Intelligent Utility MayJun2012

VOL 4, ISSUE 3 » MAY/JUNE 2012

Where smart grid meets business—and reality.

ENTERPRISE INFORMATION INTEGRATION Utilities’ journeys differ

OMS+GIS+MWFM=?

STANDARDS + INTEGRATION IEEE weighs in

Silos vs Flat Plain Integrating the utility

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CONTENTS S PECIAL REPORT OMS, GIS + MWFM

24 Combining applications for a larger whole When the sum is much more than its parts

DEPARTMENTS

4 6

10

In this issue, the theme of integration permeates our

24

feature stories, from utility departments to enterprise information to a standards-based approach to integrating utility applications.

FEATURES // MAY/JUNE 2012

Silos vs. flat plain

10 Breaking down the walls

Collaboration, not silos, drives productivity

Enterprise information integration

16 Managing the utility’s enterprise information

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TransAlta Utilities tackles data governance first

2

Standards and integration

20 Navigating the smart grid transition smoothly A standards-based approach to integrating utility operations

UTILITY ANALYTICS INSTITUTE CONTINUING THE CONVERSATION

30 36 40 42

26 Driving business value from analytics Ideas and focus explored

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7 8

Drawing the line Transmissions 6

Letters from readers

Around the globe Top 12 8

Top 12 large municipal movers and shakers

30 IT insights

30 SmartGrid 2.0

Developments on the transmission system enhance its intelligence

32 Analytics tech talk

Old-school conferences reveal high-tech challenges

36 Operational perspectives

36 The challenges and benefits of implementing DMS

OG&E’s director of grid intelligence talks about deployment

38 Automating utility pole inspection

Orangeburg DPU will realize quick return on RFID investment

40 Customer focus

40 Consumer-centric outage communications

Oncor shares its forwardlooking steps

42 New metrics for customer service?

Intelligent Utility Daily’s Phil Carson takes a look at two recent utility consumer studies

46 Out the door

46 Smart energy, made in Germany

E-Energy pilot projects a research priority

Vol. 4, No. 3, 2012 by Energy Central. All rights reserved. Permission to reprint or quote excerpts granted by written request only.

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D R AW I N G T H E L I N E

This is not a test!

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REMEMBER WHEN TELEVISION AND RADIO STATIONS USED TO SOUND A LOUD,

4

two-toned alarm and announce: “This is a test of the Emergency Broadcast System ... If this had been an actual emergency, the Attention Signal you just heard would have been followed by official information, news or instructions...”?

Well, I’m sounding the alarm here, interrupting my usual editorial, and our entire industry needs to wake up and take note, right now!

While we move industriously forward with utility and enterprise integration, grid automation and consumer engagement (some of the topics covered in this issue), there’s yet another dangerous piece of anti-smart grid propaganda going viral on the Internet, disguised as documentary. Due to be released this spring on the Internet, “Take Back Your Power” is touted as “a hard-hitting documentary feature film which exposes the technocratic ‘smart’ grid agenda, by which corporations are currently attempting to quietly assert the basis for absolute control in the lives and homes of the world’s citizens.”

An eight-minute promotional video for this “documentary feature film” opens with the following words: “Governments and power corporations around the globe, through an incessant drive to ‘modernize the power grid,’ have directly created a situation where our entire civilization’s energy source is now in danger of being taken down. With hundreds of smart grid projects now being installed simultaneously around the world, we’re seeing a globally orchestrated move to quietly merge the entire power grid with the vulnerabilities of the Internet. While described by some as ‘insane,’ it is, at the very least, completely irresponsible, as it puts everyone at risk by totally opening the door to hacking.”

And that’s just in the first minute. Other accusations in the promotional video include “no demonstrated net energy savings” and “total and permanent power outage if this smart grid is allowed to continue.”

Don’t laugh. While we may find these accusations absurd, those without a day-to-day understanding of the electric system, and the problems intelligent technology and automation are designed to solve, are eating up this kind of scaremongering like a double helping of dessert before dinner. Case in point: as I write this, yet another Facebook poster has just written, linking to this documentary to share with her all her friends, “Could so many be wrong??? I don’t think so.”

Like lemmings, the uninformed are being led right off a steep cliff edge with dangerously erroneous propaganda such as this, and it is, to some extent, our own fault for not getting out in front of sue? Then Enjoy the is for free at it with widely available information—information that really “speaks” to electricity consumers— subscribe .com/ igentutility a lot sooner. Right now, we’re playing catch-up in the last few laps of the race. www.intell subscribe Is it too little, too late? How do we bridge the widening gap? Let’s discuss.

Kate Rowland Editor-in-Chief, Intelligent Utility magazine krowland@energycentral.com

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TRANSMISSIONS

Letters from readers in its other businesses, but made a bet on a more distributed future. That Great article! What a great example company did it once again when it of how social media can be used as moved into services and away from a support tool. Thank you so much commodity box business by selling its for sharing.

PC business to Lenovo.

Name withheld What IBM learned was that to survive, a leader Connecticut: needs to adapt, even if In Search that means giving up of Microgrids on a comfortable posiIntelligent Utility Daily, automating tion in the market. the April 2 Great industries What should a utility can be disrupted by do? Resist its impulse new technologies, for protectionism and if utilities can and go with the flow, perceive such changes embrace the future of as inevitable, they distributed energy, and give the public should run out in front of the parade, what it wants—a Plan B for grid delivor risk getting moved aside by forms ered energy that is subject to disrupof energy technology that are not tion. In the near term, more and more subject to disruption by storms, building owners and occupants will squirrels, or terrorists. embrace on-site power solutions when John Cooper given the opportunity and when the Partner, NextWatt Solutions price is right. In time, those technologies will become more feasible as an Meter data, applied independent system (a microgrid).

Intelligent Utility Daily, March 1 Radical thoughts? Think again.

With all that meter data for the utility There is no wall a utility can build to chew on, how about tossing the custhat is high enough to keep distribtomers a bone? Offer people the option uted energy technology away from its of getting a text message each morning, customers. Utilities should follow the consisting of the following: Yesterday’s lead of IBM in the early 1980s, and energy consumption: XX kWh. Average embrace the future by shifting market past 30 days: XX kWh/day. Cost this focus with one eye still keenly on the billing cycle to date: $XX.XX. That ball. Faced with the advent of personal will give anybody who wants it a quick computing and on top of the world snapshot of whether something untowwith its mainframes and minis, IBM ard happened yesterday and whether gave its name to a PC design and the they will likely need to do something IBM PC clone was born. IBM stayed different to manage their usage or bill.

Even energy geeks like me only get a chance to visit a website and see all To contribute to the Transmissions department, those pretty kWh profiles one per week please e-mail your submission to at most. People need the option for intelligentutility.editor@energycentral. more frequent feedback, without com. Provide your name, address and having to browse for it. daytime phone number. Letters may be Improving customer experience January/February 2012

VOl 4, Issue 2 » March/aprIl 2012

Where smart grid meets business—and reality.

suBstatIOn autOMatIOn Best practices shared FeeDer autOMatIOn FlIsr provides smart brains

grID DMS of the future, now

utIlIQ tOp 3 utIlItIes

An E n E rgy C E ntr Al Pu b liC Ation

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6

edited for style and space.

Greg Tinfow CEO, Energy Informatics LLC

www.intelligentutility.com EDITOR-IN-CHIEF Kate Rowland

krowland@energycentral.com 250.227.8938 SENIOR CONTRIBUTORS

Phil Carson Editor-in-chief, Intelligent Utility Daily pcarson@energycentral.com 303.228.4757 FEATURE WRITERS

Mike Breslin, John Johnson, Phil Johnson, Laurel Lundstrom, Elizabeth McGowan COPY EDITORS: Martha Collins, J. Ian Tennant ACCOUNT EXECUTIVES

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AROUND THE GLOBE EUROPE

BRAZIL

Preparing for new power system challenges

Growing smart grid The Northeast Group recently released new research on

According to Maire GeogheganQuinn, EU commissioner for research, innovation and science, Europe’s first priority is to focus on R&D policy in order to reach the great challenges facing it. Two such challenges, she said, directly relate to the European power system: climate change and energy security. The latter, she said, cannot be realized without a reliable electricity supply.

In late February, InnoGrid2020+ (the joint European Network of Transmission System Operators for Electricity [ENTSO-E], the European Distribution System Operators’ Association for Smart Grids, and the GRID+ seminar on R&D dissemination) brought together more than 140 experts from nearly 100 companies, institutions, organizations and EU member state representatives, to discuss the major challenges arising for

transmission and distribution grids as a result of the increasing share of variable and decentralized generation and the integration of the energy markets.

One key point arising out of the two-day seminar included the understanding that technologies, equipment and ITC tools need to be developed urgently in order to balance vast amounts of wind and solar generation with consumption in real time, and the deployment of cost-effective smart grid solutions, empowering customers and allowing for demand response as well as for charging electric vehicles.

To help this along, more collaboration on research and development as well as large-scale demonstrations in real working conditions also involving the consumer and regulators are required, seminar attendees felt.

Acknowledging the urgency of these issues, Hubert Lemmens, chairman of the ENTSO-E R&D committee, invited stakeholders to further debate them this year with ENTSO-E and EDSO for Smart Grids representatives.

Brazil’s smart grid investments, forecasting that they will reach US$36.6 billion by 2022. Curbing electricity theft tops the list of the country’s most urgent imperatives for smart grid.

According to the report: “A very significant problem in Brazil is the high rate of electricity theft.

This is both a public safety issue and also unfairly requires paying customers to subsidize those stealing power. Smart meters are very effective tools in helping reduce electricity theft.”

Brazil also plans to use smart grid technology to improve reliability of the electric infrastructure and offer new pricing plans for customers. It also wants to pave the way for economic growth for the country.

INDIA

Robot transmission line inspection possible Three engineering students from AC Patil College of Engineering, Navi Mumbai, have developed a prototype robot for inspecting

with thermal and ultrasonic sensors, as well as a camera, is designed to identify faults while sliding over

infrastructure, is the key to Brazil’s smart grid program, according to Northeast Group. Sixty-three million AMI meters will be deployed by 2021, led by ANEEL, the Brazilian electricity

transmission lines, especially in areas where faults cannot

regulator. The coming year is

be spotted easily due to the line’s placement, such as over rivers and

expected to bring detailed regula-

in forests. The three students are in talks to commercialize the robot

tions to kick-start large-scale

prototype with the Power Grid Corporation of India.

implementation across Brazil.

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transmission lines. The robot, which is equipped

AMI, or advanced metering

7

TOP 12

TOP 12 utility champions ++In the large municipal electric utilities of the U.S.

By Kate Rowland WITH THIS ISSUE, WE TAKE A CLOSER LOOK WITHIN OUR

Top 12 for 2012 at the champions of large municipal electric utilities across the United States.

