Issuu on Google+


Where smart grid meets business—and reality.




3 utilities share strategies for smart grid success

Optimizing the electricity evolution: lessons learned The changing power generation equation




32 Distribution automation shapes future system

PPL and Avista initiate infrastructure upgrades

34 SCADA cyber attack

Some believe Stuxnet worm marks new age of supercyber weapons




Strategies for success: UtiliQ 2010’s Top 3


San Diego Gas & Electric UtiliQ’s most intelligent utility forges ahead

18 Austin Energy

No. 2 utility credits a proactive community


Testing technologies off-the-grid proves valuable


Optimizing the evolution

22 Managing the changes

Utility executives discuss the issues

Intelligent generation equation

26 Power generation equation is changing

Seattle City Light focuses on energy optimization

12 34 52 54 56


Drawing the line


Transmissions 6

Letters from readers


Intelligent Utility defined

10 The big picture

10 Top 11 movers and shakers 12 Consumers Energy’s measured steps

48 Grid(un)lock

48 Answering vexing questions

50 End of the Line

50 Fostering rapid demand response action

52 4D

52 IT and executive champions play crucial role

54 Connections

54 Dynamic pricing gurus needed

56 Out the door

56 More than just meters

Vol. 3, No. 1, 2011 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.

How do you design for future smart grids? Advanced metering infrastructure…smart grid…automation… demand response…meter data management…stimulus grants… regulatory hurdles…customer acceptance…standards…return on investment… So many decisions, so much change. You know each choice affects the other but how do you integrate the elements, manage the risk of obsolescence, and continue to deliver reliable, quality service at a reasonable cost and a favorable rate of return? Balancing technology risks with business imperatives has never been harder. KEMA leverages 80 years of utility technology knowledge and its expertise in global business consulting to help you map a strategy, design a system, test components, deploy new infrastructure and reap the rewards. With a focus on smart integration, KEMA provides solutions that help you maximize business outcomes while minimizing future technology risks.

Visit or call: 1.800.892.2006


It’s time to celebrate leadership THIS ISSUE OF THE MAGAZINE, THE FIRST OF 2011, IS ALL ABOUT WINNERS,

leaders and pioneers—those who stick their necks out and aren’t afraid to lead the pack, despite the risks involved in blazing new paths. I’ve been looking forward to this issue for months: like the joyous celebrations that rang in the new year, it’s time to truly celebrate our industry’s successes and, with them, the men and women who have helped to move the electric utility industry forward. Three of these leaders were honored for their work with Intelligent Utility KITE Awards at the Knowledge Intelligent Utility Executive Summit in Scottsdale, Arizona, in November. You can read about the KITE (Knowledge, Innovation, Technology, Excellence) Awards, and find out about those who were honored, in a special supplement to this issue. At the same summit, the Top 3 UtiliQ 2010 Utilities of the Year, first announced in the July/August 2010 issue of Intelligent Utility, were also honored. You’ll find profiles of all three, and an overview of some of their projects, in “Strategies for Success” [see pp. 14-20]. The leadership theme carries on throughout the stories within these pages: ??

Nearly every new smart grid application provides utilities with new and better information to optimize grid operations, real-time costs and more. Christopher Perdue sat down with seven utility executives from across the country as they shared the lessons they’ve learned along the path.


When ComEd and PECO, both Exelon Corp. utilities, began to implement a project to provide a mobile dispatch and workforce management platform that impacted virtually all aspects of the utilities’ operations, one key factor driving the project’s success was the direct involvement of executive leadership who championed the cause. Joe Kovacs tells their story.




Sometimes it’s a matter of putting products and technology through their paces in an off-grid laboratory environment that ensures successful interoperability for the utility. Phil Carson visited Consumers Energy’s Smart Services Learning Center in Jackson, Michigan, to learn more about the utility’s measured steps.

The stories found within these pages are but a few of the success stories we will be telling in the coming year. I encourage you to join us in celebrating industry achievements—and sharing your own—as we boldly stride into the “Year of Many New Deployments.”

Kate Rowland Editor-in-Chief, Intelligent Utility magazine

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Letters from readers

the big picture age and its use? I see the industry answering some of these questions with pilots in the coming year.


Top 11 projections for 2011

some utilities realize they don’t need Ami, and Amr will suit them


electric vehicles begin to push the limits of distribution transformers by the end of 2011. Utilities across the country in early-adopter

areas are already well aware of the potential for neighborhood-by-neighborhood electric vehicle (EV) adoption to strain the limits of some distribution transformers. Already, a handful of utilities are launching EV pilots with consumers in an attempt to determine what incentives (or disincentives, such as time-of-use price variations) will drive off-peak charging activity, whether daily travel needs and lifestyle make time-of-use pricing irrelevant, and whether concentrated charging of EVs will lead to an increase in transformer degradation.

Editor-in-chief, Intelligent Utility Daily 303.228.4757


New interoperability standards will begin to flow more quickly,

now that NisT has broken the dam. I also believe that we will begin to see cyber security standards flowing more quickly to the fore.

Christopher Perdue


Ferc will continue to move forward aggressively in the demand

response arena. Perhaps I’m cheating by adding this one, as it’s a bit of a no-brainer. FERC Chairman Jon Wellinghoff is clearly deeply committed to the demand response issue and will shepherd it through to fruition.

Vice President, Sierra Energy Group

9| 310.471.7396

social media will continue to play a growing role in industry


intermittent renewable generators test the limits of stable, reliable power. Similar to

the impact of electric vehicles on the demand for power from the grid, the “push” of distributed photovoltaic systems is seeing tremendous growth in states such as California, which has incentivized it. But with that kind of growth comes evidence that the distribution side of the equation is going to see circuits with voltage fluctuations as a result. As Lee Krevat of San Diego Gas & Electric told a conference audience in October, “Fluctuation of the voltage on the primary is very, very bad—it is not good electricity at all. It’s not the kind of electricity our customers want to have, and not the kind of electricity our equipment wants to have.” Energy storage on the

distribution circuits could resolve the issue, but who pays for it? The utility? The entire rate base?


energy storage becomes a front-and-center, immediate

need. We all understand that energy storage can mitigate the integration of renewables, and will work well as a firming resource. But there are still so many questions to be answered. Do we need to solve the intermittency issues at the transmission level, the distribution level, or point of use? Is a battery more valuable near the load rather than at, say, the wind farm itself? Can substation-sited storage become a reactive power supply and therefore a reliability asset for the utility? And, equally as important, what will be the payment mechanism for energy stor-

communication. Twitter and Facebook are playing an increasing role in utility and vendor communication, both to consumers and with each other. LinkedIn, too, has lively and ever-growing professional networks in which industry issues are debated in an extremely active fashion, building collective industry knowledge and providing safe spaces in which to toss new ideas into the mix for others to digest.

Ken Silverstein Editor-in-chief, EnergyBiz Insider


strategic vendor partnerships will continue to grow and offer more comprehensive solutions. Late 2010 brought with it a number 304.345.5777

of all-out company acquisitions, but it also saw a number of strategic partnerships, such as those between Cisco and Itron, Lockheed Martin and Tendril and many more. As vendor solutions become even more comprehensive, we will see an increase in these partnerships in the coming year.



utility business processes will get more scrutiny as utilities determine how they will deal with the massive influx of new

data. The credit for this particular bit of crystal ball gazing goes to David Elve, vice president of industry solutions for Sensus. From toaster to turbine, Elve says, each utility “needs to have a summit, if you will, of all stakeholders” to define what the asset is, whose asset it is, and how it will be handled. “You need to flesh out where these assets reside, and then figure out what standards apply.” This will truly be a major shift in the utility company’s processes. These are but a few of the changes we see in store for our industry in the coming year. Distribution will be high-visibility via a more honed-in focus on distribution optimization, distribution management systems, distribution automation and more. It will have to be, given what we’re about ready to add to it.


Mike Breslin, John Johnson, Phil Johnson, Joe Kovacs, w w w. i n t e ll ig e n t u t i l i t m

www.intelligentutilit /// novem ber/decem ber 2010

negative press about consumer pushback in early smart meter deployments. Unfortunately, the negative coverage of the pushback gave little room for focus on a growing number of utility success stories. In the coming year, both utilities deploying smart grid technology and those who aren’t yet doing so will focus their efforts on increased consumer education. Oh, and the general media will stop focusing so much on the negative and focus their efforts on the positive. (Yeah, right. Well, industry media, at least, will do so, and hopefully this will extend its reach to the general mass media.)

Phil Carson

financial cat, as Michael Ebert and Joseph Fichera have noted in this issue of the magazine in an article about smart grid cost mitigation bonds. While there is no question that stimulus funding was a welcome boon to the industry, it was also without doubt a double-edged sword, slowing the industry down to a crawl while it waited with bated breath to hear which projects would receive government funding and which would not.

The crysTAl bAll is AlwAys A liTTle murky As we




As the economy begins to turn, venture capital and other investment will continue to increase. There’s more than one way to skin the

by Kate rowland

increased consumer education focus. This year brought with it some 720.331.3555

just fine, with better back-office systems. For a good example of this, see the story about Bluebonnet Electric Cooperative in this issue’s “Can one smart grid fit all?” feature. One smart grid doesn’t fit all utilities. Some are finding unique solutions to unique needs, within a budget that works for them.

++A new year begins with a new approach

approach December and attempt to peer into the foggy depths of the year to come. It’s always that way, despite our best efforts to define what the future will bring. It reminds me a lot of those coastal California “I can see for miles and miles” days, when the marine layer abruptly rolls in, and even seeing across the street (or, in the case of the industry, into next month) becomes nearly impossible. Some trends, though, have become more clearly evident as we move from the Year of the Smart Grid Funding into the Year of Many New Deployments. The year 2011 will bring with it many new challenges with ties back to 2009 and 2010, but the era of the intelligent utility is clearly evolving, being fuelled by information gleaned both from past successes and past mistakes. All would agree, prognosticators and historians alike, that there’s a lot of change coming down the pike in the coming year. Some of it is in response to consumer/regulator pushback on the consumer-engagement/consumer-cost front, and some is directly related to new technology being added on the end of the line (electric vehicles and distributed solar generation) to a one-way distribution grid not yet ready, in many cases, to take the increased push and pull of electricity involved in these new applications. Here’s what the coming year is likely to bring:



Laurel Lundstrom, Elizabeth McGowan, J. Ian Tennant COPY EDITOR: Martha Collins VICE PRESIDENT, SALES/MARKETING SERVICES: Jennifer LaFlam 800.459.2233

Top 11 projections for 2011




I enjoyed your article and agree with you about the importance of energy storage. One underappreciated form of energy storage is distributed enduse thermal storage (cold or hot). Products with this type of storage are usually categorized as demandresponsive loads rather than as distributed storage. These products, when combined with timers or smart grid control, can be used to shave peaks, shift loads and do up-and-down grid regulation. The customer can be rewarded with lower-priced electricity or other incentives. Thermal storage can also be used to buffer the variable output of intermittent renewables. A way to greatly improve efficiency is to simultaneously heat and cool. One existing product that does this is a ground-source heat pump with a To contribute to the Transmissions department, please e-mail your submission to intelligentutility.editor@energycentral. com. Provide your name, address and daytime phone number. Letters may be edited for style and space.


desuperheater. With the heat pump operating in air conditioning mode the desuperheater uses waste heat from the air conditioner to provide virtually free water heating. A product that simultaneously heats and cools could use low-price off-peak electricity to simultaneously store heat and cold for later use. Michael Winkler

The Smart Meter Rollout Opportunity (Dec. 13/Intelligent Utility Insights)

Collecting information in the home (e.g., number/age of appliances, use of smart thermostat) and the customer’s interest in energy conservation (and energy audits) during the initial visit or installation could go a long way toward identifying those families most likely to engage and benefit from a new smart meter. Most of the energy conservation benefits of smart meters will come from a minority of customers, another application of the 80/20 rule. Knowing who those customers are and starting the smart meter conversation can speed adoption, understanding and energy savings. Jeff Fread

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electric I water I Gas I aMI I Dr I Da I MDM I outage Management I Conservation Integration I Deployment I Business Case Support I regulatory assistance


What is an intelligent utility? + It’s all about delivering information-enabled energy.

Energy Central examines the possibilities of the intelligent utility in terms of: ??


The knowledge, skills and abilities required in an informationenabled environment ??


Business objectives and their

An intelligent utility applies information to energy, maximizing its

impact on process and smart

reliability, affordability and sustainability from generation to end users.

technology deployment ??


The challenges and opportunities of new paradigms ??


Investment trends associated with smart technologies ??


The impact of politics on energy

CONTRIBUTE We welcome your voice, and your thoughts, as we all contribute to the emerging intelligent utility. Here is how you can reach us:

INTELLIGENT UTILITY—THE DIVISION Intelligent Utility is the division’s flagship, bimonthly magazine. Within its pages, we explore the strategies and realities of delivering information-enabled energy and building a smart grid, focusing on people, process and technology, economic models, finance and public policy. But Intelligent Utility is also a daily e-newsletter, a Web site, an annual summit bringing

Kate Rowland editor-in-chief Intelligent Utility magazine



together utility leaders to network with their colleagues, and a research, analysis and consulting services division. Beyond the boundaries of the magazine, we provide: A companion for Intelligent Utility magazine, this Web site provides


a deep look at the smart grid and the systems, processes and people necessary to delivering

Phil Carson

Intelligent Utility Daily: This daily e-newsletter offers insight far beyond the news of the

editor-in-chief Intelligent Utility Daily 303.228.4757

information-enabled energy.

day, delving deeply into the issues facing the electric utility industry as it moves to implement smart grid/intelligent utility projects and processes.

Sierra Energy Group, a division of Energy Central: Sierra provides information technology and smart grid research, analysis and consulting services to leading electric and natural gas

Christopher Perdue

utilities and vendors to the industry.

vice president

Knowledge Intelligent Utility Executive Summit: This annual event brings together

Sierra Energy Group 310.471.7396

Mark Johnson vice president Intelligent Utility Division 303.228.4721

leaders in utility operations, IT and customer service, allowing them to come together in a constructive forum to share the lessons they are learning and avoid the costly stumbling blocks that create barriers to success. In a relaxed environment, these leaders can network with their colleagues, learn of new solutions from their peers (both inside and outside of the utility industry) and walk away with high-impact knowledge takeaways.

Intelligent Utility Reality Webcasts: This series of monthly webcasts provides realworld perspectives on how energy providers are building intelligent utilities to deliver on the promise of information-enabled energy. These webcasts examine the challenges and opportunities utilities face in implementing smart grid initiatives and focus on topics such as distribution automation, metering, demand response, asset management and more.


Top 11 movers and shakers ++Industry leaders shape the future By Kate Rowland



TERRY BOSTON The president and CEO of PJM Interconnection has a 35-


year history in the electric utility industry, and leads or has served on a massive number of integral industry committees over those years. PJM and its members have been industry leaders in working together to adopt new technologies and new ways of using electricity and technology to enable more renewable energy and greater energy and cost efficiency.

ANN CAVOUKIAN While not an electric utility leader, Ontario’s Information and Privacy Commissioner managed this year to make an enormous impact on the utility industry with her Privacy by Design approach to utility customer data. Optimizing the interests of both electrical reform and privacy, the approach embraces a “positive-sum” principle, seeking to accommodate all legitimate interests and objectives in a win-win manner.

STEVEN CHU Love him or hate him, the United States Secretary of Energy has made no bones about his passions: energy efficiency, renewable energy, smart grid, and more. Under media scrutiny at the end of the year concerning rumors of his early departure from the Secretary’s office, Chu has remained stalwart in his focus. Remember: one man does not a department make.

