Introductory paper for a 2012 NARUC-EEI sponsored discussion series on the evolution of the US electric distribution system.

1. 1
CURRENT STATE OF U.S. ELECTRIC DISTRIBUTION
Edison Electric Institute
Prepared by Paul De Martini
Introduction
This paper is the first in a series that summarize the historical and future evolution of the US electric
distribution system to reliably and securely meet changing customer needs and current energy policy
objectives in support of an ongoing dialog among regulators, policy makers and utilities regarding the
future of electric distribution. Specifically, this paper provides a foundational overview of the current
state of U.S. electric distribution systems. This overview includes a brief history of electricity distribution
and highlights physical design elements and variations leading to the current state. Challenges regarding
infrastructure aging, reliability, cyber security and investment, drawing on recent industry and academic
work are also discussed. A list of recommended articles, reports and books on topics in this paper is
included for further reading. Also, a glossary of terms used in this paper and related webinar is available
at the end of the paper.
Electric Distribution System Evolution
1880-1945
In 1882, Edison not only built Pearl Street Station, but also a
complete distribution system, including underground cables,
electric meters, wiring, fuses, switches, and sockets. This first
distribution system initially served 85 customers’ lights.
Electrification of lighting, manufacturing production,
transportation grew quickly over the next 30 years becoming
widely available in large cities. During this period Edison’s initial
direct current (DC) systems evolved to adopt the Westinghouse
approach that used alternating current (AC). The latter was
more practical because it allowed the use of transformers to
change between lower voltages at the generator and consumer ends to higher voltages for longer-
distance transmission, which is far more efficient because it reduces the required electric current and
associated losses. By the 1930s, reliable power was the predominant energy source for business and
industry and becoming available to rural America. Early distribution systems used a primary voltage of
2.2 kilovolt (kV) AC. During the 1920s-1940s, most of the 2kV systems were upgraded to 4kV, three-
phase systems.
1946-1975
The post-WWII period through the 1960s saw dramatic housing growth and rise of suburban
developments with a corresponding growth in subtransmission and distribution systems in the US and
most of the developed world. The systems expanded on the earlier model of central generation with
Source: Kansas Historical Society

2. 2
interconnected and redundant transmission lines linking to
distribution substations serving local customer loads via radial
overhead and underground distribution circuits. Radial circuits are
one-directional, branching out like tree limbs, with only one path
from source to customer – in contrast to networked transmission
systems, which feature redundant paths and loops. Distribution
feeders emanating from a substation are generally controlled by a
circuit breaker which will open when a fault is detected.
Subtransmission systems commonly used voltages of 60/69 kV and
115/121kV. Distribution systems built early in this period continued employing 4kV primary voltages and
later used 11/12kV to accommodate the increases in customer electric loads in new suburban
developments (since more power can be transferred at higher
voltage without increasing current, the key limitation on electrical
capacity). Customers receive delivery service via secondary voltages
commonly between 208-480VAC provided by pole mounted, pad
mounted or underground transformers. Long feeders experience
voltage drop requiring capacitors or voltage regulators to be
installed along the line to maintain the voltage within an acceptable
range. The older areas of a city or industrial area typically had
distribution systems/components dating to the 1920s or earlier.
Distribution substation and feeder protection and control systems in use were analog based electro-
mechanical systems. Most large distribution substations were manned around the clock every day.
1975-2000
Utilities increasingly focused on reliability improvement through
feeder design improvements, vegetation control and use of
underground conductor to reduce the number of interruptions.
Utilities also leveraged rapid advances in computing power during
the twenty five-year period from the mid-70s to 2000 that facilitated
the development of substation automation, introduction of digital
protective relays, distribution automation and automated meter
reading. Starting in the 1970s, digital controls and automation
systems began to be deployed in distribution substations. These
original substation automation systems were based on second
generation digital Supervisory Control and Data Acquisition (SCADA)
technology that relied on distributed controls connected via first
generation local area networks (LAN) using proprietary protocols
and communications. One driver for substation automation was the
implementation of remedial action schemes to automate load
shedding, in order to mitigate the potential for regional outages like
that seen in the 1967 New York blackout. A side benefit of this
SCADA System Operator Screen
Source: A. von Meier
1980-2000 Distribution Operations Center
Source: A. von Meier
Source: Chad Baker/Getty Images
Source: JupiterImages

