Intelligent Utility MarApr2012

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

Automating the

GRID DMS of the future, now

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CONTENTS DEPARTMENTS

4 6

Drawing the line Transmissions 6

Letters from readers

8 Around the globe 10 Top 12 10

Top 12 large co-op unsung heroes

12 Top 3 UtiliQ utilities

20

This issue, we’re turning the spotlight on operations topics, in particular automation and how it affects the utility as a whole. With that in mind, our IT Insights and Operational Perspectives departments also cast a view into other issues of import to the industry.

FEATURES // MARCH/APRIL 2012

Automating the grid

20 The DMS of the future, now

EPRI technical executive discusses the importance of distribution management

Substation automation W WW.INTELLIGENTUTILIT Y.COM /// MARCH/APRIL 2012

24 Substation automation to the smarter grid

2

PECO’s progressive innovation, putting the customer first

Feeder automation

28 FLISR provides a smart brain

PG&E, Southern Company and others transitioning pilots to full-out rollouts

KNOWLEDGE2011

12 35 39 41 47

Trends explored at Knowledge2011

San Diego Gas & Electric

14

Pacific Gas & Electric

17

Austin Energy

34 IT insights 34

Change means a new level of interdependencies OGE Energy’s CIO talks about change management

35

Data analytics: start in the middle Quick insights can be gleaned from incomplete data

38 Operational perspectives 38

Communicating so that the customer cares SMUD’s assistant general manager talks about sharing success stories

39

Analyzing grid analytics SMUD and others finding value in grid data

41 Customer focus 41

Demand side management pilot scores points Colorado Springs Utilities balances overloaded circuit with customers’ help

45

The state of the electricity consumer SGCC identifies seven key themes to address

46

Meeting customer needs and expectations CenterPoint’s VP of customer service talks about demonstrating value.

47 Out the door 47

Speed, satisfaction and safety SMECO’s callout strategy

CONTINUING THE CONVERSATION

32 Focusing on customers

12

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Vol. 4, No. 2, 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

The challenges of 2012 and beyond

W WW.INTELLIGENTUTILIT Y.COM /// MARCH/APRIL 2012

IN THE LAST ISSUE, I SPOKE OF CONTINUING THE CONVERSATION FROM

4

Knowledge2011. With this issue, you’ll see that we have made some great strides in moving some of that discussion forward.

I asked our three KITE Award winners from Knowledge2011—OGE Energy’s Reid Nuttall, SMUD’s Paul Lau, and CenterPoint Energy’s Gregory Knight—what they felt was the biggest issue or challenge facing our industry in the coming year, and looking forward. Once you’ve read their comments, I encourage you to join in the conversation and share your own opinions and experiences online at www.intelligentutility.com/magazine.

We also share, within this issue, a rousing roundtable discussion that occurred during Knowledge2011 between five utility executives in charge of information technology decisions within their utilities. It’s a great mix of IOUs, munis and co-ops, and a wonderful sharing of stories, successes and challenges. From the transformation of the IT department to aging workforce issues, our roundtable executives—Leslie Barrios of Bluebonnet Electric Cooperative, Vic Hatridge of Nashville Electric Service, Cam Henderson of Portland General Electric, David Hoskins of DPL and Steve Schmitz of Omaha Public Power District—discussed documenting business processes, succession planning, integrating OT and IT and more.

Within our features in this issue, we’ve turned the microscope sights on automation from an operations perspective. I asked EPRI’s Bob Uluski what the distribution management system of the future will look like, and how soon we will see distinct and significant headway with utilities in this direction. Laurel Lundstrom took a good look at PECO’s substation automation efforts, and PECO’s Glenn Pritchard shared insights on how that project has grown in the years since first implementation.

Also of note, H. Christine Richards, senior analyst with Energy Central’s Utility Analytics Institute (UAI), shared early results from the UAI’s Annual Grid Analytics Report, the second in its series.

These and other stories in this issue of Intelligent Utility are intended to provoke further discussion.

I invite you to continue the conversation with me via e-mail, and encourage you to head to our website at www.intelligentutility.com where you will find the articles posted online, as well as a platform for online discussion on each of these stories with your peers.

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

sue? Then Enjoy the is for free at subscribe .com/ igentutility www.intell subscribe

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TRANSMISSIONS

Letters from readers Understanding the regulatory compact

world is changing, we need to ensure that our regulatory policies keep up!

November/December 2011

Name withheld

Nice discussion of the regulatory compact! As the Supreme Court has I like your description of used and defined it—utilities that make investuseful and risk-averse utilities. I am ments and dedicate them to the concerned that in the regulatory public good are entitled to a return of compact you describe, utilities would that investment and a return on that never want smart grid technology investment commensurate with the to reduce peak demands or manage risk. And, of course, imprudent invest- load, so they can justify building more ments are never rewarded. But what peaking power plants. A $1,200-peradvocates must also understand is the kilowatt peaking plant gets a great Golden Rule of Regulation—utilities ROE for utility shareholders, and may must prove to regulators that the bennot be the best asset for consumers efits to consumers of the smart grid to own over time. The utility needs investments exceed the costs. What incentives to pursue low-cost soluwe need to change are tions for growth in the regulatory policies peak demands and that were designed for a renewable integration. different era and create Economics should be unintentional barriers straightforward. What #utilitysocialMedia to smart grid applicawill raise rates for contions. One example sumers, TOU/CPP or is the prohibition on a new peaking power time-of-use rates in plant? Assuming TOU/ some states. These CPP is priced right and 1970s-era policies have consumers have similar no business in today’s contributions to peaks, economy where moving energy usage then CPP is the better choice for all. to off-peak can lower costs for all The problem is one of politics: resiconsumers. The policies also underdential customers pay more for CPP mine the ability of consumers and because 1) they are usually the largest business owners to implement costcontributors to peaks, and 2) they are effective energy management systems. less likely to modify their use. Which They also prevent the use of dynamic is why the author, from the Citizens peakings—critical peak or peak-time Utility Board, is concerned about rebates—which help utilities avoid smart grid. He is just doing his job or at least defer huge infrastructure and protecting residential consumers. investments. The bottom line: the Name withheld socialmediaCOVERfinal.pdf

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9:27 AM

VOl 4, Issue 1 » January/February 2012

Where smart grid meets business—and reality.

It + analytIcs

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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

Jean Micketti, Ken Maness, Todd Hagen, Eric Swanson sales@energycentral.com 800.459.2233 ADVERTISING COORDINATORS

Stephanie Wilson, Patricia Davis, Kendra Branch-Brett CUSTOMER SERVICE

Cindy Witwer, 800.459.2233 ENERGY CENTRAL

www.EnergyCentral.com PRESIDENT/CEO Steve Drazga CHIEF OPERATING OFFICER Steven D. Solove VICE PRESIDENT, INTELLIGENT UTILITY Mark Johnson VICE PRESIDENT, DATA & ANALYSIS Randy Rischard VICE PRESIDENT, MARKETING PRACTICES Mike Smith

M

Y

CM

MY

CY

CMY

K

segMentIng custOMers What Works? engagIng the MObIle custOMer Is there a technology road map?

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

W WW.INTELLIGENTUTILIT Y.COM /// MARCH/APRIL 2012

» WWW.IntellIgentutIlIty.cOM

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To contribute to the Transmissions department, please e-mail your submission to intelligentutility.editor@energycentral. com. Provide your name, address and daytime phone number. Letters may be edited for style and space.

More than just smart meters

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UTI LIT Y ICT PA RTN ER

A DVA NCED M E TERI NG PA RTN ER

EN ERGY EFFICI ENC Y PA RTN ER

November/December 2011

“The sum of its parts” propels recognition of the catalyzing potential of “common infrastructure” enabled by shared fiber-optic communication networks.

Steven R. Rinkin, Esq.

Future. Ready.

SM

Direct load control Voltage management Energy efficiency Variable pricing Distributed energy resources Emergency load reduction Grid reliability

Where is demand side management heading?

befutureready.com/DSM

AROUND THE GLOBE WORLDWIDE

Smart grid spend to be concentrated in 10 countries As 2011 came to an end, the Innovation Observatory released a report indicating that 80 percent of the worldwide investment in building electricity smart grids by 2030 will be concentrated in 10 countries.

Over the next five years, the United States will dominate global capital expenditure, culminating by 2030 in a spend of US$60 billion on intelligent smart grid infrastructure. Ultimately, according to the report, the top spending market will be China, where annual smart grid CAPX will overtake the U.S. around 2016. China’s overall spend on smart

grid development is expected to reach US$99 billion by 2030.

Emerging market forces include India and Brazil, ranking third and sixth, respectively. (Brazil expects to roll out 63 million smart meters by 2021, and India has plans for 130 million smart meters.) France, Germany, Spain and the United Kingdom are ranked by the report as the leading European countries in terms of investment in smart grid infrastructure, and Japan and South Korea complete the Innovation Observatory’s Top 10.

Competition to win contracts with utilities in these markets will be fierce, says the Innovation Observatory, as the scale of the investment is creating a huge appetite to supply.

G R E AT B R I TA I N

Bulk energy buying tested In early February, the Daily Telegraph in London reported that 40,000 people in Britain signed up for a pilot program called the Big Switch, in which the collective purchasing power of consumers will be tested.

British Energy Secretary Edward Davy called the bulk buying of energy “a game changer,” producing lower energy bills for consumers.

The newspaper reported that H AWA I I & J A PA N

Hawaii-Okinawa Partnership State government and energy officials joined Hawaii Governor

this is the first time collective purchasing of energy has been

Neil Abercrombie and Japan-based New Energy and Industrial

tried in Britain. The consumer

Technology Development Organization (NEDO) President Hideo Hato

advocacy group “Which?” is

in early February as the two men signed a memorandum of

W WW.INTELLIGENTUTILIT Y.COM /// MARCH/APRIL 2012

understanding to memorialize ongoing efforts between the

8

State of Hawaii and NEDO. (NEDO is an arm of Japan’s Ministry of Economy, Trade and Industry.)

handling the purchase. When enough consumers have signed up, Which?

The two are set to build a first-of-its-kind smart grid demonstration project on the island of Maui. The multimillion-dollar project is aimed at improving integration of variable renewable resources, such as solar and wind power, and preparing the electric system for widespread adoption of electric vehicles.

The project, part of the Hawaii-Okinawa Partnership on Clean

will put the energy usage contract up to a reverse auction (whereby the generator offering the lowest electric

Energy and Efficient Energy Development and Deployment, will invest $37 million in the development of advanced smart grid technology.

rates gets the contract).

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TOP 12

TOP 12 unsung heroes ++Large electricity co-ops of the U.S. shine

By Kate Rowland BEGINNING WITH THIS ISSUE, WE ARE TAKING A CLOSER

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look within our Top 12 for 2012 at the unsung heroes of electric utilities across the United States, from large co-ops to small, both large and small municipal utilities, and large and not-so large investor-owned utilities.

The first thing we realized is that every co-op works as an entity, and singling out one person from within that entity is difficult, if not impossible. So, as any of the folks highlighted below will tell you, they represent the entire co-op team, and my choices here both honor these people and the co-op teams with which they work.

The second realization was that there are far, far more unsung heroes within the large electric utility co-ops than we can possibly feature within this short article. We hope to be able to tell more of their stories, as well, in utility articles in coming months.

10

LESLIE BARRIOS of Bluebonnet Electric Cooperative would be one of the first to tell you she is but one small part of the Bluebonnet team. But as executive manager of IT, she’s on the front lines at meetings, and in webcasts and roundtables, representing her utility. (See Knowledge2011 Roundtable on page 32.) She has been with Bluebonnet since 2003, and in her current position since 2009.

