.6774 0.2415 condition can be obtained by multiplying the traANAHEIM 155.4 7 1.2623 0.1623 1.9453 0.2039 2.7838 0.2456 value in the table by the amount of the expecte

AMHERST 195.7 7 1.3514 0.1668 2.0515 0.2085 2.9071 0.2502 per foot.

ALLIANCE 246.9 7 1.4564 0.1719 2.1755 0.2136 3.0500 0.2553BUTTE 312.8 19 1.5919 0.1785 2.3355 0.2202 3.2346 0.2618 For example, the transverse load caused by a 6 

CANTON 394.5 19 1.7422 0.1851 2.5104 0.2268 3.4341 0.2684 wind on a 559.5 kcm il conductor covered by 1 iCAIRO 465.4 19 1.8667 0.1903 2.6541 0.2319 3.5971 0.2736DARIEN 559.5 19 2.0249 0.1965 2.8357 0.2382 3.8020 0.2798 .2382(6) = 1.4292 lb/ft.ELOIN 652.4 19 2.1765 0.2023 3.0087 0.2439 3.9964 0.2856FLINT 740.8 37 2.3192 0.2076 3.1713 0.2493 4.1789 0.2909GREELEY 927.2 37 2.6033 0.2173 3.4918 0.2590 4.5358 0.3007

6201 ALUMINUM ALLOY CONDUCTORS

HIGH W IND LOADINGS

6201 ALUM INUM ALLOY CONDUCTORS

NESC DISTRICT LOADINGS

6201 ALUM INUM ALLOY CONDUCTORS - MISCELLANEOUS LOADINGS
LIGHT MEDIUM HEAVY

.00" ICE, 9 LB., K=.05 .25" ICE, 4 LB WIND, K=.20 .5" ICE, 4 LB WIND, K=.30 U

VERT. TRANS RESULTANT VERT. TRANS RESULTANT VERT. TRANS RESULTANT S

NAME SIZE STRAND LB/FT LB/FT LB/FT LB/FT LB/FT LB/FT LB/FT LB/FT LB/FT 

POPPY 1/0 7 0.0991 0.2760 0.3433 0.2912 0.2893 0.6105 0.6388 0.4560 1.0849 ASTRE 2/0 7 0.1249 0.3105 0.3847 0.3313 0.3047 0.6501 0.6932 0.4713 1.1383 PHLOX 3/0 7 0.1575 0.3480 0.4320 0.3795 0.3213 0.6972 0.7569 0.4880 1.2006 OXLIP 4/0 7 0.1986 0.3915 0.4890 0.4386 0.3407 0.7554 0.8341 0.5073 1.2762 VALERIAN 250. 19 0.2347 0.4305 0.5403 0.4909 0.3580 0.8076 0.9025 0.5247 1.3439 DAISY 266.8 7 0.2505 0.4395 0.5559 0.5104 0.3620 0.8257 0.9257 0.5287 1.3661 LAUREL 266.8 19 0.2505 0.4448 0.5604 0.5126 0.3643 0.8289 0.9301 0.5310 1.3710 TULIP 336.4 19 0.3128 0.4995 0.6394 0.5976 0.3887 0.9128 1.0378 0.5553 1.4770 CANNA 397.5 19 0.3731 0.5430 0.7088 0.6759 0.4080 0.9895 1.1342 0.5747 1.5714 GOLDENTUFT 450. 19 0.4224 0.5775 0.7655 0.7395 0.4233 1.0521 1.2121 0.5900 1.6480 COSMOS 477. 19 0.4478 0.5948 0.7945 0.7721 0.4310 1.0842 1.2518 0.5977 1.6871 SYRINGA 477. 37 0.4478 0.5963 0.7957 0.7727 0.4317 1.0851 1.2530 0.5983 1.6885 DAHLIA 556.5 19 0.5220 0.6420 0.8774 0.8658 0.4520 1.1767 1.3651 0.6187 1.7988 MISTLETOE 556.5 37 0.5220 0.6435 0.8786 0.8665 0.4527 1.1776 1.3664 0.6193 1.8002 ORCHID 636. 37 0.5970 0.6885 0.9613 0.9601 0.4727 1.2702 1.4787 0.6393 1.9110 ARBUTUS 795. 37 0.7460 0.7695 1.1217 1.1427 0.5087 1.4508 1.6948 0.6753 2.1244 LILAC 795. 61 0.7460 0.7710 1.1228 1.1433 0.5093 1.4516 1.6961 0.6760 2.1258 ANEMONE 874.5 37 0.8210 0.8078 1.2017 1.2335 0.5257 1.5409 1.8015 0.6923 2.2300 CROCUS 874.5 61 0.8210 0.8085 1.2023 1.2339 0.5260 1.5413 1.8022 0.6927 2.2307 MAGNOLIA 954. 37 0.8960 0.8430 1.2802 1.3232 0.5413 1.6296 1.9058 0.7080 2.3330 GOLDENROD 954. 61 0.8960 0.8445 1.2813 1.3238 0.5420 1.6304 1.9070 0.7087 2.3344 HAWTHORN 1192.5 61 1.1190 0.9435 1.5137 1.5878 0.5860 1.8925 2.2121 0.7527 2.6366 NARCESSUS 1272. 61 1.1920 0.9750 1.5900 1.6739 0.6000 1.9782 2.3112 0.7667 2.7350 COREOPSIS 1590 61 1.4900 1.0898 1.8960 2.0194 0.6510 2.3218 2.7043 0.8177 3.1252 

13 psf 16 psf 21 psf 26 psf 31 psf 6 p

WT./FT TRANS RESULTANT TRANS RESULTANT TRANS RESULTANT TRANS RESULTANT TRANS RESULTANT TRANS 

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 

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 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 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 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 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 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 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 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 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 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 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 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 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 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 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 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 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 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 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 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 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 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 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 

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 " 

WT./FT TRANS WT./FT TRANS WT./FT 

NAME SIZE STRAND DIAM. WT./FT LBS. for 1psf LBS. for 1psf LBS. 

