Best Practices in Vegetation Management. For Enhancing Electric Service in Texas

Transcription

1 Best Practices in Vegetation Management For Enhancing Electric Service in Texas PUCT Project Submitted to: Submitted by: Public Utility Commission of Texas 1701 N. Congress Avenue Austin, TX Texas Engineering Experiment Station TEES project B2220 Texas A&M University System College Station, Texas Date: November 11, 2011 Principal Investigator: Contact Information: B. Don Russell, Ph.D., P.E. Dept. of Electrical and Computer Engineering Texas A&M University Co-Investigators: College Station, TX Jeff Wischkaemper Phone: Carl Benner 1

2 Project Disclaimer: The opinions and conclusions set forth in this report are solely those of the principal investigator and do not represent an official position of the Texas Engineering Experiment Station, Texas A&M University System, or the Public Utility Commission of Texas. The primary and overriding emphasis during the investigation was the relationship between vegetation practices and reliability as measured by service continuity metrics. Other vegetation issues including public safety, fire prevention, and aesthetic considerations were not directly investigated but are mentioned, as appropriate, in the text in relation to reliability. All results, conclusions, and opinions expressed herein should be used carefully within the context and assumptions set forth in the report. The conclusions stated are subject to change at any time based on further research investigation or the acquisition of new data leading to different scientific conclusions. The best practices of the scientific method have been utilized in all analyses and conclusions set forth in this report. Conclusions and findings have been stated to a reasonable degree of engineering certainty; exceptions may exist due to specific conditions. This investigation was not an exhaustive review of all vegetation management practices and related literature but does document common practices and their supporting science. This project has drawn from the work of many professionals in the electric utility and vegetation industry including arborists, electrical engineers, and researchers. Reference has been made to these individuals or their work or publications within the document and/or bibliography, as appropriate. If any work has been used, referenced, quoted or borrowed without proper attribution, we apologize; this was not our intent. 2

3 Acknowledgements and Recognition This work has drawn heavily on the work of various individuals and groups, including the following. The Electric Power Research Institute which has sponsored numerous research projects in vegetation management. Thomas A. Short, author of Distribution Reliability Power Quality, Taylor & Francis. John W. Goodfellow, whose research and experimentation and writings in vegetation management are highly respected and with whom insightful discussions were held. Researchers with the Power System Automation Laboratory of Texas A&M University, who have performed staged vegetation faults and whose research has captured and archived the best recorded examples of naturally occurring vegetation faults and their effects on the electric distribution system. Vegetation management experts and professionals in utilities in Texas who freely discussed their vegetation practices but, for purposes of confidentiality and anonymity, will remain unnamed. Others who provided valuable assistance include the following individuals. Jeff Wischkaemper who, based on research he conducted, co-authored sections of the report on the mechanisms of vegetation-caused arcing faults. Carl Benner, with whom valuable discussions were held concerning practical and cost effective VM practices. Sharon Loe, who provided clerical support and formatting. Jessica Meadors, who assisted with clerical support and procurement of referenced documents. 3

4 Executive Summary Vegetation intruding into overhead power lines has produced significant negative impacts on reliability since the earliest days of electricity distribution. An electric utility must address vegetation management comprehensively to maintain reliability of electric service to customers. Expenditures for vegetation management typically represent one of the largest recurring maintenance expenses for electric utilities. Vegetation-related outages have two fundamental underlying mechanisms: mechanical and electrical. The mechanical mechanism occurs when, for example, a proximate tree falls into a distribution line, breaking conductors or other line apparatus. The electrical mechanism occurs when vegetation comes into contact with intact, energized conductors, and the resulting unintended flow of electrical current either causes localized erosion and weakening of conductors, or a high-current flashover that trips system protection. Of the two mechanisms, mechanical tear-down causes the majority of vegetationcaused outages. Identification and remediation of hazard trees are therefore key elements of an effective vegetation-management program. The electrical mechanism causes a lesser number of vegetation-related outages. Single-phase lines on lower-voltage distribution systems (e.g., 15kV class, the predominant distribution voltage in Texas and the United States) typically have insufficient voltage to cause significant electrical activity when touching vegetation. Therefore, the electrical mechanism predominantly affects only higher-voltage distribution systems or three-phase feeder sections where phase-to-phase voltage is available. Reliability indices such as System Average Interruption Duration Index (SAIDI) and System Average Interruption Frequency Index (SAIFI) are valuable means to track reliability. To quantify the effectiveness of vegetation-management programs, however, it is necessary to separately calculate these indices based only on vegetation-caused outages and interruptions. These vegetation-specific indices can only be calculated and properly evaluated if detailed information is collected on the cause of feeder outages, including specific data concerning the vegetation-related cause(s) of an event. Given that mechanical tear-down, often from off right-of-way trees and limbs, represents the majority of vegetation-caused outages, trimming practices that attempt to keep small branches a few feet from utility conductors will have a relatively minor effect on system reliability. By contrast, trimming practices that seek to eliminate tear-down conditions or multi-phase faults on three-phase feeder sections will yield a significantly greater improvement to overall reliability. This is particularly true during ice, snow, and windstorm conditions, when falling trees and broken overhead branches result in substantial numbers of both electrical events and mechanical tear-downs. Trimming right-of-way vegetation on a fixed time cycle (e.g. every three years) will seldom achieve maximum reliability at optimal cost when applied uniformly across an entire utility. Rigid adherence to a system-wide fixed cycle for trimming of vegetation near conductors, without respect to local conditions, does not directly address the primary cause of outages, namely tear-down from right-of-way and off right-of-way trees, and blown and/or falling limbs. Furthermore, fixed trim cycles risk focusing too much attention to areas that have a good reliability history and too little attention on areas needing critical, more timely action. However, a targeted fixed-trim period, based on past feeder performance, 4

5 may be appropriate if adjustments are allowed based on annual variations and diversity in local conditions. Based on the last decade of study of vegetation management and arborist practices, and using the best science of condition-based maintenance protocols, this report recommends a reliability-centered program. In such programs, heavy emphasis is placed on inspection and condition-based decision making by vegetation professionals using continuously updated data on vegetation-caused outages. A reliability-centered program allows a utility to choose practices that can be selectively applied based on variations across the utility s service area. Factors such as annual growth rates, tree species, feeder construction type and feeder voltage can be taken into account to achieve optimal reliability for a given expenditure of funds. For example, drought simultaneously increases tree mortality and fire danger, but conversely slows vegetation growth into lines. Therefore, extended periods of low rainfall may require changes in VM practices. A reliability-centered vegetation program must engage the public, so that it understands the necessity of vegetation management. Success of a reliability-centered program requires continuity of vegetationmanagement expenditures to enable proper planning over multiple years. 5

6 Table of Contents Executive Summary Table of Contents Glossary of Terms 1.0 Project Methodology 2.0 Vegetation Management Introduction 2.1 Overview 2.2 Areas of Emphasis 3.0 The Nature and Mechanism of Vegetation-caused Outages 3.1 Typical Questions and Issues 3.2 Outage Causation 3.3 Mechanical Tear-Down 3.4 Electrical Causes of Faults 3.5 Fire and Electrical Injury Hazards 3.6 Learning Points 4.0 Case Studies Experience of Utilities Documenting Vegetation Management Effectiveness 4.1 Example One Seattle City Light 4.2 Example Two Oncor Snow Storm 4.3 Learning Points 5.0 Reliability Indices and Vegetation Management Metrics 5.1 Metrics Defined 6

7 5.2 SAIFI/SAIDI Accuracy and Sensitivity 5.3 Vegetation Specific SAIDI/SAIFI Measures of VM Success 5.4 Documentation of Vegetation-caused Outages Data Collection and Accuracy 5.5 Learning Points 6.0 Optimal Reliability Improvement by Targeting Resources 6.1 Targeting Three-phase Main Feeder Sections 6.2 Trimming Frequency Versus Trimming Criteria 6.3 Mandatory Clearance Requirements 6.4 Cost-Benefit Analysis and Resource Prioritization 6.5 Learning Points 7.0 National Standards 7.1 Occupational Safety and Health Administration (OSHA) 7.2 National Electrical Safety Code (NESC) 7.3 American National Standards Institute (ANSI) 7.4 Federal Standards 7.5 Learning Points 8.0 Vegetation Management Scheduling Practices - Overview and Discussion 8.1 Periodic Fixed Cycles and Cycle Length 8.2 Outage Response Clearing 8.3 Reliability Centered, Condition Based Scheduling 8.4 Hazard/Danger Tree Identification and Remediation 8.5 Evaluation of Common Scheduling Practices 7

8 9.0 Vegetation Outage Assessment, Data Collection, and Reporting Programs 9.1 Documenting Vegetation Outages 9.2 Calculation of Vegetation Specific SAIDI/SAIFI Indices 10.0 Other Considerations 10.1 Public Education and Interaction 10.2 Species Specific/Seasonal Specific Practices 10.3 Clearance Requirements during Scheduled Trimming 10.4 Constancy in VM Budgets 11.0 Recommendations 11.1 Applicable ANSI, NESC, and OSHA Provisions Should be Adopted 11.2 Vegetation Specific SAIFI/SAIDI Indices should be Calculated and Reported on an Annual Basis 11.3 Mandatory Minimum Clearance Requirements Should Not Be Adopted 11.4 Reactive Vegetation Clearing in Response to Outages is Appropriate, but Insufficient 11.5 System Wide Fixed Trim Cycles are not Recommended as the Sole Uniform Practice 11.6 A Reliability Centered Vegetation Program (RCVP) Should be Designed and Adopted by each Utility 11.7 Public Awareness and Engagement Programs are of Critical Importance 11.8 Proactive Programs can Reduce Future Vegetation Management Costs and Should be Encouraged 11.9 A Statewide Vegetation Management Public Relations Discussion and Consensus Are Needed Future Areas of Investigation and Opportunity 8

9 List of Figures in Main Text List of Figures in Appendix A Appendices Appendix A: How Electrical Faults Occur as a Result of Vegetation Intrusion Appendix B: Naturally Occurring Vegetation Outage Case Studies Appendix C: PUCT Workshop Agenda Appendix D: Bibliography and Suggested Reading References 9

10 Glossary of Terms Burn-down A burn-down results when an arcing fault generates enough conductor or apparatus damage to result in a conductor breaking and/or falling to the ground. This may occur because of the conductor melting in two, or through burning down of a utility pole. Fault A fault is an unintended, abnormal flow of electrical current within a circuit. In a power system, a fault occurs when a conductive path is formed between an energized conductor and another phase conductor, the system neutral, or ground. Interruption As per IEEE 1366, an interruption is the loss of service to one or more customers connected to the distribution portion of the system. It is the result of one or more component outages, depending on system configuration. Lockout The permanent opening of a substation recloser, generally occurring after two or three reclose attempts. Momentary interruption As per IEEE 1366, a momentary interruption is a single operation of an interrupting device that results in a voltage zero. For example, two circuit breaker or recloser operations (each operation being an open followed by a close) that momentarily interrupts service to one or more customers is defined as two momentary interruptions. Outage As per IEEE 1366, an outage is the state of a component when it is not available to perform its intended function due to some event directly associated with that component. For the purposes of this report, the term outage is used to describe a sustained interruption of power to customers. Recloser A recloser is a protective device which attempts to clear a transient fault by removing power from the system for a short period of time. This sequence is generally referred to as a trip and reclose, and may recur several times. Approximately 90% of distribution faults are temporary, and can be cleared by reclose operations. Note that each recloser operation results in a momentary interruption. SAIDI System Average Interruption Duration Index. This number represents the number of minutes an average customer would expect to be without power during a year. SAIFI System Average Interruption Frequency Index. This number represents the number of outages an average customer would expect during a year. Single-phase lateral A single-phase lateral is a portion of a radial distribution circuit that branches off from a three-phase section, consisting of a single-phase conductor and neutral. A fault on a singlephase lateral does not typically result in the interruption of power to the three-phase section it is attached to. 10

11 Tear-down A tear-down occurs when mechanical forces result in the destruction of a power line or other system apparatus; for example, a tree falling and breaking a power line, or a car snapping a utility pole in half as a result of a traffic accident. Any action that breaks mechanical supporting insulators, rips conductors from poles, or breaks and drops conductors can generally be referred to as mechanical tear-down. Three-phase feeder section A three-phase section of line is the portion of a distribution circuit consisting of three-phase conductors and a system neutral. A fault on a three-phase section of line will result in the interruption of power to all three-phase and single-phase sections of line downstream of the faulted section. Three-phase tripping When a single-phase fault occurs on a three-phase section of line, the practice of three-phase tripping interrupts power to all three phases, instead of interrupting power to only the faulted phase. Vegetation management (VM) Vegetation management includes all planning, budgeting, inspection, pruning, tree removal and similar activities to control vegetation intrusion into power lines and apparatus. Voltage gradient A voltage gradient is the voltage spread across a distance. For example, 7,200V applied across 3 feet would result in a voltage gradient of 2,400 volts per foot. 11

12 1.0 Project Methodology The objective of this report is to document the known common practices of vegetation management (VM) in the context of the best science on this subject and to determine how these practices should be applied by Texas utilities. The intent is to recommend a framework for best practices in vegetation management given the geography, flora, weather, and typical infrastructure conditions of utilities in Texas. The VM practices of electric utilities across the United States, including many Texas utilities, have been carefully studied with specific emphasis on application in the state of Texas to improve distribution reliability. An attempt has been made to identify and formulate existing best practices; however, common practices and variations thereof have been noted throughout the report. Economic issues were considered only in a relative fashion to compare practices and discuss budget optimization. Vegetation standards commonly used by utilities were considered; however, this project did not address the procedures of arborists for actual tree trimming, pruning, or vegetation treatment, except as these directly affect outage frequency. There was no experimentation or field work performed under this project. However, the prior experimentation of multiple researchers including researchers of the Power System Automation Laboratory of the Department of Electrical and Computer Engineering of Texas A&M University has been utilized as a basis for certain conclusions found in this report. Scientific literature, industry reports and surveys, and industry publications available as of the date of this report have been utilized to establish the common practices of vegetation management used in the electric utility industry. This project has concentrated on vegetation management practices for distribution systems at all common distribution voltages. This document does not directly address vegetation management practices for transmission right-of-way. This report is not an exhaustive study or analysis of all literature or statistical data available on vegetation management but rather cites such work only as required to support stated conclusions. A representative sample of peer reviewed and industry literature that provides the scientific basis for the conclusions of this report are cited and/or are listed in the bibliography to be used by the reader for further study. The reader will note that the phrase best practice is often used in quotes. This is intentional to emphasize the following points. Delineating best practices is inherently problematic, if not subjective. This is due to the wide variation in conditions and circumstances that exist across utilities. What is best for one is of secondary importance to another. Is a practice considered best because it reduces cost, or because it produces greater reliability? Is it best because it is in all cases safer to the public? One could define best practices as those that achieve the highest technical performance and safety at the lowest cost; but in the minds of some, cost should never be a criterion for best. One thing is clear as stated by C. S. Lewis, I am to give my readers not the best absolutely but the best I have. Defining best must necessarily be fluid, since the conditions at any time (e.g. rainfall) or place (e.g. forest versus prairie) may vary geographically or year-to-year across a given utility. This means that the best practices of this year may not best apply to next year. In a true sense there is no single set of best practices, but a shopping list of proven, science-based methods and procedures from which to design a good vegetation management program. It is on this basis that this project has proceeded. 12

13 2.0 Vegetation Management Introduction 2.1 Overview The utility industry has long recognized that vegetation is a significant cause of faults and outages in electric distribution systems. A fault occurs when a conductive path is formed between an energized conductor and another phase conductor, the system neutral, or ground. This may occur through direct contact, such as when two conductors are pushed together, or through an intermediary, for example when a tree branch spans two phase conductors for an extended period of time. Faults may result in momentary interruptions while protective devices attempt to automatically clear the faulted condition through a process known as reclosing, and may result in a sustained outage if the recloser cannot clear the fault. If the system is protected by fuses, an outage may occur when a fuse blows to clear a fault. Restoration of service requires manual replacement of the fuse. An outage also occurs when conductors are torn down by falling trees or vegetation. While statistics vary widely across utilities based on such factors as growth rates and the types of vegetation, it is generally thought that approximately 20% of distribution faults are related to or caused by vegetation. It is also generally understood that there is a strong correlation between weather events and vegetation-caused outages, and that there is a substantial increase in the duration of outages when they are caused by trees tearing down distribution infrastructure. Vegetation management or tree trimming has long been an emphasis of operating utilities and represents a major annual cost. It is commonly stated that vegetation management is the single largest maintenance expense for many utilities. [1] With the current emphasis on improving reliability, reducing the frequency and duration of outages, and improving storm recovery performance, utilities must be diligent in evaluating and improving vegetation management practices. This project has a wide range of purposes and objectives. The report seeks to identify best practices in vegetation management that can be employed by utilities in the state of Texas to improve reliability and distribution feeder performance under both normal and adverse weather conditions. The project seeks a balance between known science as to what can be achieved in vegetation management, versus practices that are reasonable, cost effective, and suitable (best) for electric utilities. This project has endeavored to understand the validity and uses of various metrics that attempt to measure reliability, including the unreliability caused by vegetation intrusion. The sensitivity and accuracy of these metrics and their value for quantifying the success of vegetation management procedures is presented. There has been no attempt to comprehensively document all vegetation management practices by all utilities in the United States. Major and pervasive practices have been included. The studies and research of selected utilities have been utilized, primarily as reported in the general literature; sources are hereafter cited. In general, it can be stated that the vegetation management practices of utilities in 13