Bluebonnet Electric Cooperative serves more than 81,000 meters and owns and maintains 11,000 miles of power lines, located across more than 3,800 square miles within 14 Central Texas counties.

As vice president and CFO, GARY CRIPPS provides direct leadership for Delaware Electric Cooperative’s companywide technology strategy and investments, as well as oversight responsibility for human resources, finance and accounting. Gary is a frequent speaker and subject matter presenter with the National Rural Electric Cooperative Association, IBM, the National Rural Utilities Cooperative Finance Corporation and numerous statewide utility trade associations. DEC serves more than 75,000 members in Kent and Sussex Counties in Delaware.

DAVID KOOGLER, vice president of customer service for Rappahannock

Electric Cooperative, is responsible for the leadership of all member support activities, including contact center, billing and collections, rates, conservation programs, government relations and communications. He has an extensive util-

ity experience, working for more than 30 years for Dominion Virginia Power where he managed retail access, customer billing, rates and regulatory affairs and key accounts. Rappahannock Electric Cooperative provides electric service to more than 155,000 connections in parts of 22 Virginia counties.

ANITA MORENA, manager of

member services for Flint Energies, is focused on member engagement, and it’s working. Members understand that load management can prevent their utility from making expensive, spot purchases of electricity to handle peaks, thereby saving them money.

This 74-year-old electric utility co-op covers 17 central Georgia counties.

Flint began its installation of its two-way automated control system (TWACS) meters in 2004, and is now working on a smart grid demonstration program testing in-home devices and pricing options, along with load management for peak events.

BLAKE HOUSE, vice president of member services for Sawnee EMC, can also be found on community blogs upon occasion, answering questions and comments about Sawnee’s service, explaining new products and more.

He and the team at Sawnee are even making sure their members are EV plug-in ready, understanding how their new EVs are going to affect their electricity bill. Sawnee EMC serves electricity to more than 148,000 accounts in seven counties in greater North Georgia.

ROQUE MARINHO, director of enterprise business intelligence for Cobb EMC, is one of those affable people who is extremely passionate about his job, and shares that passion widely.

Cobb is nearly finished upgrading all of its meters, and is also adding data management technologies. Managing and optimizing that new data is Marinho’s focus. Cobb EMC, located in Georgia, serves 171,000 members and about 196,000 meters.

Not pictured are: David Schleicher and Kenneth Capps.

JERRY MARIZZA is new-energy

DAVID SCHLEICHER may be new to EnergyUnited as its vice president of

program coordinator for United Power, a Brighton-based electric co-op in Colorado. Google him, and you’ll find him passionately discussing solar power in general, and the state’s first solar farm, developed by United, in particular. United Power is a cooperative serving Colorado’s front range, with a membership of approximately 120,000.

engineering and operations, but he’s a veteran of 30 years in the industry, most recently serving as general manager at PPL Electric Utilities, and is a demonstrated leader. EnergyUnited is the largest electric co-op in North Carolina, serving more than 120,000 electricity customers in 19 counties. The co-op began its smart meter deployment in 2009.

KENNETH CAPPS is chief operat-

JIM MOXLEY is senior vice president of the Northern Virginia Electric Cooperative (NOVEC). As such, he is in charge of administration, substations and telecommunications. He and his team were responsible for preparing the co-op’s winning DOE smart grid investment grant. NOVEC serves more than 145,000 customers in northern Virginia, and is using new technology to control the costs of operating its expanding system.

CATHY BITLER is vice president of administrative services at South Central Power in Ohio. She and her IT staff were able, through new technology, to increase scalability and performance while reducing data center space, power needs and costs, in fact beating the national average for power costs. South Central Power manages more than 11,000 miles of power lines, and serves more than 110,000 customers in 24 Ohio counties.

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

ing officer and senior vice president of engineering and operations at Southern Maryland Electric Cooperative (SMECO). Operations folks usually end up in the background, but they are vital to the heartbeat of the utility, and Capps is no exception.

Capps manages the engineering, operations, construction and maintenance of the transmission and distribution plant within SMECO’s entire service territory. SMECO serves approximately 149,000 customers in a 1,150-squaremile area in southern Maryland.

KEITH THOMASON has served as vice president of operations for Middle Tennessee EMC for the past 17 years, and has overseen the installation of a new outage management system, merging it with SCADA and MTEMC’s communication systems. Started by farmers and homeowners in 1936, MTEMC is now the state’s largest electric cooperative and the sixth largest in the U.S. It supplies electricity to about 185,000 customers in four counties south of metropolitan Nashville.

11

TOP 3 UTILIQ UTILITIES

1

Avery said that the biggest hurdle of the metering program was “dealing with externalities,” things that couldn’t be anticipated beforehand. But good communication before, during and after the installation helped customers “feel like they were a part of the overall deployment process.”

In fact, the deployment went so well that the California Public No. 1 utility racks up three consecutive wins Utilities Commission highlighted

By Kathleen Wolf Davis the utility’s meter plan as a type of “gold standard.” Avery was quick to THE THIRD TIME’S THE CHARM, OR SO THE OLD SAYING GOES. FOR point out that the utility didn’t work San Diego Gas & Electric (SDG&E), all three times have been magical, so hard to get the praise, rather that actually. Last year marked the third year the California utility captured the UtiliQ the praise was a bonus from the hard crown as the most intelligent U.S. utility. work, which the utility Sempra Energy-owned SDG&E is a regulated public utility that does because of a provides energy service to 3.5 million people through 1.4 million STATS passion for power electric meters and 850,000 natural gas meters in San Diego and CUSTOMERS and the consumer. southern Orange counties. Its service area spreads across 4,100 3.5 million “We don’t do this square miles and spans 25 separate communities. The utility for the accolades; it’s COVERAGE employs approximately 5,000 people who work daily to deliver merely in our DNA,” he 4,100 sq. miles power in intuitive and intelligent ways, according to Jim Avery, said. This desire to serve 25 communities senior vice president of power supply with SDG&E. the customer well has And one of the most intelligent ways to deliver power these days EMPLOYEES led to a number of techis through a smart meter.

5,000 nological deployments to help keep SDG&E’s Smart meter, smart grid consumers content and well-informed SDG&E replaced both its gas and electric meters with the smarter versions in while the system itself has become 2011, allowing for remote measurements, in-depth communications and more increasingly more reliable. The utility interactive customer applications.

San Diego Gas & Electric

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++

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has had the highest reliability numbers in the western U.S. for the past six years. SDG&E isn’t resting, however; there’s always more to do to prepare for the future.

From grid to renewables The Borrego Springs microgrid project isn’t the only smart concept on tap for SDG&E; it’s a leader in this smart grid evolution. In fact, the utility has 60 initiatives in the smart grid arena in which many average U.S. utilities clock in at four or five.

And projects like Borrego Springs have multiple applications beyond the smart grid. It will add managing renewables knowledge as well as smart grid concepts to the SDG&E portfolio because the variables required to manage a microgrid are similar to the variables required to manage renewable energy.

Additionally, SDG&E has cleared a number of renewable energy goals this year along with work at Borrego Springs, including hitting short-term generation numbers of 20 percent renewable generation, which the utility achieved in just the past few months despite having a larger renewables gap than any other California utility under that same directive and time frame.

Additionally, the utility’s Sunrise Powerlink transmission line project is well into the construction phase, allowing a variety of renewable energy initiatives from the Imperial Valley—wind, solar and even biomass—to be accessible by the smarter San Diego grid in the near future.

Glimpses of the future “In the electric industry today, as we modernize our grid here in the San Diego region and around the U.S., we have not begun to dream of what our future will be,” Avery added.

But there are a few glimpses into that future. The learning curve for SDG&E reliability will likely be defined at technology hot spots like the utility’s Borrego Springs microgrid project.

SDG&E’s been experimenting with microgrid options such as the At the fore on many fronts $15 million Borrego Springs project SDG&E leads in many arenas: smart grid, smart meters and to reduce feeder renewables. Its metering deployment may have set the stanpeak load by We don’t do dard for customer interaction kudos, but the latest customer15 percent, examine centric project on that list is Green Button. volt-amps-reactive this for the Green Button allows customers to access their smart meter (VAR) management usage information. SDG&E is one of three utilities—all in and to continue accolades; it’s California—launching the new tool, which puts up to to enhance system 13 months of consumption data at the digital fingertips of reliability. Located merely in our DNA. the utility’s consumer. The consumer can then export that in a small desert town east of data in a simple format to other applications.

Escondido, the project is currently Green Button developed from a White House call to action, asking utilities on track to becoming one of the to develop consumption tools for consumers similar to Blue Button that first fully functioning utility-spondelivers simple-to-understand health care data. Avery loves Green Button sored microgrids in the country. because it’s a nationwide push for a standard platform that can be utilized The community’s isolation and by everyone, as cooperation and collaboration are two of SDG&E’s cultural related system problems made it touchstones for smart grid efforts and the utility’s overall plans for a brighter ideal to host a microgrid pilot project, energy future. allowing SDG&E to dramatically That mindset of collaborations and bringing everyone to the table is key to increase reliability for the small making SDG&E the most intelligent UtiliQ utility, according to Avery. SDG&E community while investing in a wants to deploy the best ideas from anyone, not play it close the vest with its “living laboratory,” as Avery called own plans and ideas to the detriment of customer service. After all, part of the it, to work on the power industry’s SDG&E DNA is built on customer service. future issues, from renewables integraIn SDG&E lore, five San Diegans met in the parlor of the Consolidated Bank tion to customer participation. on April 18, 1881, to incorporate the San Diego Gas Company. In the nearly “By the end of this year, we’ll have 131 years since that meeting, SDG&E has become more than a simple supplier a large part of the Borrego Springs of gas and electricity. It has grown into a leader serving the seventh largest city in equation up and running, but the the U.S. in both traditional and cutting-edge ways—the traditional mindset of project doesn’t have an end date. We customer service paired with more intelligent technology and devices, making it will learn from it, grow and make the leading UtiliQ utility in 2011. changes as the variables change,”

“

”

Kathleen Wolf Davis is a freelance writer based in Tulsa, Oklahoma.

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Avery said.

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TOP 3 UTILIQ UTILITIES

2

Dasso pointed to efforts to collaborate on, research and develop Green Button as one example of that employee passion. Green Button is a consumer-focused push that allows customers to download energy use in a standard format that can be shared with energy service providers.

“Green Button was the culminaNo. 2 utility builds foundation for the future tion of three years of work by folks

By Kathleen Wolf Davis in IT and customer care, allowing us to be one of the first deployments PACIFIC GAS & ELECTRIC (PG&E) CONTINUES TO CLIMB THE UTILIQ of the open automated data exchange ladder. Garnering a fourth place finish in 2009 and third place in 2010, (Open ADE) standard.

PG&E has finally grabbed a silver spot in the 2011 UtiliQ rankings Our team was able to right behind fellow California utility San Diego Gas & Electric.

STATS leverage smart grid Incorporated in California in 1905, PG&E is one of the largest CUSTOMERS work and turn that combination natural gas and electric utilities in the U.S. Based in 15 million into something very San Francisco with 20,000 employees, the company provides natural useful for customers gas and electric service to approximately 15 million people throughCOVERAGE that the whole team 7,000 sq. miles out a 70,000-square-mile service area in northern and central in Northern and is very proud of,” California from Eureka to Bakersfield and from the Pacific Ocean Central California Dasso said. to the Sierra Nevadas.

Pacific Gas & Electric

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++

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EMPLOYEES Crafting a Employee passion resonates 20,000 cornerstone According to company culture and Kevin Dasso, PG&E’s senior In fact, those passiondirector of technology and information strategy, what sets PG&E ate people help in a number of apart is the people—employees with a passion for the company and for serving company initiatives, including residential and business customers.