PETER DARBEE The chairman, CEO and president of PG&E Corp. has stared adversity in the eye over the past year and not let it bow him or the company he leads. Faced with consumer pushback (and the resultant and overwhelming media coverage) in a few of the utility’s smart meter deployment areas, Darbee stood tall, argued the meters’ and the company’s merits, and has focused his utility on moving forward and incorporating lessons learned.

CHARLES DICKERSON PEPCO Holdings’ vice president of customer care has shown a prescient focus all along on the ultimate importance of customers in the smart grid equation. In fact, he said in an interview early last year that many in our industry have focused too much on the devices—the technology—and not enough on what he calls the “end game,” or changing customers’ behavior. Dickerson’s point: education is about conversations, not commercials.

LEE KREVAT The face (and director) of San Diego Gas & Electric’s smart grid initiative, Krevat is managing a dizzying number of rollouts,



utility industry is always a tough call, and it’s especially tough this year, as there are so many of them, and I am limited to choosing only 11. There were many standout utility leaders this year, as the continuing evolution of our industry moved very quickly, especially in the latter half of the year, as long-awaited stimulus grant contracts were finally signed with the U.S. Department of Energy and projects began to move forward in a meaningful way. The electric utility industry has often been accused of moving slowly, and many would agree that there are numerous reasons for that cautious approach. Some are political, and some have more to do with the traditional focus of the industry: 99.999 percent reliability. But there are also those who, while still careful and cautious in their approach, have a vision of the future that is clearer than most. Yes, there are most definitely more than 11 of these leaders, and therein lies the difficulty. Whom do I choose? Whom do I leave out? It’s been a hair-pulling winnowing process, and there will be those who won’t agree with my choices. I welcome you to submit your own, and we’ll keep an ever-growing list as the year goes on, for review at the end of 2011.



There are those that have a vision of the future that is clearer than most. BEN LAPIANTA As vice president





of the only utilities in Ontario not to have issues reading meters that resulted in billing inaccuracies. LaPianta was awarded the 2010 Intelligent Utility KITE Award for Operations Leader of the Year.

MICHAEL LOWE Salt River Project’s customer service executive has shaped service delivery as a means to increase competitive advantage at the third-largest public power agency in the nation. His team has accomplished what many believed to be impossible—providing pre-pay and dynamic pricing systems to over a third of the utility’s customer base using a legacy CIS and billing system. He received the 2010 Intelligent Utility KITE Award for Customer Service Leader of the Year, acknowledging his pioneering leadership.

JAMES ROGERS Duke Energy’s CEO is a no-regrets innovator, walking a tightrope of designing new products for the customer, listening to what the customer wants, all the while keeping in mind that “the customer doesn’t necessarily know what he wants yet” but not operating in a mother-knows-best role at the same time. Sound confusing? Welcome to 2011—every utility in the country will be walking that same tightrope this year.

GLENN STEIGER The general manager of Glendale Water & Power has been a busy man lately, leading his utility in deploying one of the most comprehensive smart grid projects in the country. In addition to deploying smart meters to its 84,500 electricity customers, it is simultaneously rolling out 33,400 smart water meters within its territory. In the near future, Glendale’s customers will receive real-time data on both their water and energy usage.

MAHVASH YAZDI Senior vice president for information technology and business integration and chief information officer for Southern California Edison, Yazdi has been a recognized innovator in the industry for the past decade. Since she joined Southern California Edison in 1997, she has shepherded the utility through a massive ERP system implementation and associated business transformation initiative. She received the 2010 Intelligent Utility KITE Award for CIO of the Year in recognition of her efforts.


of distribution grid management for the Toronto Hydro-Electric System, LaPianta led the rollout of both smart meters and time-of-use rates for virtually all of Toronto Hydro customers. One of the largest municipal electric distribution utilities in Canada, the utility was mandated by the Ontario government to introduce smart meters and time-of-use pricing, and Toronto Hydro has done so with very few bumps in the road. In fact, it was one





from smart electric and gas meters to a desert-based microgrid demonstration project, and plug-in electric vehicles to demand response and energy efficiency programs. The goal: supplying 33 percent of customer energy needs with renewable resources by 2020. SDG&E has topped the Intelligent Utility/IDC UtiliQ list of the most intelligent utilities in the U.S. two years running.



Consumers Energy’s measured steps ++Utility tackles AMI, focuses on customer needs By Phil Carson




think, a flair for analogy and a sense of timing. As he guides a visitor through Consumers Energy’s Smart Services Learning Center in Jackson, Michigan, explaining distribution automation or in-home energy displays, Longcore combines professorial erudition with a magician’s sense of drama. He sets up a potential scenario and flicks a switch. “Lightning” flashes, a tree limb falls, a circuit goes out and a recloser restores the simulated grid. How would that affect a customer? He enters a simulated home environment and segues to energy management options without pause. A moment later, Longcore, who serves as the utility’s director of enterprise architecture and standards, cracks open a door to a back room. A visitor glimpses racks upon racks of “smart” digital meters wired to servers—the reason for my visit and his current, in-house focus as his utility rigorously tests and assesses advanced metering infrastructure, or AMI, for future deployment. Assisting nationally, evaluating locally “Think globally, act locally” applies here. Consumers Energy stands out for its measured steps to assist national efforts toward standards and interoperability even as it painstakingly evaluates systems destined for its own service territory. (As his title implies, Longcore splits his time between the two efforts.) The utility is also ensuring that what works in the lab will scale to the utility’s sprawling territory.

“We’re ensuring that this larger environment isn’t an assumption,” Longcore told me. “We’re ensuring that it truly has been engineered to work cohesively,” he said. Consumers Energy’s dual approach—testing and assessment for its own system, participating in national standards and interoperability efforts—aims to produce the best results at home while contributing to an ecosystem of interoperable, cheaper technologies. “How can we drive the entire cost curve down by achieving economies of scale?” Longcore asked, rhetorically. “We’re not locking ourselves into a Consumers Energy-only vision. We have to take a larger view. Not because we’re altruistic. We’re doing this because it’s simply a requirement to enable customers to buy and use interoperable devices throughout our service territory, where there are other investorowned utilities, municipals and coops. And we need to ensure that our customers will be able to buy devices from a larger smart grid ecosystem.” Exploring both sides of the equation Consumers Energy, Michigan’s second-largest natural gas and electric utility, provides service to more than 6 million of the state’s 10 million customers in all 68 counties in the state’s Lower Peninsula. (The utility has 1.8 million electricity meters and 1.7 million natural gas meters in its service territory.) Michigan has been particularly hard hit by the national recession and the Michigan Public Service Commission has emphasized value and financial restraint to its utilities as they approach grid modernization. As the utility has explored systems design and standards development for smart grid and fleshed out its technology roadmap, it has also explored the customer side of the equation. “What are the opportunities out there?” asked Sue Swan, vice president

for smart grid development. “How will our customers react? How interested will they be in dynamic pricing, for example? What comes to mind when you throw out the term ‘smart grid’? “First, we found that the level of knowledge and understanding about smart grid is very low,” Swan told me. “Second, we found that residential customers are not all the same,” she added. Consumers Energy customers are variously interested in the new technology and control over their energy use, cost-conscious, eco-conscious or comfort-oriented.

or energy use feedback via in-home displays or Web portals. The third step is “empowerment,” or a choice among options (rate plans, for example).

A sequence of systems The technology roadmap, of course, is considerably more complex. At the Smart Services Learning Center, a large flat screen offers a geospatial look at the Consumers Energy service territory, including terrain, natural features, vegetative cover, cities, roads, buildings and the grid itself. Longcore, with remote control in hand, clearly enjoys dazzling a visitor with a demonstration of how those elements combine, underscoring his points on the utility’s choice of various smart grid elements such as meters, mesh networks, backhaul networks and how natural and man-made elements might affect them. “For Consumers Energy, one of the first steps is to gather geospatial information and ensure that our GIS is capable of dealing with distributed devices such as meters,” Longcore said. “The second step is understanding how this larger information model and architecture are going to work together,” he continued. “Without that, if we build systems that don’t have interoperable standards for data, then we’ll end up with What’s important many interfaces that cause us long-term problems. Over the past year, pilot studies of “We’re taking a ‘layered’ approach to systems,” Swan said. “You have to have consumer involvement with basic or foundational systems first to deliver basic functionality and the ability to mandetailed energy use information, with age large quantities of data. If you look at the existing and without in-home foundation, that would include enterprise software, an displays, with static We’re not locking outage management system (OMS) and a geospatial and dynamic rates, information system. Those are the tickets to entry. has given the utility a ourselves into a Advanced metering and the communication network clearer sense of how its to support it would be the next layer.” customers will respond Consumer Energy“If you want to leverage that investment and get to new options. full functionality out of your smart meter and com“To be successful only vision. We have munication network, then you need to go to the next in smart grid deploystep,” she said. “That might mean adding devices that ment and deliver value to take a larger view. provide self-healing capability like a more robust dison the investment, we tribution management system. We recently upgraded really need to have our our GIS and replaced our OMS systems; the distribution management system is customers on board,” Swan continued. something we are just starting to evaluate.” “We need to know what’s important to them and make that part of the Network needs differ program. This has a two-fold impact; a For Consumers Energy, a “hybrid network” will deal with distributed grid depositive response from our customers vices differently than customer devices, according to Longcore. will result in more support from our “We believe that some portions of that hybrid network will be a private regulators. We are developing a vision network, based on our need for reliability, security, throughput, latency and statement that details the customer other factors,” he said. “And we believe other portions of that communications benefits of smart grid, in the context network will be public networks.” of supporting Michigan and our “The unknowns?” Longcore mulled. “We’re deploying a change in how customers get information and how they react to that information. Eventually, economy. Not the technology or the they’ll receive energy use and management information on mobile devices and business case, but what’s important to have the ability to respond on the go. our customers.” “As the rise in the intelligence of devices in the home rivals the rise in intelConsumers Energy has a set of mealigence of cell phones over the past 20 years, that shift in how the grid works will sured steps for consumer involvement, be as different from today as if we’d asked a bag phone user in 1990 what they’ll just as it has a roadmap for technoluse their phone for. We know they’ll interact with mobile applications. The ogy adoption. For consumers, the unknown is that we don’t know what those apps will be.” journey begins with “enablement” via

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


smart meters. Next, “enlightenment,”



for Success

UtiliQ 2010’s

TOP 3 1

Smart meter deployment nearly finished The utility’s smart meter program includes 1.4 million smart meters (which are all due to be deployed, as well as endpoints,

Leveraging technology to increase renewables Advanced smart grid technologies are clearly tools for SDG&E with regard to facilitating a state-required 30 percent

San Diego Gas & Electric ++UtiliQ’s most intelligent utility forges ahead W WW.INTELLIGENTUTILIT Y.COM /// JAN UARY/FEBRUARY 2011

By Kate Rowland




Energy’s San Diego Gas & Electric (SDG&E) led the pack as the most intelligent utility in the United States, according to our annual UtiliQ survey of this country’s electric utilities. San Diego Gas & Electric (SDG&E) is a regulated public utility that supplies power to 1.4 million business and residential customers spread across a 4,100-square-mile service area that includes two counties and 25 communities. The utility’s prescient move into the smart grid arena began with its implementation of a comprehensive smart meter system.

by the end of 2011), as well as 900,000 gas modules. These will enable a true smart metering environment that will allow for remote measuring of energy usage; provide twoway communication between SDG&E and the electricity meters, as well as communication inside the customer premises via home area networks (HAN); and also tie gas meters into the smart metering initiative. As well, the meters enable remote disconnect and reconnect capability for residential electric meters, and present data to consumers and customer service representatives through Web and phone (and eventually personal devices). SDG&E’s smart meter program also includes 57,000 programmable thermostats capable of communicating with the HAN. I asked Lee Krevat, director of the smart grid initiative for both SDG&E and Sempra Energy’s other California regulated utility, Southern California Gas Company, about the lessons learned from the utility’s smart meter implementation, after having installed its one millionth smart meter in mid-November 2010. “Customer outreach is crucial,” Krevat told me. “Security needs to be accounted for at project conception; it should not be added in later. Technology and use cases will continue to evolve,” he said. “Design with this in mind.”




reduction in greenhouse gas emissions, and supplying 33 in managing and adjusting power usage. Batteries will also percent of customer energy needs by renewable energy be installed on homes with solar panels, to aid in filling the sources, by 2020. I asked Krevat if he felt these stipulations gaps in power supplied from the panels during the day. These smaller batteries could also meant a change in the way SDG&E has approached feed emergency supply its smart grid roadmap (as opposed to Customer benefits back to the grid for a short the approach another utility outside period when needed. California may have taken). need to drive any “In addition to micro“Early in our implementation grid technology, the of smart grid technology, we were smart grid roadmap Borrego Springs project focused on more typical industry drivwill teach us about numerers: safety, reliability and efficiency,” and implementation. ous technologies, from batKrevat said. “While we continue to tery storage to fuel cells, to pursue those customer benefits, The benefits need to balancing load on a circuitwe are increasingly driven by by-circuit basis,” Krevat leveraging smart grid technolbe clear, communiexplained.“This technology ogy to increase integration of has the potential to lead to intermittent renewable genercated well and easy increased reliability.” ation and providing our cusThe electric vehicle revotomers with the data and tools to understand. lution is well under way to improve their efficient use within the utility’s terof energy.” To this end, as but one example, ritory, too. Krevat noted that Nissan Leaf battery electric SDG&E in the past eight months has vehicles began deployment in San Diego in midannounced three power purchase December. “In addition to providing energy independence agreements for solar photovoltaic for the U.S., the storage within these vehicles has the potential energy from California’s Imperial to reduce peak load, mitigate intermittency associated with Valley. These three agreements will renewable energy and decrease overall costs for the deliver approximately 300 MW of consumer,” he said. new renewable power to the utility’s service territory across SDG&E’s Consumer still key Sunrise Powerlink, a 120-mile, The consumer is key, according to Krevat, in planning a util500-kv electric transmission line ity’s smart grid implementation. “Customer benefits need to drive any smart grid roadmap and implementation. The due to be completed in 2012. benefits need to be clear, communicated well and easy to understand,” he said. “In California, customers have Desert-based shown a preference for increased choice, convenience microgrid demonstration The utility is exploring other smart grid technologies, and control of their energy usage, resource sustainability, too. SDG&E’s Borrego Springs microgrid demonstration greater efficiency, safety and continued ‘best of the west’ project, a three-year pilot program of sensors, commu- reliability. Utilities need to consider smart grid benefits nications and control equipment, has been designed to from a customer perspective.” SDG&E has implemented more traditional energy effiincorporate solar power generators on homes and small businesses, coordinate new peak load management tech- ciency and demand response programs and has also given its nology, leverage smart meters and integrate and remotely customers the option of accessing their hourly usage data via control distributed generation storage devices to allow Google’s PowerMeter. Residential customers with only one access to electricity in emergencies. It is scheduled to be electric meter installed at their premises, who have had the new meter installed for one to three months and are a meminstalled in 2011. Borrego Springs, a small town (population 2,535) on the bers of SDG&E’s online account services, are eligible to sign edge of the Anza-Borrego Desert State Park, will serve as a up for the Google PowerMeter program. The utility is ramping up its demand response offerings, as microgrid test bed for SDG&E to experiment with “self-healing” in the event of damage to part of the utility’s grid; to set well, according to Krevat. “We will soon be deploying a ‘peak up batteries to assist in smoothing peak usage; and to install time rebate’ program that will reward customers for conserhome area networks to assist the utility and its customers vation at times when energy is in short supply,” he said.