IN. LBS. LB/FT LB/FT 

POPPY 1/0 7 0.368 0.0991 1.1418 0.1557 1.8003 0.1973 2.6142 ASTRE 2/0 7 0.414 0.1249 1.2105 0.1595 1.8833 0.2012 2.7115 PHLOX 3/0 7 0.464 0.1575 1.2898 0.1637 1.9781 0.2053 2.8218 OXLIP 4/0 7 0.522 0.1986 1.3849 0.1685 2.0913 0.2102 2.9531 VALERIAN 250. 19 0.574 0.2347 1.4695 0.1728 2.1920 0.2145 3.0700 DAISY 266.8 7 0.586 0.2505 1.4965 0.1738 2.2228 0.2155 3.1044 LAUREL 266.8 19 0.593 0.2505 1.5031 0.1744 2.2315 0.2161 3.1153 TULIP 336.4 19 0.666 0.3128 1.6335 0.1805 2.3846 0.2222 3.2911 CANNA 397.5 19 0.724 0.3731 1.7478 0.1853 2.5170 0.2270 3.4416 GOLDENTUFT 450. 19 0.770 0.4224 1.8400 0.1892 2.6235 0.2308 3.5624 COSMOS 477. 19 0.793 0.4478 1.8869 0.1911 2.6775 0.2328 3.6235 SYRINGA 477. 37 0.795 0.4478 1.8888 0.1913 2.6800 0.2329 3.6266 DAHLIA 556.5 19 0.856 0.5220 2.0199 0.1963 2.8300 0.2380 3.7956 MISTLETOE 556.5 37 0.858 0.5220 2.0217 0.1965 2.8325 0.2382 3.7988 ORCHID 636. 37 0.918 0.5970 2.1527 0.2015 2.9821 0.2432 3.9670 ARBUTUS 795. 37 1.026 0.7460 2.4024 0.2105 3.2654 0.2522 4.2839 LILAC 795. 61 1.028 0.7460 2.4043 0.2107 3.2679 0.2523 4.2870 ANEMONE 874.5 37 1.077 0.8210 2.5250 0.2148 3.4039 0.2564 4.4382 CROCUS 874.5 61 1.078 0.8210 2.5259 0.2148 3.4051 0.2565 4.4397 MAGNOLIA 954. 37 1.124 0.8960 2.6438 0.2187 3.5373 0.2603 4.5862 GOLDENROD 954. 61 1.126 0.8960 2.6457 0.2188 3.5398 0.2605 4.5893 HAWTHORN 1192.5 61 1.258 1.1190 2.9918 0.2298 3.9269 0.2715 5.0175 

1350 ALUMINUM ALLOY CONDUCTORS

MISCELLANEOUS LOADINGS
LIGHT MEDIUM HEAVY

.00" ICE, 9 LB., K=.05 .25" ICE, 4 LB WIND, K=.20 .5" ICE, 4 LB WIND, K=.30 ULTIMA

VERT. TRANS RESULTANT VERT. TRANS RESULTANT VERT. TRANS RESULTANT STRENG

SIZE STRAND LB/FT LB/FT LB/FT LB/FT LB/FT LB/FT LB/FT LB/FT LB/FT LBS

3/8 7 0.2730 0.2700 0.4340 0.4626 0.2867 0.7443 0.8077 0.4533 1.2262 108

7/16 7 0.3990 0.3263 0.5654 0.6120 0.3117 0.8868 0.9804 0.4783 1.3908 145

3/8 7 0.2730 0.2700 0.4340 0.4626 0.2867 0.7443 0.8077 0.4533 1.2262 154

7/16 7 0.3990 0.3263 0.5654 0.6120 0.3117 0.8868 0.9804 0.4783 1.3908 208

7 NO. 9 0.2076 0.2573 0.3806 0.3920 0.2810 0.6823 0.7318 0.4477 1.1578 1267 NO. 8 0.2618 0.2888 0.4398 0.4592 0.2950 0.7458 0.8121 0.4617 1.2341 1597 NO. 7 0.3300 0.3248 0.5130 0.5423 0.3110 0.8252 0.9101 0.4777 1.3278 190

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 SWIN

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 ANGL

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 3

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 2

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 3

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 2

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 37 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 37 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 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 Transverse Loadings other than 1 psf on the indicated ice 

LB/FT LB/FT LB/FT

3/8 7 1.3083 0.1550 1.9642 0.1967 2.7756 0.2383 condition can be obtained by multiplying the transverse loading 

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 

3/8 7 1.3083 0.1550 1.9642 0.1967 2.7756 0.2383 per foot.

7/16 7 1.5042 0.1613 2.1835 0.2029 3.0182 0.2446

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 on7 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:7 NO. 7 1.4333 0.1611 2.1120 0.2028 2.9461 0.2444

.1967(6) = 1.1802 lb/ft.

