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VOL 4, ISSUE 4 » JULY/AUGUST 2012

Where smart grid meets business—and reality.

IT’S COMING!

UTILITY ANALYTICS WEEK See page 40

DR 2.0 Pushing to the forefront

LEVERAGING METER DATA KCP&L shares lessons learned

ENERGY EFFICIENCY Integrating the utility

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CONTENTS S PECIAL REPORT DA + MORE

28 Intelligent and reliable

Distribution automation continues to make advances

DEPARTMENTS

4 6

14 

In this issue, the theme of looking to the future of demand-

20

data for more efficient grid operations.

FEATURES // JULY/AUGUST 2012

Energy efficiency

14 Making energy efficiency a community effort Two public utilities share their stories

18 Success stories and lessons learned Three utilities share EE and DR best practices Demand response 2.0 W WW.INTELLIGENTUTILIT Y.COM /// JULY/AUGUST 2012

20 DR playing a larger role

2

Increased renewables and regulations force DR to forefront

Leveraging meter data for grid operations

24 Drilling deep for greater achievements Meter data plays larger role

CUSTOMER SERVICE ROUNDTABLE

28 40 47

Experiences explored at AGA/EEI conference

6

54 AN E N E RGY C E NTR AL PU B LIC ATION

Letters from readers

8 Around the globe 10 Top 12

10 Top 12 large investor-owned utility movers and shakers

40 IT insights

40 Analytics business infrastructure

Keys to taking your analytics to the next level

44 The challenge and promise of unstructured data Utilities navigating a more complex world of data

47 Operational perspectives 47 What’s happening on the grid?

O&R Utilities takes ‘model-centric’ approach to reliability, efficiency

49 Big advantage, not big brother

Nashville Electric’s field crews see advantages to AVL

52 Customer focus

52 Making it real for utility consumers

CenterPoint’s VP of customer service discusses the challenges around customer engagement

54 Consumers getting more savvy

CONTINUING THE CONVERSATION

36 Consumer expectations are changing

Transmissions

side management permeates our feature stories, from energy efficiency to demand response to leveraging meter

Drawing the line

New SGCC report indicates support for positive messaging

55 Out the door

55 Transforming the customer relationship

What electric utilities must do to survive the 21st century

Vol. 4, No. 4, 2012 by Energy Central. All rights reserved. Permission to reprint or quote excerpts granted by written request only. Intelligent Utility® is published bimonthly by Energy Central, 2821 S. Parker Road, Suite 1105, Aurora, CO 80014. Subscriptions are available by request. POSTMASTER: Send address changes to Intelligent Utility, 2821 S. Parker Road, Suite 1105, Aurora, CO 80014. Customer service: 303.782.5510. For change of address include old address as well as new address with both ZIP codes. Allow four to six weeks for change of address to become effective. Please include current mailing label when writing about your subscription.


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

Learning all the Es

W WW.INTELLIGENTUTILIT Y.COM /// JULY/AUGUST 2012

IT SEEMS AS THOUGH I HAVE BEEN ON THE ROAD AT CONFERENCES—TALKING,

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listening, and gathering hundreds of pages of notes—for about half of the time we have been preparing stories for this issue. Don’t misunderstand: this is not a complaint. In fact, if anything, I wish I could attend even more conferences than I am able to. Conferences are the communications lifeblood of this industry, offering the time to share ideas and best practices, success stories and lessons learned, and the chance to connect the dots, utility-to-utility, both from the perspectives of the C-suite executives and those doing the technology deployment work. The general focus of this issue—customer service, energy efficiency, demand response and more—was particularly highlighted in three conferences I attended in the past few months: the AGA/EEI customer service conference, CS Week and the APPA national conference. Certainly no one can say, in 2012, that electric utilities aren’t focused on their customers! From consumer-facing mobile applications designed specifically for the new 24/7, always-on consumer to energy efficiency programs fine-tuned to best meet the needs of specific groups of consumers, no longer can the electric utility be accused of what Blue Space Consulting’s Roy Barnes described at the AGA/EEI conference as “the problem of strategic arrogance.” Barnes explained that strategic arrogance comes from myopic product focus. The electric utility of the past focused specifically on the production and delivery of reliable power, as that was their clear mandate. “We have efficiency and effectiveness,” he added. “Now we need another E: experience. Focusing on some of the elemental points of the business isn’t good enough if you lose sight of the customer.” It’s a good reminder, but from what I have seen reflected recently in conference presentations and roundtable discussions, our industry has begun to effectively engage in a more and more positive two-way conversation with its consumers, and the mutual benefits are growing exponentially as a result. Our Top 12 series has taken on a life of its own, and for the first time since we launched it early this year, has elicited independent nominations. I encourage you to keep them coming: in the next three issues of the magazine, we will be looking for nominations for unsung heroes in the areas of IT, operations and customer service within small co-ops, small public, and small investor-owned utilities. Let us know who you think deserves the nod! As is always the case, there simply isn’t enough room in one magazine issue to share all the sue? Then Enjoy the is for free at stories I have collected. With this issue, I chose to “hog the floor” a bit, in order to cover some subscribe .com/ igentutility of the new things I have heard these past few months. I hope you enjoy them. www.intell subscribe

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


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TRANSMISSIONS

Letters from readers to Obamacare without believing the “death panel” nonsense. There is a risk I just read your editorial and it that we underestimate and trivialize made me uneasy to hear you dismiss the opposition as merely the job of security concerns about smart grid educating the ignorant. initiatives as “absurd.” I do not believe I think you’ve nailed the source of the problem with there is a government or your simple line: “On industry conspiracy to the customer side, yes, control citizens through utilities have been slow these electric grid to follow meter swapautomation projects. outs with clear value But I do agree with the silos vs for the customer, but premise that the resultFlat Plain regulators are keeping ing “smart grid” will up the pressure for have new vulnerabilities them to do so.” that we must take very As an industry, isn’t seriously and guard that all we need to do, against. My biggest fear explain the value to the consumer? In in this regard is a wide-scale outage— my opinion, a strategy of rebutting think citywide or utilitywide—caused these dubious appeals to conspiracy by a hacked network that requires theories and radio waves will mean utility personnel to visit every meter we’ve lost the war before we’ve fought or router to restore service. I suggest the first battle. And we might win each the appropriate response to the battle on our way to a strategic defeat. documentary is to describe industry’s Do the believers in the “radiation efforts to standardize security protoproblem” ignore concerns from cols to prevent breaches and establish the (more believable) risk from cell firewalls to limit widespread failures. phones? Do these same people dose Carl Livingood themselves regularly with radiation President, GeoSpatial Innovations, Inc. from air travel? If they do, is it because they see value in these activities, and Crossroads 2012: they judge the trade-offs? meters and the future Intelligent Utility Daily, June 11 So, I might recommend we ignore Important topic and excellent example a rebuttal, and get on with the positive of an opposition comment that is message. How will smart meters lower in the range of “death panels” to the my electricity bill? Presuming that’s fore. Perhaps my only concern would a tough lift, can we at least make the be the worry that we consider most/ harder-to-sell hypothetical case: “If it weren’t for smart meters your bill all opposition to smart meters in this league—I think one could be opposed now would have been x, and instead it’s 0.90x?” Regulators are needed to keep up the pressure on utilities to To contribute to the explain the value message? Good grief. Transmissions department, please e-mail your submission to I could get my own self opposed to intelligentutility.editor@energycentral. smart meters, if this is the state of the com. Provide your name, address and industry’s sense of responsibility in its daytime phone number. Letters may be own messaging. edited for style and space. This is not a test! May/June 2012

coverFINAL.pdf

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5/4/12

9:00 AM

VOl 4, Issue 3 » May/June 2012

Where smart grid meets business—and reality.

enTeRPRIse InFORMaTIOn InTeGRaTIOn utilities’ journeys differ

OMs+GIs+MWFM=?

sTanDaRDs + InTeGRaTIOn Ieee weighs in

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 COPY EDITORS: Martha Collins, J. Ian Tennant ACCOUNT EXECUTIVES

C

M

Y

CM

Ken Maness, Todd Hagen, Eric Swanson, Jana Koehn

MY

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CMY

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

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AROUND THE GLOBE BRAZIL

EUROPEAN UNION ISLANDS

Renewable energy increases

Proposal for sustainable energy future

Renewable energy sources accounted for 88.8 percent of the electricity generated in Brazil (domestic energy supply) in 2011, much higher than the global average of 19.5 percent, according to the 2012 National Energy Survey conducted by the Brazilian Energy Research Corporation. (The report included hydroelectric power under the renewable umbrella.) Brazil showed a 6.3 percent increase in hydroelectric energy output and a reduction in bioelectricity made from sugar cane biomass, while wind energy rose 24.2 percent against 2010, to 2,700 gigawatt hours. The International Energy Agency also reported that the participation of renewable energy sources in Brazil’s overall energy mix (includW WW.INTELLIGENTUTILIT Y.COM /// JULY/AUGUST 2012

ing imported energy) reached

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44.1 percent in 2011, against the global average of 13.3 percent.

Some 2 percent of the European population, or 10 million people, live on islands with energy supplies quite different from the rest of the European Union (EU) population. The Union of the Electricity Industry—EURELECTRIC, a sector association representing the common interests of the electricity industry at a panEuropean level, recently released a report, “EU Islands: Towards a Sustainable Energy Future,” analyzing power generation in the EU Islands and providing insights into the status quo of power supply and demand, the regulatory framework and best practices, and presenting solutions that move toward sustainability for the islands. “Europe’s islands are facing considerable challenges in meeting their energy needs in a sustainable, affordable and reliable way,” the report said. “Island energy systems, despite their diversity, share common characteristics and are subject to common challenges. Their sustainable energy future

depends on an improved investment climate and policy framework.” Five main challenges were identified: market failure (islands lack economies of scale in financing and power production); inconsistent regulation (islands too often suffer from ‘copypaste’ reasons, whereby solutions from the mainland are applied to a different reality); security of supply (due to their isolation, islands have to take extra measures to ensure system stability and security of supply); emissions (islands depend upon diesel engine generation, so compliance with forthcoming emission requirements will be difficult); and import dependency (rendering islands vulnerable to oil price volatility). The report includes recommendations to national and European policymakers to incentivize the transition toward a sustainable energy future, including using islands as a priority test bed for innovative technologies such as storage, smart grids and renewable energy, and fostering R&D on the islands. Using interconnection where possible is also encouraged.

AUSTRALIA

Energy savings trials set Through its Energy Efficiency Opportunities (EEO) program, the Australian government will be conducting trials over the next 12 months of energy networks and large greenfield sites to determine the potential energy savings available to them. In 2011, participants in the program reported current or future energy savings totalling 1.5 percent of Australia’s total energy use.


Future. Ready.

SM

System reliability Distributed generation Data analytics Grid automation Interoperability Consumer engagement Peak load management

Where is

smart grid

heading?

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TOP 12

TOP 12 utility champions ++In the large investor-owned electric utilities of North America

Central Maine Power’s AMI program director, LANEY BROWN, is responsible for leading the smart meter project for CMP’s customer base of 625,000. CMP’s AMI deployment overcame complex challenges including adapting to a challenging geographic service area, designing a flexible communication network and delivering on a bold roll-out timeline. The key to CMP’s award-winning execution came from developing rigorous implementation plans early on, and partnering with innovative companies to deploy adaptable technology.

Back in 2010, when PPL Electric Utilities launched its smart grid project in Pennsylvania, MICHAEL GODOROV, now PPL’s senior project manager, was project lead and manager of compliance for the project, and was instrumental in establishing the utility’s smart meter plan, as well as leading advanced metering and data management operations. Godorov has held a number of leadership positions at PPL, including construction, marketing, distribution, power delivery and customer services.