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Austin Energy ++No. 2 utility credits a proactive community

Energy kept a firm hold on its No. 2 ranking for the second straight year. The nation’s ninth-largest community-owned electric utility, Austin Energy serves 388,000 customers and a community of 900,000. Its smart grid program covers 440 miles, includes 500,000 devices and involves 100 terabytes of data. In addition, the utility is home to one of the nation’s most comprehensive residential and commercial energy efficiency programs, managing more than 90,000 smart thermostats in homes and businesses, which at peak times can aggregate to about 90 MW of load. Austin Energy’s GreenChoice, a utility-sponsored, voluntary green pricing program, currently sits at almost 800 million kilowatt-hours in subscriptions and is still growing. Austin Energy also owns the nation’s first and largest green building program, launched in 1990. The program has been so successful that it has allowed the utility to avoid having to build 800 MW in new generation since the program’s inception.

Voluntary green pricing success GreenChoice, Austin Energy’s voluntary green pricing program, has been named the nation’s most successful utility-sponsored, voluntary green pricing program eight years running, mostly comprised of contracts from west Texas wind. Surprisingly, of the 800 million kilowatts in subscriptions (and still growing), “the majority of consumers in the program are larger corporate and industrial customers,” Popham said. The reason? “They want fixed pricing along with the positives of ‘going green.’ Early adopters locked into a very competitive rate.” But with a 2020 generation plan that includes a goal of 35 percent renewables (right now Austin Energy’s generation mix is at about 10 percent, again mostly west Texas wind), Popham says he isn’t sure that voluntary programs alone are going to help the utility, and its customers, reach that goal. “We have to look at how that’s going to be part of the mix,” he said.

Quite a journey for early adopter “It has been quite a utility journey since Austin Energy first deployed 127,000 one-way smart meters and a one-way network back in 2003,” according to Karl Popham, the utility’s former interim chief information officer, “and interesting to watch how rapidly both the technologies and the market itself have been changing in recent years.” In 2007, Austin Energy upgraded its RF network to twoway, another major milestone for the utility. The hardware (meters, sensors, network gear, etc.) and software (applications, databases and network management tools), combined with a fiber and wireless telecommunications network, made up what the utility refers to as “Smart Grid 1.0.” “In 2008, we realized we wanted to know more how smart grid technologies can impact and empower the consumer side,” Popham told me. “Smart Grid 1.0 covered utility-centric smart grid activities with a focus on grid reliability and efficiecy.” Smart Grid 2.0, on the other hand, includes plug-in electric vehicles, rooftop solar and other distributed generation, energy storage, communication

Responsive and proactive Popham says a lot of Austin Energy’s smart grid initiatives are a result of “being reactive to customer demand, such as rooftop solar, plug-in electric vehicles, more clean energy and having choices and options.” He calls it a matter of being responsive to a proactive community. And, of course, as a community-owned utility, he says Austin Energy is able to be more creative up front in response to community input. “From a utility perspective, a lot of these areas [rooftop solar, plug-in electric vehicles, etc.] are both threats and opportunities,” Popham said. “They will be threats if we don’t change; they’ll be real opportunities if we can evolve and adapt. “Plug-in electric vehicles are a perfect example. If we don’t change, and retain flat kilowatt pricing, with no incentives about when EV owners charge and don’t charge, ultimately the neighbors will be subsidizing that flat pricing if EV owners plug in and charge right when they get home,” he explained. “Why not have incentives to encourage them to

By Kate Rowland




with smart consumer appliances and further improved customer services. “Our new customer care and billing system will come online in 2011,” Popham said, adding that the next major milestone anticipated after that will be to continue to integrate the deployed technologies to give the utility more realized value and options for its customers.

“Our traditional strengths are safety, reliability and tradicharge maybe at night, when the wind is blowing? Few folks tional engineering—very consistent delivery, big on safety are actually using that Texas wind at 3 in the morning.” Part of that creative responsiveness has also involved and big on reliability,” Popham said of the industry. Was this a challenge, when it came to deploying Smart Grid Austin Energy as a partner in the cutting-edge Pecan Street Project, defined as a “communitywide collaboration 1.0? I asked him. “Obviously, there were many challenges, and challenges are ongoing,” to fully reinvent the energy delivery sysPopham said. “There are tem.” (Other founding partners include They will be threats technical challenges and the City of Austin, the University of Texas, political challenges. And the Austin Technology Incubator, the if we don’t change; they run in parallel.” Greater Austin Chamber of Commerce I asked Popham, as the and the Environmental Defense Fund.) The they’ll be real opporinterim CIO and curorganization was successful in obtaining rently a division mana U.S. Department of Energy smart grid tunities if we can ager of a smart grid early demonstration grant in November 2009, adopter utility, what he felt and elements of the project are now evolve and change. was most important for being implemented. a utility at the beginning “To be successful in that space, it needs to be of its own smart grid journey to understand. “I would say, a collaboration,” Popham said of the project, which has understand first what you want to accomplish from a busireceived kudos country-wide for its scope and early efforts. ness value perspective, and then work your way there,” he New lessons: marketing to consumers said. “There is a lot of discussion of what smart grid is, and Hand in hand with Smart Grid 2.0 comes the knowledge it means a lot of different things to a lot of different people. that marketing is not typically a utility strength, and yet, “First, understand where you need to go, because there are that’s exactly the position today’s utilities are finding different strategies, dependencies and priorities depending themselves in, in order to effectively educate their con- upon what you’re trying to accomplish,” Popham concluded. sumers regarding smart grid technologies and the new “Have a common unifying purpose of what your metrics choices open to them. are for success.”


PG&E Corp. ++Testing technologies off-the-grid proves valuable By Kate Rowland WHILE CLIMBING FROM UTILIQ’S FOURTH


spot in 2009 to third place in 2010, PG&E Corp. also weathered a tempestuous media storm in the past year, and earned every point of its third-place finish. The utility first installed what we now describe as traditional meters to measure electricity used by customers in 1912. In the 1970s, PG&E began its first energy conservation programs, actively working to help its customers reduce the use of the company’s product. PG&E soon became one of the leading utilities in the nation in energy conservation, and remains so 40 years later.

Distribution automation driving improved reliability Today, the company has moved quickly ahead in its efforts to lay the foundation for the smart grid with its transition to SmartMeter™ technology. PG&E’s goal is to have in place 10 million new electric and gas meters by mid-2012, along with new energy management tools and capabilities, with the objective of improving customer service, increasing reliability, expanding energy efficiency and demand response, and optimizing the use of renewable energy sources and electric vehicles. As so much of the public and media focus in the past year has been on the utility’s smart meter deployment, I spoke with Kevin Dasso, PG&E’s senior director of smart grid and technology integration, about the other intelligent utility efforts PG&E is also working to implement. One of the biggest is its Cornerstone Improvement Program, a $366-million, three-year program recently approved by the California Public Utilities Commission to improve electric distribution system reliability for a number of the utility’s more than 5 million customers.



The program will use the latest generation of distribution automation technology to isolate outages and redirect power flows onto neighboring circuits. Such a strategy would restore service to as many customers as possible in the shortest period of time, using sensors and automated switches out on the circuits. “Our target is to do that in less than five minutes,” Dasso told me. “The reality is that it usually only takes about a minute.”


Wide-area awareness PG&E is looking beyond its distribution lines to transmission issues, too. In September 2010, it inked a deal with the Western Electricity Coordinating Council (WECC) and part of the Western Interconnection Synchrophasor stimulus grant project, and the utility is well into detailed design and prototyping at its test facility, and should have a prototype facility completed in the first quarter. Synchrophasors and phasor measurement units (PMUs) are a new evolving area, with the devices taking in data measurements 20 to 40 times per second. “First is getting the data, and that’s not a trivial matter,” Dasso said. “Then there is a different telecommunications system design; the ability to store the data, and to display it to operators in a way that is useful.” The monitoring system project PG&E is working on with the WECC will be implemented by early 2013. “Once it’s in place,” Dasso said, “it will continue to evolve for many years to come.”


Demand response and energy storage PG&E is also working with the California Independent System Operator (ISO) on an expanded demand response program. “We are testing the ability of our demand response programs with specific customers, to see how quickly they can respond to signals sent to us by the California ISO from a renewable energy resource area,” Dasso explained. “We want to see if demand can firm the intermittency of renewables.” PG&E is also testing whether the best response is automatic or manual in nature. “The reality is, it will need to be done in an automated way, built into building management systems,” he said. The utility has also launched a number of different energy storage projects to better balance the intermittency of distributed renewable generation. According to Dasso, there are four different types of energy storage projects under way. “A basic challenge with electricity is that it can’t easily be stored; it has to be used almost immediately,” he said. “So we are constantly balancing generation output with customer demand.” One project planned includes compressed air energy storage (PG&E was awarded a stimulus grant for this project, and is still finalizing its contract with the DOE), in which it would like to use an area with unique geological

formations to pump air in the ground and store it until needed to power a turbine generator. PG&E’s project is focused on providing 300 MW for up to 10 hours by using this compressed air storage. The first steps will be to do environmental studies, preliminary permitting and initial design work. The utility has also recently requested approval from the California Public Utilities Commission to develop a large pumped hydro storage project in the Sierras using nextgeneration technology that will provide the utility with a much shorter response time than traditional or existing pumped storage technology. On a more local level, PG&E is exploring battery storage on its distribution system, including a 2-MW battery at one of its substations to firm solar energy being supplied, and a 4-MW battery sitting on the distribution system away from the utility’s substations to provide ancillary services such as frequency response, load following and avoidance of sustained outages. Finally, it is has lined up almost 700 MW of demand response at customers’ sites including the use of thermal energy storage. Engagement: interesting, immediate, important There are really two different kinds of smart grid projects, Dasso told me. First are the projects that a utility can do on its own, that don’t require customer involvement. “These are more around technologies on the grid and how it works to deliver energy, and the processes are in place for them,” he said. And then there are the projects that directly involve customers. “The key here is engaging customers early,” Dasso said. “We’re focusing on doing that as we continue to deploy smart meters.” One way PG&E is engaging customers is via its Web site, where smart metered customers can access their hourly data the very next day, and clearly view how much electricity they used, and how much they paid for it. Currently, more than 250,000 PG&E customers access that personal data. “Customer engagement is really key. You have to find ways of making it interesting, immediate and important,” Dasso said.

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Optimizing the


Managing the changes ++Utility executives discuss the issues By Christopher Perdue A SMARTER ELECTRICITY GRID COULD FUN-

damentally change the way people pay for and manage their electricity use. Smart grid investments could help reduce demand, save money and improve reliability

and efficiency. But implementing the necessary changes can be challenging. Intelligent Utility recently sat down with a group of smart grid utility executives to discuss how the smart grid is impacting their companies and the lessons that have been learned to date. Their comments, edited for style and length, follow. WHAT DO YOU THINK WE AS AN INDUSTRY CAN DO TO APPEASE CUSTOMERS WITH THEIR CONCERNS ABOUT PRIVACY?

It’s interesting. I think that the customer is the owner of the data, where the security group keeps the repository. I like the Texas model where it’s actually centralized and someone else is looking after that. We have a privacy commissioner in Ontario that wrote a paper on how to handle the privacy issues, so we are mandated to hold it LABRICCIOSA




KREVAT You say the customer owns the data. I find that term

to be a little ambiguous because there are things that we need to do with that data. We need to bill off that data. We need to do system design around that data. We need to decide whether to replace the transformer based on how it’s being loaded, now that we have that data. So I look at it more as we have rights to the data. Our customers have the right to authorize

various parties to be able to look at that data and help them save money, but we have rights. We have rights to bill off the data and to do some design. So ownership makes it sound like there’s only one owner, and they get all the rights. And I think different parties need the data for different reasons. There’s a role and responsibility I guess that comes with the rights; unfortunately I think somebody has to actually be responsible to own it and keep it. Whether it’s a centralized approach or whether it’s the decentralized utility approach. LABRICCIOSA

Especially with regard to the personal information of our customers. When the customer decides they’re going to give the rights to somebody else, then you need to make sure it’s clear who has the responsibility for protecting that customer data. LAWRY


and keep it confidential, and only the consumer is able to see their particular data. There is a richness in the data beyond just energy consumption, and people are afraid that you can now try to discern consumer behavior beyond energy consumption based on what you see in the energy profile. And so I guess the approach in Ontario is to lock it right down until we figure how to handle that. So utilities are keeping that data, and I guess we’re the trusted souls to protect it.



You’re absolutely right. When you bring in the third-party applications like the Google PowerMeter, for example, that’s a channel. And so it’s a public channel, which is great because they develop applications a lot quicker and bring them to market. But it raises an issue when data is flowing through that channel. How are you protecting it if your role is to protect it along the way? Or do you just allow that open access? LABRICCIOSA

LAWRY In our regulatory environment, the customer has to

authorize, in writing, for us to send it to a third party such as Google. Once Google has their information, it’s really up to the customer then to manage their relationship with Google. Now Google needs to provide that oversight for the data, but we still want the overall relationship with the customer.

setting up the infrastructure to be able to handle the massive amounts of data. So I think it’s going to be more of building the skill sets internally within the utilities on how to use that data smarter, to be able to make sure the customers do get some value out of it. It’s not an easy world, but it’s there. The interesting thing is I feel comfortable we’re going to be able to manage the data and use the data smartly. The challenges I think we’re all dealing with now is that whole customer energy usage and the right of the data—who owns the data, how do you handle that data with third-party providers and how do you manage your customer’s data? Whose data really is it? So that’s our biggest challenge right now, and most of our focus, trying to work and set some policy on that. FRAZIER The Texas model is a little different in that the wires

delivery company is different than the retail electric providers, and you can switch retail electric providers in a very short period of time—so the PUC has made it very clear that the data belongs to the customer. They allow other people— BOOK Well I think what happened at the outset was the government really drove the smart grid to us. And now that like the utility, like your retail electric provider—to also see it’s here and we have our meters fully deployed we are faced that data for billing purposes and load management, but it with the task of making this data useful to our members. belongs to the customer and needs to be protected accordBut I think what we’re finding is education is key. We believe ingly. Texas is very clear around this issue. While we were very that the most important part of the smart grid is the cus- supportive of an AMI program, as a large investor-owned tomer being able to use energy information in some kind of company, we had financial viability concerns for such a large an actual form. And that’s the important thing, turning all project when the Texas Legislature first told the PUC to move forward with an AMI program. this data that we’re getting into the office into an The Commission then wrote the actionable commodity for the customer to use. The most imporrules and standards for the whole And it’s a challenge, but we’re finding ways to do it. state. Every wires company had to tant part of the LABRICCIOSA It’s an odd phenomenon. The meet these standards in the types government is driving this agenda rather than of meters and in how to provide smart grid is the the other way around. Never in our industry’s the data to customers, REPs and history do I recall the agenda being driven quite ERCOT. You had to have a portal customer being the way it is here. I feel that’s wrong, but it is and you had to have machineadvancing the industry. to-machine standard interfaces. able to use energy WITH THE SMART GRID IN PLACE THERE WILL The PUC decided that the way BE MASSIVE AMOUNTS OF DATA TO MANAGE, to do that was to collaborate, information in SO WHAT SHOULD UTILITIES DO TO PREPARE lay out common rules with the FOR THIS? advanced meter implementation some kind of an teams. We spent an unbelievable MCEVOY Utilities have been managing massive amount of time in Austin in these amounts of field data for a while, for a long time. actual form. committees coming up with the We’ve had SCADA, and been managing SCADA standards. Ultimately we decided data. I think that area is still going to exponentially grow, and there has to be a stronger infrastructure on that to that it would be easier and cheaper to have one source of data be able to handle and manage that data. The customer arena all using the same portal and automated interfaces. So as a is really where the complexity is coming in, from a couple result, all of the Texas wires companies are sending the data of standpoints. First, how do you handle all the data, how to an outsourced central repository to avoid different comdo you manage it; and then what do you do with it. We’ve panies keeping all of that 15-minute data. The models work developed a center of excellence within the company to be pretty well, and we feel that it’s less expensive as a result of able to start getting used to modeling, predictive modeling, each of us not having to develop these. It’s also easier if you’re and using the data smarter. Our IT group is also working on a large company and you want to go get the data for all of AFTER $4.5 BILLION IN SMART GRID STIMULUS, WHAT NEEDS TO HAPPEN NEXT IN TERMS OF NATIONAL ENERGY POLICY?



your gas stations in the state, you don’t have to go to four different utilities to do it; you just go to one central repository. HOW WILL SMARTER GRIDS, MORE DISTRIBUTED GENERATION AND MORE DEMAND RESPONSE, INCREASED INTERMITTENT GENERATION, AND ELECTRIC VEHICLES AFFECT THE WAY WE MANAGE THE DISTRIBUTION SYSTEM?