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 C29.12-1997 C-3 

• Approximate Weights and Length of Insulator Strings Using 

Standard 5-3/4 in. x 10 in. Suspension Bells C-4 
Bulletin 1724E-200 

Page C-2 

TABLE C-1 

FLASHOVER DATA FOR PORCELAIN STRING 

5-3/4”X 10” STANDARD SUSPENSION INSULATORS 

60Hz 

Flashover-kV 

Impulse Flashover, kV 

1.5 X 50 Units in 

string 

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 C29.12-1997) 

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 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 397.5 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 
TABLE D-2: MVA LIMITS

MVA LIMIT FOR 212 DEGREE F OPERATION AT THE INDICATED VOL

(S = Summer; W = Winter) 

CONDUCTOR 34.5 kV 46 kV 69 kV 115 kV 138 kV 161 kV 

NAME SIZE & STRAND S W S W S W S W S W S 

RAVEN 1/0 6/1 15 20 20 26 31 39 51 66 61 79 72 QUAIL 2/0 6/1 18 23 23 30 35 45 59 75 70 91 82 1PIGEON 3/0 6/1 20 26 27 35 40 52 67 87 81 104 94 1PENGUIN 4/0 6/1 23 30 31 40 46 59 77 99 92 119 108 1WAXWING 266.8 18/1 29 37 38 49 57 74 95 123 114 147 133 1PARTRIDGE 266.8 26/7 29 37 39 50 58 75 96 124 116 149 135 1MERLIN 336.4 18/1 33 43 44 57 66 85 110 142 132 171 155 1LINNET 336.4 26/7 34 43 45 58 67 87 112 144 134 173 156 2ORIOLE 397.5 30/7 34 44 45 58 68 87 113 145 135 174 158 2CHICKADEE 397.5 18/1 37 48 37 48 74 95 123 158 147 190 172 2IBIS 397.5 26/7 37 48 37 48 75 96 124 160 149 193 174 2LARK 397.5 30/7 38 48 38 48 75 97 125 162 150 194 175 2PELICAN 477. 18/1 41 53 41 53 83 107 138 178 165 214 193 2FLICKER 477. 24/7 42 54 42 54 83 108 139 180 167 216 195 2HAWK 477. 26/7 42 54 42 54 84 108 140 180 168 216 196 2HEN 477. 30/7 42 55 42 55 84 109 141 182 169 218 197 2OSPREY 556.5 18/1 46 59 46 59 91 118 152 196 182 236 213 2PARAKEET 556.5 24/7 46 60 46 60 92 119 154 198 184 238 215 2DOVE 556.5 26/7 46 60 46 60 93 120 154 199 185 239 216 2EAGLE 556.5 30/7 47 60 47 60 93 120 155 201 186 241 217 2KINGBIRD 636. 18/1 49 63 49 63 97 126 162 210 195 252 227 2ROOK 636. 24/7 50 65 50 65 100 130 167 216 201 259 234 3GOSBEAK 636. 26/7 50 65 50 65 101 130 168 217 201 260 235 3EGRET 636. 30/19 51 66 51 66 101 131 169 219 203 262 237 3CUCKOO 795. 24/7 58 75 58 75 116 150 193 249 231 299 270 3DRAKE 795. 26/7 58 75 58 75 116 150 194 250 232 301 271 3MALLARD 795. 30/19 59 76 59 76 117 151 195 252 234 303 273 3TERN 795. 45/7 57 74 57 74 115 148 191 247 229 296 267 3CONDOR 795. 54/7 58 75 58 75 116 150 193 249 231 299 270 3RAIL 954. 45/7 64 83 64 83 129 166 214 277 257 333 300 3CARDINAL 954. 54/7 65 84 65 84 130 168 216 280 260 336 303 3BUNTING 1192.5 45/7 74 96 74 96 148 192 247 319 296 383 345 4GRACKLE 1192.5 54/19 76 98 76 98 151 196 252 326 302 391 352 4BITTERN 1272. 45/7 77 100 77 100 154 200 257 333 308 399 359 4PHEASANT 1272. 54/19 79 102 79 102 157 204 262 340 315 408 367 4LAPWING 1590. 45/7 88 115 88 115 177 229 295 382 354 459 413 5FALCON 1590. 54/19 90 117 90 117 181 235 302 391 362 469 422 5CHUKAR 1780. 84/19 96 125 96 125 192 249 320 415 384 498 448 5BLUEBIRD 2156 84/19 108 140 108 140 215 280 359 466 431 559 503 6
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) 

 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 

PROBABLILITY OF EXCEEDING DESIGN WIND SPEEDS 

DURING REFERENCE PERIOD 

Annual Reference (Exposure) Period, n (years) 

Probablility 

Pa 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 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 
Bulletin 1724E-200 

Page F-3 

TABLE F-2 

MOMENT CAPACITIES (FT-K) AT GROUNDLINE 

For Western Red Cedar (6000 psi), Lodgepole Pine (6600 psi), 

Douglas Fir and Southern Yellow Pine (8000 psi) and Western Larch (8400 psi) 

6000 psi 

Western Red Cedar 

6600 psi 

Lodgepole Pine 

Ht. ClassH1 Class 1 Class 2 Class 3 Class 1 Class 2 Class 3 Ht. 

50 222.2 186.1 154.2 126.2 186.9 153.9 125.1 50 

55 245.4 206.9 172.7 137.9 202.5 167.8 137.2 55 

60 270.4 229.3 192.7 150.4 225.5 182.5 150.2 60 

65 297.1 246.7 202.4 163.7 243.4 198.2 159.0 65 

70 317.7 265.1 218.6 177.9 262.4 214.8 173.4 70 

75 339.4 284.4 235.7 192.9 282.4 232.4 188.8 75 

80 362.2 304.8 253.8 203.1 303.4 251.0 205.1 80 

85 386.1 326.2 266.0 219.6 317.5 263.6 216.1 85 

90 411.1 348.6 285.6 230.7 340.4 283.8 227.5 90 

95 441.6 367.3 301.9 368.0 300.5 95 

100 473.4 395.5 326.6 387.8 317.7 100 

 

8000 psi 

Douglas Fir & Southern Yellow Pine 

8400 psi 

Western Larch 

Ht. ClassH1 Class 1 Class 2 Class 3 ClassH1 Class 1 Class 2 Class 3 Ht. 