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TOP 3 UTILIQ UTILITIES respond. At the end of 2011, the utility projects aimed at shoring up system reliability, such as the Cornerstone Improvement Program. moved into a construction phase. To The Cornerstone Improvement Program began in the summer of 2010 to move forward, the utility must beef up increase grid flexibility, mitigate outages and lay a smart grid foundation. In the telecommunications network to urban areas, the project involves installing new substation transformers, support the timing of synchrophasor equipment and feeders as well as updating several overhead and underground data streams. conductors and investing in smart automation. In rural areas, it also involves “We’ve begun installing the meathe installation of reclosers and fuses. surement devices and data collection Cornerstone is moving into full-scale construction systems, some key system this year, according to Dasso. Last year was all about components,” Dasso said.

We’ve moved testing, verification and building the infrastructure, but “And we’re starting to 2012 is all about in-depth construction of circuits, perreceive devices from our from simulating forming upgrades and adding automation technology. supplier partners. The phaBakersfield is the first focus, with the installation of a sor measurement units are to building core telecommunications structure and the retrofitcoming in now. So we’ve ting of certain circuits. By the end of 2012, 150 circuits moved from simulating infrastructure. will be automated; the goal of 400 automated circuits to building infrastructure should be reached by the end of 2013. with this project.”

One of the Cornerstone pilot installations had an outage last year on a circuit Foundation for the future that serves 2,200 customers. The system automatically detected the event (a Dasso sees Green Button and the fallen tree branch), isolated the problem and restored service to 1,800 customers company’s smart meter deployment in the unaffected portion of the circuit in less than five minutes. as two of the utility’s highlights of From corner to end-point 2011. The third was PG&E’s filing of Dasso labels both the Cornerstone program and PG&E’s smart meter deployits smart grid deployment plan. Dasso ment as “foundational,” ones providing direct benefits to customers in areas such labeled that act a “significant accomas reliability. And both will provide additional benefits in the future in terms of plishment and milestone” for PG&E. technology, data and how those items are used within the system.

“The plan allows us to think about In fact, Dasso expects that PG&E will leverage the telecommunications what’s important about smart grid,” network built for the smart meter deployment to put more sensors out onto Dasso said. “It allows us to focus our the grid in the future. efforts and communicate.”

In the here and now, that smart meter deployment is right on track, with Noting that the plan helped “crystal9 million meters installed so far and the plan to finish by this summer with lize” the smart grid concept for PG&E, more than 10 million. The smart meter program is moving from conceptual Dasso reiterated that the smart grid to reality for Dasso, who has seen the beginnings used to support programs to PG&E is “a means to an end,” with like outage management. the end being a focus on “providing Coming into the 2011/2012 storm season in California (which picks up in late safe, reliable and affordable service” to fall and early winter), the utility utilized smart meters in the restoration process. customers. PG&E sees the smart grid Rather than the more traditional truck rolls to investigate suspected outages, the as a way to advance that core mission. utility could ping meters from the office, checking to see if there were issues and To do so, PG&E has put into place avoiding sending critical resources on a wild goose chase for phantom problems. a disciplined approach to smart grid The system improved restoration times by focusing on real outages—and all this technology implementation, with a was possible with only a fraction of those smart meters in place. focus on building a foundation for the future. According to Dasso, PG&E’s High wire intelligence greatest differentiator is its careful, While distribution automation and advanced meters may be the foundation thoughtful approach to crafting a of the PG&E smart grid program, the company is also working to transform future-focused energy company. PG&E its transmission network by participating in a synchrophasor installation will make sure the technology that’s project with a number of other western U.S. utilities under the advisement cool and hip today also works efficientof the Western Electricity Coordinating Council (WECC). All of these items, ly and practically for tomorrow. fundamentally, help with system reliability.

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In 2011, PG&E built a proof-of-concept lab to simulate synchrophasor use in the field, right down to details on how it would look and how the system would

Kathleen Wolf Davis is a freelance writer based in Tulsa, Oklahoma.

3

And on Jan. 7, Austin Energy unveiled a massive solar panel site east of the city. The privately built Webberville solar project will generate enough electricity to power 5,000 homes annually from 127,000 solar panels on a 380-acre site. The No. 3 utility has its hands full 30-megawatt facility is considered

By J. Ian Tennant one of the largest in the country.

Among its ongoing efforts, the YOU WILL HAVE TO FORGIVE THE FOLKS AT AUSTIN ENERGY IF city-owned utility has been retrofitting they don’t notice they dropped a spot in the Intelligent Utility’s UtiliQ all of Austin’s streetlights, a job that is Top 25 Intelligent Utilities rankings, from second place in 2010 to about one-third comthird in 2011. plete. The new “smart STATS They have been such busy campers continuing to transform lights” will inform Austin energy consumption and delivery in the Texas capital—and CUSTOMERS Energy when a light no unveiling Austin Energy’s first proposed rate increase in 17 years— 430,000 longer shines, a much that they probably won’t even notice their new spot in the top 25. more proactive situaCOVERAGE “We’ve got our hands full,” said Jerry Hernandez, Austin Energy’s 437 sq. miles tion instead of waiting director of smart grid and system operations, seemingly enjoying in the municipality to hear from a passerby the understatement. “We are keeping pretty busy.” of Austin, TX if a streetlight is out, Hernandez said.

Rolling out renewables and efficiencies EMPLOYEES 1,710 The utility also recently The nation’s ninth largest community-owned electric utility, Austin rolled out a mobile workEnergy has about 430,000 customers and covers a population of force management system to improve almost 1 million. It relies on energy sources such as nuclear, coal, natural gas workers’ efficiency, and it is looking at and renewables, generating almost 3,000 megawatts of power.

Austin Energy ++

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TOP 3 UTILIQ UTILITIES migrating its internal management system to a large-screen video setup that is expected to enhance situational awareness.

customers, Roger Borgelt, told the local daily newspaper that the energy provider’s new plan “couldn’t even be called throwing a bone. I’d call it throwing a fingernail.”

Austin Energy has said that it must focus on small businesses and residential areas because they have historically been paying less than what it costs to service those customers. According to the new plan, homeowners would see their monthly electrical bill climb from $114 to $127 in 2012, and then inch up another $3 per month in 2014.

No-stress smart meter conversion Austin Energy has completed its conversion to smart meters and is now gathering information from its advanced metering infrastructure (AMI) to improve responses to outages. It is also “looking behind the meter,” Hernandez said, to determine how best to work with customers to manage their energy use, especially when it comes to large drags on the system like lighting.

Regarding the implementation of the smart meter program, which has been controversial in some areas of the country, Hernandez believes Austin Energy was “rather successful in our rollout.” He credits a concerted advertising and marketing campaign for informing the public about the benefits of the smart meter program and how the utility would go about installing the new meters.

“We really didn’t have a lot of customer complaints because we were very transparent with the whole thing,” said Hernandez.

Accurately reflecting true costs Balancing budgets and reserves Just like any Austin citizen, Hernandez When it comes to the public’s reaction to the proposed rate increase, however, is bracing himself for his new electricity bill, but the reality is these are Hernandez is not expecting a sustained opposition, especially if consumers realfinancially tight times and ize Austin Energy needs the revenue to mainthe utility is “trying to tain popular efforts, such as its voluntary green We really didn’t have tighten our belt too.” He pricing program, GreenChoice, the nation’s most noted that the current rates successful utility-sponsored, voluntary green a lot of customer reflect the life and times of pricing program for eight years running.

17 years ago, when Texans In fact, Austin Energy has been an ATM complaints because would crank up the air for the city, chipping in $77 million to the conditioning and leave a municipality’s general fund in 2006, a source we were very window open, an amazingly of revenue that rose to $105 million in 2011, wasteful exercise by today’s helping the city council cover expenses that transparent with standards, but one that also would otherwise have had to be covered by benefited utility providers unpopular hikes in property taxes. the whole thing. like Austin Energy: the But now Austin Energy needs $126 million more energy used, the more more in yearly revenue to cover its budget, deal revenue it collected. with rising costs and replenish its reserves, the Austin American-Statesman But Austin Energy has been runreported. On its Web site, Austin Energy projects a $75 million deficit for the ning a deficit for the past three to four upcoming fiscal year, which started Oct. 1, 2011. years, Hernandez added, so now it’s time to establish a rate structure that Two-pronged approach to rate increase proposed accurately reflects the costs of deliverAustin Energy officials met with the city council on Dec. 14, 2011, to discuss ing energy to the hip and not-so-hip its proposed 12.5 percent rate increase, which would have seen residential customers that populate the self-styled customers who use 1,500 kWh or less a month pay $10 to $20 more, one of “Live Music Capital of the World.” a series of suggested rate hikes that would have targeted small businesses, Hernandez doubts he’ll see a subchurches, apartment dwellings and homeowners. stantive change among customers in Not surprisingly, some public outcry ensued. Austin Energy went back to his laid-back hometown, no radical the drawing board and on Feb. 2 it suggested a two-pronged approach to the increase: raise rates by 8.7 percent sometime this year and by another 3.8 percent revolt or reaction to the rate increase if it is approved. in October 2014. The city council will revisit the issue in March.

If there is, the busy Austin Energy As can be imagined, the rate increase has received mixed reviews. One councrew is used to being busy. cilor, Bill Spelman, told the American-Statesman that the revamped plan suggests

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“we’re headed in the right direction.” However, church groups are still not satisfied by changes proposed by Austin Energy, and an advocate for suburban

J. Ian Tennant is a freelance writer based in Austin, Texas.

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Automating the

ing planning for smart grid distribution systems, also serves as secretary for the IEEE/PES Working Group in Smart Distribution, its task force on Volt-VAR control, and its new task force on distribution management systems. I asked him about the DMS of today, its most important components, the most important reasons for utilities to implement DMS and, finally, what the DMS of the future will look like.

The DMS of the future, now ++EPRI technical executive discusses the importance of distribution management

By Kate Rowland THE

ELECTRIC

DISTRIBUTION

SYSTEM

IS

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ILLUSTRATIONS BY ABBY ORLANDO

undergoing an evolutionary change thanks to the implementation of smart grid technology.

With the addition of millions of points of new data on the grid, it’s even more imperative that utility operations be able to monitor and control, in near real time, what’s happening on the distribution network.

Enter the distribution management system (DMS), which Robert Uluski, a technical executive with the Electric Power Research Institute (EPRI), defines in this way: “DMS is a decision support system to assist the control room and field operating personnel with the monitoring and control of the electric distribution system in an optimal manner while improving safety and asset protection.”

Uluski, who leads EPRI’s research and development activities in advanced distribution applications and engineer-

High level of growth The DMS helps collect occurring “We are already seeinformation from ing high growth in the level of DMS the growing array of deployment,” Uluski told me. “Three years distribution system ago, there were fewer than five major DMS information sources. projects under way in North America.

Now, there are dozens of DMS projects that are currently being planned or implemented by small and large utilities alike. Some of these newer projects are using a phased approach in which basic functionality (monitor, display, alarm) are implemented first, followed in a few years by more advanced functionality.”

There are many reasons for electric utilities to consider implementing DMS. The most important reason is improved operator awareness and decision-making for

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AUTOMATING THE GRID

a distribution system that is rapidly becoming more complex to operate.

“Complexity is due to heavier loading, frequent reconfiguration and the presence of high penetrations of distributed energy resources,” he said. “Operators are taking on new responsibilities, such as optimizing the efficiency and reliability of the distribution system, and asset protection.

“The DMS provides an effective mechanism to manage the wealth of new distribution system data from AMI (advanced metering infrastructure) meters and sensors, perform tedious and often complex calculations using the acquired data, and assist in operator decision-making in a timely manner,” Uluski explained. “The DMS helps collect information from the growing array of distribution system information sources and then applies suitable analytics on the acquired information to improve distribution system efficiency, reliability and performance.”