At Southern California Edison we are looking to manage many of these new devices through our distribution management system. Of course, this is going to be a new and improved distribution management system that is going to have more monitoring and control functionality than the current systems. The system will not only have to incorporate the devices and data, but the opportunities to optimally manage the system will increase exponenThe opportunities to tially. If all of this progresses as we are predicting, we have optimally manage the a very large complex system with a whole new set system will increase of applications optimizing across all of these interconexponentially. nected devices. This new distribution system and the applications to manage the system will not only be a technology challenge—requiring smart data management, new optimization algorithms, sophisticated control systems, and new customer programs for demand response and energy efficiency—but this new distribution system will also require a new process in distribution management. We expect a significant requirement to proactively manage resources at the distribution level and integrate this management more tightly with our overall energy management activities throughout the grid. This approach will not only require new systems but also require our engineering and operations personnel to collaboratively manage this new environment. So we are working with our technology vendors in the distribution management, work scheduling, asset management, and geographical systems to manage these new resources and devices. But we also know a real key factor is the visualization tools that are provided to our operations people to manage the complexity. The distribution world is going to look very different and the tools to manage this new environment and the skills required to manage the environment are going to evolve with the system complexity. We are in the middle of tackling the full-scale change out of our 5 million residential meters and have worked through the change impacts from this effort. We know going forward there will be more impacts on the technology front as well as the people and process sides that will keep us busy over the next couple of years.

THE EXECUTIVES LEE KREVAT Director Smart Grid Initiative San Diego Gas & Electric


BOB FRAZIER Director of Technology CenterPoint Energy

GREGG LAWRY Director Energy Delivery Technology Alliant

ROBERT SHERICK Manager Power Systems Technologies Southern California Edison

ROB BOOK Manager Government & Community Relations Delaware Electric Cooperative

IVANO LABRICCIOSA Vice President Asset Management Toronto Hydro-Electric Corporation W W W. I N T E LL IG E N T U T I L I T Y.CO M

BILL MCEVOY IT Smart Grid Program Integration Manager Northeast Utilities




intelligent generation


Power generation equation is changing ++Seattle City Light focuses on energy optimization By John R. Johnson SOME DAY, THE SMART GRID INFRASTRUC-

ture being assembled by utilities across the country will become a huge enabling tool for power producers and consumers alike. Although it is likely still two to four years away, a fully operating smart grid will allow for huge benefits like real-time asset management, new data management knowledge and news ways to manage bidirectional power flow on the grid resulting from expected increases in distributed generation.

“Reducing customer’s

Reducing distribution losses voltage by 1 or 2 Seattle City Light, for example, recently applied percent, customers for funding for an energy optimization project, the could save millions goal of which is to reduce distribution losses and of dollars in energy consumption for its customers by reducenergy costs. ing customer voltage levels, optimizing reactive power flow and balancing the distribution phase load. Seattle City Light is part of the nine-member Pacific Northwest Smart Grid Demonstration Project, which is testing various technologies in different use cases. Michael Pesin, chief technology advisor and smart grid architect for Seattle City Light, notes that by reducing customers’ voltage by 1 or 2 percent, customers could save millions of dollars in energy costs. Conservation voltage reduction stands to be one of the big benefits of a fully implemented smart grid. Typically,



Smart meters the first step Currently, smart meters are being deployed by the millions, helping utilities to isolate power outages more quickly and, in some cases, avoiding outages altogether. While smart meters are deemed the first step toward achieving a fully integrated smart grid, a host of infrastructure issues must be worked out in order to accomplish that goal. So while a few utilities claim to be well on the road to smart grid enablement, those that are actually collecting data already are doing very

little with it. So the real promise of smart grid technology lies several years down the road. “The current status of the smart grid is very intriguing, and a lot of the clients we’re working with are beginning to see that smart grid is not really an option, but more of a survival platform that they will need for the future,” said Kevin Sullivan, regional director for management operation consulting for consulting firm KEMA. “Realizing the benefits is still the biggest challenge for most of the utilities that are applying this technology.” Smart grid technology takes on many meanings and almost every utility describes its role and importance differently. In fact, smart grid projects vary greatly from one utility to another.



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COORDINATING EE AND DR In early 2010, the Ernest Orlando Lawrence Berkeley Laboratory published a report entitled “Coordination of Energy Efficiency and Demand Response”. In it, the authors summarize the existing research on the relationship between energy efficiency and demand response, and offer suggestions for how to coordinate the two: COMBINED PROGRAM OFFERINGS. Customers could be offered both energy efficiency and demand response opportunities under the same program and provider umbrella; separate programs are the norm today.


COORDINATED PROGRAM MARKETING AND EDUCATION. Without merging the delivery of services at the program level, program sponsors (e.g., utilities) could package and promote energy efficiency and demand response in a closely coordinated or unified way. Energy efficiency and demand response can be complicated topics, requiring sophisticated customer effort and action, so program sponsors should offer education that addresses both topics under a broad energy management theme.


MARKET-DRIVEN COORDINATED SERVICES. Coordination need not occur only within the context of programs offered by utilities, public benefit organizations, or independent system operators (ISOs). Coordination of energy efficiency and demand response could also come about through the initiative of private firms that find a market among customers who are interested in reducing their energy costs. Our research and interviews with selected energy service companies (ESCO) and curtailment service providers (CSP) suggests that they are interested in this approach; we describe their initial steps in this direction. BUILDING CODES AND APPLIANCE STANDARDS. Building codes and appliance efficiency standards can incorporate preferred energy efficiency and demand response features directly into building design and infrastructure and appliance designs, enabling significant reductions in the costs to customers of integrating energy efficiency and demand response strategies and/or measures (e.g., global temperature setback controls, automated demand response, embedded controls in appliances).

voltage reduction reduces energy consumption by an overall factor of 0.8. That means that if a utility is able to reduce voltage by 1 percent, it will see a 0.8 percent reduction in energy consumption. Pesin said that many devices in homes consume less energy at lower voltages. So when you lower the voltage at the customer’s home, you reduce the energy consumption. “For customer electrical equipment to function properly, the utility company has to maintain customer voltage between 126 and 114 volts,” he said. “In general, the lower the voltage is, the less is the energy consumption. However, if your voltage is too low you can damage some customer equipment such as electric motors.” In the past, utilities had no real-time visibility into a customer’s voltage. As a result, they had no choice but to maintain customer voltage at a higher level to prevent equipment damage. By deploying smart meters and distributed sensors, the utility can have near-real-time information about voltage, power quality and much more. “If you use this information in conjunction with intelligent computer applications and communications-enabled control equipment in the field, you can reduce customer voltage to the optimal level,” said Pesin. Another direct benefit to the utility is optimizing reactive power flowing on the distribution lines to reduce energy lost by the utility during the process of sending electricity from the distribution substation to the customers. Real-time asset management Another thing that utilities have to look forward to in a world that is interconnected by smart grid technology is the ability to better manage assets such as substations and other equipment. By having real-time visibility into the data streaming from substations, utilities will be able to better monitor the security and health of equipment, and therefore predict failures and required downtimes to repair equipment. “Most utilities rely on a scheduled maintenance system, requiring that a transformer be maintained on a certain date,” said Pesin. “When we are able to monitor the system and see real-time data come from the transformer, the data will tell us that the transformer may have failed and needs to be taken out of service and repaired immediately. Or we can look at the data graph and see that it may need to be taken out of service for maintenance in six months instead of 12 months, so that prevents a failure. Again, it’s a conceptual idea, and before we get there we need to have the infrastructure in place and have devices like sensors and other equipment that monitor these things.” Yet, it is hardly pie-in-the-sky stuff, and there are many potential use cases for an enabled smart grid. Connectivity for field crews is gaining a lot of attention. By including those workers in the same digital stream that AMI data is

gathering, dispatchers can be much smarter about where workers are deployed in the field. A distribution automation focus Experts say that the more interesting projects are the ones in which distribution automation has been the focal point for the smart grid rollout, such as the digitization of protective relays at substations and installing intelligent RTUs and networks to prepare for the use cases that might deploy that digital technology in advanced automation scenarios. “But again, we’re not at the point where those scenarios have been played out or even demonstrated,” said Sullivan. “I really think that in the next two to three years we should see the integrated role of taking data and turning it from data to information and, more importantly, taking that information and turning it into knowledge,” he said. “Three years from now I feel there will be a big renaissance, if you will, saying this was not a bad idea after all, especially when utilities start to realize that to control bidirectional power flows, you need to have a smart grid infrastructure behind your power delivery system.” Of course, the smart grid jackpot revolves around distributed energy and the increase in power generated from the

wind, sun and other renewable sources, and the utility’s ability to integrate various solutions to allow a distributedgeneration environment to exist. While renewables present the biggest opportunity for the smart grid, it is clearly also the biggest challenge. For years, power generators have worked in a right-to-left fashion to deliver energy to the customer. But as more consumers begin to produce energy from renewable sources and put energy back onto the grid, the traditional utility power generation equation will change dramatically. “The distributed renewals issue is probably what will cause the most heartache for utility operators when it comes to managing the stability on the network,” said Steve Pullins, president of Horizon Energy Group. “We have the tools at the transmission level to help to do that, but we are short on tools to manage the variability that renewables introduce to the distribution network.” John R. Johnson is a Boston-based freelance writer specializing in alternative energy and technology topics.

“We need partners that

understand our vision for the Smart Grid.”

Aclara leads. Create Your Intelligent Infrastructure™ Find out more at 1.800.297.2728 |


Aclara understands that utilities need to do more than collect data. We are driving a future that integrates AMI, SCADA, distribution automation, and more into an Intelligent Infrastructure™ with the capability for communications and control. With the strength of our solutions for electric, gas, and water utilities, we understand your vision. With our network we will take you there. Aclara Leads.



PPL automates Harrisburg In November 2009, the U.S. Department of Energy (DOE) awarded PPL Electric Utilities in Harrisburg, Pennsylvania, a $19 million grant toward the utility’s $38 million project to expand and strengthen its smart grid. The utility has begun installing hundreds of automated electrical devices across a 150-squaremile area of its delivery system in the Harrisburg suburbs in Dauphin and PPL and Avista initiate infrastructure upgrades Cumberland counties. In addition, PPL By Cate Meredith plans to add a high-speed communications network, a sophisticated distribution management system  and various AS POWER ENGINEERS, MARKETERS AND PROJECT MANAGERS are acutely aware, substation automation and distribution automation types of smart grid software. Ryan Hill, a spokesman for PPL, cites are currently experiencing the most dramatic, shaping events in their modern aging infrastructure as a big challenge, history with a whole raft of disruptive technologies we call the smart grid. not just for his utility, but throughout Traditional distribution systems were designed to perform one function: to distribute electrical energy to end-users. It has been that way since the 1960s. In the the country. PPL, like utilities across 1990s, electrical utility supervisory control and data acquisition systems began the country, has wrung as much as it evolving, bestowing us with the distribution systems we have today that deliver could from those assets, but now it is electrical energy as well as information between participants, system operators focused on replacing much of that older equipment. PPL has begun a proand system components. gram of replacements, Funding needed for build-out increasing substantially We have a unique Once focused exclusively on improving reliability, disits investment in capital tribution automation is emerging as a key for reducing improvements to upopportunity to energy loss and carbon emissions, integrating renewgrade and modernize able generation resources and supporting plug-in electhe delivery system. incorporate new tric vehicle deployments. In addition to a wide range of  “As we address the isintelligent distribution automation devices (switches, sue of aging infrastructechnology and reclosers and fault circuit indicators), a communications ture and replace more network and network management are foundational equipment, we have a to make the building blocks required for successful deployments. unique opportunity to So why hasn’t the United States fully implemented a incorporate new techsystem smarter, smart grid with modern automation distribution? The nology and to make the usual answer: money. system  smarter, more more efficient and The Edison Electric Institute has indicated that the efficient and more reliUnited States would need $1 trillion in additional capital able,” Hill said. more reliable. over the next five years to refinance existing generation   The new  distribuand network assets and to invest in both existing and tion management sysnew assets. The concept that we characterize as the smart grid is actually built on tem will collect information from top of that old 1960s infrastructure. The job of the utility is to find a way to ensure certain smart devices on other parts that each step forward is compatible with technology that was cutting-edge when of the company’s 29-county delivery Elvis was making young girls swoon. Improving the aging equipment, while try- system beyond the Harrisburg region ing to take a giant leap forward into the future, is complex and costly. and make decisions to more effectively Stimulus funding under the Obama administration is assisting utilities in manage outages. This will help to speed making that cash shortfall a little less daunting. The taxpayer funds have revived power restoration across the entire deshelved smart grid projects and, for those projects that already had traction, they livery system. have incited an enormous appetite for scale. Big pilot projects are finally possible Also, while the new system won’t because of the infusion of billions of dollars in cash. be able to manage the conven-

Distribution automation shapes future system ++



tional switching devices beyond the 150-square mile project area, it will calculate the best switching steps for system operators to take, saving them valuable time in responding to customer outages. The utility’s long-term objective is to add automated devices elsewhere and extend the full capabilities of PPL’s smart grid to other areas of the utility’s delivery system within eastern and central Pennsylvania. A key piece of the smart grid, the distribution management system,  will already be in place when it does.

can integrate intelligent communications into its utility operations for a long time. Over the past decade, upgrades such as its outage management system, which uses advanced mapping, provide a great foundation for the current smart grid projects, allowing the utility to more easily integrate smart devices into its system. These smart devices identify and restore outages, reducing outage frequency and duration for Avista customers. This vision helped Avista in indentifying valuable projects, including the Spokane Smart Circuits Project. System improvements save energy In order to achieve the project goals, Cummins says that Avista will eventually upgrade 59 distribution circuits and 14 substations as well as the associated system infrastructure. The system improvements are intended to reduce energy losses and improve reliability in the electric distribution system, ultimately helping reduce the need for new generation facilities. System efficiencies can save about 42,000 megawatt hours each year, enough to power about 3,500 of Avista customers’ homes. Avista will also install smart switches, smart reclosers and capacitor banks— nearly 400 automated devices on Spokane’s distribution system—and implement intelligent end devices. Smart switches will reroute power around an outage, and smart regulators and switched capacitor banks will adjust voltage for greater energy efficiency. Customers will experience better reliability in the form of fewer and shorter outages. And, ultimately, wireless communication throughout the system will automate operations and optimize efficiency. “This project, along with our other smart grid projects, is an exciting opportunity for Avista as a utility to learn how we can run our system more efficiently and prepare it for a smarter energy future,” Cummins said. “The complexity and broad scope of this project also give us the opportunity to increase the company’s ability to handle new issues and provides relationship-building opportunities for departments that don’t frequently interact.  The company has become more agile and adaptable to change while innovatively resolving the project challenges.” Although there is a lot of work yet to be done with substation automation and distribution automation, it is beginning to look as if some of the long-envisioned benefits of smart-grid technology may finally be realized. Cate Meredith is a freelance writer based in Houston, Texas.


