Many states of distribution

24 IEEE power & energy magazine july/august 20071540-7977/07/$25.00©2007 IEEE

july/august 2007 IEEE power & energy magazine 25

TTHE ELECTRIC DISTRIBUTION SYSTEM IN THE UNITED STATES IS CELEBRATINGover 125 years of design, development, expansion, and evolution. During that time, thousands ofutilities that sprung up across the country met their customer’s needs with many different typesof system configurations, frequencies, and line voltages. Today, these systems serve nearly 138million customers that use 3.66 trillion kWh (www.eia.doe.gov/cneaf/electricity/epa/epa_sum.html, www.eia.doe.gov/cneaf/electricity/esr/backissues.html). This article will providea brief synopsis of the prevalent distribution systems in use today. Of necessity, it must omit dis-cussion of many of the types of systems that remain from those historical beginnings. In no wayis this meant to diminish the importance, efficacy, or adequacy of those systems that currentlysatisfy customers’ needs that are not described herein.

How It StartedTo understand the broad range of voltages, wire configurations, and grounding methods used todeliver electrical energy on the distribution systems in the United States, one needs to understandthe history of the development of the electric delivery system there. When Edison, Westing-

house/Tesla, Thompson, and others showed the world how electricity could be generated, trans-ported, and utilized, capitalists in almost every mill town installed an electric generator at

one of the dams and started their own electric company. It was recognized from thestart that only one electric company could efficiently supply a specific locality, theconcept of a natural monopoly, and towns granted franchises to those companiesoffering the best terms to the citizens or, in some cases, to the town offices. Initially,the power was only used to operate the machines, and 25 Hz was often the frequency

of choice. So entrenched was this frequency for operation of motors that the last of the25-Hz delivery systems at Niagara Falls was only removed in 2006. The marketing ofelectricity for lighting required a higher frequency to eliminate flickering of the incan-descent filament. Tesla proposed 60 Hz, for many other reasons besides lamp flicker, and

we have utilized that as a national standard ever since. Expansion was rapid, and as earlyas 1891 nearly 2,000 separateelectric companies were supply-ing electricity to small towns andcities across the country.

It did not take very long forthe fledgling electric companiesto realize that economies of scalecaused a dramatic lowering ofcosts as the company increased insize. Prices for electricitydropped from around 25 centsper kWh in the early 1890s toapproximately 10 cents per kWhin the early 1900s. Those compa-

nies that were owned by men with available money bought out their neighbors that neededmoney; so started the first big merger consolidation of the electric utilities. After 20 years of thissort of consolidation, these companies still were local in scope, small in size, and run by folkswith technical backgrounds.

It wasn’t until the 1920s that many of the larger of the electric companies, from Texas toNorth Dakota to Maine, were brought together under the umbrella of one holding company,Middle West Utilities. State regulation, starting as early as 1907 in Wisconsin and New York,with 43 states having regulatory bodies by 1914, only controlled the operating companies, notthe holding companies. The financial chicanery that allowed this holding company to expand,and rapidly develop the infrastructure needed to supply electricity to an eager market, caused its

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The History and CurrentState of Power Distributionin the United StatesEncompasses a WideRange of Developments

complete collapse after the stock market crash in 1929 andthe major bank failures of 1931–1932. Federal legislation, thePublic Utilities Holding Company Act of 1935, was enactedto break up the holding companies. This set the stage for thereturn of many smaller electric companies, regulated by theindividual states that maintained their own design standards,operating procedures, and standards of service. This inde-pendence of thought, design, operation, and regulation led toa myriad of different ways to deliver electricity to customers.

Another factor must be considered to fully understand thereason for the types of distribution systems used in the UnitedStates; that is, the country is a vast land with private owner-ship of property embedded within the psyche of the popula-tion. Rather than the characteristic densely populated villagesseen throughout much of the world, people in the UnitedStates spread out, created suburbs, and the electric distribu-tion systems followed suit. Long radial systems, with heavywire main lines and smaller wire branches, spread out fromsubstations in the pattern of a two-dimensional tree. It is notuncommon to have 50 km (30 miles) of distribution line fromthe substation to the furthest customer, with a total of 320 km(200 miles) of primary line on one distribution circuit. Withcustomers located 100 meters, or more, from each other,smaller, single-phase distribution step-down transformers,serving one to four customers, are placed on every pole.