As with the unsung heroes of large electricity co-ops, the first thing these champions will tell you is that they represent their entire team. Therefore, my choices here both honor these 12 people and the teams with which they work.

These 12 represent, too, the work done by progressive municipal utilities across the country. In upcoming months, we hope to tell the stories of those not named here, as well.

As vice president of information technology and CIO of the New York Power Authority, DENNIS ECCLESTON has a lot on his plate. His responsibilities include implementation and support of IT applications; operation of the corporate data center; operation and maintenance of network and server infrastructure; cyber security; telecomm operation and maintenance; and customer service in support of IT. The NYPA is the nation’s largest state-owned electric utility, and is a leader in advancing energy efficiency and the development of clean energy technologies and electric vehicles.

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VIC HATRIDGE has served as vice president and chief information officer for

8

Nashville Electric Service (NES) for 15 years, and is responsible for all commercial computer and telecommunications systems. Hatridge is extremely active in the utility community, both with the American Public Power Association Information Technology committee and more broadly with the Nashville CIO Council. NES is a municipal electric distribution utility serving more than 350,000 customers in metropolitan Nashville, Tennessee.

JERRY HERNANDEZ, Austin Energy’s director of smart grid and system

operations, was previously Austin Energy’s division manager of the information technology and telecommunications enterprise networking and enterprise services group. Austin Energy is the nation’s ninth largest community-owned electric utility, with about 430,000 customers, and covers a population of nearly one million. It has successfully completed its AMI deployment, and is now using information gathered to improve its response to outages.

As chief operating officer for the Long Island Power Authority (LIPA), MICHAEL D. HERVEY has headed up the development of LIPA’s smart grid strategies, implementation of storm hardening strategies and more, in addition to his oversight responsibility for the operations, customer, resource and industry-facing aspects of LIPA’s T&D business. LIPA is the second-largest municipal electric utility in the U.S. in terms of electric revenue, third-largest in terms of customers served and seventh-largest in terms of electricity delivered.

MARIA KOUDOURIS, vice president of customer service and solutions for CPS Energy, oversees meter reading and field collections, customer call center and customer service centers, management of commercial accounts and the Casa Verde SA weatherization program, which she spearheaded in 2009. CPS Energy serves more than 707,000 electric customers and more than 322,000 natural gas customers in its 1,566-square-mile service territory.

MATTHEW LAMPE, CIO of the

Los Angeles Department of Water and Power, is responsible for strategic and operational direction of LADWP’s information technology and telecommunications organizations, as well as application development for all divisions of the utility. LADWP is the largest municipal utility in the country, serving 4 million residents and businesses in Los Angeles and surrounding communities.

FRANKIE MCDERMOTT, director

of customer services at the Sacramento Municipal Utility District (SMUD), oversees all customer-related operations, programs and services, including the call center, billing and credit, field services, energy efficiency and renewable energy programs, and manages the changing relationships with customers as SMUD moves forward with its smart grid projects. In mid-April, SMUD

Not pictured are: Jerry Hernandez, Michael Hervey and Carrie Young.

completed installing smart meters for its more than 600,000 residential and business customers.

As vice president of customer relations, MARLENE MURPHY-ROACH

DAWN ROTH is general manager of

information technology services for Colorado Springs Utilities, and leads 160 employees focused on every aspect of technology for a four-service (water,

STEVE SCHMITZ, Omaha Public Power District’s division manager, informa-

tion technology district, has been active in the electric utility community for many years (see “Focusing on customers” March/April 2012 Intelligent Utility).

An employee with the OPPD since 1989, he has held numerous leadership and management positions. The OPPD serves more than 346,000 customers in 13 southeast Nebraska counties.

Seattle City Light’s customer service and energy delivery officer, PHIL WEST, joined the utility in early 2010, moving north from SMUD. Among his duties at Seattle City Light, West is responsible for leading a number of infrastructure improvement projects, including the utility’s recently implemented outage management system. The utility has nearly 400,000 business and residential customers, and covers a service area just over 131 square miles.

CARRIE YOUNG manages Salt River Project’s revenue cycle services, including

all aspects and operations of the revenue cycle from meter to bill. Young cochair’s SRP’s Smart Grid Leadership Committee and sets the strategic direction for smart meter infrastructure. Based in Phoenix, Arizona, SRP provides electric power to more than 930,000 customers throughout a 2,900-square-mile service territory, and is one of the few U.S. utilities to offer a comprehensive prepayment option to customers.

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provides direct leadership for JEA’s customer relationship department.

In an interview last year, she told me, “In our view of the smart grid, and our focus in our deployments ... JEA is primarily looking for benefits that can benefit our customers.” She epitomizes this focus in her leadership of customer relationships. JEA owns and operates the largest community-owned utility in Florida, and the eighth largest in the U.S., with more than 417,000 electric customers in Jacksonville and parts of three adjacent counties, as well as water and sewer customers.

gas, electric and wastewater) utility, including software, hardware, network, database, telecommunications, Internet and Web 2.0 tools. Colorado Springs has been installing automated meters for gas, electric and water service since 2006, and has nearly completed installation across its entire territory. The community-owned utility serves 600,000 customers. Its overarching plan calls for a multi-service smart grid.

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SILOS vs

flat plain Breaking down the walls ++Collaboration, not silos, drives productivity

By Phil Carson SILOS IN BUSINESS ARE FAMILIAR BARRIERS TO

Process re-engineering provided foundation SMUD initially used a third-party facilitator and software to develop new processes and key performance indicators for its realignment. The utility followed tenets for process re-engineering developed by Michael Hammer in the late 1990s and early 2000s. Concepts that guided the resulting changes included such notions as “process ownership” and “shared accountability.”

The first concept – “process ownership” – took the notion of governance from responsibility for outputs to responsibility for end-to-end processes. The second idea meant that performance evaluations included emphasis on joint goals and metrics, with compensation tied to the achievement of common goals.

One innovation was the creation of a group dubbed “Enterprise Workforce Services,” according to Gary King, chief workforce and technology officer at SMUD. That group works to ensure that cross-functional processes tap resources from each business unit to improve integration and collaboration—and keep that line straight from point

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effectiveness, particularly when change drives an organization’s agenda.

Yet achieving desired outcomes requires focus, and focus often is expressed in organizational units for many good reasons. Departments are comprised of people with relevant knowledge and skills, inevitably leading to separate missions and cultures between departments.

New challenges in the power industry such as the new focus on customers and the grid modernization that supports it raise the issue of how to promote cross-functional collaboration for the sake of the entire organization.

Solutions to this perennial challenge often invoke eyeglazing management-speak or the sorts of disingenuous shenanigans that might make an episode on “The Office.”

What are effective utilities actually doing to eliminate silos and produce quantifiable results?

The Sacramento Municipal Utility District (SMUD) and Toronto Hydro-Electric System Limited have both implemented seismic organizational shifts for overall success, raising transparency and shared accountability while lowering the silo walls.

SMUD’s “reason to exist”: customers SMUD’s journey began more than a decade ago when the municipal utility focused on driving satisfaction for its 600,000 metered customers in California’s capital, according to Paul Lau, assistant general manager, power supply and grid operations.

“As a community-owned municipal utility, if we cannot satisfy our customers’ needs, we have no reason to exist,” Lau told me recently.

That fresh focus meant re-evaluating every aspect of the utility’s business and operations, aligning them with customer needs. That involved shifting a traditional, vertically organized company to a more horizontal one that could meet its mission via “the shortest distance between two points,” as Lau put it.

11

SILOS VS FLAT PLAIN

A to point B. Organizational development specialists in that group serve as internal consultants who work with operating segments of the business to facilitate alignment between efforts and outputs, King told me.

Every business unit, from customer service and operations to engineering, had to work in cross-functional groups to ensure that the process for delivering customer satisfaction followed that straight, short line from A to B. In the case of the old IT-OT disconnect, organizational changes placed both departments directly under one executive.

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Measuring customer satisfaction The external measure of customer satisfaction inevitably falls to third-party J.D. Power and Associates. To drive those results, SMUD also instituted outreach via its “Forty Days and Forty Nights” program that holds public meetings to explain its evolving direction and conduct customer focus group meetings. Using third-party facilitation, SMUD conducts focus groups, monthly customer surveys and market research on every customer touch point, from power reliability to tree trimming. The organization scrutinizes every project from start to finish based on its evolving sense of customer-focused mission and accomplishment.

SMUD recognized that “emotional connections”—a passion for organizational success—were needed, and needed to be tracked. Gallup, the survey organization, annually assesses employees’ engagement, and results are shared with fellow employees and supervisors. That results in “impact plans” that drive prioritized engagement practices.

Nearly four years ago, SMUD’s successful application for a Smart Grid Investment Grant from the Department of Energy drove renewed efforts to institutionalize these adaptations. That brought responsibility for SMUD’s distribution engineering, IT and customer service (including programs such as energy efficiency and renewable energy) all under one executive, the assistant general manager.

And today?

12

Transparency and metrics in DNA now “Smart grid is a way of life, not a project,” Lau said. “How could we internalize that to accommodate the new, two-way paradigm with a customer role in distributed generation, solar photovoltaics, electric vehicles, energy storage, demand response and pricing programs and integrate them into our distribution, transmission and generation systems to deliver maximum benefits to our customers? We are realigning our organization again to optimize the customer experience and operational excellence.

“The fact is, our sense of value to the customer never changes,” Lau concluded. “That has become our driver.

We don’t talk process re-engineering anymore. We have

realigned our organization. Transparency and metrics are in our DNA.” Yet the dedication to maintaining that straight line from A to B requires constant, consistent efforts.

“We can never say ‘we’re done,’” King added. “The pace of change is increasing. We need to be nimble to adapt to that change.”

Asked for lessons learned, Lau cited traditional ones such as executive buy-in and leadership, discipline and “don’t underestimate the effort required by change management.”

He cautioned that an organization must have the appetite and urgency for productive change.

“Do you have the fortitude?” he asked rhetorically.

“Expect pushback. Understand the internal ‘emotions.’

And be brave.”

Tracking change in Toronto Toronto Hydro-Electric System, which We have serves a city with 705,000 metered customers, began life in its current realigned our form in 1999 when six small utilities merged. That industry restructurorganization. ing and amalgamation resulted in workforce consolidation, followed by Transparency a drive for business transformation that was initiated in 2000 and remains and metrics are a fundamental value today.

Toronto Hydro followed the prinin our DNA. ciples of a Management Control and Reporting System, or MCRS, which brought the discipline of standardized management practices to the organization. The principal discipline was to impose short-interval controls on all end-to-end processes that would henceforth be measured in days, weeks and months, Rob Wong, vice-president, information technology and strategic management, told me.

That effort has been paralleled by a leadership development program that has played a role in nurturing executive talent among those who understand that organizational outcomes trump departmental successes.