3. 3
automation was the reduction in operating personnel and increasing productivity.
During this period higher primary distribution voltages, 21kV and 35kV became common for new
development to cost-effectively and reliably serve population and business load growth. Automatic
circuit reclosers began to be installed to further segregate the feeder, thus minimizing the impact of
faults. The idea is to minimize the number of customers whose service needs to be interrupted in order
to safely isolate a fault or perform repairs, and to avoid lengthy interruptions if a fault clears quickly on
its own. Further advancements led to initial deployment of distributed field control systems to remotely
status and operate circuit sectionalizing switches and capacitor banks, for the purpose of improving
service restoration and reliability. Additionally, the proliferation beginning in the 1980s of electronic
and micro-processor control loads, with a greater sensitivity
to interruptions, led to efforts to reduce momentary outages,
as well as focus on power quality characteristics such as
harmonic distortion. Studies and actual implementation
experience have shown, however, that distribution
automation can also provide additional reliability
improvements, especially in outage duration and frequency.
Some of the most beneficial applications are substation
automation, equipment condition monitoring, feeder
automation and intelligent load restoration schemes.
Customer adoption of distributed generation effectively began in the 1980s with qualifying co-
generation facilities leveraging waste heat for industrial processes and commercial heating and cooling
systems1
. This expanded in the 1990s with onsite natural gas fired generators including reciprocating
engines and turbines. Over the same period, utility reliability-based demand response programs
including load control and interruptible incentive rate programs came into use. Onsite generation and
demand response during this time had little impact on grid operations as they were either directly
controlled by the utility or had very predictable operations.
Current State of Distribution
Today’s electric distribution system in the US is the result of 100 years of organic population and
economic growth combined with the evolution in electric power delivery technology, control system
technology and information and telecommunication technology. This means many utilities have a mix of
primary distribution voltages such as 4/12/21/35kV and related substation and feeder apparatus and
control technologies installed over a 60 plus year period.
Over the past decade, the customer load characteristics have changed with customer adoption of
energy efficient building systems and devices, onsite generation and technologies enabling responsive
demand. Building code and appliance standards for zero net energy and efficiency will accelerate these
changes over the next two decades. Fuel cells and solar photovoltaic (PV) systems reached commercial
viability in the late 2000s and PV adoption, in particular, has recently grown dramatically due to sharply
1
United States Congress, Public Utility Regulatory Policies Act (PURPA), 1978
Source: LBNL

