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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

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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 ScreenSource: A. von Meier

1980-2000 Distribution Operations CenterSource: A. von Meier

Source: Chad Baker/Getty Images

Source: JupiterImages

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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

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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

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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

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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

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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.

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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

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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/

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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 3rd Edition and Wikipedia

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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

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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

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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