Making better informed decisions Real-time or near-real-time information (from a few seconds old to a few minutes old), as well as archived information (collected in the past) is all used in DMS applications. This enables distribuIt is no longer practical tion system operators to make into handle interactions formed operating decisions based between important on actual conditions as they exbusiness systems ist at the time of the decision. via manual, paperWhere is this information coldriven processes. lected? Most of it comes from distribution SCADA, an essential component to the DMS system. “Without SCADA and the associated analytics, decisions are based on assumptions and judgement calls, which is becoming increasingly difficult given the frequently changing and often unpredictable nature of the modern distribution system,” Uluski said.

DMS analytics, he says, help make the complex control decisions that are needed to optimize distribution system performance, efficiency and reliability: “It is not practical to perform some performance improvement calculations manually in a timely manner without DMS-driven models and algorithms.”

As many utility executives have noted, it’s more than technology that drives the smart grid. Today’s grid is also all about people and processes, and those processes, more and more, have to cross the traditional utility silos to inform all the necessary parts of the business, and quickly.

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“The interfaces to external enterprise business systems are essential for effective communication between the multitudes of business processes that exist in the electric utility corporation,” Uluski said. “It is no longer practical to handle interactions between important business systems via manual, paper-driven processes.”

Marrying OMS and DMS For some utilities, marrying its outage management system (OMS) to its DMS is an obvious slam-dunk. In fact, many are looking at it both for economies of scale, and because the combination of the two just simply makes sense.

“While some electric utilities have separate distribution control rooms and outage response centers, the outage management and operations management functions at most utilities are handled by a single organization,” Uluski explained. “So a combined OMS/DMS, with a single user interface, makes sense.”

Another strong reason for a combined OMS/DMS is that the two systems share a distribution system model that must be maintained and kept up to date at all times: “This is a challenging and resource-consuming activity, so there is significant benefit if there is only one instance of the model to build and maintain,” Uluski added.

Many system vendors that have traditionally supplied OMS to utilities have either already developed or are planning to develop a complementary DMS/SCADA system.

“Similarly,” he said, “most DMS/SCADA vendors are adding OMS functionality.”

Choosing the applications Other DMS applications vary from utility to utility, depending upon their specific needs. The most popular applications right now are Volt-VAR optimization and fault detection isolation and restoration, or FDIR. “Many utilities have implemented these two systems as separated, standalone distribution automation systems for proof of concept,

and are seeking to use DMS for a more flexible, systemwide implementation,” he said.

Looking to the near future, DMS applications for managing two imperative additions to the operational mix (managing demand response and distributed energy resources including distributed generation, renewables and energy storage) for volt-VAR control, microgrid management and more will increase in importance for utilities. Likewise, applications that manage electric vehicle charging strategies and vehicle-to-grid strategies will also become more important in regions where high EV penetration exists.

Getting there On the path to the future, there are some important needs to be considered. Although a massive amount of data is now being collected on the distribution system, not all of it has

Looking to the future I asked Uluski what he saw in the future for DMS as it evolves.

“The basic DMS building blocks will always be there: a nearly real-time interface to field devices for continuous monitoring and control, analytics to support improved decision-making and automatic control, and enterprise integration that will enable the DMS to interoperate seamlessly with other essential corporate business systems such as GIS, asset management, workforce management systems, etc.,” he said.

Currently, there is considerable variation in how these basic DMS building blocks are configured: “The design varies between a ‘centralized’ approach, where all analytics physically reside in a distribution control center or remote data center, and a ‘decentralized’ or ‘distributed’ approach, in which the analytics reside in a processor (or multiple processors) that are located in distribution substations or out on the feeders themselves (mounted on poles, pad mounted, or installed in underground vaults),” he said.

Which design, centralized or decentralized, will ultimately win the day?

Both, Uluski said. “Most of today’s distribution automation (DA) and distribution management systems include a mix of centralized and decentralized components (a ‘hybrid’ arrangement), and this is most likely a trend that will continue,” he noted.

“DA/DMS applications that require fairly high-speed automatic control actions (responding in a few seconds)— for example, fault detection isolation and restoration— may be handled by decentralized components,” he said.

“Applications that primarily support operator decisionmaking and do not require high-speed control of field equipment (such as switch order management) will most likely be centralized.”

The final key? “Regardless of the approach used, it is essential that the analytics use the latest (as operated) state of the distribution system and that the operators are always kept informed of any automatic control action,” Uluski stressed.

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“Seeing” the distribution system The massive amount of data now available on the distribution system means having effective and efficient data visualization techniques is essential on the DMS. “The number of distribution data points has grown exponentially in recent years, so displaying all DMS data points as individual numeric text data is not practical,” Uluski said.

“For example, a DMS on-line power flow program generates well over 10,000 quantifies per feeder, and DMS with more than a million available quantities is the norm,” he added.

“The data visualization techniques must draw operator attention to high-priority, actionable parameters.”

Colors and various highlighting techniques on graphical displays have been used on distribution SCADA systems for many years.

More recently, DMS visualization techniques have included high-resolution geographical displays showing street maps and physical landmarks with dynamic power system geographical display information superimposed.

“Photograph-quality displays and satellite images (Google Earth displays, for example) are common on recent DMS systems. Near-future systems will be able to view photographic and streaming video images from handheld devices and airborne drone-mounted cameras for improved damage assessment and interaction with the field workforce,” he said.

practical applications as yet. “We are still looking for worldclass ways to use the new data,” Uluski said. “This includes using AMI data, which has great potential but few real applications. We also need new applications for data mining, and new analytics for improved distribution performance.”

And, as with so many other aspects of the evolving intelligent grid, there comes the need for standards. Although integration standards such as CIM (Common Information Model) are under way, they are not yet fully realized. As well, Uluski said, “Standards for the DMS applications do not exist at all, so there is a lot of customization work, which increases cost and risk to utilities.”

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substation automation

was largely the result of different parts of PECO’s automated system being able to make quick fixes and talk to one another, from the reclosers—devices that automatically restore short-circuits—to advanced metering infrastructure that enables two-way communications between the customer’s meter and the utility.

Pritchard emphasized, in particular, that the pole-top reclosers allow PECO to “isolate an incident to few customers affected by an event,” giving the utility the tools to restore the rest of the circuit in a few minutes.

Substation automation to the smarter grid ++PECO’s progressive innovation, putting the customer first

By Laurel Lundstrom

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IN

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DAYS

BEFORE

HURRICANE

IRENE

pounded the East Coast last August with wind gusts of up to 70 miles per hour and torrential rain storms, PECO mobilized its arsenal of field staff, local and national personnel, to respond to the record-breaking Category 1 storm. But equally important to those last-minute preparations were the steps PECO took in the almost two decades preceding the storm: beginning with the automation of its substations and continuing to present day with the installation of new smart-grid technologies.

“PECO was one of first utilities on the East Coast to have all its systems restored,” said Glenn Pritchard, principal engineer, Exelon/PECO. “We had half a million customers off [of the grid]. To have them restored in five days is very significant.”

PECO spent $45 million on storm restoration, an amount that could have been significantly greater.

“PECO saved in excess of $10 million during the fall hurricane by taking a single customer call and analyzing it to see what responders needed to go out,” said Pritchard. The ability to learn about the breadth of an outage from one report

Consolidating and automating PECO’s quest toward automation began in the mid-1990s.

“PECO had an interest in modernizing the substation with better functionality, focusing on digital relays and more advanced relay schemes for transmission and distribution circuits,” said Pritchard.

At that time, without widespread Internet use, “we needed banks of computers to monitor substations,” he said. “What we found was that each of the systems required their individual system to operate. We tried to find ways to consolidate these systems into one platform.”

PECO sought “a better way, both locally and remotely, to monitor, control, diagnose and maintain equipment in the substation to reduce operating costs and provide improved customer service,” explains a case study written on the automation of its Westmoreland substation, which supplies about one-third of Philadelphia’s electrical load.

“We looked at the different scenarios when things would alarm,” said Pritchard, “and then we looked at how we could get ahead of these alarms—to be preventive instead of reactive.”

The case study describes the renovation of Westmoreland in 1997 as “a complete turnkey transmission and distribution automation solution from system design through installation and commissioning.”

fault data and breaker trouble conditions, said the case study.

“The customer not only has immediate fault location data to perform better and faster restoration, but also has detailed event reports automatically collected from the system. These event reports can be viewed in a graphic format to analyze system operation. These data can help the customer make intelligent decisions and system recommendations.”

Making it safe, keeping customers satisfied As with most utilities, once the functional requirements of a system were met, PECO was concerned with reliability, speed and cost.

“We were trying to find ways to operate more effectively and safely,” said Pritchard, “refining how we do business to increase reliability.”

Better knowledge of how the system operated led to increased safety for linemen who stored and managed circuit-

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This involved a microprocessor-based protective relay design that minimized maintenance costs through the use of self-checking and communications processors that collect and organize data from the relays to the transformers and breakers. The design ensured that the failure of any one of the protection or communication components would not prevent monitoring or control of any one of the 54 breakers and switches in the substation.

“The new design uses equipment on an unprecedented scale and is the largest single integrated system for protection, control, data acquisition, and monitoring ever undertaken by PECO,” said Jack Leonard, PECO’s principal engineer, in charge of investment strategy, at the time the case study was published.

The system increases the efficiency of substation maintenance through the automated reporting of relay-generated

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ry more efficiently and more effectively by modifying the reclosing scheme.

On the other hand, the utility was challenged to move the workforce toward automation, pulling manual controls off of the circuit breakers. “This was a significant change in practices,” said Pritchard. “But all in all it was a big safety win.”

In Pritchard’s opinion, however, it was increased reliability that was the most lucrative result of automating its 87 primary substations.

While Westmoreland was one of the last substations PECO renovated in the 1990s, it continues to increase reliability and speed and drive down costs through upgrades to other parts of its system. PECO’s system is ever more reliable today with its ability to automatically generate information on outages from its metering system and to automatically repair short-circuits with pole-top reclosers.

“The combination is really great,” Pritchard remarked.

“And reliability means customer satisfaction,” something that is paramount to staying competitive in the state.

Progressively innovating “I do believe we were very progressive in with 1,500 customers, what we were doing and that translates you only need a into where the utility is moving with handful of customers the smart grid today,” continued Pritchard. to tell you it’s off.

He says that the utility has made incredible strides through new communications and information technology tools; for example, through a fiber-optic network, wireless networks and having broadband capability wherever it is needed.

PECO’s most current venture is the integration of customer meters into its operation management system. The utility is about 20 months into a three-year push to install advanced meters to its entire customer base. Thus far, PECO has begun the installation of the first third of the advanced meters. “This will bring two-way communications to each and every customer,” Pritchard said. “All 1.8 million will then be automated.”

The utility is also installing a distribution management system, which will allow PECO to receive real-time information about the distribution grid, updating a system that has been in service for 20 years.

“A new modern distribution management system will allow us advanced voltage management to help us meet energy efficiency goals and bring us meter data and distribution automation schemes all together,”

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explained Pritchard. “It is satisfying to see this culmination of applications.”

Data tsunami As a result of all of these upgrades and promising new technologies, in the last decade, “we’ve seen the first glimpse of the data tsunami,” said Pritchard. “We have all this data and now we have to know what to do with it; how to process and make sense of it.”

A recent New York Times article (“Age of Big Data”; Feb. 12, 2012) purports that we, including the utility industry, are in “the age of big data.” Big data, says the article, is “shorthand for advancing THE DETAILS trends in technology that open the door to a new approach to PECO is the largest electric understanding the world and and natural gas utility making decisions.” The article in Pennsylvania, serving quotes IDC, a technology reapproximately 1.6 million electric customers and 490,000 natural search firm, as estimating that gas customers in southeastern data, by volume, is growing at Pennsylvania. Approximately 50 percent each year.