4. 4
lower prices and favorable commercial terms. PV prices have reached retail price parity in a significant
number of US states2
. Additionally, a large number of larger merchant PV systems are being connected
to distribution networks. Likewise smaller scale and customer owned micro wind generators are being
interconnected to distribution. The results are increasing variability of customer net load and
interconnected intermittent generation and, in a few cases, reverse power flows on the distribution
system.
These create unique challenges as the distribution system deployed over the past 60 years was
principally designed for one way power flow from central generating plant to customer loads. The
predominately radial circuit configurations are designed to meet a maximum aggregate customer load
over their length. This is why radial distribution circuits often have decreasing wire sizes the farther from
the substation and fewer customers connected toward the end of a circuit. Distribution engineering
considerations have increased as a result in the changing use of the system. Not only do distribution
engineers need to consider the traditional factors, but increasingly a new set of factors are required as
highlighted below:
Traditional distribution engineering focused on the aggregate feeder, substation transformer and
substation loading characteristics based on forecasts of customer loads. These forecast typically applied
representative load profiles for different customer types within residential, small commercial, large
commercial and industrial classes. These pre-determined loads were then analyzed to ensure that the
transformers, wires and cables and related apparatus were sized appropriately for maximum load
conditions over the engineering planning horizon. The analysis includes assessing anticipated voltage
levels, loading of the individual conductors to maintain certain balance across a feeder’s three phases as
well as the potential fault current (short circuit current) under worst case to ensure the substation and
other protective equipment could perform safely. Individual customer’s load characteristics are also
assessed in terms of load factor and power factor if material to circuit design and operation. The
modeling used for these analysis use static loading and operational data under a few peak load
scenarios. Collectively, the approach described above is called “deterministic” analysis.
Today as a result of variable generation, responsive load, electric vehicles and energy storage
distribution planning and operations require analysis of a range of scenarios using dynamic data that are
beyond the capability of traditional deterministic planning models. There are also a number of
additional engineering considerations that need to be assessed. For example, some distributed
2
Platt’s, David Crane, NRG CEO interview, November, 2011’s interview
Traditional Additional Factors Today
Voltage levels Voltage Stability
Phase balance Minimum load for DG
Maximum demand Net load/supply variability
Load factor Load & DG Harmonics
Power Factor System Transients
Short Circuit Current Protection coordination
Deterministic Modeling Stochastic Modeling
Distribution Engineering Factors

5. 5
resources can introduce problematic higher frequencies, called harmonics, into the distribution system
that can create power quality issues. The second-to-second power output from solar PV, and/or
coincident load drop or turn on3
can introduce transients on distribution that can also negatively affect
power quality and in some cases reliability. Distributed generation and other sources of power supply,
like storage, can create bi-directional power flows that can affect the protection scheme in a variety of
ways. In simple terms, the protection systems were designed to see power in a particular direction –
distributed generation can confuse these systems by flowing power from an opposite or alternative
direction. This can lead to unsafe conditions that can lead to catastrophic failure of equipment and
worse cases private property or human casualty. The complexity and dynamism of these scenarios
require more complex modeling methods to assess the variable (or stochastic) behavior of the
interaction of these devices, loads and power flows on the distribution system and in some cases the
impact on related transmission systems.
Grid modernization policy and efforts (including the “smart grid”) over the past decade have focused on
increasing reliability, efficiency and resilience of electric
grid as well as enabling greater customer participation in
markets and integration of variable renewable generation
and distributed energy resources (responsive load,
distributed generation and energy storage).
Advancements in energy technologies in distribution
systems and apparatus combined with application of
modern information and telecommunication systems
promise to enable Federal and states’ policy objectives4
.
For example, the Institute for Energy Efficiency projects that more than half the households in the
country will have a smart meter by in 20155
. Also, many utilities are also implementing advanced
distribution outage management and automation systems to further improve system reliability and
restoration capability. These programs are the first mass deployment of modern technology on the US
electric distribution system since the post-war period. However, integration of modern information and
telecommunications with distribution control systems and field devices, like switches and meters,
creates several challenges. First, many of these new systems need to interface with each other to
function and achieve operational benefits. Historically, grid systems/devices were largely proprietary
systems unlike modern information systems that are based on open architectures and interoperable
standards. New system/device deployments are attempting to integrate open interoperable systems
with legacy proprietary systems. Unfortunately, this can lead to very expensive system integration costs
– as much as 3-5 times the cost of the underlying new software application. Second, these systems had
very few security features and since many distribution systems/devices were not interconnected they
did not account for cyber security sufficiently. These issues are highlighted by Digital Bond’s Project
Basecamp effort focused on SCADA systems. This is especially true given the current threat levels
3
Roozbehani, et al., Volatility of Power Grids under Real-Time Pricing, MIT, June 2011.
4
United States Congress, 2007 Energy Independence & Security Act, Title XIII – Smart Grid, Section 1301 - Statement of Policy
on Modernization of Electricity Grid.”
5
Institute for Electric Efficiency (IEE), Utility Scale Smart Meter Deployments Plans, & Proposals, May 2012
SDG&E Distribution Operation Center

