Intelligent Utility Jan-Feb 2013

VOL 5, ISSUE 1 » JANUARY/FEBRUARY 2013 Where smart grid meets business—and reality. 

ALSO 

INTRODUCING OUR 

INTERNATIONAL 

SECTION 

Duke reveals DMS details 

NRECA, DMEA, MVEC 

examine GIS 

Experts divulge smart grid 

lessons from Sandy 

AN ENERGY CENTRAL PUBLICATION 

» WWW.INTELLIGENTUTILITY.COM

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WWW.INTELLIGENTUTILITY.COM /// JANUARY/FEBRUARY 2013 

2 

CONTENTS 

COVER // JANUARY/FEBRUARY 2013 

Input on the European market rollout and how it impacts 

consumers internationally from our London correspondent. 

See page 20. 

FEATURES // OPERATIONS 

8 Distribution management 

systems: Transforming the 

electric utility industry 

+ Duke discusses their new DMS system 

and advice for other utilities working 

on the same projects 

12 GIS evolves into backbone 

for cooperatives 

+ NRECA, DMEA, MVEC talk about the 

unexpected positives from dumping 

paper maps 

16 Sandy and the smart grid: 

Who won? 

+ A hurricane inspires industry discussion 

Vol. 5, No. 1, 2013 by Energy Central. All rights reserved. Permission to reprint or quote excerpts 

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20 

8 

16 

24 

32 

40 


SPECIAL REPORT 

GRID DATA + ANALYTICS 

32 

34 

What’s happening in 

the post-smart grid world 

Southern Co. Oncor 

discuss details 

Got GIS? You’ll need it 

to maximize analytics 

One thread woven across 

many applications 

DEPARTMENTS 

4 

Drawing the line 

6 IntelligentUtility.com 

20 International 

20 Making dumb 

European rollouts smart: 

Three golden rules of 

consumer engagement 

24 

27 

38 

40 

Customer focus 

24 Customer service requires 

collaboration, innovation 

25 Knowledge Summit kicked 

off with talk of customers, 

utility renaissance 

IT insights 

27 The DOE reaches out 

to utilities with 

cybersecurity model 

28 IT lessons from 

utilities revealed 

Top 5 

38 KITE winners look at 

utility challenges for 2013 

Out the door 

40 Focus on interoperability 

as only a part of the smart 

grid whole


DRAWING THE LINE 

4 

Face facts: The smart grid 

will never be finished 

WHEN THINGS ARE DIFFICULT AND COMPLICATED, WE OFTEN JUST WANT THEM 

to be over. In school, it was the next big test. At work, it’s the annual reviews or the large, 

complicated, interdepartmental projects. We try to think out all the steps to the final outcome, all 

the ways to get to the end a little bit faster. We want to be finished. 

We’re list makers and list finishers. And nothing feels quite so good as marking an item off the 

list. Done. Finished. 

We think this way around technology as well. 

Pat Gallagher, the director of the Department of Commerce’s National 

Institute of Standards and Technology (NIST) faced this very human, very 

American desire for completion in the smart grid arena. At Grid-Interop 

2012, he told the story of a regulator asking him, a few months into the gig, 

when this smart grid stuff would all be finished. 

And he said, after a bit of a pause, “Never.” 

The smart grid isn’t a test. It isn’t a review or a project. It isn’t a new 

technology we can choose to learn (or not learn, as the case may be). As 

the diet books all also proclaim, it’s a lifestyle change. Or, to quote REM, 

“It’s the end of the world as we know it.” (But, don’t worry, you’ll feel fine.) 

The smart grid can’t be over because it’s not finite. It’s organic and not 

pre-planned. It’s amorphous and not fully formed. It’s porous and not solid. 

When we started introducing smart grid technology into utilities, we may 

have been working under the delusion that there was an end in sight: when 

all the smart meters are in, when we switch from paper maps to GIS, when 

we get a better handle on outage management. 

But, the truth is: Smart grid grows. We start to realize interconnections that we never saw before, 

ways to use information and data that are new and useful, updates that weren’t possible five years ago. 

Some of these smart grid “growth spurts” are discussed in this issue. We look at how GIS has pushed 

into other networks for cooperatives. We examine the lessons smart grid can learn from Sandy. We 

explore standards, IT and customer service innovations that are interconnected. And, we look at how 

utilities will continue the smart grid push into other systems. 

It is now all interconnected, and it is now all smart grid. And, those growth spurts will not stop 

anytime soon. So, no more talk of finished. Instead, let’s talk options, lessons, new concepts. 

Now, read all about it so you can cross that item off your to-do list, at least. 

Kathleen Wolf Davis 

Editor-in-Chief, Intelligent Utility magazine 

kdavis@energycentral.com 

Enjoy the issue? Then 

subscribe for free at 

www.intelligentutility.com/ 

subscribe

Smart grid projects 

can be deceiving. 

The ultimate Smart Grid vision 

portrayed by many still remains 

nothing but a panacea. If you 

are interested in a practical, 

pragmatic vision of the Smart Grid 

and need your vision successfully 

realized, make us your partner. 

If you want results instead of reports 

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Smart Grid strategy which is sustainable 

both post implementation and year 

after year, make us your partner. 

We’ll help you plan and execute 

a realistic yet sensible vision of your 

Smart Grid strategy beyond smart 

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Join the large number of utilities 

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realizing their true Smart Grid vision. 

We’ll help you navigate 

the unforseen. 

osii.com 

© 2013 Open Systems International, Inc. All rights reserved.


6 

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OPERATIONAL 

PERSPECTIVES 

8

DISTRIBUTION MANAGEMENT SYSTEMS 

Transforming 

the electric 

utility industry 

By Steve Russell 

DICTIONARY.COM DEFINES THE INFORMATION 

Age as a period “characterized by the gathering and 

almost instantaneous transmission of vast amounts of information.” 

The development of the distribution management 

system (DMS) will enable the electric utility industry to 

take advantage of the unprecedented data and technological 

advances of the information age resulting in better management 

and optimization of distribution grid performance. 

Historically, distribution operations have been 

characterized by: 

? ? The manual operations of devices by field personnel. 

? ? Local operation of devices by control panels config- 

ured to largely operate independent of one another. 

? ? Operational processes based on past practices and a 

fixed circuit topology. 

? ? Operating parameters based on calculations and 

approximations focused on peak loading. 

? ? Data spread across multiple databases using various 

storage media including computer-based storage as 

well as hard copy. 

While these approaches have served the electric utility industry 

well for over a century, there are inherent limitations 

contained in these practices, which DMS enables, that offer 

significant benefit to both the customer and utility. 

At first glance, the advanced control functions most frequently 

discussed in conjunction with DMS would appear 

to be its greatest strengths. 

The ability to manage and optimize voltage and VAR 

flow through volt/VAR control (VVC) and the ability to 

automatically locate faults and develop switching solutions 

to minimize outage footprints via fault identification and 

service restoration (FISR) form the basis for the benefits 

made possible by DMS. While both functions generate tremendous 

benefit for customers and utilities alike, the real 

transformative power of the DMS is contained in the system 

model and the continuous, near real-time power flows that 

DMS generates. 

The heart of a DMS is the data model of the distribution 

system. Two types of data are required for the DMS to 

accurately represent near real-time conditions for the 

system: static and operational. 

Static system data is data that describes the distribution 

system over an extended time frame. Updates to this data 

tend to be long-term in nature and are generally considered 

permanent. This data includes information from the GIS for 

the distribution connectivity model, system configurations 

and land base to represent the distribution lines, as well as 

substation internal connectivity to model substation connectivity 

and configurations. Additionally, relay settings and 

system impedance data are required along with component 

and facilities ratings, equipment impedances and ratings, 

and device settings from reclosers, capacitors and regulator 

control panels. Finally, the DMS could not run near realtime 

load flows without customer information regarding 

customer count, load data and load schedules. 

WWW.INTELLIGENTUTILITY.COM 9

OPERATIONAL 

PERSPECTIVES 

WWW.INTELLIGENTUTILITY.COM /// SEPTEMBER/OCTOBER 2012 

10 

During the nightly model build process, static system 

data is used to create the DMS data model for the next day. 

Updates that occur on a regular basis, such as GIS updates 

are reflected each night. Updates that occur less frequently, 

such as relay setting changes can be updated on a periodic 

or as needed basis. 

Operational data, on the other hand, is short term and 

generally considered to be temporary changes. Operational 

data frequently deals with changes to connectivity or equipment 

settings in response to system conditions or fieldwork. 

This typically includes device status changes, the opening or 

closing of switches, or the installation of temporary jumpers 

or grounding sets. Operational data is generally entered 

directly into the DMS by distribution system operators or 

updated automatically by the outage management system. 

When combined with actual, telemetered data from 

SCADA devices for error correction, the DMS data model 

using both static and operational data forms the foundation 

necessary for the DMS to perform near real-time power flow 

calculations and analysis that reflect the current conditions 

on the system. These power flow calculation then enables the 

optimizations advanced functions such as VVC and FISR. 

VVC and FISR each provide significant near-term 

benefits that utilities can use to build business cases for 

DMS implementation. However, in the long run, flexibility 

and adaptability, particularity as they relate to the development 

and realization of advanced functions and optimizations, 

are critical to leveraging the investment in DMS 

and fully realizing the potential DMS represents. With this 

in mind, the following are key considerations for a utility 

considering a DMS: 

? ? Does the DMS possess sufficient data modeling 

capability to support the development and growth 

of advanced functions? 

? ? Does the DMS possess the broad-based power flow 

and analytical capabilities necessary to support the 

initial optimization algorithms as well as develop- 

ment and growth for additional advanced functions? 

? ? Does the underlying architecture support the ability 

to grow and expand, and does it have the scalability 

to accommodate the data and telemetry associated 

with an electric distribution system? 

? ? Does the DMS have sufficient initial functionality to 

support the business case required to deploy such a 

system, or is the DMS focused on a single function? 

? ? Is there a commitment from management to 

address data quality including the initial clean-up 

and implementing the processes necessary to main- 

tain the data? 

? ? Are there plans to deploy field devices to actuate 

the DMS controls? 

? ? DMS is complex software; do the vendors involved 

have the experience and technical resources to sup- 

port the initial implementation, as well as the devel- 

opment of additional advanced functions? 

As Duke Energy has worked through the implementation 

of its DMS, several lessons learned have emerged that other 

utilities may benefit from considering: 

? ? Strong executive vision and sponsorship are essen- 

tial to the success of the project and requirements to 

successfully initiate the project. 

? ? Strong management support, at all levels, is required 

to complete the implementation and realize the 

expected benefits. 

? ? The implantation of a DMS will result in significant 

change across the organization; so change manage- 

ment and communication are critical and must be 

built into the project plan. 

? ? The DMS is as much an IT project as it is a business 

project; so joint business and information technol- 

ogy leadership are required for success. 

? ? DMS will drive both GIS support and IT to become 

operational partners with the business rather than 

their traditional roles of back office support. 

? ? Establishing a viable data model that address- 

es both initial data clean-up and on-going data

management is essential, and this may require its 

own project separate from the DMS. 

? ? A project team staffed with active distribution op- 

erations personnel aids implementation and eases 

the burden of changes. 