MARK BROWNING, vice president of IT at ComEd/Exelon, has championed

BECKY HARRISON, Progress

By Kate Rowland IT’S TIME, WITH THIS ISSUE, FOR THE LARGE INVESTOR-OWNED

electric utilities across North America to take their bows. We had a little bit of help this time around in picking some of those to highlight in our Top 12 for 2012, thanks to a raft of independent nominations.

W WW.INTELLIGENTUTILIT Y.COM /// JULY/AUGUST 2012

the emergence of the intelligent utility for many years, both in his work at the utility and his focus on supporting industrywide education and a sharing of knowledge from utility to utility. A natural leader who is industry vision-focused, Browning is an Intelligent Utility favorite for his candor and his willingness to share his knowledge at industry events, as well as in webinars and magazine articles.

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NSTAR’s LAWRENCE (LARRY) GELBIEN is director of the utility’s smart grid program. He is responsible for electric system planning, transmission, substation and electric distribution design, and is also (in his spare time) evaluating electric battery storage technology, and holds three patents in distribution automation. Gelbien’s nominator told us: “I feel he is a leader in the field of self-healing grids, and he had the opportunity to prove the benefit of his vision during last year’s hurricane that hit New England. His power restoration metrics during the storm were impressive.”

Pacific Gas & Electric’s KEVIN DASSO, senior director of smart grid and technology integration, is responsible for developing strategy and policies for PG&E related to smart grid and T&D technology information. He leads the utility’s team involving T&D, customer care, energy procurement and information systems and technology service departments, meaning his responsibilities also include PG&E’s current and future distribution grid enhancement projects and distribution integration automation pilots. ERWIN FURUKAWA is senior vice president of customer service for Southern California Edison, and is responsible for leading SCE’s demand-side management programs, customer products and services, customer engagement and call center operations, field services, account management, customer satisfaction, and advanced metering. Furukawa also provides strategic leadership for the marketing and management of one of nation’s leading energy efficiency programs.

Energy’s director of smart grid technology and research, was responsible for establishing Progress Energy’s smart grid program for both its California and Florida service territories. Harrison has more than two decades’ experience in the industry in distribution and information technology. She is also active within the broader industry’s smart grid work, serving as finance chair on the Smart Grid Consumer Collaborative’s and GridWise Alliance’s boards of directors. GREGORY KNIGHT, CenterPoint Energy’s division vice president of customer service, is responsible for the management of the utility’s electric and natural gas call centers, customer


service training and quality assurance, as well as gas credit and collections. His group manages the needs of more than 5 million electric and natural gas customers throughout six states. His refreshing approach to the needs of—and understanding of—the “new consumer” catapulted him to the top of the 2011 Knowledge awards in customer service, and to a place on this issue’s Top 12 large IOU utility champions.

Pacific Gas and Electric’s VAHID MADANI is the technology lead for advanced wide-area warning systems and system integrity protection schemes (SIPS), and is also responsible for protection and control standards and modernization at PG&E. A registered electrical engineer with nearly 30 years of academic and utility assistance, his latest assignment is deploying large-scale interconnected advanced warning systems, integrating synchrophasor technology into PG&E’s energy management system, and developing synchrophasor-based adaptive protection and interconnected SIPS. Hydro One’s vice president of asset management, RICK STEVENS, developed the overall business strategy and business case for the deploying Hydro One’s smart meter program, and also led Hydro One’s smart meter/smart grid initiative, which involved the rollout of 1.2 million meters. In March 2012, the utility moved to assess the next generation of distribution equipment to replace its aged components, test new delivery models for electricity and validate the costs and benefits associated with its upgrading. American Electric Power’s TOM WEAVER, manager for distribution system planning, is a 34-year AEP veteran. He has covered everything from T&D engineering, metering and communications to customer service, line supervision and distribution planning.. He has been actively involved in developing and applying deployment plans for gridSMART technologies on the AEP distribution system since 2005. He is also active with EPRI as the utility chair of the distribution programs and is chair of EEI’s planning, design and asset optimization working group.

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

No IOU Top 12 list would be complete without the addition of LEE KREVAT, director of smart grid at Sempra Energy (and its subsidiary, SDG&E). His IT direction at the utility dates back to 2004, and he has been front and center in San Diego Gas & Electric’s smart meter rollout, advanced distribution grid management, outage management, microgrid, energy storage, electric (plug-in) vehicle charging projects, leading the multi-department team responsible for the implementations. Krevat is

also an unabashed cheerleader for the benefits of new technology deployments within the electric utility industry.

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ENERGY EFFICIENCY Making energy efficiency a community effort ++Two public utilities share their stories By Kate Rowland THERE’S AN OLD ADAGE THAT SAYS THAT

there’s no sense reinventing the wheel. However, in the case of energy efficiency (EE), new technology and new thought along the years have continually increased the opportunities for utility energy efficiency programs to make their mark. Take, for example, tiny Sauk Centre Public Utilities Commission in central Minnesota, which introduced EE programs as early as the late 1980s.

Little Sauk Centre makes big gains In the past decade, even more savings have been effected by energy efficiency. The city built a new city hall, a new fire hall, and new water and wastewater treatment plants, all as energy efficient as possible. And even more customers have joined in. Industrial customers have replaced their 400-watt metal halide fixtures with T8 high bays, and the city schools have changed all fixtures to T8s and added pop machine computer devices that will adjust the temperature upward when they are not being used, Sunderman said. “Our utility also has an annual recycling event, and exchanges old appliances for cash incentives [to purchase new ones],” he added. In order to ensure proper recycling of CFL bulbs, Sauk Centre PUC has initiated a CFL recycling program for its customers with a very simple and effective message: “Looking to recycle your old CFLs? Bring in an old, unbroken CFL and we will replace it with a new CFL at no cost to you! Limited wattages available. Limit of four bulbs per month.” Finally, one of its most interesting solutions, managed and administered by Missouri River Energy Services as the joint action agency, is Bright Energy Solutions (BES). Briefly, the

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

ILLUSTRATIONS BY MELISSA DEHNER

Starting small Sauk Centre, the birthplace of Sinclair Lewis, the first American to be awarded the Nobel Prize in Literature, has a population of 4,317. The utility itself has 2,400 electricity/water/wastewater customers, and 70 percent of its load is commercial. The city’s motto, “A view of the past—vision of the future,” is particularly apt when it comes to energy efficiency measures and sustainability. Back in the late 1980s, according to Marty Sunderman, the general manager of Sauk Centre PUC, the public utility installed load management receivers on 300 air conditioning and water heaters, with no monthly incentives to partici-

pating customers. “They understood that the money saved would go back to benefit the entire community in keeping rates low,” Sunderman said. A second program initiated in the same time period was commercial stored in-floor heat. “Twenty-five percent of our load was off-peak,” Sunderman explained, so the program was activated between 10 p.m. and 5 a.m., at a rate of 2.95 cents. Fast forward to the 1990s, as Sauk Centre began to explore additional energy efficiency options. “We upgraded our distribution voltage from 4160 to 7200 for less line loss,” he said, resulting in an improvement of 2.5 percent to 3 percent. As well, the city developed a capacitor program with its industrial customers, with the new equipment being financed by the savings the customers were gaining by using it.

15


ENERGY EFFICIENCY

program offers cash incentives and information to help residential and business customers save energy. Sunderman said Sauk Centre’s BES savings of 1,117,715 kWh achieved during 2011 far exceeded the goal of 958,630 kWh, with $59,318 in incentives paid out to customers.

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Making history with an ambitious goal Farther west, larger public utility Seattle City Light holds the record for the longest continually operated energy conservation program in the country, which has been running since 1977. Since that time, it has delivered 1.5 billion kWh total savings, and more than $500 million in unreimbursed ratepayer total investment. Seattle City Light (SCL) serves Seattle, Washington, and seven suburban cities. It is the 10th-largest public electric utility in the U.S., and delivers power to nearly one million Seattle-area residents, as well as commercial and industrial (C&I) accounts. It holds the distinction of being greenhouse gas neutral since 2005, the first electric utility in the nation to achieve it. “Energy efficiency is least cost, least risk, least environmental impact,” said Glenn Atwood, SCL’s conservation director. “Energy efficiency is Seattle City Light’s first-priority energy resource.” In fact, he added, it has doubled its EE targets and budgets since 2007.

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SCL focuses on reducing customer bills “In terms of least cost, you might want to think of it as greatest net benefit,” Atwood said. “Our focus historically has been on reducing customer bills rather than focusing on rates—not that we’re indifferent to rates.” Also, he added, “If you have local transmission or distribution bottlenecks, you can use energy efficiency to defer upgrading.” Ninety-five percent of SCL’s generation is hydro. “We have no need to acquire new generation to meet load. We’re all about the kilowatt-hours,” Atwood explained. That, and Initiative 937, passed in Washington state in 2006, with the intent of requiring large utilities to use renewable energy (defined as solar, wind, geothermal, ocean energy and some forms of biomass energy) when new sources of generation are needed. (Interestingly enough, hydroelectric power is not defined as renewable energy under the I-937 mandate.) “Least environmental impact” has been a particularly compelling argument for energy efficiency in Seattle. “It is generally agreed that conservation has the least impact on the environment,” Atwood said.

Seattle City Light is mindful of this “to the extent that our customers and community want to highlight the least environmental impact aspect and highlight those values,” he said, and there is the additional benefit of helping to mitigate the risk of future environmental impact. “There is a nuance in our analysis ... particularly around carbon creation and fossil fuel plants. The reality is, in any given year there’s going to be only so much water behind the dams, and only so much wind that is going to be carbon free,” Atwood said. Finally, there is the least-risk aspect to energy efficiency. “Inherently, there’s a risk management aspect to energy efficiency,” he pointed out. “If we fail on the efficiency side, we fail on the margins.” All about the customers and the community “Of course it’s all about the customers. Fundamentally, providing energy efficiency helps them to manage the cost of their bills,” Atwood said. “And our engagement with customers on energy efficiency helps build loyalty, helps build The money saved awareness of our brand.” And it’s about commuin energy efficiency nity, as well. “Community is the ‘public’ in ‘public stays within the power,’” Atwood pointed out. Energy efficiency has community in terms proved to be a cost-effective strategy for building econoof economic benefit. mies across the country without necessarily growing consumption, and this is true of Seattle, as well. “The money saved in energy efficiency stays���in a multiplier effect—within the community in terms of economic benefit,” he said. The bulk of the utility’s residential savings recently have been in lighting, and in particular CFL sales. “There’s still work to be done there,” Atwood said.

All on board! Whether it’s CFL sales or other energy efficiency improvements spearheaded by the utility, it’s imperative to get the community on board. With energy savings reflected on energy bills, it shouldn’t be a hard sell. At the same time, though, it’s critical that the win-win be clear. Our next story in this feature highlights ideas for successful programs, both in energy efficiency and demand response, and why they work.


ENERGY EFFICIENCY

Success stories and lessons learned ++Three utilities share their EE and DR best practices By Kate Rowland AT

THE

AMERICAN

PUBLIC

POWER

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Association (APPA) national conference this summer, three public utilities shared energy efficiency and demand-response best practices stories with a full house of interested attendees. Questions flew quickly throughout the session, with ideas from across the country shared by panelists and participants alike. Here we share some of the best, from two utilities in Washington state and one in Nebraska.