14 the state of Texas are a representative sample of utility practices throughout North America. Furthermore, there is no significant vegetation management practice that is not practiced in some form by one or more utilities in the state of Texas, with the possible exception of maintaining continuous minimum clearance distances from lines for all vegetation. Comparisons of the practices of utilities in and outside Texas will be made throughout this document, as appropriate, to support the findings of this report. There is a broad misunderstanding on the part of the public and among some utility and vegetation management professionals as to the nature of electrical faults caused by vegetation. This is understandable since most vegetation professionals are not trained in electrical science. To avoid misunderstandings leading to incorrect conclusions, we have included a section in the report that discusses, in detail, the mechanisms of electrical fault creation through vegetation. It is hoped that this discussion will be of general use by vegetation professionals and electric power engineers. 2.2 Areas of Emphasis A review of vegetation management history, literature and practices, as well as recent research, reveals specific areas that must be emphasized when investigating VM best practices. Consider the following statements: Trimming and clearing of trees makes electricity delivery more reliable, as measured by: - Fewer outages - Shorter outages - Fewer momentary interruptions - Improved power quality Trimming and eliminating trees makes the distribution system safer. - Tear-downs of energized lines and equipment are reduced. - Burn down of conductors is reduced. Trimmed feeders reduce the time and cost of storm restoration. - Cleared rights-of-way are accessible to repair crews - Rights-of-way without vegetation debris to be removed speeds repairs. Vegetation management is expensive. - Often cited as the single highest recurring maintenance expense. The performance and effectiveness of vegetation management programs are difficult to evaluate on a short time scale. - Deferral of trimming may not immediately affect outage frequency. - Increased future costs due to poor VM practices today are difficult to document. 14

15 The above listed truisms were carefully investigated in this project since they provide the basis for understanding and evaluating vegetation control methods. These statements provide insight and context into the best practices for vegetation management. Specific emphasis is also given to how reliability can be quantified, documented, and tracked, as it is affected by vegetation management practices. The sensitivity of standard reliability indices to various VM practices is a key factor in deciding which practices should be labeled best and, therefore, should be adopted by utilities. Attention is also given to other negative consequences of vegetation intrusion on power lines. These include public safety considerations such as fires ignited by arcing from vegetation-caused downed power lines. 15

16 3.0 The Nature and Mechanism of Vegetation-caused Outages 3.1 Typical Questions and Issues Q1. How does vegetation cause outages on electric distribution feeders? Q2. What percentage of vegetation related outages are due to mechanical forces versus electrical short circuit conditions? Q3. What are the electrical characteristics and behavior of vegetation faults? Q4. What factors affect or exacerbate vegetation-caused outages? Q5. What is the contribution of hazard and danger trees as causes of distribution system outages? 3.2 Outage Causation Bare overhead conductors carry electricity at distribution voltage levels supported by insulators on poles. For most of the span above ground, air provides the insulation between energized conductors and/or neutral conductors or ground. Two mechanisms exist to compromise overhead, air insulated conductors. Any action that breaks mechanical supporting insulators, rips conductors from poles, or breaks and drops conductors can generally be referred to as mechanical tear-down. The consequences of mechanical tear-down include falling energized conductors. Another mechanism which compromises overhead conductors is the creation of short circuit conditions caused by objects bridging the air gap between conductors or causing conductors to come into contact with each other. Examples would include a branch falling over two parallel energized phase conductors built on horizontal cross arms. In this event, a short circuit condition may result if the voltage gradient is sufficient and the branch remains in place for an extended period of time. The primary mechanisms for vegetation-caused outages can be summarized in two categories: - Mechanical tear-down of electric lines and/or apparatus, causing outages - Electrical short circuits or arcs causing overcurrent faults, most often resulting in operation of system protection devices to clear the fault, thereby causing an outage. Frequently, a combination of both tear-down and short circuit mechanisms occur. In fact, either mechanism can occur first, leading to the second. For example, lines torn down by trees (mechanical tear-down) can cause conductors to arc when they hit ground, creating an electrical short circuit. Phaseto-phase tree limb faults (electrical short-circuits) can burn conductors in two, which fall to the ground and sometimes remain energized. 16

17 The overall contribution of tree or vegetation related outages as a function of all outage causes on the distribution feeder is important to note. Over all utilities, approximately 20% of faults on distribution systems are caused by tree contact. [2] A 1984 Electric Power Research Institute (EPRI) study showed a high correlation between these tree contact faults and adverse weather, a subject addressed hereafter. [3] Significant statistical work and data mining by Duke Power shows similar results as shown in Figure 1. Figure 1: Distribution Faults in the Duke Power System Source: Duke Power, L.S. Taylor, 1995 Data between 1987 and 1990 Duke Power also determined that over 70% of tree outages were caused when an entire tree fell over a line creating a tear-down situation. [4] It is also important to note that 86% of these tear-down conditions were from trees that were outside the utility right-of-way, a figure confirmed by EPRI studies. [5, 6] It also reports that dead limbs or trees cause 45% of tree outages as opposed to outages caused by live trees. The EPRI report is based on data in for the US and Canada related to tree caused outages covering 17 utilities. This data confirmed that at least 70 to 80% of tree related outages in any given year were due to a tear-down condition, often due to entire tree failure. In that same study, Niagara Mohawk stated that a high percentage of tree related outages or interruptions were 17

18 caused by uprooted trees. They report that over 80% of permanent tree related faults were caused by trees outside of the right-of-way. [7] 3.3 Mechanical Tear-Down Mechanical tear-down refers to physical destruction or damage of lines, poles, and apparatus without respect to any electrical event. Based on the data above, we conclude that mechanical tear-down represents the primary cause of vegetation-related outages on electric distribution feeders. For this investigation, a ratio of 80% tear-down to 20% other causes will be used for all vegetation-caused outages. Examples of mechanical tear-down causing outages on electric distribution systems are easily found. A frequent cause of outages is large branches breaking and falling over one or more phases of a distribution feeder, often severing the lines and creating a downed conductor. A similar situation occurs when an entire tree falls (referred to as hazard or danger trees), tearing down distribution conductors. In these mechanical tear-down scenarios, an electrical fault may or may not occur, based on local circumstances and system configuration. The physical and weather circumstances at the time of the incident frequently dictate whether an electrical fault accompanies the tear-down or only mechanical damage occurs. In some situations, electric utilities will deenergize distribution lines in advance of major weather events such as floods or hurricanes to prevent electrical damage to apparatus. In this case, because the conductors are not energized, no electrical fault will occur when the mechanical tear-down drops conductors to the ground. However, under most circumstances, a mechanical tear-down condition that results in energized downed conductors also results in electrical faults for at least the first span of conductors to touch the ground on each feeder. If multiple tear-down conditions occur, the entire feeder or a section of the feeder beyond the initial tear-down is deenergized, and subsequent teardown conditions downstream from the open substation breaker, feeder recloser or fuse will not have an associated electrical fault. Repair of a feeder section that has been torn down fundamentally requires the same effort and time whether an electrical fault has occurred or not. Factors contributing to mechanical tear-down include ice accumulation on trees and/or conductors, snow accumulation, and wind generated mechanical forces. There is a high correlation between weather and tear-down events. The best and most recent examples in Texas of mechanical tear-down due to environmental forces are the outages that occurred across many utilities during Hurricane Ike. Hurricane Ike represented the largest outage of CenterPoint customers in history resulting from a single weather event. [8-10] CenterPoint did not, in general, lose energy supply, nor were most substation based apparatus and transformer facilities damaged by the hurricane. For the CenterPoint system in the period following the initial wave of outages, there was an excess of generation available which caused significant operating problems. It was simply not possible to deliver this energy to loads due to excessive outages of 18

19 components on the distribution system, primarily due to fallen trees and limbs resulting in mechanical tear-down of feeder conductors. The length of outage for the average CenterPoint customer was often dictated by the level of vegetation-induced tear-down at multiple locations on a given electric distribution feeder. In some cases, a single distribution feeder had scores of line conductor spans on the ground and/or poles destroyed as a result of trees falling over lines. For most of these tear-down conditions, no electrical fault occurred because the first fault on the feeder resulted in the operation of the substation circuit breaker for that feeder, thereby deenergizing the entire circuit. Consequently, there was no failure of electrical systems or burn-down of lines but multiple mechanical tear-down conditions that each required physical repair. Remediation efforts were significantly hampered by the need for substantial work by vegetation crews to cut and remove vegetation before access could be gained by electrical workers to repair electric lines and poles. As shown during Hurricane Ike and similar events, the impact of on and off right-of-way hazard and danger trees and their effect on distribution system reliability cannot be overstated. Trees falling during major weather events such as a hurricane, wind storm, or ice storm cause a substantial number of the vegetation related outages in Texas. The Public Utility Commission of Texas (PUCT) separately commissioned reports on hazard and danger trees as well as storm hardening of electric distribution systems related to vegetation outages; therefore, danger/hazard trees will not be addressed in detail in this work. [11] This issue is considered, however, as one important factor affecting vegetation management practices and overall reliability. 3.4 Electrical Causes of Faults A fault condition occurs on an electric conductor when a short circuit condition causes unintended current to flow outside the conductor. For example, a tree limb falling across two horizontal phases of a three-phase distribution line represents a fault condition. Current may flow through the branch causing an arc or explosive event. Electrical faults are generally classified as single-phase or multi-phase short circuit conditions. Most of the exposure miles of typical distribution feeders in Texas are single-phase lines which carry only one energized conductor and a neutral conductor that represents system ground. For these lines, an electrical fault must be a line-to-neutral (or ground) fault, as no other phase conductors are present. Most distribution feeders in Texas are 15 kv-class distribution feeders, with voltages ranging from 11,000 to 14,500 volts measured on a phase-to-phase basis. The most typical distribution feeder in Texas will have a nominal 7,200 volts-to-ground, measured line-to-neutral (~12,500 volts measured phase-to-phase). At 7,200 volts-to-ground, and for conventional construction distances between energized conductors and neutral conductors, a vegetation-caused fault due to trees growing into lines is exceptionally uncommon. In general, a living tree branch bridging the line and neutral conductors will not draw sufficient current or act to create an arcing fault condition. Momentary operations and/or lockout of 19

20 system protection devices are uncommon for this configuration. While clipping or electrical pruning of new growth vegetation near distribution lines occurs due to the microamp to milliamp currents that flow on the vegetation, these events do not often result in an arcing fault, do not result in substantial current flow, and do not represent an interruption of service to customers since no line protection devices will operate to deenergize any part of the feeder. Experimental work has shown that 7,200 volts-to-ground from a phase conductor to vegetation represents an insufficient voltage gradient to create a fault condition through vegetation over any significant distance. [12] Experimentation by Goodfellow summarized in Figure 2 shows the probability that a fault will occur based on voltage gradient across a tree branch. For low voltage gradients (less than 2 kv per foot), an electrical fault is extremely unlikely. As the voltage gradient across a branch increases, the probability of an electrical fault occurring also increases. If a branch spans a 7,200 volt feeder with a phase spacing of six feet, the voltage gradient across the branch will be 1.2 kv. As Figure 2 shows, the probability of burning of a limb with a subsequent high current arc at this voltage gradient is very low. At voltage gradients below 2 kv per foot, the probability of a fault occurring is almost zero. This is because low voltage gradients do not cause limbs to burn or arc, which must happen before current can flow. The charring or burning of a limb takes time. Figure 3 shows that the time required to create a fault condition at a voltage gradient of less than 2 kv per foot is very high. This means that if a tree only contacts a single-phase energized conductor or bridges the energized conductor and neutral conductor, absent other compounding circumstances, a fault condition will not occur. A detailed analysis of the vegetation-related electrical mechanisms causing distribution faults is found in Appendix A. Figure 2: Fault Causation due to Voltage Gradient Source: Goodfellow,

21 Figure 3: Time Required to Create Vegetation Faults Source: Goodfellow, 2000 There is a common misunderstanding that when trees grow into power lines, surrounding the lines below and above, there is constant contact between the energized conductors and the trees at many thousands of points. I have documented a different conclusion based on the experience of utility linemen and the observations of researchers. The picture shown in Figure 4 is typical of the tunnel created around energized conductors where trees have grown around the conductors to envelop the line. The mechanism can be described in lay terms as follows. Figure 4: Typical "tunnel" effect from an energized conductor passing through vegetation Source: Picture by B. Don Russell,

22 As new vegetation growth touches an energized conductor, micro-amp currents begin to flow which heat, destroy, or clip the vulnerable growth. Moisture in new growth is heated, and growth ends are destroyed. This does not represent a burning of limbs and, in general, no fire danger exists from this specific phenomenon even during drought conditions. As a consequence, conductor contact with this new growth and small limbs is much reduced as the conductor carries out a self-trimming process. The subsequent growth of the tree will therefore be to the sides and then will grow back over the conductors leaving the characteristic tunnel shown in Figure 4. Other mechanisms at play in creating this phenomenon are the mechanical forces that occur around the conductor due to conductor movement and due to the movement of branches. These forces can be considerable during wind storms. The movement creates mechanical trimming of certain branches, resulting in the characteristic tunnel effect. As a result of the described mechanisms, the significant majority of exposure miles of distribution conductor has no contact with vegetation, even though full tree growth under and around and over the conductors on the right-of-way may exist. Once this characteristic tunnel has been created and branches have overgrown and become dense above the conductors, little sunlight reaches the tunnel area, and regrowth of the inside branches is inhibited. Again, contact with conductors inside the tunnel is mitigated, and for much of the feeder, often eliminated. Direct tree contact with single-phase 15 kv class conductors is not a statistically significant cause of faults. The experience of distribution engineers who study the number and type of faults documented on feeders confirms this finding. [13] If each instance of new growth of trees into distribution conductors actually caused an electrical arc and fault condition, most distribution feeders in operation in overgrown vegetation areas would be faulted on a virtually continual basis. This is, however, not the case. Experimentation and direct measurement of feeders with heavy vegetation growth has been performed by the Power System Automation Laboratory at Texas A&M University. This has shown that for feeders in heavy vegetation with many exposure miles of conductor, it is very rare for the feeder to experience an arcing fault and that momentary, self-healing interruptions due to tree contact with single-phase conductors are also rare. [1] Phase-to-phase vegetation contact on a distribution system represents a substantially higher voltage gradient and if a contact is sustained, frequently does result in the operation of system protection devices, leading to an outage condition. Normal spacing between phases (e.g. four feet) on a 12.5 kv phase voltage would result in greater than 3 kv per foot voltage gradient. As shown in Figures 2 and 3, the probability of a fault occurring is more significant as phase voltage increases. This becomes an important issue as the trend toward higher distribution voltages increases to support increasing load levels. If a tree limb is weighted by ice and bridges two phases of a feeder, or if it breaks and falls from a tree falling over two phases in a horizontal constructed distribution feeder, an arcing fault with significant follow-on current may occur after several minutes. An infrequent, but well documented, occurrence is a branch falling over two phases and either burning clear or, alternatively, causing a permanent fault. If 22

23 the branch is not removed from the line either through damage to the branch (e.g. burning) or other mechanical action, the resulting high current event will likely cause a lockout of a recloser or substation breaker, leading to an outage. An actual example of this mechanism is described in the case studies of Appendix B. It is commonly thought that electrical current conducts uniformly through the cross section of a tree branch, causing a rapid short circuit event and resulting in an outage. There is no scientific support for this mechanism. When a broken branch or other vegetation bridges line-to-neutral or phase-to-phase conductors, various electrical activity is initiated, including carbonization of the surface of the vegetation with a progression that may, after substantial time, lead to a low impedance path and possible arcing fault. Again, this mechanism is described in detail in Appendix A and in reference [14]. In general, a voltage gradient of greater than 2 kv per foot is needed to generate an arcing fault. Additionally, the tree branch must contain enough moisture to allow an initial high-impedance conductive path to form. [1] Another mechanism for electrical fault occurrence involves branches falling and pushing one phase conductor into another phase conductor or system neutral, thereby causing a fault. Similarly, weighting caused by ice or snow pushing vegetation down onto conductors causes faults. In these cases, the construction architecture of the distribution conductors (e.g. vertical or horizontal) dictates the nature of the fault. In some situations, an energized line over a neutral several feet below can be pulled down, resulting in metal to metal contact between the line and neutral conductors, thereby generating a fault. Similarly, a phase-to-phase fault may occur for either vertical construction or horizontal construction where tree branches push or pull phases together or bridge phases creating a conductive path. In summary, vegetation-caused electrical faults frequently occur when the natural insulation properties of air are lost after vegetation reduces the effective resistance between the energized conductors and/or ground. Another different but similar mechanism is the metal to metal contact that occurs if phase conductors and/or neutral conductors are pushed together by vegetation. It should be noted that many, if not most, electrical short circuit conditions caused by vegetation do not cause a reported outage but may result in a momentary interruption. However, utilities generally do not capture and document the frequency or magnitude of momentary interruptions from any cause, and are unable to distinguish vegetation-related momentary interruptions from those caused by other factors. [14] It is important to note that momentary interruptions, by definition, result in a loss of power to all affected customers, which may last up to several minutes. [15] A detailed explanation of the behavior of electrical faults from vegetation is included as Appendix A. 23

