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YOUR POWER DELIVERY MEDIA SOURCE

T H E O F F I C I A L P U B L I C A T I O N O F

Prepare for Disasters More Effciently

18 Tallahassees Single Smart Grid Platform

26 Asset Management: Data, Analysis and Decisions

31 GIS Data From the Cloud to the Field

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18 Combining Utility Efforts for a Single Smart Grid PlatformBrian Halcomb with Honeywell Smart Grid Solutions writes on the benefits the city of Tallahassee, Fla., gained by integrating multiple utilities in a single shared architecture. The utility increased meter-reading efficiency, improved meter-reading reliability, enhanced customer service, reduced fleet costs and lowered labor costs.

22 Benchmarking Results: T&D Crew Size and Equipment AnalysisTim Szybalski of First Quartile Consulting writes on why benchmarking comparisons are worth exploring for an individual company, and the many factors that go into determining the right size crew: safety requirements, equipment, union rules, skill sets, use of apprentices, role of working crew leaders, job mix and travel distances.

26 Asset Management Data, Analysis and DecisionsDon Angell, Tony McGrail and Kenneth R. Elkinson, with Doble Engineering Co., reveal the value of applying formal asset management principles in the electric power industry. This approach enables the institutionalization of asset management best practices and consistent outcomes in this era of aging work force and ever-greater demands on the assets.

34 Products

35 Calendar/Ad Index

36 From the Pages of Electricity History

From the Editor 2

Notes 6

JULY 2013 VOLUME 18.07

31 Next in GIS in the Field and in the CloudJason Brewington of Schneider Electric describes a new GIS system that can provide a map of all assets, along with real-time updates on statuses and conditions. The information it provides isnt useful, however, if it can be accessed only by an office worker on a computer. Brewington describes how to make information available to field crews working on day-to-day network operations or responding to outage events.

Utilities can Prepare for Disasters More Efficiently

Ron Brown of PricewaterhouseCoopers LLP describes the recent surges in severe weather and the increased frequency of cyberattacks

that have clarified two points: electric utilities no longer can afford a short-term approach to

business continuity and disaster recovery and they should be better prepared for

unexpected disruptions.

240V kWh

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Engineering Services for the Intelligent GridSEL Engineering Services provides a wide range of engineering, procurement, and construction

management capabilities. We deliver complete turnkey solutions to make electric power safer,

more reliable, and more economical. Learn more about SEL Engineering Services, a division of

Schweitzer Engineering Laboratories, at www.selinc.com/7pgi.


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EDITOR IN CHIEF Teresa Hansen

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SENIOR EDITOR Kristen Wright


ASSOCIATE EDITOR Jennifer Van Burkleo


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POWERGRID International is the offcial publication of


EDITOR IN CHIEF TERESA HANSEN

FROM THE EDITOR

Get Ready for Industry Changes

The electric utility industry is changing quickly. President Barak Obama

made it clear in his speech on June 25 that if Congress doesnt regulate

carbon dioxide emissions from power plants through a federal energy

policy, he will continue to push the Environmental Protection Agency

(EPA) to do so. The plan Obama laid out in his speech shouldnt be a

surprise to anyone who follows current energy policy, politics or both.

Since he took office, Obama has pushed to reduce the use of coal-fired

electricity generation and increase the use of green technologies,

including more renewable energy generation.

Although much of Obamas recent speech focused on electricity

generators, transmission and distribution companies are impacted by his

plan, too. The grid must be prepared to deal with the changing generation

mix. A report from Navigant Research described on page 6 indicates

Obamas vision of more renewable energy is accurate. Navigant predicts

the global generation mix will become more diversified and decentralized

in 2013.

Some states regulators, customers and lawmakers also want change in

the electric utility industry. They believe disruptive weather events are

more frequent and extreme and that utilities are ill-prepared to deal with

such events. Some utilities are pressured to improve communications with

customers and decrease outage duration during weather-related events.

In the feature beginning on page 14, Utilities can Prepare for Disasters

More Efficiently, Ron Brown of Pricewaterhouse Coopers LLP writes that

risk-based business continuity and disaster recovery can improve utilities

performance when disaster strikes.

Another story on page 6 reports that Newton-Evans Research Co.s

latest T&D investment study reveals that utilities are increasing their

2013 capital spending significantly on energy management systems,

SCADA and outage management systems; another indication that disaster

preparedness and efficient grid operations are priorities for T&D utilities.

Other articles in this issue describe a benchmark study on T&D crew

size, how effective asset monitoring helps ensure asset health, the city

of Tallahassees combined metering infrastructure and how moving GIS

technology to the cloud can improve field and IT operations. These are

important in meeting future political, regulatory and customer demands.

Another interesting short item in From the Pages of Electricity History

reveals that in 1999 the U.S. Court of Appeals - D.C. Circuit ruled the

EPA could not regulate ozone particulates because certain issues are

too important for Congress to delegate to administrative agencies, more

evidence of how much the industry is changing.

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NOTES


NEWTON-EVANS STUDY: 43 PERCENT OF UTILITIES PLAN

TO INCREASE 2013 CAPEX ON EMS/SCADA/OMS

reason for increases in 2013 Capex.

Seventy-one percent of responding

utilities said they plan to start a new

smart grid project in the upcoming two

years, and 59 percent of those projects

will include some form of distribution

automation.

The new 2013 edition will include

information about relative market trends

and market size estimates for major

smart grid building blocks.

The Newton-Evans Research Co.

released preliminary findings from

Global CAPEX and O&M Expenditure

Outlook for Electric Power T&D

Investments: 2013-2014 Funding

Outlook for Smart Grid Development,

its fifth study in the multiyear tracking

research program that looks into elec-

tric power utility capital expenditure

(Capex) budgets related to smart grid

investments and infrastructure spending

plans.

Early findings from utilities in 24

countries that participated in the study

of electric power transmission and distri-

bution investment indicate that 43 per-

cent of utilities plan to increase Capex

for 2013 on enegy management systems

(EMS), SCADA and outage management

systems (OMS). Half plan on increas-

ing Capex in 2013 for protection and

control, and 55 percent plan on increas-

ing transmission infrastructure Capex.

Automatic meter reading (AMR) and

advanced metering infrastructure (AMI)

seem to be leveling out; 63 percent of

respondents so far said there will be no

change from 2012 spending on this.

Operations and maintenance (O&M)

budgets for 2013 reflect a somewhat

different story. Most categories of O&M

spending were less likely to see an

increase from the budgets of 2012.