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Programs need to be customer friendly “The reality in Nebraska? We do not have an REP (renewable energy portfolio), we do not have state rates ... so while not all the ingredients may be there for energy efficiency, it’s the right thing to do,” said Marc Shkolnick, manager, energy services, for Lincoln Electric System. As well, he added, “We are looking at peak demand, not overall conservation incentives. The big picture is we’re trying to defer that next generation resource.” Shkolnick’s No. 1 suggestion? “Develop a program that is customer friendly. Keeping participation processes simple and straightforward is one way to ensure that your energy efficiency program isn’t [creating] barriers to participation,” he said. For Lincoln Electric, this means the pre-authorization form is simple for customers—all they have to do is sign and date it, because the contractor fills out the rest. “There

are not a lot of customer questions on our form. There is no need to ask questions you don’t need the answers to,” Shkolnick said. So existing fixtures, fixture types, wattage, etc., and replacement fixtures, fixture types, and the rest, are charted by the contractor. And when the customer gets the final bill for energy efficiency upgrades from the contractor, Lincoln Electric’s incentive is already deducted from the bill, with the contractor responsible for seeking reimbursement from the utility, rather than the customer. Shkolnick also advised developing and maintaining a strong relationship with local contractors. “That’s where the rubber hits the road. Over one-half of our customers learned about our program through contractors,” he said. In order to keep the utility-contractor relationship strong, Lincoln Electric holds a required orientation for participating contractors, and also holds program planning sessions with contractors in order to elicit feedback on the program. Keep it simple, and look for feedback For Andrew Grassell, energy development and conservation manager at Chelan County Public Utility District in Wenatchee, Wash., simplicity is also important. “Keep it simple. Customers are the key to the program’s success,” he said. “We have an agreement with our commercial and industrial (C&I) customers that is short, simple and easy to implement. It has consistent terms and conditions, and has been very successful. Sixty to 70 percent of our savings come from our C&I customers.” Grassell also recommended fostering creativity within the utility staff by allowing them to test ideas. He cited a staffinitiated “Reduce Your Use” promotion in which customers nominated themselves for participation. “We had nine residential customers, and staff conducted a pre-contest energy audit,” he said. “The winner cut usage by 35 percent, and overall savings averaged 9 percent.”


It’s also important, he said, to keep co-workers involved in giving feedback on program ideas. Chelan County PUD has put together a Conservation Program Review Committee comprised of representatives from all parts of the utility, including financial, legal, compliance, customer service and more. “The committee meets quarterly to review the programs and changes,” Grassell said, adding that internal buy-in is increased by knowing there is a robust evaluation process. Another tip: Don’t reinvent the wheel. Use history as your guide. “Learn from others,” Grassell urged. “Participate in regional initiatives—you can learn a lot by what other people are doing. Get to know your neighbors, especially if another utility has like demographics, and benchmark yourself against others.”

Learn as you go Everyone encouraged continual evaluation and refinement of any program. “This is important,” Shkolnick said. “Every new program is an opportunity to look, inform and improve. The 2012 version of our Sustainable Energy Program is significantly different from the 2009 program in its offerings, processes, terms and conditions. Each year is a learning experience. Be prepared to jettison strategies that don’t work, but keep your focus on your goal.” Grassell concurred. “Don’t be afraid of change,” he said. “Constantly scan for opportunities and threats to your programs, and use data to assess them mid-stream. Don’t be afraid to change when the information says so. Plans are just that: our annual plans are based on the best information we have at the time.”

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Looking to the future Jim West, assistant general manager, customer and energy services, for Snohomish County PUD in Everett, Wash., looked to the future in terms of his utility’s energy efficiency needs. “What got us here in energy efficiency projects in the past probably won’t get us there in the future,” he said. “For years we have pretty much known what the predictable base load is going to be. But our supply mix is changing.” The other side of the equation is changing, as well. “The marketplace and measures customers are installing are helping us to achieve energy efficiency,” West said. “But the cheap and easy energy efficiency that we acquired over the years is disappearing. Commercial lighting programs are changing. In residential, it is phenomenal the savings we have achieved with CFLs, but lamps are changing, and we have to shift to systems that are more complicated and expensive to install that we are going to have to invest in with customers to achieve energy efficiency savings in the future. “So, the question becomes: how do we take the lessons we’ve learned over the past 30 years and apply those in a

way that helps us to develop a new model to achieve energy efficiency with customers in ways that are beneficial both to us and to them?” West said. “Energy efficiency has got to deliver more than kilowatthours of savings in the future. We’ve tended to think about energy efficiency gains in terms of kilowatt-hours. Energy efficiency Now we have to think about the timing of those, has got to deliver and the geographic placement of those,” he said. more than kilowattIt’s not an easy equation. “In the northwest, hours of savings in lots of hydro and wind in the spring create negative the future. pricing,” West pointed out. “We have to think of how energy efficiency plays in that world of negative pricing. It’s a very different world.” But that’s not necessarily bad news, just a new future, according to West: “The time has never been better in this business to think about new business models and exciting ways to do it all.”

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Response 2.0 DR playing a larger role ++Increased renewables and regulations force DR to the forefront By Kate Rowland

W WW.INTELLIGENTUTILIT Y.COM /// JULY/AUGUST 2012

DEMAND RESPONSE IS EVOLVING, AND JUST

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in time. With increased pressure on integrated systems operators and utilities themselves, thanks to new environmental regulations that go into effect in 2015 and aggressive renewable portfolio standards in many states, utilities are turning to demand response (DR) programs in greater numbers to augment the changing generation mix. Total expected coal plant closures within the next three years are ranging from a 40 GW to 60 GW potential loss in generation capacity, depending upon who you talk to. That being the case, all eyes are turning to both demandresponse resources and energy efficiency to help maintain grid reliability. It’s a transformative change for the electric utility industry, allowing consumers—in coordination with their utilities—to use demand-side resources as alternatives to traditional electricity generation. And this change is being reflected across the board.

Higher DR & EE in PJM’s capacity market In May, PJM Interconnection announced the results of its capacity market, the annual Reliability Pricing Model, had secured record amounts of new generation, demand resources and energy efficiency to meet power supply needs between June 1, 2015, and May 31, 2016. New generation amounts to 4,900 MW, most of it natural gas-fired. In addition, new generation included 56 MW of solar and 796 MW of wind, a 22 percent increase and 15 percent increase, respectively. But the interesting numbers come a little farther down in the announcement: “In addition to new generation, most of it natural gas-fired, the capacity auction also procured 14,833 MW of demand response, a 5 percent increase over last year, and energy efficiency, a 12 percent increase. The amount of demand response was also a record for PJM.” 2.0 or 3.0? Demand response is shifting in nature, as well, aiming for more sophisticated load shaping rather than just the simple load curtailment of the past. Taking demand response to the next level requires a number of things: two-way communication to confirm demand response signals have been received and usage has been curtailed (meaning real-time confirmation can be documented and proven), and analytics that can be used to design specific demand-response programs to fit individual customers’ needs.


Add to that the challenges of synchronizing more disruptive generation—like wind and solar, which occur when they occur—and both active automation and active analytics become imperative to best manage load and immediate changes, if need be.

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Regulatory smooth sailing unlikely Federal Energy Regulatory Commission (FERC) Order 745, issued in March of last year, requires that retail customers receive payments for reducing their retail purchases of electricity (or electricity usage). This compensation scheme was supposed to pave the way for demand response and energy efficiency to be able to participate in the market in a balanced way, right alongside generation. Adoption of FERC standards was intended to improve the methods and procedures used to accurately measure demand response and energy efficiency performance, and help organized wholesale power markets to properly credit demand response and energy efficiency resources for their services. However, the Order has received some serious pushback, including a petition filed in early June 2012 with the U.S. Court of Appeals for the District of Columbia Circuit by the Electric Power Supply Association, the American Public Power Association (APPA), and Edison Electric Institute, along with NRECA and Old Dominion Electric Cooperative.

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DEMAND RESPONSE 2.0

“We think the aggregator or other demand response provider should be paid the full LMP [locational market price]–minus the retail rate they didn’t pay,” Susan Kelly, the APPA’s senior vice president for policy and general counsel, told the association’s magazine in June. “If demand response resources are subsidized at a rate that’s not efficient or rational, it will encourage too much activity by ARCs [aggregators of retail customers].”

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Bumpy road ahead for FERC Petitioners note in their brief that there are defects in the Order, including the fact that FERC has no authority to regulate retail sales of electricity, which it would be doing by treating retail demand response and energy efficiency reductions as “the functional equivalent of producing energy for sale at wholesale.” As well, the petitioners argue, there are other problems, including a compensation scheme that overcompensates demand-response providers while “unfairly subsidizing them,” and the unlawful imposition by FERC of a new rate mechanism without first demonstrating that existing rates were “unjust and unreasonable.” Without agreed-upon compensatory regulations for demand response and energy efficiency, their break into the generation market will be somewhat hindered. In the meantime, however, work continues in the areas of automated demand response and in states like California in which aggressive renewables integration goals have been set.

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California surging forward California’s aggressive goal of a 33 percent renewables portfolio standard by 2020 has put it in a position of needing approximately 4,500 MW of new ancillary services to assure grid stability and reliability are maintained given the variable nature of the renewables generation being added to the state’s generation mix. Researchers at Lawrence Berkeley National Laboratory’s Demand Response Center have noted that, while traditional gas-fired generators would be one approacch to adding new ancillary services resources, energy storage technologies such as grid-scale batteries, flywheels, and pumped hydro could overocome many of the environmental downsides of the gas-fired generators. Unfortunately—and herein lies the rub—the cost of energy storage technologies such

as these is still very high, and the energy available for discharge is limited. Berkeley Lab is now working on an advanced form of demand response, “Demand Response Optimization and Management System–Real Time” (DROMS-RT). This system is expected to reduce the cost of operating demand response and dynamic pricing programs in the U.S. by 90 percent, while also allowing more integration of renewable energy into the grid (important in California and other states with extremely aggressive renewables portfolios). According to Berkeley Lab’s Julie Chao, who wrote about the project in May, Berkeley Lab researchers first automated the process with OpenADR, an open communications standard which has become one of the first 16 national standards for the smart grid. One of the advantages Traditional demand of DROMS-RT, she said, is that it is dispatchable, response doesn’t have rather than having to be scheduled in advance, much—if any—foreand customers will receive price signals in near-real casting or predicttime. The automated system will also use computability built into it. er-based machine learning algorithms to make forecasts of future loads based on past behaviors, she noted. “Traditional demand response doesn’t have much–if any–forecasting or predictability built into it,” Berkeley Lab researcher David Watson told Chao. “Our algorithms figure out, based on historic behavior, what is the likelihood of any individual site to participate and predict the likelihood they’ll participate in the future.”

Technology continues to advance In the meantime, Automated DR, or ADR, has seen a terrific amount of research and development over the course of the past year, with new companies and products arriving on the industry scene in unprecedented numbers. By mid-May 2012, the OpenADR Alliance had reached a total membership of 71 different groups, including utilities, independent system operators, regulators and controls suppliers, a 44 percent growth in membership since December. “Industry momentum is clearly growing globally for standards-based demand response,” said Barry Haaser, the OpenADR Alliance’s managing director. “The addition of our new members and our rapidly growing membership base reinforces the importance policy makers, utilities and equipment manufacturers place on interoperable management systems.”


Smart grid projects can be deceiving.

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leveraging

METER DATA for grid operations

Drilling deep for greater achievements ++Meter data plays larger role By Phil Carson

W WW.INTELLIGENTUTILIT Y.COM /// JULY/AUGUST 2012

KANSAS CITY POWER & LIGHT WANTS TO DO

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it all. KCP&L, as the utility is known, is working with local stakeholders to modernize a significant part of its urban grid, revitalize the city’s urban core and engage customers and community for a more sustainable local economy. A successful outcome would benefit not only Kansas City, Missouri, but myriad utilities and urban cores around the country. After all, this is a Smart Grid Regional Demonstration Project with a price tag of $50 million, with $23.9 million coming from a stimulus grant. So KCP&L, like other utilities engaged in such pilot projects, must do its work transparently and in a manner that can be replicated elsewhere. You may recall we featured KCP&L in Intelligent Utility magazine’s May/June 2011 issue, in a story titled “Smart Grid as Economic Development,” highlighting the utility’s innovative approach to grid modernization: make it part of urban revitalization by engaging disadvantaged customers.