? ? A skilled project team with an operational focus is a 

key to success. 

? ? A phased approach to deploying the DMS func- 

tions into the operations group helps to mitigate 

change management. 

? ? Testing with operational scenarios and pilot- 

ing DMS functions in operations can be 

used to build confidence in the system while 

verifying functionality. 

? ? New operating strategies to clearly delineate trans- 

mission, and EMS control, from distribution and DMS 

control, are required but not always easy to achieve. 

? ? Operator roles will change potentially creating 

staffing challenges, particularly as it related to 

skill sets. 

? ? Agreement to use standard software with minimal to 

no customizations will simplify the project. 

A breakthrough in Smart Grid performance. 

Callisto delivers the answers that electric, gas, and water utilities 

require to improve grid performance and manage their operations 

more efficiently. Our Grid Performance System includes: 

? ? Agreeing on a standard design and configuration 

across all user regions will also simplify the project. 

? ? Implementing a clear technical environment strat- 

egy and change control policy is required. 

? ? Regulatory considerations and uncertainty must 

be considered. 

• Groundbreaking, customizable user interface tailored to each customer 

• Standard notification and analytics capabilities for outage, voltage, 

transformer monitoring and theft, at no additional cost 

• “Stackable Answers” that provide the ability to upgrade functionality and 

enable the lowest total cost of ownership in the industry 

Built on Elster’s proven solutions – with more than 100 operational systems, and 

a wealth of experience working with utilities, Callisto and our exceptional support 

teams will exceed your expectations. You have questions? Elster Answers. 

Call 919.212.5067, contact sales@us.elster.com or visit Elster.com for more information. 

? ? Establishing and maintaining a strong vendor/user 

relationship is essential. 

VVC and FISR are just the beginning of what DMS can 

do to benefit customers and utilities for decades to come. 

With an accurate data model, SCADA telemetry and power 

flows, the DMS has all the ingredients necessary to support 

virtually any conceivable optimization algorithm to manage 

the system. These elements are what set the DMS apart from 

other systems and applications, and establish the DMS as the 

strategic platform needed to enable growth and the development 

of future functionality necessary to transform the 

electric utility industry. 

Steve Russell is Duke Energy’s grid modernization DMS project 

manager. He has been with Duke Energy for nearly 30 years, serving 

in a variety of roles, including engineering, operations, construction, 

finance, forecasting, scheduling, outage management, metering and 

corporate compliance and ethics. 



OPERATIONAL 

PERSPECTIVES 

12 

IS 

evolves 

into backbone 

for cooperatives 

By Kathleen Wolf Davis 

A DECADE AGO THE INDUSTRY ACRONYM GIS 

brought to mind gas-insulated switchgear. Today, 

gas-insulated switchgear runs a far second to geographic 

information systems (or geospatial information systems) as 

the definition of that acronym. This modern GIS has transformed 

the utility landscape from traditional to cuttingedge, 

especially with cooperatives. 

Originally put in place simply to replace old books and 

paper maps, GIS now benefits from an operational “creep” 

into other systems. Once the advantages became obvious, 

the uses for GIS began to multiply. 

“From an operational standpoint, GIS is the backbone 

for anything that has to do with mapping,” said Brad Hicks, 

principal transmission and distribution engineer for the 

National Rural Electric Cooperative Association (NRECA). 

“It’s used for a visual representation of their electric systems, 

but also for outage management, asset and vehicle tracking, 

rights-of-way maintenance and electrical models.” 

Steve Metheny, assistant general manager with Delta- 

Montrose Electric Association (DMEA) a cooperative 

in Colorado, put it eloquently: “A system designer can 

design expansions without leaving the office in some cases. 

A dispatcher can look at structure type and advise appropriate 

repair materials in advance. An engineer can more 

accurately model the electric system for reliability and 

performance enhancements. Outages can be handled much 

more expeditiously.” 

In six simple words: GIS has made almost every- 

thing easier. 

Where GIS works now 

GIS all started with a conundrum about paper maps. 

“With paper maps, the crew’s maps were outdated 

the day after they were printed and remained 

that way until new map books were printed the following 

year,” said Jeremy Richert, director of engineering 

with Maquoketa Valley Electric Cooperative 

(MVEC), which provides electric service to over 14,000 

members across 3,100 miles of line in and around 

Anamosa, Iowa. 

So, along came GIS, which updated those maps, but GIS 

also allows a number of other benefits, such as smarter, more 

up-to-date hardware and software management. Utilities 

now know—in many cases for the first time—what’s old, 

what’s new, what’s reaching the lifetime limit, what should 

last another 50 years. 

Hicks added, “From an asset management standpoint, 

GIS allows utilities to know every nut, bolt and washer installed 

in the field, which helps with inspections by creating 

a history of issues found and repairs made.”

“ 

Knowing those issues can be vital if a cooperative has 

borrowed money for equipment. There are detailed guidelines 

on inspecting equipment for U.S. borrowers, and those 

guidelines require documentation. So, the GIS serves as a 

repository for this vital inspection 

data, keeping all of it in a 

With paper maps, 

central location. 

But, centralization isn’t the only 

the crew’s maps 

benefit of GIS. On the opposite 

end of the spectrum, the mobile 

were outdated 

aspect of GIS is just as valuable, 

according to Richert and Metheny. 

the day after they 

So, GIS has made the lives of 

field crews significantly easier, 

were printed ...” especially in outage situations. 

Dispatchers now know where 

the crews are in the field and which crew is closest to the 

outage. More significantly, GIS can track a utility’s best 

asset: the consumer. 

Hicks revealed that a utility he worked for prior to his 

current stint with the NRECA has the GIS tied into the accounting 

system with map locations associated with customers. 

In a single-case scenario, the consumer calls in an 

outage, the outage management system (OMS) answers the 

call, identifies the phone number and links it to an account 

number (which is automatically linked to a map location 

number, resulting in the location popping up on the map). 

Additionally, if multiple consumers call in, the system can 

roll up the data together in a bundle along with asset and 

map information and predict locations for the outage. If, 

for example, five people on the same single-phase line call 

and report an outage, the system could predict the nearest 

up-line device with a problem, such as a fuse or a recloser. 

That’s invaluable, active, immediate information that would 

have taken much longer before this positive GIS creep across 

utility systems. 

At MVEC in Iowa, the utility has a real-time interface between 

GIS and the customer information system enabled by 

NRECA’s MultiSpeak standard, allowing up-to-date consumer 

details to be available to crews in the field. Along with 

the consumer connection, the GIS interfaces with several 

other utility subsets: electronic staking, system engineering 

model, outage management system, AMI, mobile mapping 

for both field and office use, automated vehicle location. 

At DMEA in Colorado, the GIS system is being utilized 

to design new facilities, model existing and planned facilities, 

and help troubleshoot during outage or during other 

operational issues. Additionally, DMEA is using GIS to locate 

faults using short-circuit data (fault currents) from 

substation devices immediately after events to create more 



OPERATIONAL 

PERSPECTIVES 

14 

GIS SNAPSHOTS 

One of a utility’s old 

paper maps as an 

example. 

Using the dashboard, 

a utility can find faulty 

equipment before it 

fails and causes an 

unplanned outage. 

accurate maps with impedance information and to help 

employees pinpoint areas needing repairs. 

“Co-ops are always looking for multiple ways to use 

equipment and information,” Hicks said. “GIS has really 

fit that bill perfectly, becoming vital to so many parts of 

the cooperative.” 

Where GIS is headed in the future 

Richert noted that today’s GIS systems “play a significant role 

in the automation of tasks that used to be done manually.” 

Richert considers Maquoketa Valley’s GIS system the center 

of the utility’s technology hub that interfaces with many other 

software packages. Metheny says the same about DMEA. 

Overall, GIS has made a huge impact on models for cooperatives, 

and Hicks expects that to grow even more over the 

next few years. 

“A high percentage of co-ops use a model based off of 

their GIS,” he noted. “I think there will be more emphasis 

put on that modeling connection, especially with the accuracy 

of the GIS and its use for connectivity.” 

Unless a cooperative has a supervisory control and data 

acquisition (SCADA) system with communications all 

This section (from a 

GIS used by a utility’s 

mapping application) 

shows where lights 

were added in an area. 

A GIS dashboard provides 

an outage overview that 

keeps management, the 

communications department 

and customer service 

representatives aware 

of how many and which 

customers are out of power. 

This screenshot 

shows poles to be 

inspected in green. 

Courtesy of ESRI. 

the way down the line, which would allow for complete 

system monitoring, modeling is essential. (Richert noted 

that MVEC has their GIS connected to SCADA with 

results displayed graphically including highlighting line 

sections where problems are likely to have occurred based 

on information recorded by SCADA. This process is completed 

within a couple of minutes, significantly reducing 

outage times.) 

Typically, a SCADA system is only monitoring substations 

and a few key locations on the distribution system, approximately 

10 to 20 values or points. That leaves a lot of gaps. 

Modeling works in those gaps, and, with a detailed field 

audit done first, a good GIS system can make modeling a lot 

closer to monitoring than guesswork. 

Richert said that MVEC falls under Hicks’ category of coops 

using their GIS for modeling. That modeling helps with 

engineering system studies in the areas of construction work 

planning, long-range planning, sectionalizing studies and 

arc flash studies. 

“The GIS creates the connectivity model that is the centerpiece 

of the cooperative’s outage management system,”

WHAT ADVICE WOULD YOU GIVE UTILITIES 

ON THE IMPLEMENTATION AND USE OF GIS? 

BRAD HICKS, NRECA // Spend the time and the money to gather 

the data. Don’t base your decisions and your design off of a 

paper map. If you spend the time to go out and do a field audit, 

you’re not only gathering data for the GIS, but you’re taking 

the time to get to know the details. Be aware of the fact that 

the paper maps are outdated. Things were removed or added 

that may not have gotten posted. That’s the key to getting it 

right. It’s much more difficult to correct errors after the fact. Do 

the audit first. 

JEREMY RICHERT, MVEC // Make sure to have the staffing resources 

available to maintain the GIS and keep it current. If used prop- 

erly, it is a critical component of a cooperative’s technology sys- 

tem, and it needs to be maintained so that all systems can oper- 

ate accurately and efficiently. Too many co-ops use the GIS only 

for maps and don’t maximize all that a GIS system has to offer. 

STEVE METHENY, DMEA // Learn from others before you. Answer 

the questions of the problems you are trying to solve in 

advance: How detailed do you want your inventory to be? While 

you are there, what other information could/should be collect- 

ed and how will it be used in the future? More importantly, how- 

ever, is how will all the system inventories be updated? It takes 

a lot of effort, but once the system is integrated and properly 

updated, it can be a tool that becomes essential in serving the 

electric customers. 

he commented, revealing that the outage management system 

helps MVEC manage and dispatch crews during outage 

events more efficiently. What used to take eight people now 

takes two or three. 

Hicks added that, at the utility he worked for, they would 

use GIS and their electrical model in tandem, plugging information 

into the model to reveal locations on fault current, 

issues and outages, as MVEC is doing. 

“For utilities that have GIS, this is a typical practice. 

For the ones that don’t, these are the benefits they long for,” 

he said. 