More than half (58 percent) of the

utilities that responded so far indicated

that regulatory mandates are the reason

for Capex increases in 2013. Only 13

percent cited government stimulus as a

SMART GRID AND INFRASTRUCTURE 2012-2013 2012-2013 2012-2013

CATEGORY INCREASE DECREASE NO CHANGE

SCADA/EMS/OMS 43% 20% 37%

Substation A&I 44% 19% 36%

Protection and Control 50% 11% 39%

Distribution Automation 29% 18% 54%

AMR/AMI 33% 3% 63%

Transmission Infrastructure 55% 6% 39%

Distribution Infrastructure 48% 7% 45%

Cybersecurity: Operations 55% 9% 47%

Cybersecurity: Enterprise 38% 3% 59%

COMPARISON OF 2013 PLANNED CAPEX

INVESTMENT FOR SMART GRID PROGRAMS

NAVIGANT: 2013 PIVOTAL IN TRANSITION TO MORE DIVERSIFIED ENERGY MIX

The white paper, Smart Energy:

Five Metatrends to Watch in 2013 and

Beyond, outlines key trends that affect the

development of smart energy industries

worldwide, the specific market impacts of

these trends in 2013, and the longer-term

impact of these emerging developments.

The full white paper

is available for free

download on the

Navigant Research

website.

The smart energy sector is evolving

rapidly, expanding from a collection of

niche markets into a standardized part of

the global energy portfolio.

Small, distributed generation

technologies such as solar panels, small

wind turbines and residential combined

heat and power systems enable people to

produce and sell their power. As a result,

new energy sources and advanced energy

technologies have entered the market and

are posting revenue. According to a new

white paper from Navigant Research, part

of Navigants energy practice, the transition

to a more diversified and decentralized

energy mix will be a key trend for the

global energy industry in 2013.

The white paper identifies five emerging

metatrends that will have an increasing

impact in 2013 and beyond. These include:

Increasingly democratized energy.

Changing role of government

innovation funds.

Converging technologies.

Transitioning of the Southern African

Power Pool to the new Brazil, Russia,

India and China (BRIC).

Changing role of utilities.

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Only Itron.

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NOTES

EYE ON THE WORLD

Ofgems Low Carbon Networks Fund, which has given

us the opportunity to work with four of the U.K.s electric-

ity distribution companies to find novel and affordable

solutions to help them bring about a low-carbon elec-

tricity future for consumers.

Smarter Grid Solutions creates and delivers real-

time grid management software to help electricity

distribution companies manage local, regional and

national electricity grid congestion issues and cope

with increasing volumes of low-carbon generation and

demand. The technology frees up capacity in the exist-

ing electricity grid so electricity companies can avoid

or defer building new grid infrastructure. The result is a

faster and cheaper solution to connecting distributed

generation, such as wind turbines or small hydro, so

electricity companies can concentrate on building a

low-carbon electricity system for their customers.

The chief executive of Ofgem, the regulatory body

for the electricity and gas industry in Great Britain,

recently opened a new head office in Corunna House,

Cadogan Street in central Glasgow for smart grid tech-

nology company Smarter

Grid Solutions.

The company has

grown rapidly to become

one of the U.K.s leading

dedicated smart grid tech-

nology companies since

it was established in 2008. Today, it employs more

than 35 people, has an office in London and will open

another in New York in July.

Were honored that Alistair Buchanan has agreed

to open our new head office, said Chairman Robert

Armour. The companys growth has been driven by

Ofgem chief executive opens new Smarter Grid Solutions HQ in Glasgow

Network Mapping Pty to provide as-built engineering models to Powerlink, Brisbane

Sydney-based survey and engineering com-

pany Network Mapping will aerially survey more

than 1,000 km of high-voltage transmission

lines throughout Queensland, Australia, during

the next six months.

The aerial surveys will be conducted from heli-

copters and will use LIDAR, which is designed to

produce detailed 3-D PLS-CADD models.

The surveys are being undertaken for

high-voltage electricity company Powerlink

Queensland.

The information provided through the 3-D

models will be used to update Powerlinks

records and assist in planning to deliver a safe,

efficient and reliable high-voltage transmission

supply, said Roland Vitelli, Powerlinks executive

manager for infrastructure delivery and techni-

cal services.

Network Mapping CEO Kevin Jacobs said

the company looks forward to working with

Powerlink.

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NOTES

THE DEMAND TO GRID LAB: TESTING AND DEMONSTRATING

SMART GRID AND CUSTOMER TECHNOLOGIES IN BERKELEY LAB

Interest Energy Research (PIER) pro-

gram initially funded the DRRC, man-

aged by Berkeley Lab. The DRRCs

research, development and demonstra-

tion has led to a communications tech-

nology called Open Automated Demand

Response Communication Standards

(OpenADR), which standardizes how

demand response technologies work

and interoperate within a smart grid.

OpenADR helps manufacturers of

building automation equipment design

products for smart grid implementa-

tion and power aggregators incorporate

demand response into their work, said

Mary Ann Piette, research director for

DRRC. OpenADR builds on more than

10 years of research.

The initial goal of the OpenADR

research was to explore the possibil-

ity of developing a low-cost commu-

nications infrastructure to improve the

reliability, repeatability, robustness and

cost-effectiveness of automated demand

response. After the formal release of

OpenADR 1.0 specifications in 2009

and implementation, the OpenADR

standards are taking hold in the U.S.

and around the world:

Hundreds of sites use OpenADR

with more than 250 MW of

At the Lawrence Berkeley National

Laboratory Guest House, guests who

have business with Berkeley Lab can get

a comfortable nights sleep while expe-

riencing a living example of some of

the laboratorys scientific research. The

guest house is one of the demonstration

sites and the testing site for the Demand

to Grid (D2G) Lab in the Demand

Response Research Center (DRRC).

During the past year, the D2G Lab

has tested and improved strategies and

standards for demand-side interoper-

ability, wired and wireless communi-

cations, communication architectures,

devices, and monitoring and controls

technologies. These strategies and stan-

dards are part of research that will

improve the efficiency of the nations

electric grid and how it responds to

fluctuations in electricity demand or

supply.