Early lessons learned At the time, Gail Allen, senior manager of strategic initiatives at KCP&L, offered suggestions and lessons learned in the early days of the deployment. “KCP&L’s smart grid approach, obviously, is different,” she said. “First, it focuses on applying smart grid technologies to help disadvantaged customers in an area of the city now targeted as a Green Impact Zone. The zone is a comprehensive, location-based plan to invest public and private funding to transform a neighborhood plagued by high rates of poverty and violence, unemployment and abandoned property. “Second, the project is broad and being rolled out at a brisk pace. It includes advanced renewable generation, storage resources, distribution system automation, in-home customer systems and digital technologies, and innovative rate structures. The programs will benefit about 14,000 commercial and residential consumers, while providing the critical energy infrastructure required to support the urban revitalization efforts of the zone,” she added. End-to-end solution I recently followed up with Bill Menge, KCP&L’s director of smart grid, who described the project’s drivers, challenges and the lessons learned so far. “From a technical standpoint, this is a true, end-to-end smart grid solution,” Menge said. “Almost anything you’d say, `Hey, that’s smart grid,’ is part of our demonstration project.” The focus, as Allen pointed out, is on a 150-block urban core in midtown Kansas City


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LEVERAGING METER DATA

designated as the Green Impact Zone, as well as an area that wraps around the Green Impact Zone, which is known as the Blue Zone. The affected customers, about 14,000, are largely residential, though some businesses are involved. The project area consists of 14 circuits connected to KCP&L’s Midtown Substation, which serves a 140 MW load, critical to downtown Kansas City, Mo., of which Green and Blue Zones are just a part. “A big driver for us is `proof of concept’ for business cases for what we want to do moving forward,” Menge told me.

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Improving reliability And the utility would like to improve reliability indices for customers, defer capital investments, particularly at the Midtown Substation, and learn how various components work or don’t work together. “We’re trying to see how tools and education can help folks understand how they use energy, how it gets delivered to them, what drives the cost of energy, and how they can use tools and knowledge to manage their energy use and have an impact on their bill,” Menge said. The customer-facing work has been ongoing since 2010, when KCP&L began outreach efforts to inner city residents to explain the project and the tools that would be made available to residents, such as smart meters, home energy Web portals and in-home displays of energy use information. Initial efforts were accompanied by a hightouch process of meeting with residents in various settings to raise awareness of the potential benefits of participating in the project. Installing advanced metering infrastructure and designing the project’s system also began in 2010 and was completed last year. Beginning last year and extending into this year is the project’s deployment phase, which addresses substation upgrades, advanced distribution automation and installation of a distribution management system.

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Distributed energy resources important too On the customer side, work continues on distributed energy resource deployments of customer devices, rooftop solar photovoltaic installations and a Distributed Energy Resource Management system. Time-of-use rate pilots began in May and will run through September 2014, with an “aggressive” spread between $.06 per kWh off-peak and $.36 per kWh on-peak, which is 3 p.m. to 7 p.m. “It’s geared toward shifting usage,” Menge said. “It’s a fairly narrow-band window with a significant change in price. We’re testing two hypotheses: First, how do people respond to time-of-use prices. And second, do people perform better with the tools we’re providing or without the tools?” Themes that run behind all these project details include systems integration and interoperability and cyber and physical security, Menge added.

For those of us who eagerly await the outcomes based on real data, patience is in order. The data collection, reporting and analysis comes in 2013-2014. The project addresses an impressive array of technology. Under “SmartGeneration,” KCP&L will test energy storage, demand response, solar photovoltaics and Volt/VAr optimization. Under “SmartEndUse” the utility will test Web portal usage, the effects of in-home displays, digital thermostats, TOU pricing, electric vehicle charging and home area networks. “SmartDistribution” and “SmartBuilding” efforts also include broad arrays of technology. Lessons to date As much as I’d like to jump ahead to see how it all turns out, though, just implementing the pilot so far has delivered a number of lessons learned to KCP&L and the project team. “We’re striving toward building things on the emergWe’re trying to ing standards from the NISTIR standards,” Menge said. “That’s see how tools and one of our greatest challenges as we approach pulling the trigger on a final design. If education can help those standards aren’t ready or available or nobody makes folks understand anything based on that standard, then we have to pull how they use energy. back from those standards. But we’re really pushing for off-the-shelf products that can plug and play in our system.” Dealing with vendors in a period of uncertainty regarding standards development has been a challenge. Did Menge have any advice for other utilities undergoing a similar process? “Having good requirements up front is the best plan, but that’s been very challenging for us because we’re trying to build requirements on standards,” Menge said. “It’s hard to tell a vendor to build to a standard that isn’t written yet. And it’s hard for a vendor to give me a price. We all agree we’re going to try to do that, but when you get down to the brass tacks, the vendor says `I’m not sure I can do that’ or the standard still doesn’t exist, well, solid requirements help. If you were proceeding with upgrades across the enterprise, you may not take some of the risks we’re taking in this pilot project.” Some early learnings have a familiar ring to them. “One of the things we mention frequently in team meetings is `Plan B,’” Menge said. “What if `Plan A’ doesn’t work or doesn’t go well? Call it contingency planning— there are lots of fancy ways to say it. Can we undo something if necessary? “Remember,” Menge added, “this is a demonstration project—a big part of this is learning.”

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


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Intelligent and reliable

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++Distribution automation continues to make advances By Kate Rowland THE OPTIMIZATION OF NEW, DISTRIBUTED RESOURCES REQUIRES

more intelligent control over electrical power grid functions, both at the distribution level and beyond it. As Electric Power Research Institute (EPRI) technical executive Robert Uluski told us in the March/April issue of this magazine, a distribution management system “is a decision support system to assist the control room and field personnel with the monitoring and control of the electric distribution system in an optimal manner while improving safety and asset protection.” The goal of advanced distribution automation (DA) is real-time adjustment to changing loads, generation and failure conditions of the distribution system, usually without intervention.

Defining the issue The IEEE Power & Engineering Society (IEEE PES) has described it in this way: “Although higher reliability and quality are the goals of the utilities, they would like to accomplish this while optimizing the resources. Another goal for a utility should be improvement in system efficiency by reducing system losses. Distribution automation provides options for real-time computation, communication, and control of distribution systems, and thus provides opportunities for meeting the above mentioned goals.” Typically, advances in distribution control technology have lagged considerably behind advances in generation and transmission control. Until recent years, the progress of distribution automation has been relatively slow due to the reluctance of utilities to spend money on automation because many utilities have found it difficult to jus-


acquisition (SCADA) systems in all substations, in order to provide information for system operators. At the same time, it deployed automatic switches at strategic points along the grid, which allowed the system to respond to disturbances more precisely, and it buried 90 percent of its overhead lines. According to a case study on the upgrades, “Every year since 2001, Naperville’s annual System Average Interruption Duration Index (SAIDI) values have shown improvements ranging from 14 to 55 percent, depending on weather conditions and other factors. In addition, automatic restoration process decreases the number of trucks and repair crews being deployed in the field for maintenance and repair services.” The benefits not only include increased reliability and service to customers, but also translate into savings for the City of Naperville and for its residents. Wadsworth optimizes distribution system The City of Wadsworth, Ohio, is a municipal utility without its own generating capacity, and purchases wholesale power at a relatively high cost. Recently, it began work on upgrading and adding new capabilities to its protection and control (P&C) system, documented in “Case Study: Using Distribution Automation to Build the Next Generation Utility in the City of Wadsworth,” a paper written by Mark Fuller, the City of Wadsworth’s communications, substation and project superintendent, and technologists from Wadsworth’s project partner. The paper is designed not only to explain the technical details of the project, but also to illustrate the advantages of having systems that can be aware of the entire distriAutomatic restoration bution system, the authors say. “There is always a balance to be found between centralized and process decreases distributed intelligence as distribution automation becomes more prevalent, and that balance the number of trucks should be discovered by leveraging the usefulness of centralized knowledge while sacrificand repair crews ing as little of the inherent redundancy that comes with distributed intelligence as possible,” being deployed in Fuller et al. wrote. More specifically, “a cohesive set of groundthe field. breaking new technologies is being deployed, leveraging an existing fiber-optic communications network. The integration of modern recloser controls, capacitors, regulators, and feeder circuits with a centralized automated fault detection, isolation and restoration system is the focus of the new P&C system. “In addition,” the paper notes, “the new P&C design provides a solution to a present challenge: engineering a centralized automated feeder voltage profile optimization solution that can remain fully functional alongside a fault detection and isolation system that is capable of automatically modifying the distribution system topology.” The two technologies are being integrated into a single interdependent system, Fuller noted, that “provides the city with a volt/VAR control system that can automatically and appropriately adapt to constantly changing distribution system topology as faults, loss of potential, mis-coordinations, or overloads occur and are automatically and immediately integrated.” Because of Wadsworth’s situation as a power purchaser, rather than a self-generator, the need to optimize its distribution system operation was seen as critically important, in order to reduce power consumption and losses, and avoid contractual costs related to reactive power demand.

tify automation based purely on costbenefit numbers. Automation allows utilities to implement flexible control of distribution systems, “which can be used to enhance efficiency, reliability and quality of electric service. Flexible control also results in more effective utilization and life extension of the existing distribution system infrastructure,” the IEEE PES notes.

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Long-term upgrades at Naperville Utilities across the country have deployed both distribution automation and advanced distribution automation in projects such as that advanced by the City of Naperville in Illinois, which has been investing in distribution automation systems for more than a decade. The municipal utility began its grid modernization program in the late 1990s, beginning with the installation of supervisory control and data

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“EPRI IntelliGrid project will focus

Nashville Electric laying the groundwork on geospatial In October 2011, Nashville Electric Service announced plans to deploy high-speed network information system infrastructure to meet its immediate advanced metering and demand-response needs, as well data quality as its distribution automation communications needs, and to lay the groundwork for improvement. future needs. Once the network umbrella was in place, the utility’s goal for this year was to begin to monitor voltage at the meter to help manage the system voltage, and to begin automating control of distribution system equipment, such as capacitor banks, to improve power quality and efficiency.

W WW.INTELLIGENTUTILIT Y.COM /// JULY/AUGUST 2012

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IntelliGrid presses forward EPRI’s IntelliGrid has focused a number of its 2012 projects on intelligent distribution systems. Three under the infrastructure umbrella merit attention. The first project supports cost-effective utility integration of distribution applications by advancing CIM-based design, implementation, and interoperability testing. It focuses on tracking CIM development progress and developing guidelines for the application of standards to real back-office integration. Another project focuses on geospatial information system (GIS) data quality improvement, and aims to provide utilities with an adaptable template and set of tools that can be used to assess, improve and ensure ongoing GIS data quality. The third, which supports field force data visualization of operational data, will “develop a polished mobile data access application using modern standards in conjunction with modern mobile operating systems to create an application to merge data from disparate systems with real-time video to create a user interface for the visualization and dissemination of operational data.” GIS data needs improvement The second project is especially important as utilities seek to resolve data quality issues. EPRI defines these in the following way:

??

GAPS. For example, key data

are missing. ??

REDUNDANCIES WITH OTHER SYSTEMS. For example, data are

captured in many systems, and they are inconsistent or require duplicate data entry to update. ??

LACK OF CURRENCY WITH SYSTEM “AS-BUILT.” For example, there

is untimely work order completion/backlog. ??

INACCURACIES WITH THE FIELD.