Smart Spokane Across the country, in Spokane, Washington, another electric utility has a similar plan. Avista Utilities provides electric service to 355,000 customers across a service territory covering 30,000 square miles in eastern Washington, northern Idaho and parts of southern and eastern Oregon. The company’s Spokane Smart Circuits Project was chosen by the DOE to receive the largest matching grant awarded in Washington state, totaling $20 million. Avista is contributing a further $22 million for a total planned project investment of $42 million. The goals of the Spokane Smart Circuits Project are to reduce energy losses, lower costs, increase reliability and enhance the utility’s ability to integrate renewable generation resources. The project is targeted to provide an annual energy savings of 42,000 MWh and an annual reduction in carbon emissions of 14,400 tons. Federal funding has allowed Avista to accelerate the pace of its planned upgrades. Avista has completed upgrades on four substations and 15 distribution circuits; it has installed 160 smart switches, reclosers and capacitor banks; and it is on track for completing construction of the project by March 2013. Distribution Engineering Manager Heather Cummins, who oversees Avista’s smart grid projects, says that the utility has been exploring how it



SCADA cyber attack ++Some believe Stuxnet worm marks new age of super-cyber weapons By Mike Breslin ATTACK OF THE SCADA KILLER IS NOT A NOT NEW HORROR


film, but a real scenario that sends chills down the spines of electric utility operators. It could be directed by a mischievous hacker, a terrorist group, statesponsored espionage, or by a disgruntled employee, or a former one. And let’s not dismiss those miscreants with proficiency, a computer and dreams of destruction that see the disruption of the grid as a purely technical challenge, a demonstration of hacking star power. “SCADA [supervisory control and data acquisition] has the control to open and close switches on the transmission grid. That’s why the concern exists. When one thing happens in a power system, it can result in other things happening automatically from a protection point of view,” said Mark McGranaghan, director of distribution, power quality, and smart grid for the Electric Power Research Institute (EPRI). “It’s unlikely that doing something at one switch, or even a number of switches, would be likely to result in a cascading outage. We have had a number of those over the years and every time we learn … and put in additional protection to prevent the problem.”


Stuxnet worm a new cyber beast Nevertheless, in late September 2010, the Stuxnet worm invaded Iran���s nuclear program and other computer systems around the world. Some believe this invasion marks the beginning of the age of super-cyber weapons. Unlike a virus, this malware not only spread to affect Microsoft Window networks, but also burrowed into related industrial control systems, causing even wider alarm. Security experts speculate that a government or a high-capability organization created it with extensive programming capability. Here is how Symantec, one of the leading software protection companies, described it: “Stuxnet targets industrial control systems in order to take control of industrial facilities, such as power plants. It was the first piece of malware to exploit the Microsoft Windows Shortcut ‘LNK/PIF’ Files Automatic File Execution Vulnerability (BID 41732) in order to spread. The worm drops a copy of itself as well as a link to that copy on a removable drive. When a removable drive is attached to a system and browsed with an application that can display icons, such as Windows Explorer, the link file runs the copy of the worm.”

It is safe to say that no computer system is immune from cyber attacks. Hackers have breeched even ultra-high security U.S. government systems, including those at the Department of Defense. These are a few of the reasons why the utility industry has been and continues to hold cyber security at the top of the reliability priority list as the most important issue of all. “I don’t know if the grid is vulnerable anywhere, but the further up in the chain you go, the more things that are affected by any potential problem that gets created. At the distribution level, you are affecting a much smaller number of customers than you are if something has been compromised at the SCADA transmission or generation level,” EPRI’s McGranaghan said.

status of the nation’s transmission and distribution systems. Over the next three years, up to $10 million may be spent to establish NESCO, set up administrativeoperational functions and fund research and development. Among the collaborative tasks are: assessing requirements and results developed by the National Institute of Standards and Technology, North American Electric Reliability Corporation and other organizations; reviewing power system and cyber security standards in meeting power system security requirements; and testing grid security technologies protocols using laboratories and pilot projects. “NESCO will create a cyber-security organization that will track any vulnerabilities, identify issues, make all utilities aware, provide solutions and have a process of getting vulnerabilities fixed as quickly as possible,” said McGranaghan. One major NESCO collaborative participant, The Idaho National Laboratory (INL), brings six years of cyber security experience and knowledge to the table. According to Rita Wells, energy sector leader of the critical infrastructure protection and defense systems at INL, “Emerging smart grid technologies are challenging traditional security and functional boundaries, and this is requiring us to pursue new approaches to cyber security.” McGranaghan added: “Utilities have security right at the top of the list. I can tell you from talking to executives that they are making sure they are addressing security concerns in every way possible. Some of it is a problem from an R&D point of view, really being able to understand and characterize all of the potential vulnerabiliHackers have ties and threats.”

Mike Breslin is a freelance writer and novelist based in New Jersey.


Collaborating on cyber protection In late September of last year, EPRI was named by the U.S. Department of Energy to lead one of the largest energy industry collaborative projects to date aimed at protecting the power system from cyber attacks. This was among 10 cyber security initiatives representing an investment of more than $30 million announced that same month by U.S. Energy Secretary Steven Chu. The EPRI-led collaborative comprises national and commercial research laboratories, universities and experts in key areas of cyber security. The mission is to create a National Electric Sector Cyber Organization (NESCO), a federal government-electric sector partnership that will analyze the cyber security

breeched even ultraUtilities playing it close to the vest We asked a few major utilities to talk about high security U.S. what specific measures they are using to prevent cyber attacks. Not surprisingly, government systems, they were close-mouthed on the subject. Everyone is playing it close to the vest, including those at unwilling to reveal strategies being used. The Atlanta-based Southern Company, the Department which generates over 42,000 megawatts to serve more than 4.4 million customers in of Defense. the southeast, responded to our inquiry. Tom Wilson, Southern Company’s director of IT security, told us: “Southern Company and its industry-leading cyber security partner have found no evidence of this threat (Stuxnet worm) in or emanating from Southern Company’s network. “The company’s exposure to this specific threat is limited based on the systems targeted. We are monitoring this situation closely, working with control system vendors beyond the targeted systems to ensure that our systems are protected against associated threats. Additionally, the industry is in contact with federal agencies regarding this threat.” The level of cyber defense, of course, improves in proportion to the resources invested to fight off attacks. In other words, it appears we are entering an expensive, escalating cyber weapons race, a race that may increase operating costs and ultimately result in higher energy costs. Reduced to the simplest terms, it is a battle between good and evil—those who wish to bring light and power into the world versus the malevolent forces of darkness. Fortunately, a united utility industry has the smarts and the resources to win.


ITRON: Solutions rooted in reality


ÖÖNorth American utilities are being buffeted by the winds of change, yet charting a course to reach a moving destination known as smart grid requires pragmatic, flexible solutions.


This is true across the world as well, though the global challenge is considerably broader. Flexible solutions might simply involve the fundamental act of bringing electricity to users in developing countries, automation for a European utility or a smart grid solution with business analytics for a cutting-edge utility in California or Texas. Itron is involved at all of these levels across the globe. In fact, the challenges faced by utilities worldwide require a deep understanding of local culture, technology use cases and regulatory regimes, along with respect for every utility’s unique business needs. To help its customers meet their sometimes disparate challenges, Itron devotes enormous resources to research and development and to its ecosystem of partners. We believe that a sustainable approach to meeting our customers’ needs creates the most value for our customers and contributes to our mutual goals of efficient stewardship of the natural resources we collectively manage. Itron CEO and President Malcolm Unsworth articulated these themes recently when he addressed an audience nearly 1,000 strong at the company’s 29th annual Users’ Conference.

“The way we manage energy and water will shape our century,” Unsworth said. “Utilities need flexible solutions, rooted in reality. They need new thinking, new tools, in order to provide effective, efficient management of the world’s resources.” As a growing company with an unmatched breadth of solutions and partnerships, Itron is well positioned to deliver that thinking and the tools to achieve it. “We are a truly global company operating locally,” Unsworth added. “We do business in 130 countries with 8,000 customers speaking 27 languages. We offer solutions rooted in reality.”

North American nuances Utilities across North America, whether in the power sector, natural gas or water industries, need solutions rooted in reality as they face enormous challenges. As siting new power plants becomes difficult and with restrictions on traditional fuels such as coal, operational efficiencies and engagement with customers will enable utilities to do more with less. Still, the litany of challenges is daunting. THOUGHT LEADERSHIP ­– SPONSORED BY ITRON

Photos provided courtesy of Itron

monitoring for impacts on load and distribution infrastructure. Dynamic pricing programs that shape load require metering and backend solutions as well as public outreach and education. Uncertain economic conditions demand efficient use of capital and operating budgets. How is Itron responding to these utility needs? We’re sensitive to the nuances of local markets, including their varied regulatory requirements



Customer engagement is part art, part science, and early stumbles on smart meter deployments in some regions of the United States have produced public pushback and regulatory wariness. Mandates for the increased use of utility-scale renewable energy, as well as the growth in distributed generation, present major engineering challenges. The introduction of electric vehicles into the market requires tracking and

and relationships. We are leading the investment in technology solutions and data management strategies. We are pursuing partnerships that vastly increase our capabilities across the distribution system. We hold frank discussions with customers about their challenges. We understand that our mutual bottom lines depend on delivering business value. “There is a great deal of diversity to the North American market,” said Philip Mezey, senior vice president and chief operating officer for Itron North America. “We sometimes make the mistake of talking about this continent as if it’s a homogenous entity. The business drivers vary across this market, so we need to be sensitive to the many nuances here.” Market-leading utilities in California, Texas and Ontario have responded, respectively, to limits on new fossilfuel generation, deregulation and the retirement of coal-burning power plants. In markets where smart meters are not required or sought, regulatory acceptance varies and Itron offers solutions for local needs. “We’re in the position of offering a range of technologies at different price


points,” Mezey said. “Many of our customers are perfectly happy using a handheld device to read meters and are getting the business results they need out of that approach. Our attitude is to let the market mature and work with our customers so they understand the value we’re generating with the customer base that’s using the new technology. “We’re aware of and supportive of our customers’ relationships with state regulators,” Mezey added. “We’re very respectful of that relationship.”


The value of sustainability


Just as wise stewardship of our natural resources is the hallmark of the modern utility industry, so Itron believes that a sustainable business approach yields the most value in the long run. “As an established public company, we think this is an opportunity to build a sustainable business over time,” Mezey said. “It’s healthy to have the market develop over a decade or two, to deliver positive business results and make sure the smart grid works. “We think the best thing we can do for the market is to deliver real value,” he continued. “In order to deliver that value, it takes software and services to meet the business cases that our customers are presenting to their regulators. So we feel we need to participate more broadly than just delivering a product. Our approach is to push for open standards that unlock innovation.” In the near term, partnerships with companies offering complementary technology and services allow Itron to bring an unprecedented breadth of solutions to its disparate customer base. “We have over 100 partners participating in a large ecosystem,” Mezey said. “That’s exciting, because they’re out there innovating on top of our system. We think that by driving

that forward we’ll derive benefits from the ‘virtuous cycle’ of software and services that drives value. We need to keep it open to the marketplace for new and different ideas.” The strategic alliance we’ve just announced with Cisco, for instance, gives us an opportunity to embrace what they’ve learned from other industries,” Mezey said. In September 2010, Itron announced a strategic alliance between Itron and Cisco to deliver collaborative solutions to transition smart metering technology into an open and interoperable, enterprise-class network for utilities. Specifically, the two companies will develop a secure, standardsbased platform for IPv6 implementation of field area communications in support of smart meters, distribution automation and interfaces to the customer’s premise. Itron will license and embed Cisco IP technology in its OpenWay meters and offer Cisco networking equipment and software with its AMI deployments. In April 2009, Itron announced a partnership with Teradata, a global leader in business analytics, data management and warehousing. This deal extends the value of our offerings by resolving the oft-cited observation “drowning in data, starving for knowledge.” Together, Itron and Teradata are introducing a new concept to the market called Active Smart Grid Analytics™. Active Smart Grid Analytics is a complete data management platform to deliver business intelligence value from the smart grid. Active Smart Grid Analytics (ASA) will apply advanced analytics to data from meter data management systems and advanced metering infrastructure, as well as customer, financial and operational information to enable smarter, faster decision-making.

Lowering total cost of ownership While maximizing the business value of our offerings to our customers is the fundamental driver behind these partnerships, an underlying, complementary goal is to lower the total cost of ownership. “Frankly, smart grid costs too much,” Mezey said. “If every utility has to build a lab to prove out the technologies and experiment with them and acquire new skills and

build out network operation centers and do industrial-strength security for millions of endpoints and meet all the challenges and seize the opportunities that smart grid offers, the cost will be too high. “If you look at the rate cases being filed, all parties are concerned about the costs,” Mezey continued. “That money goes toward development, integration and proving systems through testing and deployment. There are one-time capital costs and the recurring costs of operating and maintaining a complex system over its life cycle. If we don’t address that as an industry, this is going to be a short ride. Part of what we’re doing with the Cisco relationship, for instance, is trying to standardize as many


components as we can, harmonize the technologies and drive down costs. “The utility industry has been plagued by islands of automation, which raise total cost of ownership,” Mezey said. “We need to materially address that with a platform that allows us to integrate many different products from different suppliers. We need to speed up the time-to-value for our customers and reduce total cost of ownership.” Itron invites you to visit our Web site and read about our partnerships through our own press releases as well as business and industry media articles under “Itron in the News” to learn more.

Itron’s corporate culture: walking the talk

Pushing innovation across utility sectors “We are really excited about taking the concepts developed in the electricity sector and applying them to the natural gas space,” Mezey said. “Obviously, some of our largest utilities are integrated gas and electric utilities. We think there are tremendous opportunities there in operational efficiency and conservation, as well as safety. We see these opportunities extending into the water space as well.” Meanwhile, North America often serves as a proof point for utilities around the world anxious to see how Itron and its partners and customers are tackling utility issues that resonate globally. “Interestingly,” Mezey concluded, “our customers are visited frequently by a wide range of global utilities, which are very interested in what’s going on in North America. That provides a good exchange of ideas.”

The global perspective Citing forecasts that project a 40 percent increase in global energy demand by 2030, Malcolm Unsworth emphasized that such demands underscore Itron’s aggressive investments in research and development alone, and with partners.


Future challenges, once ephemeral, now loom as tangible requirements for utilities, Itron’s president and CEO said. “It took a century to perfect the filling station for internal combustion engines, yet we’re expecting 50 million electric vehicles on the road within 20 years,” Unsworth said. “Utilities face a huge challenge to make EV charging a ‘convenient necessity.’” In the natural gas sector, mere modernization of the distribution network poses an enormous task, not to mention bringing new, smarter meters to that industry. “Utilities must upgrade an enormous inventory of aging infrastructure for safety and reliability,” Unsworth noted. “In the United States alone, there are more than two million miles of natural gas pipelines and 60 percent of that inventory is 40 years old.” Water utilities face an analogous challenge. Across the globe, a centuryold distribution system is leaking, wasting a precious resource and hurting utilities’ bottom lines through the loss of “non-revenue water.” Itron systems will enable utilities to find their points of leakage and conserve this precious resource. Finally, utilities across all sectors seek to engage their consumers. In the power sector, that trend will grow a new market in Web-based presentment, in-home energy displays and programmable appliances that will spread to mobile devices via iPhone apps and social networks. Itron’s technology enables this engagement, for utility efficiency and customer satisfaction. “Itron and our partners are right there with you to meet our collective future,” Unsworth concluded.