24 3.5 Fire and Electrical Injury Hazards Several hazards occur when power lines fail and fall to the ground due to either mechanical tear-down and/or electrical faults. As described in sections 3.3 and 3.4, when a tree falls and rips conductors from insulator supports and falls to the ground it often remains energized. A 15 kv class feeder can have downed energized conductors remain on the ground in an energized and arcing condition for many minutes until a sustained over-current fault causes operation of protective devices. Arcing from these lines can cause fires. Similarly, a limb across two phases in the air can cause intermittent arcing and burning of the limb. Falling pieces of the limb and burning embers may result. An example of this event is included in Appendix B. Both arcing downed power lines and burning limbs represent competent ignition sources for fire if ground conditions are susceptible. Sufficient fuel load must exist and moisture conditions must be suitably low for combustion to occur. However, sustained low rainfall levels often result in drought conditions that create an extreme fire hazard. These conditions have been experienced in the last two years in Texas and have created a fire hazard that continues today. In addition to concerns over fire causation, downed power lines that remain energized represent an electrical hazard to the public. In many cases, protective devices, cannot see downed power lines which may not draw sufficient current to operate breakers, reclosers, and fuses. Fires may occur and electrical hazards may persist beyond the control of the utility. However, when possible, attention must be given to mitigate and eliminate the conditions that may cause downed power lines. 3.6 Learning Points 1. Trees and other vegetation represent less than 20% of all fault causation for non-storm conditions. 2. Mechanical tear-down is the primary (e.g. 80%) cause of vegetation outages. This is exacerbated during storms and/or high winds which cause trees to fall. 3. Electrical contact between a single conductor and live branches is rarely the root cause of a vegetation-caused outage. 4. Single-phase vegetation faults for 15 kv class or lower distribution voltages are rare due to the relatively low voltage gradient from line to ground. 5. Arcing vegetation faults on 15 kv class single-phase feeders are rare absent mechanical forces causing direct phase to neutral (metal to metal) contact. 24

25 6. Higher voltage distribution feeders (e.g. 25 kv, 35 kv) have an increased probability of electrical faults due to vegetation because of the higher voltage gradient. 7. Phase-to-phase vegetation faults occur on 15 kv feeders if two conditions are met. (a) The vegetation (e.g. branch) must bridge phases in a mechanically stable way over a sufficient time period to create an arc path by charring and burning the branch (generally requires solid contact on the order of minutes). (b) The vegetation must not burn or fall free before a permanent outage occurs (e.g. arcing fault initiating protective device operation). 8. Downed energized electrical conductors represent a fire hazard and an electrical hazard to the public. 25

26 4.0 Case Studies - Experience of Utilities Documenting Vegetation Management Effectiveness Controlled experiments conducted by electric utilities to evaluate vegetation management practices are rare. This is due to a significant number of factors including the long duration over which these experiments must be conducted and the liability associated with allowing vegetation to continue in contact with lines long after the incidence of outages has markedly increased. Consequently, documented examples of how particular vegetation management practices have directly affected the performance and reliability of distribution feeders of a given utility are most important. Two examples have been found which provide us with great insight and understanding of the effects of specific vegetation practices on the reduction of the frequency and duration of outages. 4.1 Example One Seattle City Light The first example comes from the experience of Mr. Bernie Zeimianek who is the director of Energy Delivery Operations for Seattle City Light (SCL). Mr. Zeimianek was interviewed for the purposes of this report. Based on discussions with Mr. Zeimianek and based on information he has published in Transmission and Distribution World magazine, we have summarized the SCL experience. [16] For multiple reasons, Seattle City Light had a period approaching almost a decade where regular vegetation management was not practiced. During this time, very few funds were expended on vegetation management. Little work was done beyond trouble men and linemen clearing vegetation in the immediate area where an outage or event had already occurred. One can describe the process used during this period by SCL as purely reactive, clearing vegetation after a fault had occurred but with no proactive approach or periodic trimming of trees and vegetation. Mr. Zeimianek brought his considerable industry experience to SCL and, with broad support, initiated a comprehensive vegetation management program in The hallmark of this program was a four year trim cycle over the entire SCL system. Mr. Zeimianek calls this a system wide haircut. SCL operates a 26 kv system, which creates the potential for higher voltage gradients than 15 kv class systems. As a result, Mr. Zeimianek chose to fully trim utility easements to a 10 to 15 foot clearance from the line infrastructure. This effectively removed all intruding vegetation, right-of-way trees, etc. The data benchmark for unreliability cited by Mr. Zeimianek was the following. After a decade of no trimming, except during repairs of outages, SCL experienced 12,000 vegetation-related outages per year. In the context of the size of SCL, this represents a very high incidence of vegetation-related outages. Mr. Zeimianek reports that many outages during this period could be referred to as burners, where vegetation-related electrical activity or arcing vegetation caused outages and/or damage. He also noted that there was a very strong correlation between the number of calls and outages and wind levels greater than 20 MPH. The dramatic improvement of SCL after initiating a system wide haircut and a four year trim cycle cannot be overemphasized. After four years of trimming, Mr. Zeimianek reports that the number of tree 26

27 related calls or outages had dropped from 12,000 calls per year under a purely reactive vegetation management policy to 1,000 calls per year after implementing a comprehensive vegetation management program. These statistics and analysis reported by Mr. Zeimianek represent one of the most dramatic and well documented long term experiments observing the effects of vegetation on the long-term reliability of an operational distribution system. Even though Mr. Zeimianek s system operates at a relatively high voltage and is thus able to generate voltage gradients necessary for fault conditions to occur much more easily, it is clear that vegetation-caused outages can be substantially brought under control by a carefully designed and executed vegetation management program. Uncontrolled growth of vegetation, including overhanging branches along with danger and hazard trees, will lead to a substantial increase in the frequency and duration of outages. Burn down conditions due to electrical faults, and tear-down of lines due to falling trees, will increase the time and cost of physical repairs and lengthen outages. Additionally, downed energized conductors represent a public safety hazard when people contact lines. This can only be addressed by reducing the statistical probability of downed conductors. In the case of SCL, problem of burn-downs was exacerbated by the relatively high distribution voltage. As distribution voltages increase above 15 kv in Texas, the SCL experience with increased frequency of burn-downs of conductors due to vegetation-caused faults will become more relevant. As described in Appendix A, the burning of a limb or the burn-down of conductors that arc to the ground can ignite a fire in grass or undergrowth. This danger is exacerbated during drought conditions. When an effective vegetation management program was introduced by SCL, burn-downs were significantly reduced which also reduced the time to repair and manpower requirements for restoring service. The overall effect of the SCL vegetation management program was a more reliable system with fewer outages and increased public safety. Conclusions from the SCL experience include the following. 1. If you cancel a vegetation management program for up to a decade, the unreliability of your distribution system will dramatically increase. 2. The number of outages associated with vegetation dramatically increases as a percentage of all outages when vegetation management programs are arbitrarily extended or eliminated. 3. Vegetation trimming and hazard tree removal over the entire system can dramatically decrease the number of tree-related outages. 4. The level of manpower for maintenance and repair, the duration of outages, and danger to the public from conductor burn-down can all be reduced through an effective vegetation management program. 27

28 % of Feeder Lock outs 4.2 Example Two: Oncor Snow Storm In February 2010, Oncor experienced a major snow storm event that resulted in a significant level of customer outages extended over several days. The maximum number of customers out was 200,151 on Friday, February 12, The total number of customer outages was 529,048. [17] The event can be generally described as a record snowfall starting February 11, with snowfall of 12.5 inches that continued into the next day. The wet snow that fell during this event was significantly heavier than typical snow density and weighed approximately 25 pounds per cubic foot. The effect was heavy weighting of lines, apparatus, and specifically vegetation. Figure 5 shows the performance of feeders as measured by the number of lockouts, sorted by the vegetation management program history of the feeders in question. It illustrates a strong correlation between the number of lockouts leading to outage and the length of time since vegetation trimming. Oncor reports that the benefits of trimming based on its clearing practices begin to degrade in the fourth year after trimming and degrade somewhat linearly after that point. 20% 18% 16% 14% 12% 10% 8% 6% 4% 2% % Feeder Outages and Vegetation Maintenance Feb 2010 Snowstorm 4.7% 15.1% 18.3% 0% VM Four Years or Less VM Greater than four years Limited record of VM 57 of of of 476 Figure 5: Effects of Vegetation Management During 2010 Oncor Snowstorm Source: Oncor Consequently, Oncor used a four year benchmark in evaluating the outage data. Oncor reports that distribution feeders which have had vegetation pruning in the preceding four years were 67% less likely to experience an outage due to tree contact. They concluded that recent trimming dramatically 28

29 reduced the likelihood of a feeder outage. Given the nature of the mechanical tear-down and/or short circuits on affected feeders due to snow heavily weighting trees and branches into the power lines, it is reasonable to conclude that Oncor pruning practices had reduced the overhead branch canopy for trimmed feeders. Where there were no overhanging branches which could be weighted by the snow, an outage was far less probable. It is important to put the number of outages that Oncor experienced during this five day period into context. As has been previously stated, it is normal to expect that only one in five faults on distribution feeders will be related to vegetation and, for any given feeder, the number is often less. However, during this exceptional snow week, 71.4% of outages were tree related. Oncor replaced over 8,000 fuses on its system, a number that it describes as comparable to the period of restoration following Hurricane Ike. Interpretation of this Oncor event is very important to understanding the impact of certain vegetation management practices. Snow and ice loading on overhead branches creates multiple fault and outage scenarios. First, weighted branches will break and fall, causing mechanical tear-down of distribution conductors. Second, weighted branches that remain in the air can create phase-to-phase short circuit conditions on horizontal three-phase feeders, resulting in high-current faults that cause outages which may involve the entire circuit. Similarly, phase to neutral short circuit conditions can occur from weighted branches pushing the phase conductor and neutral together. Tear-down conditions can also occur on single-phase laterals. These often cause fuses to blow, resulting in partial feeder outages. These multiple fault scenarios are widespread where overhanging branches exist. Though this snow fall event is relatively rare, it mirrors the same physical conditions of ice storms which are more common in Texas. The only solution to such widespread outages is derived from Oncor s analysis of this snow event. It shows that recently trimmed feeders without overhanging branches were not as susceptible to the weighting of snow or tear-down. It should also be noted that since falling branches causing teardown conditions represent a considerable percentage of vegetation-caused faults during normal, nonstorm conditions, emphasis on elimination of overhanging branches in any vegetation management program is necessary and will have very positive results. Conclusions from Oncor s snow experience include the following: 1. During a major weather event including snow or ice, the number of vegetation-caused faults will increase to several times the normal, non-storm rate. Vegetation faults and tear-down become the predominant outage cause under these conditions. 2. Where overhanging vegetation is in near proximity to power lines, heavy snow and ice will cause a dramatic increase in outages, including electrical faults and mechanical teardown. 3. A recently trimmed distribution feeder (e.g. less than four years) will experience dramatically fewer outages than feeders which have not been trimmed over longer periods, assuming overhanging branches have been targeted for removal. 29

30 4.3 Learning Points The examples of SCL and Oncor provide us great insight into the effectiveness and requirements for vegetation management for Texas. 1) The number and duration of customer outages will dramatically increase if vegetation programs are eliminated or significantly deferred. Continued emphasis on vegetation management is needed. 2) The number of vegetation-caused faults and tear-downs under normal system operation (nonstorm) can be significantly decreased through an effective vegetation management program. 3) The number of ice and snow storm related outages caused by vegetation can be dramatically decreased by an effective trimming program. 4) The elimination or proper trimming of overhanging branches is a very significant component of an effective vegetation management program and will improve both storm and non-storm reliability. 30

31 5.0 Reliability Indices and Vegetation Management Metrics 5.1 Metrics Defined An important issue related to vegetation management is the ability to measure the effectiveness of practices. Since the primary purpose of vegetation management programs is to improve reliability as measured by reduction in the frequency and duration of momentary and sustained outages, it is appropriate that we address the major indices commonly used by utilities and the PUCT to characterize the reliability of utility distribution systems. These include the System Average Interruption Frequency Index (SAIFI) and System Average Interruption Duration Index (SAIDI) as well as several related indices. SAIFI = Total number of customer interruptions Total number of customers served SAIDI = Sum of customer interruption durations Total number of customers served The SAIFI index represents the number of interruptions on an annual basis that can be statistically expected by any given customer. Similarly, the SAIDI ratio provides a normalized expected duration of an outage for any given customer. These indices are now recognized almost universally and included in various standards of the Institute of Electrical and Electronics Engineers and the Power Energy Society. As a frame of reference, according to IEEE , the median values across 61 surveyed utilities in North America in 1998 were as follows. [15] SAIFI: 1.16 SAIDI: 88 minutes. In the best of all possible worlds, these indices would be zero; it is therefore desirable that the frequency and duration of outages be as low as possible. In practice, these indices can never be zero due to conditions and outages that are beyond the control of the utility. An informal survey of large Texas utilities taken in preparation for the workshop described in Appendix B shows a range of SAIDI and SAIFI indices as follows: Non-storm SAIFI: 0.67 to 1.2 Non-storm SAIDI: 71 minutes to 106 minutes. These numbers can be considered typical of those found for utilities in the United States, unless extenuating circumstances prevail in a given year. National norms are shown in the histograms of Figure 6 and Figure 7. 31

32 There are no standard benchmarks or figures of merit for SAIFI and SAIDI indices across all utilities. This is due to the wide variety of factors that affect these quantities including weather, physical environment, voltage level, age of infrastructure, percentage of underground feeders, etc. Other factors that affect these numbers include the way customer interruptions are defined and recorded, the way outage duration is documented, and under what circumstances outages are reported. The accuracy of data reporting or quality of data can dramatically affect these indices. Figure 6 shows an inverted cumulative distribution function (CDF) of SAIFI indices across surveyed United States utilities. Figure 7 shows an inverted CDF of SAIDI from the same utilities. These graphs should be interpreted in the following manner: as one moves from left to right along the horizontal axis, the vertical axis represents the percentage of utilities whose reported SAIDI or SAIFI value is higher than the horizontal axis value. For example, in Figure 6, 95% of utilities reported a SAIFI of greater than 0.1, whereas only 5% reported a SAIFI of greater than 2.7. The median value occurs in each figure where the value of the vertical axis is 50% and is indicated by a vertical line. As shown, over 90% of surveyed U.S. utilities maintain a storm included SAIFI of greater than 1.0. Over 50% of the utilities show a storm included SAIFI less than approximately 1.3. This data also shows that there is little change in the SAIFI indices when storm data is excluded. In other words, SAIFI indices are insensitive to annual variation in storm activity. A practical conclusion is that the typical feeder in the United States will experience 1.3 outages on an annual basis without respect to the level of storm activity. It is important to note that this represents only outage data, and, for data with storms included, does not document the substantial increase in momentary interruptions that occur during storm conditions due to such factors as lightning. Figure 6: SAIFI Values for US Utilities Including and Excluding Storms Source: Edison Electric Institute 32

33 Figure 7 shows the distribution of SAIDI indices for surveyed utilities in the United States. Fifty percent of utilities report a system SAIDI average per feeder of less than two hours per year when storms are excluded. This increases to three hours per year when storm data is included in the calculation. A comparison of the informal survey data previously mentioned shows that large Texas utilities currently report SAIFI and SAIDI indices that would favorably compare with performance of the top quartile (25%) of utilities in the United States, based on these Edison Electric Institute (EEI) reported data. Figure 7: Distribution of SAIDI Values for US Utilities including and excluding storms Source: Edison Electric Institute 5.2 SAIFI/SAIDI Accuracy and Sensitivity Further investigation shows the effect of root cause on SAIFI and SAIDI reliability parameters. Data from the Canadian Electrical Association presented in Figure 8 shows that tree contact is not a major contributor to the frequency of interruptions. However, Figure 9 indicates that tree contact represents a substantial contribution to the duration of outages which, with a high degree of certainty, we can attribute to the high incidence of tear-down of distribution infrastructure due to trees falling and the significant length of time required for repairs and service restoration. This is consistent with the outage mechanisms described in Section 3.0. Incidental tree contact does not cause electrical faults or outages, and the number of tear-downs due to trees falling is small compared to certain other outage causes. Hence, the frequency of outages as measured by a system wide SAIFI is not dramatically changed even when the number of tree events increases or decreases. The average duration of outages is much more sensitive to an increased number of tear-down events with corresponding effect on SAIDI indices. 33

