1540-7977/10/$26.00©2010 IEEE34 IEEE power & energy magazine march/april 2010

The Future of Power

TransmissionTechnological Advances for Improved Performance

By Stanley H. Horowitz, Arun G. Phadke, and Bruce A. Renz Digital Object Identifi er 10.1109/MPE.2009.935554

TTHE ELECTRIC POWER SYSTEM IS ON THE VERGE

of signifi cant transformation. For the past fi ve years or so,

work has been under way to conceptualize the shape of a

21st-century grid that exploits the huge progress that has

been made in digital technology and advanced materials.

The National Energy Technology Laboratory (NETL) has

identifi ed fi ve foundational key technology areas (KTAs), as

shown in Figure 1.

Foremost among these KTAs will be integrated communi-

cations. The communications requirements for transmission

enhancement are clear. Broadband, secure, low-latency chan-

nels connecting transmission stations to each other and to con-

trol centers will enable advances in each of the other KTAs.

Sensing and measurements will include phasor mea-✔

surement data streaming over high-speed channels.

Advanced components, such as all forms of fl exible ✔

ac transmission system (FACTS) devices, HVDC, and

new storage technologies will respond to control sig-

nals sent to address perturbations occurring in mil-

liseconds.

©BRAND X PICTURES

34 IEEE power & energy magazine march/april 20101540-7977/10/$26.00©2010 IEEE

march/april 2010 IEEE power & energy magazine 35

Advanced control (and protection) methods will in- ✔

clude differential line relaying, adaptive settings, and

various system integrity protection schemes that rely

on low-latency communications.

Improved interfaces and decision support will uti- ✔

lize instantaneous measurements from phasor mea-

surement units (PMUs) and other sources to drive

fast simulations and advanced visualization tools

that can help system operators assess dynamic chal-

lenges to system stability.

Each of these elements will be applied to the moderniza-

tion of the grid, at both the distribution level and the transmis-

sion level. Because it is clearly less advanced, distribution is

receiving most of the initial focus. This is dramatically illus-

trated by the American Recovery and Reinvestment Act’s

Smart Grid Investment Grants (SGIGs), announced in Octo-

ber. Of the $3.4 billion awarded to 100 proposers (of the more

than 400 that applied), only $148 million went to transmission

applications; most of the rest was for distribution projects.

While the changes to distribution will be revolutionary,

transmission will change in an evolutionary manner. Dis-

tributed generation and storage, demand response, advanced

metering infrastructure (SGIGs will fund the deployment of

18 million smart meters), distribution automation, two-way

power fl ow, and differentiated power quality together rep-

resent a sea change in distribution design that will require

enormous fi nancial and intellectual capital.

The role of transmission will not be diminished, how-

ever, by this new distribution paradigm. Large central power

plants will continue to serve as our bulk power source, and

many new ones will be fueled by renewable resources that

would today be out of reach of the transmission grid. New

lines will be built to connect these new plants, and new

methods will be employed to accommodate their very dif-

ferent performance characteristics. Addressing the result-

ing greater variability of supply will be the job of the fi ve

KTAs listed above. As KTA technology speeds increase,

control of transmission will advance from quasi-steady-

state to dynamic.

The traditional communications technologies capable of

supporting these strict requirements are fi ber optics (e.g.,

optical ground wire) and microwave. Recently a third can-

didate has appeared on the scene. Research funded by the

U.S. Department of Energy (DOE) and American Electrical

Power in conjunction with a small Massachusetts smart-grid

communications company, Amperion, has demonstrated the

viability of broadband over power line (BPL) for application

on transmission lines. Currently, a fi ve-mile, 69-kV line is

operating at megabit-per-second data rates with latency of

less than 10 ms. The next step will be to extend this high-

voltage BPL technology to 138 kV.

How We Got Here In 551 B.C., Confucius wrote, “Study the past if you would

know the future.” The future of the electrical power trans-

mission system must be based on a study of the past con-

sidering its successes and failures, on knowledge of the

existing system and all of its component disciplines, and

on a thorough understanding of the latest technologies and

their possible applications. The electrical power system,

and in particular its transmission and distribution network,

is a vital and integral part of today’s society. Because it

is essential to all our endeavors, we must be prepared to

integrate new, exciting, and highly innovative concepts to

guarantee that it performs reliably, safely, economically,

and cleanly.