90% of PECO’s customers are Pritchard says it is important residential and the remaining that utilities not “get blinded by 10% are commercial and industrial. the attraction of endless data.”

“If you have a circuit with Glenn Pritchard, the principal 1,500 customers,” he explained, engineer quoted in this story, can be reached directly by “you only need a handful of cuse-mail at glen.pritchard@ tomers to tell you it’s off—you exeloncorp.com don’t need all 1,500.”

The case study referenced With the need for advanced in this story was written by data analytics growing, PECO Dave Dolezilek of Schweitzer has spent a great deal of effort Engineering Laboratories, finding the right tools to conand can be found here: http://bit.ly/yWPzjkN. duct the analyses. Through its formal request-for-proposal process, the utility chooses software largely focused on specific areas of interest to the utility.

“We are less interested in ‘one size fits all’ and more biased toward specialty programs with a narrower purpose. The big ones do a lot of things, but maybe not as well,” he said.

Because new software applications for managing data create new areas of learning, staff capacity must be built in these areas. Keeping staff interested in and invested in advancing PECO’s system is paramount to success, insists Pritchard.

“With a multiyear project, you need dedicated people. You need staff to take ownership and become stakeholders in the process itself,” he said.

Both with customers and internally, Pritchard continued, “don’t overpromise. Stay grounded about what you are really capable of and take the baby steps first.”

Laurel Lundstrom is a freelance writer based in Washington, D.C.

Smart grid projects can be deceiving.

We’ll help you navigate the unforeseen. osii.com

© 2012 Open Systems International, Inc. All rights reserved.

FEEDER AUTOMATION

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FLISR provides a smart brain ++PG&E, Southern Company and others transitioning pilots to full-out rollouts

By Kate Rowland IN A POWER OUTAGE, RESTORATION TIME

becomes the most imperative issue, from a customer’s perspective. Automation, thanks to devices out on the feeders and a good, two-way telecommunications network reaching out from the utility’s control room, can isolate the outage within minutes and reroute electricity routes around it while the issue is being resolved.

Fault location, isolation and service restoration, or FLISR, is a primary automated line switching application gaining traction with electric utilities. In fact, in a survey of utility

executives on distribution optimization applications conducted last year by IDC Energy Insights, FLISR scored highest in terms of interest and technical feasibility, and was deemed likeliest (of four distribution optimization applications) to lead an adoption cycle starting this year.

Enabling a smart process FLISR has been described as the smart brain at the control center, using remotely controllable devices to execute the smart decisions. It, and other automated applications, can alternatively be viewed as the heart of the system, operated remotely from the operations control center via the “arteries and veins” of an extensive two-way telecommunications network.

True to its name, FLISR performs this way. It: ??

Detects that a feeder fault has occurred;

??

Locates the damaged portion of the feeder between two remote controlled line switches;

??

Isolates the damaged portion of the feeder by opening appropriate remote controlled line switches; and then

??

Re-energizes undamaged portions of the feeder via the primary feeder source and one or more backup sources using remote controlled tie switches.

Putting FLISR to the test Pacific Gas & Electric recently piloted FLISR in Rio Vista, the largest small town in California’s Eastern Solano County, as part of its Cornerstone Improvement Program, authorized by the California Public Utilities Commission (CPUC) in 2010. Here, the longest rural electric circuits that serve the

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Put to the test Last September, the FLISR equipment in PG&E’s pilot project was put to its first real-world test. On the morning of Sept. 12, a downed overhead line took out one of PG&E’s two circuits to Rio Vista. Marshall says the FLISR equipment sized up the problem, quarantined the bad section and restored service to 1,774 of 2,294 customers in under two-anda-half minutes.

“Based on typical repair times, that quick response slashed the number of affected customers by 77 percent and the number of minutes they were out of power by two-thirds,”

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It’s gaining traction with utilities that have deployed smart meters, according to IDC Energy Insights analyst Marcus Torchia, who earlier spoke with Intelligent Utility Daily editor-in-chief Phil Carson about FLISR’s interest. “With smart meters and AMI (advanced metering infrastructure) in place, FLISR becomes a process, an application, that’s more readily enabled because the meters act as sensors that can trigger an alarm that the power is out,” he said. “With meters, FLISR becomes more accurate and restoration goes more quickly.”

But implementation, Torchia said, requires greater effort than volt-VAR control, which scored higher on economic feasibility in the IDC survey. FLISR requires integrating a number of systems across operations, engineering, customer service and billing to get utility visibility out into the distribution grid.

Volt-VAR control, on the other hand, is operations-facing alone, meaning less integration and less cost to implement.

community of 7,300 residents are subject to being knocked out by extreme weather, tractor drivers who take out power poles and even birds that straddle the charged wires. In other words, a perfect test case for FLISR. FLISR was piloted by the utility on 25 miles of circuits served by one substation in the Delta. The circuits deliver electricity to Rio Vista, Isleton and Clarksburg along the Sacramento River, as well as to the farms and ranches within the area.

But before the pilot was even launched, the FLISR technology was lab-tested and evaluated at PG&E’s Smart Grid Test Center in San Ramon, according to Jonathan Marshall, PG&E’s chief of external communications, who wrote about it extensively in the utility’s NEXT 100 blog last spring. The test center’s first smart grid project involved “the rapid design and construction of a three-circuit simulation to test and evaluate state-of-the-art FLISR systems,” Marshall noted, before the FLISR devices ultimately chosen were installed on key urban and suburban circuits across its service area as part of the three-year Cornerstone Improvement Program.

“Currently, the typical switching time is Quick response about an hour,” Kevin Dasso, PG&E’s senior slashed the number of director of smart grid and technology inaffected customers tegration, said as the FLISR technology was by 77 percent and the being lab-tested. “Our target is to do that in number of minutes less than five minutes.

The reality is that it they were out of usually takes about two minutes.” power by two-thirds.

In the new lab, Dasso’s technical team was able to thoroughly test out new FLISR devices and software under all manner of realistic scenarios, ironing out the risks of a full field implementation, Marshall reported.

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FEEDER AUTOMATION

Integration in larger pilots Southern California Edison, San Diego Gas & Electric (SDG&E) and Southern Company, among others, are also expanding their FLISR pilots further into their larger coverage areas. NSTAR and EPB Chattanooga have large-scale implementations underway, as well.

SDG&E, for example, has been installing automated switching since 2008, with plans to have its entire distribution area covered by 2016. In addition, its feeder automation system technology (FAST) is part of an integration of five technologies it is piloting as a proof-of-concept Beach Cities Microgrid test.

Besides feeder automation system technology, the U.S. Department of Energy (DOE) component of the microgrid pilot includes distributed energy resources and volt-ampsreactive (VAR) management, advanced energy storage, the integration of outage and distribution management systems, and price-driven load management.

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he later wrote. “This will be a big deal to many customers. An hour of downtime can cost businesses tens, even hundreds of thousands of dollars. But even if you’re working from home, an hour lost can blow your deadline, costing you both money and aggravation.”

Expanding FLISR equipment beyond the pilot area will provide economies of scale, adding up customer benefits with any outage. The Cornerstone Improvement Project’s authorized budget through 2013 is approximately $360 million, with about half of the money to be used to help automate more than 400 of PG&E’s 3,200 electric distribution circuits. The CPUC has also said it will take a fresh look at FLISR technology in 2014 with an eye to authorizing more upgrades if they prove cost-effective.

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Reliability improvement important A report on the value of distribution automation, prepared for the California Energy Commission by Navigant Consulting in March 2009, noted that reliability improvement is one of the most common reasons cited by utilities for implementing distribution automation. “Automatic or remote-controlled switches installed on distribution circuits enable utilities to isolate faults more quickly, and reduce the amount of time many customers are without power,” the report stated. “This application, becoming known in the industry as ‘Fault Location, Isolation and Service Restoration’ (FLISR), can yield significant reductions in outage minutes experienced by customers.

“By combining FLISR capabilities with advanced sensors and controls that enable automatic condition-based equipment maintenance, distribution automation could yield even greater reliability improvements.”

No glamor, but lots of workhorse intelligence It’s not glamorous, and it’s usually discussed in the larger context of outage management, but FLISR technology is one of the next best steps a utility can take once intelligent meters and a utility-wide communications infrastructure are in place. The ability to localize an outage, quickly reducing larger-scale outages to more localized ones, minimizes the scope of the work necessary for the crews dispatched to verify and repair the identified fault on the circuit.

Its immediate benefits are observability and coordinated automatic control. As with many of the new technologies being implemented, the increased granularity of the data available means distribution operations can become increasingly more efficient. And the ability to locate the fault remotely turns into both reliability and savings benefits, narrowing the scope of work necessary by field crews for each event and reducing the number and scope of prolonged outages.

While FLISR technology, or fault response automation, can’t automatically clear a hard fault, it can definitely both reduce the impact of the fault and narrow the scope of the work that needs to be done by the field crew, who would otherwise be patrolling along the entire feeder to locate the problem, and then manually restoring service to as many customers as possible before repairing the fault.

It’s all about knowledge Integrating FLISR with other distribution automation technologies, in short, gives system operators increased knowledge about the system, better data to deal with in terms of responsiveness and decision management, and the ability to improve both reliability and safety, too.

According to industry analysts, we’ll be hearing a lot more about FLISR in the years to come.

With files from Phil Carson.

I certainly agree that the aging workforce is an issue for us, as well. A third of our employees are eligible to retire in the next five years, and so that’s a concern about how we prepare for that. We’re doing some succession planning there. Security is also a big issue. Keeping our system and our customer data secure is very important to us. In addition, our industry has many external agencies concerned about security. The North American Electric Reliability Corp., the Federal Energy Regulatory Commission, the U.S. Department of Homeland Security and the state public utility commissions are all placing security demands on utilities. I think staying a step ahead of all those security requirements is a worry to our whole industry.

HENDERSON

Focusing on customers ++Trends explored at Knowledge2011

By Kate Rowland WE SAT DOWN WITH ELECTRIC UTILITY CHIEF INFORMATION

officers gathered in Florida for Knowledge2011 to discuss the issues of most importance to their companies in 2012. Their comments, edited for style and length, follow.

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What is the biggest challenge facing the electric utility industry?

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HATRIDGE Certainly, an aging workforce is a business issue with us. The big challenge of that is not only that we have a lot of pending retirements in the next few years, but we’ve operated based on the Socratic method in the past, where knowledge was passed on from individual to individual, and we’ve not been particularly good at preparing formal documentation on all of our business processes. So that’s the area that we’re really focused on the most across our organization, developing more formal documentation of our knowledge and putting it into electronic format. We’re also making sure it’s in a format that can be passed on to others, and we’re starting the process of transitioning that knowledge to new individuals. As a government agency, we have civil service rules that restrict our ability to prefill positions before the retirements occur. That presents some additional challenges for us with the whole concept of succession planning, which is extremely difficult to do in a government organization because of the rules.

BARRIOS I would agree with both of these. Another issue of ours is the changing consumer expectation. One of our corporate initiatives is shaving the peak for a 20-by-2020 reduction.

But figuring out how to get members to adopt a load management program or demand management, energy management, and what the mechanics of that system are going to look like, is a challenge. With some of this technology, it’s a commitment— a decade-long commitment for the life of that equipment, so we feel that we really have to make the right decision and a prudent investment.

Those are all valid points.

I think for us in Ohio, a lot of it has to do with competition from deregulation. It’s been around for years, but it’s just now really heating up, and so we see a lot of switching going on with customers. We also see a lot of confusion being created with customers, as well, and from an IT perspecHOSKINS

tive, that translates into much more of a need to be dynamic around the projects. And there were always some dynamics involved, but now it seems like we’re having to revisit that planning more often and do a little bit of a reset or readjust it in a new direction.