34 Figure 8: SAIFI by outage cause Source: Canadian Electrical Association, 2001 Figure 9: SAIDI by outage cause Source: Canadian Electrical Association,

35 Calculation of SAIFI and SAIDI indices is statutorily required in Texas. These indices are appropriately used by the U.S. power industry and will continue to be used as a quantitative mechanism for reporting the overall reliability of distribution systems. They should be reported and used as they are now by all Texas utilities. However, it is very important to understand the relative sensitivity of these metrics to fault causation and to assess their effectiveness as a measure of good vegetation management practices. A reasonable question to ask is, Are SAIFI/SAIDI indices highly correlated to vegetation management practices? If we refer to the SCL and Oncor case studies presented in Section 4.0, we conclude that the SAIDI index will be strongly correlated to vegetation management trimming practices if measured over many years. Given Oncor s experience, the number of outages during storms attributed to tear-down of distribution feeders is dramatically less for feeders that have been trimmed in the previous four years. A full teardown of multiple spans of an electric distribution feeder substantially increases the duration of a given outage as compared to a temporary arc condition created by vegetation contact at a single location. A vegetation management practice that includes heavy emphasis on eliminating overhanging branches will have a dramatic effect on reducing tear-down conditions during ice and snow loading and will therefore reduce the duration of outages during storm conditions. Recall from the Oncor data, that 73% of the outages during the storm period of five days were related to tree and tear-down conditions. By comparison, Oncor separately reports that, for the current year, only 15.19% of non-storm outages were caused by vegetation. Hence, SAIDI averages correlate positively to the long term neglect of vegetation management. Also, major storm events can increase an annual SAIDI calculation unless a storm exception is taken. But since non-storm outages are infrequently caused by vegetation, system wide SAIDI is not sensitive to short term changes in vegetation management practices. System wide SAIFI is not a good indication of reliability with respect to vegetation management activity. As seen in Figure 8, the total incidence of interruptions associated with vegetation or tree contact is relatively small as compared to the total number of interruptions from all causes. Dr. Roy Billinton, internationally recognized expert in power system reliability, has studied the causes of unreliability for the Canadian Electrical Association (CEA). In a study of customer service continuity contributions to SAIFI done in 2003, Dr. Billinton reports that tree contact represents only 0.27 of an overall SAIFI of 2.67 (2.37 excluding significant events). [18] Based on this data, if all tree contact were eliminated, the total reduction in SAIFI would be approximately 10%. If one studies the variation in SAIFI calculated from feeder to feeder over a whole system over multiple years, the annual variation in feeder events and the variation in annual weather conditions make it impossible to statistically identify and separate vegetation management contributions without independent knowledge and information as to the number of vegetation-caused faults. An overall annual SAIFI index is not sensitive to wide variations in vegetation management activity over one or two years. Only after vegetation-caused outages become a major or predominant factor in the total number of outages would statistical sensitivity occur. This would only occur after years of VM inactivity, if it occurred at all. 35

36 Stated differently, we find that if all vegetation is clear cut for tens of feet away from a distribution feeder and all danger or hazard trees are eliminated for their respective fall distances for a given feeder, the SAIFI index for that feeder may still increase next year due to the occurrence of other outage conditions unrelated to vegetation. Therefore, it must be concluded that the movement of SAIFI, up or down, for a given year or for a small number of years is not a definitive or reliable indicator of the effectiveness or ineffectiveness of vegetation management practices. Some utilities and/or regulators target vegetation management resources (and other inspections) on worst performing feeders. The objective is to improve the reliability of these feeders through additional maintenance and manpower. This technique has significant merit if the root cause(s) of outages on worst performing feeders are correctable by increased maintenance or repair (i.e. problems that an inspection might reveal and which, if remediated by maintenance or repair, would have prevented the outage). However, as can be seen from the analysis above, high SAIDI and SAIFI indices for a given feeder may or may not be an indicator of vegetation intrusion or other correctable causes of outages. A feeder with no vegetation intrusion and a perfect inspection report may be worst performing based on a few long outages due to equipment failure, animal caused faults, a traffic accident which breaks the first pole outside the substation fence, repetitive incipient failures that are self-healing and difficult to find, etc. Targeting vegetation management funds and manpower to the worst performing feeders may therefore have no impact on SAIDI and SAIFI indices for the next year and may not remove the subject feeders from the worst performing list. It is necessary to carefully investigate the root cause of outages on worst performing feeders in order to make an informed decision as to whether additional vegetation management expenditures, or indeed other generic maintenance expenditures, will affect feeder performance. Recall, if only 15% of non-storm outages on all feeders are caused by vegetation intrusion, we must assume that many worst performing feeders in any given year did not achieve this distinction because of vegetation problems. The SAIDI/SAIFI indices should be calculated and reported as they now are on a standard basis by all utilities. These metrics are most helpful in many reliability studies and accurately measure what they are designed to measure namely the overall statistical reliability experienced by customers irrespective of cause. However, the indices do not precisely and sensitively measure vegetation management practices over the short term and should not be used or interpreted as if they do. The correlation of system wide SAIDI/SAIFI over time after feeders are trimmed can be summarized as follows. a) For 10+ year time scales with storm events included or excluded there is a strong correlation of VM practices with these indices. b) For 4 5 year time scales with storm events excluded, there is a weak correlation of indices to VM practices. c) For 1 3 year time scale with storm events excluded, correlation is unreliable. 36

37 These are explained as follows. If VM is neglected for a decade, the number of vegetation-caused outages will dramatically increase. Conversely, if a well-executed trimming program is practiced, there will be few vegetation outages in the first few years immediately following a trim date to affect SAIDI/SAIFI indices. As the five year mark is approached after trimming, vegetation outages will increase but not necessarily predominate over all other outage causes. Of course, it is critical to note that this analysis is based on SAIDI and SAIFI indices for data accumulated over the entire distribution system for all outage causes. These conclusions will not necessarily be true for any given feeder. This uncertainty is part of the reason why SAIDI/SAIFI calculations including all outage causes cannot be relied upon to target VM activity. 5.3 Vegetation Specific SAIDI/SAIFI Measures of VM Success The question should be asked, Can we use vegetation specific SAIDI/SAIFI metrics to measure the incremental value, effectiveness, and quality of vegetation management practices? If a utility s distribution management system captures and documents interruptions and outages caused by vegetation, then a vegetation specific SAIDI/SAIFI can be calculated for a given feeder (or the entire system) using this data. It will then be possible, with high confidence, to use such indices to measure the relative performance of vegetation management practices over a several year timescale. A hypothetical example may prove instructive. Assumptions: - a given feeder has significant vegetation intrusion and has experienced a significant number of vegetation-caused interruptions and outages of known duration. - the cause of each individual outage is documented and vegetation specific SAIDI and SAIFI are calculated. - we trim the subject feeder in a given year; the trimming practices create a vegetation free zone surrounding conductors, eliminate hazard/danger trees, and eliminate overhanging branches. Expectations: We can expect that calculated vegetation specific SAIDI and SAIFI indices for this hypothetical feeder will drop dramatically (near zero) after trimming and remain low for all non-storm conditions. The indices may also remain low during storm conditions, such as snow or ice weighting, as was documented by Oncor. However, as the time since trimming increases, the frequency of interruptions due to vegetation will increase. 37

38 Vegetation specific SAIDI and SAIFI indices will also increase as time since trimming increases. Conclusion: Vegetation specific indices can be utilized over an arbitrarily long horizon (as compared to the trim period) to assist in vegetation management scheduling. Similarly, if we calculate system wide, vegetation specific SAIDI/SAIFI indices, (assuming feeders are trimmed over the whole system in a systematic fashion) these indices can be used as one measure of the overall effectiveness of vegetation management practices. 5.4 Documentation of Vegetation-caused Outages Data Collection and Accuracy In order to calculate vegetation specific SAIDI/SAIFI indices, it is necessary for a utility to establish and carefully manage a reporting protocol that captures all causes of significant outages and separately documents in detail how vegetation outages have occurred. For example, if an off right-of-way tree falls and tears down distribution lines causing an extended outage, there are implications of this event on VM practices for off right-of-way tree inspection. If a significant number of outages in a given geographic area of heavy vegetation intrusion are caused by arcing faults, there are different implications. Vegetation specific SAIDI/SAIFI and statistical tracking of the various modes of vegetation-caused outages can be used by a utility to target resources to correct specific or systemic problems. Certain utilities such as Xcel Energy require detailed investigation of each significant outage that has received a vegetation-caused coding. [19] These field investigations document the size and species of tree, on or off right-of-way location, and the cause of tree failure. Xcel also documents how and when the area has last been trimmed and correlates this data to how the specific outage was created. Furthermore, the investigation captures a wide range of electrical and mechanical data on the incident site, including the type of utility construction, which can later be correlated to possible failure mechanisms. More detail concerning the practice of certain individual utilities, including utilities in the state of Texas, is given hereafter. However, we conclude that the calculation of vegetation specific SAIDI and SAIFI indices requires capture of outage causes at a level of detail not practiced by most utilities. Another factor that must be taken into consideration is the accuracy of reporting. It is generally believed that a 25% inaccuracy exists in the reporting of outages by field crews. Reliability engineers anecdotally relate that utility crews who cannot discover the cause of an outage routinely mark vegetation or lightning as a cause, in spite of the fact there may be no evidence suggesting the involvement of either as a causative factor. The pressure to attribute a cause to a particular outage, even when cause is unknown or in dispute, can result in substantial bias in the outage data. This must be taken into account by each utility. 38

39 5.5 Learning Points 1. The frequency of outages (SAIFI) over an entire system is not significantly affected by typical storms. 2. The duration of outages (SAIDI) is significantly increased when storm data is included. 3. SAIDI and SAIFI indices, calculated without respect to outage cause, are not a valid statistical measure for short term evaluation of the performance of vegetation management practices on distribution feeders. 4. Elimination of all close vegetation growth contacting or very near distribution conductors while leaving hazard or danger trees and overhanging limbs will have an indeterminate but probably small effect on the system wide, non-storm SAIDI and SAIFI indices of a given utility. 5. Total elimination of all tear-down events on distribution feeders will have a measureable and positive effect on SAIDI and SAIFI indices. 6. A vegetation specific SAIDI/SAIFI measurement can be used as one measure of the effectiveness of vegetation management practices if carefully tracked and analyzed over a multi-year period with adequate attention given to accurate data collection of the cause of outages. 39

40 6.0 Optimal Reliability Improvement by Targeting Resources It is not the purpose of this study to evaluate the appropriate expenditure level or to quantify the cost effectiveness of vegetation management expenditures by utilities. However, the sensitivity of various vegetation management activities and practices to the relative priority of expenditures is an important topic. In other words, Where on the system do we spend money in order to achieve the greatest improvement in reliability? How do we optimize expenditures given limited funds? How do we get the most bang for the buck from our vegetation management expenditures? The following conclusions can be technically supported by statistical data and the previous analysis. 6.1 Targeting Three-phase Main Feeder Sections We must consider the large number of exposure miles of single-phase laterals on the typical utility system in Texas versus the three-phase main portions of the feeder. Given the typical utility practice of three-phase tripping for single-phase faults, as explained in the following paragraph, the number of customer-minute interruptions is dramatically increased on a per fault basis for vegetation faults occurring on a three-phase portion of the feeder and for those causing operation of a three-phase protection device (e.g. substation breaker). Three-phase tripping dramatically affects outage statistics and, from a quantitative perspective, places extra value on eliminating potential fault conditions from vegetation along three-phase sections of the feeder. [13] If we use as our measure of vegetation-specific reliability the minimization of the duration of customer outages as measured in customer-minutes of interruption caused by vegetation, the first logical step to improve vegetation-specific reliability is to target three-phase portions of feeders to eliminate vegetation-caused faults. If all vegetation faults were eliminated on three-phase sections of all feeders, the overall number of customer-minutes of interruptions caused by vegetation-related events would be significantly reduced. This fact derives from the architecture of the system. If a fault occurs on one of the three conductors of a three-phase section of the feeder, system protection devices (e.g. three-phase reclosers or substation breakers) operate to deenergize, or trip, a major portion of the feeder or the entire feeder from service, dropping electric service to hundreds of customers simultaneously. If the vegetation outage is caused by a three-phase tear-down condition, the duration of the outage can be significant due to the complexity of the repair, and the number of customer-minutes of interruption climbs. A three-phase outage can result in thousands of customers interrupted. Researchers have documented multiple cases of a single vegetation outage on a three-phase section of line resulting in over half a million customer-minutes of interruptions. [1] Conversely, the loss of customer service on a 40

41 single-phase lateral with the same type of vegetation fault results in a comparatively small level of interruption. Figure 10: Histogram of customers affected by individual outages Source: PSERC Final Report, Project T27G This point is illustrated by the data shown in Figure 10 which shows a histogram of vegetation-related outage data measured at a 32-feeder substation over a period of six years. During this six year period, there were a total of 171 vegetation-related outages on the 32 distribution feeders served by this substation. Almost 95% of these outages affected less than 250 customers. Only nine outages affected more than 250 customers, and all nine of these outages occurred on three-phase sections of the feeder. A similar analysis holds true when plotting a histogram of customer-minutes of interruptions, shown in Figure 11. Eight events resulted in over 100,000 customer minutes of interruption, and six of the eight occurred on three-phase sections of the line. The two single-phase events in this group of eight took over 14 hours to repair, underscoring the significant amount of time it can take to restore service if conductors or other apparatus are torn down and damaged. 41

42 Figure 11: Histogram of customer-minutes of interruptions by outage Source: PSERC Final Report, Project T27G The top nine events in Figure 10 represent 67.5% of the total number of customers affected due to vegetation-related outages during the six year period. In other words, eliminating nine specific threephase vegetation-related events out of 171 total vegetation-related outages, would result in a 67.5% improvement in vegetation-specific SAIFI over the six year period. Elimination of the same nine outages would result in a 65% improvement in vegetation-specific SAIDI over the same period. Elimination of the top eight outages as measured by customer-minutes of interruptions, shown in Figure 11, would result in a 53% reduction in vegetation-specific SAIFI, and a 73% reduction in vegetation-specific SAIDI. Eliminating the union of the two sets, eleven events in total, would result in a 67.7% reduction in vegetation-specific SAIFI and a 75.5% reduction in vegetation-specific SAIDI. The conclusion is obvious. A relatively small number of vegetation related faults, specifically faults occurring on three-phase sections of distribution feeders, contribute disproportionately to both vegetation-specific SAIDI and SAIFI indices. In the case of data cited in the PSERC report, eliminating all vegetation-related faults occurring on the three-phase portions of the feeders would result in a 73.5% reduction in vegetation-related SAIFI and a 72.6% reduction in vegetation-related SAIDI. When considering all outages from all causes at the substation over the six year period, eliminating only 42

43 vegetation-related outages occurring on three-phase portions of feeders would result in a 5.7% reduction in overall SAIFI, and a 10% reduction in overall SAIDI across all 32 feeders, even though these outages represent only 1.2% of the total outages recorded over this period. Consequently, based solely on the use of customer-minutes of interruptions as a metric of reliability, resources should be targeted on the three-phase portions of the system to eliminate intruding vegetation and all hazard and danger trees. While the tear-down of an energized conductor on a singlephase lateral is no less dangerous than the tear-down of a single conductor of a three-phase feeder section, the consequence on reliability metrics is dramatically different. Finding: Prioritizing VM resources on three-phase feeder sections will reduce vegetation-specific SAIDI and disproportionately improve overall reliability as compared to trimming single-phase laterals. This finding is independent of any decision about VM practices on single phase laterals which must be separately considered. 6.2 Trimming Frequency Versus Trimming Criteria If vegetation is properly trimmed to a reasonable distance in a first trimming activity with emphasis on overhanging branches, danger tree removal, etc., substantial resources are wasted if the feeder is retrimmed too soon. Recall, it has been shown from utility data and scientific experimentation that the growth of vegetation into lines is not a major cause of outages on distribution feeders. Tear-down conditions from overhanging branches and/or falling trees represent the major cause of vegetation outages for storm and non-storm conditions, significantly affecting both frequency and duration of outages. Assuming no program to remove hazard trees, the mere trimming of vegetation in proximity to conductors, even if done on an annual basis, would represent a substantial cost and would not materially improve the reliability indices for a feeder. As previously noted, for utilities which have substantial vegetation (e.g. rapid growth environment), it is possible to trim vegetation effectively and expect that vegetation outages resulting from intrusion or overhanging branches will remain relatively constant and low for a number of years until overhanging re-growth or tree mortality takes effect. This, of course, assumes no extraordinary storm conditions. Since as many as three out of four incidents of vegetation-caused outages are caused by trees falling or leaning or heavy branches falling on lines, the effectiveness of the hazard/danger tree program for the utility will have a far greater effect on the duration of outages and probably the frequency of outages than will short cycle periodic trimming of re-growth of intruding vegetation into the lines from the sides or below the conductor level. Therefore, a widely spaced vegetation trimming program that heavily emphasizes elimination of overhead branches and hazard/danger trees will result in greater reliability than even an annual trimming of re-growth vegetation near lines. Finding: Short interval (frequent) trimming does not represent an optimal use of resources and will not necessarily yield the highest reliability for a given level of VM budget. 43