Along with GIS growing more in the modeling arena, 

Hicks revealed the possibility of GIS tying into advanced 

metering infrastructure (AMI) systems, allowing for automated 

notification of meter outage for dispatchers and crew. 

DMEA is hoping to accomplish that in the next five years, 

according to Metheny, along with a connection to the meter 

data management system to allow for customer interaction 

on usage information. 

MVEC’s GIS is already AMI connected. According to 

Richert, to ensure AMI readings are using the appropriate 

communication path comparisons are done daily between 

the AMI database and the GIS polygon information to ensure 

all meters are communicating off of the proper device. 

The utility is alerted if there is a change, and that notification 

can be especially helpful when putting in new meters. 

The GIS model is also used with AMI to automatically ping 

potentially affected meters when a system disturbance is 

recorded by the SCADA system. The results are displayed 

graphically on the GIS map viewer, and, in many instances, 

crews can be dispatched to the outage prior to receiving a 

call from the member. 

For MVEC, Richert anticipates enhanced mobile workforce 

applications for GIS, bringing even more system information 

into the truck for field crews: SCADA, AMI and outage 

management all on the same digital map. Additionally, 

he sees GIS playing a larger, more central role in assisting 

with implementation and oversight of system maintenance 

programs (vegetation management, pole treatment, equipment 

maintenance, facility upgrades). 

Returning from what could be to the here and now, 

Richert labels the most important feature of GIS as the 

ability to produce a map that helps operate the system in 

a safe and reliable manner—no different than the primary 

role of paper maps before GIS. Beyond this primary 

mapping function, significant benefit comes from the GIS 

connectivity model and its ability to interface with other 

software packages. 

“The GIS model and database play a major role in how 

technology is used at Maquoketa Valley,” he said. “We’ve 

been able to use it to improve day-to-day operating efficiencies 

and greatly improve service reliability to members. 

With the help of technology, MVEC has reduced outage time 

to members by 38 percent over the last 14 years. Without 

a functioning GIS system, our ability to take advantage of 

technology offerings would be severely limited.” 

At DMEA, it’s the hub concept that ranks highest—the 

use of GIS to tie the plant, the customer and the electric system 

together accurately, with timely updates and an intuitive 

graphical user interface. 

First and foremost for NRECA’s Hicks, outage management 

is GIS’ crown jewel; no other system impact is more 

important in his mind. 

“If the meters aren’t turning, revenue isn’t being generated, 

reliability goes, and the consumer isn’t happy,” he 

said. “The opportunity that co-ops have to fine-tune member 

restoration, that is one of the most important features 

GIS brings.” 

Jessica Wyland at ESRI and Tracy Warren at NRECA contributed to 

this story; ESRI supplied the artwork. 



OPERATIONAL 

PERSPECTIVES 

16 

SANDY AND 

THE SMART GRID 

WHO WO 

A hurricane inspires industry discussion 

By Phil Carson 

AS HURRICANE SANDY MADE LANDFALL along 

the New Jersey shore at 8 p.m. on Monday, Oct. 

29, its storm surge and 80 mph winds submerged power 

substations and underground power lines, knocked down 

trees, flattened homes, ignited fires and spread chaos. 

Communication systems and transportation were severely 

compromised, if not stopped. 

Utilities in the storm’s path had taken traditional precautions, 

arranging for field crews from outside the region, 

shutting down parts of the grid as the storm hit to avoid 

worse damage and monitoring damage as it occurred to inform 

a restoration strategy. 

One potential bright spot: Along with its destruction, 

Hurricane Sandy brought renewed attention to the critical 

nature of electricity in a digital economy and the challenges 

of infrastructure hardening and resilience for the 21st century. 

And the grid had company: the devastation included 

infrastructure for water and natural gas systems, transportation 

and communication. 

The upshot for power 

Long before storm waters receded or utilities filed their major 

incident reports to regulators, storm-inspired discussions 

turned to the role of the smart grid in the event. Did 

smart grid systems assist before, during or after the storm? 

Anecdotes abound but solid answers will take time. (This 

article went to press a mere 30 days after the storm struck, as 

restoration work continued.) 

Scrutiny of smart grid functionality and costs is likely to 

increase, just when greater long-term investments are urged

N? 

Hurricane Sandy envelopes the East Coast. Courtesy of the National Oceanic and Atmospheric Administration. 

by power sector players. Jeff Lewis, who heads the global energy 

consulting practice at PA Consulting Group, which is 

tracking utility performance during Sandy, tried to put the 

matter into perspective. 

“Damage to physical assets was severe,” Lewis said. 

“Obviously if a bunch of trees come down, the effectiveness 

of schemes of smart technology such as sectionalizing and 

automated restoration is quite limited.” 

Smart grid, so far 

“Such risks are going to persist and we’ll see more and more 

extreme events, more variability will hit our systems and 

infrastructure,” said Massoud Amin, an IEEE senior member 

and a professor of electrical and computer engineering 

at the University of Minnesota, where he also serves as 

director of the Technological Leadership Institute. “This 

brings a wider range of uncertainty to future events. This is 

both a local challenge and a regional and national opportunity 

to upgrade and harden the system.” 

Now, to “the system.” Advanced metering infrastructure 

(AMI) and distribution automation (DA) remain the most 

widely deployed smart grid technologies, along with geographic 

information systems (GIS) and outage management 

systems (OMS). All four technologies have been touted to 

regulators and customers as contributing to outage detection 

and self-healing, as well as customer notification of estimated 

time to restoration (ETR). But these systems present 

integration challenges. And, currently, fully integrated smart 

grid systems are a rarity. 



OPERATIONAL 

PERSPECTIVES 

18 

“ 

According to Arshad Mansoor, a senior executive with the 

Electric Power Research Institute (EPRI), full integration of these 

systems—with data analytics running on top—is a multi-year, 

multi-hundred-million-dollar proposition for any large utility. 

“It’s not just system integration but you need business 

analytics running on top of all this,” Mansoor said. “Those 

analytics do the ‘circuit chasing’ for you.” 

(“Circuit chasing” is the act of assembling known enduser 

outages into a pattern that indicates a malfunctioning 

asset upstream, a process once—and still—initiated by customer 

phone calls.) 

According to Mansoor, well-integrated systems with analytics 

can identify the critical juncture where field crews 

need to go and, he noted, the accuracy of field crew dispatch 

has a major effect on restoration time. 

The last integration piece, Mansoor’s “holy grail,” is a 

work management system that would automate accurate 

field crew dispatch following 

the analytics work. 

In the past century “Fuller integration is 

where we’re headed,” 

we had to run the Lewis agreed. 

distribution system Work has just begun 

“Will regulators allow the 

blind, and now we right levels of expenditure 

for integration and ana- 

are blinded by data.” 

lytics?” Mansoor asked 

rhetorically. “They cost 

much more than meters 

do. That’s a difficult sale. But we’ve got to do it. To us, the 

value of smart grid becomes fully realized when this level of 

integration, with the right analytics, is baked into a system.” 

“How you handle data is a huge undertaking,” Mansoor 

said. “In the past century we had to run the distribution system 

blind, and now we are blinded by data. I’d say we’re only 

at the early stages. We’ve only just installed our sensors.” 

Hardening and resiliency 

“At EPRI we see a three-pronged approach to resiliency,” 

Mansoor continued. “First is hardening—undergrounding, 

vegetation management, substation vault design. Second is 

recovery—identifying the location of damage, isolating the 

damaged portion and restoring it. The third prong is survivability, 

which is the least-resourced area. We must assume 

that infrastructure can never be technically or cost-effectively 

feasible to withstand everything that Mother Nature or a 

human act can throw at it. We must plan for failures.” 

Con Edison crews hard at work after Sandy. Courtesy of Con Edison. 

Amin also divides his thoughts between hardening and 

resilience, and the link between the two. 

“Do we need a stronger, hardened grid, or do we need a 

smarter and more resilient grid?” Amin asked. “Actually, we 

need both. At some level you need to strengthen and even 

maybe reconfigure the grid itself. You need to strengthen 

and increase intelligence.” 

“We can do better in terms of physical protection to 

strengthen the physical infrastructure of distribution and 

transmission systems,” Amin continued. “You don’t harden 

the entire system; you judiciously harden parts of it based on 

risk, and the cost drops. We need a framework for our nation 

to advance progress, but it boils down to local issues and the 

best local solution based on risk and cost-benefit analyses.” 

On the resilience side, Amin suggested that the 

specific technologies are less important than three 

basic functionalities: 

? ? Real-time monitoring and decision-making to tune 

the grid to an optimal state. 

? ? Monitoring for precursor conditions to guide grid 

operations prior to a high-impact event. 

? ? Rapid isolation of faults. 

“We cannot build a zero failure system, it’s too expensive,” 

Amin concluded. “But we can localize the disturbance and 

lower its impact.” 

The value proposition, moving forward 

According to Amin, current outages cost the economy 

somewhere between $80 billion to $188 billion each year. 

A smarter, stronger grid would reduce the low-end estimate 

of $80 billion a year by $49 billion, in his estimates. 

A smarter grid would increase the system’s efficiency by 

about 4.5 percent. That’s worth another $20.4 billion, he 

said. Together, improving just those two aspects—reducing 

outages, improving efficiency—brings about $70 billion in

Con Edison crews at work in lower Manhattan the day after Hurricane 

Sandy hit New York City. They worked through the night pumping water 

from basements and substations. Courtesy of Con Edison. 

benefits. A smarter grid would also reduce CO2 emissions by 

12 to 18 percent. 

Amin’s cost estimates range somewhere between $338 billion 

and $476 billion for a smarter grid, and about $82 billion for 

a stronger grid. When those dizzying numbers are recast as 

a 20-year project, that’s a cost of $25 billion to $30 billion a 

year for 20 years. (Hurricane Sandy’s 

impact led New York alone to request 

$42 billion in federal aid, and 

in December 2012, economists were 

crediting the storm with significantly 

slowing the national economy.) 

“Don’t forget, this investment 

means job creation,” Amin added. 

“And it’s cheaper to pay for now than 

down the road. Interest rates are 

at an all-time low. Investment in a 

stronger, smarter grid means that for 

every dollar we spend, it’s going to have an economic return 

of $2.80 to $6 per dollar that goes into smart grid. To reach 

these numbers we used a very narrow definition of ‘smart 

grid.’ If you widen that definition, the benefits would increase. 

Conservatively, for every dollar spent on smart grid, including 

localized upgrades, the benefit would be about 3 to 6 times 

return on investment in terms of jobs and economic output.” 

“A lot more needs to be done for the benefit of smart grids 

to kick in,” Amin concluded. 

Sandy exposed the 

Smarter practices, including customers 

Smart grids are only a piece of the puzzle to greater resiliency 

Amin and Mansoor both suggested. Other utility practices, 

such as using small, camera-equipped drones and mobile 

imaging technology to assess and pinpoint damage should 

be added to the tool kit, they suggested. 

Better-prepared, more self-sufficient homes, businesses 

and communities should take steps to weather events. 

“ 

tremendous opportunity 

we have to partner with 

consumers to speed up 

the restoration process. ” 

Microgrids, solar arrays that can island when the grid is 

down, hand-cranked radios and cell phones can provide 

emergency communications. 