50 220.3 187.2 152.1 121.7 222.4 183.9 148.7 123.0 50 

55 246.4 204.2 167.1 134.7 243.6 201.1 163.8 136.4 55 

60 266.8 222.3 183.0 148.7 264.3 219.4 179.9 145.4 60 

65 288.4 241.5 200.0 163.5 294.4 238.9 203.5 160.4 65 

70 311.2 261.9 218.1 179.4 318.0 259.5 215.3 176.4 70 

75 335.3 283.4 230.3 190.2 333.8 281.3 227.7 187.3 75 

80 360.6 306.2 250.2 201.5 359.6 296.1 247.8 198.7 80 

85 387.2 321.5 263.7 213.3 386.7 320.0 261.5 210.6 85 

90 405.2 337.5 285.5 225.5 405.0 336.2 275.8 229.9 90 

95 438.0 357.3 303.2 438.3 365.6 301.5 95 

100 461.5 387.3 321.5 462.1 386.7 319.9 100 
Bulletin 1724E-200 

Page F-4 

TABLE F-3 

POLE CLASSES 

Wood poles are separated into 15 classes based on the minimum circumference of the pole 6 feet 

from the butt. The minimum circumferences have been calculated in order for each species (in a 

given class) to develop stresses approximately equal to those shown in the table. These stresses 

are developed at the groundline, when a horizontal load is applied 2 feet from the top of the pole. 

The horizontal loads used in these calculations are as follows: 

Class Horizontal Load (lbs.) 

H6 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 
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 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. 

OLF W ( )s

M OLF 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

= −
Crossarm Loading Chart - Maximum Permitted Vertical Loads 

of Various Sizes of Douglas Fir Crossarms

 (A fiber stress of 7400 x 0.5 or 3700 psi is assumed)

0

1,0002,0003,0004,0005,0006,0007,0008,000

2 3 4 5 6 7 8 9 

Moment Arm in Feet

Load in Pounds 3-5/8 x 9-3/8

 4-1/8 x 5-

 5-5/8 x7-3/8

 4-5/8 x 5-5/8

 3-5/8 x 5-5/8

FIGURE G-1 
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 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 l

= 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 l

(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

 

Gradien

t 

Gradien

t 

Gradien

t 

Gradien

t 

Gradien

t 

 Radius 

Radiu

s (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

 

Gradien

t 

Gradien

t 

Gradien

t 

Gradien

t 

Gradien

t 

 Radius 

Radiu

s (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 J-1 

APPENDIX J 

INSULATOR SWING TABLES 
Bulletin 1724E-200 

Page J-2 

TABLE J-1 

INSULATOR SWING VALUES FOR STANDARD TANGENT STRUCTURES 

(Porcelain Insulators with Ball Hook and Suspension Clamp 

per Drawing TM-1A. Insulator String Lengths per TABLE C-3) 

Sturcture 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, TSD1X, 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-1 (Continued) 

INSULATOR SWING VALUES FOR STANDARD TANGENT STRUCTURES 

(Porcelain Insulators with Ball Hook and Suspension Clamp 

per Drawing TM-1A. Insulator String Lengths per TABLE C-3) 

Sturcture 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 then 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 

spans limited by pole strength at locations on the pole. 

ft 

HSR = Horizontal span limited by bearing ft 
Bulletin 1724E-200 

Page K-2 

 APPENDIX K 

SYMBOLS AND ABBREVIATIONS 

HSx = Horizontal span as limited by crossbrace strength 

Of an H-frame structure 

ft 

I = Moment of inertia of a structural member in4

L 

= 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 

P-δ = P-delta moment, additional moment due to deflection ft-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 

S = Section modulus of a structural member equal I/c in3
Bulletin 1724E-200

Page K-3 

 APPENDIX K 

SYMBOLS AND ABBREVIATIONS 

S = Sag of conductor ft 

Se = Soil constant 

Sf = Final Sag of a bare conductor at condition specified ft 

Si = Sag of an iced conductor ft 

Sl = Sag of the lower bare conductor ft 

Sil = Sag of an iced lower conductor ft 

SRS = Sag at midspan for a span equal to the ruling span ft 

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

h T T +

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 

V = Vertical separation between phase conductors at a structure ft 

 
Bulletin 1724E-200 

Page K-4 

 APPENDIX K 

SYMBOLS AND ABBREVIATIONS 

a = Length as indicated ft 

a = Insulator swing clearance for normal condition in 

b = Distance between two poles for an H-frame ft 

b = Bolt hole diameter; width of a section in 

b = Insulator swing clearance for 6 psf wind condition in 

c = Insulator swing clearance for high wind condition in 

c = Distance from the neutral axis to the extreme fiber in 

dc = Diameter of conductor in 

dg = Diameter of overhead ground wire in 

dg = Diameter at the groundline of a pole in 

dn = Diameter of a pole. Depending on the location the diameter 

may be indicated as da, db, dc, dd, , etc. 

in 

dt = Diameter at the top of a pole in 

f = Frequency of conductor vibration Hz 

fb = Computed bending stress psi 

a = Length as indicated ft 

a = Insulator swing clearance for normal condition in 

b = Distance between two poles for an H-frame ft 

b = Bolt hole diameter; width of a section in 

b = Insulator swing clearance for 6 psf wind condition in 

c = Insulator swing clearance for high wind condition in 

c = Distance from the neutral axis to the extreme fiber. in 

dc = Diameter of conductor in 

dg = Diameter of overhead ground wire in 

dg = Diameter at the groundline of a pole. in 
Bulletin 1724E-200

Page K-5 

 APPENDIX K 

SYMBOLS AND ABBREVIATIONS 

dn = Diameter of a pole. Depending on the location the diameter 

may be indicated as da, db, dc, dd, , etc. 