So some of that’s not entirely new, but the frequency and the dynamics of it are greater than we’ve seen in the past.

How are information technology and operations technology converging at your company?

HENDERSON We went through a reorganization/transformation in IT

I think continuing to strive to get that seat at the table and to be out in front of those things during the discovery phase of the strategy is critically important.

We’ve done something similar, and we call ours “business relationship managers,” but they are our link to the business. They are essentially our eyes and ears as to what’s going on and making sure that we continue to stay involved in those things, and that’s been somewhat effective for us as well.

HOSKINS

I think as systems continue to get more integrated, it does become a requirement. We’re very integrated, so we have a group that specializes in OT, and a group that specializes IT, but there’s no project where they’re not both involved. You can’t do it without both sides.

It’s very hard to introduce any new process that’s not going to affect the entire system.

BARRIOS

I think we’ve seen that, as well, where the IT/OT organizations that typically wouldn’t have had to work together, the NERC critical infrastructure program has brought us to the table together, and it’s been a really good relationship. And I see that continuing. Smart grid, for me, is where I see the convergence really happening with IT/OT, and I don’t know exactly what that looks like. I’m not necessarily in a hurry to push that. It’ll happen. What I’m in a hurry to do, really, is to keep the open relationship.

SCHMITZ

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SCHMITZ Everything everybody’s said—except maybe for competition—is something that’s on our minds. We came out of pretty much a lost summer with the floods in the Missouri River Valley, and it created a big impact on our customer-owners.

A lot of cost and our energy went into protecting more than $3 billion in assets. Consequently, a lot of the things we planned to do just didn’t get done. So going through our portfolio and trying to figure out what’s not going to get done versus what is, is challenging. And then there is the EPA, and the cross-state pollution rules that are coming our way. We are in one of the states that got pulled into that really late in the game. Our major problem is the timing. We’re getting six months to do the same things other utilities have had many years to prepare for. That makes it extremely expensive and significant.

Our customers aren’t used to the rate increases that are coming their way due to some of the U.S. Environmental Protection Agency and flood issues, and that’s a big communication opportunity that our team is spending a lot of time on.

this past year. As a part of that exercise we interviewed all of our officers and THE EXECUTIVES a large group of senior managers, and we asked what their expectations were LESLIE BARRIOS for IT. The mesExecutive Manager, IT sage came through Bluebonnet Electric Cooperative loud and clear VIC HATRIDGE that they want IT Vice President and CIO to be a business Nashville Electric Service partner, that they CAM HENDERSON want IT to be an Vice President, ally in helping Information Technology & CIO them bring the Portland General Electric technology to the DAVID HOSKINS table to help solve CIO the business problems and help them DPL (parent company assess the technologies, keep them of Dayton Power & Light) from making mistakes, but be a partSTEVE SCHMITZ ner with them. And so, as a result, Division Manager, we’ve developed a group in IT called Information Technology Division “business partners,” and we put our Omaha Public Power District business analysts there. We’ve got consultants dedicated to each line of business, and that’s been very well received. In order to execute on our strategic plan, there’s usually an IT component there somewhere, so it’s important that we be aligned in the business and be partnering with them to make sure that we’re working on the right things that give the most value.

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IT INSIGHTS

Change means a new level of interdependencies ++OGE Energy’s CIO talks about change management

By Reid Nuttall

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TO ME, THE BIGGEST ISSUE IS JUST, SIMPLY, CHANGE.

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The change is transformational within the industry and how we do business, because we’re being hit from so many sides with so many different things.

If you talk about the IT department specifically, again, it can’t be a silo in itself, because people, processes and technology all have to work together. It’s an interesting industry, because in so We asked Reid Nuttall, OGE much, it’s been very project-based. You Energy’s vice president get a project, you get it done, you move on. and CIO, who won Intelligent Well, it’s different now. When your projUtility’s 2011 KITE Award as CIO ects don’t go and operate themselves, you of the Year, to discuss what he have a whole bunch of skills needed that felt was the biggest issue facing need to work together. And this is also true electric utilities today. Here, in of the big picture outside of IT. A power part, is what he told us. plant does not operate now without a significant amount of information technology.

Within IT, too, you can’t buy software and expect it to run by itself.

Here is why I say the big issue is change: we’re handling a level of interdependencies that we’ve never seen before. The industry has seen a lot of people in the same company, doing the same job, or pretty close to the same job, for life.

Now all of a sudden we’re saying, “OK, the world has changed, and you have all these different things that are working in other places with other things and other technologies and other people, not just what you’ve been doing for life.”

Technology is one of the things that is changing, but it also changes the people and the processes.

Sharing excellence companywide We spent a lot of resources on data. Data’s important. We worked a lot on our Information Factory, making things that relate, making it so that we take the enterprise look, not the personal look, at everything. And now, we realize that

we have all these business analysts out there, and we have this data, and some of them are doing fabulous things, and some aren’t doing anything yet.

So we’ve created a Center of Excellence internally. We have a lot of the technology under way and the processes working, and now we’re working on the people side of it. We are jointly training, having people learn from each other, having different departments show to others what they’re doing. All of this helps to put some pressure on departments throughout the company to increase the quality and make it meet our standards.

It’s really interesting to watch people who have been advancing their skills in that they’ve been using a new version of Excel, and now all of a sudden they see that the world has changed, and the tools are amazing, but now the people have to change. It’s also interesting watching the different groups. There are some people that, once you get them into a tool enough that they’re excited about it, all of a sudden they just blossom. And then there are other people where you have to hold their

hand through (the training). And then there are others that you don’t want to touch because they think that the tools should do it all, and it doesn’t work because tools don’t work without people.

So it’s a challenge looking at all three.

“

”

As told to Kate Rowland

Data analytics: start in the middle ++Quick insights can be gleaned from incomplete data

By Phil Carson LLOYD TOKERUD, SENIOR MANAGER OF ANALYTICS FOR

First Choice Power, a competitive retailer in Texas, was hired from PepsiCo to lead the utility’s analytics group. I spoke with him recently about issues in data analytics.

First Choice Power has been in business since January 2002, when deregulation in Texas took effect. The retailer was acquired by Direct Energy last November.

Perhaps Tokerud’s most intriguing role is to work with “business clients” across the organization to understand their challenges and to develop data reporting and analytics to swiftly address those challenges.

Data challenges “The unofficial goal of our team,” Tokerud told me, “is to allow the organization to make decisions faster than our competition.”

I asked for examples of the data challenges for a competitive energy retailer in Texas.

“The biggest question we asked first was around customer profitability,” Tokerud said, “and trying to understand which of our customers, among our different enrollment processes, were more profitable than others. We bring customers into the organization in different ways, some are more costly, some less costly.

Some have higher, ongoing operational costs. So we wanted to understand who in our customer base is really returning the best profit to us so we could better understand and market to those people.”

An article, “Big Data, Analytics and the Path from Insights to Value,” by Steve LaValle et al., published in the MIT Sloan Management Review (Winter 2011), suggests focusing first on a single major question to apply analytics for early results and, thus, organizational acceptance and change.

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The magic of 2013 For us, 2013 is magic. Most of the contractors go home and we have to keep this thing in operation, so it’s not just the cool new stuff we’re talking about.

We have everything coming in that’s now The silos in the project phase.

For the past year and of the past a half I’ve been walking around with a little don’t work notebook that says 2013 on the front of it that I anymore. keep writing things in.

We have been spending the past year and a half building our organization, doing our total cost of ownership, changing and changing and changing, so we learn. But we’re always trying to keep our focus on what it is going to take in 2013 to operate these things we’re putting in.

The other thing I haven’t talked about, which is part of the change and the interdependency, is that everyone, whether it’s the CIO or the IT department as a whole, is a part of the business. This is really key: be with your friends, and talk to them. The silos of the past, and the lack of personal relationships in the past, don’t work anymore. You no longer need to be defensive or offensive or anything. You need to be there, and talk to each other more, because you’re going to have problems and so are they.

The key is that you have to work together. Technology means nothing without people and process. And we’re all finding that out. In the old days the utility could depend on people, and then they added process to it. Now everything they do requires technology, because they’re married.

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IT INSIGHTS “One of the functions of a good analytics team is the ability to work with the executive team to understand and clarify what exactly is ‘at task,’” Tokerud told me. “More importantly, you need to eliminate a lot of ‘noise’ in order to get insights quickly.

“

Steps to quick insights “The first step is to define what you’re after and what you’re not after,” Tokerud said. “Which groups of customers are most relevant? Which ones do we not want to worry about for now? What’s the correct equation for profitability? Answer those questions first.

“The second step is to assess the current data ‘landscape’ or sources so that I understand what I’m being asked to measure and deliver insights on,” Tokerud continued. “What components of that are readily available now? And what are the tangled messes of information that we may never be able to get an answer on? Then draft a framework that will get you where you need to be quickly, with an acceptable level of error.

“One of the points in that MIT article is to get to a workable solution as fast as possible, instead of getting hung up on defining absolute perfection before you can start reporting anything,” Tokerud said. “You may be missing key pieces of data. You have to make assumptions, fill that information in and keep rolling.

The concept is that you ‘start in the middle.’

There’s an 80/20 rule. You can get most of (Our goal) is to allow the way there. Don’t get hung up on getting 99 percent accuracy for that data set.” the organization to The third step, Tokerud continued, is that once you have preliminary insights, socialmake decisions faster ize that information back to your audience.

Share your findings with your in-house than our competition. client to determine whether you’re headed in the right direction. This helps you, but also more importantly gets directional results back to the leadership team which may influence decisions or change behavior.

The final step is sharpening your findings and putting insights into action so they become a new metric or key performance indicator to manage against. That completes the cycle and enables real-time management of information.

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”

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Centralizing analytics Tokerud said that data analytics are likely to become a centralized function.

A centralized team enables uniformity, puts everyone on the same page and produces the proverbial “single version of the truth.”

“The challenge with a centralized model is that you’re ‘it,’” Tokerud said.

“Suddenly, everyone is coming to you to answer some basic questions about their bailiwick. It’s time consuming. That makes how you approach your task more critical. You need to prioritize, tackle the most valuable questions first.”

Thus, Tokerud has established two prioritization streams: one is a queue of requests from each business unit, which is dealt with on certain days of the week; the second is a separate queue from the executive leadership, addressed on other days of the week.

Analytics, in Tokerud’s view, are heading toward real-time “decisioning.”

“That’s the stuff that companies need,” he said, “because if you can answer stuff on the fly, then you can move in the marketplace faster than your competition.”

Are analytics likely to be handled in-house or outsourced?

“In a lot of ways, First Choice Power follows an outsourcing model,” Tokerud said. “One company runs our call center, another runs our billing system. We’ve contracted with an outside company to develop analytical tools for us.

“But the core competency of analytics should not be outsourced,” he emphasized. “When it’s done right it’s more of a partnership and organizational ability. You want analysts who can talk to the business users, understand their problems and meet them halfway on how data can help answer those questions.”

Defining the limits Finally, as data analytics become the newly revered tool, what are its limits?

“It’s more a question of pitfalls,” he said. “There is a startling number of ways in which analytics can be less effective than it could be.

“Your approach, how you set up things organizationally, is really foundational to the success of your analytics efforts,” he continued. “A common pitfall is to approach it as a reporting exercise, instead of an analytical exercise. If you have it roll up to a functional department that’s misaligned with the objectives of the leadership, that’s another potential problem. If you don’t have the right sponsors or participants, that can be a problem.”