While people in and around towns and cities lived at adensity that allowed companies to economically provide elec-tric service to them, farms were located at such distancesfrom each other that they seldom shared in the benefits ofelectrification. It wasn’t until 1936 that the federal govern-ment stepped in and passed the Rural Electrification Act(REA). This provided low cost capital financing and techni-cal assistance to customer-run co-operatives that built distri-bution infrastructure to rural areas. Along with the low-costfinancing came requirements to build to specific standards.These materials and construction requirements, applied todistribution systems constructed across the country, led toadditional economies; from the manufacture of line equip-ment to construction and operating methods. Investor-ownedutilities also benefited from this, often accepting the stan-dards developed for the REA utilities.

Voltage DevelopmentWhile a majority of the distribution systems in the UnitedStates are presently operated within the 15-kV class of volt-ages, this was not always so, and many other voltages are still

utilized throughout the country. Again, to appreciate the pres-ent, one needs to understand the past and the evolution of thosefirst systems to what is now used. Once electric companies gotbeyond Edison’s direct current delivery system, and its inherentlimitations of delivery distance due to the need to operate at theutilization voltage, a higher alternating current primary deliv-ery voltage and phase configuration had to be chosen. Teslarecommended early on the efficiency and enhanced operationalcharacteristics of three-phase delivery systems, and thatbecame the standard. The voltage to use for the delivery sys-tem, however, has seen many evolutionary steps.

Ever mindful of the economies in construction required tokeep the costs to the customers as low as possible, a voltageof 2,400-V phase-phase delta, requiring the minimum ofthree conductors, was chosen early on by many systems. Asload grew and the need for either larger conductors or a high-er operating voltage became necessary, the conversion of2,400-V delta systems to 2.4/4.16-kV grounded-wye systemsoccurred. This type of conversion allowed the amount ofpower transported over the existing conductors to beincreased by a factor of three as well as the use of the existingstep-down transformers by connecting them phase-groundinstead of phase-phase.

Other companies also facing growth in a local area, butwanting to retain the perceived benefits of a delta system,accepted a slightly more costly upgrade by doubling the volt-age to 4,800-V delta, or in those areas with rapid growth,tripling the lower voltage to 7,200-V delta. Converting to 7.2kV resulted in a nine-fold increase in the capacity of theexisting conductors but did require the replacement of allstep-down transformers. As the loads and load densitiesincreased further, the need for more capacity on the distribu-tion lines saw the conversion from 7,200-V delta to7.2/12.47-kV grounded-wye, another tripling of the linecapacity. It should be noted that many of the 2.4/4.16-kV sys-tems have also been converted to 7.2/12.47-kV as the loadson those systems increased. Two paths were taken to reachthe same destination, each appropriate according to their eco-nomic factors driven by the load growth.

Other voltages derived from these systems were frequent-ly used for distribution systems. For most of the regulatedhistory of electric utilities, the voltages used in the distribu-tion delivery systems were allowed to vary within definedlimits, mostly plus or minus 5%. As systems operated con-stantly at the upper 5% limit, these limits became the newnominal operating level. Therefore, 7.2/12.47-kV systems

26 IEEE power & energy magazine july/august 2007

The efforts of U.S. President Lyndon Baines Johnson’s wife, LadybirdJohnson, to beautify the country in the mid to late 1960s led to amovement to place all “ugly” utility infrastructure underground.

became 7.6/13.2-kV systems, which then evolved to 7.9/13.8-kV systems. In addition, the 7.2/12.47-kV system was dou-bled to provide the 14.4/25-kV system often used by theaforementioned REA delivery systems serving remote,sparsely populated areas.

The desire for even higher distribution primary deliveryvoltages required an evolution of the transmission voltagesused in the early years of electric system development. The 11-kV delta lines were upgraded, again by a factor of three, to 33kV. As these were consistently operated at a 5% operatinglevel, to reduce losses and offset voltage drop on the lines, a

new nominal level of 34.5 kV was established. In 1957, Vir-ginia Electric Power Company (VEPCo) added a multiground-ed neutral to create the first 19.9/34.5-kV distribution line.