44 6.3 Mandatory Clearance Requirements Proposals to mandate permanent minimum vegetation clearance distances to distribution conductors have been discussed in recent years. Some of this discussion may be driven by concerns over fire causation. However, the cost associated with maintaining minimum distances is high and the benefits to the public, if any, must be carefully documented. Recall, that mechanical tear-down causes most vegetation-related outages, particularly long outages. Vegetation intrusion into typical 15 kv class feeders rarely causes even a momentary interruption, much less an outage. Therefore, expending funds to maintain a minimum distance of one foot or two feet from conductors will likely have little effect on the reliability of the system and will not likely be measurable in terms of reliability indices, as compared to clearing trees and branches that can fall on lines. Mandating minimum clearance distances greatly overestimates and overemphasizes the value of not having vegetation contact lines. Eliminating overhead branches has much greater impact on reliability compared to keeping all under-growth and side-growth vegetation at a mandatory distance. If the primary objective is to improve and maintain high reliability, it is not an effective use of resources to maintain a minimum encroachment or intrusion distance for all vegetation. Other VM practices have greater benefits for much less expenditure. The cost for minimum clearance criteria will likely be much higher than current vegetation management budgets, and the effect on overall reliability will be minimal. Finding: Mandating minimum vegetation clearances from conductors will not significantly improve reliability but will require significant resource expenditure. 6.4 Cost-Benefit Analysis and Resource Prioritization Prioritizing the expenditure of vegetation management budgets can only be achieved if one knows the parameter(s) to be optimized. If the objective is to maximize reliability for each dollar expended as measured by accepted indices, spending funds to eliminate all vegetation issues on three-phase main lines is advisable. By contrast, if the objective is to minimize the number of vegetation-caused downed conductors (a relatively rare event), then the prioritization of vegetation management budgets would change and all single-phase and three-phase feeder sections would require a similar level of vegetation management attention focused on eliminating tear-down conditions. (These two examples are provided only to contrast the issue and are not presented as a recommendation of alternatives.) It has been established that tear-down conditions are the cause of 80% of vegetation outages. Consequently, it is reasonable to prioritize resources toward eliminating those conditions that result in tear-down events. The elimination of hazard trees and overhanging branches has been shown in our previous discussion to have a far greater effect on maintaining high reliability than resources targeted at keeping vegetation from contacting 15kV class lines. 44

45 Resource prioritization can never be performed independent of public policy considerations. These issues are discussed hereafter. The final recommendations of this project take into account a balance of technical, budget, and public concerns. 6.5 Learning Points Optimum use of resources and good cost-benefit results can be achieved as follows. 1. Resources must target three-phase feeder sections where three-phase outages will result from vegetation-caused faults. 2. Hazard/danger tree identification and remediation programs will greatly improve reliability. 3. Eliminating or properly pruning overhanging branches can significantly improve reliability, particularly in storm conditions. 4. Maintaining a mandated minimum vegetation clearance (e.g. not closer than 18 inches) will likely not impact overall reliability and will not be cost effective. 45

46 7.0 National Standards VM practices do not yet receive significant attention in national standards. However, the following questions should be addressed. Q1. Which national standards are commonly used by electric utilities to guide vegetation management practices? Q2. Are any provisions of national standards contrary to best practices? A review of literature identifies several standards which are currently used in the electric utility industry with respect to vegetation management. These are identified as follows. 7.1 Occupational Safety and Health Administration (OSHA) OSHA rules for safe work practices for workers are almost universally accepted as applicable to the electric utility workplace, including VM activities. Careful attention must be given to all relevant safety practices for workers performing vegetation management functions. While OSHA requirements are of a general nature and are often not specific to vegetation management, they nonetheless are a very important component of all vegetation management best practices. The trimming of vegetation in near proximity to energized electric power lines creates an inherently dangerous environment for workers, specifically any unqualified or untrained worker. For example, OSHA places proper emphasis on all workers maintaining clearance (e.g. 10 feet) from energized lines and apparatus during all work activities. [20] Other considerations include proper safe practices when working with tools. 7.2 National Electrical Safety Code (NESC) The National Electrical Safety Code provides general guidelines applicable to line maintenance, worker safety, approach distances, etc. In addition, NESC sets forth general provisions establishing the need for appropriate and suitable vegetation management practices, as determined by each electric utility, to ensure the safe and reliable delivery of electric power over electric power lines. NESC does not establish specific trimming distances, trim cycles, or explicit rules but rather in Section 218 provides a broad foundation for vegetation management as an important function of the utility industry. Section 218 states that trees which may interfere with ungrounded supply conductors should be trimmed or removed. [21] However, the term interfere is subject to interpretation in light of utility experience. 7.3 American National Standards Institute (ANSI) The American National Standards Institute (ANSI) has several standards that are almost universally cited in the vegetation management programs of various electric utilities. These include A300 and Z133 which set forth trimming and pruning practices and safety requirements for vegetation management activities.[22, 23] 46

47 ANSI A300, in general, describes how trees should be trimmed. This includes information on how to make cuts, various definitions with regard to proper pruning procedure, and best practices for the physical act of actually trimming the tree itself. ANSI Z133 details safety practices for workers who are involved in arboricultural operations in general, including utility vegetation management programs. ANSI Z133 is also intended as a guideline for various governmental authorities for use in drafting regulations. It serves as a reference for safety requirements for those engaged in tree pruning, repairing, maintaining, removing trees, cutting brush, or performing pest or soil management. 7.4 Federal Standards It is important to note that there are no national (federal) standards for vegetation management on electric distribution lines. North American Electric Reliability Corporation (NERC) standards and associated federal requirements apply to transmission systems at higher voltages. While there is some discussion to apply VM transmission standards to sub-transmission, no requirements currently exist for distribution lines since these are not governed by NERC but are left to state regulatory entities. [24] If, in the future, any standards from any federal entity are created for distribution systems, then the practices of electric utilities in Texas should be modified as appropriate. 7.5 Learning Points The principles of the referenced NESC, OSHA, and ANSI standards should be included in the VM practices of all electric utilities. This includes ANSI A300 and ANSI Z133. By law, the latest editions of NESC and OSHA should be followed. Collectively, these standards appropriately address worker safety and good arboriculture practices. However, they provide little guidance on such issues as trimming frequency and clearance distances. There is much latitude and room for interpretation in the provisions of the standards. Strict adherence to these standards by a utility may result in a significant increase in tree removal and/or increased severity of trimming. Conversely, another utility could, with a less rigid approach, be considered in full compliance. It is important to note that all standards including VM standards, by their nature, never incorporate the latest and/or best science. Standards are written to identify agreed upon, consensus practices and are always behind current knowledge. Adoption of VM standards is appropriate, but insufficient to define best practices. Findings: NESC and ANSI standards should be adopted by PUCT. Broad latitude should be given to individual utilities to interpret and apply provisions of these standards based on local conditions and requirements. 47

48 Utilities should be allowed to take exceptions to these standards, after PUCT review of written justification. 48

49 8.0 Vegetation Management Scheduling Practices Overview and Discussion A review of vegetation management literature, journal articles, and surveys of the electrical utilities yields a general understanding of the common practices of vegetation management scheduling in the United States. Utility practices vary widely. The following categories have been selected as representative of many vegetation management programs. The range of scheduling practices can generally be classified as periodic (fixed cycle) scheduling, condition based scheduling, or reactive scheduling in response to outages. It is important to note that many utilities use a combination of practices. 8.1 Periodic Fixed Cycles and Cycle Length Some utilities maintain a fixed, periodic trimming schedule based on a perceived need to trim vegetation to match tree growth, because of the simplicity of the approach, or due to regulatory requirements. In these cases, a utility may designate a fixed period for trimming lines (cycle length). This may apply to all lines or to certain high value sections of lines (e.g. three year rotating trim cycle for three phase feeder sections). For some utilities, short, periodic vegetation trimming is used for highly vulnerable areas with rapid vegetation growth that cannot be fully cleared on each visit. Some utilities trim three-phase main trunk lines on a periodic basis but do not trim laterals except as conditions dictate. Other utilities make no distinction between three-phase and single-phase line spans, trimming all on the same trim period or only trimming as needed. Cycle length may vary based on such factors as feeder voltage level. The range of periodic cycles for vegetation management is typically three to five years though in areas of extremely rapid growth may be shorter. Periods exceeding this length are not typical unless supplemented by another vegetation management practice. The general literature indicates that trimming lines more frequently than every two years is not common except in extraordinarily high growth or sensitive areas that cannot otherwise be fully trimmed. Fixed cycle trimming across an entire utility system is easily managed but will over emphasize areas that need little attention and wait too long to address poor performing feeders. 8.2 Outage Response Clearing Virtually all utilities practice some form of vegetation remediation during normal repairs of fault or apparatus damage where vegetation intrusion is noted. Repair crews frequently will trim vegetation away from work areas before repairs are executed. This is necessary to provide a clear workspace for repair crews per OSHA and NESC standards. In other cases, repair crews will notify VM crews of the need for clearing in the subject area. In a few utilities, this is the only vegetation management work performed. Some utilities have no scheduled or reliability based vegetation management protocol, but rather only trim vegetation on an as needed or as found basis, often associated with other repairs or based on ad hoc inspections. As previously noted in the SCL experience described in Section 4.1, this 49

50 method will result in a large number of annual outages. This practice will often result in poor storm performance and will significantly increase the duration of storm caused outages. 8.3 Reliability Centered, Condition Based Scheduling Condition based scheduling of vegetation management, if we use a broad definition, is a common practice. Utilities with this protocol do not have a fixed trimming cycle, but rather use a wide variety of factors to determine which feeders should be trimmed and where funds and manpower should be allocated. This system is typically referred to as reliability centered and condition based vegetation management. Many parameters are taken into consideration to determine which circuits will be scheduled for maintenance. These factors include SAIFI and SAIDI indices, customer reported problems, outages by feeder, the length of time since a feeder was last trimmed, and the type of construction of the feeder. Additional factors include the voltage level of the feeder, the general conditions and type of vegetation dominating on the feeder, and the degree to which the right-of-way can be cleared in light of public sentiment and pressure. When all of the above parameters and factors are taken into consideration, decisions are made on an ongoing (continuing) basis to focus manpower and budget resources towards certain feeders or certain VM activities. With this system, certain feeders might be trimmed every two years, while other feeders may not be trimmed for many years. The justification for such a system is that resources are focused on those feeders and activities that achieve the greatest reliability improvement. Reliability centered or condition based trimming practices are sometimes criticized because they are seen as somewhat subjective. They are highly dependent upon the available knowledge, tracking of feeder performance and the collection of an accurate database of vegetation-caused outages and faults. Unless attention is given to properly gathering necessary data, performing proper statistical analysis, and carefully considering the data sensitivity to the wide range of controlling parameters (e.g. species growth rates), this system may fail to be effective. Condition based maintenance programs, whether for VM or for other industry areas, cannot be managed casually; they require continual review and value decisions by professionals. These decisions are not required in fixed cycle VM scheduling programs, but they are required to optimize reliability for a given cost. It is important to note that selected use of fixed cycle trimming and/or inspection can be an effective component of a reliability centered VM program. 8.4 Hazard/Danger Tree Identification and Remediation Hazard/danger trees represent a substantial contribution to feeder outages. On right-of-way and off right-of-way trees and limbs falling from such trees frequently result in tear-down conditions that are the primary cause of vegetation related outages. [11] Many utilities have developed hazard/danger tree identification programs based on inspection by arborists, often on a periodic, fixed cycle basis. For some utilities, these inspections and subsequent remediation are only applied to three-phase main lines and are not applied to single-phase laterals. 50

51 Hazard/danger tree identification and periods of inspection vary widely among utilities. Some utilities report full inspection as often as two times per year for all lines while others have no hazard tree identification program, depending instead on customer notification or informal observation by work crews. Remediation practices of hazard/danger trees also vary widely. Some utilities aggressively remove all right-of-way trees and also aggressively engage the public to remove weak or dying trees from off rightof-way areas or tall trees that will likely create a tear-down condition during adverse weather. Alternatively, some utilities ignore off right-of-way trees and have no program to remove trees, even those in the right-of-way. In Texas, some utilities have no official hazard/danger tree program. Several large utilities have hazard tree identification programs staffed by trained arborists who perform periodic inspections. 8.5 Evaluation of Common Scheduling Practices Reliability centered practices are common in Texas with many utilities in the state practicing some form of condition based maintenance. The details of each utility s procedures can vary widely. Some utilities that currently practice a form of reliability centered vegetation management are considering moving to fixed trim cycles. Some intend to maintain flexibility to target those feeders on geographic areas that demonstrate poor vegetation related performance during off cycle periods. Drawing inferences from discussions with vegetation management experts in various utilities, we conclude that a change to system wide, fixed-cycle vegetation trimming protocol for all lines would likely result in increased costs. This is partially due to the level of under-trimmed feeders that exist in the state and the fact that existing condition based, reliability centered programs have not always targeted hazard/danger trees or overhanging vegetation. Given the wide variation in conditions across each utility and given the need to optimize resources, all utilities should adopt some form of reliability centered vegetation management program. With such a program, a utility has ultimate flexibility to use every form of vegetation practice, as appropriate, to their individual circumstances and conditions. For example, proper data collection and analysis may show that fixed cycle trimming of three-phase lines in a limited area with relatively uniform vegetation may be both effective and cost optimal. A hazard tree inspection program might be run on a different inspection cycle and should be based on scientific sampling techniques. In other words, the program can be designed by each utility to optimize resources. In summary, no VM scheduling methodology will optimize resources and achieve higher reliability than a properly designed and executed reliability centered, condition based maintenance program. Specific recommendations for a reliability centered VM program are made hereafter. 51

52 9.0 Vegetation Outage Assessment, Data Collection, and Reporting Programs 9.1 Documenting Vegetation Outages Since vegetation causes a significant number of outages and interruptions on certain distribution feeders, resources for vegetation management are best targeted to those feeders that have demonstrated specific vulnerability to vegetation intrusion, as opposed to generally applying vegetation budgets in a uniform fashion across the entire utility. However, targeting feeders with poor vegetation performance can only be accomplished if accurate data is collected and properly analyzed on a continuing basis. The reporting practices of individual utilities as to the cause of outages dictate the availability and quality of data to be analyzed. Even comprehensive, high quality data must be properly interpreted and used to achieve optimal results. Some utilities collect no data as to the cause of outages on distribution feeders. Work orders for outages are issued and the tickets closed with only nominal information collected, sometimes noting only the time that service was restored. In these cases, the actual root cause of the outage is not documented and therefore data to assess the ongoing impact of vegetation intrusion on distribution feeders is simply unavailable. By contrast, some utilities in the United States have instituted aggressive data collection programs in an attempt to fine tune and target vegetation resources. An example of such a utility is Xcel Energy, which uses a detailed data collection process aimed at providing information to vegetation management professionals that includes high level data collection, individual outage inspection by vegetation experts, and subsequent data analysis that focuses on vegetation management activity. It is useful to discuss the norm or mean practice for data collection. It is common to find utilities that require repair crews to check boxes for the cause of an outage. Examples would be a box for outages caused by an animal versus a box checked for outages caused by vegetation. However, it is common for all vegetation related outages to be lumped together with no distinction made for an outage caused by an off right-of-way tree falling over and tearing down lines versus on right-of-way vegetation growing into lines causing an arc condition. The absence of fine detail in these check box procedures is problematic and significantly limits subsequent use of the data. In Texas, many utilities have some form of outage reporting program. Some programs will designate whether a particular outage was caused by a right-of-way or off right-of-way tree. However, it is not common to find a distinction made between an arcing burn down of conductors due to vegetation versus a mechanical tear-down. Preliminary assessment of vegetation-caused outage reporting used by utilities in Texas shows practices that should be continued, but for some utilities, greater detail must be added to forms used by field crews to capture key information. Additionally, it appears that the collected information is only informally used and, in some cases, is never used to dictate or target vegetation management budgets, manpower allocation, or to schedule VM activity. 52