in 

dt = Diameter at the top of a pole in 

f = Frequency of conductor vibration Hz 

fb = Computed bending stress psi 

fs = Computed skin friction of soil psf 

g = Acceleration due to gravity 9.81 (32.2) ft/sec2

g = Conductor surface gradient 

hn = Length, may be indicated as h1, h2, h3, or ha, hb hc, etc. ft. 

kVL-G = Line to ground voltage kV 

kVL-L = Line to line voltage kV 

l = Unbraced length used in buckling calculations ft. 

li = Insulator string length in. ft. 

mc = Mass per unit length of the conductor lbm/ft. 

mg = Mass for unit length of the overhead ground wire lbs./ft. 

pc = Horizontal force per unit length due to wind on the 

conductors (plus ice, if any) 

lbs/ft. 

pg = Horizontal force per unit length due to wind on the overhead 

ground wire (plus ice, if any) 

lbs/ft 

pt = Total horizontal force per unit length due to wind on the 

conductors and overhead ground wire 

lbs/ft 

qa = Calculated allowable soil bearing capacity psf 

qu = Calculated ultimate soil bearing capacity. psf 

r = Radius of gyration. a property of a cross section equal to I / A . 

lbs/ft 

r = Radius of conductor in. 

rc = Resultant load per unit length on conductor including ice 

and wind and K factor 

lbs/ft 
Bulletin 1724E-200 

Page K-6 

 APPENDIX K 

SYMBOLS AND ABBREVIATIONS 

s = Maximum moment arm for a crossarm ft. 

wc = Weight per unit length of the conductors (plus ice, if any) lbs/ft. 

wg = Weight per unit length of the overhead ground wire (plus 

ice, if any) 

lbs/ft. 

xn, yn, 

zn

= Length. May be indicated as x0, x1, z0, x1, etc. ft. 
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

Page M-1 

INDEX 

Subject Page Numbers 

A 

 

AAC Aluminum conductor (1350 H-19) 4-2, 9-2 

AAAC (6201 conductor) 4-2, 9-2, 9-6, 9-8, 9-15 

AACSR conductor 9-4 

ACAR conductor 9-2, 9-3 

ACCC conductor 9-4, 9-5 

ACCR conductor 9-4 

ACSR conductor 4-2, 9-1, 9-2, 9-6, 9-8 

ACSR/AW conductor 9-2 

ACSR/SD conductor 9-3 

ACSR/TW 9-4 

ACSS 9-4, 9-5 

AWAC conductor 9-3 

Aeolian vibration 9-3, 9-4, 9-8, 9-13, 9-14, 9-15, 15-6 

to 15-7 

Ampacity, conductor 9-6, D-2 

Anchors 

logs 

plate 

power screw 

11-17, 11-18, 14-2, 14-9 

14-9 

14-9 

14-9 

Armor rods 15-1, 15-3, 15-4, 15-6, 15-7 

Authorizations 3-5 

AWAC conductor 9-3 

Axial loading, for guyed structures 14-2, 14-4 to 14-8 

 

B

Backfill 12-8 

Backswing 7-5 

Bearing capacity 12-6, 12-7 

Bisector guys 14-1, 14-4, 14-7 

Bolt hole, moment reduction due to 13-4, F-20, F-21 

Buckling 10-13, 14-4 to 14-7, 15-12 

Buckling, calculation of buckling loads 14-5 to 14-7, 14-12 

Building, clearance over 4-4, 4-6 to 4-8 

Building, horizontal clearance to 5-1, 5-2, 5-3, 5-9 

Bundled conductors 15-8 

 