6. 6
addressed in the National Institute of Standards and Technology (NIST) guidelines6
. Also, it is important
to keep in mind that about 97% of the US electric grid, in terms of total circuit miles, is not covered by
the North American Electricity Reliability Corporation (NERC) Critical Infrastructure Protection
requirements or other similar cyber security imperatives.
Distribution Investment & Reliability
The US electric distribution system serves over 144 million customers through about 6 million miles of
overhead lines and underground cables7
over an estimated 500,000 circuits originating from 60,000
distribution substations.8
A considerable amount of this massive critical infrastructure is or approaching
the end of its expected life. The Brattle Group, in 20089
, estimated that distribution infrastructure
investment in the US could reach $675 billion through 2030. The American Society of Civil Engineers
(ASCE) gave the US electric infrastructure a grade of D+ in 2009 and recently identified an investment
gap of $ 57 billion of through 202010
. The US is not
alone as most OECD countries are facing similar
challenges. The UK graph below illustrates the
distribution investment post-war and current
replacement need if done on a similar pace and scale.
In their 2012 report on grid reliability, Lawrence
Berkeley National Lab found that Investor Owned
Utilities reported average duration and average
frequency of power interruptions has been increasing
over the past 10 years at a rate of approximately 2%
annually. However, they have not yet determined the
cause of this statistically significant trend or reconcile
the increase in both average and frequency of outages
with reported utility investments in outage
management systems and other grid modernization
technology.
6
NISTIR 7628, Guidelines for Smart Grid Cyber Security
7
National Rural Electric Co-op Association estimate
8
Energy Information Administration, Electric Power Annual 2010, Nov. 2011
9
The Brattle Group. “Transforming America’s Power Industry”, 2008
10
ASCE, Failure to Act; The economic impact of current Investment Trends in Electricity Infrastructure, 2012
30%
21%
49%
U.S. Distribution Equipment Age
Beyond Expected Life
Near Expected Life
Within Expected Life
Source: Black & Veatch 2008 Electric Utility Survey
Source: Scottish Power

7. 7
While LBNL has not yet identified the causes, utilities and
equipment manufacturers globally understand the
engineering principles related to physical equipment and
systems end of life failures. Several academic and industry
studies over the past twenty years suggest that continued
aging of the infrastructure will lead to an increase (from an
average of about 33%) in service interruptions from
equipment failures. This is considered especially true where
devices are increasingly abnormally stressed toward end of
life. Also, equipment failure rates curves have a “hockey
stick” characteristic that suggests that the LBNL observations may be a prelude a tipping point in which
reliability may begin to seriously deteriorate if distribution investment doesn’t materially alter the
average age of the system and its components over this decade. Specifically, Southern California Edison
argued in their 2009 General Rate Case testimony11
that: “The likelihood that a given component will fail
is a function of its age. …the component’s probability of failure will remain low for a long period of time.
Then, at some point in its life, the component’s probability of failure begins to increase dramatically. …as
the average age of the population approaches its mean-time-to-failure, the volume of components
wearing out and needing replacement will increase significantly. … As long as the average age of a
population continues to increase, the number of components wearing out and needing to be replaced
each year will also increase.” (This effect is illustrated in the “Time-Dependent Failure Rate” curve above
from SCE’s filing)
Additionally, the investments described earlier are needed to modernize the grid under the classic
central generation and one-way flow to customer model. However, they do not fully address the
increased challenges of broad customer adoption of variable distributed energy resources that also
create bi-directional flow on the grid.
Key takeaways
Today’s electric distribution system is a compilation of 100 years of advancements in electric power
engineering, electrical apparatus, control systems, and information and telecommunications driven by
the organic population and economic growth over this period. Specifically, distribution systems have
grown in five respects:
1. Age and Diversity of voltages and operational systems (mix of 60 plus years’ technology)
2. Speed and Precision of operation (fault isolation, sectionalizing, service restoration)
3. Convergence of energy and information technologies (integration and interoperability
challenges)
4. Exposure to cyber security threats (given greater use of information systems and connectivity)
5. Complexity of the system (given variable and distributed energy resources)
11
Southern California Edison, 2012 General Rate Case T&D Policy testimony regarding relationship between aging
infrastructure and reliability and the large-scale replacement challenges.