Distribution SystemsAs noted above, distribution circuits in the United States aremost often radial in design; a dendrite-structured deliverysystem with a single source and no switch device linking thatcircuit with another (see Figure 1). The basic protectivescheme involves a reclosing protective device installed at thesource and often at each main, a three-phase branch of the

figure 1. A typical distribution system (from Power Distribution Engineering by James J. Burke, Marcel Dekker, Inc. 1994).

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circuit; fuses at each single-phase tap point; and either com-pletely self-protected customer service transformers, withinternal high side fuses, or fused cutouts protecting the trans-formers. The voltage profile is maintained over what could beas many as 50 km (30 miles) of line from the source to thefurthest customer by the application of line regulators orshunt capacitors, or in some instances both. The wire size ofthe main line from the substation can be as large as 750-kcmil aluminum, while at the ends of remote, rural, single-phase taps, No. 6 copper weld still exists on many systems.The wire sizes used vary dramatically from utility to utility,based on the specific economic conditions at the time thewire was installed, the load growth occurring within the sys-tem, and the load density of the area served. Copper was thematerial of choice for line conductors up until the SecondWorld War. The needs of the war effort made copper for thispurpose unavailable. Utilities were known to install steelwires during this time, and the acceptance of other materials,mainly aluminum, became ingrained in the design of distribu-tion circuits.

When a failure occurs on the radial circuit describedabove, action must be taken by the utility employees torestore power to the customers. In most cases this does nothappen automatically, thereby leaving customers withoutpower for a period of time.

In densely populated, high load areas, usually within largercities with limited ability to safely construct an overhead dis-tribution circuit, utilities have installed secondary networks.These consist of multiple distribution voltage-level feeders,each serving a number of underground transformers installedin vaults, with the low-voltage, most often 120/208-V, second-aries of the transformers interconnected, and customers servedfrom these interconnected secondaries. This system provides avery high degree of reliability to the service provided to thecustomers, as a number of components can be out of service atany one time. Network protectors are installed at the trans-former locations, and due to the high short-circuit currentsavailable with the multiple, parallel connected transformers,current limiters are often installed in the secondaries. Thehigher cost of this construction has limited its initial installa-tion, and now its expansion, to those areas that absolutely can-not serve an area in any other manner.

Another type of distribution circuit construction commonto the North American utilities is underground residentialdevelopment (URD). The efforts of U.S. President LyndonBaines Johnson’s wife, Ladybird Johnson, to beautify thecountry in the mid to late 1960s led to a movement to placeall “ugly” utility infrastructure underground. Many cities andtowns mandated that all new residential developments beserved with utilities place below ground. Initially, the lineswere installed in a manner mimicking the design of the over-head systems they replaced: radial single-phase lines servingsubmersible or pad-mounted transformers. The failure ratesexperienced with the high molecular weight polyethylenecables installed in the 1960s and early 1970s encouraged the

distribution engineers to move to a looped circuit design forURD, a concept utilized most often today.

Impact of Reregulation on ReliabilityEach of the 50 states has a single regulatory body that sets therequirements the utilities in that state must meet. As post-reregulation regulatory purview shifts from generation todistribution, regulators have become increasingly concernedwith the delivery of safe, reliable electricity to all customersat a reasonable cost. Each state has the right to mandate dis-tribution reliability standards and targets. In fact, some stateshave no reliability regulation at all, while others have veryprescriptive rules that even mandate how often their systemsmust be inspected, and they impose large penalties for per-formance failures. Today, regulators may participate in theNational Association of Regulatory Utility Commissioners(NARUC) where they can share ideas, but there is no require-ment to adopt the same approach on any issue, thus makingpotentially 50 different sets of regulations throughout theUnited States.

Regulators have many concerns in this post-reregulationperiod. One concern is that parent/holding companies, oftenwith headquarters outside the state the operating companyserves, are siphoning off profits that could be reinvested in theelectric delivery systems to improve reliability. They want toensure that reliability performance does not degrade and, insome cases, they are asking for improvements in the servicethat customers receive. Unfortunately, it appears that reliabili-ty performance is worsening across the nation (see “Reliabili-ty of the System” below). While this may be a true indicationof the utilities’ reliability performance, it also may largely be afunction of the utilities changing information systems andassociated processes and not a decrease in the underlying cus-tomer service performance. Individual utilities have seen theirreliability metrics increase by 15 to 125% after implementa-tion of automated outage reporting systems.