For example, the GIS has data, but does not represent the actual system in the field. ??

INACCURATE OR UNAVAILABLE LAND BASE. For example, there are

varying degrees of accuracy of land-based data based on the source. ??

CUSTOMER TO TRANSFORMER CONNECTIVITY BY PHASE IS IN DOUBT.

??

THE GIS MODEL ITSELF ALLOWS FOR “BAD” DATA.

The idea, at project’s end, is to be able to provide utilities with a template and a toolset for assessing and improving these issues, thereby ensuring ongoing GIS quality.


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Grid Optimization Built On Smart Meter Networks And Data W WW.INTELLIGENTUTILIT Y.COM /// JULY/AUGUST 2012

Kip Gering, Itron Product Line Manager Tom Wilson, Itron Senior Product Manager

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U

tilities are looking for more ways to turn smart meter data into valuable, actionable information. Their goal is to take maximum advantage of the capabilities of smart grid networks and smart meter implementations and increase the value of their investment for the benefit of customers and other stakeholders. Over the past several years, primary drivers for smart grid implementations

have included facilitating meter-to-cash, improving customer service, and supporting targeted programs such as demand response. The significant business benefits of these use cases have been demonstrated in field implementations. Of course, the smart grid vision goes far beyond smart meters. Objectives for expanded initiatives, designed to take advantage of smart grid networks and newly available sensor data, are

shifting to emphasize improved grid efficiency, reliability and service quality. Also of interest is using acquired data to assess asset health to help determine optimum timing on future capital infrastructure deployments. Utility investments need to be tied to practical and realistic business cases. This is what utilities and regulatory commissions are looking for – projects with clearly identified near- and longerterm benefits, as well as a strong return

THOUG HT LE AD E RS H I P - S P ON SOR E D BY ITRON


on investment. A key consideration for these investments is being able to support the widest range of potential applications with the flexibility to prioritize their deployment where and when they can deliver the highest value.

The Enabling Smart Grid Architecture Smart grid network investments are major, complex decisions. More emphasis has been put on assuring that infrastructure investments provide a clear path to the future with the longest possible useful life. An important consideration is to start with a smart grid network architecture that supports current requirements and is positioned as a platform to support future initiatives. For example, the platform should have the ability of scaling to many millions of endpoints with an open standards interoperability path to support future applications as well as communicate to virtually any type of endpoint sensor and control device. In addition, utilities should consider an architecture that can support near/real-time data delivery, robust management of multiple devices and applications, both centralized and distributed intelligence, and emerging smart grid analytics.

THOUG HT LE AD E RSH I P - S P ON SOR E D BY ITRON

Of course, simply identifying an array of potentially compatible vendor devices that might be able to communicate over a common network infrastructure is not the right approach, if that infrastructure is all or mostly proprietary. A key question utilities are asking is: “does it makes sense that multiple applications and vendors will continue support of, and expand interoperability with, the proposed architecture over the longer term?” The question of long-term viability highlights the value of layered, open standards architecture. Robust options for network and endpoint manageability become essential in this multi-application smart grid environment. The emphasis is not only to keep the network up and running in an optimum manner, but also to efficiently manage security, monitor network services, and upgrade network and endpoint devices as needed.

Challenge Of “Big Data” Smart grid technology and the advent of smart meters capable of capturing frequent interval usage data and additional valuable information, with twoway communication, ushers the industry into an era of unprecedented large volumes of information. This information requires not only a scalable platform in which to reside, but an intelligent way to selectively capture the data and use it to drive operational efficiency, optimize asset management, and support robust demand response programs. There are many new opportunities, as well as a number of new challenges, resulting from the greatly increased type, variability, volume, and timing

of smart grid data. Data from multiple sources, such as sensors and transactions, is not only generated in high volume, but is also delivered at a high rate. This huge growth of information and related methods for making the information available in a useful form is has been termed “big data.” There are various emerging big data strategies for effectively dealing with this information and leveraging it to maximum advantage. New paradigms around “utility analytics” are quickly being defined. Utilities have focused efforts in architecting and executing on initial smart grid deployments. They are now starting to build strategies for using the newly available data, recognizing that the new information obtained is a valuable asset and are considering their big data options. Fundamentals include putting mechanisms in place to identify and analyze the most important data, and assure that the data can be retrieved in a reliable and timely fashion.

Grid Optimization Opportunities Grid optimization can be described as getting the best possible power quality and efficiency from the grid and keeping power losses to a minimum. Utilities are looking to get results by addressing a range of opportunities. Significantly improved data collected from the grid is enabling enhanced system modeling, better outage management and distribution management, as well as utilization of advanced analytics. Solutions for grid optimization are evolving to take advantage of new smart grid monitoring and control capabilities. One area getting significant attention is power quality improvement.

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There is increasing awareness that proprietary platforms, functioning in silos, can be more costly to operate over the life of the assets and simply do not offer the potential for delivering the range of information that will be required. This point has already played out in traditional IT with exhaustive proof that multiple, proprietary systems are not worth it. Also, proprietary approaches do not offer the proven benefits of the more

robust security possible with open, widely embraced standards.

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Power Quality Improvements Using Meter Voltage Data

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In power quality improvement scenarios the smart meter can function as a “grid sensor� endpoint. Information is obtained from the meter related to power quality, such as voltage, frequency and power factor data. This data can be acquired as needed from the grid locations of interest. Information on voltage levels at the point of service delivery can serve as a very good indicator of both overall system performance as well as customer

satisfaction. For example, areas with voltage issues often correlate with locations of dissatisfied customers. In the past, utilities have relied on representative system models in order to estimate voltage levels throughout the delivery system. There was no efficient way to monitor voltage in near real time. Instead of being able to monitor voltage fluctuations on a proactive basis and take preventive action, utilities had to rely more on broad studies and customer complaints to identify issues. Emerging solutions are combining enhanced smart meter data retrieval

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options with the new capabilities of flexible smart grid networks. When accompanied by data warehousing and sophisticated analytics, the result is a robust capability to proactively monitor and improve power quality. From a smart meter perspective, meters can have the capability to be configured for specific voltage data acquisition purposes. For example, utilities can start measuring voltage on targeted subsets of a meter population on circuits of interests. Voltage data is obtained for selected intervals and durations and delivered for analysis as required to meet the specific goals. Voltage threshold violations and durations can be logged. This information can be delivered on a timely basis to, for example, an analytics engine that performs calculations and correlations. These solutions are essentially painting a valuable picture of the grid situation to support decision making.

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Vision For Grid Optimization Opportunities will continue to expand for utilities to take advantage of data from smart meter and other smart grid sensors to help meet business challenges. One previously highlighted example is power quality improvement applications. An important step is to start with a smart grid network architecture that has the capability to support current and future initiatives, including massively scalable, open standards-based multi-application support. Also critical is robust network and endpoint manageability, as well as support for smart grid analytics.

This provides the utility with the potential to identify and address issues in the system, monitor and measure effects of improvements, and identify grid optimization candidates that can offer the highest return on investment. Tom Wilson has more than twenty years experience developing, implementing and managing large scale wireline and wireless network solutions for telecommunications carriers and electric utilities, and their enterprise end customers. At Itron, he has product responsibility for Cisco and Itron joint development of smart grid network solutions. Kip Gering has over ten years of product management experience with workforce management, meter data collection, and smart metering applications in the utility industry.

The vision will enable utilities to proactively monitor system performance at delivery points across the smart grid.

At Itron, he is a product line manager responsible for Itron’s smart metering applications and networks.

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This same type of smart meter data can help reduce power losses. Volt/VAr optimization (VVO) and conservation voltage reduction (CVR) are good examples of distribution automation solutions, related to the power quality and efficiency discussion, which can be enhanced using end-of-line smart meter data. Smart meters can be configured to acquire voltage measurements at discrete intervals and with channels to transmit this information in near real time to upstream control systems. Using this additional smart meter data, combined with field data from other sensors, supports a higher level of accuracy for applications which provide voltage control responses. All of these sensor and control functions can be effectively supported on the same multi-application smart grid network.

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Consumer expectations are changing ++Experiences explored at AGA/EEI conference By Kate Rowland WE SAT DOWN WITH ELECTRIC AND GAS UTILITY CUSTOMER

service officers gathered in Austin, Texas, for the AGA/EEI Customer Service conference to discuss issues of importance to their companies and their customers in 2012. Their comments, edited for style and length, follow.

PARTICIPANTS JIM ALBERTS Vice President, Customer Services KCP&L BRIAN KAGE General Manager, Strategy and Business Performance, Customer Relations Integrys Energy Group PEGGY RICKETTS Vice President, Customer Care Westar Energy, Inc. BOBBI SCHROEPPEL Vice President, Customer Care, Communications & HR NorthWestern Energy


What do you feel your customers expect from you as the utility, and has that changed over time?

ALBERTS Customer segments have some unique needs, but in general, customers expect reliability. We think of reliability in broader terms to include service quality and community engagement from employees that truly care, providing clean and (Customers) want to affordable energy, as well as the traditional expectation for high levels of power quality and system interact with us on reliability. Customer expectations are growing in every component as our industry becomes more their terms, meaning dynamic. Those expectations are also shaped by every other customer experience they have, so we when they want to. need to monitor the changes and trends in order to stay tuned into their needs. KCP&L’s higher purpose is to improve life in the communities we serve, so keeping up with those expectations is vital to our overall success.

BRIAN KAGE

RICKETTS

I think that the core business remains the same. I feel pretty strongly they still expect us to provide reliable service at a low cost, and that’s been that way for a long, long time. I think what’s changed a little bit is being that trusted adviser going forward, because there’s so many more options for customers. So I think that they want to see us as that trusted adviser, someone who can come and put all those things together for them, and be that one-stop shop where they can find out information about their energy needs. Are you finding it easy to step into the role of trusted adviser, or is it more difficult? Are your customers asking for that, or is it a matter of a mutual, new relationship? RICKETTS

I think it varies, depending upon the customers. But what we’re finding at Westar is that customers do see us as that trusted adviser, and often come to us to get advice. SCHROEPPEL

K AGE

I agree, especially in the area of reliability, it’s really a given. So when you do have a reliability issue, it’s a much bigger customer service event compared with what it would have been 15 or 20 years ago, because customers aren’t used to it anymore. Building on something Bobbi said, a lot of our thinking is focused on self-service and interacting with customers in a different way. In our service territory, we’re not finding that being a trusted adviser is an issue – what we’re

PEGGY RICKETTS

seeing is that customers want to interact with us on their terms, meaning a time that’s convenient for them, doing more from a self-service standpoint, and then all the things that flow into that. So what does that mean for your call center? If someone’s going to pick up and call you, they may say, “How do I do something on the Web?” instead of “Handle my transaction.” And, quite frankly, as an industry, we’re nowhere near where we need to be in our ability to answer those types of questions. So I think things are changing, because, with the immediacy of the technology now, customers expect that they can do anything, any

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We still spend the majority of our time doing traditional utility things as far as people calling in or making payments, and that sort of thing. But, having said that, customers are looking at other industries, and they’re looking at the business-type options that are available in other industries: banking, as an example, and airlines. So that’s something that I think we’re catching up on in the utility industry, and data mining, but we’re not there yet. But I will throw one other item in there that is at least important in our service territory with respect to customers. We’re a big fish in a small pond. Our customers expect us to be a leader in the communities. They expect us to be volunteering. We’re always at the top of the list when it comes to sponsorships and donations, and we take that very seriously. It is a major driver for our customer satisfaction, along with price. But prices are good; rates have gone up in the U.S., but it’s still a really good deal. And everybody’s done such a good job with reliability that it has just become a given. People only think about those things when it’s not there.