53 In order to make accurate, scientifically based judgments about vegetation management programs, it is critical that sufficient information is captured in a timely and accurate manner by utility companies. For each significant outage, this information should include, at a minimum: Tree species, whether the tree was on or off right-of-way; Whether the event was caused by an electrical or mechanical failure; Information regarding the line construction and voltage (e.g. 12.5kV, horizontal construction); The date the feeder was last trimmed; Estimated clearance from the line before the failure; Branch diameter; and Weather conditions in the area when the failure occurred (e.g. wind, ice, snow, etc.). In addition, for events caused by mechanical teardown, utilities should capture as much information as possible regarding the cause of the tree-failure (e.g. decay, root damage, insect damage, dead tree, etc.), and also the root cause of the outage (e.g. was the outage caused by overhanging branches, an uprooted tree, etc.). 9.2 Calculation of Vegetation Specific SAIDI/SAIFI Indices SAIDI/SAIFI indices have become the standard reliability metric for most utilities in the United States. While the indices are not unilaterally used by all U.S. utilities and are not always calculated on the same basis or using the same definitions, the use of these indices is increasing and now may be considered pervasive. Utilities in the state of Texas, based on PUCT requirements, uniformly collect and report these indices. This practice should continue. An informal survey of utilities in the state and a review of the practice of utilities across the country indicate that most utilities believe there is a strong correlation between SAIDI/SAIFI indices and vegetation-caused unreliability. However, review of technical and scientific literature indicates that contrarily the majority of outages on distribution feeders and the majority of lost customer service are not associated with vegetation-caused outages. Given that other factors predominate as causes of outages and given that the effects of vegetation in the years immediately following a VM activity are relatively low, it must be concluded on a statistical basis that, under the current vegetation management practices commonly employed by utilities, there is not a strong correlation between these indices and vegetation practices, particularly for non-storm calculations. Stated differently, most utilities vegetation management programs do enough to prevent vegetation outages from becoming a significant contributing factor to SAIDI/SAIFI. As shown in the SCL example, however, neglect of vegetation management practices for many years can produce a strong correlation between SAIDI/SAIFI and the lack of good vegetation management. Some utilities have carefully analyzed the problem and have come to the correct conclusion that an exceptional increase in vegetation management expenditures is necessary in order to achieve even a small increase in the overall SAIDI/SAIFI indices for a large distribution system. A few utilities, having 53

54 recognized the problem, have adopted vegetation specific SAIDI/SAIFI calculations drawing on aggressive data collection programs from field crews. In these programs, the causes of all outages related to vegetation are heavily documented including whether the outage was due to a tear-down condition, on or off right-of-way trees, vegetation growth intruding into lines, or an arcing condition related to falling or growing vegetation. Obviously, if feeder specific SAIDI/SAIFI indices are calculated only for vegetation-caused outages, the correlation between these indices and vegetation-caused unreliability is one-to-one. Such VM specific indices have been utilized by utilities such as Xcel to target vegetation management resources. 54

55 10.0 Other Considerations 10.1 Public Education and Interaction Virtually all utilities with vegetation management programs utilize some form of public education, public awareness, and public involvement. This is true of most utilities in Texas. Utilities frequently utilize specific notice programs when trimming in neighborhoods including pre-trimming notification, onsite work notification, and post trimming customer satisfaction surveys. General media education programs are frequently used, at times associated with general electric safety public service announcements. For some utilities, face to face meetings with property owners in areas being trimmed are practiced. Community meetings are sometimes held in areas before tree trimming begins. Local newspaper notifications are sometimes used. Discussions with utilities indicate that programs for public awareness, education, and engagement are considered extremely important and very beneficial in mitigating the negative response of the public to having trees cut. Some utilities go so far to say that it is the most important element of an effective vegetation program. It is a reasonable conclusion that the general public does not understand the importance of vegetation management to power system reliability and the continuity of electric service. Only after a major event such as Hurricane Ike or the 2010 snow storm in north Texas do some segments of the population comprehend the VM problem. Improved education programs are needed to address this significant public relations issue Species Specific/Seasonal Specific Practices Many vegetation management practices may be categorized as all or nothing, non-specific programs where rights-of-way are trimmed or even clear cut based on rigid periodic schedules, or based on an arbitrary time when tree trimming crews arrive at a specific location. In these programs, secondary considerations are not taken into account. For some utilities, consideration of disease that may be spread (e.g. oak wilt) is taken into consideration which would affect the nature of trimming practices and the time of year these practices are applied. Other utilities use trained arborists to identify certain fast growing or problem species trees that must be eliminated rather than trimmed. In certain areas where there is a wide variety of species, slow growing species may be selectively trimmed while fast growing species may be eliminated from right-of-way areas. Certain short lived species are particularly problematic in that they are fast growing yet have a high mortality rate and therefore become danger trees causing tear-down conditions during adverse weather. In Texas, several large utilities report that the species of tree is taken into account during trimming based on whether the species has a slow or fast growing habit. Other utilities in the state report that they have no species specific or seasonal considerations in their vegetation management program. 55

56 Because of the wide variation in tree species in Texas, a single rule for trimming would be complex to create and cumbersome to implement. Species specific guidelines are appropriate for reliability centered VM programs. Each utility should include such considerations, as appropriate Clearance Requirements during Scheduled Trimming Practices vary widely for utilities as to the clearance achieved during trimming activities. For some utilities, trim distances are voltage specific and for other utilities they are species specific. For some utilities with heavy use of higher voltage distribution (e.g. 35 kv), a distinction is made when these feeders are trimmed as compared to 15 kv class feeders. For other utilities, all primary feeder spans are trimmed at the same distance without respect to voltage. For many utilities, the species of tree dictates the degree to which trimming occurs. For slow growing species, the trim distance may be half or less of the distance trimmed for fast growing species. In Texas, it is common to find clearance distances of approximately 10 feet measured horizontally from conductors. Some utilities are experimenting with smaller trim distances. In select cases, 15 feet or greater clearance is used under circumstances including for fast growing species or for trees that are left in the right-of-way. At least one utility has reported a trim distance of 20 feet for fast growing species. If a mature tree is known to be a slow growth species, a minimum trim distance of six feet is used by at least one utility. The trim distances noted above are primarily to control vegetation intrusion until the next regularly scheduled trimming. For some utilities, emphasis is given to overhanging branches and at least one major utility in the state has an objective to remove all overhanging branches on utility right-of-ways because of very negative performance during adverse ice and snow weather conditions. The trim practices described above do not account for hazard and danger tree conditions which are separately addressed. As has been noted, merely trimming trees in proximity to conductors (e.g. 6 foot horizontal clearance) is of limited value in addressing the major cause of vegetation related outages, namely, tear-down conditions due to falling trees or falling or blown larger limbs. Recent research has shown that the magnitude of clearance distance is not the key factor in good VM trimming performance. Attention should be given to the method of pruning of large branches to eliminate failure modes related to ice, snow, wind, and mortality. [11] 10.4 Constancy in VM Budgets For the typical utility, vegetation management is the largest recurring maintenance expense. Distribution feeder pruning, trimming, and tree removal is a major component of the utility VM budget. 56

57 The Utility Arborist Association has identified inconsistent funding as a major issue for vegetation managers. [25] This is due to two primary factors. First, vegetation management should be planned over a multi-year planning horizon for optimal use of funds. Significant, unplanned deferral of expenditures by utility management will often result in inefficiencies and higher costs. Secondly, studies over the last 15 years have shown that deferring vegetation management has a substantial impact on maintenance costs and significantly increases expenditures in future years to achieve the same reliability performance. [25-27] These studies show that costs continued to escalate as the vegetation management work is deferred and reactive emergency work increases; emergency response can have a substantially higher incremental cost. Because vegetation management activity is considered preventive maintenance and is not fixing something that is broken today, utility management often targets VM budgets for deferral based on corporate financial priorities. The impact of deferral of vegetation activities is almost never felt over a matter of months and may not be noted for even years. Ultimately, higher costs can result, reliability will suffer, and unsafe conditions can be created. Recall the experience of SCL after VM deferred. These ultimate negative outcomes are often never directly attributed to a budget deferral decision made years before. The best practice with respect to vegetation management budgets must include long term, sustainable, and consistent funding that is not subject to wild swings or instability. The negative performance impact of VM budget deferral will not be fully explored here; extensive discussion can be found in the above references. However, a few of the negative impacts will be mentioned. Deferral of VM budgets increases costs in several key areas including contractor expenses and clearance complexity. Vegetation management activities require a skilled workforce that is often obtained by hiring contractors. Acquiring, training, and keeping a skilled workforce to meet utility needs can only be optimized if contractors have budgets that are stable over months to years. Arbitrary deferral of budgets causes layoffs of skilled workers and reduces the average skills and availability of workers in the future. This can increase the incremental cost of future contracts. A second factor is the complexity of vegetation trimming and pruning activities that have been deferred for a substantial period. As vegetation grows higher, closer, and more dense around utility feeders, the complexity, time, and cost of vegetation remediation increases. It is also the case that tear-down conditions will increase disproportionately when utilities defer budgets and neglect to remove hazard/danger trees on an ongoing basis. It is not sufficient to just maintain VM budget levels over multiple years. Consistent funding by category of VM activity is also important. While a degree of flexibility is needed by utility VM managers, unplanned or arbitrary movement of VM resources from one activity to another can be as damaging as an overall deferral or reduction in VM budgets. 57

58 Consistent funding of the following VM categories is recommended. - Hazard/danger tree identification, tracking, and removal - Right-of-way trimming, pruning, and clearing Three-phase trunk lines Single-phase laterals - Arborist and VM professional inspection - Scientific studies, reliability calculations, statistical outage tracking, etc. 58

59 11.0 Recommendations 11.1 Applicable ANSI, NESC, and OSHA Provisions Should Be Adopted Basis: These standards and rules are almost universally cited and practiced in principle. They represent a common denominator for arborists and VM specialists and provide guidance for safety in vegetation management activities. ANSI standards including ANSI 300 and ANSI Z133 should be adopted as the standard of care for vegetation management practices in the areas they address. However, accommodation of local conditions should be allowed in the implementation of these standards. NESC Section 218 should be followed by all utilities. Comment: A strict interpretation of ANSI standards may lead to increased removal/trimming of trees as compared to the present practice of a given utility Vegetation Specific SAIFI/SAIDI Indices Should Be Calculated and Reported on an Annual Basis Basis: SAIFI/SAIDI indices that include all outage categories are not a reliable measure of vegetation management effectiveness (on a short term basis) and cannot be used from one year to the next as a reliable indication of where vegetation management resources should be invested. However, such indices calculated specifically for vegetation-caused outages inherently reflect unreliability caused by vegetation intrusion, hazard trees, or neglect in good vegetation management practices, if measured and compared over several years. Common criteria and conditions must be used by all utilities to define and report vegetation causes of outage events and their duration. This is necessary to ensure that an apples-to-apples comparison of VM SAIFI/SAIDI indices can be made between various utilities in the state. Calculations should separately reflect storm, non-storm, and all-inclusive data using common definitions. Reporting criteria for outage cause data must be standardized. Comment: Data collection discipline is difficult to enforce with work crews. Training and positive feedback as to the importance of accuracy are very important. Changes in reporting requirements will require careful attention and effort by utilities beyond just changing reporting forms Mandatory Minimum Clearance Requirements Should Not Be Adopted Basis: Mandating a continual minimum clearance distance of vegetation from conductors will not achieve reliability objectives. Vegetation intrusion within a few feet of conductors has little effect on overall reliability. Given that most vegetation faults are due to tear-down from large limbs or trees falling and given that energized conductors self-trim considerable vegetation as growth approaches 59

60 conductors, mandating a minimum clearance (e.g. 18 inches) will raise the cost to consumers with little effect on the number or duration of outages. Comment: This vegetation management practice has not been justified by cost-benefit analysis as a means to achieve reliability as measured by the frequency and duration of outages 11.4 Reactive Vegetation Clearing in Response to Outages is Appropriate, but Insufficient Basis: Clearing vegetation only in response to outages that have occurred or only as egregious conditions are found during other repair or maintenance procedures is not acceptable as the sole vegetation management practice of a utility, unless the utility is in an area where vegetation intrusion is improbable. Such a practice will result in the numbers of interruptions increasing over time and longer outage durations. Utility experience shows that a moratorium on all scheduled vegetation trimming/clearing causes a substantial increase in outage frequency. Tear-downs will increase over time. Under this practice, electrical repair crews must extensively trim and clear vegetation before electrical outages are remediated thereby increasing outage duration. Storm performance will deteriorate. Comment: For certain parts of the state with very few trees or little vegetation, reactive clearing of the area where a rare vegetation-caused outage has occurred may be an acceptable part of a reliability centered VM program System Wide Fixed Trim Cycles are not Recommended as the Sole Uniform Practice Basis: A fixed-period trim cycle should not be established for statewide application and should not be used as a uniform means to achieve reliability. Fixed cycles may be applicable and effective for a given utility for targeted application if justified by cost-benefit and/or reliability analysis using vegetationspecific outage data. However, this should be left to each utility for case-by-case application. Statewide variations in vegetation type, tree species, growth rates, rainfall, terrain, feeder construction, etc. make a statewide fixed cycle impractical. The climatic and flora diversity of Texas make a single best trim cycle impossible to calculate. If a specific cycle length were picked for all utilities in Texas it would be suboptimal (too little VM) or too costly (too much VM) for any given utility. Rigid adherence by a utility to a fixed trim cycle across its system will not optimize VM resources, resulting in too much attention to areas of good performance and too little attention to key areas that most adversely affect overall reliability. Limited use of a fixed trim cycle may be appropriate, but utilities should continuously evaluate procedures using vegetation-specific SAIDI/SAIFI indices. In other words, a limited use of fixed trim cycles could be a component of an overall reliability centered VM program discussed hereafter. 60

61 Comment: Based on supporting data and analysis, a given utility could use a fixed cycle length for selected purposes. A utility with a near homogenous vegetation profile might successfully adopt a fixed cycle, but should be open to modifying the cycle as performance dictates A Reliability Centered Vegetation Program (RCVP) Should Be Designed and Adopted by Each Utility To achieve maximum reliability at near-optimal cost, vegetation clearing should be scheduled using condition based, reliability centered methods (RCM). We have labeled this a Reliability Centered Vegetation Program (RCVP). Using a combination of techniques including analysis of vegetation-caused outage data analysis and professional inspection procedures, areas of greatest need can be scheduled for attention (e.g. clearing) to maintain acceptable reliability performance. Each utility should design a vegetation management program which should be continually adjusted to achieve reliability objectives. The RCVP must include appropriate protocols for system inspection by vegetation specialists. Inspection should be based on modern sampling and statistical techniques and should take into account local conditions such as tree species, growth rate, rainfall, and other conditions such as time since last trimmed. A well designed RCVP can be tailored to the specific needs of the utility and can be made sensitive to the variation of conditions. In other words, one region of the utility where heavy pine forests predominate may be placed on a fixed-cycle inspection protocol with an emphasis on hazard tree removal. By contrast, an area where scrub trees predominate may not be trimmed for many years pending any upswing in vegetation-caused outages or potential problems identified by inspectors. In both cases, reliability targets can be met with near optimal expenditures. An element of best practice in a well-designed RCVP should be post-outage assessment of all significant outages to determine whether improved or different tree trimming/clearance procedures could have reasonably prevented the outage. It is often the case that a vegetation-caused outage is not preventable even if a scheduled trimming of the area had occurred in the weeks or months immediately prior to the outage. Capturing this preventability designation can further help in future targeting of resources and adjusting criteria used for scheduling. The RCVP must include a hazard/danger tree inspection/remediation protocol using trained professionals. An effective RCVP vegetation management program must include vegetation-specific SAIFI/SAIDI indices. Basis: Conditions across the geography of a large utility vary widely, making a single fixed cycle suboptimal. Annual conditions such as rainfall, also vary, which can dramatically affect regrowth or tree mortality. Inspection by vegetation-management specialists can target resources for optimal effect to maximize reliability performance. Vegetation-management specialists may recommend fixed-cycle trimming of certain infrastructure (e.g. three-phase line sections) in high-growth vegetation areas, but flexibility must exist to target resources based on varying conditions. 61