Although not unique in world events involving power

systems, two widely known outages in the United States and

Canada serve as examples of the history, analysis, and reme-

dies for blackouts and can provide a basis for future actions.

Widely publicized, the blackouts of 9 November 1965 in

the northeastern United States and 23 August 2003 in the

northeastern United States and Canada are typical events

that can help shape our planning and operating efforts for

the future.

In 1965 we learned that cooperation and interaction

between utilities were essential. In response to the blackout,

utilities established the National Electric Reliability Cor-

poration (NERC) in 1968, which began distributing recom-

mendations and information. These communications formed

the basis for more reliable and secure planning, operating,

and protective activities. The decisions of the newly formed

NERC were, however, only recommendations. Defi ciencies

due to limitations in transmission planning, operations, and

protection were recognized, and steps were taken to correct

them. Transmission systems were strengthened considerably

by the construction of 345-kV, 500-kV, and 765-kV lines.

System planning studies were made cooperatively; operat-

ing parameters and system problems were studied jointly.

Underfrequency load shedding became universal, with spe-

cifi c settings arrived at by agreement between utilities, and

loss-of-fi eld relaying was recognized as a system phenom-

enon and studied accordingly.

In 2003 another blackout of similar proportions affected

the northeastern United States and parts of Canada. The

figure 1. NETL’s five key technology areas.

Advanced

Components

Sensing and

Measurements

Advanced

Control

Methods

Decision SupportIntegrated

Communications

36 IEEE power & energy magazine march/april 2010

causes of that event included not recognizing load and sta-

bility restrictions and, unfortunately, human error, which

suggested that improved systemwide monitoring, alarms,

and power system state estimation programs would be

useful and should be instituted. The ability of a distance

relay to differentiate between faults and load, particularly

when the system is stressed, has become a major concern.

NERC requires that this condition be included in relay set-

ting studies.

In 1920, Congress founded the Federal Power Com-

mission (FPC) to coordinate hydroelectric power devel-

opment. Fifty-seven years later, in response to the energy

crisis, the DOE was formed. The DOE included the FPC,

renamed the Federal Energy Regulatory Commission

(FERC), whose mandate was primarily to conduct hear-

ings and approve price control and related topics, including

electric practices on bulk transmission systems. After the

2003 event, FERC also became a regulatory instrument,

reviewing transmission line improvements and rights-of-

way. FERC review and approval, as with NERC, has now

become mandatory. The actions of FERC and NERC will,

in the future, be major components of system decisions

and practices.

Technology’s Role Going ForwardWith the preceding as background, we can now review in

greater detail some of the transmission enhancements that

will be part of the 21st-century transmission system.

Advanced ControlIt is axiomatic that the fundamental basis for the reliable

performance of the transmission system has to be the system

itself. The primary components, system confi guration, line

specifi cations, and design of high-voltage equipment must

be consistent with the mission of the power system, i.e., to

deliver electric energy safely, reliably, economically, and in a

timely fashion. Furthermore, high-voltage, electronic-based

power equipment such as bulk storage systems (e.g., fl ow

batteries), FACTS devices (including unifi ed power fl ow

controllers, static var compensators, and static synchronous

compensators), and current-limiting devices (CLDs), which

are based on high-temperature superconductivity, are now

or will soon be available. Coupled with sophisticated com-

munications and computing tools, these devices make the

transmission system much more accommodating of varia-

tions in load and/or voltage.

Of these advanced control devices, FACTS represents

the most mature technology. It is in somewhat limited use

at present but has the potential to be an increasingly impor-

tant element in the future. FACTS can provide control of

ac transmission system parameters and thus increase power

transfer capability and improve voltage regulation. Changes

in generation and load patterns may make such fl exibility

extremely desirable. With the increased penetration of central

renewable sources and with the continued variability of

electricity markets, the value of these various electronics-

based power devices will only grow.

In addition to FACTS, bulk storage, and CLDs, vari-

ous new aspects of the distribution system such as demand

response, distributed generation, plug-in hybrid electric

vehicles (PHEVs), and other forms of distributed storage can

be centrally coordinated and integrated to function as a “vir-

tual power system” that supports the transmission system in

times of stress.

Advanced ProtectionRecognizing that protection of specifi c equipment and

localized systems is inadequate in the face of systemwide

stress, in 1966 a joint IEEE/CIGRE questionnaire was

circulated. The results indicated that protection schemes

had to encompass wider areas of the transmission system.