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10 years of financial statements.” We’re going to have to get there. This is going to mean we’re going to have to have our own data warehouses, and keep that information accessible. RICKETTS What do you think is holding back for getting some of these things to happen sooner in your utility? SCHROEPPEL

Just catching up on our core technologies. We’re upgrading our CIS right now, and that’s going to open us up to be able to do all of this, but I think a lot of utilities in the 1980s and ’90s weren’t spending a lot of money on technology, and now, GIS, outage management, and MDM, it’s great stuff, but ... RICKETTS

BOBBI SCHROEPPEL

We’re experiencing that same thing at Westar. We had an old CIS that’s been around for many, many years. And so we have all these great ideas of things we want to do, but we have a totally inflexible system, and any time a customer wants information, it takes an IT person to go in and query the information and get it out–no data analytics at all. So that’s what we’re excited about. I’m glad to see you’re starting. We’re not there yet. K AGE

I think an important factor is the cost. If you look at any kind of survey about what customers want, it’s reliability and low price. So this whole thing about making investments to get to the data, well, that impacts price, which is always more important than some of the other stuff. I think that’s something we always run into, especially with rate pressure and the economy and those types of things. It’s been hard to get those those investments through. So you’re balancing pain points with customer pressure points, as well, and looking at the cost? How important is customer selfservice to your utility? K AGE

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JIM ALBERTS

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time they want. And we’re a little bit behind, because sometimes we’ve got to roll a field crew, and that doesn’t happen instantaneously. SCHROEPPEL

We’re seeing more and more requests for data, and not just one or two years’ worth of data, but 10 years’ worth of utility data. It’s starting with our universities and larger customers, and they can’t go onto our website and get that now–they’re going to be able to–and so we have to run queries to get the information. It’s incredibly time-consuming. People are used to being able to go to Wells Fargo and say, “I want to download seven or

Self-service has been the centerpoint of our strategy since 2007-2008. We’ve done a lot of things in e-billing, e-payment, just getting more and more transactions done on the Web. Our big constraint is we have three CIS systems among our six utilities. We want to get that common feel on the Web, but we have three different things to plug into, and it becomes problematic. After a series of mergers, that was really where we focused: how do we build a self-service layer on top? We’ve seen some good success–we took e-bill from four percent to 16 percent of our customers in a couple of years. I think that’s where the customers want us to be. It’s just a matter of how fast we can get the technology and the business cases through, because things like turn on/turn off on the Web–we’d love to do that, but getting the business case through is sometimes a little harder than you would think it would be. However, it’s absolutely core. Our strategy is self-service, because that’s where we think the mass market is going. It’s a whole different thing in the C&I world, where expectations are a little more specific, especially in the electric C&I world. In the mass market self-service is core to everything we are doing. SCHROEPPEL

Increasingly. We’ve done a really good job at NorthWestern of making our call centers accessible. We answer the phone in a couple of rings for the most part; our CSRs are very professional. So, don’t get a lot of complaints about our lack of self-service functionality, but it’s creeping up on us. We’re hearing more and more about it. Kids that are growing up with iPhones aren’t going to even know anything else. So we figure we’ve got three to five years, probably, to get to where we want to be. But in the meantime, we still have local offices and we have great contact centers, so our customers can find us very easily, and I think that’s probably helping us, as far as not having too much push back. And


then there’s our age demographics–we are a little bit grayer than other states.

that arena, we want to be providing that excellent service that they’re used to with other industries that they do business with every day.

RICKETTS

ALBERTS When we look at self service as an option, it has to make sense, Many times in the past in our utility, we’ve thought about meaning it has to add value for us and the customers, creating a mutual benefit. self-service options as an operational Generally the goal of self service should be to improve the experience and help savings. We could avoid calls getting manage costs. This is much easier when it comes to basic transactions, such as into the call centers, we could make it processing payments or establishing service, but the future brings bigger chaleasier that way. But the focus has really lenges as customers want more information in order to make the best possible switched to: “What does the customer decisions for their business or family about their energy and service needs. This really want?” What we rewill have to include modeling options and sceally want to do is be easy to narios, then presenting the outcome to help make We figure we’ve got do business with. I think choices. Achieving that will require access to lots of that customers want us to data from across the company in order to ensure three to five years, be available at all times on the mutual benefit goal is achieved. their terms, and we have Self service is very important to us and our probably, to get to a long way to go to get customers; it allows people to conduct business there, admittedly, but it’s any time they want, which helps us meet growwhere we want to be. certainly what we’re striving expectations, and manage seasonal peaks, ing for. We’re not getting a as well as communication during outages. Even huge amount of customer complaints though self service is growing, we need to support those tools with experienced about these kinds of things, because I and knowledgeable people to answer questions and manage expectations. The think they’ve just kind of grown used bottom line from a customer point of view is to do whatever we can to help to the utility being that way to do busi- keep energy as affordable as possible while improving the customer experience ness with. But we don’t want to be in along the way.

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IT INSIGHTS

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Analytics business infrastructure ++Keys to taking your analytics to the next level By H. Christine Richards AT THE UTILITY ANALYTICS INSTITUTE, WE’VE SPENT THE

past several months focusing on two key analytics areas: customer analytics and grid analytics. Although increasingly advanced analytics will focus primarily on these areas, many advanced analytics initiatives will eventually need an enterprise-level analytics infrastructure to support them. In fact, this need for a supporting analytics infrastructure is so great, we’re making it a conference track at the upcoming Utility Analytics Week conference and exhibition. In this article, let’s talk a little bit about why analytics business infrastructure is important, and what the term means.

Targeted wins to enterprise-wide analytics A way utilities are getting started with analytics initiatives is through targeted efforts. Utilities are likely to identify many potential analytics projects as they identify their key business objectives and how they can address them with analytics. It is important to prioritize them and begin with projects most likely to deliver tangible business benefits quickly. By targeting specific, high-priority pain points with analytics, a utility can use the results to demonstrate the value of analytics and ultimately build confidence for applying analytics to other parts of the business. The success of these first projects will help fuel company confidence in analytics, but it’s important to have a plan in place to help expand the analytics capabilities throughout the company. The key to the quick-win approach is to make the wins repeatable throughout the organization. On top of expanding quick-win projects, utilities need to consider the cross-functional needs of advanced analytics. Utilities have excelled at managing individual functional areas, but advanced analytics will provide utilities a greater ability to monitor and analyze across their supply chain from generation to consumption. With these changes, utilities will be able to better understand how changes within one part of the company affect another through analytics. Utilities will have to break down the siloed nature of their business to address the enterprise-wide needs of analytics. Here are some ways that will happen: ??

MERGING NEW AND EXISTING DATA SOURCES. Technologies and ap-

plications that dig into existing data sources, such as asset management systems, but can also handle new data from sources such as smart meters, smart network sensors, electric


vehicles and distributed generation resources. These analytics can also sort through both structured and unstructured data sources. ??

BUILDING FOR FLEXIBILITY. Analytics that offer flexible customization

capabilities, while not being so customized that they can’t be used to satisfy multiple company needs. ??

BRINGING TOGETHER MULTIPLE DATA SOURCES. Analytics that pull together

information from multiple business areas and sources across the utility, including generation, transmission, distribution and customer service. Analytics can also pull in data from outside a utility company, such as weather and traffic data, or even as-built plans for commercial buildings.

JOIN US

UTILITY ANALYTICS WEEK September 18-20, 2012 Arlington, Texas Learn more about the event and register at utilityanalyticsweek.com.

In order to support these cross-functional analytics needs, and to be able to expand quick-win initiatives, utilities must work to build an analytics business infrastructure, which ultimately creates the foundational platform for advanced analytics. Analytics business infrastructure is the hardware, software, professional services, business processes and people needed to successfully support and implement analytics initiatives across the enterprise that are not specific to either customer analytics or grid analytics. Examples of analytics business infrastructure include:

??

Analytics hardware, such as analytics-specific servers

??

Software and middleware that support analytics applications or offer enterprise-wide analytics capabilities

??

Communications networks

??

Professional services, such as data management and integration

??

Business plans for supporting enterprise-wide analytics initiatives

Recommendations So how do you make that leap from targeted analytics projects to a companywide analytics initiative? There is not necessarily one path, but there are some steps you can take to get started: ??

Define what it means to take your analytics project to the next level, and what that means for your company in terms of planning and resources. Essentially, what does it take to move from one or a few smaller analytics projects to an enterprise-level effort?

??

Consider what you can do to ensure that the infrastructure you’re installing today will serve your company well into the future. It is important to consider the analytics needs of today

At the Institute, we’ll be discussing business analytics infrastructure in more depth over the coming months, and a good place to start that discussion is Utility Analytics Week, September 18 to 20, 2012, in Arlington, Texas. We’d love to have you join us. You can learn more about the event and register at www.utilityanalyticsweek.com. H. Christine Richards is a director at the Utility Analytics Institute, a division of Energy Central. You may reach her at crichards@energycentral.com.

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and those of tomorrow.

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TOP 3 REASONS TO ATTEND Arlington Convention Center, Arlington, TX September 18-20, 2012 Register 3 or more from the same company and save $200 per person! Utility Analytics Week is your opportunity to sit side-by-side with your utility peers, learn from utilities that are tackling similar initiatives, and offer up your ideas for solving challenges others are facing.

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Learn through focused content for your Entire Team. Through concentrated workshops in Customer Analytics, Grid Analytics and Analytics Business Infrastructure, you’ll develop actionable plans to answer your most pressing analytics challenges. You’ll leave with key takeaways that can be applied in your own utility/business.

Hear from industry thought leaders who are driving advancements in Utility Analytics initiatives, including:

Jim Greer

3

Senior Vice President and Chief Operating Officer, Oncor

Brenda Jackson

Senior Vice President and Chief Customer Officer, Oncor

Paul De Martini Principal, Managing Director, Newport Consulting Group

Lloyd Tokerud

Director of Analytics, Just Energy

T. Michael Quinn, P.E. Vice President and Chief Technology Officer, Oncor Electric Delivery

Experience first-hand cutting edge solutions to your analytics challenges. The data analytics marketplace is filled with options and knowing which one to select can be confusing. Utility Analytics Week includes a robust exhibit hall — where you’ll experience analytics options up close and in person, to help you make an informed decision on which solution best meets your objectives.

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IT INSIGHTS

The challenge and promise of unstructured data ++Utilities navigating a more complex world of data By Mike Smith

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AS UTILITIES HAVE WADED INTO THE DATA-HEAVY POST-

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smart grid era, utility leaders from across the enterprise are seeing that there is value in all of that data beyond simply managing the volumes of data and getting it to the right people. This, of course, is where analytics is proving to be a game changer at many utility organizations. We’ll be discussing these and other issues at Utility Analytics Week in September. Turning the volumes of data into actionable intelligence is what the analytics game is all about, and utilities are finding more ways to score points in this game on a seemingly daily basis. The examples range from new business processes for managing assets predictively to segmentation, and targeting customers for new programs to re-shaping the load curve, and more. These examples—and countless others—are all dependent on the ability to move the organization from using all of that data to report what happened to operating predictively by taking the knowledge from the historical data and changing business processes based on this knowledge. When done well, the improvements across customer, financial, operational and regulatory requirements can be significant.

Opportunities and challenges Inherent in these opportunities are a new set of challenges, including the emergence of unstructured data in utility customer and grid databases. Unstructured data (or unstructured information) is information that either does not fit into a pre-defined data model and/or does not play well with relational tables. Unstructured data is typically characterized as being text-heavy, but may also have numeric information, such as dates and raw numbers. This lack of structure creates irregularities and ambiguities that make it difficult to understand using traditional computer programs that would pull data from more tabular types of database structures. Examples of how different unstructured data can be include text data from various social media platforms, voice data from customer service telephone calls that have been converted to text, or possibly even data from synchrophasers out on the distribution grid. Nuggets of quantitative and qualitative information are buried in these unstructured piles of data, but they require different management, manipulation and application tools to be effective.