8. 8
Current adoption trends of distributed energy resources look to fundamentally transform distribution in
two respects; reverse power flow is possible, and demand can respond to system conditions. However,
the basic engineering design and control logic has essentially remained the same for 100 years. This will
require fundamental re-thinking of how we design and operate. As such, over the next two decades
many utilities will need to adapt their distribution systems to new engineering paradigms and
infrastructure to enable new uses for electric distribution networks. A key factor for utilities and
regulators will be the cost of replacing aging infrastructure and incorporating advanced operational
systems to maintain the lowest possible cost to deliver electricity. The next paper in the series will
discuss future trends and related engineering, infrastructure and investment considerations to ensure a
reliable and secure system.
Acknowledgements
The author, Paul De Martini, managing director, Newport Consulting acknowledges the following
individuals who contributed to the development of this paper:
• Alexandra von Meier, Co-Director, California Institute for Energy and Environment
• Jared Green, Project Manager, Electric Power Research Institute

9. 9
Further Reading
von Meier, A. Electric Power Systems: A Conceptual Introduction, John Wiley/IEEE Press, 2006
Sallam, A., Malik, O., Electric Distribution Systems by, IEEE Press Series 2011
Chowdhury, A., Power Distribution System Reliability: Practical Methods and Applications, John Wiley &
Sons, 2009
Hertzog, C., Smart Grid Library, Smart Grid Dictionary 3rd
Edition, 2010
The Brattle Group for Edison Foundation, Transforming America’s Power Industry:
The Investment Challenge 2010-2030, 2008
American Society of Civil Engineers, Failure to Act; The economic impact of current Investment Trends in
Electricity Infrastructure, April, 2012
Eto, Hamachi, LaCommare, Larsen, Todd, and Fisher, An Examination of Temporal Trends in Electricity
Reliability Based on Reports from U.S. Electric Utilities, LBNL, 2012
Black & Veatch, 2011 Strategic Directions in Electric Utility Industry Survey Results, 2012
Galvin Electricity Institute, Electricity Reliability Report, 2011
Galvin Electricity Institute, Electricity Reliability: Problems, Progress and Policy Solutions, 2011
Electric Power Research Institute, Papers & Reports:
 Reliability of Electric Utility Distribution Systems, 2000
 A Utility Standards and Technology Adoption Roadmap
 Distribution Operations Guide to Enterprise Service Bus Suites
 CIM for Distribution Interoperability Testing Preparation
 Benefits of Utilizing Advanced Metering Provided Information Support and Control Capabilities in
Distribution Automation Applications
 Distributed Energy Resources and Management of Future Distribution
 Lemnos Interoperable Security
 Distribution System Cyber Security Architecture
Massachusetts Institute of Technology, The Future of The Electric Grid, 2011
Department of Energy, Grid 2030 - A National Vision for Electricity's Second 100 Years, 2011
Smart Grid Interoperability Panel, Catalogue of Standards, 2012
Gridwise Architecture Council, Decision Maker Checklist v1.0, 2007
EnerSec & nCircle Smart Grid Security Survey:
http://www.ncircle.com/index.php?s=resources_surveys_Survey-SmartGrid-2012
Digital Bond, Project Basecamp: SCADA Vulnerability: http://www.digitalbond.com/tools/basecamp/