62 Comment: Some U.S. utilities cite an RCM program but have no scientific procedures in place, do no professional inspection, collect no VM outage data, and regularly defer or reduce vegetation management budgets. This can have a delayed but very negative effect on reliability and can substantially worsen storm performance with the result that overall costs increase when measured over future years. A good RCM-based vegetation-management program requires trained professionals using approved scientific methods. It requires aggressive inspection and continuous evaluation of performance and continuous commitment of adequate resources. For obvious reasons, an RCM-based program is more difficult to police than a fixed-cycle program. However, a properly designed and implemented RCM program will achieve the desired reliability with targeted, near-optimum resource allocation Public Awareness and Engagement Programs Are of Critical Importance An important element of every vegetation management program is proper and effective engagement of the public in advance, during, and after vegetation clearing activities. Each utility should design and implement an effective program. The following list is not intended to be exhaustive but rather representative of the wide range of tools currently used by some utilities in the state and nation to engage the public and avoid negative public sentiment. Elements of a best practice program should include an appropriate mix of the following. General public education media programming (e.g. TV spots) emphasizing issues of electrical safety and the need for vegetation management are important. Attention must be given to scientific accuracy when telling the public of the dangers caused by vegetation intrusion into power lines. Targeted education programs in communities, subdivisions, homeowners associations, etc. are needed in advance of vegetation clearing activities. Prior engagement of the public in this way avoids the surprise of strange men cutting trees in my backyard! The use of door hangers and other notices in advance of trimming activities can be effective with specific emphasis on whom to call for questions and answers. Post-trimming surveys can be effective in documenting the level of public irritation or acceptance of the procedures used by a utility Proactive Programs Can Reduce Future Vegetation Management Costs and Should Be Encouraged Tomorrow s hazard tree is being planted today! In new subdivisions that were clear-cut before construction, inappropriate tree species are being planted on or near the right-of-way. This includes 62

63 fast-growing, short-lived trees, tall species, and species that shed branches planted such that their ultimate height and breadth will overhang utility rights-of-way. Such trees will adversely affect future reliability and will increase vegetation management costs over the life of the tree. Programs coordinated with local authorities (e.g. municipalities) that control planting as a function of distance from right-of-way and tree species will significantly reduce vegetation life-cycle costs to consumers. Volunteer programs based on public education, while valuable, can never achieve the effectiveness of rules incorporated into property and homeowners association covenants. While such programs are discussed, an example of such a program that has been scientifically evaluated has not been found. Comment: Prohibiting the planting of certain species within specified distances of utility rights-of-way will be considered by some a draconian measure and a violation of the right of homeowners to use property as they wish. Balance may be hard to achieve, but this method of reducing future vegetation management costs should be studied. A specific recommendation is not included at this time; more study is needed A Statewide Vegetation Management Public Relations Discussion and Consensus Are Needed At any given moment, utilities are being criticized for excessive tree trimming or removal while being sued for alleged injuries or dangers due to vegetation in lines. This dichotomy can never be fully alleviated and case-by-case attention is appropriate. However, clear VM expectations for utilities are needed. Prioritization of reliability enhancing VM practices will not and cannot remove all perceived or real dangers of vegetation around power lines. Care must be taken that public information and educational documents are written consistent with the best science and knowledge to avoid unrealistic expectations Future Areas of Investigation and Opportunity 1) New technologies for real-time monitoring to detect distribution feeder vegetation intrusion should be investigated. Controlled experiments should be conducted. 2) Additional research is needed to better define and quantify the best scientific sampling and statistical methods to determine optimal inspection protocols and frequency. These techniques are not fully mature and deserve investigation. 3) There is a deficiency of long term, controlled experiments defining the exact behavior of feeders over multiple years following trimming. Using advanced monitoring techniques to detect and characterize momentary interruptions and outages, experiments should be conducted to track the behavior of feeders to vegetation intrusion. Scientific protocols will require monitoring of a number of feeders over five years or more with annual inspection by arborists to document vegetation re-growth. These experiments could be designed to definitively answer persistent questions that cannot adequately be addressed with current scientific knowledge. 63

64 4) Studies should be conducted to design and evaluate public information and education programs on the need for vegetation management. While certain public relation tools have been found effective by some utilities, scientific and statistically significant evaluations are still needed. 64

65 List of Figures in Main Text Figure 1: Distribution Faults in the Duke Power System Source: Chow, M.-Y., and Taylor, L. S., Analysis and Prevention of Animal-Caused Faults in Power Distribution Systems, IEEE Transactions on Power Delivery, vol. 10, no. 2, pp , April 1995 Figure 2: Fault Causation due to Voltage Gradient Source: J. Goodfellow, Understanding the Way Trees Cause Outages, 2000 Figure 3: Time Required to Create Vegetation Faults Source: J. Goodfellow, Understanding the Way Trees Cause Outages, 2000 Figure 4: Typical tunnel effect from an energized conductor passing through vegetation Source: picture by B. Don Russell, 2010 Figure 5: Effects of vegetation management during 2010 Oncor snowstorm Source: Mauren, L., ONCOR PPT presentation, 2010 Figure 6: Distribution of SAIFI including and excluding storms Source: Edison Electric Institute, EEI Reliability Survey, 8 th Meeting of the Distribution Committee, March Figure 7: Distribution of SAIDI including and excluding storms Source: Edison Electric Institute, EEI Reliability Survey, 8 th Meeting of the Distribution Committee, March Figure 8: SAIFI by outage cause Source: Canadian Electrical Association, 2001 Figure 9: SAIDI by outage cause Source: Canadian Electrical Association,

66 Figure 10: Histogram of customers affected by individual outages Source: PSERC Final Report, Project T27G Figure 11: Histogram of customer-minutes of interruptions by outage Source: PSERC Final Report, Project T27G 66

67 List of Figures in Appendix A Figure 1: Experimental setup Source: Power System Automation Laboratory, Texas A&M University Figure 2: Tree branch following flashover, carbonized path visible on right Source: Power System Automation Laboratory, Texas A&M University Figure 3: Carbonized path extends from both ends Source: Power System Automation Laboratory, Texas A&M University Figure 4: Carbonized path extends under bark, producing steam and smoke Source: Power System Automation Laboratory, Texas A&M University Figure 5: Formation of an arc between conductors Source: Power System Automation Laboratory, Texas A&M University Figure 6: RMS current from neutral conductor, measuring during staged vegetation fault Source: Power System Automation Laboratory, Texas A&M University Figure 7: RMS Phase currents, 11/2/2004 vegetation fault Source: Power System Automation Laboratory, Texas A&M University Figure 8: RMS Phase voltages, 11/2/2004 vegetation fault Source: Power System Automation Laboratory, Texas A&M University Figure 9: RMS Phase currents during final failure in vegetation outage Source: Power System Automation Laboratory, Texas A&M University Figure 10: RMS Phase voltages during final failure in vegetation outage Source: Power System Automation Laboratory, Texas A&M University Figure 11: Vegetation contacts causing momentary interruptions Source: Power System Automation Laboratory, Texas A&M University 67

68 Appendix A: How Electrical Faults Occur as a Result of Vegetation Intrusion Research Source: Power System Automation Laboratory Department of Electrical and Computer Engineering Texas A&M University Introduction Faults occur on electrical systems for a variety of reasons. Broadly speaking, all faults are caused by the formation of a conductive path between an energized conductor and another phase conductor, the system neutral, or ground. The electrical characteristics of a fault and the system s reaction to it are determined by the nature of the conductive path that is formed. If the conductive path is a short-circuit (low impedance), current flow will increase in magnitude until it reaches the maximum available current at the location of the fault, causing significant physical damage. If the conductive path has high impedance, current may flow for extended periods of time before being detected, creating a significant public safety hazard. Because electrical faults are a hazard both to the power system and the public, devices are installed at multiple levels to interrupt power in the event a fault is detected. The most familiar example of system protection for most people is a residential circuit breaker. One of the most important functions of circuit breakers in residential applications is to interrupt power when a short-circuit condition is detected. The circuit breaker trip allows the faulted condition to be safely corrected before reenergizing the circuit. Transmission and distribution circuits behave in a similar way. When protective devices along a circuit detect a fault condition, they deenergize the circuit. On transmission and distribution lines, this interruption will often result in the permanent removal of the faulted path. As one example, if a squirrel stands on the unprotected terminals of a distribution transformer, a conductive path will be created through its body. If the circuit is deenergized, the squirrel will usually fall off the transformer, and when the circuit is reenergized, the conductive path will no longer be present. As a result, a common standard practice is to interrupt the circuit, then reapply power ( reclose ) to see if the fault persists. Protective devices may be set to reclose several times before permanently interrupting the circuit ( tripping out ). Vegetation causes electrical faults in a variety of mechanisms. This appendix focuses on faults caused by mechanisms not related to broken conductors or other conductor tear-down. Vegetation contacting distribution feeders Vegetation management on distribution systems is designed to prevent trees and other vegetation from contacting power lines. While these programs generally do a good job of preventing contact, there are situations where vegetation does contact primary lines. 68

69 If a branch contacts only a single-phase conductor or the system neutral, previous research suggests that at typical distribution voltage levels, only a relatively small amount of current is conducted through the tree and root system to ground, due both to the relatively high impedance of the tree and the low voltage gradient between the line and ground. Multiple tests have been performed where energized lines remain in contact with the trunk of trees for extended periods of time drawing only a few amperes of current. Each of these studies concluded that that a branch contacting a single conductor was unlikely to progress electrically into a high current event. When a branch bridges either two phase conductors or a single-phase conductor and the system neutral wire, however, a high current event is far more likely. Instead of the available voltage being spread over a large physical distance, resulting in a relatively low gradient, it is instead concentrated on a much smaller distance, typically on the order of a few feet. The increased voltage gradient creates the possibility of a high current fault. This phenomenon has been observed both in laboratory and field conditions for a single-phase conductor and the system neutral, and by extension should also occur between multiple phase conductors. If a branch spans a phase conductor and a neutral conductor with a sufficiently close physical distance, scintillation begins near each contact point. Localized heat is generated which begins to char and carbonize organic compounds in the wood. The carbonized portion of the wood is far more conductive than non-carbonized parts. As a result, the non-carbonized area immediately adjacent to the nowcarbonized portion of the branch begins to scintillate and burn, extending the charred portion of the branch. This process continues, with each carbonized path extending from both contact points preferentially toward the other contact point. Each charred path continues to extend until they meet and form a continuous carbonized path between the two lines. At this point, a low-impedance path is formed between both conductors, and a high current event occurs. Staged vegetation faults As part of a vegetation management project funded by the Power Systems Engineering Research Center, researchers at Texas A&M performed a series of tests to characterize the electrical nature of vegetation faults. These tests were conducted at the downed conductor test facility located on Texas A&M s Riverside campus. The distribution feeder serving Riverside campus is monitored at the substation by Texas A&M researchers on a continual basis as part of their ongoing work to detect, prevent, and mitigate power system faults. The tests were performed with two primary objectives. First, researchers wanted to better understand the progression of how vegetation contacts cause electrical faults. Second, researchers wanted to explore the possibility of detecting such faults from substation-based equipment to address the feasibility of improving vegetation management through advanced monitoring. The downed conductor test facility is served by a 7,200V primary distribution feeder, and is located approximately two electrical miles from the substation. The facility has been used for a variety of testing involving high-impedance faults, including research on vegetation contacts. The test facility allows 69

70 researchers to conduct experiments on an operational power system, as opposed to simply simulating such experiments in a laboratory. These experiments were designed to explore prolonged contact of branches with power lines. Researchers selected branches on various trees in the area to trim and use for experiments. Local vegetation consists primarily of hackberry, chinaberry, and crape myrtle trees, all of which were selected for experimentation. In addition to multiple species, branches of varying diameters and lengths were selected. The experimental setup consisted of two sawhorses, initially positioned four feet apart. Each sawhorse had two insulators, one attached to each end, which supported a conductor. The conductor on one sawhorse was connected directly to a single-phase of the distribution feeder at 7,200V. The other was connected to ground through a bank of resistors with an equivalent impedance of 500 ohms for current limiting purposes. Branches were then laid across the lines, held in place only by gravity. The entire setup was fused with a 2A, type T fuse. The entire experimental setup can be seen in Figure 1. Figure 1: Experimental setup After a branch was laid across the line, linemen would energize the circuit. Video and still photographs were taken to document the progression of each run. Multiple tests were performed, and all tests produced similar results. Photographs and electrical measurements presented below are indicative of all tests performed. 70

71 Physical progression of staged vegetation fault As noted in the previous section, when the conductor was energized, scintillation began at each end of the branch, forming a carbonized path, as seen in Figure 2. This process occurs at both ends of the branch, with the path lengthening toward the center of the branch. As the carbonized path extends, it may do so either on the surface of the branch, as shown in Figure 3, or underneath the bark, as seen in Figure 4, which shows steam and smoke escaping through holes in the bark as the carbonized path burns underneath. While the carbonized path is burning, the un-carbonized portions of the branch serve essentially as a high-impedance conductor. Significant heat, burning, and steam can be produced while the fault is drawing an ampere or less of current. Eventually, the two carbonized paths meet near the middle of the branch, forming a continuous carbonized path from one conductor to the other. The carbonized path has significantly lower impedance than the branch, resulting in a high-current flashover event, shown in Figure 5. Figure 2: Tree branch following flashover, carbonized path visible on right 71

72 Figure 3: Carbonized path extends from both ends Figure 4: Carbonized path extends under bark, producing steam and smoke 72

73 Figure 5: Formation of an arc between conductors After a high-current event occurs, an arc forms between the two conductors, as shown in Figure 5. The arc initially forms along the carbonized path, but quickly shifts to the plasma immediately surrounding the branch. Figure 5 clearly shows the arc wrapped around the center of the branch. As common with arcing faults of this nature, the heat of the plasma causes it to rise, extending the length of the arc, and also increasing its impedance. Eventually, the voltage between the lines will be insufficient to sustain the arc through the plasma, and it will extinguish. Because the carbonized path remains on the branch, the arc immediately restrikes along the branch, repeating the process until the operation of the fuse. Figure 6 shows electrical measurements obtained during one of the tests. The figure shows the RMS current for the neutral conductor while the branch was arcing. Each peak in the graph corresponds to the increase in current, followed by its subsequent decrease after the extinction of the arc. The final step down in the graph corresponds to the operation of the fuse. Several things are clearly evident from this graph. First, in its high-impedance state, the branch conducted a relatively small amount of current. The difference between the high impedance state shown at the beginning of the recording and the postfault state shown at the end is approximately 1 ampere. Second, it is also clear that so long as the branch remains in contact with the line, high-current events will continue to occur until a protective device operates, or physical damage removes the branch, either through damage to the branch or the line. 73

74 Figure 6: RMS current from neutral conductor, measured during staged vegetation fault 74

75 Appendix B: Naturally Occurring Vegetation Outage Case Studies Research Source: Power System Automation Laboratory Department of Electrical and Computer Engineering Texas A&M University Background Researchers at Texas A&M have ongoing projects with utilities across the country to develop advanced power system monitoring equipment with the goal of preventing power system failures and increasing situational awareness. In the course of these projects, researchers have compiled a large database of faults, including vegetation faults. In many cases, there is significant advanced warning before the final catastrophic failure which results in a permanent outage for customers. Two cases of recorded, naturally occurring vegetation faults are presented hereafter. Case Study 1: Vegetation related outage On the morning of November 2, 2004, one of Texas A&M s monitors detected a single-phase fault on the feeder it monitored. The RMS currents measured during this fault are shown in Figure 7, and the RMS voltages in Figure 8. Before the fault, each phase served slightly less than 200A of normal load current. The fault drew an additional 700A of current, resulting in an instantaneous current value of 900A RMS on the faulted phase. This additional current triggered the operation of a protective device, a three-phase recloser located on a poletop between the substation and the faulted point. Figure 7 shows the high-current event, which is terminated by the operation of the poletop recloser, which trips at approximately 2.6 seconds in the graph, then recloses approximately 2 seconds later. When the breaker reclosed, the fault was no longer present, and the system continued to operate normally, at least temporarily. All customers downstream of the poletop recloser experienced complete loss of electrical power for the entire two second period the relcoser was open. 75

76 1,000 RMS Phase Currents 11/02/ :57:47 RMS Amps Time (seconds) Figure 7: RMS Phase currents, 11/2/2004 vegetation fault 9,000 RMS Phase Voltages 11/02/ :57:47 RMS Volts 7,000 5,000 3, Time (seconds) Figure 8: RMS Phase voltages, 11/2/2004 vegetation fault 76

77 Table 1: Recloser operations during vegetation fault Date Time Trips 11/2/2004 6:57:47 1 7:58: /3/2004 0:09:06 1 0:16:48 1 0:40:38 1 0:40:53 1 1:10:51 1 1:12:37 1 1:15:30 1 3:24:47 1 4:19:39 1 4:30:36 1 5:51:01 1 Total 6:19: Over the next 24 hours, the fault recurred multiple times. Table 1 shows 14 distinct times over the next day when the fault created an overcurrent condition, each time tripping the recloser at least once, and sometimes tripping it multiple times. Each time the fault recurred, all customers on the feeder experienced a momentary voltage dip, and all customers past the recloser experienced a momentary interruption. Figure 9 and Figure 10 show electrical measurements obtained during the final failure in this sequence, which burned down the line at the point of contact, leaving 140 customers without power for 62 minutes. Utility crews responding to lights out calls found that a tree limb had fallen on the line without immediately breaking the line. The line was constructed with a phase conductor on top of the pole, and a neutral conductor several feet below on the same pole. A fork in the branch caused it to hang on the conductor, and the weight of the branch pulled it down closer than normal to the neutral conductor. As a result, the tree branch contacted the phase conductor continuously and the neutral conductor intermittently. This casual contact eventually resulted in periodic flashovers that resulted in the momentary interruptions and eventually caused enough damage to burn down the line, resulting in a sustained outage. 77