In an era when the notion of “corporate culture” is often cited due to its absence, Itron proudly does its manufacturing domestically for the North American market and believes that its “solutions rooted in reality” contribute to the greater good. “Unlike a number of our competitors, we operate our own factories and build the products we sell right here in North America,” Mezey said. “We are focused on and committed to the electricity, natural gas and water markets here. To succeed at high-volume manufacturing requires discipline. And to effectively compete against products developed and manufactured offshore requires ferocious focus.” Mezey credits the dedication of Itron’s people for achieving that discipline and focus. “To travel among our facilities and look people in the eye and understand the impacts we’re having on communities — providing quality jobs — is actually very inspirational for me. I have tremendous people working for me, from product development and manufacturing to sales, marketing and project delivery.” Just as Itron’s business strategy dovetails with our customers’ needs,

we believe that our success contributes to achieving national priorities. “As citizens we have an interest in promoting energy efficiency,” Mezey said. “We are believers, as a company, that it’s easier to save energy than it is to generate it. We’re not eco-crazy, we’re soundly focused on the business of delivering customer value. Yet we do have a point of view and we do believe that the work we’re doing in the energy space can have an influence on national security. Reducing waste or inefficiencies in the transmission and distribution network should be considered a renewable resource.”


2010: Itron’s 29th Annual Users’ Conference Did you know we live in exponential times? It took radio 38 years to reach a market audience of 50 million. To reach a market audience of 50 million, television needed 13 years; the Internet, only 4 years; iPods, 3 years; and Facebook, 2 years.


Only 1,000 Internet devices existed in 1984. In 2008, that number surpassed 1 billion.


ÖÖThese intriguing factoids flashed across a big screen in a large ballroom at the Omni Orlando Resort at ChampionsGate in Orlando, Fla., where nearly 1,000 people from more than a dozen countries gathered for the 29th annual Itron Users’ Conference. The numbers, presented in “Did You Know?” a YouTube video, were intended to dazzle the mind with the pace of change. For many in the audience, this rapid acceleration in market development was not news, but instead mirrored their day-to-day duties running electric, gas and water utilities in an era governed by rapid change. Moments earlier, the phrase “our global energy future” had flashed across the big screen. A narrator intoned other phrases such as

“operational efficiencies” and “lower carbon footprint” and stated, “consumer empowerment will transform the energy landscape.” All this would be an eye-opener for the uninitiated, but Itron’s customers and partners had gathered for an annual conference to share solutions to these challenges with their peers. Thus, the conference’s theme, “Discover 2010,” was apt.

The throng came to discover answers to day-to-day operational challenges and strategies for the future. And with seven tracks, more than 125 sessions, networking opportunities, a Knowledge Center on Itron solutions and a Partner Pavilion to illuminate the larger ecosystem, answers were in abundance, waiting to be discovered.

Keynotes laid the groundwork Russ Vanos, vice president of marketing at Itron, exhorted the assembled to ponder a few fundamentals. “Do we really know our customers? What they need? What they want? Tomorrow’s customer will look a lot different than they do today,” Vanos told his audience. “We’re moving from reactive to proactive interactions.” Vanos introduced Paula Hadley, who supports gas operations at Southwest Gas and who served as chairperson of Itron’s Users’ Advisory Board. Hadley and Bill Cloutier, Jr., manager of smart grid interoperability standards at DTE Energy, reminded the audience that this was in fact their conference, designed by the users of Itron’s technologies and services to meet their needs. With the stage thus set, Malcolm Unsworth, president and CEO of SPECIAL REPORT ­– SPONSORED BY ITRON

Special Report: Discovering a Smarter Future Sponsored by

Unsworth continued. And new forces are driving change, as well. Utilities are morphing from top-down, unidirectional suppliers of energy and water to become organizations that interact with their customers, requiring engagement and communication. This new landscape has led Itron to develop an unparalleled ecosystem of partnerships and to make aggressive

“the most difficult economy in our lifetimes.” Kurmas’ description of recent history really spelled out many of the forces buffeting utilities in North America since the 1990s, which included attempts at deregulation, mergers and expansions, the rise of merchant generation and energy trading, and the turbulent cross-

the world’s resources and Unsworth emphasized that Itron, with more than 100 partners, has a global footprint in 130 countries with 8,000 customers speaking more than a score of languages. That track record reflects a pragmatic focus and a disdain for hype, he implied. “We offer solutions rooted in reality,” Unsworth said. “We are a truly global company operating locally. And we understand the challenges and complexities of utility issues.” Perennial concerns about reliability and safety have been exacerbated by aging infrastructure across the electric, gas and water sectors,

investments in research and development and business analytics to serve its customers and their new mandates. Understandably, Unsworth’s pledge was greeted warmly.

currents that resulted. By the mid-2000s, Kurmas said, it was “back to basics” with environmental regulations and requisite spending to meet them, a decrease in capacity due to difficult economic times and higher fuel costs. Today, mandates to integrate increased amounts of renewable energy, updating aging infrastructure and decreased dependence on coal — all with no increase in load — has delivered a heaping plate of challenges. “Large investments with a decreasing load are a real predicament,” Kurmas noted. The utility executive also noted that while Detroit Edison and its

Photos provided courtesy of Itron

Itron, commanded the floor for a brisk tour of the world and a bracing reminder of the challenges posed by rapid change. “The way we manage energy and water will shape our century,” Unsworth said, repeating that mantra to ensure it sank in. Utilities need flexible solutions to efficiently and effectively manage

Unsworth’s offer of “solutions rooted in reality” had a willing listener in Steven Kurmas, president and chief operating officer at Detroit Edison, an investor-owned utility serving southeast Michigan. Kurmas took the podium next and described a “tumultuous decade” in the industry and some rough years for his beleaguered city, which has experienced



Dateline: Detroit


peers traditionally have focused on customer affordability, that guiding principle has morphed into “customer satisfaction.” Not that affordability has dropped from view. Kurmas noted that his customers have been hit disproportionately hard by recent developments and not just by the automobile industry’s woes in Detroit. The average ratepayer shells out 3.7 percent of their out-of-pocket expenses while ratepayers in Detroit pay as much as 10 percent and live in under-insulated homes, according to Kurmas. To meet the affordability challenge, utilities must increase productivity, pace their investments and invest in technology that facilitates the balance between customer affordability and satisfaction, Kurmas said. Detroit Edison’s parent company, DTE Energy, has done this with its SmartCurrents program by investing in Itron’s OpenWay® smart grid platform, realizing an increase in net income.


Critical asset: your people


The technology landscape is not the only place where the ground is shifting. Utility workforces will be retiring in droves in the next five years, and capturing departing employees’ knowledge and experience while attracting and training a new generation of workers will be as critical as adopting technology, according to Robert DeLoach, general manager and CEO of the Cucamonga Valley Water District in Southern California. High-performance organizations are driven by three factors, DeLoach said: emerging workforces, visionary leadership and the impacts of

their corporate culture. Soon, half a utility’s workforce is lik ely to be under age 30 and, by retirement, this emerging workforce will have had 10 to 14 jobs. That means, to DeLoach, that hiring should be based on values, not skills. Self-direction will be a primary value, one that means that CEOs’ roles will involve supporting their workers. Strategic planning used to be a top-down exercise, based on known data. In coming years, organizations are likely to design their own futures “without knowing all the steps along the way,” a quote courtesy of the Harvard Business Review. That method of planning will require organization-wide input into forward-looking strategies, according to DeLoach. How important are these foregoing points? “Corporate culture impacts productivity and performance,” DeLoach said. “Ask yourself what your customers think of your company and brand.” Is it “U.S. Postal Service” or “U.S. Marines”? he offered.

Operations & Best Practices. Sessions included “Occupational Dog Bite Prevention Training,” “Plug-in Electric Vehicles,” “Complex Billing Issues Solved” and “Transitioning from Utility-focused Services to Customer-focused Services.” The offerings drew bustling, energized audiences and many sessions were guided by representatives of Itron’s utility customers who shared their findings and insights with their peers. Half-hour breaks between sessions allowed ample time for networking in the hallways and exploring the informative offerings in the Itron Knowledge Center and nearby Partner Pavilion.

Sessions: from dog bites to business analytics With these vivid reminders of the challenges ahead, attendees then dispersed to follow their choice of educational tracks, which included Analytics, ChoiceConnect™, Consumer Engagement & Demand Response, Metering & Control Technology, OpenWay and Utility

In the Knowledge Center, Itron customers could learn about the company’s newly revamped Web site, which offers a simpler user interface and intuitive options for accessing account information, technology overviews and case studies of Itron’s solutions. Visitors could experience interactive displays illustrating Itron’s SPECIAL REPORT ­– SPONSORED BY ITRON

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meter data collection processes, the company’s hardware and software solutions, and its communications networks, system design and analytics, forecasting and smart grid. Next door, in the Partner Pavilion, more than two dozen Itron partners offered to explain their value-added products and services. The products and services included consulting, in-home energy displays, communication networks, systems integration, business analytics, mobile workforce devices, demand response and geospatial information systems. The range of sponsors, Itron partners all, reflected the industry’s most influential names, including Capgemini, Microsoft, Certicom, IBM, Digi, Nighthawk, Panasonic, RouteSmart, Accenture, AT&T, Comverge, HP, Infosys, Johnson Controls, SAP, SmartSynch, Tendril, Teradata and Verizon Wireless.

Cisco and Itron: speaking the same language


De Martini answered, simply, “reduced operations and maintenance costs for the grid” — a powerful argument.

Business analytics and the Teradata deal Another session — “Active Smart Grid Analytics™: System and

Technology Overview” — detailed the results of another recent alliance, this one formed by Itron and Teradata. With AMR, AMI and meter data management systems second to none, Itron sought to extend its value into the crucial new frontier of business analytics, explained Julie Hance, Itron’s vice president for software solutions. In April 2009, Itron inked a deal with Teradata, a world leader in data analytics, management and warehousing, and a company with deep experience in other vertical markets. “Drowning in data, starving for


One packed session was devoted to the implications of the recently announced alliance between Itron and Cisco. As information technology and operations technology become more tightly entwined, a direct connection from meter to IT has gone mainstream, said Rich Creegan, Itron’s vice president for strategy and marketing. That calls for a platform that answers utilities’ needs for interoperability, security and scalability, he said. Itron and Cisco believe they have the answer to these challenges. Specifically, the two companies are jointly developing a standards-based, highly-secure technology for full

IPv6 implementation of field area communications to support smart metering, intelligent distribution automation and interfaces to the customer premise. Itron will license and embed Cisco IP technology with its OpenWay meters and distribute Cisco networking equipment and software as part of its smart meter deployments. At one time, meters served a meter-to-cash function, observed Paul De Martini, now the chief technology officer for Cisco’s smart grid team, formerly the vice president in charge of advanced technology for Southern California Edison. Now, the meter is an integral part of the distribution system, an interactive role that can be leveraged for much greater operations insight and business value. The vision, De Martini said, is to enable pervasive monitoring and control of the grid’s distribution network to enhance the efficiency and intelligence behind energy delivery, for a low-carbon society. The direct benefits to utilities include protection against stranded assets, simplified deployments, lower total cost of ownership and a standards-based architecture that conforms to evolving security standards and offers multiple business applications. “The same structure has served other vertical industries,” De Martini said. One IT director asked how to “make the sale” internally, to which




knowledge,” is a common phrase that captures the dilemma addressed by the two companies’ new solution, dubbed “Active Smart Grid Analytics.” This analytical tool can assist utilities in getting the most business value out of legacy systems or new AMI deployments and it can assist in managing operations and planning and designing grid modernization projects, Hance said. “We’re helping Itron leverage our experience in managing large volumes of customer data to derive business value and intelligence,” said Terry Burns, an executive consultant in Teradata’s energy and utilities practice. Teradata has vast if not total market share in numerous vertical industries, from telecommunications to banking, transportation to retail, and now brings that experience to the utility business. High-performing companies across the board use data analytics and, Hance suggested utilities can use this new tool for a variety of applications, including revenue protection, improving the accuracy and timeliness of settlements among electricity market participants, and preventing voltage issues. The list of potential applications is long. “This has the power to change your business,” Hance said. The importance of these alliances to utilities was underscored later in the day when Thomas Chang of CenterPoint Energy, a large OpenWay customer with 2 million advanced electric meters in the Houston area, gave a presentation about smart meters’ contribution to performance management and diagnostic work.

The advantage of analytics, Chang said, can be grasped by considering the following three facts: ŠŠ Four in five business leaders see analytics as a competitive advantage. ŠŠ One in two doesn’t have access to key information across the entire organization. ŠŠ One in three business leaders make decisions without the information they need.

“The aggregation and correlation of events and data are important because they help you focus on the real problem — the root cause — and reduce time to resolution,” Chang said. “If you can’t measure it, you can’t manage it,” said copanelist Kevin Klein of IBM.

readers in its sprawling 50,000square mile service territory. “We’ve been in the EV world a long time,” said Haralson, who proceeded to share insights gleaned from two decades of research and preparation for the pure plug-in electric vehicles and hybrids now hitting the market. Drivers for the uptake of EVs among consumers include the low cost of “fuel” per mile, reduced maintenance of electric drive trains and the appeal of reducing dependence on foreign oil, Haralson pointed out. Still, he predicted that

PEVs: The business of plugging in One forthcoming wild card for all electric utilities in the United States is the advent of electric vehicles. So it’s not surprising that a session offered by Southern California Edison’s Percy Haralson, manager of field technologies for that utility’s transmission and distribution business unit, was well attended. The utility glimpsed the future nearly 20 years ago, founded its Electric Vehicle Technology Center in 1993 and wields a fleet of EVs for meter

hybrid vehicles would prove to be most popular, due to consumer unease — known as “range anxiety” — about getting stuck without convenient access to charging infrastructure. Of course, one of the biggest concerns on the utility side is how EV uptake and charging will affect local transformer loads. At Southern California Edison, transformers SPECIAL REPORT ­– SPONSORED BY ITRON

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OpenWay and cyber security The fundamentals of providing cyber security for your utility’s business and operations is not only a government mandate, it’s a way of life going forward, according to Scott Palmquist, an Itron senior product manager. Thus, it helps to understand the motives for cyber security attacks, likely perpetrators and how to define threats, he said. First, why do hackers hack? The spectrum of hackers begins with inadvertent errors that have unintended consequences, typically a careless or poorly trained employee, according to Palmquist. The spectrum further includes disgruntled employees, competitors, organized crime, cyber terrorists, hackers and nation states. The motives range from bragging rights to economic theft to political aggression. Palmquist noted that “security defined” calls for confidentiality (only authorized users can view the information), integrity (protecting data from malicious or accidental modification) and availability (data is available when needed by an authorized user). Prioritizing your security strategy means knowing what to watch for and understanding the distinctions between threats (a potential event or attack), vulnerabilities (a weakness that can be exploited) and actual

attacks (an intentional attempt to exploit a vulnerability). Countermeasures require controls, which can include encryption, key management, certificates, authorization, authentication and physical security, Palmquist continued. While automating security to the extent possible is a good practice, it’s worth noting that the National Institute for Science and Technology’s recent cyber security guidelines are more than 70 percent composed of organizational matters. Security is only as good as the people who practice it.

Compliance with regulatory mandates, while important, is hardly the entire solution, Palmquist noted. “Smart grid is also a business,” he said, “and security must map to the business drivers.”