Shifting from the cost of service (COS) model for ratemaking, utilized for as long as regulation has been in exis-tence, to long-term rate plans that include cost-sharingmechanisms between utilities and customers has certainlyled to a different infrastructure investment pattern for utili-ties. Emphasis has been placed on finding efficiencies with-in the long-established system development paradigms.Asset management techniques are used to focus mainte-nance and replacement efforts on just those items that needimmediate attention.

The average age of electric delivery systems is increas-ing, as should be expected due to technological advances,but some are aging faster than the average due to utilitiesasking more of their installed investment and the lack ofnew or replacement investment. The traditional approach,not replacing any item of the installed infrastructure untilthe failure rate of any particular device becomes excessive,referred to as “run to failure,” may not work in the coming


july/august 2007 IEEE power & energy magazine

years. While increased maintenance spending can over-come the adverse impact of increasing average age, theneed to cut costs to meet profit requirements under thereregulation model has kept many companies from doingall that is needed. Those systems that have been properlymaintained will have fewer problems, as one would expect.That said, by the time most assets reach 70 to 80 years ofage, they should be retired, but current regulatory plans arenot necessarily structured to handle a mass removal andreplacement of assets.

All of these and many other issues are causing regulatorsto implement new performance-based rate plans that try tomitigate their concerns. These plans often include servicequality targets with penalties for failure to perform. In a fewcases, there are offsets and/or incentives for good perform-ance. Service quality targets are often comprised of:

✔ reliability metrics (see below for definitions of SAIFI,SAIDI, CAIDI)

✔ number of meters read on cycle✔ time to answer customer phone calls✔ complaints to regulators✔ lost time incidents (safety metric)✔ service appointments met.

Reliability of the SystemReliability of the distribution system isdescribed in terms of unreliability, oftenusing metrics to describe the experience ofthe average customer. For example, theSystem Average Interruption FrequencyIndex (SAIFI) is used to describe the annu-al frequency of power interruptions to theaverage customer. The System AverageInterruption Duration Index (SAIDI) isused to describe the annual duration ofpower interruptions to the average cus-tomer. Reliability is also described by theexperience of those customers who haveexperienced an interruption in service. Theduration metric is the Customer AverageInterruption Duration Index (CAIDI).Unlike financials, when reliability indicesrise, the performance is deteriorating.

These metrics are engineering-basedaverages that track frequency and durationof customer interruptions. These indicesare applied on system, circuit, and cus-tomer levels for planning and regulatoryreporting purposes. While these metricsprovide a reasonable method for utilities toplan their operations, they lack a connec-tion with customer satisfaction. Consistentcustomer satisfaction data are often diffi-cult to obtain, and when it is available, itmust be considered at a different confi-

dence level than accounting or reliability data, thereby mak-ing it difficult to use for utility decision-making purposes.Recently, utilities are beginning to be able to use their sys-tems to track customer-level interruption experience. It islikely that within the next 10 years the industry will movefrom averages to customer-based metrics. Figure 2 showsone example of how customer experience can be viewed withthe integration of different software systems.

Because all 50 U.S. states have developed different relia-bility reporting requirements, it is almost impossible tocompare reliability performance across the nation basedupon reported indices. To illustrate the issue, consider threestates’ rules to identify major storm events, where customerinterruptions are not included in the calculation of reliabilitymetrics. State A uses a threshold of 15% of the customersserved in a utility’s service territory being interrupted atsome time during the storm. For this state, the number of

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figure 2. Customer-based view.

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customers impacted before a major storm is declared rangesfrom 6,000 for a small utility to about 180,000 for a utilityserving over a million customers. State B uses a thresholdof 10% of the customers served in a division of the compa-ny being interrupted. For this state, the number of customersimpacted before a major storm is declared ranges from10,000 to 40,000. State C uses a threshold of 10% of thecustomers interrupted in a division, or any customer out ofservice for 24 hours or more. In this state, only one cus-tomer has to be without service for more than 24 hours forthe event to be declared a major storm and be excludedfrom the calculated metrics. The IEEE Working Group onDistribution Reliability developed a standard to help nor-

malize the performance information regardless of statereporting rules. The standard was approved in June 2004and since then a number of states have adopted theapproach, as can be seen in Figure 3. As dockets open, it isprobable that more states will consider adopting theapproach outlined in IEEE Std. 1366–2003.