C

Calculation of a ruling span 9-11, 9-12, 9-21 

Checklist, review of plan and profile 10-15 

Clamp top clamps 15-2 
Bulletin 1724E-200

Page M-2 

INDEX 

Subject Page Numbers 

Clearance 

at crossings 10-10, 4-9 to 4-13 

between transmission and underbuild 

distribution conductors 

16-1, 16-2, 16-3, 16-4 

examples of, calculations 4-9, 4-10, 4-11, 5-9, 6-5, 6-6, 7-5 

for lines along roads in rural districts 4-3 

for lines over buildings 4-4, 4-8 

for lines over railroads 4-4, 4-5, 4-6, 4-7 

for lines over swimming pools 4-5, 4-8, 5-3 

for sag template 4-4 

horizontal 5-1 to 5-3, Chapter 5 

horizontal to vegetation 5-4, 5-5 

insulator swing Chapter 13 

minimum horizontal clearance of conductors to 

objects 

Chapter 5 

over water 4-4, 4-6, 4-7 

radial and horizontal, to vegetation 5-4, 5-5 

side hill 10-8, 10-13 

to grain bins 4-8, 5-3 to 5-7 

to guys 14-3, 7-4 

to objects under line 4-6, 4-7, 4-8, Chapter 4 

to rail cars 4-4, 4-5, 5-3 

to swimming pools 4-5, 4-6, 4-7, 4-8, 5-3 

to tall vehicles 4-3 

to vegetation 5-4, 5-5 

under differential ice loading 6-6, 6-7 

vertical, between conductors of different lines at 

noncrossing situations 

4-10 

vertical, between conductors where one line crosses 

over another 

4-9 to 4-13 

vertical, conductors to ground 4-1, 4-2, 4-6, 4-7 

vertical, conductors to ground (underbuild 

distribution), 16-1, 16-2 

vertical clearance to underbuild 16-2, 16-3, 16-4, 16-6 

Climbing space 16-4 

Communication underbuild 16-2, 16-3 

Conductor 

AAC (1350 H-19 aluminum) 4-2, 9-2 

AAAC-6201 4-2, 9-2 

AACSR 9-4 

ACAR 9-2, 9-3 

ACCC 9-4, 9-5 

ACCR 9-4 
Bulletin 1724E-200

Page M-3 

INDEX 

Subject Page Numbers 

ACSR 4-2, 9-1, 9-2, 9-6, 9-8 

ACSR/AW 9-2 

ACSR/SD (self-damping) 9-3 

ACSR/TW 9-4 

ACSS 9-4, 9-5 

ampacity tables 9-6, D-2 

AWAC 9-3 

bundled 15-8 

corrosion considerations 9-5 

design for vibration 9-3, 9-8, 9-10, 9-14 

design tensions 9-8, 9-9 

determination of conductor sags and tensions 9-13, 9-16, 9-17 

economic considerations 9-1, 9-6 

extreme ice tension 9-9, 9-10, 11-2 

extreme ice and concurrent wind tension 9-9, 9-10, 11-2 

extreme wind tension 9-9, 9-10, 11-2 

final unloaded tension 9-8, 9-10 

high temperature 9-4, 9-5 

initial unloaded tension 9-7, 9-9, 9-15

mechanical loading tables B-2 to B-9 

minimum size 9-6 

motion hardware 15-1, 15-6 to 15-8 

ruling span of 9-11 to 9-13, 9-21 

related hardware 15-1 to 15-8 

sagging of 9-19 

selection of size 9-6 

selection of type 9-5 

standard loaded tension 9-9 

stringing of 9-18 

swing angle 5-8, Chapter 7, 7-3, 7-5, 7-6, 7-9 

temperature 4-2, 4-9, 4-10, 5-1, 7-1, 7-2, 7-3, 

9-6, 9-10, 9-13, 9-15, 11-2, 16-2 

thermal consideration 9-5 

twisted pair (T-2) 9-4 

vibration 9-8, 9-10, 9-14, 9-15, 15-6, 15-7, 

15-8 

voltage drop considerations of 9-6 

Considerations in establishing radial and horizontal 

clearances to vegetation 

5-4, 5-5 

Contamination, insulation 8-7 to 8-10 

Contraflexure for H-frames 13-13, 13-14, H-3 

Corrosion of hardware 15-12 

Corrosion considerations, conductor 9-5 

Crossarm braces 13-15, 13-16, 13-17 
Bulletin 1724E-200

Page M-4 

INDEX 

Subject Page Numbers 

Crossarm data 

moment capacities G-2 

crossarm loading chart G-3 

Crossarm fittings 15-8, 15-9, 15-10, 15-17 

Crossarm, wood, designated stresses 13-3 

Crossbraces 13-15, 13-8 

Cushioned suspension unit 9-15, 15-2, 15-6 

 

D

Dampers 9-15, 15-7, 15-8 

Deadend clamps 15-3, 15-4 

Deflection, structure 4-12, 5-1, 5-5, 5-8 to 5-12 

13-4 to 13-8 

Design data summary 2-1, Appendix A 

Design data summary book, suggested outline A-10, A-11 

Design data summary form A-3, A-4 

Design data summary form, instructions for filling out A-5 to A-9 

Determining conductor sags and tensions 9-13 to 9-17 

 

E

Easements 3-3, 3-4, 3-5 to 3-8 

Electrical characteristics of insulators 8-2, 8-3 

Embedment depths 12-1, 12-2 to 12-6 

Embedment depths of wood poles 12-2 to 12-4 

Embedment depths of steel/concrete poles 12-5, 12-6 

Environmental criteria 3-1, 3-5 to 3-8 

Establishing a ruling span 9-11 to 9-13 

Excessive insulator swing 7-9, 10-10, 10-11 

Extreme ice 11-2 

Extreme ice with concurrent wind 11-2, 11-8 to 11-13 

Extreme ice, conductor tension 9-9, 9-10 

Extreme winds, 11-2 to 11-8, 11-14 

conductor tension 9-9, 9-10 

gust response factors for 11-3, 11-4 

velocity pressure exposure coefficients 11-3 

 

F

 

Fasteners 15-8, 15-9, 15-11 

Fault clearing 4-1 

Fault clearing and switching surges 4-1 
Bulletin 1724E-200

Page M-5 

INDEX 

Subject Page Numbers 

Field survey, soil 12-2 

Final unloaded conductor tension 9-8, 9-10 

Fittings 15-5, 15-10, 15-11 

Footing resistance 8-6, 8-7 

Foundation stability Chapter 12, 12-3 to 12-7 

G

 

Gain plate 15-10 

Galloping 6-7, 6-8, 6-9, 15-8 

Grid gains 15-10 

Gust response factor 

wire 11-3, 11-4 

structure 11-4 

Guy attachments 15-11 

Guy strands, strength H-4 

Guyed structures 10-14, Chapter 14, 16-5, 16-6 

Guys 

bisector 14-1, 14-4, 14-7 

clearance to 14-3, 7-4 

for steel and concrete poles 14-6 

for wood poles 14-6, 14-7 

force in 14-2 

head and back 14-1, 14-4 

hold-down (uplift) 10-11 

in-line 14-7, 10-13 

rated breaking strength of H-4 

strength factors 11-16 to 11-18, 14-2 

 

H

 