“

”

Becoming a performance-oriented organization “We place a lot of emphasis on organizational development,” Wong said. “Collaboration is the key criteria, as are internal and external stakeholder management. Are we 100 percent there? No. There’s always room for improvement.

“But we’ve become a performance-oriented organization,” he added. “We use a ‘balanced scorecard’ system that depends on key performance indicators. A large part of executive compensation is dependent on those KPIs. And we have rigorous systems in place that track this stuff.

We manage down to the individual.”

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SILOS VS FLAT PLAIN

At a strategic level, the utility’s “balanced scorecard” rests on four pillars—customers, financials, operations and people—that compose the corporate KPIs. Common business case templates are applied across the organization for projects to ensure that benefits and outcomes are strategically aligned with those four pillars.

Wong echoed Lau at SMUD when he emphasized executive buy-in—with a twist. The organization’s five core business processes are each owned by an individual executive, so that “everyone has skin in the game,” Wong said.

Change management and process engineering sometimes require succession policies to complete the de-siloing process, Wong noted. For instance, in Toronto Hydro’s case, that IT-OT divide didn’t fully fall until like-minded executives who agreed on organizational imperatives were promoted to enforce such changes.

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Management success You’ve heard the term “continuous improvement,” typically followed by jargon. At Toronto Hydro, performance trends are analyzed and baselines established, from reportable injuries to attendance, from operating cost targets to net income. System reliability is defined by familiar metrics such as the frequency and duration of outages, and that analysis extends to the feeder level for greater transparency on actual impacts to customers. Beyond familiar metrics, “stretch targets”—harder-to-attain goals— are identified as new challenges year-over-year.

Initially, all this business transformation was achieved with help from a third-party consultant and software applications, Wong said. As the organization internalized the processes, the MCRS principles became a standard for management practices.

One initial issue for other utilities on a similar path may be how to best select a third party to assist.

“For me it’s a matter of a cultural fit,” Wong said.

14

Keeping the lights on through change And then there’s risk involved with degrees and speed of change. A utility has to keep the lights on while it breaks down those silo walls.

“Every organization is different,” Wong said. “What’s your level of preparedness? How much change can you live with?

Sometimes there’s just too much effort for the benefit. You want to avoid a point of diminishing returns.”

In a rough analogy to SMUD, Toronto Hydro has an executive whose bailiwick encompasses organizational development, including leadership development and change management. That’s Ave Lethbridge, vice president of organizational effectiveness and environmental, health and safety, who focuses on “people systems.”

Over the past dozen years, since the merger of six utilities into one, that work has focused on managing to achieve goals, measured by KPIs. “That doesn’t happen overnight,” Lethbridge cautioned.

“Begin where the organization is experiencing the most pain.”

Advantages include shared accountability Organizationally, a simpler, flatter structure has advantages, she said. Tying common goals across process lines brings shared accountability, which when tied to compensation can level the walls that once housed silos.

The uncertainties wrought by change can be overcome when replaced by executives’ and workers’ confidence that there’s rigor around achieving goals and a consistent system for rewards and recognition, according to Lethbridge.

It appears that, at Toronto Hydro, “organizational development” is akin to “staff development,” in that hiring and promotions are driven by the same values. The “fit”—that is, the recognition of the organization’s emphasis on collaboration and the ability to address it—is more important than technical qualifications, Lethbridge told me. Those who consistently demonstrate their ability to contribute to the organization’s core performance metrics, working collaboratively with a focus on customer value, get promoted.

Lethbridge called these “behavioral competencies.”

Accountability means not just achieving results, but how you achieved them, she said. Employees are rewarded for both the “what” and the “how” goals are achieved.

In her decade with Toronto Hydro applying this thinking and evolving a platform to support it, Lethbridge has seen the importance of sustainability—remaining flexible, responsive and true to its alignment with its goals over time. After all, Toronto Hydro, like other utilities, faces generational turnover and strives to consolidate its hard-won gains.

Facing a new challenge Toronto’s work in driving organizational transformation today faces new challenges: an aging workforce and need to replace aging distribution structure while facing external pressures on electricity rates.

That may be another lesson learned. If you don’t know what’s coming down the pike, you’d better be prepared for anything. Determining organizational success and aligning people and processes to achieve it increasingly looks like an effective way to prepare for the unknown challenges ahead.

Phil Carson is editor-in-chief of Intelligent Utility Daily. He can be reached at pcarson@energycentral.com.

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Managing the utility’s enterprise information ++TransAlta Utilities, and others, tackle data

By Kate Rowland

W WW.INTELLIGENTUTILIT Y.COM /// MAY/JU N E 2012

ENTERPRISE INFORMATION MANAGEMENT AND

16

smart grid integration are the heart and lungs of the new utility world. That is, if we accept that smart grid integration is the heart, then enterprise information management is surely the lungs of the intelligent utility.

Enterprise information management, at its core, means the structuring and governance of information assets across the utility, overarching the historical boundaries that have defined IT information and data, operational information and data, customer service information and data, and so on. In so doing, the utility has the ability to take enterprisewide ownership and responsibility for the data, including its

accuracy and quality, in order to improve both the data itself, and the company’s operations.

While enterprise information management (EIM) is not a new term, its importance has come to the fore more recently, as intelligent utilities are amassing more data through devices throughout the grid, and more information about electricity usage patterns, load shapes and more.

At the recent Utility Analytics Summit, a number of utility directors discussed their road maps to enterprise information management and integration, and shared their experiences to date.

Strong business team critical in efforts Hydro One, one of the largest electricity delivery systems in North America, controlling 100 percent of the transmission in the province of Ontario

as well as a 123,528kilometer distribution system, set up its information management program in 2008 and set both short-term and long-term goals for it at the time, said Brad Bowness, Hydro One’s director of business architecture and IT, with the strategy being set in the first year.

“It took us one-anda-half to two years to implement the recording stack,” he said. In 2009, the system’s foundation was established, and it went live. With that experience then under its belt, Hydro One spent 2010 and 2011 stabilizing and enhancing the program, and started 2012 with what Bowness described as “continuous improvement.”

“Taking two years to stabilize the system is important,” he noted.

Hydro One’s asset analytics initiative brought information from the operations technology side of the house and correlated it with other data. “A strong business team is critical (in the information manage-

ment program effort),” Bowness said. “During the initial implementation, we had a key business team, who have lived and breathed it through the entire life cycle.”

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A valuable work in progress Dean Balog, a self-described “data dude” and TransAlta’s director of enterprise applications, discussed the three areas of focus of TransAlta’s EIM: data governance, business intelligence and data architecture and modeling.

It’s a work in progress: the data governance program launched the week before the February summit, Balog said.

“This year, the focus is on process, roles and responsibilities, and a focus on data quality,” he explained. “We need to have people understand what data governance is, and their roles in it. That’s the role of the pilots.”

The utility is also focusing, in its early implementation, on data quality. Here is an area in which the old adage, “garbage in, garbage out,” holds true, as decisions are made based on the data available, and bad data can result in lessthan-optimal decision-making.

TransAlta already has some early data governance successes. Data is now a priority, directly from the CEO on down.

As well, Balog said, “business is on board and motivated.”

With that, he also shared lessons learned: “Persistence is important—three to five false starts are normal,” he said. “Look for small wins, and communicate success widely. Finally, external domain experts can help to explain the concepts.”

Balog says the next steps for TransAlta’s EIM program include a transition from pilot projects to a sustaining EIM practice, with information life cycle management rolled

17

ENTERPRISE INFORMATION INTEGRATION

into the mix. The utility also plans to link data governance to business intelligence governance. New tools will be investigated to assist the utility in its EIM focus. And, of course, a policy review is on the “to-do” list, as well.

W WW.INTELLIGENTUTILIT Y.COM /// MAY/JU N E 2012

A single version of the truth First Choice Power, based in deregulated Texas, formed a centralized analytics group a few years ago. The prime challenge, according to Lloyd Tokerud, the utility company’s manager of analytics, was the complexity of the data.

First Choice’s centralized analytics model promotes what Tokerud describes as “truth and consistence.” (This has also been described by others as a “single version of the truth” for data over time.)

Further, the centralized solution adopted by First Choice means education and training are reduced, and live data sessions with executives accelerate decisions.

“Our philosophy is, first, start big, and start in the middle with one thing that matters most,” he said. “And,” he added, to knowing chuckles from the audience, “speed, accuracy, scope: pick two, because you can’t have all three.”

First Choice uses visualization to accelerate business intelligence, or “prove it, then build it.”

“We gather the information manually, then use a visualization tool to rearrange the data in real time for consensus, so that we can build only what’s relevant,” he said. “This kind of approach has worked well for us.”

18

Making decisions more easily The underpinning of Southern California Edison’s analytics model, SCE’s Ron Grabyan, manager of business intelligence services, said, is “enabling the business to get to the data to make their decisions. We’ve been doing continuous improvements all along, small changes. We want to make big changes.”

Part of those changes include migrating SCE’s entire data warehouse into an environment that will allow analysts to get their data faster.

The current environment, he said, has many challenges, including report response time, data loads, and build and maintenance costs. “In the 2012 environment, however, we are not developing as many objects.”

The benefits of this new approach are many, but these two are significant. In the area of performance improvement, SCE is getting reports approximately two to three times faster, and data load is proving to be three times faster.

“We can provide an environment for analysts to get their data faster,” Grabyan said.

Multiple enablers Consumers Energy has approached enOur philosophy is, terprise information management in a first, start big, and somewhat different fashion, according to start in the middle Stephen Hirsch, director of data quality with one thing that for the utility.

Consumers Energy, matters most. an integrated gas and electric utility in Michigan, launched its information quality program in the mid-2000s as it began replacing a range of legacy systems with an enterprise-wide system.

“The high-level goal of our project,” he said, “is to enable customer experience value, to use customer data for competitive advantage, to facilitate safe and reliable actions and to help ensure consistent financial performance.”

In terms of program value and outcomes, Consumers Energy is looking for quality, accurate data that enables: detailed segmentation (enabled by customer data); a better categorization of customers to facilitate providing the appropriate programs to the appropriate customers; an improved understanding of parent/business partner relationships; and lower invoice processing and anti re-work costs.

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STAND ARDS AND

INTEGRATION Navigating the smart grid transition smoothly ++A standards-based approach to integrating utility operations

W WW.INTELLIGENTUTILIT Y.COM /// MAY/JU N E 2012

By Dick DeBlasio

20

WE ARE IN A PERIOD OF RAPID, GLOBAL

rollout of smart grid standards. With the smart grid’s promise dependent on crossing the various geographic, operational and technological boundaries that have historically defined electricity delivery around the world, standards serve as bridges for two-way power and information flow end-to-end across an infrastructure that more closely connects energy generation, distribution, delivery and consumption.

So fast and furious is standards development for the smart grid around the world, in fact, that the utilities on the vanguard of real-world rollout may feel a little befuddled in

trying to make sense of what is and is not possible today.