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IT INSIGHTS customers communicate is unstructured. Utilities need to ask if they can afford to ignore up to 80 percent of their customer contact data.” A third customer interaction dimension Continuing with the customer management challenges and how utilities are using unstructured data to meet these challenges, Dan Burgess, an analyst at Avista Utilities, based in Spokane, Washington, added an interesting perspective. “We have historically looked at our customer interacUp to 80 percent tions in two dimensions, typically based of how customers on time and cost,” he said. “These are helpful, communicate is and help us build some Mining free text fields quantitative metrics, unstructured. Utilities Another example of unstructured data that but this neglects the most utilities encounter is from free text fields in third dimension, need to ask if they can systems and survey applications. Customer service that of the customer representatives or customers populate these fields perspective.” Burgess afford to ignore up with valuable customer data in an uncodified also noted that this format that’s hard to mine. new type of customer to 80 percent of their Mari Vandewettering at Portland General data has added a qualiElectric in Portland, Oregon, tells of the utility’s tative element to the customer contact data. challenges in working with this type of unstrucutility’s customer tured data: “A lot of the unstructured data that we service metrics. see is in free text fields in our operational systems and from surveys that customAs utilities continue to drive ers fill out directly on our website, or in our community offices. We’re still learnforward in this new era of analyticsing how to work with this and are using some new text-analytics software tools centric management, the ways that to get there, but we are starting to use this data to decipher customer sentiment they are using all of this data—be it and digest and categorize customer feedback.” traditional, tabular data or the more Going a bit broader and deeper to yield new insights and tangible, measurcomplex unstructured data—continue able improvements is where the use of unstructured data is heading for utility to evolve. Social data didn’t even exist analytics professionals. Alyssa Farrell, global energy product strategy lead at until a few years ago, nor did interval SAS, provides a few more examples of how utilities can benefit from analyzmeter data or deeper, broader ing unstructured data. “We see a variety of applications for unstructured data availability of asset data via sensors at utilities—some of which are in use today, others of which are being used in deployed across the grid. other industries that can be applied to utilities,” she said. As utilities learn to move from Areas with immediate value, she said, include using call center data to improve simply managing this data to leveragoutage root cause analysis, or even the use of technician’s notes from standard ing it for predictive operations, the maintenance or emergency replacements of field assets to build predictive modimpact will be seen and felt across els of future asset failures. Reiterating the challenges noted above, Farrell points the enterprise and from the executive out that “utilities have to turn to data storage mechanisms such as Hadoop that do not impose structure on the data,” and that tools built for analyzing the senti- suite to the field crews. ment in text are called for to help capture the value in this new data. Mike Smith is vice president of Energy Pointing to how critical unstructured data can be for customer service, Bryan Central’s Utility Analytics Institute. He can be reached at msmith@energycentral.com. Truex, Teradata’s utility industry director, noted that “up to 80 percent of how

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O P E R AT I O N A L PERSPECTIVES

What’s happening on the grid? ++O&R Utilities takes model-centric approach to reliability, efficiency By Phil Carson WHEN HURRICANE IRENE AND AN EARLY SNOWSTORM HIT

Wringing functionality from legacy systems O&R’s case illustrates how sensors, resulting data and an effort to wring the most functionality from legacy systems can lead to cost-effective improvements in an electric utility’s most fundamental responsibilities. The results of O&R’s efforts should be in by next year, possibly offering its peers an opportunity to replicate this utility’s approach, according to Charlie

Looking under the hood O&R’s model-centric approach not only builds on legacy systems, but also relies on well-vetted technologies and employs open architecture to preclude point solutions, cutting costs and avoiding vendor lock-in, Scirbona said. The O&R project is twofold: it adds hardware and extends the communications network to five circuits and two substations, affecting about 10,000 customers in part of its New Jersey service territory, and it uses the equipment to optimize the economic performance of O&R’s distribution circuits in parts of New York. Let’s first look at the model-centric approach. Today, O&R’s system incor-

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Orange & Rockland Utilities’ service territory last fall, the storms wreaked the worst havoc ever. The hurricane knocked out 40 percent of the utility’s 300,000 electric customers. Then an October snowstorm dumped nearly 20 inches of snow and the temporary loss of power to customers was even greater. O&R was hardly alone, as utilities across the Northeast all were devastated by nature’s double whammy. But O&R already was working on several fronts to improve “blue sky day reliability,” reduce storm-related outage and restoration costs and improve grid efficiency through coordinated voltage reduction, while deferring large capital investments to avoid a rate increase.

Scirbona, manager of smart grid engineering at O&R Utilities, a subsidiary of Consolidated Edison, Inc. O&R has two subsidiaries of its own, serving a population of 750,000 in New York, New Jersey and Pennsylvania. The O&R project is part of a larger $272 million project—half funded by a Smart Grid Investment Grant of $136 million from the U.S. Department of Energy—undertaken by ConEd, O&R and other subsidiaries.

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O P E R AT I O N A L PERSPECTIVES porates field devices such as reclosers and automated switches. The drawback to the present configuration is that these devices can only respond automatically to pre-programmed scenarios; events outside those parameters can cause those devices to shut down. O&R’s model-centric approach, being built and tested on one circuit, will provide real-time data from many points on the circuit, allowing more accurate depictions of power flows. That will provide greater accuracy in understanding what’s happening on the grid and allow more options for, say, rerouting power in an outage.

Situational awareness for the computer “In a model-centric system we have a very detailed model of the system that we continually run power flows on,” Scirbona said. “The model is hooked up in real time to field devices, which constantly deliver real-time data. The power flow takes that real-time data and scales it between devices so that you have an accurate depiction of the system—every asset on the system, not just devices, but every wire, every transformer, the whole system. So the system has either a realtime value or a calculated value associated with it. “It’s situational awareness for the computer,” Scirbona continued. “The computer now knows what’s going on in the entire system. The computer is looking for a device in the field to change state or, let’s say, clear a fault. There are some “The model-centric system will clear a fault automatically. That change of state is reported tremendous effiback to the computer system, which then polls all the devices on the primary circuit and its ciencies to be gained backup. From that information, and having knowledge of the entire system, the computer by optimizing for the makes a selection as to the best way to restore the system.” entire year versus Because it has knowledge of the system, the way the system re-routes on-peak may be difjust the peak period. ferent from how it re-routes off-peak, Scirbona added. The response is designed to be sure that it doesn’t violate any user-set parameters—such as emergency voltage levels or emergency loading levels—and maximize the number of customers restored.

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Groundwork began early The impetus for O&R’s work began in 2006, prior to the onset of smart grid hype. “Essentially, we used to have low-level automation,” Scirbona said. “Just recently we’ve gotten to the point where we’re getting hands-on SCADA. We’re putting a SCADA system in so we can do a model-centric approach. “Prior to getting into this we didn’t have a SCADA system,” he continued. “In 2006 we started to make a determination of what sort of system we wanted, how we wanted to communicate with that system, how the system would communicate with field devices. We ended up having to build out our radio system and our communications backbone and also install a SCADA system. “Now the SCADA system, our improved radio network and communications backbone are serving as the prerequisite for what we term ‘smart grid,’” Scirbona added. “Once we had the prerequisites in place, we said, ‘Let’s take a look at using some model-centric kinds of controls.’” That approach required building a detailed model of O&R’s entire distribution system. Now that that work on system implementation is nearly complete, operations will begin to go live.

“By the end of the year I expect to have operating circuits under modelcentric control for auto restoration and by end of first quarter 2013 for coordinated control,” Scirbona said. Optimizing voltage for energy efficiency The coordinated control piece is about voltage optimization for energy efficiency, another ongoing project at O&R. “The plan is to take in all the realtime data and the calculated data and store it,” Scirbona said. “We want to be able to get at the energy usage on the circuit. So if we’re dropping voltage on the circuit to minimum levels without low-voltaging anybody, we want to see what kind of energy savings results. We’re also looking at loss reduction. By being able to do a coordinated volt/VAR control we can optimize the reduction of losses across that entire system of circuits. Normally you optimize for peak, but that’s only 300 hours per year out of 8,760 hours. So there are some tremendous efficiencies to be gained by optimizing for the entire year versus just the peak period. In order to do that you need to be able to coordinate the control of both voltage and VARs—that’s why it’s called ‘coordinated control.’”


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

Big advantage, not big brother ++Nashville Electric’s field crews see advantages to AVL IN AN INDUSTRY IN WHICH TECHNOLOGY IS RAPIDLY

evolving, sometimes there are positive messages to be found in the success stories of technology’s first iterations. In a May Intelligent Utility Realities webcast, “Going Mobile: Lessons in Workforce Management,” Vic Hatridge, Nashville Electric Utility’s vice president and CIO, talked about his utility’s first implementation of automated vehicle location (AVL) nearly 13 years ago. “We joined with our municipal fire and police Knowing where organization to build a new digital radio system that was deployed in late 1999. One of the features our vehicles were that we bought on that system was some digital data channels. The application that we identified improved the that would give us the most value from that was an AVL solution. efficiency of “We weren’t able to use it for data because the bandwidth was so low, but we immediately our operations. found that knowing where our vehicles were improved the efficiency of our operations. Our service dispatchers could locate vehicles that were physically close to an outage where they needed to send them. We also quickly learned, and our employees quickly learned, that we were tracking their progress and their location. We had anticipated a lot of union push back, but we actually had some very positive experiences as we used that system to assist our employees. “One night we had a service crew out looking for a set of fuses that had gone out. We have a lot of trees in Nashville, and it was dark. Unable to find the fuses, they radioed in, and the dispatcher told them to just drive along the street, and he would tell them when they arrived at the right spot. A few moments later, he said ‘Stop. Look up.’ Sure enough, they were at the correct location. “We also have ‘How’s my driving?’ stickers on all our vehicles. We got a call once on one of our crews. Someone said they were out in this area on this street driving too fast. We were able to go back through our AVL solution and determine that none of our vehicles were in that area anywhere near there at the time the customer had supposedly seen this incident. “So, word quickly spread with our employees that this was not just Big Brother watching them, but there was truly business value, not only to the company in our operations, but to the employees and their interests in protecting them and helping them if they became disabled or had a 911 emergency. Not only did we know they had an emergency, but we knew exactly where they were located.”

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Critical lessons learned To succeed, O&R added staff both for the current project and expected future work on distribution automation. But the significant efficiencies to be gained from improvements in storm restoration make adding staff a cost-effective decision. The additions included two smart grid engineers, a communications engineer, a protection engineer and a SCADA engineer. The new positions initially were provisional, but O&R decided to make them permanent to address ongoing distribution automation work across the entire system. That automation work includes increasing the number of reclosers more than 100 fold. The more reclosers, the more granular a storm response can be. O&R’s auto-restoration work enables it to isolate faults to 250 customer segments, down from 1,000 customer segments, immediately cutting the number of customers affected and helping pinpoint restoration efforts. “One of the most expensive things that a utility does is storm-related restoration,” Scirbona pointed out. “An all-hands-on-deck scenario can cost a small utility hundreds of thousands of dollars per hour. If you can use the auto restoration feature and you have granularity down to 250 customer segments, you’re cutting a lot of time for crews that used to do switching to restore as many customers as possible before they even started the restoration work. Even if you cut just eight hours’ work in a multi-day storm, at $175,000 per hour, that becomes real money fast. “We got punched pretty hard last fall,” Scirbona concluded. “But remember, these systems are not live yet. Did the storms bring attention to our projects? Well, internally, the light came on that this project is a very good thing to get into service.”