RESPONDING TO DEMAND

Demand response can be manual,

semiautomated or fully automated,

depending on the

market and cus-

tomer choice. As

the grid has become

more complex

and diverse, stud-

ies and testing on

automated demand

response programs

have increased. Fully

automated demand

response does not

involve human

intervention but is

initiated at a home,

building or facil-

ity when an exter-

nal communications

signal triggers pre-

programmed load-

shedding strategies.

In 2004, the

California Energy

Commissions Public

DEMONSTRATION AREA SOLUTION PROVIDERS AND VENDORS

Residential Appliances, Thermostats, Plug-load Meters, HAN Integration, Data Analysis

GE, CloudBeam, Radio Thermostat, NEST, Itron, SilverSpring

OpenADR Technologies and Auto-demand Response Systems for End Uses, Strategies

Akuacom, AutoGrid

Lighting Controls, Communication and Technologies

Lunera and NEXT Lighting, CloudBeam

Electric Vehicle Chargers and Grid Integration Coulomb Technologies, Auto-Grid

Analytics and Visualization GE, CloudBeam, Akuacom, AutoGrid

D2G LAB RESIDENTIAL DEMONSTRATION ACTIVITIES 1


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NOTES


and switch to low-power operations in

response to demand response signals.

The guest house also features an

electric vehicle charger by Coulomb

Technologies, which switches to lower

charge levels during demand response

events. Before and during a demand

response event, a message is displayed

on the chargers screen that lets con-

sumers know what is happening and if

they have to take any action. All appli-

ances are pre-programmed to oper-

ate in a low-power-using mode when

they receive test signals that emulate a

demand response event.

COMMUNICATION

AND MONITORING

Smart appliances are one piece of the

puzzle, but the way information moves

between consumers and the gridand

the way it can be viewed and moni-

toredis the foundation for demand

response success. The D2G Lab is

demonstrating and testing communica-

tion architectures including the Energy

Service Interface, a generic interface

between the service provider and the

customer that can be a smart meter, a

electricity load automated in

California.

OpenADR is in full-scale

commercial deployment and

advanced OpenADR pilots are

underway.

More than 10 countries are

reviewing and conducting

pilot tests to use OpenADR for

automated demand response.

The OpenADR Alliance, established

in 2010 to foster the adoption of

the OpenADR standard, is growing

with more than 100 members.

RESIDENTIAL RESEARCH

Early in 2011, Berkeley Labs Grid

Integration Group took the work fur-

therfrom commercial-industrial

applications to residential demonstra-

tion through the D2G Lab at the Guest

House, said Rish Ghatikar, deputy lead-

er for the Grid Integration Group.

Our team has been doing other

research on commercial and industrial

facility grid integration and demand

response and its market transforma-

tion, Ghatikar said. We decided to

use the guest house as a residential

appliance research lab since the infra-

structure we needed for the set up was

there.

Demonstrations include communi-

cation between many end-use devices

such as smart appliances, revenue-

grade smart meters and a home-area

network (HAN) gateway to receive

demand response reliability pricing sig-

nals using OpenADR. Within the dem-

onstration test bed, wireless and wired

Internet and in-home protocols and

standards such as ZigBee Smart Energy

Profile 1.0 and other proprietary pro-

tocols are used to interoperate with

OpenADR and respond with a change

in energy use.

The guest house features applianc-

esheat pump water heater, refrig-

erator, washer and dryer, loaned by

General Electrican electric vehicle

charger, programmable communicating

thermostats, smart plugs and dimmable

LED lighting fixtures. All are controlled

by the HAN using demand response

signals and with Web-based energy

visualization tools to provide informa-

tion on energy choices made during

demand response events.

The guest houses heat pump water

heater is part of the demonstration.

It has two modes of heating: resistive

heating where a heating coil heats the

water for everyday operation, and a

heat exchanger that is used during

demand response events. The heater

uses 4,500 W of electricity during stan-

dard electric mode and powers down to

550 W using the heat exchanger during

demand response events.

Like the water heater, General

Electrics other appliancesa washer

and dryer and a staff refrigerator

are smart appliances that communicate

D2G CAPABILITIES PERFORMANCE PARAMETERS, BENEFITS

Lighting System Control, Energy and Peak Demand

System energy use, and peak demand; energy savings relative to noncontrolled 1980s retrofit base-case in twin cell

HVAC Control, Energy and Peak Demand Zonal Load Measurement, Hydronic or Air

Robust Data Acquisition System to Accommodate Additional Instrumentation

Flexibility to Integrate Experiment-specific Measurement Hardware With Existing Test Bed Instrumentation

Demand Response Automation Server and Client Designs

Client-server Capabilities, Price and Reliability Signals, Latency Testing

Energy and Demand Response ModelsEnergyPlus and Modelica Tools to Model Control Strategies, HVAC, Lighting and Whole Test Bed Energy Use

D2G LAB DEMONSTRATIONS AT THE FLEXLAB 2

1307PG_12 12 7/8/13 1:05 PM

July 2013 | 13 www.power-grid.com

gateway or devices in residential set-

tings, building management systems

for commercial buildings, and energy

management and control systems for

industrial facilities.

OpenADR signals are used at the

D2G Lab and can be sent over networks

and transports (including the Internet)

from the utility and other entities. Once

the demand response event signal is

sent, the appliances and equipment

respond by changing the power use for

a short time. Customers can override

the changes if desired.

These signals are monitored and

energy usage information for each end-

use device is collected. The perfor-

mance information is stored locally or

in the cloud and is available from any

Web browser via computer or smart

phone.

INTEGRATION WITH FLEXLAB

First-year D2G Lab operations have

demonstrated the goal research areas,

identified new research and develop-

ment areas and validated findings and

conclusions that benefit the wider

demand response community. In addi-

tion to continuing existing demonstra-

tions, the second-year goals include

conducting new demonstrations that

provide a suitable grid integration

research and demonstration frame-

work for Berkeley Labs new Flexlaba

research facility opening later in 2013

to study energy efficiency technologies

in buildings.

POWERGRID International magazine

is accepting nominations for the 2014

Projects of the Year awards! Nominations

may be submitted for notable projects

in four categories: smart grid, renewable

grid integration, demand response/energy

efficiency and customer engagement. Two

finalists will be selected in each cat-

egory and the winner will be announced,

at the Electric Light & Power Executive

Conference Awards Dinner on Jan. 27,

2014, in San Antonio. Award winners also

will be recognized during DistribuTECH

Conference and Exhibitions opening

keynote on Tuesday, Jan. 28. Additional

information and nomination forms are

available at www.power-grid.com.