Hardware 

armor rods 9-15, 15-1, 15-3, 15-6, 15-7 

bolts 15-8, 15-9, 15-11, 15-12, H-4 

clamp top clamps 15-2 

conductor motion 9-14, 9-15, 15-6 to 15-8 

conductor-related hardware 15-1 to 15-8 

corrosion of 15-12 

crossarm fittings 15-10 

cushioned suspension units 9-15, 15-2, 15-6 

dampers 9-10, 9-15, 15-7 

deadend clamps 15-3, 15-4 

fasteners 15-8, 15-9 
Bulletin 1724E-200

Page M-6 

INDEX 

Subject Page Numbers 

fittings 15-5, 15-8, 15-9, 15-11 

gain plate 15-10 

grid gains 15-10 

guy attachment 15-11 

reinforcing plate 15-10 

spacer fitting 15-10 

splices 15-4 

stepbolts 15-12 

strain yokes 15-4 

structure-related 15-8 to 15-12 

suspension clamps 15-1, 15-2, 15-6 

swing angle brackets 15-10, 15-11 

tied supports 15-2 

Head and back guys 14-1, 14-4 

High temperature conductors 9-4, 9-5 

High wind (insulator swing) clearance 7-2, 7-3, 7-4 

Hold down guys (uplift) 10-11 

Horizontal clearance recommendations Chapter 5, 5-1 to 5-7 

Horizontal separation 6-1 

Horizontal separation recommendations 6-1, 6-2 

Horizontal span, definition 7-7 

Horizontal span, max. as limited by structure strength 

single pole structures 13-4 to 13-9 

H-frames 13-16 to 13-27 

 

I

IEEE 516 5-4 

Ice loading 11-2 

Ice loading, differential 6-6, 6-7, 11-13 

Initial unloaded conductor tension 9-8, 9-10, 9-15 

In-line guys 10-13, 14-7 

Insulation Chapter 8 

footing resistance 8-2, 8-6, 8-7 

high altitude considerations 8-3, 8-4, 8-5 

recommended agency levels 8-2, 8-3 

tables for C-2, C-3 

Insulation contamination 8-7 to 8-10 

Insulator greasing 8-10 

Insulator washing 8-10 

Insulator lengths C-4 

Insulator load limits 

porcelain and non-ceramic 8-11 to 8-14 
Bulletin 1724E-200

Page M-7 

INDEX 

Subject Page Numbers 

post, pin, suspension 8-11 to 8-14 

Insulator orientation 8-8 

Insulator swing, Chapter 7, 10-10, 10-11, 13-1, 15-8 

charts 7-6, 7-8, 7-9, 7-11 to 7-14 

effect on design 7-6 

excessive 7-9 

formulae for 7-8, 7-9 

Insulator string flashover data 8-2, 8-3, C-2, C-3 

Insulator swing clearance 7-1 to 7-5 

Insulator swing tables, structure Appendix J, 7-6 

Insulator swing values 7-5, 7-6, J-2 to J-3 

Insulator weights, suspension C-4 

Insulators, 

corrosion of 15-12 

electrical characteristics of 8-2, 8-3 

horizontal post (porcelain and non-ceramic) 8-1, 8-3, 8-11, 8-12 

horizontal post (special considerations) 8-12 

lengths, suspension C-4 

load limits of 8-11 

mechanical considerations of post and pin 8-11, 8-12, 8-13 

mechanical considerations of suspension 8-11 to 8-14 

porcelain vertical post and pin mounted on 

crossarms 

8-11, 8-12, 8-13 

post 8-1 to 8-3, 8-9, 8-12, 8-13 

suspension 8-1 to 8-3, 8-9, 8-11, 8-12, 8-13 

types 8-1 

weights, suspension C-4 

L

 

Licenses 3-5 to 3-8 

Lightning 8-5 to 8-7 

Lightning arresters 8-7 

Lightning flashover mechanism 8-5 

Line routing considerations 3-1, 3-2 

Line survey 3-3, 3-4 

Load factors Chapters 11 and 13, 14-2 

Loading, axial (for guyed structures) 14-4 to 14-9 

Loads 

extreme wind 11-2 to 11-8, 11-14 

combined ice and wind (NESC) 11-1, 11-2 

extreme ice 11-2 

extreme ice with concurrent wind (50 yr) 11-2, 11-8 to 11-13 
Bulletin 1724E-200

Page M-8 

INDEX 

Subject Page Numbers 

ice 11-2 

NESC district loads 11-1, 11-2 

longitudinal loads 11-13 

Longitudinal loads 11-13 

Longitudinal structure strength 10-13, 11-13, 11-14 

M

Meteorological data 

wind velocities and pressures E-2 

annual extreme winds 11-2 to 11-8 

annual extreme ice with concurrent wind maps 11-8 to 11-13 

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

NERC FAC 003 5-4, 5-5 

NESC loading districts 11-1, 11-2 

No wind (insulator swing) clearance 7-1, 7-3, 7-4 

O

Offset clipping 9-19, 9-20 

Overhead ground wire 8-5, 8-6, 9-7 to 9-10, 10-4, 

sags and clearances 6-3, 6-7

selection of size and type 9-8 

tension limits 9-9, 9-10 

P

Permits 3-5 to 3-8 

Percy Thomas formula 6-4 

Photogrammetry 3-3, 3-4 

Plan-profile drawings, 3-4, Chapter 10 

preparation of 10-1 to 10-4 

Pole, moment capacities F-5 to F-19 

Pole classes F-4 

Pole embedment depth 12-1 to 12-6 

Pole stability 
Bulletin 1724E-200

Page M-9 

INDEX 

Subject Page Numbers 

direct embedded, wood 12-2, 12-3, 12-4 

direct embedded, steel and concrete 12-5 to 12-6 

Pole top assembly, TP and TS 13-4 to 13-9 

Pole top assembly, wishbone 13-10 

Pole top assembly, H-frame 13-15 to 13-18 

Pole, weight F-22 

Poles, wood, designated stresses 13-3 

Post insulator 8-1 to 8-3, 8-11, 8-12, 8-13 

Preservative treatment 13-3 

R

Rail cars, clearance to 4-4, 4-5, 4-6, 4-7 

Reconnaissance and preliminary survey 3-3 

Reference component and tall Vehicles/boats 4-3 

Rerouting 3-4, 3-5 

RI and TVI I-2 to I-6 

Right-of-way 3-3, 3-5 

calculated width 5-8 to 5-13 

clearing 3-5 

typical width 5-9 

width 5-9 

width for a line directly next to a road 5-10 

width for two or more structures on a single 

right-of-way 5-11 

Roads, clearances for lines along roads in rural districts 4-3 

Route selection 3-1, 3-2, 3-3 

Route survey 3-3, 3-4, 10-1 

Ruling span 9-11, 9-13, 10-5, 10-6 

calculation of 9-10 

effects of a wrong 9-12, 9-13 

establishment of 9-11 

 