Consumer engagement: not business as usual From the cloistered world of cyber security, attendees might have selected to join Risa Baron from San Diego


typically are sized to handle 100 percent of their intended load, but at peak times they probably handle 150 percent of their nameplate capacity, Haralson pointed out. That heats them up during the peak, but they have an opportunity to cool down overnight. That introduces a “what if” question on EV adoption, he pointed out. What if utilities succeed in encouraging nighttime charging, perhaps to take advantage of lower-cost wind energy available between sunset and sunrise, and transformers experience two peaks and don’t have the time to cool down? Greater numbers of transformer failures are likely, he said. “The challenge is potentially way bigger than we’re thinking, with our conservative assumptions,” he said. “The good news is, we’ve got time. But from a utility standpoint, we’ve got to be prepared for this.” Southern California Edison has analyzed its distribution infrastructure and found that the biggest uptake of EVs is likely to take place in areas with the weakest infrastructure, he noted. Thus his utility has a 20-year plan that begins with encouraging nighttime charging at home, readies the utility for local distribution system impacts and eventually leads to billing systems that can track a driver’s use of public charging infrastructure away from home. Meanwhile, the key is stakeholder engagement: with customers to register their vehicle, choose a rate and install charging equipment at home; with state and local government to expedite the permitting process; and with third-party installers for proper installation of gear.



Gas & Electric to learn more about outward-looking customer engagement — the linchpin to smart meter and smart grid acceptance and, consequently, support by the public. “Smart grid will bring more change in the next 10 years than electricity consumers have seen in the past century,” Baron told a packed session. “Your utility needs to seek actual conversations with your customers to get their buy-in for products and services that will change the relationship.”


SDG&E understands that challenge well, for it has deployed 1.4 million meters across a service territory of 4,100 square miles that include 25 cities with a mix of urban and suburban residents, Baron said. The challenge is not simply a technical one, she added. “Most of our customers don’t have an interest in energy,” she said. To overcome inertia and have genuine contact with millions of people, SDG&E devised a set of guiding principles for an AMI rollout. Be proactive. Be collaborative. Work toward mutually beneficial outcomes. Be responsive. Be nimble.

That sounds good on paper, but what steps did SDG&E employ to achieve a positive outcome? First, it formed a technical advisory panel of stakeholders, including consumer groups, the California Public Utilities Commission, the California Energy Commission and technology advocates in the community. It developed a plan with 30- 60and 90-day goals. The utility phoned customers three or more days prior to a smart meter installation, providing a Web-based deployment map for customer access. The day of installation, door hangers were left notifying the home or business owner that SDG&E had been there and explaining why. Follow-up calls were made and utility ambassadors — typically, retired utility employees — went door-to-door. Several “aha moments” occurred in the process. First, smart meter deployment is best scheduled for the smallest seasonal impact; i.e., don’t schedule during summer when usage typically jumps and consumers might fear that higher bills are due to the meter installation. Secondly, understand that digital smart meters are very accurate and may be replacing slow or even stuck meters. SDG&E decided its policy would be not to charge consumers for huge initial discrepancies between the old and new meter readings. That stance paid dividends in public relations, she said, and avoided media frenzies.

Also, SDG&E sought to resolve conflicts within three to five days, offering enhanced training to customer service representatives and creating a dedicated “escalation” desk for emotional disputes. “This is not business as usual,” Baron said. Metrics on results speak for themselves: Of 1.4 million smart meters installed, SDG&E received 1,780 complaints, or 0.15 percent of the total. High-touch consumer engagement is hard work, Baron noted, but because it is likely to be the beginning of a new relationship with customers whose cooperation you need, make the most of it. “Community outreach is not 9 to 5,” she said. “When you meet over smart meters, talk about what other value you can offer.” SDG&E also found that offering immediate value to the consumer was beneficial, so it recommended Google’s PowerMeter, which offers day-old energy use data. “After customers get a new meter, they ask, ‘What’s next?’” Baron noted.

‘Managing our own energy’ The sessions described thus far, just a smattering of those offered during the first day of the Itron Users’ Conference, certainly fired up attendees in search of solutions to their challenges. But Itron was taking no chances. The evening was devoted to a “Crazy ’80s” dinner and dance and the next day began with a motivational speaker who demanded participation. Desi Williamson, pacing the SPECIAL REPORT ­– SPONSORED BY ITRON

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ballroom stage like a big cat, exhorted his audience to manage their own energy and find inspiration within. To each of the questions he called out, the audience responded “Absolutely!” Williamson, a master storyteller, combined drama, humor and visual imagery to bring his audience to its feet repeatedly. “Redefine your purpose,” he intoned. “Raise your own standard of performance. Create the conditions you want. New and better ways to do things begins with ourselves! You can’t just drift to the top of the mountain!” “How far are you willing to go to realize your own potential?” Williamson demanded. “We can all go further than we have before, further than we think we can!” “Am I right?!” he called. “Absolutely!” the crowd responded.

Smart meters and societal benefits


grid yield operational benefits, would those benefits in the aggregate begin to approach societal benefits? Certainly, Messenger suggested, reduced prices, reductions in pollution and increased trade are candidates for consideration. “The moving pieces in a network require careful attribution of costs and benefits,” Messenger said. While utilities will track those costs and benefits for their own business

cases and for regulators, who will track societal benefits, and how will they do so? Messenger asked rhetorically. Some means of tracking should be devised “because social benefits are diffuse and hard to come by,” Messenger concluded. Yet the advantages of quantifying societal benefits would seem to be self-evident and sufficient to justify the effort. Sound like topics you’d like to hear explored further? Planning for the 30th annual Itron Users’ Conference—to be held in Phoenix— is already under way. We’ll see you there. ✸


Among the sessions offered during the second day of the Itron Users’ Conference, one standout was a talk given by Itron’s own Mike Messenger, an economist and senior principal energy consultant at the company. His talk, “Quantifying Societal Benefits from Deployment of Smart Meters: Crucial to Success or Fool’s Errand?” had potentially far-reaching implications for the industry. An appropriate answer to that question might well serve utilities involved in making a rate case, just as it might form the basis for public outreach over a meter deployment. It might also serve smart grid propo-

nents in government agencies such as the U.S. Department of Energy who engage in the art of political persuasion when setting and defending their priorities. Anyone involved in siting or cost allocation for a transmission line that crosses state lines is already familiar with attempts to allocate benefits, too. “We live in interesting times, with the benefit of converging networks,” Messenger told his audience. “You could argue that the California energy crisis of 2000–2001 was the birth of smart grid, because we couldn’t island the problems, they just spread. “Every network originally designed for private gain has yielded 10x in societal benefits,” Messenger said. Among the most important networks in history, defined this way, Messenger named money, water distribution, roads, books, Pony Express/ mail/email, telegraphs/ telephones/cell phones, high-voltage electric grids, radio/TV and the Internet/financial networks. Coming next: social networks. Societal benefits might be defined as indirect economic or environmental benefits, Messenger proposed. The growth of electric grids, historically, lowered rates for each consumer, so there’s a societal benefit that flowed from an effort at private gain. Today, reduction of pollution by lowering peak demand or overall demand might be considered a benefit, Messenger offered. While the attributes of a smart



Answering vexing questions ++Balancing distributed generation, microgrids and grid reliability By Dick DeBlasio




experience, constructed atop bedrock commitments to service reliability and availability, as well as worker and customer safety. The utility’s entire business model is based on long-term justification of ratepayers’ investment in high-quality, proven, dependable and safe equipment that sometimes comes at a very high price and always is expected to last … and last and last. Then, along comes the “smart grid.” (Even the name gets under the skin of power engineers who in some cases have already invested long careers into making the electricity-delivery facility gradually more intelligent and dependable over decades.) Suddenly, the tried-and-true grid stands to be infiltrated with rapidly changing computer, communications and information technologies, inherently intermittent renewable power sources and a revolutionary vision of decentralization. Is it any wonder that utilities were a little wary of adapting to a changing world where, for example, Moore’s Law is accepted as a fact of doing business? While the industry’s initial reluctance and skepticism were understandable, utilities are now helping drive the movement in the wake of advancements in distributed generation and renewable technologies that have brought into focus the smart grid’s promise for their operations and the electric power system. Innovations such as microgrids stand to dramatically bolster the historically robust profiles of service reliability and availability that utilities are determined to maintain throughout the smart grid’s worldwide rollout. The power of microgrids Microgrids aggregate various distributed generators—fuel cells, solar thermal generating stations, photovoltaic fields, wind farms, diesel, natural-gas-fired turbines, microturbines and other renewable and nonrenewable sources of energy— into a concentrated cluster of power that can be an important and flexible friend to a utility. Multiple distributed-generation technologies, in fact, might be engaged over a regional sector. The microgrid can be either connected to or isolated from the traditional power grid, depending on the utility’s needs at the moment. A microgrid might be normally connected to the centralized grid in a scenario of two-way power flow, helping the utility continuously meet demand under normal or peak

conditions. Then, in the event of a reliability issue, the microgrid would function independently to ensure ongoing service for a power application sector. Or, the microgrid typically could remain disconnected—or “islanded”—from the traditional facility, only to be engaged by the utility in abnormal or upset conditions, moments of unreliability or periods when the grid is completely shut down or jeopardized. The smart grid’s two-way communications and control comes into play for synchronization between the microgrid and traditional grid at

“Innovations such as microgrids stand to dramatically bolster the historically robust profiles of service reliability and availability.

points of engagement, as the transition from connected to islanded mode of operation (or vice versa) must be efficient, perfectly smooth and safe. This demands new capabilities for management and protection end-to-end across the grid, from remote substations to utility operations centers. Employing a microgrid Microgrids offer utilities considerable potential for key tasks such as sectionalizing the grid relative to certain emergency sectors (such as hospitals) and addressing disturbances. As an example, say a utility has a power line from one city to another with five or six tributaries, and say one of those feeders goes down. Up the line, there’s no problem, but sensors in the first of the cities down the line detect a droop in voltage. The edge point where the problem is occurring could be closed to protect the larger

grid until the fault is resolved, and, in a matter of microseconds, the microgrid system could be engaged to ensure uninterrupted service to all of the affected areas in the islanded sector. In California, where utilities are challenged by state regulation to steadily increase reliance on renewable sources of power over time, microgrid experiments are already being undertaken to help utilities evaluate their potential to contribute to the Smart Grid’s ability to self-heal and avert blackouts via islanding, “smooth” periods of peak demand and more fluidly adapt to fluctuations in usage. Ongoing development in energy storage will make microgrids more valuable in terms of increasing reliance on renewable energy sources specifically by helping offset their inherent variability. By and large, however, the technologies to enable planned islanding of distributed-generation clusters and microgrids are largely available. Crucial interconnection and interoperability standards are emerging, too. IEEE, for example, has about 100 globally relevant smart grid-related standards either ratified or in progress. Since March 2009, IEEE’s P2030 Working Group has worked to identify interconnection and intra-facing frameworks and strategies with design definitions. IEEE P2030’s representatives from the power, communications and information technology (IT) industries have already detailed more than 70 standard interfaces that will prove necessary in the smart grid’s rollout, and the working group’s guide is scheduled to be released for sponsor balloting within IEEE in March.

Dick DeBlasio is chair of the IEEE P2030 Working Group, a member of the IEEE Standards Association Board of Governors and chief engineer with the National Renewable Energy Laboratory.


Finding equitability Microgrids are a prime example of why politics and economics figure to be key frontiers for ongoing smart grid progress over the next decades. Technology has advanced, interconnection standards are emerging and utility consensus has gathered around

the potential of microgrids to dramatically improve grid reliability. And, yet, highly charged business questions remain before the industry moves forward in bold steps: Who pays the piper for interconnection, and how can we define ways of being equitable to sources of distributed-generation power, as well as the utilities? Every player in the relationship has investments to be recouped, and key regulatory decisions in these areas will have to play out across jurisdictions worldwide. In the United States’ regulatory environment, though the Federal Energy Regulatory Commission (FERC) mandates reliability and security of the bulk, interstate grid, each state will also have a hand in defining its own rules as the disparate public utility commissions regulate the distribution and retail levels of the power system within their own jurisdictions. Here’s another critical, related dynamic. The government has invested in smart grid demonstrations that are encouraging the development of distributed generation, renewables, microgrids and other innovative technologies. But the private investment community will have to do something more dramatic if mass-scale production of these technologies is to take root and yield more cost-competitive products and, in turn, accelerated, wide-scale implementation. The private investment community’s enthusiasm to fund that momentum will in part be driven by the data emerging from the government demonstration projects. So the millions of data points that roll in over the next years will be closely scrutinized. While there remains technology and standards development to be undertaken in order for utilities and their customers to realize the greatest potential of innovations such as microgrids, it is these political and economic fronts where many of the smart grid’s next vexing questions will be answered.



Fostering rapid demand response adoption ++Alliance formed to establish national ADR standard By Mike Breslin IN LATE OCTOBER 2010, A SIGNIFICANT MILESTONE WAS


reached in the development of automated demand response (ADR) with the formation of the OpenADR Alliance, a government/industry collaboration dedicated to establishing a national ADR standard communications protocol designed to help advance a smarter grid. OpenADR standardizes a message format used for Auto-DR so dynamic price and reliability signals can be delivered in a uniform and interoperable data model.


Easier adoption Establishing uniform technical standards across broad applications is usually time-consuming and problematic, but OpenADR may prove to be the exception and foster the rapid advance of smart-grid implementations nationally. “It’s always a challenge for control vendors to adopt standards because they want to stay proprietary, but I think OpenADR is going to be easier to adopt compared to having control standards within the building,” said Albert Chiu, senior program manager of demand response at PG&E. “We are only specifying the demand response signal between the system operator [i.e., IOUs, ISO/ RTO, etc.] and the buildings, but we have not specified how the control company responds to that demand response signal.” “OpenADR was originally developed here at Lawrence Berkeley National Laboratory to facilitate demand response markets in California,” said Mary Ann Piette, a staff scientist at the lab. The concept was that an open data model for automation would be the lowest cost to society. The OpenADR technology specification was published in April 2009 and we became part of the NIST (National Institute of Standards and Technology) smart grid standards in May of 2009. We’ve also been working with the other standards development organizations.” Deployment spreads Currently, more than 250 buildings and industrial facilities in California are using OpenADR. It is being used there by the three largest investor-owned utilities, San Diego Gas & Electric, Southern California Edison and Pacific Gas and Electric, to automate some of their demand response programs. A total of approximately 100 to 150 megawatts of demand response is presently OpenADR compliant signal format or planned for the coming year. Besides installations in Canada, OpenADR has been deployed in Washington by Seattle City Light in partnership with the Bonneville Power Administration, and it is currently being tested by utilities in New York and Florida. In Nevada, the investor-owned electric utility NV Energy, Inc. is expecting to support OpenADR with a vendor software application for commercial custom-

ers as part of an upcoming dynamic pricing program in mid-2011.  “Control vendors will have an easier time to be compliant with OpenADR because they can still maintain their proprietary systems within a facility. All they have to do is a relatively simple translation of the OpenADR signal to their systems,” said Chiu. “The main reason why we want to standardize the communications signal between the system operator and control vendors is that control vendors do not have to develop different translations for different customers.” Rapid demand response PG&E began introducing OpenADR into its service area in 2007. Today, the utility has it deployed to approximately 200 locations including retailers IKEA, Target, Walmart and Staples as well as several commercial and industrial facilities. “Internally, we can better predict customer load reductions and increase customers’ DR performance,” said Chiu. “We like the fact their DR capabilities are more reliable so we can potentially provide the DR resources into the wholesale market. Customers who understand demand response and have more sophisticated energy management systems really like the Auto-DR technology.” Piette at Lawrence Berkley National Laboratory explained how OpenADR became important in California and why the federal government is sup-

porting it for the future of the smart grid nationally: “In California we have renewable portfolio standards. As we get more wind and solar on the grid we are looking at how demand response can respond very quickly to help manage an intermittent grid. “With an intermittent supply, managing the grid becomes more difficult and getting the demand systems to be more interactive with the supply systems will help provide more reliable power with low carbon systems,” she said. “OpenADR is part of what is being used to test very fast demand response. Whether you are using prices day-ahead, hour-ahead or literally minutes-ahead, OpenADR is capable as a platform for common signaling.” Convenient technology development “Over the next few years everybody in California will be subject to dynamic

pricing and we assume it will continue to spread across the country,” said Chiu. “With more renewables, the intermittency problem will be a concern. With the paradigm of having renewables and the development of smart grid, using customer load as a resource is not going to be an option, rather a requirement, in the future. Hopefully, regulators in other parts of the country will start adopting dynamic pricing and utilization of Auto-DR. We are developing the technology that will make it more convenient for all stakeholders in using DR as a resource.” OpenADR Version 2.0 is being refined and should be available for a formal review this spring in partnership with the NIST Smart Grid Interoperability Standards efforts. Eventually, the OpenADR Alliance expects it will be adopted by FERC (Federal Energy Regulatory Commission). Barriers remain There are many barriers to the widespread adoption of OpenADR, but they can be overcome. It will require investment on the part of load generators or third parties to provide demand response automation servers and buildings and large facilities to respond to Auto-DR. Customers currently participating in OpenADR programs continue to be notified by fax, e-mail and pager (as done in manual DR), so transitions to automation could be relatively seamless. Of course, it will require more education on the customer side. Control system providers are already selling the benefits of automated demand response to commercial, industrial and residential applications, and customers are eager to cut energy bills by participating in DR programs. Mike Breslin is a freelance writer and novelist based in New Jersey.