Projects of the Year Awards Nominations Open


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Utilities can Prepare for Disasters More Efficiently

programs is surprising. PwCs The Global

State of Information Security Survey 2013

found that only 52 percent of utilities

respondents have implemented a BC/DR

strategy.

This is particularly troubling, given

the lessons of Superstorm Sandy and the

upsurge in cyberattacks.

If your company were hit by a disaster,

natural or otherwise, would it be prepared

to maintain operations and availability

across the business?

Utilities should move aggressively from

a defensive responsive capa-

bility to a more offen-

sive, prepared stance

Recent surges in severe weather and an increased frequency of cyberat-tacks have clarified two points: Electric

utilities no longer can afford a short-term

approach to business continuity and disas-

ter recovery and they should be better

prepared for unexpected disruptions.

Consider, for instance, Superstorm

Sandy. It hammered the mid-Atlantic and

Northeast in October and left flooding and

wind damage estimated at $71 billion.

During the storm, more than 8.51 mil-

lion homes lost power, according to The

New York Times.

At the same time, a new report by com-

puter security firm Mandiant shows that

advanced cyberattackers target energy, oil

and gas companies more frequently than

any industry except aerospace and defense.

The Mandiant 2013 Security Report

found that 14 percent of advanced attacks

in 2012 targeted energy, oil and gas

concernsan increase of 40 percent over

the previous year.

President Barack Obama in February

issued an executive order on cybersecu-

rity that recommends sharing of classified

information among the government and

owners and operators of critical infrastruc-

ture, including utilities.

Sharing this information might provide

electric utilities with warning and response

recommendations for potential attacks or

attacks in progress. The order is aimed at

raising awareness of cyberthreats and their

potential impacts.

Without a risk-based business continu-

ity and disaster recovery (BC/DR) program

to counteract such threats, electric compa-

nies could be vulnerable.

The number of companies without

Ron Brown is a managing director with

PwCs governance, risk and compliance prac-

tice. He has more than 25 years experience

in developing business continuity capabilities

and delivering management services to help

clients establish structured and consistent

programs that improve operational perfor-

mance and resilience.

BY RON BROWN, PWC

C

AN

STO

CK

PH

OTO

IN

C. /

DU

STIE

1307PG_14 14 7/8/13 1:05 PM


These strategies should be approved by

executive leaders, who set the tone and

commitment needed for recovery plan

development and implementation.

Prior to deployment, plans should be

exercised and validated to confirm require-

ments and recovery expectations.

Even organizations that have performed

BIAs must be diligent. Severe storms are

redrawing the lines of safety, and that

makes it increasingly important to regu-

larly update the existing BIA.

Sandy, for instance, flooded areas that

never had been under water.

As a result, flood zones have been

redefined in certain areas, and that might

dictate a reconsideration of disaster recov-

ery plans.

Regular exercising of BC/DR programs is

equally critical.

regarding events that can have prolonged

impact on their ability to generate, trans-

mit, distribute and provide critical cus-

tomer and internal business services.

USING THE BIA TO AVOID RISKS

Business continuity planning is an

offensive strategy to reduce recovery

impacts and costs. BC/DR is risk avoidance.

Thats why an effective program begins

with a thorough business impact analysis

(BIA) that identifies then prioritizes critical

business functions and supporting capa-

bilities needed to sustain services during

unexpected disruptions.

The BIA together with a risk assessment

is required to classify unique, critical busi-

ness threats, determine the likelihood of

core business disruption, and identify the

associated cost of loss.

As such, the BIA must be

performed with owners of

individual lines of business.

The BIA provides an under-

standing of business-interrup-

tion risks and impacts and helps

prioritize recovery needs by iden-

tifying key business areas that

require attention and driving

the appropriate level of consideration so

business needs are aligned with the BIA

and are in place to mitigate risk.

The outcome of the BIA establishes

requirements for investments in recovery

capabilities, as well as prioritizes functions

not commonly identified as critical to utili-

ties, such as back- and front-office process-

es that support nonoperational functions.

After requirements are confirmed, strat-

egies should be developed to mitigate

potential business interruptions.

1307PG_15 15 7/8/13 1:05 PM


and processes should verify information.

Most electricity providers prepare only

for risks they consider likely, such as hur-

ricanes, winter storms and floods. Given

todays environment, they also should plan

for extraordinary but possible threats such

as cyberattacks and events that provide

little to no notice. An effective cybersecu-

rity program dictates an offensive stance

that requires thinking like potential adver-

saries. What information do they want?

Whom would they target? How would

they infiltrate? Answer these questions and

seek input from your BIA, which has iden-

tified your most valuable assets, and craft

a cyberstrategy to protect them. Ensure

employees know what they are protecting,

why they are protecting it and their roles

in protecting it.

As cyberthreats multiply and constantly

evolve, it becomes increasingly difficult

for an electric utility alone to safeguard

its data, networks and service-delivery

capabilities. As Obamas executive order on

cybersecurity underscores, electric utilities

potentially have much to gain by collabo-

rating with government agencies and poli-

cymakers to share cyberattack information

and strategies. They also want to be pro-

tected from privacy lawsuits if they share

customer information and from negligence

suits for failing to act on warnings.

Finally, some electricity providers think

they can avoid planning for unlikely events

because they might never happen. Thats

not a risk worth taking.

Disaster recovery should be elevated to

a strategic investment and supported with

a cost-benefit analysis. Demonstrating, for

instance, that investing a relatively small

amount can provide a huge cost savings

after a disaster can be convincing.

An effective BC/DR program that embeds

strategy, processes, technology and security

into the fabric of an organization might be

costly but can pay off many times over if

needed.

Yet around-the-clock availability require-

ments often make it difficult for electricity

providers to perform extensive exercises,

particularly for plans that address long-

term interruptions.

A risk-based approach also dictates that

critical vendors, suppliers and partners

participate in BC/DR exercises.

These third parties also should have

their own BC/DR plans.

It might be beneficial for them to have

an audit of their programs as proof of

readiness.

PLANNING BEYOND

THE FIRST 48 HOURS

Sandy confirmed power outages can

endure far longer than 48 hours, yet many

utilities limit planning and exercising to

the first two days of an event or less.

Electricity providers should think

beyond survival of an interruption and

develop long-term recovery capabilities

and planning.

Most utility emergency plans include

mutual aid agreements and procedures

such as recruiting storm response crews

from other states or regions, develop-

ing alternative delivery and transmission

process controls capabilities because of

technology interruptions, and prioritizing

critical services to be maintained to sup-

port safety and health services.