This effort required communication and control center

involvement. The effort was termed special protection sys-

tems (SPS). The primary application of SPS at that time

was for limited system events such as underfrequency and

undervoltage, with some advanced generation controls.

As system stress becomes a more common concern, the

application of SPS takes on added importance and in fact

becomes an important tool for protecting the grid against

wide-area contingencies.

The SPS concept is no longer considered “special” and

is now commonly referred to as system integrity protection

systems (SIPS), remedial action systems (RAS), or wide-

area protection and control (WAPC). These schemes are

intended to address widespread power system constraints or

to be invoked when such constraints could occur as a result

of increased transfer limits. The Power System Relaying

Committee of the IEEE initiated a recent survey on power

system integrity protective schemes that was distributed

worldwide with cooperation from CIGRE, NERC, IEE, and

other utility organizations. The survey revealed very wide-

spread application, with more than 100 schemes of various

complexity and purpose. Emerging technologies in high-

speed communication, wide-area measurement, and phasor

measurement are all employed and will be vital components

of the transmission system in the future.

One of the most exciting features of the transmission sys-

tem of the future involves power system protection. This is

due in large measure to the advantages of digital technology

for relays, communication, and operation. Relays now have

the ability to perform previously unimaginable functions,

made feasible by evaluating operating and fault parameters

and coupling this data with high-speed communication and

computer-driven applications within the power system con-

trol center. With the ever-increasing restrictions on trans-

mission line and generator construction and siting and the

decreasing difference between normal and abnormal opera-

tion, loading, and stability, the margins between the relay-

ing reliability concepts of dependability and security are

becoming blurred. Consequently, the criteria of traditional

march/april 2010 IEEE power & energy magazine 37

protection and control are being challenged. The hallmark

of relays is the tradeoff between dependability (the ability to

always trip when required) and security (the characteristic

of never tripping when not required).

Traditionally, relays and relay schemes have been designed

to be dependable. Losing a transmission line element must

be tolerated, whether the loss is for an actual fault or for an

inadvertent or incorrect trip. When the system is stressed,

however, an incorrect trip is not allowable. With the system

stressed, losing another element could be the fi nal step in

bringing down the entire network. With digital logic and

operations, it is possible to reorder protection priorities and

require additional inputs before allowing a trip. This can be

done with appropriate communication from a central center

advising the relays.

Probably one of the most diffi cult decisions for a relay is

to distinguish between heavy loads and faults. Heretofore,

relays simply relied on the impedance measurement, with

settings determined by off-line load studies using conditions

based on experience. As in the two blackouts mentioned

above, this criterion was not adequate for unusual system

conditions that were not previously considered probable.

Digital relays can now establish such parameters as power

factor or voltage and remove the measured impedance from

the tripping logic.

The bête noir of protection has traditionally been the

multiterminal line. The current to the fault and the voltage

at the fault defi nes the fault location. A relay designed to

protect the system for this fault, however, sees only the cur-

rent and voltage at that relay’s specifi c location. The advent

of high-speed communication and digital logic remedies this

condition and allows all involved relays to receive the appro-

priate fault currents and voltages.

The increasing popularity of transmission line differen-

tial relaying also provides both dependability and security

for faults in a multiterminal confi guration. Although primar-

ily a current-measuring relay, the digital construction allows

far more protection, monitoring, and recording functions.

Future applications will be available to accomplish the fea-

tures mentioned above and in ways not yet implemented or

even thought of.

One of the earliest advantages of the computer relay

is its ability to monitor itself and either repair, replace, or

report the problem. This feature is sure to be a major fea-

ture in future transmission line protection. In addition, the

information stored in each relay during both normal and

abnormal conditions and the ability to analyze and trans-

fer this information to analyzers have made previously used

oscillography and sequence-of-events recorders obsolete.

Replacing these devices will result in very signifi cant sav-

ings in both hardware and installation costs. AEP, in con-

junction with Schweitzer Engineering and Tarigma Corp.,

has embarked on a revolutionary program that lets selected

centers receive data from critical substations that will com-

bine, display, and analyze fault data to a degree and in a

time frame heretofore not possible. Combining the current,

voltage, communication signals, and breaker performance

from several stations on one record that can be analyzed at

several control and engineering centers permits operations

to be verifi ed and personnel to be alerted to potential prob-

lems. A vital by-product of this advanced monitoring is the

fact that it allows NERC requirements for monitoring and

analysis to be met.