“Sandy heightens the opportunity for innovation,” 

Mansoor said. “The changes on the customer side? How 

many of us had iPhones and tablets five years ago? Today, 30 

percent of utility customers don’t have landlines. Sandy exposed 

the tremendous opportunity we have to partner with 

consumers to speed up the restoration process. We’ll have to 

educate our customers.” 

Hurdles to forward progress 

Lewis, whose clients include utilities, is concerned that faultfinding 

may trump progress. 

“I think there’s merit in looking at [utility responses],” 

Lewis said. “The utilities didn’t do everything right, by any 

means. I just fear that with the number of investigative agencies 

and lawsuits involved, it’s really going to distract utility 

managers from their day job.” 

Amin called attention to the process 

under which change must occur. 

“One important constraint is the 

regulatory oversight of grid modernization,” 

Amin said. “Jurisdiction over 

the grid is split: the bulk electric system 

is under federal regulation, but 

the distribution grid is under statelevel 

public utility commissions. And 

those local regulations essentially kill 

the motivation for any utility or utility 

group to lead a regional or nationwide effort. So we need a 

policy framework to provide incentives for a collaboration in 

grid modernization and for research and development.” 

The bigger picture 

The 20th-century grid exceeded our expectations for basic 

services, rural electrification and economic development, 

Amin said. But the power grid, like water, transportation 

and communication, are in need of serious investment to 

maintain national competitiveness, let alone resiliency in a 

major storm. 

“We have not advanced our infrastructure sufficiently,” 

Amin said. “The World Economic Forum’s recent competitiveness 

report ranked our U.S. infrastructure below 20th in 

most of the nine categories of infrastructure, and below 30 

for quality of air transport and electricity. We wouldn’t have 

settled for something like that in the 1950s or 1960s.” 

Phil Carson is editor-in-chief of Intelligent Utility Daily. 



INTERNATIONAL 

20

ILLUSTRATION BY CHARLES THOMAS 

Making dumb 

European rollouts 

SMART 

Three golden rules of consumer engagement 

By Tim Probert 

THE EUROPEAN UNION’S (EU’s) AMBITIOUS 

plan to rollout smart meters to 80 percent of its 500 

million population by 2020 is not going as well as hoped. 

Europe has enjoyed notable success with smart meters. In 

2006, Italy became the first country in Europe to complete a 

national smart meter program after utility Enel conducted a 

five-year, $2.6 billion (US) scheme—mainly to reduce nontechnical 

losses—for its 30 million customers. 

Elsewhere, Scandinavia leads the way. Sweden also achieved 

full-scale penetration in 2010, while Finland, Norway, and 

Denmark are likely to achieve their targets by 2016. Yet for 

many EU nations who did not take it upon themselves to be 

early adopters, smart meter programs have struggled. 

The European Union’s 2009 Third Energy Package, 

which sets out measures to liberalize Europe’s power sector, 

required each of the 27 member states to publish a cost-benefit 

analysis by end-September 2012. If the analysis found a 

positive business case, member states are compelled to install 

smart meters to 80 percent of consumers by 2020. 

Most nations have reported a positive cost-benefit analysis, 

although there were some exceptions. The Czech Republic’s 

analysis was negative and has recommended its rollout start 

in 2018, while Germany has delayed the publication of its 

report until February 2013. 

The three basic lessons 

While utility benefits of smart meters are not in doubt, for 

the average European the case for consumers has not been 

well established. Significant tactical errors have been made, 

not least in the Netherlands, which proposed all 7 million 

households of the country should have a smart meter 

by 2013. 

Faced with a growing moral panic over data privacy concerns, 

the Dutch government pushed for compulsory installation 

of smart meters, with refusal punished by a fine or 

six months in prison. After vigorous campaigning by consumer 

organizations it eventually relented and the Dutch 

Parliament moved to make installation voluntary. 

The Dutch example is a salutary lesson in the dangers of 

putting the cart before the horse. Dr Philip Lewis, CEO of 

Finland-based utility analyst Vaasa ETT, says rollouts cannot 

be successful without consumer trust. 

“There are three basic stages of consumer motivation,” 

said Dr. Lewis, a psychologist who now specializes in utility 

customer behavior. “First, there are reasons to be positive 

about overall smart meter developments at a national level. 

The second is to be positive about reasons to get involved 

with smart meters. The third is eliminating reasons not to 

get involved.” 



22 

INTERNATIONAL 

“ 

Preaching the first lesson 

Promoting them at a national level in Britain is the job of 

Maxine Frerk, deputy director and head of consumer engagement 

of the UK Department of Energy’s smart meter 

program. 

Engaging consumers is proving tough in Britain, which 

is very much its own beast. Rather than regulated distribution 

network operators, deregulated energy retailers have 

the responsibility to procure and install 53 million gas and 

electricity meters, involving visits to 30 million homes and 

small businesses, by 2019. 

It is an interesting policy choice and, in that respect, 

Britain is in a minority of one worldwide. The rationale is 

simple: Energy retailers have a relationship with their customers, 

and customer behavior change is a major element of 

their business case. So it was decided that it made sense for 

suppliers to be the primary interface for the rollout. 

After years of inflation-busting price increases, tariff misselling 

and poor customer service at a time of stagnant wages 

and rising unemployment, however, British energy retailers 

are among the least popular 

Getting consumers organizations in the nation, 

barely more popular than 

to just open their banks, estate agents and 

even parking attendants. 

front door is the 

So the energy companies 

will have assistance 

first challenge. from the UK Department 

” 

of Energy’s new smart meter 

‘Central Delivery Body’ 

that will conduct a public awareness campaign about the 

benefits, which are estimated at a total £16 billion ($26 billion) 

in return for £11 billion in costs. Frerk believes a strong 

push from the center is needed because smart meter awareness 

and public trust in utilities is very low. 

“Our latest survey of consumer awareness showed only 49 

percent of respondents had heard of smart meters and from 

some of the other questions we asked, it’s not clear that even all 

of those did,” she said. “Getting consumers to just open their 

front door is the first challenge. If suppliers are faced with a lot 

of apathy, and find it hard to get access, it will increase costs.” 

Putting the second lesson into practice 

The British division of German utility E.ON aims to install 

1 million smart meters by the third quarter of 2014, around 

the time the national rollout officially begins. The program 

started in 2011 and the company is close to 300,000 installations. 

By the designated end of the national rollout in 2019 

it expects to install 8 million electricity and gas meters to 

5 million homes. 

The stakes are high for E.ON UK. Up for grabs are 

hundreds of millions of pounds in efficiency savings, the 

potential to offer critical peak period and other time-of-use 

tariffs and even the possibility of harnessing data for thirdparty 

marketing purposes. 

“We’re investing £1 billion in this,” said Chris Lovatt, head 

of field operations, E.ON UK. 

“Our head office in Germany regularly asks me why they 

should spend it on smart meters when we could invest that 

money in, say, Brazil and see a much greater return. So 

we owe it to our customers and shareholders that this is 

done efficiently.” 

E.ON has created two “centres of excellence,” essentially 

customer service contact centres to hold their customers’ 

hands through the end-to-end experience 

of smart meters. “We’re also creating a field 

centre of excellence to ensure all our meter 

technicians are technically skilled,” said 

Lovatt. ”They will also go through 

comprehensive customer service 

training so they’re able to have 

softer conversations with our 

customers to explain how the 

smart meter benefits them.” 

E.ON is working with 

charities such as Age UK to 

ensure smart meters do not 

leave elderly consumers out 

on a limb. “Age UK was particularly 

concerned about the 

support that customers got 

post-installation, so we’re actually 

training some of their staff 

in five different regions across the 

UK to handle queries.” 

Initial feedback shows that E.ON’s 

efforts are paying off. “The levels of NPS 

(Net Promoter Score) are in the high 20s, 

higher than anywhere else across our portfolio,” 

said Lovatt. “We’re feeding some of the knowledge 

gained from smart meters into our classic environment.” 

Lessons learned the hard way 

The message is clear: Consumer engagement should be 

done prior to the rollout with the technology coming at a 

later stage, and not the other way round. This was a lesson 

learned the hard way by Californian utility Pacific Gas and 

Electric (PG&E), which since 2007 has installed 9.5 million 

power and gas meters in 6 million households, taking 90 billion 

meter reading intervals per year. 

At peak, it installed 18,700 meters a day with contractors 

and its internal workforce, equivalent to one every 2.5 seconds. 

Yet the path of smart metering did not run smoothly. 

“If we were to start again we would have done things

differently,” said Jim Meadows, director of PG&E’s smart 

meter program. 

“The more you separate out the installation from customer 

engagement, the more customers are suspicious 

about the motives behind smart meters. You need to make 

customers feel part of the bargain from the start. And in 

order to use the data efficiently you also need to have your 

operations center completely functional from the day the 

first meter is installed,” Meadows said. 

Ogi Kavazovic, vice-president of marketing and strategy 

at Opower, says utilities should be thinking about their customer 

strategy at least a year before the smart meters 

are installed. 

“The cost is probably less than 1 percent of 

the overall smart grid program costs yet 

many utilities don’t do it because they 

think consumers will change anyway,” 

he said. 

The third lesson: Don’t 

be afraid of opt-outs 

Despite their mandatory nature, 

European law may mean rollouts 

are subject to opt-outs. 

PG&E believes opt-outs are 

to be welcomed. “If we learned 

one thing it’s that customers 

don’t like strictly mandatory 

programs,” said Meadows. “They 

like to know there’s an opt-out. In 

hindsight, we would have offered 

an opt-out from the start.” 

E.ON UK says the carrot of energy 

savings should be sufficient to 

gain public acceptance, but U.S. utilities 

also know that wielding a big stick is useful. 

PG&E has an opt-out rate of just 0.5 percent, 

helped in part by the imposition of a $75 up-front 

fee and a further monthly charge of $10 per month to 

cover the expense of manual meter reading. 

Opt-out rates in Europe are so far reassuringly small, said 

Lonneke Driessen-Mutters, head of smart meter operations 

at Dutch firm Enexis. “We have installed 220,000 smart meters 

and less than 1 percent has refused. It seems that just 

having the option to opt out is enough, but we are very vigilant 

that things will stay that way.” 

The endgame: smart pricing 

Post-installation, some European utilities may not be able 

to offer smart pricing but even without it there is much to 

be done with smart meter data, said Opower’s Kavazovic. 

“Home energy reports give insights on consumption data 

and when customers call they can be given new insights, 

targeted discounts and coupons based on their data. As 

well as giving insight into their consumption, we also show 

the potential savings that could be made on the report,” 

he added. 

Opower says its monthly mail energy report is the most 

effective method to engage consumers, but it also uses 

e-mail and web portals. 

“Engage customers where they are not where you wish 

they are,” said Kavazovic. “In Europe, mobile phone channels 

look very promising.” 

For most utilities, the endgame of smart metering is 

smart pricing. VaasaETT’s Lewis says consumers must feel 

part of the deal for time-of-use tariffs to be successful. 

“Customers need to feel they are in control. When they 

introduced time-of-use pricing in Australia without consumer 

permission the backlash was so bad they had to 

stop it. There was a perception that some people were suffering 

from smart meters. We don’t want that to happen 

in Europe,” he said. 