10. 10
Glossary of Terms12
Current: The flow of electricity in an electrical conductor, measured in amperes.
Power: The rate at which energy is transferred, used, or transformed. The unit of power is the watt. For
example, the rate at which a light bulb transforms electrical energy into heat and light is measured in
watts—the more wattage, the more power, or equivalently the more electrical energy is used per unit
time.
Voltage: The value of the difference, or voltage, across a conductor when a current of 1 ampere
dissipates 1 watt of power in the conductor. Using a water analogy, the volt is the measure of water
pressure, the amp measures the water’s flow rate (current) and the ohm defines the pipe size,
resistance.
Reactive power: In alternating current circuits energy is stored temporarily in inductive and capacitive
elements, which can result in the periodic reversal of the direction of energy flow. The portion of power
flow remaining after being averaged over a complete AC waveform is the real power, which is energy
that can be used to do work (for example overcome friction in a motor, or heat an element). On the
other hand the portion of power flow that is temporarily stored in the form of electric or magnetic
fields, due to inductive and capacitive network elements, and returned to source is known as the
reactive power. Reactive power flow on the alternating current transmission system is needed to
support the transfer of real power over the network. Energy stored in capacitive or inductive elements
of the network give rise to reactive power flow. Reactive power flow strongly influences the voltage
levels across the network. Voltage levels and reactive power flow must be carefully controlled to allow a
power system to be operated within acceptable limits.
Power factor: The ratio between real power and apparent power in a circuit is called the power factor.
It's a practical measure of the efficiency of a power distribution system. The power factor is one when
the voltage and current are in phase. It is zero when the current leads or lags the voltage by 90 degrees.
Power factors are usually stated as "leading" or "lagging" to show the sign of the phase angle of current
with respect to voltage.
Voltage drop: Voltage drop is the reduction in voltage along a distribution circuit. The simplest way to
reduce voltage drop is to increase the diameter of the conductor between the source and the load
which lowers the overall resistance. The more sophisticated techniques use active elements (load tap
changers, line voltage regulators, capacitor banks and power electronics) to compensate the undesired
voltage drop.
Substation: Substations transform voltage from high to low, or the reverse, or perform any of several
other important functions. Distribution substations transform voltage levels between high transmission
12
Source for definitions: Smart Grid Dictionary 3
rd
Edition and Wikipedia

11. 11
voltages and lower distribution voltages as well as interconnect the distribution system with the
transmission system.
Transformer: A transformer is a device that transfers electrical energy from one circuit to another
through inductively coupled conductors—the transformer's coils. A varying current in the first or
primary winding creates a varying magnetic flux in the transformer's core and thus a varying magnetic
field through the secondary winding.
Circuit breaker: A circuit breaker is an automatically operated electrical switch designed to protect an
electrical circuit from damage caused by overload or short circuit. High-voltage breakers are broadly
classified by the medium used to extinguish the arc; Oil, Air blast, Vacuum, Sulfur Hexafluoride Gas (SF6)
Radial system: A tree structure system with individual circuits branching off a substation transformer.
Each primary (distribution voltage of 4/12/21/35kV) circuit leaves a substation and ends as the
secondary service from a pole or pad mounted transformer (service voltage 480/240/208/120V) enters
the customer's meter socket.
Network system: In very dense city areas, a secondary service network may be formed by connecting
the secondary side of transformers on 2 to 4 primary circuits to a common bus to serve one or more
large customer loads (typically large office buildings and manufacturing facilities). This is done to
increase the reliability of the secondary service as if one or two primary circuits fail, the other circuit/s
will continue to service the customer load.
Conductor: Metal wires, cables and bus-bar used for carrying electric current.
Tap changer: In distribution networks, a substation step-down transformer may have an off-load tap
changer on the primary winding and an on-load tap changer on the secondary winding. The high voltage
tap is set to match long term system profile on the high voltage network and is rarely changed. The low
voltage tap may be requested to change positions once or more each day, without interrupting the
power delivery, to follow loading conditions on the low-voltage network.
Voltage regulator: A voltage regulator is an electricity regulator designed to automatically maintain a
constant voltage level. In an electric power distribution system, voltage regulators may be installed at a
substation or along distribution lines so that all customers receive steady voltage independent of how
much power is drawn from the line.
Capacitor: A capacitor is a passive two-terminal electrical component used to store energy in an electric
field. The forms of practical capacitors vary widely, but all contain at least two electrical conductors
separated by a dielectric (insulator). In electric power distribution, capacitors are used for power factor
correction. Such capacitors often come as three capacitors connected as a three phase load. Usually, the
values of these capacitors are given as reactive power in volt-amperes reactive (VAr). The purpose is to