Perhaps even more exciting is the possibility of predicting

the instability of a power swing. Modern protection theory

knows how to detect the swing using zones of stability and

instability. The problem is how to set the zones. With accu-

rate synchronized phasor measurements from several buses,

the goal of real-time instability protection seems achievable.

Out-of-step relays could then establish blocking or tripping

functions at the appropriate stations.

The role of underfrequency load shedding has already

been discussed. Future schemes, however, could use real-

time measurements at system interconnection boundaries,

compute a dynamic area control error, and limit any poten-

tial widespread underfrequency by splitting the system.

Computer relays, if not already in universal use, will be

in the near future. This will let utilities protect, monitor, and

analyze system and equipment performance in ways and to a

degree not possible before.

Synchronized Phasor MeasurementsIt has been recognized in recent years that synchronized

phasor measurements are exceedingly versatile tools of

modern power system protection, monitoring, and control.

Future power systems are going to depend on making use

of these measurements to an ever-increasing extent. The

principal function of these systems is to measure positive

sequence voltages and currents with a precise time stamp

(to within a microsecond) of the instant when the measure-

ment was made. The time stamps are directly traceable to

the Coordinated Universal Time (UTC) standard and are

achieved by using Global Positioning System (GPS) trans-

missions for synchronization. Many PMUs also provide

While the changes to distribution will be revolutionary, transmission will change in an evolutionary manner.

38 IEEE power & energy magazine march/april 2010

other measurements, such as individual phase voltages and

currents, harmonics, local frequency, and rate of change of

frequency. These measurements can be obtained as often

as once per power frequency cycle, although for a number

of applications a slower measurement rate may be prefer-

able. In well-designed systems, measurement latency (i.e.,

the delay between when the measurement is made and when

it becomes available for use) can be limited to fewer than

50 ms. The performance requirements of the PMUs are

embodied in the IEEE synchrophasor standard (C37.118). A

measurement system that incorporates PMUs deployed over

large portions of the power system has come to be known as

a wide-area measurement system (WAMS), and a power sys-

tem protection, monitoring, and control application that uti-

lizes these measurements is often referred to as a wide-area

measurement protection and control system (WAMPACS).

Automatic Calibration of Instrument Transformers It is well known that current and voltage transformers

used on high-voltage networks have ratio and phase-angle

errors that affect the accuracy of the measurements made

on the secondary of these transformers. Capacitive volt-

age transformers are known to have errors that change with

ambient conditions as well as with the age of the capacitor

elements. Inductive instrument transformers have errors that

change when their secondary loading (burden) is manually

changed. The PMU offers a unique opportunity for cali-

bration of the instrument transformers in real time and as

often as necessary. In simple terms, the technique is based

on having some buses where a precise voltage transformer

(with known calibration) is available and where a PMU is

placed. Potential transformers used for revenue metering are

an example of such a voltage source. Using measurements by

the PMU at this location, the calibration at the remote end

of a feeder connected to this bus can be found. This calibra-

tion is not affected by current transformer (CT) errors when

the system loading is light. It is thus possible to calibrate

all voltage transformers using current measurements at light

system load. Using the voltage transformer calibration thus

obtained and additional measurements during heavy system

load, the current transformers can be calibrated. In practice,

it has been found (in simulated case studies) that by combin-

ing several light and heavy load measurement sets a very

accurate estimate of all the current and voltage transformers

can be obtained. Although a single accurate voltage source

is suffi cient in principle, having a number of them scattered

throughout the network provides a more secure calibration.

Precise State Measurements and EstimatesState estimation of power systems using real-time measure-

ments of active and reactive power fl ows in the network

(supplemented with a few other measurements) was intro-

duced in the late 1960s to improve the awareness among

power system operators of the prevailing state of the power

grid and its ability to handle contingency conditions that

may occur in the immediate future. This was a big step for-

ward in intelligent operation of the power grid. The limita-

tions of this technology (such as nonsimultaneity of system

measurements across the network) were rooted in the tech-

nology of that day. The fact that the data from a dynamically

changing power system was not obtained simultaneously

over a signifi cant time span meant that the estimated state

was an approximation of the actual system state. Conse-

quently, the system state and its response to contingencies

could only be reasonably accurate when the power system

was in a quasi-steady state. Indeed, when the power system

was undergoing signifi cant changes due to evolving events,

the state estimator could not always be counted on to con-

verge to a usable solution.