PG&E has a peak summer load of 16 GW. Its SmartRate 

tariff dictates that for 15 days a year a surcharge of 

$0.50/kWh is imposed between 14:00-19:00. In exchange, 

participants get credit for off-peak hours. 

“You have some unintended consequences such as at 19:00 

demand for air conditioning is higher than usual because 

the higher heat of homes,” said Meadows, “But 80 percent 

of the customers find a way to save money. And we’ve had a 

13 percent critical peak period load reduction.” 

Dr. Lewis warns that customers must become accustomed 

to smart pricing. “You can’t suddenly shove it 

upon them and sit on them. There needs to be a fair and 

transparent link between the sacrifice and the reward, 

and customers have to explore what those benefits are for 

themselves directly.” 

The psychologist sees best practice in Scandinavia where 

the Finnish utility Fortum has launched a product whereby 

customers can automatically control their hot water heating 

linked to the spot power market, Nordic. The heating system 

is timed throughout the day and is switched on or turned off 

depending on market prices. 

“From the customer point of view it’s a profit-sharing 

scheme”, said Lewis. “The utility benefits by getting the customer 

engaged in sharing market volatility and the customers 

save by taking advantage of that volatility, rather than 

suffering from it.” 

The EU is a big place and there can be no one-size-fitsall 

solution for a continent of 27 nations and 500 million 

people but, says Lewis, follow the three golden rules and 

progress will be less problematic, and less costly. 

Tim Probert is a London-based freelance writer with a focus on 

European power markets and new smart grid technology. He helms 

Millicent Media and can be reached at timprobert@millicentmedia.com. 



CUSTOMER 

FOCUS 

24 

Customer service 

requires collaboration, 

innovation 

+ + Stage the smart grid message well 


I’M BRAND NEW TO ENERGY CENTRAL AND THEIR 

Knowledge Summit. You may even go as far as inserting the colloquial 

“spankin’” into that phrase. I am, indeed, brand-spankin’ new. In fact, at the 

conference, I was a whopping six days old with this gig. 

But, I’m not at all new to energy conferences. When I fell into the energy 

publishing industry after finishing my MFA in writing (a fall which was entirely 

an accident of geography, by the way), I spent a lot of time at conferences over 

the next dozen years. Figuring that the average conference lasts three days, during 

which time you’re busy at least 10 hours of those days, I’ve spent 2,880 hours 

(approximately) knee-deep in energy conferences in my lifetime (not counting 

planning for those I worked on). That’s about four full months of my life (or 

eight months at just working hours of the day) at energy conferences. 

At the Knowledge Summit, executives 

and managers sat down and 

discussed openly issues and concerns 

that they all were facing—a collaboration 

rather than a presentation. 

The collaboration at Knowledge2012 

covered customer service and IT topics 

extensively, especially in areas where 

the two overlap (as with mobile applications 

for consumers, for example). 

A number of small, medium and 

large utilities gathered to discuss 

smart grid customer education 

efforts, key performance indicators 

for smart grid success, social media 

issues, analytics, cybersecurity and 

even the economic challenges utilities 

face—all with open dialogue and 

honest questions. 

The greatest bit of advice I heard 

from anyone at the conference (and 

the anonymity of the conference 

doesn’t allow me to quote her directly) 

was that utilities must not let anyone 

else drive their stories—not media, not 

consumers, not vendors. Utilities must 

get comfortable controlling the plot 

of their stories along with the power 

of their services. 

To that end, some customer service 

lessons learned from these Knowledge 

discussions include: 

? ? If you stage the smart grid 

message well, consumers will 

(mostly) react positively. And, 

money remains the best mes- 

saging for consumers in that 

arena. If you do see a smart grid 

backlash growing, however, re- 

act immediately and personally. 

? ? Know your customer better. 

Consider programs that exam- 

ine customer segmentation and 

the psychology of what drives 

both their choices and their 

apathy. And, use that knowl- 

edge to offer your customer 

options, right down to the 

ways they communicate with 

you (text, email, phone, online, 

app, etc.).

? ? There will always be the 

consumers who don’t want to 

change. So, look into opt-out 

programs, even if you’re hoping 

that your public utility commis- 

sion won’t force the issue. 

Be prepared. 

? ? Remember that customers 

don’t care about data. Data 

has to be interpreted. Custom- 

ers care about benefits. Don’t 

simply send emails on use and 

think customers will make 

behavior changes. Gear that 

data to highlight benefits. 

? ? Prepay is coming. Be prepared. 

Talk to utilities already piloting 

programs in this arena about 

options (use of kiosks or third- 

party partners, such as grocery 

stores, for payment). 

? ? Your employees are your 

smart grid ambassadors. Train 

them all well (not just the field 

workers) and let their growing 

education work for you. 

? ? In juggling shrinking customer 

service budgets, consider 

out-of-the-box options such 

as allowing workers to take 

phone calls from home (saving 

you on overhead). 

Hopefully, you can use some of 

these Knowledge lessons to help 

drive your stories. 

Overall, the idea of planning for 

growing consumer choice and IT 

systems dominated Knowlege2012. 

Each attendee walked away with 

notes on areas to research, people to 

talk to and changes to think about. 

And that makes all those hours 

dedicated to conference attendance 

time well spent. 

Kathleen Wolf Davis is editor-in-chief of 

Intelligent Utility magazine. 

Knowledge Summit 

kicked off with talk 

of customers, 

utility renaissance 

+ + Consumers now rule 


ENERGY CENTRAL’S 7TH ANNUAL KNOWLEDGE SUMMIT 

opened on Tuesday, November 13, 2012 at the Hotel Zaza in Houston, 

Texas, with a utility panel discussion on the growing importance of consumers, the 

interaction of systems, and the growth of community outreach and education. 

Dan Hill, retired CIO of Exelon and IT chair for the conference began the 

session with a note on the evolution of customer/utility interaction. 

“As we think about the dramatic changes that we’re in the middle of, let’s 

reflect on this: Many of us in the room used to refer to our customers as rate- 

payers. How dramatically our perception of them has changed, and [how 

dramatically] their perception of us has changed. Their perception of us isn’t 

guided by their experience at [a traditional retailer such as] Sears, per se, but 

by Apple and Amazon.” 



CUSTOMER 

FOCUS 

26 

Hill and others in the session noted, 

however, that this change in customer 

perception is an opportunity to grow 

and develop. 

“Customers, indeed, 

compare us to the Apples “ 

Many of us in the 

and other competitive busi- room used to refer 

nesses,” added Tracy Bridge, 

senior VP & division presi- to our customers 

dent, electric operations, 

for CenterPoint Energy, as ratepayers. How 

later in the discussion. 

Bridge continued by dis- dramatically our 

cussing how utilities such 

as CenterPoint can spend perception of them 

millions on operations, 

but those millions need to has changed ... 

translate to a consumer- 

” 

based value or that money 

» DAN HILL 

“is largely wasted.” Bridge 

pushed customer impact, noting that 

CenterPoint shows customers power use in 

15-minute intervals and offers the option 

to switch power companies in Texas’ deregulated 

markets in 30 minutes or less most 

of the time (approximately 97 percent of 

the time, according to Bridge). 

Dawn Roth, general manager, IT, 

Colorado Springs Utilities noted that 

customers of their utility benefit from capital investments, demand response programs 

and the combination of multiple systems for smart grid benefits that blends 

data from traditional systems, along with info from metering data and patterns. 

“We have found that we can change behavior using time-of-use rates,” Roth 

said. “The reward, combined with a [customer] watching the data, seems to 

make a big difference. When we had an open portal, usage changed in the first 

month and then nothing after that. The rewards helped with that. “ 

Leslie Barrios, executive manager, IT, Bluebonnet Electric added that her 

customers, which they refer to as members, were active from the start with their 

data, with consumer changes coming into play as early as the moment members 

could see data use. 

“We’ve been displaying hourly intervals for a little over 16 months now, and 

it does change their behavior,” she said. “It’s been a good tool to explain the load 

curve for individual usage.” 

Bridge, Roth and Barrios all view the customer as a large catalyst for the 

IT/OT convergence that could be seen as a utility renaissance. Bridge sees that 

renaissance itself reflected in the “cross-pollination” of systems. Roth added a 

note toward leadership development, and Barrios reflected on the community 

aspect of this renaissance across the organization, inviting everyone to the table. 

Bluebonnet Electric has a meeting twice a year with everyone in the business, 

including executives, coming together to discuss the evolution of the 

utility, which is a new cross-governance approach in an industry that was 

once über-vertical. 

“Historically, utilities tend to be silodriven, 

but we’ve changed that,” Bridge 

added, citing that CenterPoint, like 

Bluebonnet, helps different aspects of 

the company, such as IT or operations, 

understand each other. And, customer 

service, which used to simply be where 

the complaints were sent, is now a 

large driver of that open communication 

from the top to the consumer. 

Roth’s Colorado Springs Utilities 

pushes their renaissance through leadership 

development, identifying potential 

future leaders and placing them 

in a program to develop skills and 

communication channels. They’ve 

also reached out to high schools and 

community colleges to find those 

leaders, who may be more interested, 

initially, in other options. 

There are a lot of sexy industries,” 

she noted. “Unfortunately, [electricity’s] 

not in one of them.”

I T 

INSIGHTS 

The DOE reaches 

out to utilities with 

cybersecurity model 

+ + ES-C2M2 is on the scene 


THERE’S AN OLD JOKE WITH AN EQUALLY ARCHAIC PUNCHLINE 

that quips about the U.S. government never getting a thing done, how 

every project takes forever. At least in the case of a cybersecurity model, the U.S. 

government has definitely proven that joke completely and utterly wrong. 

The Electricity Subsector Cybersecurity Capability Maturity Model (ES-C2M2) 

hasn’t been in the works for a decade. It hasn’t been languishing in a subcommittee 

waiting for rescue or funding. In fact, it all started just a scant year ago when 

the White House knocked on the door of the Department of Energy (DOE) and 

asked how we (as a government body and as an industry entity and as a group of 

concerned consumers) start to pinpoint what utilities are doing on cybersecurity 

and what they should be doing, a now-and-the-future scenario. 

Thus was born the ES-C2M2, a public/private partnership allowing electric 

utilities and grid operators to assess their cybersecurity capabilities. It also allows 

utilities to prioritize future actions and investments in the cybersecurity arena 

with a series of steps—gradual assessments in platform areas that build to a 

complete picture. 

The collaborative effort that started in 2011 came to a head in May 2012 

with the release of the first version of the model (just a few months after first 

initiated in January of this year). 

The model, according to the DOE’s 

Office of Electricity Delivery & Energy 

Reliability, “combines elements from 

existing cybersecurity efforts into 

a common tool that can be used 

consistently across the industry.” It 

also includes a cybersecurity self- 

evaluation survey tool, which discusses 

situational awareness, along with 

threat and vulnerability management, 

to allow a utility an internal option 

for the cybersecurity discussion. 

The challenge from the White 

House was to develop capabilities to 

manage dynamic threats and understand 

grid cybersecurity, Matthew 

Light, infrastructure systems analyst 

at the DOE told insiders at the 

cybersecurity focus group during 

Grid-Interop 2012 in Irving, Texas, 

December 4, 2012. 