Thanks to key development activities over the past decade and a new era of smart grid-driven coordination among standards development organizations (SDOs), a standards-based approach to integrating utility applications is, indeed, possible.

Grid interconnection, for example, has been a point of emphasis of the standards community for several years, providing utilities and distributed-generation operators with the ability to flexibly implement standards and tailor processes and infrastructure accordingly. Storage has more recently emerged as a fervent area of standards development.

Innovation in interconnection Leveraging renewable energy sources on significantly greater scale is among the most commonly shared goals of smartgrid deployment around the world. Expanded reliance on distributed generation of renewables promises a host of revolutionary benefits, including enhanced grid reliability, strengthened national energy strategies and reduced environmental impact and costs.

For utilities, however, the prospect of large-scale penetration of renewables has been a major concern. Utilities are determined to not let distributed and inherently intermittent sources of energy, such as wind and solar, threaten their traditionally strong profiles of service reliability and availability and power quality. Given that utility electric

W W W. I N T E LL IG E N T U T I L I T Y.CO M

power systems (EPS) were not initially engineered to link Integration standards are growing with active, distribution-level generation and storage tech- First, there are extensions to the IEEE 1547 base stannologies, how can such technologies be safely, simply and dard itself. A host of standards, application guides and smoothly integrated with utility EPS and the grid? recommended practices—addressing conformance test These are the types of questions that the U.S. Department procedures, monitoring, information exchange and conof Energy (DOE) sought to answer trol, island systems and distribuwhen it funded the research into intion secondary networks—have The prospect terconnection methods that, in 2003, fleshed out the IEEE 1547 suite. And yielded IEEE 1547™ “Standard for development continues. For exof large-scale Distributed Resources Interconnected ample, IEEE P1547.8™ “Recomwith Electric Power Systems.” mended Practice for Establishing penetration Addressing performance, operation, Methods and Procedures that testing, safety considerations and mainProvide Supplemental Support of renewables has tenance of a grid interconnection, IEEE for Implementation Strategies for 1547 delivered groundbreaking techExpanded Use of IEEE Standard nical specifications for installations of been a major concern.

1547” is intended to expand the distributed-generation technologies of relevance of the base standard 10 MegaVolt Ampere (MVA) or less at the point of common coupling. The U.S. Energy Policy Act to additional technologies such as energy storage, hybrid of 2005 named the standard in its discussion of interconnec- generation storage systems, intermittent renewables, plugtion services, and 80 percent of public utility commissions in electric vehicles and inverters used in home solar power (PUCs) in the United States have adopted IEEE 1547. IEEE systems and other devices.

Then there’s IEEE 2030® “Guide for Smart Grid in 2008 re-affirmed the standard.

Furthermore, the successful IEEE 1547 development Interoperability of Energy Technology and Information effort—which relied on open, consensus-based processes— Technology Operation with the Electric Power System has spawned other key standards in relation to integrating (EPS), End-Use Applications, and Loads.” Its development utility applications. effort was modeled on that of IEEE 1547. Communications,

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STANDARDS AND INTEGRATION

W WW.INTELLIGENTUTILIT Y.COM /// MAY/JU N E 2012

information technology (IT) and power engineers came together in March 2009 through the IEEE 2030 Working Group to define the necessary elements and functional requirements of the emerging smart grid, and the cross-discipline collaboration was unprecedented in standards development.

Power engineers identified the devices and information on which the smart grid would rely in order to function, and communications and IT engineers studied how to enable secure, two-way data flow end-to-end across the grid.

Dozens of standard interfaces that would be required for integrating utilities with end-use applications and technologies were identified. In September 2011, IEEE 2030 was published, becoming the first foundational, system-of-systems standard developed from the ground up to explore interconnection and interoperability in the smart grid.

22

The storage frontier Now, with so much research and standards work having been conducted around improving interconnection, storage has moved to the forefront of activity. It is a logical progression.

While interconnection technologies and standards development have advanced to support significantly expanded reliance on renewable energy sources in the smart grid, there are additional challenges that utilities face in adopting wind, solar and other such sources for voltage support, supplemental peak power at critical operational times and other ancillary services in large scale. A substantially more robust storage capability is necessary, and, again, the inherent intermittency of renewables is the primary issue in the engineering problem to be solved.

For the sake of consumer and worker safety, grid stability and power quality, utilities must conform to regionally diverse regulations with regard to the frequency and voltage bands within which they are allowed to deliver electricity.

To offset the uncertainty of not knowing when the sun is going to shine, when the wind is going to blow, etc., the energy drawn from such sources must be able to be stored in order for utilities to buffer their dynamic effect and to advance into large-scale integration of renewables for operational optimization.

This need is the seed of IEEE P2030.2TM “Guide for the Interoperability of Energy Storage Systems Integrated with the Electric Power Infrastructure” and IEEE P2030.3TM “Standard for Test Procedures for Electric Energy Storage Equipment and Systems for Electric Power Systems Applications,” both of which are currently under development. IEEE P2030.2 is envisioned as a sweeping technical knowledge base for discrete and hybrid energy

storage systems—defining terminology, functional performance, interoperability of various system topologies, evaluation criteria, operations, testing and engineering principles, etc. IEEE P2030.3, then, is intended to focus on the test and conformance verification concerns associated with integrating such storage systems with the electricity grid.

Standards Coordination Coordination is taking shape around and across the global standards community with regard to the smart grid, and this, too, is a helpful trend for utilities that are seeking to take a standards-based approach to integrating their applications.

IEEE 1547, for example, was among those standards that the U.S. National Institute of Standards and Technology (NIST) identified as important for encouraging smartgrid development to proceed in the United States. And the launch of the IEEE P1547.8 standards-development project was informed in part by a NIST Priority Action Plan that urged expanded interconnection functionality. Similarly, the International Electrotechnical Commission (IEC) has launched a multidimensional graphic interface—the “Smart Grid Standards Mapping Solution”—that details the standards that are needed within a particular subsystem of the grid.

There are instances of various SDOs working together, too. IEEE P2030, for example, is a system-of-system guide to the interfaces across the smart grid, and, as such, it names important standards from a variety of other SDOs in order to provide a comprehensive road map of the options available to utility and manufacturer engineers. Another piece of evidence for this trend is the partnership forged by the IEEE Standards Association (IEEE-SA) and SAE International in smart grid-related vehicular technology, toward the goal of faster introduction of better standards.

The smart grid is a tremendously complex undertaking for the world’s utilities, which must at the same time balance the promise of integrating innovative applications and modes of operation against the necessity of maintaining power reliability and quality levels and controlling costs.

A framework of globally relevant standards is gathering form to help utilities navigate that transition smoothly.

In addition to his role as chair of the IEEE 2030 Working Group

(http://grouper.ieee.org/groups/scc21/2030/2030_index.html),

Dick DeBlasio is a member of the IEEE Standards Association Board of Governors and chief engineer with the National Renewable Energy Laboratory (http://www.nrel.gov/).

SPECIAL REPORT

» OMS, GIS + MWFM

Combining applications for a larger whole ++When the sum is much more than its parts W WW.INTELLIGENTUTILIT Y.COM /// MAY/JU N E 2012

By Kate Rowland

24

FOR MORE THAN A DECADE, GEOGRAPHIC INFORMATION

systems (GIS) have been inextricably linked to outage management.

The reason? GIS is able to integrate all the essential data from SCADA systems, customer information, work orders and the network, and put it all into play for a more rapid field crew response to outages.

Whether the utility is large or small, GIS has its advantages. Service quality and restoration time are equally important, whether you have a thousand customers, or millions. In a large service area covering thousands of square miles with differing geography, the advantages of using GIS-supported outage management are a no-brainer. Field crew efficiency must be optimized, the outage and its fallout must be identified in order to prioritize crew repairs, and it all has to be done quickly, with real-time outage data able to be mapped to physical assets.

Consumers Energy has better visualization Consumers Energy, which provides electricity and natural gas service to almost 6.5 million of Michigan’s 10 million residents, deployed a new outage management system (OMS) using GIS in 2008 to replace its 25-yearold, mainframe-based, non-geographic system. According to Wendy DeVries, a member of Consumers Energy’s OMS project team, who wrote about the project after its launch, the visual and analytical capabilities that the new system would provide gave Consumers Energy the advantage of being able to see more clearly the conditions affecting its distribution network.

Managing outages across a 35,000-square-mile service area with varying geographical landscapes, while maintaining service quality and keeping outage time to a minimum, brings with it some definite challenges. Prior to the new OMS deployment, Consumers Energy dispatchers and crews had to rely upon limited customer call information regarding the outage or outages. In the case of

wanted to create digital maps of its entire network, in order to enable its field crews to respond more quickly to outages. As well, moving to digital maps would improve network data accuracy, and help to keep both customers and utility staff better informed.

So, the co-op took to the field with its GIS, mapping everything in its entire service territory, including every customer meter. A mobile GIS application now allows the utility to transfer information to and from the field. As but one example, field workers can now make notes, or redlines, on their personal computers while in the field, and then sync with the GIS server once they return to the office to send those notes to all other users, as well as to Northeastern REMC’s mapping department for review.

GIS mapping also allows the utility to create optimal driving routes for field crews, taking into account all information available, including all applicable network data, to further reduce outage response time. Staff and customers both are better informed with new data that can be viewed by staff, revised and searched from the office and from the field.

multiple outages, trying to figure out whether the incidents were related was also difficult.

A more advanced geographical OMS provided both visual and analytical capabilities that would allow Consumers Energy to digitally map physical assets and spatial relationships with its GIS, and then marry that with outage data provided real-time, for a better understanding of the outage or outages, and the means to respond and repair the issue more quickly.

Mapping everything A visual map of utility assets means real-time visibility, a tool of extreme importance in this new era of customer expectations and utility abilities. It can also provide the ability to automate certain tasks, from linking field workers with mobile supervisors and the dispatch center to dispatching work orders to the closest crew, and much more. In this case, knowledge is power, and visibility means the ability to provide the customer with much better outage restoration information than ever available before.

In an era in which Google Earth can provide satellite images and street-level views to the average home computer operator—though, granted, these images are not real-time—consumers expect their electric utility to be able to know, without a telephone call, that they have lost power. Geographic information systems offer that bird’s eye view to the utility, but in real-time.

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From paper maps to PCs Depending upon the size, budget and needs of an individual utility, many legacy outage management systems and processes rely upon paper maps.

Northeastern Rural Electric Member Corporation (Northeastern REMC) was one of many in this position.

Now, its field crews have graduated from paper maps to PCs to better serve their customers, thanks to the help of a GIS-supported OMS system.