The advent of wide-area measurements using GPS-

synchronized PMUs led to a paradigm shift in the state

estimation process. With this technology, the capability of

directly measuring the state of the power system has become

a reality. PMUs measure positive sequence voltages at net-

work buses and positive sequence currents in transmission

lines and transformers. Since the state of the power system

is defi ned as a collection of positive sequence voltages at

all network buses, it is clear that with suffi cient numbers of

PMU installations in the system one can measure the sys-

tem state directly: no estimation is necessary. In fact, the

transmission line currents provide a direct estimate of volt-

age at a remote bus in terms of the voltage at one end. It is

therefore not necessary to install PMUs at all system buses.

It has been found that by installing PMUs at about one-third

of system buses with voltage and current measurements, it

is possible to determine the complete system state vector.

Feeding this information into the appropriate computers

provides the information necessary for the adaptive protec-

tive function described above. Of course, a larger number

of PMUs provides redundancy of measurements, which is

always a desirable feature of estimation processes.

Complete and Incomplete ObservabilityIn order to achieve a state estimate in the traditional way,

i.e., by using unsynchronized supervisory control and data

acquisition (SCADA) measurements, a complete network

tree must be measured. With PMUs, however, it is suffi cient

to measure isolated parts of the network, which provides

islands of observable networks. This is possible since all

phasors are synchronized to the same instant in time. The

process has been described as PMU placement for incom-plete observability. The remaining network buses can be

estimated from the observed islands using approximation

techniques. This is, of course, not as accurate as providing a

suffi cient number of PMUs in the fi rst place. But it has been

shown that combining incomplete observations with such an

approximation technique to estimate the unobserved parts

provides surprisingly useful results. Incomplete observabil-

ity estimators are a natural step in the progression towards

march/april 2010 IEEE power & energy magazine 39

complete observability and will be a feature in future trans-

mission systems.

Figure 2 illustrates the principle of complete and incom-

plete observability. In Figure 2(a), PMUs are placed at buses

identifi ed by dark circles. By making use of the current mea-

surements and the network impedance data, it is possible to

calculate the voltages at the buses identifi ed by light blue

circles. In this case, complete observability is achieved with

two PMUs. Figure 2(b) illustrates the use of fewer PMUs

than would be necessary for complete observability. Even

with current measurements, it is not possible to determine

the voltages at the buses identifi ed by the red circles. These

buses form islands of incomplete observability. As men-

tioned earlier, these bus voltages can be estimated fairly

accurately using voltages at surrounding buses.

State Estimates of Interconnected SystemsA common problem faced by interconnected power systems

is that various parts of the system may be under different

control centers, with each part having its own state estimator.

This, of course, implies that each partial state estimate has its

own reference bus. To perform studies such as contingency

analysis on the interconnected power system, it is necessary

to have a single state estimate for the entire network. This

requires either that 1) a new system state using data from

all partial control centers be determined or 2) an alternative

must be found to modify the results of individual state esti-

mates to put all states on a common reference. Option 1 is

cumbersome and wasteful of computational effort. Option

2 becomes exceedingly simple with PMUs. At the simplest

level, one can visualize putting a PMU at each of the ref-

erence buses, thus obtaining the phase-angle relationships

between all partial estimates. These phase-angle corrections

may then be used to form a combined state estimate for the

entire interconnected network on a single reference. It has

been found in practice that the placement of a few PMUs

in each partial system (rather than just one at the reference

bus) leads to greater security and optimal performance. This

principle is illustrated in Figure 3. Systems 1 and 2 are con-

nected by tie lines and have state estimates S1 and S2 that

are obtained independently, each with its own reference bus.

With the use of PMU data from optimally selected buses

(shown in red), it is possible to determine the angle differ-

ence between the two references and obtain a single state

estimate for the interconnected system.

Intelligent Visualization Techniques The traditional visualization techniques used in energy man-

agement system (EMS) centers focus on showing network bus

voltages and line fl ows, along with any constraint violations

that may exist. It is, of course, possible to reproduce such

displays using WAMS technology. Dynamic loading limits

of transmission lines have been estimated with WAMS, and

it would be relatively simple to show prevailing loading con-

ditions and their proximity to the dynamic loading limits.

Many PMUs offer the possibility of measuring system unbal-

ances. It would then be possible to display unbalance cur-

rents to determine their sources and mitigation techniques to

correct the unbalance.

figure 3. Connecting adjacent state estimates with phasor data.