The objectives for the model 

development included the desire to 

strengthen cybersecurity capabilities, 

along with the need to enable consistent 

evaluation and benchmarking, 

share knowledge and benefits, and help 

prioritize actions and investments. 

Additionally, Light noted, the utilities 

wanted to know where they were 

relative to their peers, and the government 

needed an assessment to discuss 

options for federal resources. 

The model has ten domains and 

four maturity indicator levels (MILs). 

The domains include logical groupings 

of cybersecurity practices, including: 

risk management; asset, change 

and configuration management; 

identity and access management; 

threat and vulnerability management; 

situational awareness; information 

sharing and communications; event 

and incident response, continuity of 

operations; supply chain and external 

dependencies management; workforce 

management; and cybersecurity 

program management. 

According to documentation about 

the model, “the practices within each 



I T 

INSIGHTS 

28 

domain are organized into objectives. 

The objectives represent achievements 

that support the domain.” For example, 

the risk management domain 

has three objectives: 

? ? Establish a cybersecurity risk 

management strategy, 

? ? Manage cybersecurity risk, and 

? ? Manage risk management 

activities. 

Currently, over 77 utilities 

have downloaded the model’s 

assessment tool. 

“That’s pretty significant across the 

space—cooperative, international, 

IOU, public power and RTOs. Overall, 

we’re getting some great adoption,” 

Light said. 

To date, the ES-C2M2 has had 17 

pilot assessments where the DOE 

went on-site with industry volunteers 

and walked through the model. They 

wanted to adjust the model to meet 

industry needs with a primary focus 

on feedback. Currently, that feedback 

is leading to new changes to the 

next version of the model, including 

additional maturity indicator levels, 

performance metrics and measurement, 

and informative materials. 

The ES-C2M2 effort is led by 

the DOE, in partnership with the 

Department of Homeland Security 

(DHS), Carnegie Mellon University 

and industry stakeholders. 

The ES-C2M2, designed specifi- 

cally for the electricity industry, can 

be downloaded from the DOE’s 

website or by contacting the DOE 

at ES-C2M2@hq.doe.gov. 

“We want organizations to take the 

assessment tool, have the DOE come 

on-site or preform it on their own,” 

Light noted. “The key pieces are analyzing 

the gaps. The organization has 

to keep in mind a risk profile, tolerance 

and priorities. Each organization 

will achieve a different maturity level 

based on their risk profile.” 

IT lessons from 

utilities revealed 

+ + Consumers driving change 


AS UTILITY EXECUTIVES SAT DOWN AT ENERGY CENTRAL’S 

Knowledge Summit the week before Thanksgiving, they revealed 

their own concerns, thoughts and company progress in the overlap between 

IT and operations. 

While the conference relies on anonymity to keep an open dialogue, insiders 

were allowed to jot down general notes on the meetings. 

Some IT lessons learned from these closed-door discussions include a fount 

of revelations about consumer influence, IT coverage and gaps still left to hurdle, 

whether that jump is through technology advancements or changes in governance. 

These advising points came to the forefront of the discussions: 

? ? Remember that even IT is tied to the consumer, as growing consumer 

choice is driving IT innovation. So, don’t deny consumer influence 

across your company, including how the smallest IT widget will 

cascade down to a consumer impact. 

? ? While analytics is great, without the ability to automate and impact 

operations, it’s just knowledge. It just sits. That knowledge needs to 

be applied.

? ? You can outsource areas that aren’t too security-oriented, in order to 

focus your IT staff on the stack of growing tech projects. If you don’t 

have enough people to begin with, don’t bog them down with both the 

small data details (like break/fix) and the big coming issues (like build- 

ing mobile field applications). 

? ? Your next largest challenge isn’t the smart grid, the consumer or the 

big data deluge on the horizon. It’s the big exit deluge that will occur 

in your company with retirement spikes. You’ll have to think outside 

the box (outsourcing/micro-sourcing) to cover that mass exodus. 

? ? Prioritize. Not every IT project can be done right now. Make your 

people, especially executives, work out what’s most important and 

what can sit a little while. 

? ? Technology costs will rise. Your budget will not rise in response. There 

will be a gap. Figure out when you can resource current assets and 

when you just must say “No, that cannot be done on this budget.” 

? ? Consider cloud options for non-core services, but verify these areas: 

privacy, security, monetary value and guaranteed access (will it always 

have data where you want it when you want it). 

? ? Yes, cybersecurity keeps some CIOs up at night, but not all. Still, it is 

a growing area of concentration with worries about whether enough 

is being spent to manage it. 

? ? Think about security while designing your newest IT system interface, 

not after the system is finished. Plan ahead. And remember, it’s not 

if your system will be penetrated but when. So, know how you 

will respond. 

? ? You may be trying to emulate banking systems with your mobile 

applications, but, on the consumer side, you may need to think more 

in parallel with retailers like Amazon. 

? ? As consumer and field-based 

mobile apps develop, think 

ahead about bringing multiple 

environments and options 

(outage maps, bill pay) togeth- 

er in a single interface rather 

than separate developments 

for each task. 

? ? While the cost/benefit analysis 

for consumer-based mobile 

applications may not pan out 

in straight economic terms, 

what’s the worth assigned for 

creating a high-tech utility 

brand in the minds of consum- 

ers? Will consumers apply how 

well you do your mobile app 

to how well the rest of your 

system works? Will mobile 

apps help pull your utility 

into the arena with Apple for 

consumers? Think about the 

branding options, too, not 

just about the technology 

and the money. 

Finally, one retired CIO of a large 

utility conglomerate revealed that 

“change is the new normal” when 

it comes to utilities and IT systems. 

While change isn’t a concept traditional 

vertical utilities have ever been 

truly comfortable with, it’s time to sit 

with it and learn to at least respect it. 

Change is now the one thing utilities 

can count on as the IT systems they 

have learn to adapt and continue to 

evolve with the smart grid. Last year, 

we were talking about IT/OT convergence. 

This year, we’re talking about 

mobile apps and cybersecurity details. 

In 2013, the conversation for utility 

IT may have a completely new focus 

that has yet to reveal itself. 

Energy Central’s 7th annual 

Knowledge Summit occurred 

Nov. 12-14 at Hotel Zaza in 

Houston, Texas. 


The network platform a utility uses is a driving factor in what it can do with its smart 

grid –– today and in the future. Most agree: A long-lasting and future-enabled solution 

that requires fewer supplementary systems is best. However, finding the most robust 

and suitable network platform for your operation means considering four key attributes: 

1 

High Degree of 

Scalability 

Transmitting massive amounts 

of data without overloading the 

system is one of the principal 

jobs of a network platform. As 

more utilities look to implement 

distribution automation and 

demand response programs, 

they need platforms with extra 

headroom –– in processing 

capacity, data speeds and 

executable memory. 

Building true scalability into 

a network platform requires 

thoughtful architecture. A 

balance between “push” and 

“pull” traffic is key. This is best 

achieved through a combination 

of techniques: 

• Randomization of the data 

stream 

• An efficient routing algorithm 

• Message prioritization to 

differentiate distribution grid 

automation and advanced 

metering traffic 

• Message consolidation 

to reduce the number of 

simultaneous messages 

during high-traffic periods 

(such as a mass outage) 

Get more insights from landis+Gyr 

What to look for in a 

Smart GriD 

nEtwork PlatForm 

By: Tim Weidenbach 

VP Product Management, Landis+Gyr 

Another important factor is 

network design, or the physical 

layout of hardware and 

components. A successful 

design ensures that the quantity 

of infrastructure meets the utility’s 

performance requirements. 

Substantial Flexibility 

Because a tailored solution 

more readily meets a utility’s 

unique needs, flexibility is 

also a key consideration. 

Flexible network platforms 

typically offer several options 

for communications media, 

such as RF mesh, cellular and 

power line carrier. For utilities 

that serve customers in urban, 

suburban and rural areas, this 

enables a more customized mix 

of communications. 

A platform must also be able 

to handle several types of data 

and network traffic. Look for 

a solution whose architecture 

employs both fixed-path 

networks and data stream 

randomization. This prevents 

system overload and laborintensive 

traffic monitoring. 

Find out more about evaluating network platforms, and learn why 

our Gridstream ® solution is the most robust option on the market. 

Visit befutureready.com/network. 

2 

3 

4 

Future-Proof Design 

To avoid obsolescence, utilities 

need network platforms that 

can evolve. Look for solutions 

with interchangeability and 

interoperability. Interchangeability 

ensures component collaboration 

across previous and future 

hardware and software releases. 

Interoperability ensures the 

solution is built to accepted 

global standards. Not only do 

standards represent a consensus 

on industry best practices, 

but they are often designed to 

integrate with other industries’ 

regulations as well. 

Proven Provider 

Expertise 

Finally, utilities must consider 

the track record of the solution 

vendor. Seek providers with a 

history of success in complex, 

large-scale implementations. 

They have likely encountered the 

most common challenges and 

have fine-tuned their processes 

accordingly. In addition, they are 

already accustomed to meeting 

deadlines and delivering on 

service level agreements.

Future. Ready. SM 

System reliability 

Distributed generation 

Data analytics 

Grid automation 

Interoperability 

Consumer engagement 

Peak load management 

where is smart heading? 

grid 

befutureready.com


SPECIAL 

REPORT » ANALYTICS 

32 

What’s happening 

in the post-smart 

grid world 

+ + Southern Co., Oncor discuss details 

By H. Christine Richards 

AS UTILITIES COMPLETE THE ROLLOUT OF SMART GRID 

technologies, including smart meters and other intelligent distribution 

network devices, they are finding tangible examples of how data and analytics 

can support their grid operations. In this article, you’ll meet two analytics professionals 

and learn about their work to leverage data and analytics from their 

smart grid deployments. These stories come from presentations at the recent 

Utility Analytics Week conferences and are told by: 

? ? Derl Rhoades, Southern Company/Alabama Power 

? ? Jonathan Pettit, Oncor Electric Delivery 

ALABAMA POWER Outage analytics for distribution operations 

Alabama Power has 4.4 million retail customers, of which the company has 

automated metering for 4.3 million. “Our smart meter projects are pretty much 

done,” said Rhoades. “We do meter 

alerts for values other than billing. We 

do voltage. We do amps, phase angles 

and momentary outages.” 

Rhoades said that 10 or 15 years 

ago, many people in distribution 

didn’t see much value in AMI, but 

today most of them can’t live without 

it, especially on the outage management 

side. He said just 10 percent of 

customers actually call with an outage 

when they have one. 

However, when a utility has an 

AMI system integrated with an outage 

system, many people call every day. 

“Our system basically assimilated a 

phone call,” he said. “When a meter 

comes in, it goes in as if the customer 

called, so it goes into the system. We 

can predict the outages. The beauty 

about it is, now we have so many 

people calling that the outage prediction 

model is perfect.” 

Then, when customers call in to 

restore and the meters report that 

they’re restored, the Alabama Power 

system automatically takes them 

off the outage list. “If the meter was

eported out or is predicted out, it’s 

in the list,” Rhoades said. “So it comes 

back, and the meters start coming off 

the list, and if a meter does not report 

back in, the system automatically 

pings the meter and determines if the 

outage is cleared or not. If the outage 

is not cleared, naturally operations 

would roll somebody there. We can 

do it all in a matter of 10 minutes 

versus waiting until somebody makes 

a phone call. It has improved our 

outage management system and 

restoration times. It was one of the 

first things we did.” 