Mutual aid agreements have existed

among utilities to mitigate disruption in

field operations, but there might be oppor-

tunities to broaden collaborative efforts

to call center backup and other support

functions.

Electricity providers also should prepare

for incidents that might prevent employees

from working in corporate facilities. If a

call center is under water, for instance, it

will be necessary to plan for employees

to work at a remote location or leverage a

service provider. Even with these plans, if

customer service or outage management

systems are not operational, recovery

options might be affected severely.

As a result, a comprehensive plan and

approach to conducting exercises are not

nice to have but are necessary because

of the complexities and interdependences

that typically are not uncovered until a

comprehensive exercise is conducted.

Beyond planning, electric utilities

should conduct business continuity exer-

cises for durations beyond 48 hours and

publish results internally so all employees

understand the processes. BC/DR person-

nel should document processes that failed

or were inefficient and make sure these

gaps are remediated. These reports can

provide lessons that improve the BC/DR

program and potentially reduce recovery

costs.

THE RIGHT TECHNOLOGY

FOR BC/DR, CYBERSECURITY

BC/DR is not strictly a technology exer-

cise, but having the right technology is

important to supporting an effective BC/

DR program. With the advent of smart

grid and smart meter technologies, utili-

ties can gain insights into the location of

problems. But this increase in knowledge

can augment reliance and risk in the event

of disruption. Electric utilities should care-

fully and broadly consider how new tech-

nologies are used and incorporated into

overall BC/DR plans.

As managers evaluate new technologies,

they should rethink and embed processes

that can help streamline disaster recovery

efforts. These might include mobile

devices, apps and GPS services to dispatch

and track power-restoration workers

more efficiently and streamline damage

assessment.

The right technologies also can enable

employees to work remotely if corporate

facilities are unavailable. In addition, social

media can help identify and communicate

situational issues quickly, but procedures

1307PG_16 16 7/8/13 1:05 PM

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240V kWh240V kWh

BY BRIAN HALCOMB, HONEYWELL

rate strategies to its customers.

3. Provide utility customers with

improved access to account informa-

tion, such as real-time energy usage,

a review of their historical usage and

the ability to see how much energy

they have used during the current

billing cycle, allowing customers to

make informed efficiency decisions

concerning their energy use.

To empower customers to make smart

decisions that minimize energy and water

use and save money, the utility must give

customers improved control over infor-

mation about their usage as quickly as

possiblenot just when the monthly bill

arrives. Because the municipal utility pro-

vides three services, it has an opportunity

to provide that information to custom-

ersand back to the utility itselfconsid-

erably more efficiently than had it provided

only one service.

SOLUTION

The project involved developing and

installing utility metering infrastructure

s the smart grid continues to devel-

op, what practical benefits can be

gained by the integration of multiple utili-

ties in a single shared architecture?

The city of Tallahassee in northwestern

Florida combined its electric, water and

gas metering into a single technological

platform as part of its smart metering

project. The intended benefits include

improved access to real-time usage infor-

mation, real-time communication to

customers, an effective platform for its

demand response program and the ability

to offer variable rate strategies to custom-

ers. The system has provided unprecedent-

ed access to account information through

a Web portal, which allows customers to

make informed efficiency decisions con-

cerning their energy use and determine

what aspects are delivering as expected or

what further development is needed.

Tallahassee has a population of 182,000.

Its municipal utility services 87,000 resi-

dential customers and 14,000 commercial

customers with electric service. The city

also serves 26,800 gas customers and

75,600 water customers with some over-

lap among the three utilities. This includes

the city of Tallahassee and a portion of

Leon, Wakulla and Gadsden counties,

which provide a mix of rural and urban

areas. Reading utility meters is a major

undertaking and has been a manual pro-

cess in which meter readers have had to

visit each residence and business monthly.

The city is completing its smart meter-

ing project to roll out a single smart grid

platform for its electric, water and gas utili-

ties to create real-time communications

that can enable a number of programs that

encourage conservation and off-peak usage

of resources. The program enables the util-

ity to more effectively roll out creative pric-

ing programs. For instance, the city has a

large university population and structured

a pricing plan specifically for students. It

supports night and weekend rate plans.

The program also enables the utility to

more easily accommodate solar power

generation by residences and businesses.

The new infrastructure makes it easier

for customers to sell excess solar power

they generate back to the grid. Having all

three utilities owned by the municipality

simplifies creating the single infrastructure

that makes creative programs such as this

possible and lowers the costs of doing so.

PROBLEM/OBJECTIVE

The citys program has three primary

objectives:

1. Provide the utility access to real-time

usage information and communica-

tion to its customers.

2. Provide the utility an effective plat-

form for its demand response pro-

gram and the ability to offer variable

Brian Halcomb is a program manager

with Honeywell Smart Grid Solutions and

manages the West Florida Branch suite of

programs for the city of Tallahassee and

Gulf Power (Pensacola, Fla.). His opera-

tions and project management experi-

ence spans 20 years.

1307PG_18 18 7/8/13 1:05 PM


beyond the city limits into neighboring

counties and, in some cases, this includes

other utility service territories. In some of

these regions, the city provides gas and

water service while another utility, such

as Progress Energy, provides the electrical

service.

Under the new system, the electric

and computer systems to automate the

metering function of all three of the citys

utilities.

The project was budgeted for some $40

million and initially launched in 2007.

Much of the cost was for the metering sys-

tems infrastructure, but the overall proj-

ect included selecting the smart metering

system, training city employees, installing

the system infrastructure and installing

software, including in-home messaging

for customers.

There are two main parts of the system:

advanced metering infrastructure (AMI)

and the meter data management system

(MDMS).

AMI. The AMI includes utility meters

provided by Elster Electricity, a backhaul

network to transmit the meter data and a

central head-end system that collects the

data.

The program involves installing some

213,000 new Elster meters. Each home or

business has separate water, gas and elec-

tric meters. The gas and water meters com-

municate wirelessly to the electric meters.

Each water and gas meter is identified

with a unique serial number that prevents

customers from being accidentally charged

for a neighbors usage.

The electric meters track electric usage

and act as repeaters that accept the data

from the water and gas meters and trans-

mit all the data through the network to the

head end.

They can transmit data on a regular

schedule or on demand. Some enable

the city to connect or disconnect service

remotely.