A consumer-owned utility that supplies electricity to members in 26,000 households and businesses in northeastern Indiana, Northeastern REMC

Nashville Electric beats the weather Nashville Electric Service (NES), which serves more than 360,000 customers in a 712-square-mile service territory in metropolitan Nashville, Tennessee, is subject to wicked weather that can wreak havoc on its electric grid.

One of the 12 largest public electric utilities in the United States, NES has had its share of natural disaster. In 1998, for example, a tornado ripped through downtown and east Nashville, taking out power for 75,000 of NES’s customers. In fact, this particular tornado marked another first for NES: it suffered more damage to facilities and equipment than any other utility in recent history. In 2010, record rainfall caused widespread flooding and damage to Nashville icons, neighborhoods and downtown equipment, submerging three NES substations in water, and leaving 42,000 customers without power.

NES first implemented GIS software nearly a decade and a half ago to help with the planning, design, operation and maintenance of its electricity network, and has continually updated it ever since. Now, most processes at NES incorporate some form of GIS applications, according to Vic Hatridge, the utility’s vice president and CIO. In addition to mapping its grid assets, NES is also able to use its GIS software to assist its automated vehicle location (AVL) system, a real time-saver in terms of putting the right field crew in place at the right time.

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W WW.INTELLIGENTUTILIT Y.COM /// MAY/JU N E 2012

26

Driving business value from analytics ++Ideas and focus explored at Utility Analytics Summit

By H. Christine Richards WHEN

YOU

GET

FOLKS

TO

A

6:30

A.M.

ROUNDTABLE—

Eastern time no less—you know you have folks dedicated to analytics.

At the recent Utility Analytics Institute (UAI) Summit, we pulled together utility analytics professionals to talk about all things analytics—from the ongoing IT versus business debates to selling a utility company on the value of analytics. Their comments, edited for style and length, follow.

What we’re looking at today is how to drive business value with analytics. What does that mean for your company?

WETZEL

Most of our analysis is not as far along in increasing business value as we would like. We don’t have as good an enterprise data warehouse as we’d like to have in order to generate significant value. So the first thing we’re trying to do is to create a data foundation, or at least put something together that will enable more of the value-added analytics and business processes to occur.

CALVERT

As part of IT, business value is what we’re all about. If you’re driving business value, we need to understand your environment and understand what tools you need and facilitate that for you. At the same

time, it’d sure be nice if data was actually backed up and the systems wouldn’t go down, so we have a lot of work to do in the background to support that business value.

KUNZI

It’s interesting. I think IT versus business is really a question of how you manage your company and how IT is aligned with the business.

We have an integrated planning process which brings everybody together and really prioritizes the initiatives for the coming year and the long term.

I also created a business process practice, which is really IT, and we have a business process architecture which maps all the processes across the organization. So we’re very much business driven. There’s no question that IT is in support of the business.

In terms of business value, I could mention so many examples. The fact that we went from daily reads to hourly reads, for instance, enabled PARTICIPANTS us to really understand what’s going on out there MALLIK ANGALAKUDATI and catch people who are potentially giving Acting vice president, up our energy. distribution support We also had very good success with another National Grid application. We’re pushing information to our LARRY CALVERT customers in terms of their consumption, and we IT director give them the capability to understand how their Citizens Energy Group consumption fluctuates. We give them the abilPEGGY CLIPPERT ity to set thresholds, and then we notify them by Manager, analytics text, email, or voicemail if they go over the threshWe Energies old that they have set. So extending processes to FREDERIC KUNZI our customers and partners, that’s where we are CIO getting business value.

LCEC

CLIPPERT

PIETER NORTJE

GREG WETZEL

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IT in our organization has constrained resources, and I think that’s true everyProgramme manager, enterprise where. And I think that one of the reasons we, as performance management business users, get frustrated with IT is because Eskom they have more discipline, frankly, than we do GREG WETZEL around this stuff. They really work hard with what Principal engineer their resources are, they try to be reasonable and PPL Electric Utilities figure out exactly how many people they need to support this, that, and the other thing. By the time we’re looking for them to do something new and different there’s not a lot of pie left to do that.

I think that IT gets a bad rap as a result of that, but by the same token I also don’t necessarily think that they’re always open to newer technologies. We have a CIS that’s 20 years old and we have to search for people who can program in some ancient language nobody speaks anymore to support that, so when we come to them with a host solution they’re a little bit skittish and a little bit skeptical about it. So it just makes it very frustrating and very difficult. And I think the other thing is they—probably rightly so—lean toward wanting to protect and defend the data and make sure it’s pure and wonderful and perfect.

It’s wonderful, but it’s not pure and perfect. To the extent where they lock it away in data jail and they don’t let anybody play with it, right? So that’s a little bit frustrating also.

PIETER NORTJE

FREDERIC KUNZI

27

What is your focus on analytics at the moment?

ANGALAKUDATI

National Grid, where I work, is a vast company, so there is not just one analytics group, there are different groups. We have a customer analytics group that works with marketing and sales to the customer. My group is a lot more operational, and we are looking into a lot more operational optimization and process optimization by way of analytics.

NORTJE

PEGGY CLIPPERT

I work for a utility that generates 85 percent of the power in the continent of Africa. A big utility, but it doesn’t focus on the customer end because we distribute out to the communities, and then they sell our power from there on. So the last mile we don’t do. I’m particularly interested in analytics on the improvement of the utility, rather than the end, because the end is a very minute part of it all. I am part of a group working on enterprise performance management within our utility. We’re business-focused but we are not IT-focused. IT is a tool that assists in getting us there.

KUNZI Lee County Electrical, right now, is a distribution utility with mostly residential customers. We invested in business intelligence about two years ago.

We are at a point now where we have dashboards and reports in all the divisions, and I was amazed to hear, in yesterday’s sessions, that people want to do that without IT. What we would like to do is to move further into analytics and predictable data, and predict our revenues, our loads, and more. That’s really an area where I’m interested in going forward.

CALVERT

Citizens Energy Group is a corporate trust of the citizens of Indianapolis, Indiana. We are not-for-profit and also serve as the Department of Utilities for the City of Indianapolis. So we do a little bit of everything. In our shop mainly we’ve been trying to gather data which is manufactured—unfortunately—every other month, and service from the IT shop. Whether it’s operations, distribution or customer service with data in any way, shape or form, we can get it. We are looking at how we can begin to mature how we slice and dice that data, and I’m trying to find the best tool set to use.

MALLIK ANGALAKUDATI

If you have one piece of advice for utility companies that are either undertaking an analytics initiative right now, or are considering it, what would it be?

W WW.INTELLIGENTUTILIT Y.COM /// MAY/JU N E 2012

KUNZI

28

You start with your board or your senior management team and you make the case for the value of business intelligence. You need your business partners with you. It’s not an IT initiative, it’s the organization that really realizes the value and the fact that data is very powerful.

WETZEL KUNZI

LARRY CALVERT

It is difficult. How do you get the business units to buy in?

That’s the relationship you have to build, there’s no other way around that.

With bigger companies it’s a struggle because making that decision is going to be a half billion to a billion, right? It’s a strategic decision. That’s for sure, it’s a board-level decision and you can make a case, but it’s a very complex decision.

You need to have good partners and it’s long-term. With analytics it’s actually a two-prong strategy, you need to go to the board level to pursue that foundational investment, but also present any data and technology, even if it is in spreadsheets. It demonstrates tangible value to the business, which could then provide fuel to make the argument for analytics at a higher scale. You need to have tangible examples. You can’t just show up and say I think this company has done

it, and this company has done it, and that company has done it—because you will also find are there are a lot of companies that spent millions with no return on investment.

NORTJE Somebody has to commit and then go back and show progress.

That’s the only way you can do it. My biggest concern with analytics is doing analytics for the sake of analytics. I’m very wary of stepping into the hole of analysis paralysis. We focus so much, and yet if we step out of it, from a more holistic point of view, we need to look at it all in terms of business improvement, business performance. That’s what it is for us, not about analytics.

CLIPPERT

I think you just have to start with what you have. I find it disconcerting that there seems to be this opinion that you can’t be successful in analytics unless you’ve got some bazillion dollar humongous system with all

your data locked away in nice, neat, tidy rows. I think you can do analytics— whatever that means—with a piece of paper if you have to.

KUNZI

But it may take much more work than you realize.

CLIPPERT

Well it might, but I think you have to get into the data and swim around in it and figure out where some of those value things are. What is it that’s going to drive the decisions you need to make, and then you can start to codify that and make it more structured and standard—but first you have to figure out what it means. As a user of data it doesn’t make sense to me to all line it up and think ahead and try to figure out what are those relationships that are going to be important to you five years from now, so that you can get it all in place. I think the iterative nature is what’s important, and if you get so focused on we have to build this enormous data set and bring in all the data from the entire company into this one place, then that becomes the end goal instead of the actual use of that data. And that seems crazy.

ANGALAKUDATI

That actually kills the spirit in the company. I actually think even though there are good techniques, you don’t need to get millions of zillions of data points, you can intelligently sample parts of the process and build a picture up to prove it. We have done it repeatedly. Again, I’m not saying you shouldn’t go for the big database system, I’m just saying that they’re interactive.

It’s definitely a balance.

H. Christine Richards is a senior analyst with the Utility Analytics Institute, a division of Energy Central.

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29

IT INSIGHTS Through the U.S. Department of Energy’s Smart Grid Investment Grant (SGIG), about 850 synchrophasors, or phasor measurement units (PMUs), are planned across the nation.

SmartGrid 2.0 ++Developments on the transmission system enhance its intelligence

By Carl Dombek and Rosy Lum

W WW.INTELLIGENTUTILIT Y.COM /// MAY/JU N E 2012

DISCUSSIONS OF SMART GRID TECHNOLOGY HAVE LARGELY

30

focused on the distribution system and technology that will reach the retail customer—things like smart meters, smart appliances and plug-in hybrid cars. But there is a need to make the actual transmission system smarter, and there are initiatives under way that give the term “smart grid” a more literal meaning.

“Think of it as a two-layer smart grid,” Mark Maher, CEO of the Western Electricity Coordinating Council (WECC), said. “Most of the talk is about [devices on the] distribution system: new meters on houses, plugging in your electric car, having smart appliances and [things like] that. The other level is what we’re operating in, and that’s at the transmission level.”

WECC and the Midwest ISO (MISO) are currently deploying one of the more cutting-edge technologies, called synchrophasors. The devices are installed on the transmission system and measure voltage, current and frequency at high sampling rates—30 to 60 times per second—giving control rooms and system operators the ability to see what is happening on the grid in near real-time.

Upgrading SCADA MISO plans to install 165 PMUs across the region in a $34.5 million program, $17.3 million of which is funded by a grant from the U.S. Department of Energy. As of January 2012, MISO had installed 85 PMUs. WECC is expected to install about 350 new or upgraded PMUs across the Western Interconnection by the end of the initiative’s funding period in March 2013.