Traditional SE Result: E1 Traditional SE Result: E2

Reference Reference

Optimal Placement of PMUs

A common problem faced by interconnected power systems is that various parts of the system may be under different control centers, with each part having its own state estimator.

figure 2. (a) Complete observability. (b) Incomplete observability.

Indirect

PMU

PMU

Indirectly

Observed

Unobserved

(a)

(b)

40 IEEE power & energy magazine march/april 2010

With direct measurement of synchronized phasors,

many more display options become possible. For example, a

geographical display with phase angles at all network buses

shown at the physical location of buses—and perhaps fi tted

with a surface in order to provide a hilly contour—would

immediately show the distribution of positive sequence volt-

age phase angles.

Figure 4 shows such a visualization of a hypothetical net-

work state for the entire United States. The map colors iden-

tify the magnitude and sign of the positive sequence voltage

phase angle with respect to a center of angle reference. The

lower plot is a footprint of equiangle loci from the map. Since

the positive sequence voltage phase-angle profi le of a net-

work conveys a great deal of information regarding its power

fl ow and loading conditions, such visualizations can instantly

show the quality of the prevailing system state and its dis-

tance from a normal state. High-speed dynamic phenomena

can be represented by animations of such visualizations.

Such a display would instantly show the general dispo-

sition of generation surplus and load surplus areas. Such a

picture can be updated at scan rates of a few cycles, leading

to visualization of dynamic conditions on the network. If

thresholds for phase-angle differences between key buses

have been established for secure operation of the network,

then violation of those thresholds could lead to important

alarms for the operator. Similarly, when islands are formed

following a catastrophic event, the boundaries of those

islands could be displayed for the operator. Several protec-

tion and control principles are being developed to make

use of wide-area measurements provided by PMUs. Adap-

tive relaying decisions made in this manner could also be

displayed for the use of protection and control engineers.

The technology of visualization using WAMS schemes is

in its infancy. As we gain greater experience with these

systems, more interesting display ideas will undoubtedly

be forthcoming.

ConclusionModernizing the U.S. power grid has become a national pri-

ority. Unprecedented levels of governmental funding have

been committed in order to achieve this goal. The initial

focus has been on the fundamental transformation of the

distribution system. This is in itself a huge technical chal-

lenge that will be measured not in years but in decades. The

end result is expected to be higher effi ciency, reduced envi-

ronmental impact, improved reliability, and lower exposure

to terrorism.

The revolution in distribution must be accompanied by

the continued evolution of the transmission system. Events

like the 2003 blackout—more the result of human shortcom-

ings than technological breakdowns—can be eliminated

by exploiting the huge progress made in recent years in the

digital and material sciences. Other industries have already

harvested these opportunities; now it is our turn.

Technological development is an engineering challenge.

This nation has time and again demonstrated its ability

to meet such challenges whenever they have been clearly

focused. But there is another challenge that may actually

be more diffi cult. It is to fi nd the political alignment that is

needed to accept the vision and move forward aggressively.

For transmission, that means recognizing that new lines, not

just better lines, will be needed. It is simply not acceptable

to wait ten or more years for a new line to move from con-

cept to reality. Unlike many other parts of the world, the

United States has allowed fragmented responsibility for

transmission additions to slow the process to an unaccept-

able extent.

With the intense focus now on energy in general and

electricity in particular, it should be possible to overcome

both the technical and the political obstacles and to reestab-

lish U.S. leadership in this vital arena. Doing so is a matter

of huge national signifi cance that will affect the lifestyle of

all Americans in this new century.

For Further ReadingV. Madani and D. Novosel, “Getting a grip on the grid,”

IEEE Spectr., pp. 42–47, Dec. 2005.

P. Anderson and B. K. LeReverend, “Industry experience

with special protection schemes,” IEEE Trans. Power Syst., vol. 2, no.3 , pp. 1166–1179, Aug. 1996.

“Global Industry Experiences with System Integrity Pro-

tection Schemes,” Survey of Industry Practices, IEEE Power

System Relaying Committee, submitted for publication.

Biographies Stanley H. Horowitz is a former consulting electrical engi-

neer at AEP and former editor-in-chief of IEEE Computer Applications in Power magazine.

Arun G. Phadke is the University Distinguished Profes-

sor Emeritus at Virginia Tech.

Bruce A. Renz is president of Renz Consulting, LLC. p&e

figure 4. U.S. Phasor contour map.