The meters also can link to central

thermostats or other home automation

systems and provide digital information

displays that customers can read.

There is also a significant direct cost sav-

ings that comes with replacing independent

repeaters with the electric smart meters.

Each independent repeater costs $1,100

and another $3,500 for installation.

One added challenge is that the city

of Tallahassees utility footprint does not

neatly align with the city itself, and it varies

depending on the utilities provided.

In each case, that footprint extends

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implementation challenge was process

change management, including redesign-

ing existing processes and developing new

ones.

Previously, the municipality had three

parallel processes for water, electrical and

gas for most aspects of the business. Each

utility was its own kingdom. The excep-

tion was that billing was centralized across

all three utilities with the PeopleSoft sys-

tem. As a result, beyond simply installing

new meters, the organization was forced

to consider common processes to achieve

the efficiencies it was seeking. This was a

collaborative process with its technology

partner, Honeywell.

For example, customer service sup-

port was significantly affected by the new

metering system. Call center staff needed

to be trained on what new information

customers had access to to be effective

in energy efficiency advocacy and sales.

Customer calls shifted from primarily

billing disputes to questions concerning

energy usage. This requires more robust

communications, situation handling and

data interpretation skills. Call centers can

initiate connects and disconnects rather

than scheduling a service order or truck

roll.

There also were impacts to distribu-

tion field operations personnel, as well, if

somewhat less significant than those facing

the call center.

Most significant was volume, as auto-

mation significantly decreased the size of

the team. Personnel shifted from connect

and disconnect or meter reading to more

complex tasks, such as grid infrastruc-

ture device installation and maintenance,

as well as preventive maintenance. The

full impact of these changes is still being

understood.

Communications to customers was

another part of the program. Information

meters transmit the data, so in those homes

and businesses, the municipality needed a

different source of electricity.

In some cases, it chose independent

repeaters powered by solar panels installed

on a pole some 10 feet in the air.

The city reduced the size of the panels

used from 3.5 feet by 4 feet to 18 inches

by 2 feet to make them less obtrusive.

Before the project, these repeaters didnt

exist. The city and Honeywell designed an

initial basic solution and Elster Electricity

refined the design with a model one-third

the original size.

Solar power worked only for some loca-

tions, however, because northern Florida

is heavily wooded, especially in rural areas.

To complement the solar approach, the

city signed an agreement with cable pro-

vider Comcast Corp. that enabled the

city to install a cable modem and data

collection device in cable system power

supplies.

This solution was used in nearly half

the nonelectric service territory. The city

also had to install 315 backhaul gate-

keepers. The gatekeepers were integrated

with cable fiber (270), city fiber (13) and

wireless (32) backhaul systems. The three

backhaul systems are integrated with the

AMI head-end system. Network creation

remains ongoing.

The city is using city government facili-

ties that have local-area network (LAN)

capability in the first line of backhauling

data, which provides about 5 percent of

network coverage for power of devices and

backhaul of data.

In addition, the city has established

an agreement with Comcast to use cable

modems installed in the power supplies

throughout the service territory to provide

some 90 percent of network coverage for

power of devices and backhaul of data.

The utility also uses cellular modems in

partnership with Verizon Communications

Inc. to provide the remaining network cov-

erage for backhauling data.

Power to the devices is supplied either

from city power at the utility poles or

through solar power.

MDMS and portal. The MDMS is a

separate computer system responsible for

maintaining the metering data, analyzing

it and reporting on the data.

It integrates with other computer sys-

tems and a centralized billing system from

PeopleSoft called a customer information

system (CIS).

This system previously existed and was

the only aspect of the municipalitys utility

infrastructure that already integrated elec-

tric, gas and water.

The MDMS system had to be developed

largely from the ground up in conjunction

with Aclara. This is a critical system for

tying everything together, including the

smart grid platform and existing utility

systems. It is the key point for connec-

tion to the Web portal. It also will include

advanced meter theft analytics. MDMS

work was completed by internal infor-

mation technology staff and third-party

integrators.

The Web portal is called e+ Online,

which is where customers can view their

current and historical bills and usage for

all three utility services plus sewer, solid

waste, fire and storm water services. From

this portal, customers also can pay their

bills, use a rate comparison tool to choose

the best rate for their lifestyles and look

at weather data and consumption. Meter

data is available in 30-minute increments.

Gas and water data are available in hourly

increments.

CHANGE MANAGEMENT

Beyond system implementation,

the training reflected that a significant

1307PG_20 20 7/8/13 1:05 PM


misunderstandings and hurt feelings.

Customers also are affected by the new

smart metering system. Having an excel-

lent customer communication plan is

essential to maximizing customer satis-

faction by providing them with adequate

educational information about the system

and its benefits.

Although the city of Tallahassee enjoys

ownership of all three utilities, it can envi-

sion scenarios in which this is not the case,

and yet a single smart grid system still

could be employed through a partnership

model with other utilities.

All the utilities would benefit by

increasing efficiency around meter read-

ing, improving meter-reading reliability,

enhancing customer service, reducing fleet

costs and lowering labor costs.

was created to help customers understand

why the utility was replacing dumb meters

with smart ones, highlighting benefits to

customers and not just the utility.

OVERCOMING CHALLENGES

Working with internal utility depart-

ments and the technology provider pro-

duced a system that works well, and the

city already is beginning to reap benefits.

The city has reduced overall costs by

requiring a smaller fleet and personnel

pool for reading meters, with meter read-

ing essentially automated. The field ser-

vices department reduced its staff by half,

and a team remains for troubleshooting

and handling connects and disconnects.

In some cases, a lack of available power

presented challenges. Some areas in the

service territory have neither solar nor city

power available, including heavily wooded

locations outside the citys electrical cover-

age area.

The utility is working with the technol-

ogy provider on strategies to achieve full

network coverage for these instances.

One approach might be drive-by auto-

mated meter reading (AMR) rather than a

true smart meter network.

In this case, a truck can drive down the

street to pick up readings. This approach

loses the real-time benefits, but this situ-

ation applies to less than 5 percent of the

service territory.

LEARNINGS, RECOMMENDATIONS

Technology can create many issues that

are not or could not be anticipated.

As noted, the MDMS system had to be

developed largely from scratch. The utility

originally assumed it could rely on an off-

the-shelf system.

A related learning is allowing adequate

time and resources for software revisions.

Bugs and other issues arose and resulted

in a new revision, installation and round

of testing.

None were too challenging to overcome

but delays accumulated.