The ideal data analyst would combine roughly equal competencies in business and IT. “We need people who understand both sides and can communicate with leadership,” Tokerud concluded. “How it’s set up and who’s brought in to run it are important decisions.”

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

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O P E R AT I O N A L PERSPECTIVES

Communicating so that the customer cares

Shot of Paul Lau

++SMUD’s assistant general manager talks about sharing success stories

By Paul Lau

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I THINK THERE ARE A COUPLE OF KEY ISSUES. FIRST, BECAUSE

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there’s so much discussion about smart grid, what we don’t want to do is over-promise and then under-deliver to our customers. Because no matter how you look at it, if smart meter is any indication of the first impression that they have of smart grid, some companies have done it very well, but some companies have not. So now that we’re rolling, and your customers have all this information about, “Oh, you have a smart meter now, you have two-way communications,” how is the utility going We asked Paul Lau, to translate that into benefits customers Sacramento Municipal actually care about?

Utility District’s assistant general So that’s one of the biggest challenges. manager, power supply and grid The meters are in; what are you doing operations (formerly assistant about it? And what are you doing that is general manager, customer, actually going to make sense and benefit distribution and technology), who won Intelligent Utility’s 2011 the customer? In the customer’s language, KITE Award as Operations Leader what are you doing to find the plan that of the Year, to discuss what he is going to improve her lifestyle, or help felt was the biggest issue facing him reduce his bill, or is going to be more electric utilities today. Here, in convenient for their lives? part, is what he told us.

How do you communicate that so that the customer cares? Utility customers think about their utilities about six to eight minutes a year: when they pay their bill (unless it’s automatically paid), and when they have an outage. And even then, if you’re lucky, only 15 to 25 percent of the people call you when they have an outage, because they assume the neighbor has, or they assume you already know about it.

Customers don’t know utility realities That’s one thing we found out when we did the smart meter installation. We did 130 community workshops before we even rolled the meters out, and the customer had no idea that we didn’t know. They say, “You’ve got to be kidding! You didn’t know I’m out of power?” I say, “No.” And they pull out their smart phones and say, “I know exactly where I am in the world, I can pick a restaurant, book a table and then get point-to-point directions on how to get there. And you, the utility, actually don’t know if I’m out of power or not?” I say, “I only know if it’s a major outage. But if a fuse blew in your transformer, I wouldn’t know.”

We’re putting intelligence out there now, making the distribution system a lot more intelligent, but it’s still a long way away. The Smart Grid Investment Grant we received is literally only 12 percent of our system. So it’s going to take a while before we can upgrade the rest of the system. And so the key challenge is, how do you communicate to customers the benefit that you have to keep the customer’s interest?

If you can’t, it’s like green-washing something—smart this, smart that— so when you have real programs that benefit them, they’ve already lost interest. One of the big challenges is: how do you stage your program and services, and the data analytics now that you have on the smart meters and your distribution system, and how do you parlay it into a benefit that customers could actually care about?

Even as much as we talk about voltVAR optimization and conservation voltage reduction, and the customer doesn’t have to do a thing and can get between two percent and two-anda-half percent reductions on their bills, most customers say, “Paul, my bill is $80 a month at SMUD. Well, two percent is $1.60. I can’t even buy

a cup of coffee at Starbucks with that.

It’s not going to be really high on my priority list when I’ve got to compete with taking my kids to soccer, piano, worry about college, worry about high school and SATs and PSATs, it doesn’t compete with that.” And so that’s really why I think it’s so important for utilities to be really thoughtful about the customer experience. To me, I think that’s actually a bigger challenge.

“

”

As told to Kate Rowland

++SMUD and others finding value in grid data

By H. Christine Richards AS THE UTILITY ANALYTICS INSTITUTE, A DIVISION OF ENERGY

Central, wraps up its Annual Grid Analytics Report—the action-packed sequel to our first report, Market Outlook and Forecast—we’d like to discuss some of the grid analytics findings from the report.

First, it’s important to understand what we mean when we say grid analytics.

Grid analytics are analytics that enable utilities to ensure better planning, design, construction, operation and maintenance of utility transmission and distribution networks.

We segment grid analytics into two key areas: ??

ASSET OPTIMIZATION Analytics that assist with optimiz-

ing the performance and reliability of grid assets; the focus here is on management of grid assets. This area includes transformer and substation management, as well as overall transmission and distribution asset management. ??

GRID OPTIMIZATION Analytics that assist with opti-

mizing the operation of the grid to minimize power losses and maximize efficiency and quality; the focus here is on management of grid functions. This area includes outage management, system modeling, power quality optimization, advanced distribution management and analytics for real-time applications.

Grid optimiation is the bigger focus Both of these grid analytics segments are critical for the success of more advanced, intelligent grids. However, when we analyzed the primary focus of utilities’ grid analytics initiatives, we learned that grid optimization rules the roost today. According to our research, a whopping 72 percent of utilities made grid optimization the main focus of their grid analytics initiative compared with about 18 percent of utilities that focused on asset optimization. Of the grid optimization efforts, top areas included advanced distribution management, outage management and system modeling.

Does this mean that utilities just aren’t tackling asset optimization? No. Grid analytics initiatives for utility companies typically don’t just cover one area—other areas are certainly a part of the formula. About 30 to 40 percent of utilities are pursuing asset optimization in addition to their primary focus of grid optimization. Grid optimization is at the forefront of utilities’ minds

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Getting usable data into the system Technically now, we have EVs, PVs, time-of-use rates, demand response— how do you actually get the data into the distribution and transmission systems, so people can actually use it?

That’s one of the challenges that we’re tackling right now. There are literally millions of data points that we have to make sense of before we overload our operators. I think our biggest challenge of 2012 is to determine when we have enough intelligence that we can start optimizing the system so it translates into dollar savings or improved reliability for our customers.

It is overwhelming if you don’t really spend the time to think out strategically where do you want to go The meters and how to prioritize those needs. are in; what Because you do have to prioritize, are you doing and you really need to keep an about it? eye out and share the knowledge within the utilities. Specific utilities have different problems they’re trying to tackle, and there truly are unique challenges that each utility faces, when you talk about living the smart grid vision. But there are also a lot of similarities. I think that it’s finding the right balance. We can really learn from each other, and say to ourselves, “How does this apply to my utility?”

Analyzing grid analytics

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O P E R AT I O N A L PERSPECTIVES

as they move forward with the smart grid, but how do utilities find a balance between the excitement of grid optimization and smart grid, and the necessity of asset optimization?

Utilities in action Sacramento Municipal Utility District (SMUD) offers a great example of a utility that effectively blends smart grid, grid optimization and asset optimization.

SMUD is including grid analytics as part of a significant investment in digitizing and automating their grid. SMUD may not be focused directly on asset management with their smart grid efforts, but the data and analytics they’re using for grid optimization and automation ultimately helps with asset management.

SMUD is working on several initiatives as part of their smart grid program.

Some of those initiatives include: ??

Bolting an advanced operating system onto their existing energy management system.

??

Retrofitting another 40 of the company’s distribution substation transformers with SCADA—they already have 120 with SCADA—

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meaning roughly 70 percent of their distribution substation

40

transformers will have SCADA capabilities. ??

Automating 109 feeders, which equals about 19 percent of their service territory.

??

Doing Volt/VAR optimization and conservation voltage reduction.

SMUD is laying the foundation for better analytics capabilities through their automation and smart grid investments, but how are they actually using analytics?

Lora Anguay, senior project manager, distribution automation, provided some great examples around grid optimization. She noted, “If we have a fault, the data coming back is telling us whether we can tie circuits together, and whether a circuit can take the additional load because we’ve had a fault on another circuit. For the circuit that doesn’t have the fault, we don’t want to create a bigger outage because it couldn’t pick up additional load. So we’re looking at that before we switch the reclosers.”

Those decisions are happening in less than a minute, so SMUD’s goal is to have the

information coming back every three to five seconds on the reclosers.

Another grid optimization area SMUD is focusing on is conservation voltage reduction by reducing substation voltages. “We’re using the smart meter data and the line devices that we’re installing to bring back the voltages on the lines,” Anguay explained.

“The meter has the capability of giving us the instantaneous voltage so when we’re backing off the voltage of the substation, we can see whether or not we’re within the required voltage constraints on the customer end. By doing that, it allows us to be more efficient.”

SMUD has a voltage range that they can deliver power within and before smart meters, there was really no way to validate that at the customer level.

“We could do the math and figure it out, but there was no real validation unless we put some sensing devices at the end of the lines,” said Anguay.

Even with the focus on automation, SMUD is finding ways to support its asset optimization as well. “Within distribution operations, it does spill over to our asset management operations,” explained Anguay. “For example, with collecting the smart meter voltage data, we’re able to identify areas that have voltage issues on the system. So we’re able to take that voltage information and pass it along and say ‘here’s where we’re having some voltage issues and here’s where we need to concentrate our efforts.’”

SMUD is just one example of how grid analytics is rapidly changing how utilities run their distribution businesses. With the grid analytics market projected to grow to $2 billion in North America by 2016, we expect to see more success stories like this in the coming months and years. If you’re interested in learning more, please check out www.utilityanalytics.com.

H. Christine Richards is a senior analyst with the Utility Analytics Institute, a division of Energy Central. She can be reached at crichards@energycentral.com.

CUSTOMER SERVICE

Demand side management pilot scores points ++Colorado Springs Utilities balances overloaded circuit with customers’ help UTILITIES HAVE A COMPELLING STORY TO TELL ABOUT THEIR

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efforts in grid modernization, but that story has to reach their customers and ring true. In a February Intelligent Utility Realities webcast on utility best practices in customer engagement, Angie Thoma, Colorado Springs Utilities’ smart grid project manager, discussed her utility’s Appaloosa Pilot Program, a capital deferrment project that relied heavily on consumer support.

Colorado Springs Utilities is a public, four-service utility company covering about 491 square miles, which includes almost 213,000 electric accounts, 189,000 gas accounts, and 135,000 water accounts. (The utility also services wastewater, which is not a metered service.)

Here, edited for length, are excerpts from her comments.

We automated all of our meters over the course of a five-year time period, which was completed in 2010. Our electric system provides retail services for the cities of Colorado Springs and Manitou Springs, and we also deliver a special contract power to four local military installations in the area.

We currently have system capacity to meet our projected customer demand until 2028, given we achieve some of our DSM (demand side management) goals. So, given our current capacity, our real opportunity to divert capital investment was at the distribution level. We have areas of town where the distribution system is close to its feeding design guide limits, therefore our pilot project focused specifically on one curcuit that was overloading during the peak month of the year. We call it the Appaloosa Project.

41

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CUSTOMER SERVICE that 57 percent were willing to shift Achieving cost avoidance usage and over 65 percent were As a municipality, we wanted to take the smart grid initiative at a slow and steady pace so that we’re not putting our ratepayers at risk of incurring unnecessary costs. willing to shift for a savings of $20 to $40 per month. So, using this So the goal of the capital deferrment project was to achieve cost avoidance information, we modelled different through the deferrment of capital investment by identifying highly loaded types of pilot rate options. circuits, in which customer peak load could be shifted to nonpeak times.

We asked customers how So the Appaloosa Project leveraged AMI techmuch they would need to nology, demand side management tools and pilot Our real opportunity save in a load-cycling prorate options, partnered with customer behavior, gram in which they could as an additional low cost to defer these capital to divert capital not opt out of utility-called investments of the electric system. events. We found that Our hope was to not only learn more about investment was at 87 percent of the customers customer behavior, but also to reduce the peak on the circuit did, in fact, demand by spending less on customer options the distribution level. have central air conditionthan it would cost us to upgrade our distribution ing, 43 percent with the system. We looked at the net present value of the capital upgrade as our starting point of the amount we could spend on the effort central air would participate in an incentive-based load cycling program, to achieve the required demand reduction. In this case, it was $105,000. and over 47 percent would participate Analyzing customer-circuit demographics for $25 per month. So we chose the Once we knew how much capital we could defer, we started analyzing the $25 price point for our pilot. customer demographics of the circuit. The Appaloosa Circuit is 98 percent Our load cycling program is called residential and less than 2 percent small and medium commercial.