Rhoades said that, to make it all 

work, a utility has to have its interfaces 

right, and it has to 

monitor those interfaces. 

At Southern “ 

Company, everything 

runs on a bus system, 

so it is essential to 

make sure the bus systems 

are operational, 

“Because once you 

start depending on all 

these outages coming 

in from your meters, 

you need to make sure that systems 

are up and operational. It’s taken us a 

while to get all the right monitoring 

points to make sure they’re flowing 

properly,” Rhoades said, “But we got 

all that done.” 

Alabama Power had some problems 

with the ping response time from its 

OMS system that reduced the success 

rate below an acceptable level, but 

setting the priority messages correctly 

fixed the problem. “Everything works 

fairly well, and it’s a good project,” he 

said. “It really helps our distribution 

people in managing outages.” 

ONCOR Theft detection 

and outages 

Oncor has 175,000 smart meters 

left to install to reach its goal of 

3.2 million installed. Jonathan 

Pettit, advanced meter system 

(AMS) manager at Oncor Electric 

Delivery, said the key at Oncor is AMS for a variety of reasons, including analytics 

and automation. 

“Currently, we have about 250,000 automated operations a day for which, in 

the past, we would have had to roll a truck. To date, the automation has saved 

between 4 million and 4.5 million truck rolls, along with the associated fuel 

and man hours.” 

Analytics also help Oncor protect its revenue from loss through theft. The 

protection involves the use of manual queries. Pettit said that although the queries 

are automated, Oncor doesn’t kick out service orders automatically. He said 

the utility wants to reach the point of 90 to 95 percent assurance of true theft or 

revenue protection. “The processes have an average 80 percent hit rate in a range 

from 60 to 90 percent,” Pettit said. “The one that’s 90 percent is about ready to be 

automated. There are many ways to steal electricity, and it’s amazing what people 

will do. You’ll find that theft is probably twice as high as you ever thought it was, 

and people are twice as smart as you thought they were, too.” 

According to Pettit, there is an urban myth that meters give false indications 

of outages. “They actually are telling you there’s something wrong with your 

secondary,” he said. “Even our meter vendor hadn’t 

thought about this. But in 100 percent of the cases 

where we had a false indication, we had a loose 

terminal or a problem with the transformer. With 

predictive analytics, you can learn that there’s 

something wrong out there. So we have a team that 

does nothing but go around fixing these potential 

problems before they occur.” 

Pettit described the integration of various systems, 

including OMS and DMS, as a “big find,” 

but something the utility should roll out in bits 

and pieces. However, Oncor’s distribution operation 

center said, “This is great!” and all of a sudden, Oncor turned on all of the 

integration. “They’ve been happy,” he said. “And now it’s as though they can’t 

live without it.” 

Pettit said that utilities will likely find that most OMS systems are not ready 

to deal with a high quantity of messages. Oncor had an outage that affected a 

half-million people. He said the systems are not scaled for millions of outage 

messages. “You have to find a way to filter, modify or otherwise limit the amount 

of messages,” he said. 

Automation has saved 

between 4 million and 

4.5 million truck rolls, 

along with the associ- 

ated fuel and man hours.” 

The future of analytics 

Regardless of the project or challenges, utilities have their eyes open for the next 

killer app in analytics. 

Rhoades said as Alabama Power integrates its AMI and SCADA data, it would 

like to improve light feeders. “Why is one feeder two percent more inefficient 

than the next feeder when it should be just like it with the same miles of line?” 

he asked. “That’s something in the future we’re looking at.” 

Pettit said much of the future for data analytics in Oncor’s projects is unknown. 

He said although the smart grid and smart meter programs have been 

going on for a long time, they represent the biggest change in the electric utility 

industry in 100 years. 

H. Christine Richards is the director of knowledge services for the Utility Analytics Institute. 

You may reach her at crichards@energycentral.com 



SPECIAL 

REPORT » ANALYTICS 

34 

Got GIS? 

You’ll need it to 

maximize analytics 

+ + One thread woven across many applications 

By Mike Smith 

AS MANY OF OUR READERS, CLIENTS AND PARTNERS HAVE 

noticed, here at the Institute we view the utility analytics market primarily 

through two lenses: those of customer analytics and grid analytics. (Yes, 

we also cover the business infrastructure, too.) In our coverage of these market 

segments we have learned about what applications 

have moved to the forefront and which ones are 

still percolating for future use. One common thread “ Much of the legacy 

woven across many of the applications that we look 

at—be they in the grid or customer market seg- around GIS is that it 

ments—is the role of geospatial technology, a.k.a., 

geospatial information systems or GIS. 

is still viewed as a 

In fact, the genesis of this article is that in many 

of the research interviews conducted by our staff in mapping tool, when 

recent months, GIS kept coming up—more so than 

we expected. In grid optimization, this was usually it is really a decision 

around the critical role of the connectivity model; in 

asset optimization this was usually around using GIS support tool with 

either as the asset repository or a hub for all things 

assets. On the customer side of the world, locational a very strong 

analysis for endless customer applications creates a 

significantly more valuable proposition for utility visual component.” 

staff and managers working to improve customer 

service and engagement. 

For industry perspectives for this installment of our analytics leadership 

articles, I called on Bill Meehan, ESRI’s director of utility solutions. Bill’s 30-plusyear 

career in the utility space includes senior management roles in operations 

and engineering at a large investor-owned utility prior to joining ESRI, so he 

speaks from a depth of experience 

with many of the issues facing today’s 

utility leaders. 

As noted above, the connectivity 

model, while already critical, has 

arguably reached a greater level of 

importance with the advent of analytics. 

In Institute research the connectivity 

model is often cited as one of 

the hurdles in deploying the applications 

that fall into the Institute’s grid 

optimization segment. “One of the 

challenges that we see at utilities trying 

to leverage their connectivity models is 

rooted in the legacy of how their GIS 

was developed,” explained Bill. “Much 

of the legacy around GIS is that it is 

still viewed as a mapping tool, when it 

is really a decision support tool with a 

very strong visual component.” 

Bill is passionate about the role of 

GIS in utility operations; accordingly, 

he continued: “Looking at the overall 

GIS world, mapping is probably the 

legacy of what people thought GIS was 

supposed to be in the first place. With 

a migration from hand-drawn mapping 

systems to computer-generated 

mapping systems, this legacy has the 

thinking around the 

production of maps. The 

shift that needs to happen 

is that there needs to 

be a realization that GIS 

is not just a visualization 

of the map, but is more 

about discovery and 

analysis—it is a decision 

support tool, not just a 

mapping tool. Because 

of this, utilities do not 

always capture the connectivity 

or the phasing 

on the grid.” 

Looking deeper into 

some of the analytics 

application areas across 

the grid and customer 

market segments reveals the critical 

roles that integration and data quality 

will play in the successful implementation 

of so many of these solutions that

leverage GIS. For example, in asset 

management, utilities need to have a 

clear vision of the role that each system 

plays in the overall scheme of managing 

millions or even billions of dollars 

of assets in the field that keep the lights 

on for millions of customers. The GIS 

provides the locational data and in 

some cases is the repository for the 

asset data, while in other cases the asset 

data resides in another system, like SAP 

or Maximo. Factor in inventory store 

and crew dispatch functionality and 

the requirement for clean integration 

becomes readily apparent. Here’s a new 

driver to the asset management world: 

the proliferation of sensors across the 

grid creates more opportunities to 

manage those assets predictively, and 

with an integrated GIS, spatial analysis 

of the repair-versus-replace decision 

can identify trends and streamline 

maintenance processes. 

On the customer service and 

engagement side of the utility, the 

potential roles of GIS are too many 

to list here, but, for example, spatial 

analysis can be integrated with third-party demographic data for debt collection 

and improvement. Or companies can integrate third-party demographic and 

even income data to profile and target customers for energy efficiency or 

demand response programs. Also, everybody who has a smart phone is a source 

of customer intelligence with a utility’s ability to spatially analyze the unstructured 

data from Twitter tweets for a variety of customer service applications, 

like outage reporting and bill payment. 

When I get someone with Bill’s experience and wisdom on the line, I always 

like to throw out a crystal ball type of question, which in this case was about 

what benefits might come out of the analytics era that we aren’t necessarily 

thinking about right now. Bill didn’t miss a beat and jumped right on this: “I 

think and am hoping that smart meter data will eliminate many of the bad 

surprises that I have experienced over the years in utility operations. Especially 

things blowing up—like when transformers overload and blow up. Smart meter 

data will enable better monitoring of the system health and well-being of their 

assets. Also, with the smart grid there will be more prediction of failure than actual 

failure itself. This will also enable the system to run more effectively, and this 

might even enable utility staff to learn more about the system that they never 

knew. With more data available, patterns will emerge and intelligence will result.” 

The analytics market continues to be a field rich in opportunity for improvement 

of utility grid and customer operations, and GIS can and will be a key 

piece of utilities realizing the full potential of their investments in analytics. 

For more on GIS, see the feature “GIS evolves into backbone for cooperatives” on page 12 

of this issue. Artwork courtesy of ESRI. 

This article originally appeared in the Utility Analytics Weekly e-newsletter. To subscribe to 

the newsletter, visit www.utilityanalytics.com. Mike Smith is a vice president with the Utility 

Analytics Institute. He may be reached at msmith@energycentral.com. 


Utility leaders will share their insights 

Rick Harris 

Vice President 

& CTO 

PG&E 

Je Nichols 

Director 

Information 

Management 

& Information 

Security 

SDG&E 

Kevin Dasso 

Senior Director 

PG&E 

Glenn Pritchard 

Principal Engineer 

PECO/Exelon 

TCS Company Mark - Stacked - 3 lines 

For use in 2D applications 

James M Spitz 

Executive Director 

Fisher CIO 

Leaders 

Jaser Marabeh 

Project 

Manager Asset 

Management 

& Smart Grid 

Projects 

SDG&E 

X 

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TOP 5 

38 

Top 5 

KITE winners look at 

utility challenges for 2013 

+ + Featuring Branndon Kelley, Monica Whiting 

and Caroline Winn 

ENERGY CENTRAL’S KITE AWARDS RECOGNIZE LEADERS WHO 

have demonstrated exemplary knowledge, innovation, technology, and 

excellence (KITE) in information technology and customer service. 

Intelligent Utility contacted the 2012 award winners to get insight into the 

top five challenges they see utilities facing (in the areas of IT, operations or 

customer service) in 2013. 

BRANNDON KELLEY with 

American Municipal Power won CIO 

of the Year, Small Utility Category 

(less than 1,000,000 metered customers). 

These are the top five challenges 

he sees for utilities next year. 

(1.) CYBERSECURITY // It is just the 

world we live in. The days of us protecting 

our IT networks and infrastructure 

from the novice hacker are 

over. Today, we must fight very wellorganized, 

state-funded organizations 

that want to break into our systems. 

There is nothing cool or innovative 

about it, and the challenge is not only 

technical but finding ways to fund 

these rather large projects that do not 

have a direct return on investment. 