Having strong partnerships internally

and externally is paramount to working

through the issues and finding solutions.

Significant new technologies create non-

technology people-centered problems.

In particular, implementing a merged

smart grid system will disrupt existing

business processes.

That was true for the city of Tallahassee.

Identifying and modifying business pro-

cesses will require significant interdepart-

mental cooperation. Having a strong part-

nership with a technology provider with

related experience can improve opportuni-

ties to identify and assist with the needed

changes.

It is important to

provide the education

needed to create inter-

nal understanding of

the business process

changes and how

they will benefit other

departments.

This leads to buy in

from employees who

will be affected most

by the system imple-

mentation. Related,

these changes can

drive unmanageable

wish lists as employ-

ees imagine excit-

ing new possibilities

enabled by these new

technologies.

Understand what

the utility needs

and separate the

needs from wants.

This can prevent


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Scenario 1: 100 A, 240/120 V service from existing overhead transformer, 75-foot overhead wire to a service mast.

Scenario 2: 200 A, 240/120 V service, set new pole and transformer in an existing single-phase primary, service 100 feet underground to a meter base.

Scenario 3: 200 A, 240/120 V service, run 200 feet. Underground primary from existing overhead to new padmount transformer, run service to meter base.

Scenario 4: 200 kW demand, 120/208 V service, set riser pole in existing overhead line, run primary 200 feet to a new padmount transformer, three-phase service 50 feet underground.

TYPICAL CREW SIZE BY SCENARIO 1

1: Overhead Service 2: Underground Service 3: Install Padmount andUnderground Service

4: New Riser Pole, Padmountand Underground Service

1 person 2 person 3 person 4 person 5 person 6 person

4

1 0 0

9

4

0 1

2

3

5

2

0

6

5

6

0

2

3 3

0 0 0 1

Benchmarking Results: T&D Crew Size and Equipment Analysis

BY TIM SZYBALSKI, FIRST QUARTILE CONSULTING

First Quartile Consulting (1QC) has

surveyed utility crew productivity

practices as part of its annual questionnaire

for the past five years. One of the factors

for improving productivity is scheduling

the right size crew for the jobpart of the

overall important role played by the plan-

ning and scheduling function.

1QC asked several detailed questions

regarding typical crew sizes and equipment

for different types of jobs. Two approaches

were used to gather crew size data: first,

four detailed scenarios were presented

for jobs of increasing complexity; then a

broader list of work tasks without detailed

descriptions was presented to gather data

on smaller jobs.

The conventional wisdom is that smaller

crew sizes are more productive. Analysis

suggests companies change crew composi-

tion to fit specific tasks. The data suggests

that one-person crews are used for the

simpler overhead jobs but two- and three-

person crews are more the rule for most

underground tasks. Larger underground

jobs generally are still assigned to four-

person crews.

In a post-survey analysis, the most

important finding was the number of trips

to job sites. Crew sizes reported for the

various scenarios varied greatly. For some

of the companies, especially electric-only

utilities, developers or contractors perform

much of the trenching and civil work.

Other utilities use specialty or contract

crews for pole delivery and pole setting.

Benchmarking comparisons are worth

exploring for an individual company, but

1QCs experience shows that many other

factors go into determining the right size

crew: safety requirements, equipment,

union rules, skill sets, use of apprentices,

Tim Szybalski is a director at First Quartile

Consulting, a management consulting firm

that performs consulting and benchmark-

ing services across electric transmission,

distribution and customer service for North

American utilities. Szybalskis career includes

more than 25 years of consulting to utili-

ties and more than 15 years working as

an engineer and manager for SDG&E and

PG&E. He has a bachelors degree in indus-

trial engineering from Stanford University, a

masters degree in operations research from

University of California, Berkeley and a MBA

from San Diego State University. Reach him

at [email protected] or visit

www.1qconsulting.com for more information.

role of working crew leaders, job mix

and travel distances.

CREW SIZES FOR FOUR SCENARIOS

The survey identified four detailed sce-

narios of increasing complexity:

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1. Overhead service (from existing

overhead transformer);

2. Underground service (set new

pole, install overhead transform-

er, and underground riser and

service);

3. New padmount and under-

ground service (from existing

overhead primary); and

4. New riser pole, padmount and

underground service.

Figure 1 shows the number of

companies that send different size

crews for each scenario:

1. Scenario 1 (overhead service).

The most common practice is to

NO. OF COMPANIES WITH CREW SIZE OF N AVERAGE

CREW SIZETASK N=1 N=2 N=3 N=4 N=5

Night Shift Trouble Call Response 12 2 1 2 0 1.4

Line Patrol 11 4 0 1 0 1.4

Day Shift Trouble Call Response 9 3 1 0 0 1.4

Overhead HV Switching 11 5 0 1 0 1.5

Overhead Service Installation 5 9 0 0 0 1.9

Street Light Maintenance 5 5 0 2 0 1.9

Underground HV Switching 3 10 1 0 1 2.1

Underground Fault Location 2 2 2 4 1 2.3

Underground Secondary Cable Repair

2 5 3 3 1 2.6

Underground Primary Cable Repair 0 4 5 4 1 3.1

Set Tangent Pole in Energized Line 0 3 4 8 1 3.4

TASK AND DISTRIBUTION OF CREW SIZE 2

G OR E? SCENARIO 1 SCENARIO 2 SCENARIO 3 SCENARIO 4

Assumption for companies that do not send out digger/backhoe is that trench is dug by developer or contractor

E Single-bucket, reel truck2-person bucket, line truck, 1-ton pickup

2-person bucket, line truck, 1-ton pickup

2-person bucket, line truck, 1-ton pickup

E NAAerial lift truck, single bucket

2 medium trucks, 1 trailer, 1 boom truck

NA

E Bucket truck Bucket truck, boom truck Bucket truck, boom truck Bucket truck, boom truck

E 37 MH 55 MH, CF pickup 55 MH, CF pickup 55 MH, CF Pickup

E Service bucket50 bucket, foreman truck, boom truck, material trailer

NA50 bucket, foreman truck, boom truck, material trailer

E Small bucket Bucket truck, boom truck UG vanOH: bucket, boom truck, UG: van

Assumption for companies that send out digger/backhoe is that they dig their own trench

G&E Bucket Bucket, diggerTrencher, bucket, digger, dump truck, equipment trailer

Trencher, bucket, digger, dump truck, equipment trailer

G&E Service bucket Bucket, digger derrick Bucket, pickup, digger derrickBucket, pickup, cable hog, crane truck, digger derrick