78 1,000 RMS Phase Currents 11/03/ :19:45 RMS Amps Time (seconds) Figure 9: RMS Phase currents during final failure in vegetation outage 9,000 RMS Phase Voltages 11/03/ :19:45 RMS Volts 7,000 5,000 3, Time (seconds) Figure 10: RMS Phase voltages during final failure in vegetation outage 78

79 Case Study 2: Advanced monitoring prevents outage caused by vegetation intrusion On the morning of July 12, 2010, researchers at Texas A&M recorded three individual faults on a 25 kv distribution feeder. A fourth fault on the same feeder was recorded the following morning. Each of these faults exhibited similar electrical characteristics. The feeder was monitored in an experimental program in which automated algorithms developed at Texas A&M were used to identify that all four faults were likely related to one root cause. In particular, each of the faults occurred on Phase C, all faults had magnitudes between amperes, each time the fault tripped a single-phase recloser, each time the recloser took two cycles after the fault initiated to open, and each time minimal load was past the sectionalizing hydraulic recloser that momentarily interrupted the fault. Each reclose was successful and no sustained outage occurred, but, the root cause persisted causing four separate momentary events over two days, indicating that further occurrences were likely. Researchers informed the utility, which was able to use the referenced information to narrow its search area. Based on the possible feeder locations identified by electrical measurements, the utility dispatched a crew on the afternoon of July 13 to check for problems along the circuit. A two-man crew located the likely problem following a brief search. Photographs of the fault area follow. The sequence of events for July were as follows. 7/12/10 8:02 AM - Feeder trips due to vegetation fault at 812 amps - DFA records faults; no outage 7/12/10 8:31 AM - Feeder trips due to 819 amp vegetation fault - DFA records fault; no outage 7/12/10 9:28 AM - Feeders trips due to 860 amp vegetation fault - DFA records fault; no outage 7/13/10 10:01 AM - Feeder trips due to 831 amp vegetation fault - DFA records fault; no outage Even though no sustained outage occurred, the repetitive faults caused momentary interruptions in customer service and affected power quality. Each event also likely caused a high-energy, hightemperature arc and possibly emitted burning particles. 79

80 Figure 11: Vegetation contacts causing momentary interruptions 80

81 Figure 11 shows vegetation encroachment on the lines in the search area. The top portion of Figure 11 shows both the neutral and phase conductor passing through vegetation, while the bottom portion of Figure 11 is zoomed to show the burned tips of branches. Utility crews trimmed the trees, but did not have certainty that this tree contact was the culprit of the momentary interruptions observed at the substation. Subsequent monitoring of the feeder resulted in no similar interruptions for the six months between the time of the event and the writing of this report. Four episodes of the fault occurred in two days, trees were trimmed, and no further episodes occurred, confirming the crew s diagnosis that the vegetation contacts were responsible for the interruptions. Conclusion Vegetation contacts need not tear down a power line to cause a momentary interruption or sustained outage on power systems. A variety of mechanical configurations exist which can result in the formation of a conductive path through a branch between two conductors. Regardless of the mechanical configuration and voltage levels involved, the electrical progression is similar in all cases. Intermittent or sustained contact over an extended period time results in scintillation and charring which forms a carbonized path along the branch or underneath the bark. This carbonized path eventually forms a continuous low-impedance path between the two conductors, resulting in a high-current event. On operational distribution circuits, the resulting current is generally high enough to operate a protective device, which may result in the temporary removal of the fault. If the underlying vegetation cause persists, however, the fault will recur, ultimately resulting in a sustained outage. 81

82 Appendix C: PUCT Workshop Agenda The attached agenda and slides were used in the workshop held at PUCT on March 10, 2011 in Austin, Texas. The workshop was facilitated by Dr. B. Don Russell. Discussions and input from this workshop was used in the project that resulted in this report. PUC/TAMU Vegetation Management Workshop March 10, 2011 (Project: 38257) Facilitator: Dr. B. Don Russell, P.E. Regents Professor Texas A&M University Leading 8:00 AM Introductions and Logistics PUC Staff 8:10 8:20 Overview of Purpose and Objectives PUC Staff 8:20 9:30 Vegetation Management Overview Dr. Russell How Vegetation causes outages a. Mechanical tear-down b. Electrical causes of faults c. Video Presentation of vegetation faults d. Case Studies Framing the VM Issues Does vegetation contact create a public safety hazard? 9:30 10:00 Measurement Methods (Metrics) for Assessing Effectiveness of VM Practices (SAIDI, SAIFI, etc.) 10:00 10:15 Break 10:15 12:00 Reliability Improvement vs. VM Budgets Dr. Russell Mainline verses lateral trimming relative value Discussion of National Standards Mandated minimum clearance requirements Targeting worst performing feeders 12:00 1:15 PM Lunch 82

83 1:15 2:45 Vegetation Outage Reporting Practices Dr. Russell Species Specific Targeting/Seasonal Trimming Public Education/Public Awareness (The value of media, materials, PR ) 2:45 3:00 Break 3:00 4:15 Discussion: Dr. Russell Characteristics of VM Best Practices 4:15 4:45 Open Forum Wrap-up - Action Items PUC/TAMU 5:00 Close 83

84 Appendix D: Bibliography and Suggested Reading Appelt, J. J., Goodfellow, J. W., Research on How Trees Cause Interruptions- Applications to Vegetation Management, Proc. of IEEE Rural Electric Power Conference, Scottsdale, AZ Aucoin, M., Russell, B.D., "Fallen Conductor Faults: The Challenge to Improve Safety," Public Utilities Fortnightly, Vol. 129, No. 3, February 1992, pp Beard, A., System Forester Best Management Practices-Customer Interface, white paper, Syst. Foresters Summit. Benner, C.L., Russell, B.D., "Characteristic Behavior of Downed Electrical Lines Including Evaluation of Various Electrocution Scenarios," presented at the 51st Annual Meeting of the American Academy of Forensic Sciences, Orlando, FL, February 15-20, Benner, C.L., Russell, B.D., "Arcing Fault Detection - An Update on the Technology," presented at the IEEE PES Winter Power Meeting, Tampa, FL, February 2-5, Brooks, L., Utility Vegetation Management and Bulk Electric Reliability Report From the Energy Regulatory Commission, Brown, R. E., Gupta, S., Christie, R. D., Venkata, S. S., and Fletcher, R., Distribution System Reliability Assessment: Momentary Interruptions and Storms, report Vol Brown, R., Distribution Hardening: Benchmark Survey and Best Practices, Project no Raleigh: Quanta Technology, Brown, R., Hazard Trees: Benchmark Survey and Best Practices, Project no Raleigh: Quanta Technology, Browning, M., Wiant, H. V., The Economic Impacts of Deferring Electric Utility Tree Maintenance, Journal of Arboriculture, May 1997, 23(3) pp Burke, J. J., Lawerence D. J., Characteristics of Fault Currents on Distribution Systems, IEEE Transactions on Power Apparatus and Systems. vol. PAS-103, no. 1, pp. 1-6, January Chow, M.-Y., and Taylor, L. S., Analysis and Prevention of Animal-Caused Faults in Power Distribution Systems, IEEE Transactions on Power Delivery, vol. 10, no. 2, pp , April Cieslewicz, S. R., and Novembri, R. R., Utility Vegetation Management Final Report, report Ed. Mary F. Burns

85 Detection of Downed Conductors on Utility Distribution Systems, IEEE Tutorial Course, Text No. 90EH PWR, Course organizer: B. D. Russell, presented at the IEEE/PES Summer Power Meeting, Minneapolis, Minnesota, July Electric Power Research Institute. An Asset Management Approach to Vegetation, 27 Oct [PPT]. Electric Power Research Institute, Project , Electric Distribution Hazard Tree Risk Reduction Strategies, Electric Power Research Inst., Palo Alto, CA, Electric Power Research Institute, Project , Power Quality Implications of Transmission and Distribution Construction: Tree Faults and Equipment Issues, Electric Power Research Inst., Palo Alto, CA, Finch, K., Understanding Tree Outages, EEI Vegetation Managers Meeting, Palm Springs, CA, May 1, Goodfellow, J., Understanding the Way Trees Cause Outages, 2000, Goodfellow, J., Peterson, W., Trees and Reliability, [Online]. Available: Goodfellow, J. W., Development of Risk Assessment Criteria for Branch Failures Within the Crowns of Trees, BioCompliance Consulting, Inc. [PPT]. Goodfellow, J. W., Understanding How Trees Cause Interruptions, [PPT]. Goodfellow, J.W., Utility Vegetation Management: Use of Reliability Centered Maintenance Concepts to Improve Performance Report, Electric Power Research Inst., Product ID #043237, Goodfellow, J.W., Overhead Distribution Vegetation Challenges: Touch Potential Voltage at Ground Level and Aloft in Trees Contacting Energized Distribution Conductors, Electric Power Research Inst., 2008, Project Goodfellow, J.W., Distribution Overhead Lines: Understanding Touch Voltage Potential Risks due to Tree-to-Conductor Contacts on Distribution Circuits, Electric Power Research Inst., Project No Goodfellow, J. W., Research Update: Tree-Initiated Faults and Interruptions, presentation to IEEE Power Engineering Society Distribution Committee, January 2007, [PPT]. Goodfellow, J. W., Development of Risk Assessment Criteria for Branch Failure Within the Crowns of Trees, Int. Society of Arboriculture (ISA)/Utility Arborists Assoc. Annual (UAA) Conference, July

86 Goodfellow, J. W., Characterizing the Risk that an Aging Urban Forest Poses to an Overhead Distribution System, International Society of Arboriculture (ISA)/Utility Arborists Association Annual (UAA) Conference, August 2009 Goodfellow, J. W., Blumreich, B., Nowacki, G., Tree Growth Response to Line Clearance Pruning, Journal of Arboriculture, August 1987, 13(8) pp Goodrich-Mahoney, J., Electric Distribution Hazard Tree Risk Reduction Strategies, Tech. No Electric Power Research Inst., Goodrich-Mahoney, J. W., ROW: Siting, Vegetation Management, and Avian Issues, Land and Groundwater Area Council, 16 Mar [PPT]. Grayson, L., UAA Best Management Practices-Funding, white paper, Syst. Foresters Summit. Guggenmoos, S., Vegetation Management Concepts and Principle. Kuhns, M. R., Reiter, D. K., Knowledge of and Attitudes About Utility Pruning and How Education Can Help, Arboriculture and Urban Forestry, 2007, 33(4) pp Mauren, L., Snowstorm February ONCOR, [PPT]. Neal, M., Goodson, D., System Forester Best Management Practices-Cost Driver, white paper, Syst. Foresters Summit. Olearczyk, M., Crudele, F. D., Overhead Distribution Vegetation Challenges, Tech. No Electric Power Research Inst., Olearczyk, M., Optimal Design of Overhead Distribution Systems, Tech. No Electric Power Research Inst., Rees, W. T., Birx, T. C., Neal, D. L., Summerson, C. J., Tiburzi, F. L., Thurber, J. A., Priority Trimming to Improve Reliability, Russell, B.D., Aucoin, M. "Detection of Incipient and Low Current Faults in Electrical Distribution Systems," Proceedings of the 24th Intersociety Energy Conversion Engineering Conference, Washington, D.C., August 6-11, 1989, pp Russell, B. D., Benner, C.L., Arcing Fault Detection for Distribution Feeders: Security Assessment in Long Term Field Trials, IEEE Transactions on Power Delivery, Vol. 10, No. 2, April 1995, pp

87 Russell, B. D., Benner, C. L., Intelligent Systems for Improved Reliability and Failure Diagnosis in Distribution Systems. Tech. No st ed. Vol. 1. IEE Transaction on Smart Grid, Russell, B. D., Benner, C. L., Wischkaemper, J., Jewell, W., McCalley, J., Reliability Based Vegetation Management Through Intelligent System Monitoring, Power Systems Engineering Research Center (PSERC), report Texas A&M University, Short, T. A., Distribution Reliability and Power Quality. Boca Raton.: CRC/Taylor & Francis, Williams, C., Kreiss, D., Bad Weather vs. Power Reliability Progress: Florida Seeks to Normalize Reliability Indices, Utility Automation and Engineering T&D, September Wischkaemper, J. A., Benner, C. L., Russell, B. D. Electrical Characterization of Vegetation Contacts with Distribution Conductors Investigation of Progressive Fault Behavior, Proceedings of the PES T&D Conference and Expo, Chicago Illinois, April Xcel Energy, Vegetation Management (root cause analysis, vegetation outages September 2008-August 2009.) [PPT]. Ziemianek, B., "Northwest Utility Tackles Tree-Trimming Issues." Transmission & Distribution World. T&D, 1 Oct Web. 87

88 References [1] "Reliability Based Vegetation Management Through Intelligent System Monitoring," PSERC T-27G Final Report, [2] C. A. Warren, R. Ammon, and G. Welch, "A survey of distribution reliability measurement practices in the US," Power Delivery, IEEE Transactions on, vol. 14, pp , [3] J. J. Burke and D. J. Lawre, "Characteristics of Fault Currents on Distribution Systems," Power Apparatus and Systems, IEEE Transactions on, vol. PAS-103, pp. 1-6, [4] C. Mo-yuen and L. S. Taylor, "Analysis and prevention of animal-caused faults in power distribution systems," Power Delivery, IEEE Transactions on, vol. 10, pp , [5] "Electric Distribution Hazard Tree Risk Reduction Strategies," EPRI , Palo Alto, CA, [6] "Power Quality Implications of Transmission and Distribution Construction: Tree Faults and Equipment Issues," EPRI , Palo Alto, CA, [7] K. Finch, "Understanding Tree Outages," presented at the EEI Vegetation Manager's Meeting, Palm Springs, CA, [8] "Hurricane Ike Situational Reports," United States Department of Energy, [9] D. Sevcik, "Lessons from Hurricane Ike - Centerpoint Energy," presented at the 62nd Annual Confrence for Protective Relay Engineers, Texas A&M University, [10] Energy Information Administration / Electric Power Monthly September [11] R. Brown, "Hazard Trees: Benchmark Survey and Best Practices," PUCT 36375, [12] K. L. Butler, B. D. Russell, C. Benner, and K. Andoh, "Characterization of electrical incipient fault signature resulting from tree contact with electric distribution feeders," in Power Engineering Society Summer Meeting, IEEE, 1999, pp vol.1. [13] W. Rees, T. Birx, D. Neal, C. Summerson, F. Tiburzi, and J. Thurber, "Priority Trimming to Improve Reliability," Baltimore Gas and Electric Company. [14] J. A. Wischkaemper, C. L. Benner, and B. D. Russell, "Electrical characterization of vegetation contacts with distribution conductors - investigation of progressive fault 88

89 behavior," in Transmission and Distribution Conference and Exposition, 2008, T&D, IEEE/PES, 2008, pp [15] "IEEE Guide for Electric Power Distribution Reliability Indices," IEEE Std (Revision of IEEE Std ), p. 0_1, [16] B. Ziemianek. (Oct. 2010) Northwest Utility Tackles Tree-Trimming Issues. Transmission & Distribution World Magazine. [17] L. Mauren, "Snowstorm February 2010 [PPT]," ONCOR. [18] R. Billinton, "Probabilistic Reliability Evaluation of Electric Power Systems," presented at the Distinguished Speaker Series, Texas A&M University Department of Electrical Engineering, November [19] "Vegetation Management (Root Cause Analysis, Vegetation Outages), September August 2009) [PPT]," Xcel Energy. [20] "Worker Safety Series," Occupational Health and Safety Administration. [21] "National Electric Safety Code C2-2012," IEEE Standards Association, IEEE. [22] "Arboricultural Operations," American National Standards Institute Z133. [23] "Standards for Tree Care Operations," American National Standards Institute, A300. [24] "Transmission Vegetation Management Program," National Electric Reliability Corporation, FAC-003. [25] L. Grayson, "UAA Best Management Practices - Funding," System Foresters Summit - white paper. [26] J. Goodfellow, "Development of Risk Assessment Criteria for Branch Failure within the Crowns of Trees," presented at the International Society of Arboriculture/Utility Arborists Association Annual Conference, July [27] D. M. Browning, "The Economic Impacts of Deferring Electric Utility Tree Maintenance," Environmental Consultants, Inc. April