power grid international july 2013
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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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PowerGrid International: ISSN 1547-6723,
is published 12 times per year (January,
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2 | July 2013www.power-grid.com
14
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.
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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
918.831.9504 [email protected]
SENIOR EDITOR Kristen Wright
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ASSOCIATE EDITOR Jennifer Van Burkleo
918.832.9269 [email protected]
ONLINE/ASSOCIATE EDITOR Jeff Postelwait
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GRAPHIC DESIGNER Deanna Taylor
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phone 847.559.7501 fax 847.291.4816 [email protected]
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Richard Baker 918.831.9187 [email protected]
PENNWELL CORP. IN EUROPE PennWell International Limited
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phone +44.1992.656600 fax +44.1992.656700
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PRESIDENT/CEO Robert F. Biolchini
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Phone 918.835.3161 Fax 918.831.9834 [email protected] http://pennwell.com
POWERGRID International is the offcial publication of
4 | July 2013www.power-grid.com
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
6 | July 2013www.power-grid.com
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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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
Go to http://pgi.hotims.com for more information.
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NOTES
12 | July 2013www.power-grid.com
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
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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
Go to http://pgi.hotims.com for more information.
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14 | July 2013www.power-grid.com
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
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July 2013 | 15 www.power-grid.com
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.
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16 | July 2013www.power-grid.com
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
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Thinking Smart Grid ?
Go to http://pgi.hotims.com for more information.
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18 | July 2013www.power-grid.com
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.
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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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20 | July 2013www.power-grid.com
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
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July 2013 | 21 www.power-grid.com
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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22 | July 2013www.power-grid.com
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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July 2013 | 23 www.power-grid.com
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
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24 | July 2013www.power-grid.com
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
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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