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CUSTOMER FOCUS

Making it real for utility consumers ++CenterPoint’s VP of customer services discusses the challenges around consumer engagement By Gregory Knight

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I THINK THE CHALLENGES ARE MANY IN TERMS OF THE

52

utility industry right now, as it relates to consumer engagement. It is well known that there’s a range of diverging opportunities that are driving transformation. On the one hand, we have grid modernization initiatives, and our regulators are really holding us accountable to transform the consumer relationship and to make the smart grid relevant and real to consumers. On the other hand, we know that consumers have a hard time understanding synchrophasing, switching We asked Gregory Knight, CenterPoint Energy’s and circuits. Thus, T&D technology division vice president, customer enhancement is difficult for the average services, who won Intelligent consumer to get their heads around when Utility’s 2011 KITE Award as discussing the benefits of the intelligent grid. Customer Service Leader of the So the best way for us to do that for conYear, to discuss what he felt was sumers is to make it real to them. And how the biggest challenge facing we make it real to them is we place an acute electric utilities’ customer service today. Here, in part, is focus on the channels through which we what he told us. interact with them like our Web, phone centers, text, mobile device, etc. Our big challenge right now is to really begin to develop the strategies that we’re going to have to deploy to make the marriage between these channels and our back-end distribution systems relevant to consumers. Internal and external pressure Outside of that we have other challenges going on, those challenges around how we think about consumer engagement in general. I always like to say there’s external and internal pressure: there’s a push and a pull. We’re being pulled in some ways by our consumers, and that’s because our consumers are benchmarking us outside the utility industry around experience. So if I can pay my phone or cable bill, if I can go online and do trouble-shooting, these are the types of things that the telecom companies began to do years ago. You used to call AT&T if you had trouble on your line, and they’d say “Hold a minute and let me check your line.” We’re being pulled by our consumers to innovate and transform in terms of how they interact with us by those expectations.

On the flip side, we’re being pushed by the regulators to drive greater efficiencies in terms of the reliability of our grid as well as providing consumers more information. The smart grid and the smart meters are one way to do that. But again, the way that we do that is through the channels in which we interact with consumers. So, more than ever before, you see us contemplating mobility, social media, Web interactions, and really thinking about how we react in our IVRs [interactive voice recognition] in such a way as to make these solutions more relevant for consumers, their expectations, and also delivering in terms of regulators’ expectations.


There are a lot of things that we can offer them, but there’s only so much you can offer a consumer on the traditional IVR platform until there are too many buttons and too much of a maze they have to go through.

Ensuring the value-add for the consumer Given that, it’s important for us to be very thoughtful about how we do this. So having a supportive leadership team, all the way up at your CEO level, is critical, and we have that. And so is bringing consumers into the equation in terms of getting that voice of the consumer to ask them what types of channels and what types of offerings are going to be value-adding to them. And so, as a part of our journey, we plan to have a group of consumers go through this journey to help us validate things that we’re putting out there for them. It is important to start with the strategy, and then to start talking about what the solutions are to the strategy, and to be very outcome-specific. Depending upon what your focus is—whether it’s smart grid, or whether it’s driving greater efficiencies—being really clear on the outcomes and how they tie to that strategy is a critical success factor.

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For example, at CenterPoint we have begun to offer multiple capabilities in our IVR. The challenge and the problem that we find is that there’s only so much that you can add to the touch tone IVR before you reach a point of proliferation. Every time a consumer has to do something, they’re drilling down another level in the IVR menu. At some point they get fatigued, and so they zero out, when they really want a self-service. One of the things we’ve contemplated at CenterPoint is using natural language capabilities in the IVR as one way for us to flatten that IVR experience out for the consumer, so that when a consumer calls in, they can just talk in their own language.

Starting with a customer vision How do you flatten that out? In the future, one of the things that the smart meters allow us to do is to ping the meter to determine if in fact we do have voltage going to that consumer’s home. That’s something that could easily be done in an IVR. CenterPoint is developing the kind of distribution operations capability to support this. But how do you add that with payments, extensions, changing your billing information and more? This is when it becomes a lot more complex. The way that we’ve tried to approach it is to start with a customer vision, or who we want to be to our consumers. What is CenterPoint Energy’s vision for its consumers? We are contending with the transmission and distribution relationship with the consumer in a deregulated market. We are contending with a meter-to-cash relationship with a gas consumer. We also have consumers who have appliances service plans. These consumer relationships overlap across these different products and services. This is one of the reasons why we have to be strategically thinking about who we are going to be to our consumers: how do we now present the appropriate options, segments and channel strategies in a way that adds value to the consumers and doesn’t confuse? We’re starting with a strategy in determining through segmentation analysis and process design what channels we should be offering up to what consumers, and by what capabilities, and how this is going to benefit them and also benefit the utility in terms of our ability to become more efficient and to be the trusted adviser. At CenterPoint, what has made me excited about it is that our senior executive team gets the value of consumer engagement from a utility perspective. We are a services company; we provide services to consumers. Sometimes I joke that, within our industry, the utility is always fighting the last war as it relates to what we’re offering consumers. We’re always sitting around the room saying, “Hey, Bank of America can do this” or “AT&T can do this, why can’t we?” So one of the things that we have contemplated is a much more forward-looking strategy. When you start getting really serious about consumer engagement transformation, especially leveraging technology, sometimes these projects can go anywhere from one to three years. Our journey is definitely going to be three years at this point, looking at the total complement of consumer transformation.

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CUSTOMER FOCUS ??

We need a more up-to-date distribution grid to manage an

Consumers getting more savvy

increased number of renewable power sources, which many states are now requiring. ??

meters, consumers will be able to see their electricity usage

++New SGCC report indicates

at any time and make choices

support for positive messaging By Kate Rowland

With smart grid and smart

to save money. ??

With a smarter, highly responsive grid that more efficiently manages supply, storage

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NEW RESIDENTIAL ELECTRIC CONSUMER RESEARCH DONE

54

for the Smart Grid Consumer Collaborative (SGCC) in April of this year is encouraging, as utilities continue to move forward with intelligent technology deployment projects. In-depth interviews were conducted on behalf of the SGCC by Market Strategies International with 24 residential electricity customers spread across three key cities: Atlanta, Los Angeles and Chicago. In mid-June, the SGCC released some of the key findings in a 20-page report, “Consumer Voices 2012.” The section on smart grid messaging, an area of prime importance to electric utilities as the two-way conversation with consumers continues to grow, was especially interesting. Both positive and negative statements about smart grid were reviewed with study participants, with half of the participants hearing positive messages first, and the other half hearing the negative messages first (so as to avoid order bias). Participants were asked to read each list of statements and identify those they found most persuasive, the ones that would do the most to influence their feelings, positively or negatively, about smart grid. Interestingly, in general, participants found the positive messages more credible and persuasive than the negative messages. The most persuasive positive messages, overall, were the following: ??

Since the 1990s, smart grid technology has proven it can help utilities prevent blackouts and restore power faster if they do occur. As smart grid is implemented nationwide, reliability will improve.

??

Many components of our electrical grid are decades old and wearing out. Replacing them with smarter technology in a timely way will help ensure the consistent power delivery we depend on.

??

U.S. power demand will continue to grow. Without smart grid improvements, the already strained 20th century grid will not be able to meet 21st century demand.

and demand, fewer costly generating plants will need to be built and maintained— reducing costs that ultimately fall on consumers. ??

The electric grid built in the mid-20th century once gave our nation a competitive advantage. Today, even developing countries are building advanced electric systems. We need a smarter, modernized and expanded grid for the U.S. to remain competitive in the world. ??

Smart grid and smart meters will give me more control of my home energy use, helping me make smarter energy decisions.

Another interesting note: While the negative messages were considered less credible and persuasive, there were at least a few participants, the report indicated, “who found each of these negative messages persuasive or disturbing, and indicated that hearing such messages would erode their support for smart grid. Those in Atlanta seemed to be the least open to influence by the negative claims, those in LA the most, with Chicago in the middle.”


OUT THE DOOR

Transforming the customer relationship ++What electric utilities must do By Michael Gianunzio INVESTOR-OWNED AND CONSUMER-OWNED ELECTRIC

utilities need to address a new challenge in the next decade or they may become mediocre, obsolete, servant infrastructure to businesses who will take their customers away from them. The transformation of the electric customer is a new phenomenon and electric utility boards of directors and executive management cannot wait to respond, but must proactively meet this challenge head on.

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to survive the 21st century

Changing the customer relationship and behavior The next big challenge for electric utilities is to change their relationship with their customers and change customer behavior, so electric utilities can keep their customers and their business. This is about survival, not new lines of business. It is about changing electric customers from passive “So what? The lights come on� consumers to actively engaged consumers who want to use energy wisely. Customer energy literacy, in a new customer paradigm, should be a top priority. Electric customer communications need radical change and modernizing. To survive and flourish, electric utilities must become consumer coaches as well as power providers, and for some customers, they must become personal trainers, motivating customers to pick and to adhere to individualized energy plans and packages. Electric utilities must become proactive communicators with their customers, developing multiple communication channels to interact with and serve electric consumers, by way of the Internet, the Web, texting, mobile devices, smart phones and Twitter (and even more communications channels to come). Handheld devices are going to become the link to electric consumers for everything we do as utilities. Long gone will be the meter reader and customer service representative as we know them today. What used to be a poles, wires and power business is about to become an energy communications-customer relations industry. Electric utilities don’t want to come late to the game in crucial modern technologies like mobile, search, media and tablets. There has emerged in our society a seamless fusion of hardware, software, social networking, online shopping, data access and new forms of cyber-based social interaction. These new technologies have

55


OUT THE DOOR been embraced by all customers, in all generations, for seemingly every kind of transaction or interaction. Electric service is next in the queue for these technologies. What is this new relationship? Electric customers are about to be bombarded with Internet applications that promote home energy savings, and marketers will use that premise to capture other profitable services to consumers as well. Home energy audits, performance evaluations and energy usage monitoring will be combined with access to shopping for energy-saving devices, appliances and The next big challenge for computers and data that also will be linked to lots electric utilities is to change of totally unrelated applicatheir relationship with their tions and things to buy over the Internet. customers and change What will be lost is the old utility-customer relacustomer behavior, so electric tionship. Left unchecked or utilities can keep their unchallenged, electric utilities won’t have direct cuscustomers and their business. tomers anymore; Internet, media and telecommunications companies will have the electric customer relationship as just one aspect of their relationship with the customer. The thousands of electric utilities operating today across America will be viewed as the old backbone, backwater infrastructure, like the roads, sewers and water pipes that are just there to be used up, and need to be fixed upon occasion. And electric utilities will have to be there to fix everything at their cost, so Internet companies and energy service marketers can make a profit on the relationship electric utilities used to have with their customers.

Not only do electric utilities have to act now and pre-empt the invasion of these marketers and Internet giants on their customer turf, they need to take on the things that these companies will offer, or find ways to partner with these marketers, to survive. And electric utilities will have to be proactive in Congress, state legislatures and regulatory agencies, showing federal and state officials that electric utilities can do all these things being promised, and do them better. Changing customer behavior The most successful and powerful way to permanently change behavior is to change social norms. When people find out that their neighbors are more successful than they are at anything, they want to know more, and want to meet or beat them. Peer pressure can be very effective. And for those couch potatoes who don’t care what the neighbors do, they will probably need financial incentives to inspire significant energy consumption behavior. Michael Gianunzio is chief legislative and regulatory affairs officer for the Sacramento Municipal Utility District. This article was excerpted from a longer essay. The full essay can be read here: http://bit.ly/MzvXZB

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+ ©© ADVERTISER INDEX

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back cover

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7

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Structure

17

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Utility Analytics Institute

inside back cover

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Utility Analytics Week

42–43

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Verizon

5

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Intelligent Utility JulAug2012