An annual reliability benchmark effort is performed bythe IEEE Working Group on Distribution Reliability, usingthe approach defined in IEEE Std. 1366–2003. This bench-mark has shown that reliability appears to be worseningacross the nation, as shown in Figure 4. The 58 utilities sur-veyed that provided consistent information for five yearsserve over 54 million customers collectively.


figure 3. States using the IEEE-1366 standard.

States Using IEEE-1366 Guidelines for Distribution Reliability

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Rather than the characteristic densely populated villages seenthroughout much of the world, people in the United States spread out,created suburbs, and the electric distribution systems followed suit.

It appears that several factors may be influencing this shiftto poorer recorded performance. The weather patterns acrossNorth America have been more severe in recent years due toEl Niño and La Niña bringing intense rain to some areas anddrought to others (http://www.ncdc.noaa.gov/oa/climate/globalwarming.html#Q7, http://www.elnino.noaa.gov/).

Another key factor is the change in the way utilities col-lect interruption information. Outage management systems(OMS) have evolved from paper-based systems to advancedIS systems that are tightly integrated with geographical infor-mation systems (GIS) and customer information systems(CIS), thereby enabling utilities to very accurately record andreport reliability performance.

Paper-based systems were used to assist utility operationswith restoring power to interrupted customers as quickly aspossible. During both major and minor storm scenarios, paperforms would be filled out, sorted, and given to crews forrestoration. In many cases this information was not enteredinto the recording system after the fact, because customerswere restored and there was no need to keep the information.Another important fact about paper-based systems was thatinformation about how many customers were connected to aparticular part of the system was unknown. Instead of havingan exact figure, line personnel were asked to estimate, using abest-guess method, the number of customers impacted by anoutage. This method was inaccurate.

The new, state-of-the-art systems use afully connected GIS model, so that thenumber of customers affected is knowneach time an outage occurs. There is nopaper forms associated with the system;hence, it is unlikely that information is lostin the process. In the very large storms(hundreds of thousands of customers out ofservice), it is possible that some informa-tion is still lost because some of the systemscan be overwhelmed with information, but,for the majority of conditions, all interrup-tions are tracked.

During this evolutionary process ofchanging from simple to sophisticated datagathering methods, it is imperative to recog-nize that changing the system used toprocess customer interruption data will havea significant impact on the reported systemperformance. Better measurement techniques

often result in the appearance of worsening performancebecause more data and more accurate data are being recorded.

Future TechnologyLine workers of the 1930s might be impressed by the tools,personal protection equipment, and multifunctional vehi-cles now in use on the electric utility systems, but theywould have to take very little time to familiarize them-selves with the actual delivery infrastructure today. Distrib-ution system design has not seen many truly momentouschanges over the years. However, there are a few new tech-nologies on the horizon.

It is expected that utilities will employ true distributionautomation, as the cost of this technology decreases, toallow for sectionalizing of the circuits, switching loads toalternate sources, and even optimizing line loadings tominimize losses and voltage problems. Motor-operatedswitches, or reclosers, will be installed on feeders such thatthere is one or more normally open devices in placebetween adjacent feeders, along with multiple normallyclosed switches used to segment the feeder. Normallyclosed switches will automatically open when a fault isdetected, or operating limits are reached, isolating theproblem area. Normally open switches will close to restoreservice to as many customers as possible. The switches will

figure 4. National reliability performance.

Trends for Utilities Providing Data Between 2000-2005IEEE Benchmarking Survey(58 North American Utilities)

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There is no requirement to adopt the same approach on any issue, thus making potentially 50 different sets of regulationsthroughout the United States.

communicate with each other and, using preset conditions,or even artificial intelligence, will operate without humanintervention.