12. 12
counteract inductive loading from devices like electric motors and transmission lines to make the load
appear to be mostly resistive.
Protection scheme: In order to prevent damage, each station along the network is protected with circuit
breakers or fuses which will turn off power in the event of a short circuit or overload. This presents a
major problem dealing with transient events. For instance, a tree branch that is blown off a tree during a
windstorm and lands on the line may cause a short circuit that could cause damage. However, the fault
will quickly clear itself as the branch falls to the ground. If the only protection system is the circuit
breaker at the distribution substation, large areas of the grid would be blacked out while the repair crew
resets the breakers. Reclosers and sectionalizers address this problem by further dividing up the
network into smaller sections. A recloser, or autorecloser, is a circuit breaker equipped with a
mechanism that can automatically close the breaker after it has been opened due to a fault. Reclosers
are used on overhead distribution systems to detect and interrupt momentary faults. Since many short-
circuits on overhead lines clear themselves, a recloser improves service continuity by automatically
restoring power to the line after a momentary fault. Reclosers may cooperate with down-stream
protective devices called sectionalizers, disconnects equipped with a tripping mechanism triggered by a
counter or a timer. A sectionalizer does not interrupt fault current. It observes fault current and circuit
interruption by the autorecloser. If the autorecloser cycles and the fault persists, the sectionalizer will
open its branch circuit during the open period of the autorecloser, thereby isolating the faulty section of
the circuit. Fuses in distribution circuits are very simple devices that work like electronic fuses in your
car, burning open under high current to interrupt power flow. They are often used on short sections of
primary distribution tap lines and to protect distribution secondary transformers.
Three-phase system: Three-phase electric power is a common method of alternating-current electric
power generation, transmission, and distribution. It is a type of polyphase system and is the most
common method used by grids worldwide to transfer power. It is also used to power large motors and
other heavy loads. A three-phase system is generally more economical than others because it uses less
conductor material to transmit electric power than equivalent single-phase or two-phase systems at the
same voltage. The three-phase system was introduced and patented by Nikola Tesla in 1887 and 1888.
Phase imbalance: Most household and small commercial loads are single-phase. In North America and a
few other places, three-phase power generally does not enter homes. Phase imbalance is the unequal
allocation of customer loads on the 3 phases of a primary distribution circuit. Imbalance can cause
increase of distribution losses and adversely affect voltage management by three phase capacitor banks
as the loading differences may cause higher than acceptable voltage on lightly loaded circuits.
Distributed generation connected to a single pahse, like a home with roof-top solar, can create the
effect of phase imbalance.
Distribution Automation: Several terms are used interchangeably to describe specific aspects or broadly
automation of distribution substation equipment, field equipment and/or operational systems. The
terms as commonly used do not denote any level of sophistication. That is, the terms are often used to
describe relatively simple capacitor and recloser status and controls to very advanced self-healing or

13. 13
micro-grid type control schemes. It is usually necessary to ask clarifying questions to understand what is
being described.
SCADA: Supervisory Control & Data Acquisition
DA: Distribution Automation
DMS: Distribution Management System
AMI: Advanced Metering Infrastructure (aka, smart metering and automated meter management)
OMS: Outage Management System
GIS: Geospatial Information System
DRMS: Demand Response Management System