S

 

Sag, overhead ground wire 6-7 

Sag and tension relationships 9-16 

Sag template, 10-4 to 10-7 

curves 10-5 to 10-7 

Sagging of conductors 9-19, 9-20 

Section properties, (structural) H-2 

Selection of conductor size 9-6, 9-7 

Selection of conductor type 9-5 
Bulletin 1724E-200

Page M-10 

INDEX 

Subject Page Numbers 

Self-damping conductor 9-3 

Separation, horizontal 6-1, 6-2 

between transmission and underbuild 

distribution conductors 

16-1, 16-2, 16-3, 16-4 

Separation, minimum vertical 6-1 to 6-3 

Separation between lines as dictated by minimum 

clearance between conductors carried on different 

lines 5-10 

Separation between lines as dictated by minimum 

clearance of conductors from one line to the 

supporting structure of another 5-11 

Shielding angle 8-5, 8-6 

Side hill clearance 10-13 

Single pole structures, a method of structural analysis 

of 

13-4 to 13-8 

Site survey 12-1 

Soil, 12-7, 12-8 

bearing capacity 12-6, 12-7 

construction backfill 12-8 

Soils, description of types 12-2 

Spaces and ways accessible to pedestrians only 4-3, 4-6, 4-7 

Span, 

definition of 7-7, 10-10, 10-11, 10-12 

horizontal, definition 7-7 

maximum, as limited by structure strength for 

single pole structures 13-4 to 13-8 

maximum, as limited by structure strength for 

H-frame structures 13-12 to 13-27 

maximum, as limited by clearance to underbuild 16-3, 16-4 

maximum, as limited by conductor separation 6-1, 6-2, 6-4, 6-5 

maximum, as limited by conductor separation under 

differential ice loading 

6-6, 6-7 

maximum, as limited by galloping 6-7, 6-8, 6-9 

maximum possible 9-15, 9-16 

vertical 10-8, 10-10, 10-11, 10-12 

Splices 15-4 

Standard loaded conductor tension 9-9 

Stepbolts 15-12 

Strain yokes 15-4 

Strength factors 11-16 to 11-18 

Strength of pole top assembly, H-frames 13-15 to 13-18 

Stringing of conductors 9-18 

Structure, designated stresses, wood 13-3 

Structure deflection 5-1, 5-4, 5-8 to 5-12, 13-4 to 13-7 
Bulletin 1724E-200

Page M-11 

INDEX 

Subject Page Numbers 

Structure related hardware 15-8 to 15-12 

Structure spotting 10-7 to 10-14 

Structure strength, longitudinal 10-13, 11-13, 11-14 

Structure uplift (H-frame) 12-8 

Structures, Chapter 13 

general design considerations for steel/concrete 13-2 

general design considerations for wood 13-3 

guyed Chapter 14, 10-13 

H-frames, a method of analysis of 13-13 to 13-27 

single pole, a method of analysis of 13-4 to 13-12 

Suspension clamps 15-1, 15-2, 15-6 

Suspension insulators 8-1, 8-2, 8-11, 8-12, 8-13 

Swimming pools, lines over 4-5, 4-8 

Swing angle bracket 15-10, 15-11 

T

T2 Conductor 9-4 

Temperature, conductor 4-2, 4-9, 4-10, 5-1, 9-6, 16-2 

Thermal considerations, conductor 9-6 

Thunderstorm days, map E-4 

Tied Supports 15-2 

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 16-1, 16-2, 16-3 

distribution neutrals 16-4 

horizontal separation from transmission conductor 16-1, 16-2 

sag template curves 4-4, 10-4 to 10-8 

strength requirements Chapter 11, 16-1 

vertical clearance to ground 16-1, 16-2, 16-3 

Uplift 10-10 to 10-13, 12-8, 13-20, 13-21 

 

V
Bulletin 1724E-200

Page M-12 

INDEX 

Subject Page Numbers 

V-braces 13-15 to 13-18 

Vegetation, clearance to 5-4, 5-5 

Vehicles, tall, clearance to 4-3 

Velocity pressure exposure coefficient 

structure 11-4 

wire 11-3,11-4 

Vertical separation 6-1, 6-2, 6-3, 6-4, 6-5, 16-3 

minimum 6-3 

Vertical span, 10-8, 10-10 

definition 7-7, 10-10, 10-11, 10-12 

maximum vertical span limited by structure 

strength for single pole structures 13-9 to 13-12 

maximum limited vertical span limited by structure 

strength for H-frames 13-15 to 13-19 

Voltage, maximum operating 4-1 

W

Wind, annual extreme winds 11-2 to 11-8, 11-14 

Wind, annual extreme ice with concurrent wind 11-8 to 11-13 

Wind, velocities and pressures 11-3, 11-4, E-2 

Wood, preservative treatment 13-3 

Wood, designated stresses for 13-3 

Wood, stress limitations 13-3