“The amount of data that’s able to be collected and the speed at which that data is able to be ferried back to operator control rooms to give the folks operating the system insight into what’s going on on the grid, what could potentially be coming their way, and knowing that sooner than they were able to, is the exact definition of what the grid being smarter is about,” said Brian Slocum, ITC Holdings’ vice president of engineering.

Current technologies on the grid collect data once every two to four seconds.

“Synchrophasors represent an upgrade from the existing SCADA (supervisory control and data acquisition) system,” Maher said. “SCADA data is like looking in a rear-view mirror. It’s coming in at around a sixsecond lag into the system, whereas phasor measurements are coming in 30 to 60 times a second.”

While some utilities poll their SCADA equipment at intervals as short as two seconds, Matt Olson, senior engineer with the engineering and consulting firm Burns & McDonnell, which recently dedicated a new smart grid laboratory, agrees that SCADA data has its limitations.

“If you have oscillating power flows and you’re only sampling every few seconds, you may see the power go

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IT INSIGHTS

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up and down [several times, and] if you’ve got a blackout coming, you can’t really tell if that oscillation is dampening out or if it’s increasing,” Olson said. “With a synchrophasor, you are going to get detailed enough information that you can see that impending doom coming and you can take appropriate action.”

Data from PMUs feeds into data concentrators on the systems of various utilities. Additional software will take that data and turn it into information so that dispatchers and reliability coordinators can look at the PMUs, “bringing in voltage, frequency, phase angle, a number of technical parameters that we need to operate this system optimally,” Maher said.

Synchrophasor data can alert the operator that conditions are outside normal parameters. “[A utility’s system] would be monitoring the data continuously and if it sees a condition it deems abnormal, then it would alert the operator who would then make the ultimate decision of the appropriate action to take,” Olson said.

32

Truly making the grid smarter “The fact is that this is making the grid smarter. Everything else you hear about smart grid, ironically enough, is not really applied to the grid, it’s applied to the end user, or the substation before it goes to the end user,” Slocum said. “In my mind, that’s always been very ironic, that we tag these things as ‘smart grid,’ but none of them really applies to the grid.”

With the ability to gather and synthesize data in real time, Maher says the next logical step is automation. “[PMUs] will eventually lead to automated control so that we can conceivably have a self-controlling, self-balancing transmission system,” Maher predicted.

Although such a development is technologically possible, Olson cautions that utilities have valid concerns about placing too much trust in automation.

“The automation may come up with a proposed answer but are we going to let it implement that automatically, or are we going to have a human look at it before it goes off and takes an action such as shedding load that may not need to be shed,” Olson added.

“You’ve just got to be cognizant that we don’t go the wrong way and end up with some of the lessons we learned from Three Mile Island where we relied too much on the computer and the information wasn’t getting to the humans fast enough,” Olson added.

Carl Dombek is senior editor for TransmissionHub, a division of Energy Central. He can be reached at cdombek@energycentral.com. Rosy Lum is TransmissionHub’s chief analyst.

She can be reached at rlum@energycentral.com.

Analytics tech talk ++Old-school conferences reveal high-tech challenges

By H. Christine Richards CONFERENCE SEASON IS DEFINITELY UPON US. AT THE

Utility Analytics Institute we’ve been hitting the road—including for our recently wrapped-up Utility Analytics Summit and the upcoming Utility Analytics Forum in September—to talk and learn about what’s happening in the analytics space. Through all the good old-fashioned handshaking and roller-bag lugging, we’re seeing some pretty high-tech analytics challenges arising. Let’s take a look at a couple of technology challenges facing utilities as they move forward with analytics.

Who should we turn to for the analytics “stuff”?

Analytics are the hardware, software, professional services, business processes and people that transform data into actionable insights. At the Institute, we harp about the importance of people and business process change in analytics because these areas are often overlooked. However, the analytics stuff—also known as hardware and software—is certainly important. Going a step further, perhaps more important in a rapidly evolving marketplace, is not just the technology, but who provides that technology. For example, will your technology provider be around in a year? Will the company’s solution for a pain point you’re experiencing right now serve your company’s needs well into the future?

During my recent conference presentations, several utilities have asked me who are the top five analytics vendors—particularly for analytics middleware.

Utilities said they were getting inundated with vendor pitches, and needed help figuring out which vendors were the best. This inundation isn’t surprising. In our most recent research report around customer analytics, we had over 60 solution

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IT INSIGHTS

$ and service providers who said they served the space in one form or another.

Narrowing those sorts of numbers down to the top five is tricky because each utility has unique needs. We’ll be exploring this area more in the coming months, but here are a few quick things to keep in mind as you evaluate analytics vendors: ??

COMPANY DURABILITY In this rapidly evolving marketplace, the viability

of companies is crucial to understand. Not that upstarts can’t provide great products, but it is important to understand the financial health and stability of any company you’re working with. ??

FOCUS ON UTILITY ANALYTICS There are analytics companies and then

there are companies providing analytics. Either type of company can offer value, but just take time to understand the company’s commitment not just to analytics, but utility analytics. For analytics companies, ensure that they are committed to the utility industry, and for companies that have traditionally provided other utility solutions, confirm

meters need to be tested and certified each time they come in for service.

So how do utilities keep track of all of that? These utilities couldn’t find a good answer.

These utilities also realized that if they tracked meter problems and the locations of those meters, then they could analyze that information to identify trends in meter problems.

Again, how to do this eluded them.

We’ll be exploring this topic more at the Institute, but a few things to keep in mind for now: ??

that analytics are a key part of their long-term vision. ??

other asset management

MATURITY OF ANALYTICS SOLUTIONS Analytics have to get started some-

needs? Can your company

where, but it’s important to consider the number of pilots, projects in

leverage existing asset

progress and full projects completed for a specific product.

W WW.INTELLIGENTUTILIT Y.COM /// MAY/JU N E 2012

??

34

FLEXIBILITY/INTEGRATION OF ANALYTICS SOLUTIONS We’ve seen a lot of

How will this system support

management systems? ??

Are there ways to engage

specific point solutions, much like the bazillion apps out there, which

existing analytics to help with

can be a great solution. With the focus on building enterprise-wide

tracking meter problems? Could

analytics, it’s just important for technologies to be able to play with

new solutions be leverage in

one another when needed.

other areas, too?

Please, give us a meter asset management system!

While inundated with vendors for some analytics, utilities are sending up flares and waiting for help to arrive for other analytics areas. At one conference, two utilities—within five minutes of one another—asked me about analytics and asset management solutions available for smart meters. As smart meters roll out, utilities now have to maintain them. The trick is that the complexity of these meters is much greater than traditional electromechanical meters. There are communications cards and all sorts of newfangled devices in them, and the

Technology always has its challenges, and analytics is no exception, but that’s what makes it interesting. Well, time to hit the road again. As always, thanks for reading.

H. Christine Richards is a senior analyst with the Utility Analytics Institute. She can be

reached at crichards@energycentral.com.

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O P E R AT I O N A L PERSPECTIVES

The challenges and benefits of implementing DMS ++OG&E’s director of grid intelligence talks about deployment

AS DISCUSSED IN THE MARCH/APRIL ISSUE OF THIS MAGAZINE,

W WW.INTELLIGENTUTILIT Y.COM /// MAY/JU N E 2012

the electric distribution system is undergoing what can only be described as an evolutionary change. We brought together two utilities that are in the trenches of implementing new distribution management systems (DMS) in an April Intelligent Utility Realities webcast on DMS lessons from the field.

During the webcast, Scott Milanowski, director of grid intelligence for Oklahoma Gas & Electric (OG&E), and Al Mithani, distribution management system program manager for BC Hydro, shared their utilities’ journeys, and what they’re learning.

Here, we share some of Milanowski’s comments, edited for style and length, about the benefits to OG&E of deploying DMS, as well as the challenges of adding a DMS to the mix.

36

The benefits of DMS We have a range of specific benefits that we identified in our business case that we have also committed to our regulators for these benefits. One is reducing energy peak demand. We have an ultimate goal of automating 400 circuits with voltVAr optimization (VVO). And when that is done, we expect to be able to reduce our peak demand by 75 MW. That’s an important part of our smart grid business case, because a large part of the value is deferring the construction of the next peaking power plant in our generation expansion plan. And if we can defer the construction of that plant by reducing our peak demand through VVO and through demand response on the AMI [advanced metering infrastructure] side, the customer program side of our smart grid program, we can see significant value in avoided costs resulting from that.

So, associated with VVO is reduced electrical losses. We’re improving the power factor and we expect to be able to achieve over 100 GWh per year in loss reduction.

On the fault isolation and restoration, we expect to see a system-wide reliability improvement of SAIDI and SAIFI of 30 percent once we have automated 200 circuits, which would be just under 20 percent of our system. We’ll be focusing the application of that on our worst-performing circuits where we have a large CMI [customer minutes of interruption] at this time.

We also expect other improvements in our operational efficiency. This will help our control center enhance our operational efficiency. This will help our control center enhance its outage management capabilities, improve operator situational awareness, and we’ll be able to find faults faster and fix them faster, and improve our reliability even further.

System challenges So, system challenges? The challenges of the DMS are many. It’s not a trivial matter. One is data. This system consumes a large amount of data. A huge piece of it is a connectivity model from the geographic information system [GIS]. It needs to be correct.

It’s got connectivity, it uses conductor size to calculate impedances, it’s important for load flows, for fault location. We are performing a field inventory of our entire distribution system to ensure that that model is as correct as possible.

Substation one-lines, and the automated devices in the substations, must be modelled. And there are two sides to this. In our case, we have the

“A large part of the value is deferring

Integration challenges The DMS will have numerous interfaces with outside systems. We’ve really defined our DMS as both distribution SCADA and the DMS applications.

the construction

We’ll be using DA [distribution automation] devices we’re communicating of the next peaking through our smart grid communication network that we’re building. We have existpower plant in ing substations connected to an existing SCADA/EMS that we already have in place, our generation and to communicate to the distribution devices in the substations we are doing that expansion plan. through a link between the two SCADA systems, our distribution SCADA and our existing transmission SCADA, through a secure ICCT link to transfer data and control.

Next is our OMS [outage management system]. Even though our DMS does have a built-in OMS, we opted, at least temporarily, to utilize our existing OMS. That must be integrated. It is important to keep the as-operated state of the model synchronized between the two systems. So we have interfaces going both ways to ensure that that occurs.

The geographic information system [GIS] is where the as-engineered system model is built and maintained, and that will be exported daily to both the DMS and the OMS systems.

We’ll actually be using an enterprise service bus for integrating AMI data, but right now we’re working on integrating meter outage information from the meters into the OMS to enhance its operations. We have a future upgrade plan to export meter load profiles into the DMS so it can read that for load application.

And finally, in terms of our customer information system, we’re importing from that a customer-to-transformer relationship so that we can take meter loading and allocate it up to the transformer level for proper load allocation, and load populations, as well.