Communicating over a utility’s overhead wires is not anew concept. System protection engineers have used the con-ductors of transmission lines to send signals to coordinate thefast operation of relays at each end of the line. A number ofsystems were introduced in the 1970s to use the wires of thedistribution circuits to communicate with end devices at cus-tomer premises. Meter reading, gathering data for load sur-veys, direct customer load control, and even control of lineswitches, reclosers, capacitors, or any other function thatcould be accomplished at a low baud rate was achieved. Now,high speed communication is being accomplished acrosselectric distribution lines. The potential for monitoring, con-trolling, and operating distribution circuits to optimize lineloading, voltage profile, power factor, losses, and reliability isnearly unlimited.

While many in the industry think of distributed genera-tion as a new phenomenon, it was federal legislation,passed after the oil embargo of 1974, that initiated andencouraged the construction of small, nonoil-based gener-ators, many of which were installed on distribution cir-cuits. Distribution engineers, entrenched in theirfamiliarity with radial circuits, the electricity always flow-ing from a single source out to the customers, did notembrace the introduction of generators, of any size, intotheir domain. Now, more than 30 years later, utilities areconsidering installing distributed generation on their dis-tribution circuits to reduce the need for expensive infra-structure additions, to improve the efficiency of theoperation of their distribution circuits, and even toimprove their customers’ service quality.

Distributed generation, communicating with and control-ling customer equipment, circuit devices operating on theirown “intelligence,” and instantaneous data availability forany device or operating condition will change our distribu-tion systems, and the way we run them, in ways that canonly be imagined. The times are changing, and excitingtimes they are.

For Further ReadingJ.J. Burke, Power Distribution Engineering. New York: Mar-cel Dekker, 1994.

C.E. Neil, “Entering the seveth decade of electrical power —Some highlights in the history of electrical development,” Edi-

son Electric Inst. Bull., Sept. 1942 [Online]. Available: http://www.eei.org/industry_issues/industry_overview_and_statistics/history/Engineering7thDecade.pdf

“The changing structure of the electric power industry: Anupdate,” DOE/EIA-0562(96), Distribution Category UC-950,Appendix A, Dec. 1996 [Online]. Available: http://www.eia.doe.gov/cneaf/electricity/page/electric_kid/append_a.html

T.A. Short, Electric Power Distribution Equipment andSystems. Boca Raton, FL: CRC, 2005.

BiographiesJames D. Bouford received a B.S. in electrical engineeringfrom the University of Maine and an M.S. in managementfrom Thomas College. Bouford worked for Central MainePower from 1968 to 1999 where he held numerous positions.Today, he is the vice president of engineering for National GridUSA Service Company, Inc., based in Northborough, Massa-chusetts. He is the recipient of two EPRI Innovator Awards(1992 and 1993). He also chaired the EPRI Distribution TaskForce (1991 to 1993) and the EPRI Custom Power DistributionTask Force (1993). Bouford has authored and co-authored sev-eral technical papers, spoken at several conferences, andchaired a national conference on optimizing distribution relia-bility. He is an active Senior Member of the IEEE, where hehas chaired the Task Force on Reliable Distribution Design, isthe vice-chair of the Working Group on Voltages at Publiclyand Privately Available Locations, and is a member of theWorking Group on System Design. He is a principal author ofthe “Major Event” definition for IEEE Std. 1366.

Cheryl A. Warren received her B.Sc. in electrical engi-neering and M.Sc. in engineering from Union College inSchenectady, New York. She has been employed by CentralHudson Gas and Electric Company in Poughkeepsie, NewYork; Power Technologies, Inc./Stone and Webster in Sch-enectady, New York; and Navigant Consulting, Inc., inAlbany, New York. She now works for National Grid, basedin Albany, as the director of Asset Strategy and Perfor-mance. Her main areas of expertise are distribution reliabili-ty analysis, power quality; GIS/OMS, and enterprise-wideIT systems integration. Warren has authored and co-authored 29 technical papers. She chairs the IEEE WorkingGroup on Reliability that wrote the Guide on Electric PowerDistribution Reliability Indices (IEEE Std. 1366-2003). Sheis also chair of the IEEE PES Distribution Subcommittee. InJune 2007 she received the IEEE PES Excellence in PowerDistribution Engineering Award.


By the time most assets reach 70 to 80 years of age, they should be retired, but current regulatory plans are not necessarily structuredto handle a mass removal and replacement of assets.

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Many states of distribution