(2.) AGING TECHNOLOGY // Today’s 

utilities are faced with systems, 

application and IT infrastructure that 

are dated and don’t fit nicely with the 

new innovative platforms. We must 

find those, prioritize them and come 

up with plans to transition them. 

Keeping in mind the answer might 

be outside of our four walls. 

(3.) WORKFORCE // IT in general is 

facing the 40-year mark. Over the last 

five years or so, we have, for the first 

time, seen a wave of people retire out 

of the industry. Utilities (with their 

aging technology) must ensure the 

intellectual knowledge does not leave 

with them. We must also make sure 

we can challenge the new workforce 

and create an environment they can 

be successful in. 

(4.) MOBILE // We must enable technology 

that allows our workforce and 

customers to do their jobs and interact 

with us. Through BYOD, mobile, 

cloud or additional options, we can 

accomplish this, but only after we 

know that we can keep it secure. 

(5.) BUSINESS INTELLIGENCE // We 

must harvest the data that exist in our 

utilities and work with our partners 

in operations and customer service 

to turn it into valued information. 

MONICA WHITING with 

Colorado Springs Utilities won 

Customer Service Leader of the Year, 

Small Utility Category (less than 

1,000,000 metered customers). 

“For decades, the utility industry 

remained fairly constant. Meters 

were mechanical. Reads were received 

monthly. Paper bills generated. Basic 

utility rates applied to all customers 

in the same class. Customer service 

was about answering a phone,” 

said Whiting. 

“That has all changed, driven by 

rapidly advancing technology and

equally evolving customer expectations. 

In my opinion, the greatest 

challenge facing utilities today is the 

call for speed in customer-centric 

change. Today’s utility leaders have an 

amazing opportunity to help re-shape 

our industry and future generations, 

keeping a focus on the customer.” 

These are the top five challenges 

Monica sees for utilities next year. 

(1.) CUSTOMER CHOICE TECHNOLOGY // 

Utilities must embrace technology 

to provide customers better service 

options and a robust portfolio of 

choice—not from the traditional 

utility perspective but from the enduser 

perspective. 

(2.) EFFICIENCY TECHNOLOGY // Utilities 

need to leverage new technology to 

re-engineer processes to become more 

efficient and cost-effective in their delivery 

of customer service, and in turn, 

helping keep rates low for customers, a 

key driver to customer satisfaction. 

(3.) CUSTOMER EDUCATION // 

Utilities need to create empowered 

and educated customers who can 

modify behaviors and become more 

responsible utility users and environmental 

stewards. 

(4.) CONSUMER RELATIONSHIPS // 

Utilities will help transform how consumers 

use power by piloting groundbreaking 

programs such as electric 

vehicles, solar, time-of-use and other rate options, along with ensuring customer 

value, technical feasibility and cost-effective operations. 

(5.) CUSTOMER SERVICE // Utilities will redefine customer service and create 

customer service representatives of the future, focused on providing holistic 

service as technical utility advisors, as well as community advisors. 

CAROLINE WINN with San Diego Gas & Electric won Customer 

Service Leader of the Year, Large Utility Category (1,000,000 metered customers 

or more). 

“Utilities today face significant challenges, both traditional (providing safe, 

reliable and efficient service to customers while complying with regulations) 

and emerging (providing value-added products and services to customers),” 

Winn said. 

These are the top five challenges Caroline sees for utilities next year. 

(1.) CUSTOMER ENGAGEMENT // Most customers find energy generally uninteresting. 

Our challenge is to not only keep pace with customers’ increasing expectations 

(borne out of the airline or financial industry where innovative online 

and mobile services are the norm) 

but to provide socially engaging and 

meaningful offers. 

(2.) ELECTRIC VEHICLE/ROOFTOP SOLAR 

INTEGRATION // Dealing with the 

significant new load of EVs and the 

intermittency of distributed solar is 

a significant challenge. We need to 

address both the equity aspects and 

the engineering. 

(3.) PRIVACY AND SECURITY // We need 

to be trusted stewards of customer 

data while also protecting critical 

infrastructure, both from a cyber and 

physical security perspective. Both are 

must haves. 

(4.) BIG DATA AND DATA ANALYTICS // As new technologies (like smart meters and 

synchrophasors) are deployed that generate data at unprecedented levels, utilities 

must utilize analytics to extract value. 

(5.) OPERATIONS TECHNOLOGY/INFORMATION TECHNOLOGY (OT/IT) INTEGRATION // 

Skill sets of employees must evolve and utilities need to integrate planning, 

engineering and operating functions among IT, traditional grid operations 

(control center and in the field) and customer services. 

Branndon Kelley is CIO of American Municipal Power, a nonprofit corporation that owns 

and operates electric facilities with the purpose of providing generation, transmission 

and distribution of electric power and energy to its members in Delaware, Kentucky, 

Michigan and Ohio. 

Monica Whiting is general manager, customer revenue and services with Colorado Springs 

Utilities, a community-owned utility in Colorado Springs, Colorado, since 1924. 

Caroline Winn is vice president, customer services and chief customer privacy officer 

with San Diego Gas & Electric (SDG&E), a Sempra Energy company. SDG&E is a regulated 

public utility that provides energy service to 3.4 million people in San Diego and southern 

Orange counties in California. 



40 

OUT THE DOOR 

Focus on 

interoperability as 

only a part of the 

smart grid whole 

+ + Advice from Avista 


SMART GRID DISCUSSIONS MAY REVEAL DETAILS OF CUSTOMER 

benefits and notations about the use of “big data,” the current industry 

trend, but they sometimes ignore the basic necessities of a smart grid: smarter 

equipment, analytics ability and, at the core, interoperability. 

Having a holistic approach to both the smart grid and its necessities, such 

as interop, is the advice of Avista Utility’s Curtis Kirkeby, a senior electrical 

engineer in charge of technology strategy with more than 30 years in the 

industry. Kirkeby, who started his career in substation design and helped Avista 

self-build an interactive GIS system, suggests focusing on the whole. 

Founded in 1889, Avista is an investor-owned utility with annual revenues of 

more than $1.3 billion, Avista provides electric and natural gas service to about 

481,000 customers in a service territory 

of more than 30,000 square miles. The 

utility serves those customers with a 

mix of hydro, natural gas, coal and biomass 

generation delivered over 2,100 

miles of transmission line, 17,000 miles 

of distribution line and 6,100 miles of 

natural gas distribution mains. 

Avista’s Kirkeby said it’s true that 

having a step-by-step process that 

begins with interoperability will get 

a utility to the end-result smart grid 

eventually; and, one can piecemeal 

backward from meters and other 

smart grid equipment. Yet, Kirkeby 

believes a big-picture approach helps a 

utility move along the smart grid path 

more efficiently, as it has with Avista. 

“Yes, interoperability has to happen, 

but it’s not something to get in the 

way of your aspirations,” he insisted. 

Instead, Kirkeby suggests knowing 

where you want to go and creating an 

architecture that will get you there. 

Interoperability will be a part of that 

architecture, but Kirkeby warns that a 

single-focused view—one simply on 

interoperability, for example—may 

actually slow down the process. 

“If you encumber yourself up front, 

you create a system based on what you 

currently have, instead of what you 

can actually do,” he added. Kirkeby did 

note that it’s fairly normal in the field 

of engineering to focus on a single 

issue, but that may be a hindrance. 

There are a number of variables in the 

smart grid that you may have on your 

list (business cases, customer education, 

analytics) or not (manpower 

issues, budget constraints, regulatory 

interference). For Kirkeby, flexibility is 

key to a smoother, smarter system. 

To create that system based on 

what you can do, Kirkeby advises to 

begin with strategy. He suggests first 

examining components that work, 

researching geographic information 

systems and other areas within your 

utility with lots of data and then mapping 

out how those systems can synch 

up—both in areas that are necessary

“ 

and in areas that will simply be beneficial to the future. While you may not tackle 

all those areas at once, knowing the desired future state can help you lay a bit of 

groundwork while working on the necessary interconnections. 

“Get immersed in what’s in your system,” he said. “It’s a daily process.” 

In fact, that immersive process of mapping and creating interoperability may 

help you develop multiple purposes for equipment and analysis that you hadn’t 

thought of beforehand, Kirkeby noted. Although utilities traditionally operate 

in silos, isolated by area and specialty, one of the key benefits from having 

numerous people across multiple disciplines involved in this immersion process 

is that people gain visibility and understanding of the bigger picture. The result: 

Kirkeby believes interoperability work and a smart grid road map can actually 

help shake up that old-school vertical structure, a 

necessary shake-up for a holistic smart grid. 

If you encumber 

“Just because we’ve always done things a certain 

way doesn’t mean it should continue that way,” 

yourself up front, you 

Kirkeby concluded, revealing a final bit of advice 

for making interoperability work and the smart 

create a system based 

grid evolve a little faster. 

To make that evolution a bit smoother, Kirkeby 

on what you currently 

and Avista advise others to keep the customer in 

the loop: keep communications open with noti- 

have, instead of what 

fications that have real value to consumers and 

allow them to proactively control use. And, do 

you can actually do.” all of that with the focus on solutions. 

“If we can characterize the remedy, we can 

motivate the customer,” Kirkeby said. “Our mantra with the customer: Deliver 

actionable items. Information [by itself] doesn’t motivate.” 

For Kirkeby, the timeline for interoperability to smart grid work should be 

visualized in a more flexible, less linear fashion. You may have finished step A 

(the basics of interoperability) and be knee-deep in step B (updating equipment 

with smarter widgets, as Avista is doing with items as detailed as distribution 

transformers) but never stop planning for where you should be at steps G, R or 

T—all the way to that final, ending Z where the consumer sees benefits and can 

control use with ease and comfort. 

“It’s all about trying to define where you should be headed with the remainder 

of the system,” he said. “Don’t just focus on interoperability. Instead, know your 

system, know your plan and be strategic.” 

+ 

© ADVERTISER INDEX 

Company Page URL 

Aclara inside front cover www.aclara.com 

CSWeek 3 www.csweek.org 

Elster 11 www.elster.com 

NEW CONVERSATION 

STARTERS 

Not all of the interesting details 

of our chat with Curt Kirkeby 

could be discussed in depth in 

this short piece, but we wanted 

to include a few other notes 

from our fall discussion over 

coffee in Spokane that may 

start a conversation inside your 

operations group, too. Kirkeby 

additionally noted that: 

? ? There are so many smart 

grid standards that no 

product can meet every 

standard. 

? ? There is no compelling 

reason for the U.S. to 

change from DNP to 61850, 

and there is no bridge-over 

component in place to 

make that shift possible. 

? ? The combination of an 

industry slow to change 

and standards that are 

never finished tends to 

hinder smart grid evolution. 

? ? Shoving through XML for 

interoperability to ensure 

human readability may 

be detrimental to the 

developing data process. 

? ? Every utility needs cross- 

organization buy-in to 

succeed in smart grid 

implementation. 

EnergyBiz Leadership Forum 7 www.energybizforum.com 

Landis + Gyr 30–31 www.befutureready.com 

OSI 5 www.osii.com 

Schneider Electric back cover www.schneider-electric.com 

Siemens 1 www.usa.siemens.com/poweracademy 

UAI Summit 36–37 www.utilityanalyticssummit.com 


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Intelligent Utility Jan-Feb 2013

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