”

Milanowski also discussed how OG&E is dealing with securing its DMS. To hear Milanowski’s and Mithani’s entire DMS presentations, go to http://bit.ly/HYz36A

W W W. I N T E LL IG E N T U T I L I T Y.CO M

SCADA system—you’ll have a display linked to dynamic points coming in from the field—and then on the DMS, which uses this GIS-based connectivity model, and it’s not the same model that’s in the SCADA. So we have to create substations, again model them in GIS, with impedances and the connectivity defined so that it can use that in the load flow calculations.

And then they’re all linked together, so we’ll have linkages between field devices, SCADA, DMS, and scaling factors associated with our calculations, so there’s quite a bit of data engineering going on to set this up.

And then, of course, there are the devices in the field. Every recloser, every capacity controller, is an RTU [remote terminal unit]. They have to be defined, point lists set up, points checked out to make sure they operate correctly. So there’s quite a bit of labor involved in setting that up.

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O P E R AT I O N A L PERSPECTIVES

Automating utility pole inspection ++Orangeburg DPU will realize quick return on RFID investment

By John R. Johnson THE ORANGEBURG, S.C., DEPARTMENT OF PUBLIC UTILITIES

W WW.INTELLIGENTUTILIT Y.COM /// MAY/JU N E 2012

used to have one of the simplest utility pole inspection programs in the industry.

“Our policy was basically that when the pole falls down, we put one back up,” acknowledged John Bagwell, director of the Electric Division at Orangeburg DPU, located about 40 miles southeast of Columbia, S.C. “We never really used to inspect poles.”

That was before the utility discovered the benefits of radio frequency identification (RFID) technology. The Orangeburg DPU, the largest municipal electric utility in South Carolina, began affixing RFID tags to its wooden utility poles last year. The utility has tagged 4,000 poles to date, and hopes to tag an additional 5,000 poles this summer.

Bagwell said that the utility turned to RFID to help it “to monitor, service and maintain its entire pole distribution network.” He hopes to tag all 33,000 poles owned by the utility within two to three years.

38

Pole data helps emergency response RFID technology involves placing tiny chips onto objects that can then be tracked by accessing the information with portable handheld or fixed RFID readers.

While many utilities still rely on bar codes, RFID tags do not require a line of sight for scanning that bar codes require, meaning that utility poles and other assets can be scanned from greater distances and through obstacles such as fences or vines that grow on some poles and make it impossible to read bar codes.

Aside from allowing greater visibility into a utility pole’s maintenance history, having the data readily available from each pole can help Orangeburg and other utilities to be better prepared to respond to emergencies, such as power outages following severe storms.

“We’ll know much more quickly what our asset needs are for a particular pole, and that will also help us to disperse our manpower in a more efficient manner, ensuring a quicker response rate,” said Bagwell.

The visibility provided by RFID can also help utilities when it comes to generating claims from storm losses. In many cases, utilities recover a portion of their labor and parts losses from the federal government after a major storm or disaster. However, utilities often have very little visibility into the unmanned storage yards where poles and other assets are stored. Oftentimes, they are providing only estimates to the government when it comes to recovering losses for assets used during a power restoration project. RFID can provide highly detailed information about those assets, allowing the utility to recover a greater amount of capital.

Labor savings in automation Bagwell said that the utility has spent about $100,000 on hardware and software costs, and about $50,000 in labor costs to get the system up and running and to tag each pole and enter vital equipment information about each asset. Based on labor savings alone, the utility expects to pay off its investment in less than three years by automating the inspection process.

To keep project costs as low as possible, the company has hired college interns to tag the next set of 5,000 poles this summer. Because of the asset tracking and maintenance capabilities that RFID offers, Bagwell said the utility is considering tagging all assets at its 22 substations as well.

and overall upkeep. The inspector is prompted by his handheld to answer a series of pre-formulated questions for each pole. The technicians then enter a priority level for any maintenance needed, and can send an immediate alert if the request is high priority, such as a leaning transformer or a severely damaged pole.

Upon returning to the office, the inspector syncs his computer system with DPU’s software system, generating a work order that maintenance crews follow up on the next day.

The RFID process allows for the Orangeburg DPU to fully integrate its inspection process with its field maintenance teams, ultimately improving workforce productivity.

In addition, Bagwell said that the utility can now quickly capture and determine pole event data related to storms and other natural disasters, while monitoring—and often improving—the productivity of inspectors and maintenance personnel.

Tagging utility poles also enables utilities to track the complete life cycle of the unit and all the assets located on the pole. The data can also help utilities to comply with regulatory requirements regarding asset management and asset tracking.

Speeding up return on investment Bagwell says that eventually poles will likely arrive at his facility pre-tagged, once RFID is embraced by more utilities. In fact, Orangeburg DPU’s pole supplier recently installed an RFID-based yard management system. The supplier is also tracking poles for its own inventory management needs by tacking inexpensive UHF tags on the butt end of poles so it can track when Instead of being an asset leaves the facility. However, that tag is useless once it arrives at the utility, as the butt reactive to potential end is buried underground during installation.

Eventually, the supplier says it will tag poles maintenance issues, on the side of the unit, allowing utilities to electronically verify receipt of the product and we are proactive, avoid the labor costs of tagging their own poles.

One of the biggest advantages to deploying and that has helped RFID is that the utility can deploy faster reporting and recovery of joint use revenues related to increase our to third-party agreements with cable providers and cell phone companies. In many cases, utilireliability numbers. ties are unaware that a third party has placed equipment on its poles, and even when they are aware the billing process can often be slow. The RFID-generated information can help to automate that billing process, resulting in better cash flow, and can greatly speed up the return on investment for installing an RFID system.

“RFID has actually allowed us to develop a pole maintenance program, which has been our biggest benefit from the technology,” Bagwell said. “Before we instituted this, we didn’t have a maintenance program. Now, instead of being reactive to potential maintenance issues, we are proactive, and that has helped to increase our reliability numbers.

“This really gives the utility and the entire community a sense that we’re doing all we can to keep the lights on.”

“

“I can see us someday certainly tagging every asset we have here with some kind of RFID chip,” he said.

”

John R. Johnson is a Boston-based freelance writer who specializes in alternative energy and technology topics.

W W W. I N T E LL IG E N T U T I L I T Y.CO M

Simple scans can generate work orders The RFID system allows DPU’s inspection and maintenance teams to capture pole-specific information with a simple reader scan, providing the utility with a thorough inspection record for poles and the assets that reside on them.

Armed with handheld RFID scanners and mobile computers, DPU inspectors record a variety of data about the tagged poles into their system, such as the condition of the pole and its cross arm, transformers, wiring

39

CUSTOMER FOCUS

Consumercentric outage communications W WW.INTELLIGENTUTILIT Y.COM /// MAY/JU N E 2012

++Oncor shares its forward-looking steps

40

By Kate Rowland

OUTAGE MANAGEMENT AND OUTAGE COMMUNICATION ARE

essential to a good utility-customer relationship. At the AGA/EEI Customer Service Conference in April, Oncor shared its story of how it shifted from a traditional utility mindset to a re-energized, customer-focused company, particularly where it concerned outage communications.

As a regulated piece in the deregulated market puzzle that is Texas, Oncor is the largest utility in the state, and the sixth largest in the United States. Oncor has a relatively small (100-seat) call center to handle outage management, with 5 million call center transactions per year. According to Pam Wheat, director of customer contact operations for Oncor, 2 million of those transactions are

Oncor’s Customer Experience Program began in 2010. It focused first on business process and technology to improve the customer relationship. The customer service council began its focus on outage communication improvement; the voice of the customer; content management, intranet and a mobility initiative; employee education; a brand and communication program; customer interaction training; and setting up a customer experience council.

The focus on the voice of the consumer was imperative. Oncor senior business analyst Jill Beavers told attendees, “We realized, in essence, we were asking the customer after the fact.” So Oncor set up customer focus groups, and is revamping its customer surveys for actionable data.

Benchmarking against other industries As well, Oncor is benchmarking customer experience in reference to other industries. (This is a theme that came up repeatedly during the course of the conference. Utility customer service is being benchmarked by the customer with regard to the service he/she is receiving from other industries such as telecommunications, entertainment, banking and airlines, and so it makes good sense for utilities to look to other industries in order to benchmark themselves.)

One area of opportunity that made immediate sense to Oncor was to improve its outage communication, Beavers said, with text notification, an IVR redesign, enhanced outage maps, social media monitoring, and a Web and mobile refresh.

Its work to date was put to the test on April 3, 2012, when the Dallas/Fort Worth metro area experienced a weather crisis, as a dozen confirmed tornadoes hit in a matter of a couple of hours, and large storm systems devastated neighborhoods. During the storm, Oncor sent out 13 proactive posts, including news updates, safety information, weather warnings and links to outage maps. interactive voice response (IVR) transactions, 1 million are e-business, and the remainder are telephone calls into the call center.

With about 90 electricity retailers active in Oncor’s market, when something goes wrong, customers still turn to Oncor for answers, rather than their retailers. According to Wheat, the Public Utilities Commission of Texas has defined it in this way: “The retailer has customers, you have consumers.”

Mapping the outages and more Beavers said Oncor’s work on an enhanced outage map providing detailed outage information to customers will come to fruition later this year, as well.

The map will be smart-device friendly, with enhanced mapping display and technology, and will provide a weather overlay and up-to-date outage information including estimated time of restoration, number of customers out of power, number of outage events, and the cause of the outage (if known).

Oncor’s IVR redesign is due to be launched this summer, as well. IVR revamps take a long time to implement, as utility customer service managers well know, and it’s important that they be completely right when launched. As such, Oncor was, in mid-April, conducting usability tests with customers.

All in all, it’s a package that should excite customers, and energize them to engage.

W W W. I N T E LL IG E N T U T I L I T Y.CO M

Better connecting with the consumer Nevertheless, the consumer looks to Oncor as the the “trusted advisor” and Oncor has stepped up to provide that service. “We started a customer service council, and we have 40 people across the different disciplines,” Wheat said. “Our strongest support is back through the top. We have rebranded and want to be the customer’s trusted advisor, focusing on transparency, predictability and consistency.”

Ask your utility The utility also formed an “Ask Oncor” group to handle any complaint escalation. Ask Oncor includes an appealing redesign with user-friendly features, robust search capabilities of content, and frequently asked questions (or FAQs).

And the Ask Oncor feature is smart device friendly, as well.

Ask Oncor has just gone live, and Oncor Mobile went live at the end of January. Oncor Mobile features ease of use (customers can click on the link to dial the number), and highlights the most important information sought by customers. Oncor Text Notification is also live now, being piloted to employees and customers in select areas. This pilot provides the opportunity for those customers to text in power outages and receive updates on service requests. To date, at the time of the conference in mid-April, more than 600 outages had been reported by text. Text notification will be fully implemented later this year.