Enspiria. When weighing your choices in smart grid systems integration and consulting, there is one clear powerhouse. From project management, to enterprise architecture, to business process and change management, to field testing, Enspiria has done the heavy lifting for more than 2500 successful client engagements. And nine out of 10 clients are repeat customers, coming to Enspiria time and time again to assess, design, implement and monitor their smart grid projects. Some say it’s because of the relationships forged with our people, who work hand-in-hand with your team to continually surpass expectations. Others point to the high return on investment that occurs when every Enspiria person dedicated to your project team is a recognized expert in his or her field. Clients and market analysts agree. When it comes to smart grid, no one carries more weight than Enspiria.


Real People with Inspired Solutions to Real Problems • 303.741.8400


© 2011 Enspiria Solutions, Inc., a Black & Veatch Company

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IT and executive champions play crucial role


++ComEd and PECO deliver on an ambitious mobile platform By Joe Kovacs JUST OVER A YEAR AGO, TWO ELECTRIC UTILITIES THAT ARE

part of the Exelon Corporation—ComEd and PECO—delivered on an ambitious project to provide a mobile dispatch and workforce management platform that impacted virtually all aspects of the utilities’ operations. Successfully integrating technological applications and capabilities represented more than just add-on benefits to customer service capabilities; it restructured— with an aim toward greater efficiency—how line and dispatch personnel interface, how communications work and how response times to outage reporting, metering services and other responsibilities improve. The mobile dispatch solution was a multi-year endeavor and is the story of a well-thought-out business case that articulated the value of more effective communications and improved customer service.

A compelling argument first Mark Browning, IT director for Exelon Business Services in Chicago, explained that securing approval (and the financial investment) for an initiative that would ultimately outfit thousands of vehicles with mobile dispatch terminals, as well as deliver an array of new technological applications and dispatch stations, meant delivering a compelling argument for how the utilities and customers stood to benefit. Much was at stake, given the magnitude of the project. Chicagobased ComEd delivers electricity to approximately 3.8 million customers across northern Illinois, or nearly three-quarters of the state’s population. Approval for mobile dispatch came in 2006—more than three years before the end product was delivered in December 2009. Charleen Miller, project manager for the mobile dispatch workforce management system at ComEd, says there was a precedent for utilizing such applications—that in fact the project was a scale-up from applications that already existed and were in use by ComEd’s metering teams. Implementing technologies wasn’t a foreign concept, therefore, and new capabilities became available such as GPS, electronic dispatch of work orders to field teams as well as their status (e.g., ongoing, closed). Beyond the availability of new applications and the information they delivered was communications via a dispatch infrastructure—personnel in need of outage-, geographicor customer-related data had access to the technology or the means to capture it. Browning points to the essentially horizontal nature of the mobile dispatch system as one key to the project’s success or, as he says more simply, “trust and respect.” Whether it was line or field personnel or leadership in need of information, the same tools,

resources and, most importantly, access was available to all. “We make sure no one is left out,” he said. Change caused some concern Of course one fundamental aspect of mobile dispatch was the significant impact on workforce management. Following a needs assessment of skill sets and technological know-how, personnel were trained and equipped with the knowledge needed to operate in the new technologyA shared sense of ownerdriven environment. Change on this scale caused some concern ship led not only to greater among personnel. But, Miller said: “It was fortuunderstanding but also to nate our workers clearly vocalized their hesitation, which allowed active feedback. trainers to deliver learning in a manner that would be most effective. Some ‘superusers’—colleagues with existing familiarity with the technology—could go out with some members of less experienced field teams and work with them.” As a result, a great deal of enthusiasm was generated about the new dispatch capabilities, about improved and quicker communications and also about data sharing and the ability to deliver benefits such as real-time responses to customers.

Joe Kovacs is a freelance writer based in Washington, D.C.

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A shared sense of ownership In addition to customized training, one key factor driving the success of mobile dispatch was the direct involvement of executive leadership who championed the cause. Vice presidents from ComEd and PECO participated in a steering committee to guide the project. Even if in only a limited way (i.e., through the metering teams), technology held a respected place in the utilities’ operations and executive management willingly committed to furthering its applications to deliver business benefits of improved customer communications and operational efficiencies. Finally, IT team members played a crucial role. Typically, IT will deliver end products and applications that respond to business needs. But by the very technical nature of IT expertise, there is the potential for not understanding broad strategic business goals. Project teams for mobile dispatch, however, spanned departments and incorporated a sophisticated array of personnel—including IT. This is typical for Exelon project teams, Browning said. Miller further explained that with executive leaders and line and dispatch team members collaborating, a shared sense of ownership led not only to greater understanding but also to active feedback regarding benefits unperceived in earlier stages of the initiative. Although customers were not aware of the existence of mobile dispatch per se, they have noticed quicker, more thorough communications with the utilities. With cost savings projected to amount to more than $27 million by the end of 2012 (in line with targeted goals), ComEd and PECO have successfully maneuvered through a complex, technologydriven initiative that impressively responds more efficiently to the electricity needs of customers across Chicago and a great part of the state of Illinois.

Transaction Papers Needed



Dynamic pricing gurus needed ++The new utility focus: sell, sell, sell By Patti Harper-Slaboszewicz UTILITIES ARE SHIFTING THEIR ATTENTION FROM DELIVERING


commodities to partnering and offering choices to their customers. It’s a paradigm shift for utilities today—what might our customers need from us as a service provider? This new perspective is not entirely accepted by all policy makers and consultants. But, as we go forward with system upgrades in an atmosphere where customers may question the value of those upgrades, the customer experience will be given much higher priority in regulatory hearings as well as in utility strategic initiatives. Rather than making decisions for customers, utilities will need to offer customers compelling products and services for them to select from that are seen as desirable by regulators and other policy makers.


California sets a precedent The relationship between regulators and customers has changed. In California in 2008, the vision was that all customers would eventually take service under dynamic pricing. However, in 2010, new California legislation and regulatory rulings make it clear that all customers will be allowed to opt out of dynamic pricing, even if that is the default rate. Since there have been relatively few precedents set in this area, other states are likely to follow the lead of California and make dynamic pricing optional, even if it is the default plan. The one exception to this rule may be peak-time rebate plans, since customers can only save on these particular plans. Regulators and other policy makers are likely to view rebate plans as more benign, especially if rebate plans are stacked on top of current pricing plans. Going forward, then, in order get broad participation in dynamic pricing and energy efficiency, utilities will need to behave differently—they will need to SELL. They will now require marketing, sales and delivery strategies. They have to create demand for products that customers don’t know they need. While it may seem daunting to sell customers products they’re not sure they need or want, we’ve seen plenty of successful new product launches in the past few years, including: cameras, internet access and e-mail in cell phones; eBooks and eReaders; Netflix; and internet service cards for laptops.

My family uses all of the items on the above list and would not want to go back to life without them. How were these sold to us? The first attempts to sell us on camera phones weren’t very effective. Eventually we ended up with cameras in our phones because they were the cell phones of choice, and by the way, they had cameras. It was only after having embedded cameras in our cell phones that we found them useful. Now, we use them regularly to communicate with pictures where words would be less effective. As another example, our family began using eReaders and eBooks in December. We had resisted them for a long time. However, with a son in the Navy about to embark on submarine duty, we thought a Kindle where he could store a lot of books in a small space might be attractive. The other new products listed above were easy to sell to us. Some products and services just sell themselves because it’s obvious how each new product will enhance their lives. Marketing and the role of geniuses Selling dynamic pricing is going to be similar to selling cameras in cell phones—the need for dynamic pricing will not be obvious to most customers. We’re going to have to sell customers on why they need dynamic pricing and our first efforts may fall flat. To market effectively, we need stories that evoke scenarios where customers are motivated to take action to reduce energy during events or enroll in dynamic pricing and in energy efficiency programs as well. In my position of working as a consultant to utilities with dynamic pricing or energy efficiency on the

Patti Harper-Slaboszewicz is a consulting and management professional with more than 20 years’ experience in utilities and consulting.

The Cisco Connected Grid It’s The Direction Energy Is Moving In Announcing a whole new way to improve the efficiency and energy management of the power grid. The Cisco® Connected Grid is an end-toend communications solution that delivers more control, efficiency and savings than before by enabling utilities to interconnect critical areas of the grid through a central network. With the Cisco Connected Grid you can automate your entire energy chain—from transmission and distribution to businesses and homes. So now you can dramatically increase grid reliability and responsiveness while still lowering your operating costs. To learn more about the benefits of connecting your utility to the network, visit us at


horizon, I’ve had the opportunity to visit with utility executives about reaching out to customers. Most utilities are well aware this is a new and unusual concept for their organization and are engaging with marketing firms to take advantage of their expertise in developing effective campaigns. But there is a lot more to a successful product launch than marketing campaigns that inspire customer participation and enrollment. Consider, for example, customer service. No matter how clearly written your instructions or how many Frequently Asked Questions, or FAQs, are posted online, until customers attempt to use your new product or service, it won’t be clear what additional help they may require. When Google launched the Nexus One phone in January 2010, Google sold it directly to consumers rather than through the normal channel of a cellular provider. Google seriously underestimated the need for customer service and had to scramble to cobble together a solution. Its lack of planning—and, furthermore, even understanding of the need for customer service—threatened the product launch. It’s notable that in the launch of the new Nexus S phone from Google, it is being offered through other companies who will presumably provide customer service. Utilities may want to consider emulating Apple— the innovative company created a “Genius Bar” staffed by “Apple Geniuses” in its retail stores. Customers can bring any question about Apple products to the Genius Bar, at no cost. Even better, an Apple Genius has the autonomy to make decisions to resolve problems. Motto of the Apple Retail Store: “Come to shop. Return to learn.” Utilities might entertain hiring and training selected customer service representatives to be “Dynamic Pricing Gurus” or “Energy Efficiency Pros.” Answering customer questions about whether a dynamic pricing plan is the best option may lead to follow-up calls on energy efficiency. Dynamic Pricing Gurus and Energy Efficiency Pros will need to be well versed in all utility products—not only programs but also tools offered to customers to help them be successful on utility programs. Changing the paradigm requires not only offering customer choices but extending the recognition of customer choice throughout utility business processes and, in particular, providing quality customer service to support the transition of utilities thinking of customers and customers thinking of energy.



More than just meters ++EPB reduces emissions while producing energy savings By Ken Silverstein




one local electricity distributor says that it is about a lot more than just the meters. Chattanooga-based Electric Power Board (EPB) says that it is about optimizing technology for the benefit of the entire community. Smart grid systems center on controlling energy use, which in turn will limit emissions, preserve the environment and increase grid reliability. It’s an holistic approach. That means scheduling the most economical fuels and building a digital network that extends to meters, which can then signal consumers to cut their energy usage. High hopes now exist as the cause is supported by national public policy that is enabling pilot projects to become commercialized. “We wake up thinking about what we can do for our community, not the shareholders,” said David Wade, chief operating officer for EPB. “The smart grid is about being intelligent, interactive and self-healing.” Smart grid trials have reduced brownouts If the smart grid is to grow in value, he says that it must be able to communicate with hundreds of thousands of devices throughout the system. The goal is to reduce outage times, which in turn, keeps economic activity humming. In the case of EPB, its trials with the smart grid have cut brownouts by 40 percent. In other words, its installation of the appropriate switches and meters has boosted the local economy there by 40 percent—a number that it says is “conservative.”

If, for example, it cost $100 million to implement but it resulted in 40 percent more productivity, then the payback is quick. As for EPB, it says that it got a $111 million smart grid grant from the federal stimulus plan. It matched that grant with its own $111 million. By August 2012, the local distributor (which is tied to the Tennessee Valley Authority) says that it will be mostly done with its rollout, including 170,000 meters. The process started in 2009 and entails the utility reaching inside customers’ homes to adjust energy usage during peak periods. During this time, EPB said that it did not receive any complaints and that the estimated savings ranged from very little to noticeable amounts. By using demand management, it says that it could avoid or delay buying additional generation, which is often at high prices. Beyond the switches and the meters, EPB has also been building out its fiber and communications systems for the past two years. In short order, it will be able to offer high-speed Internet services to 100,000 homes and businesses. “Electric rates will be going up,” said Harold DePriest, chief executive of

EPB. “The smart grid can reduce that increase. But we should be careful to not promise that it will reduce rates.”

conditions as well as fuel costs and then compile that information so that utilities can operate their plants as a fleet. At the same time, the grid is changing. With or without national renewable portfolio standards that mandate green energy usage, such sustainable fuel forms will grow. It then becomes a technical question as to how to integrate those renewables into the system, particularly as they expand from 2 percent of the portfolio mix today to as much as 20 percent. It involves maximizing the performance of power plants and the transmission grid while also communicating with customers so that they can participate. To succeed, a comprehensive approach is necessary—one that increases the productivity and efficiency of everything from power plants to distribution grids to consumer appliances. The tools to achieve higher standards are, in fact, emerging and are partly driven by consumer concerns and partly by global initiatives meant to minimize emissions. It’s a powerful one-two punch.

Reducing emissions, producing energy savings All utilities are under pressure to limit their emissions and to produce energy savings. And many power companies are already making investments somewhere along the value chain in the intelligent utility. Now that the federal government is more involved, it should expedite the progress. Altogether, the stimulus plan sets Energy efficiency will save jobs aside about $4.5 billion to According to Cognyst Advisors, the advanced metering modernize the grid—an The smart grid industry that permits utilities and consumers to commuendeavor that involves nicate with each other grew by 40 percent from 2008 to increasing reliability and is about being 2009. At that pace, a third of all meters will be “smart” by curtailing consumption. the end of 2011. It’s all coupled with the intelligent, The Electric Power Research Institute, meanwhile, says push to limit carbon emisthat deployment of a highly automated system could limit sions and to increase the interactive and electricity consumption by reducing sales by 1.2 to 4.3 use of renewable energy. percent by 2030. The Galvin Electricity Initiative adds for Utilities are therefore self-healing. every dollar spent on the smart grid, $4 or $5 is returned. under the twin pressures That’s not just from the marginal savings of electricity. It’s of managing their fuel mix also from job growth and productivity. while keeping down costs. Part of the The smart grid is already delivering results for EPB. Businesses are seeing intelligent utility involves equipping fewer outages and are therefore staying more productive. Over time, though, power plants with the tools to analyze they are also hoping to see less price volatility. That’s money that will be used to and monitor efficiency and emissions grow their enterprises and help expand the region’s fortunes. processes. Such technologies can also Ken Silverstein is editor-in-chief of EnergyBiz Insider Daily. evaluate market and environmental



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