Energy Cooling Optimization. We We knew our opportunity was primarily with the residential market. However, implemented a variation of our northere was almost 10 percent of the circuit loading that was contributed to the mal program, in which the customers commercial sector, as well. could not override curtailment events.

So, using market studies, we determined that the best potential candidates for In return, we paid customers $25 per the DSM and rate options would be our residential consumers who had central month for June, July and August. air conditioning that could be cycled off during peak times. We identified and The second pilot we implemented surveyed customers who used over 800 kWh during the hot summer months. was a Circuit Time of Day rate. The circuit peak is from 5:30 p.m. to Customer surveys provided valuable information 7:30 p.m. every day of the week, We conducted a pre-project survey for residential customers in early 2010. When Monday through Sunday. The peak we asked customers how much they would need to save each month in order months are June, July and August. And to participate in a time-of-day rate option, the response was varied. We learned this particular circuit also had a winter peak in December and January. In return for participating in this pilot rate, we offered to give customers a reduced rate for all circuit off-peak hours, and (offered) to e-mail their 15-minute interval usage graphs so that they could monitor their consumption.

Because of the circuit peak in the winter as well, we figued lighting was a key contributor, so we also offered a CFL exchange program, which was marketed to elementary schools and a community center that resided on the circuit.

“

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”

44

For Colorado Springs Utility’s first-year pilot results, and to hear the rest of the webcast, go to http://bit.ly/zaUFHF

more energy control/management, reduced environmental impact, and saving money.

These benefits can be woven together to successfully increase customer support, SGCC’s research says. ??

SIMPLE AND CLEAR MESSAGES SPUR SMART GRID PROGRAM ENROLLMENT.

Elements of successful smart grid and smart meter messages that increase smart grid program enrollment include a simple promise to resolve a consumer’s unmet need or desire, and product features/ attributes that give credibility to the promise. ??

FREE AND TIMELY USAGE DATA CREATES INTEREST IN SMART GRID PROGRAMS. Interest in partici-

pating in smart grid programs

The state of the electricity consumer

is higher when consumers are given timely access to their energy usage data using channel(s) easy for engagement. As well, SGCC says, direct and continuous feed-

++SGCC identifies seven key themes to address

back has been shown to be

By Kate Rowland

more successful in triggering behavioral changes in energy

OVER THE COURSE OF 2011, THE SMART GRID CONSUMER

Collaborative (SGCC) conducted three foundational pieces of consumer research, intended to provide a better perspective on the U.S. residential electricity consumer.

Within this research, featured in the SGCC’s latest report, 2012 State of the Consumer, seven key themes came to the fore. A few were somewhat surprising, given what we have been hearing in the popular media of late.

Here’s what the SGCC’s research determined: ??

CONSUMERS NEED SMART GRID AND SMART METER EDUCATION. The SGCC

notes that overall consumer awareness and knowledge of smart grid remains low in 2011. Best practices reveal that customer education strategy, leveraging internal education and community outreach to promote awareness and acceptance. ??

??

AWARENESS AND KNOWLEDGE FAVOR SUPPORT FOR SMART GRID IMPLEMENTATION.

ers’ reason-to-believe in the benefit(s) of the smart grid/ smart meter program. ??

SEGMENTATION IS THE KEY TO MESSAGE OPTIMIZATION AND EFFICIENT ENGAGEMENT. A

one-size-fits-all approach to marketing and communication strategies may not be as successful in strengthening demand for smart grid and smart meter technology as targeted approaches that take into account dimensions like

Knowledge about what smart grid is and how it would work leads to

consumer attitudes, values,

greater favorability and support for smart grid.

behaviors, motivations,

MANY SMART GRID AND SMART METER BENEFITS RESONATE WITH CUSTOMERS.

technology adoption and

Utilities have promoted a wide array of smart grid benefits, including

communication preferences.

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should start before AMI deployment using a staged messaging

usage by reinforcing consum-

45

CUSTOMER SERVICE ??

THE JOURNEY FROM AWARENESS TO ADOPTION REQUIRES TRANSFORMATION OF THE CORE SERVICE MODEL.

Tasked with acting more like marketing and sales organizations as they launch smart grid programs, utilities will have to transform their service model from one that focuses primarily on the reliable delivery of electricity to one that also focuses on customer needs and engagement.

That last point is likely going to be the most difficult for some utilities, as the need for a changing core service model comes as the utility workforce is changing, too—somewhat like a perfect storm that can provide either great challenges or great opportunities.

But there are those who are already moving to leverage existing touch points with their customers, the report notes. Among them: ??

AUSTIN ENERGY promotes a

direct load control program through its call center. The program has 22 percent participation. ??

ARIZONA PUBLIC SERVICE AND SALT RIVER PROJECT use cus-

tomer call-ins as opportunities for program enrollment, and this has helped the utilities to achieve leading program par-

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ticipation rates of 50 percent

46

and 22 percent, respectively. ??

SOUTHERN CALIFORNIA EDISON

uses an incentive to increase program enrollment, by donating $5 to schools when parents participate in the utility’s Home Energy Efficiency Survey.

“As customers gain awareness with smart meters and their familiarity with the benefits grow,” the report says, “utilities can use new channels to drive enrollments, such as comparative energy reports, internal and/or third party referrals.”

Meeting customer needs and expectations ++CenterPoint’s VP of customer service talks about demonstrating value

By Greg Knight THE GREATEST CHALLENGE I FORESEE FOR 2012 IS THE

continued focus on the utility around the customer and the engagements, whether that is the smart grid and how will it demonstrate the value and the benefits of the grid for consumer engagement, or whether that be customers’ expectations and how they are increasing based on At Knowledge2011, late last how they interact with other providers of services. year, we asked Greg Knight, I see that as the greatest challenge in terms of CenterPoint Energy’s division vice us being able to really triangulate that around the president of customer service, good business strategy that really meets their needs and the winner of Intelligent Utility’s 2011 KITE Award as and their expectations.

Customer Service Leader of the That is why this conference [Knowledge] is so Year, to discuss what he felt was appropriate—where we’re bringing IT, operations the biggest issue facing electric and customer service leaders together—because utilities today. Here, in a nutshell, each one plays a role in terms of fulfilling that comis what he said. (Look to the May/ mitment to our customers.

June issue of the magazine for a CenterPoint Energy will be the utility host for Knowledge2012.

longer discussion with Knight.)

OUT THE DOOR

Speed, satisfaction and safety ++SMECO’s callout strategy

By A.C. “Bo” Sonntag IF A TRANSFORMER BLOWS OR AN AUTO ACCIDENT BRINGS

Looking for a better way By 2005, we began looking for ways to simplify and speed up the callout process. As a first step, we brought together our foremen, regional managers and union personnel to iron out the details of what we wanted. Everyone agreed that they should choose an automated

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down a pole, a callout is what gets crews to the scene of the outage.

But my colleagues at Southern Maryland Electric Cooperative (SMECO) haven’t picked up their phones to launch a callout in five years. That hasn’t damaged our relationship with our customer-members. And it hasn’t hurt SMECO’s power restoration work, either. That’s because we make after-hours emergency calls with software.

Founded in 1937 as the Southern Maryland Tri-County Cooperative Association, SMECO today is one of the 10 largest electric co-ops in the nation. SMECO provides electric service to approximately 150,000 customers in a 1,250-square-mile area, just 25 miles southeast of Washington, D.C. The co-op serves the southern portion of Prince George’s County, all of Charles and St. Mary’s counties, and all but the northern tip of Calvert County.

The shift in the way SMECO handles callouts came in 2004, after we centralized our operations department to better serve customer-members across Calvert, Charles, Prince George’s and St. Mary’s counties. As part of streamlining operations, SMECO combined three operating regions that were conducting callouts separately.

Consolidation sheds light on callout The consolidation led us to create distribution system operators (DSOs) who would handle callouts for our entire service area as part of one group. Once we brought our operations department and transmission system operations teams together, we discovered just how time-consuming making callouts could be. On one occasion a callout to find seven available workers for restoration took more than one hour.

We learned that callouts were complicated. SMECO doesn’t rely on seniority to pick first responders or line crews when emergencies strike.

Instead, we employ a call rotation.

Service crews are paired, so a serviceman and helper work as a team, which SMECO calls out as a team. If one of the team’s members can’t accept a callout, a time-strapped DSO would have to carefully scan a complex roster and set of rules to find the person entitled to get the next call. Mistakes were made. And that led to grievances.

In fact, SMECO supervisors were spending a lot of time researching complaints about bad callouts, which had become a weekly occurrence.

Management, line personnel, and, of course, customer-members had no idea how complicated or timeconsuming the callout process was.

The DSOs spent so much time making calls that they couldn’t accomplish much else until a callout was filled.

Ultimately, the callout process was costing SMECO and the businesses we serve because the power wasn’t being restored as fast as it could be.

47

OUT THE DOOR system that would conform to the existing callout process. Some doubted whether any technology could mimic SMECO’s sometimes complex requirements.

In 2006, SMECO installed an Internet-based automated callout and resource management system. The software uses a set of algorithms to call crews in the order that our work agreements dictate. Because the system applies logic to the way it places calls, the automated callouts mirror SMECO’s work agreements.

Integrated approach takes shape After implementing the system, SMECO integrated the callout software with a mobile computer-aided dispatch system. The mobile dispatch system is what DSOs now use to assign crews to a job. If the dispatch system shows that a crew isn’t available, then the DSOs launch a callout.

The automated callout system stores information on the makeup and skills of SMECO’s service crews and crew availability, along with data on more than 150 other employees who may need to be called in a crisis situation.

Every morning, the callout system and mobile dispatch system communicate and upload available crews for DSOs and supervisors to see. The integration enables SMECO to generate a deployment plan for the day. We have made the automated callout system our system of record because the software tracks which crew members are available in real-time. If a crew is unavailable, then the automated callout software will not send the crew’s details to the mobile dispatch system.

When an after-hours emergency occurs, DSOs tap the callout system and the software launches phone calls to all available crews needed. The system reports on each crew member’s status from acceptance to completion of work.

Improving satisfaction, speed, safety Since we automated our callout and mobile dispatch systems, assembling the utility’s 16 service crews and 26 line crews for an after-hours emergency takes minutes.

Before implementing these systems, SMECO’s callout records show that a manual callout of seven men could take more than an hour to fill. Since putting the systems in place, there have been numerous callouts of this size, and these callouts take only 20 minutes on average. In one case, the automated callout took only 24 minutes to fill a 14-person crew requirement.

From 2008 to 2011, we received four J.D. Power and Associates customer satisfaction awards. We believe the new callout system played a part in winning those awards. The technology serves a strategic purpose because it trims restoration time. The system has also freed our DSOs to concentrate on managing their crews and outages.

DSOs can now put more time into a game plan for power restoration. They have more time to collect intelligence at the scene of an outage and pass that on to the crew. That, of course, contributes to safety. For example, the new callout system includes a notification module.

SMECO’s DSOs will launch a call to crews via this module if they see personnel coming into close proximity with one another as they restore lines.

Co-ops, like SMECO, often lack the number of people and resources that investor-owned utilities claim.

But automating business processes, like callouts, can make a co-op more efficient and give it a way to do more with less.

A.C. “Bo” Sonntag is distribution operations supervisor for Southern Maryland Electric Cooperative. He has been a SMECO employee for 32 years.

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