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CUSTOMER FOCUS Real-time energy information at the appliance level enhanced

New metrics for customer service? ++Real-time information is important, too

By Phil Carson

WE ALL KNOW—OR SHOULD—THAT “CONVENTIONAL WISDOM”

often means hearsay repeated too often. Actual, bona fide research, of course, can cut through the fog of conventional wisdom, but only if the audience is receptive and willing to examine the facts.

Thus we offer some insights into customer behavior from “SMUD’s Residential Summer Solutions Study,” conducted last summer by Karen Herter of Herter Energy Research Solutions, in conjunction with (and funded by) the Sacramento Municipal Utility District (SMUD) and the Intelligent Utility Daily Lawrence Berkeley National Laboratory. editor-in-chief Phil Carson

Responses and perceptions tested Herter worked with 265 residential cusreported back within his daily tomers in the SMUD service territory last online columns. Here, we excerpt summer in an effort to test responses to his discussion of two of those (and perceptions of) an integrated energy reports, SMUD’s Residential efficiency and demand response program Summer Solutions Study and The with real-time energy information, a Crossroads of Customer Metrics dynamic rate and thermostat automation. and Strategy in the Utility Sector.

The study’s main purpose was to test the effect of three different “information treatments” on summer energy use, peak load and event loads for a group of customers exposed to dynamic pricing, traditional direct load control, or both— all with automated thermostats.

Under an experimental, dynamic rate, participants in the study controlled their own automated response to events through a menu option in the thermostat.

In contrast, participants on the direct load control program—the Automated Temperature Control option (ATC)—did not have thermostat menu options.

They could override only one event of 12 in a summer.

Here are a few findings: recently looked at a number of

W WW.INTELLIGENTUTILIT Y.COM /// MAY/JU N E 2012

utility consumer studies, and

42

??

Customers on the dynamic rate lowered their summer energy use by 10 percent, reduced weekday peak loads by more than 20 percent, shed more than 50 percent of their load during events, and lowered their bills by about 15 percent overall.

??

Compared to those on the dynamic rate, customers on the direct load control option saved a similar amount of energy, but saved less energy during the weekday peak periods and events.

??

Real-time energy information showed modest benefits. Real-time information at the home level enhanced energy savings by about 4 percent.

daily peak savings by about 7 percent. Neither information type affected event savings.

As for the findings on the initial objective—how does real-time energy data affect electricity use?—Herter said it depended on which energy treatment was delivered.

Being strategic in load management efforts “The answer for feedback at the aggregate home level was that it seems to reduce energy consumption by a few percent overall,” Herter told me. “Participants saved slightly more energy during the waking hours than did the participants without realtime information.

“The folks with appliance-level data did not save more energy across the day,” she continued, “they only saved more energy during the peak.”

“One possible explanation for this pattern is that those [participants] with only home information, being less aware of individual contributions to total energy use, employed a more general strategy for keeping energy use low all the time,” according to Herter’s report. “In contrast, those with appliance energy data may have the precise knowledge required to be more strategic in their load management efforts.”

“It was one study, one summer, one group of customers,” Herter said. “As far as I know that type of study has not been done anywhere else and one study is not enough to draw general conclusions. But it’s a start.”

Herter hopes to run the research again this summer to confirm her findings, which could give utilities several tools to apply, depending on their individual needs and goals.

Reduce overall energy use? Reduce peak use? Curtail demand on “event” days? Find the customers who would like to participate and begin there.

Build outward to a broader base of

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W WW.INTELLIGENTUTILIT Y.COM /// MAY/JU N E 2012

participants as you can show how they save energy and money. It’s cheaper to provide smart thermostats and price signals than to build more power plants. That’s the logic, anyway.

What’s just as important as the findings on customer behavior under the various treatments is that 90 percent of the participants in the study chose to participate again this year.

44

New consumer metrics needed?

A new white paper, “The Crossroads of Customer Metrics and Strategy in the Utility Sector: A Case for Alternative Metrics”, was written

by Jamie Wimberly, CEO of DEFG and EcoAlign.

Customer service is evolving to accommodate changes wrought by smarter grids and “utility industry stakeholders are questioning traditional customer service metrics as indicators of performance,” the paper begins.

Under traditional metrics, a utility could be providing excellent customer service, yet see its scores drop due to rising energy prices or storm-related outages—i.e., external factors. Or a utility may sacrifice customer service resources (due to budget constraints) without seeing a dip in scores.

Some traditional metrics are at odds with each other, Wimberly argues. While some metrics focus on speed, others—such as first-contact resolution—may contribute to deepening the customer relationship.

Surveys by DEFG have shown that utility customers prefer to spend more time on the phone with a customer service representative than to make repeated calls.

“If utilities cannot impact the outcome, how relevant is the metric?” the paper asked, rhetorically. “There’s an expectation that elevated levels of customer engagement will be required to meet regulatory mandates and utility business objectives in the future.

Customers are expected to become an integral part of the resource portfolio.

Engagement is built and earned through trust. How, then, is trust in the utility to be measured?”

No need to reinvent the wheel First, utilities don’t have to reinvent the wheel, because the cable television and telecommunications industries have found that customer engagement “begins with accountability, trust and passion (emotional ties), as well as the functional requirements of the interaction.”

That said, the paper zeroes in on the first contact resolution (FCR) as “becoming the single most important measure.” Another metric—a measure of a customer’s “ease of doing business”—is gaining ground in the form of a customer effort score or CES. While traditional metrics have focused internally on the effectiveness, including cost-effectiveness, of utility efforts at various touch points, the new trend focuses on measuring how well one meets customer expectations.

Aligning traditional measures with these new ones could provide utilities with a view of the overall “customer experience,” the paper argues—though making that transition may be difficult while utilities “remain rooted in a regulatory structure that treats the utility’s customer service costs as operating expenses with limited to no opportunity to earn a return.”

“Right time metrics” used in other service sectors are designed to align “the right option with the right customer through the right channel at the right time,” the paper continues. “Through this prism, customer metrics need to be more forward-looking, even predictive and tied increasingly to a customer of one rather than the traditional view of treating all customers the same.”

Intelligent Utility Daily editor-in-chief Phil Carson can be reached at pcarson@energycentral.com.

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OUT THE DOOR

Smart energy, made in Germany ++E-Energy pilot projects a research priority

By Kate Rowland

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IN THE COURSE OF BASIC ENERGY REFORM, GERMANY IS

46

vastly changing the structure of its supply system in the coming decades.

“Affordable and reliable energy supply is essential for our industrial growth.

Climate change, growing energy demand and depleting raw materials pose great challenges for Germany, as also reflected in the energy and climate policy decisions of the last two years: First, greenhouse gas emissions will be substantially curtailed by 2050. Second, renewable energies will provide the bulk of our power supply in future, and third, we are looking to to curb energy demand by a large margin while raising energy efficiency,” wrote Dr. Philipp Rosler, Germany’s federal minister of economics and technology in the foreword of a new report, Smart Energy Made in Germany.

The bulk of the 44-page report details the interim results of Germany’s E-Energy pilot projects, moving toward what it is referring to as the Internet of Energy. Six regional pilot projects covering the gamut of technologies, ideas and research are a inter-ministerial partnership between the German Federal Ministry of Economics and Technology (BMWi) and the Federal Ministry of the Environment, Nature Conservation and Reactor Safety (BMU).

Systematically maximizing power supply efficiency “Whether we call it smart, active or intelligent grid, we are talking about systematically maximizing the efficiency of electric power supply. This ranges from power generation to storage, transport, distribution up to efficient use,” Rosler wrote. “E-Energy means Smart Energy made in Germany,” he added. “We have some enterprising partners on board. Together, we want to find out what is technically feasible and what makes economic sense.

With different scenarios in six model regions, industrial and scientific syndicates are investigating and testing the essential elements of intelligent energy supply.”

Germany’s energy policy is pursuing three major goals—economic efficiency, supply security and compliance with environmental standards— energy goals many of today’s developed and developing countries share.

But Germany has taken its renewables targets to an extreme: “The share of renewable power generation in gross energy demand will be raised from 17 percent today to 35 percent by 2020 ... The target for 2050 is a ration of 80 percent of power demand,” says the report.

The six pilot projects’ research efforts cover energy efficiency, integration of renewable energies, decentralized energy generation, supply security/grid bottlenecks/ grid expansion, market deregulation, storage devices, load flexibilization, IT security and data protection, information and communication technologies (ICT) architecture, smart metrology and e-mobility.

A regional electricity marketplace is key Regional and local energy marketplaces play a large role in the country’s changing supply system revamp. In the Cuxhaven region, for example, the eTelligence project is testing a complex

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OUT THE DOOR control system designed to balance out fluctuating wind power by intelligently consumption into line with the variable integrating electricity into the red, and a regional market. According to the prices on the energy market. report, “The core component of eTelligence is a regional electricity marketplace Finally, the Smart Watts system hopes that brings together producers, consumers with shiftable loads, energy service to provide an information and control providers and grid operators. As well as improving supply security from renewmodel for the energy system, one that able energies, this also enhances economic efficiency.” will provide market players with nearThe pilot project in the Harz region is time, actual production focusing on “the joint marketing of regionally and consumption data, Whether we call it smart, available renewable producers and flexibiliand end-to-end optimizaties grouped into a virtual power station on tion of the energy supply. active or intelligent grid, different markets.” The IEC-61850 standard In summary, the goal is enabling simple and secure connection is that the Internet of we are talking about of systems to a joint control station, and a Energy, will “network “regional renewable energy rate” is being ofthe many actors of the systematically maxifered to consumers in the pilot. According to energy system,” according the report, “The rate is geared to minimizing to the report. “Every unit mizing the efficiency of the residual load within the region so that the connected to the power customers can make an active contribution to grid is integrated into the electric power supply. balancing out production and consumption.” control system through Another interesting aspect of the Harz plug and play. They region project is that it is demonstrating that the storage requirements for energy are connected to the overall system can be reduced through short-term wind forecasts. And load shifts on the conthrough equipment called energy sumer side, the report notes, help to improve voltage regulation in the distribumanagers, communication managers, tion grid and compensate for forecast errors. control boxes or ICT gateways.

“They are provided with the necesIntelligent consumption management tested sary information and help to match Other pilot projects include the E-DeMa project, which is investigating intelligent up production, grid load and conconsumption management and the near-time capture and provision of consump- sumption largely automatically. This tion data. It, too, has a regional energy marketplace that functions as a central will give rise to an integrated data and data hub, both for consumption and contract data. In the MeRegio project, 1,000 energy network with completely new electricity customers from Freiamt and Goppingen are testing the smart home. In structures and functionalities.” the moma project, new “energy butlers,” or control devices, have been installed in The full report can be read at: 200 homes. Through energy management, customers are learning to bring their http://bit.ly/IWoh1h

“

”

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