G&E Bucket truck2-person bucket truck, 3 bread vans, 3 pickups, pole truck, digger

2-person bucket truck, 3 bread vans, 2 pickups

2-person bucket truck, 3 bread vans, 2 pickups

E Small bucket Aerial bucket, digger derrick Aerial bucket, digger derrick Aerial bucket, digger derrick

G&E BucketBucket truck, trencher or backhoe

Bucket truck, trencher or backhoe

Bucket truck, trencher or backhoe

E Bucket Bucket, digger 2 buckets 2 buckets, digger

E Bucket service truck 55 bucket, digger 55 bucket, digger 55 bucket, digger

G&E 1- or 2-person bucket2-person bucket, line truck, backhoe

2-person bucket, line truck, backhoe

2-person bucket, line truck, backhoe

G&E Bucket Bucket, digger Bucket trailer Bucket, digger

EQUIPMENT ASSIGNED TO WORK TASKS 3

E = Electric utility and G = Gas Utility

1307PG_23 23 7/8/13 1:05 PM


appears the companies that did not report

diggers and backhoes relied on developers

or contractors to do the work. These

tended to be the electric-only companies

as shown in the first column. The detailed

results for the scenarios are shown in

Table 3. The detail for additional tasks is

available but not reported here.

Table 4 shows the types of equipment

being sent to the job site for each scenario.

A company different than the norm

might investigate differences in practices.

One key driver is the use of developers

of contractors to do the trenching work.

Another area to investigate is the number

of trips and timing of specialized crews

or pieces of equipment for trenching and

material delivery.

The survey was designed to find the

answers to Whats the right number of

people? and Whats the right type of

equipment for the job? There isnt one

right answer. Variables include whether

the company relies on developers

or contractors to do the trenching;

whether equipment is delivered to the

job site; and how safety concerns affect

staffing decisions. This crew size and

assigned equipment analysis is valuable

to companies that are interested in

exploring their crew practices and

evaluating their positions compared

with peers. If a companys typical crew

is wildly outside the norm, then that

is a flag to look for an opportunity for

improvement.

send a two-person crew, followed in

preference by a one-person crew.

2. Scenario 2 (underground service).

The results were mixed; a four-per-

son crew was most common but

varied from two to five, depend-

ing on trenching work done by the

developer or contractor.

3. Scenario 3 (install padmount

and underground service). Both

three- and four-person crews were

predominant, although three com-

panies are using five-person crews,

again depending upon the work

done by others.

4. Scenario 4 (a more

complex job). The

four-person crew

was the most used,

although the crew

sizes ranged from

two to six. Several

companies relied

on pole setting or

pole delivery crews that were not

reported in the data.

A few data points were omitted. One

company reported a one-person crew who

acted as inspector for contractor crews.

Another company reported the cumulative

number of employees who went to the job

site (an interesting benchmarking number

but not consistent with other reporting).

The survey also asked for employee

classifications. The typical larger crew had

a mix of journeyman, apprentice, working

foreman and other. None reported non-

working foreman. This information might

be useful to a company that wants to know

why its crew sizes are different than other

companies crew sizes.

CREW SIZES FOR BROADER

LIST OF WORK TASKS

The survey also asked about crew

sizes for a broader list of work tasks.

The average crew size and number of

companies reporting each crew size are

provided for the following tasks. Table

2 is sorted from top to bottom based

upon the average crew

size (which ranges from

1.4 to 3.4).

Going down the chart,

the average crew size

increases with job com-

plexity, although there

are variations among

companies. The tasks at

the top tend to have one-person crews,

those in the middle have two-person

crews, and the largest tasks have three-

or four-person crews. The same caveats

about differences in work done by

developers, contractors and specialty

crews still apply. A company could use

this table to identify where its practices

differ from other utilities practices.

EQUIPMENT ASSIGNED

TO DIFFERENT JOB TYPES

The survey also asked for types of

vehicles assigned to different job types

for all the scenarios and the broader list

of tasks. The detailed results of the four

scenarios illustrate the range of practices,

equipment types and nomenclature

received. A significant difference was

whether companies reported using

diggers, backhoes or both. Based upon

conversations with selected companies, it

EQUIPMENT SCENARIO 1 SCENARIO 2 SCENARIO 3 SCENARIO 4

Aerial lift truck 14 14 11 14

Line trucks/UG vans 0 1 4 6

Digger derricks/backhoes/trenchers

0 8 4 5

Medium truck 0 0 2 1

Passenger vehicles 0 3 1 5

NUMBER OF COMPANIES USING EACH TYPE OF EQUIPMENT FOR EACH SCENARIO

4

The typical larger crew had a mix of journeyman, apprentice, working foreman and other.

1307PG_24 24 7/8/13 1:05 PM

JAN. 28-30, 2014

HENRY B. GONZALEZ CONVENTION CENTERSAN ANTONIO, TEXAS

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1900

1906

1912

1918

1924

1930

1936

1942

1948

1954

1960

1966

1972

1978

1984

1990

1996

2002

2008

300

240

180

120

60

0

100

80

60

40

20

0

Quanti

ty

Cum

ula

tive

%

Year

TRANSFORMER AGE PROFILE 1

98.7 Percent of Units With Age Data

Median Age: 34

Mean Age: 33

Units WithoutAge Data

TxD

DxD

Asset Management

Data, Analysis & Decisions

BY DON ANGELL, TONY MCGRAIL AND KENNETH R. ELKINSON, DOBLE ENGINEERING CO.

age of a unit is not necessarily a good

indicator of transformer reliability.

Much more attention should be given

to design, manufacturer and service

history.

There is dawning realization in the

electric power industry of the

value of applying formal asset manage-

ment principles.

Such an approach, as embodied in

the British standard PAS-55 and the

incipient international standard ISO

55000, enables the institutionalization

of asset management best practices and

consistent outcomes in this era of aging

work force and ever-greater demands

on the assets.

In this context, the use of asset health

scoring as a condition assessment tool

and condition- and criticality-based

ranking of the fleet as a template for

asset management is gaining currency.

It is vital for utilities to rapidly spot

underperforming or potentially failing

assets.

Access to offline test data, online

monitoring and synthesis of the result-

ing monitoring data with operational

and asset historical data provides the

backbone for action planning and

Documents

Power Grid International July 2013