Vol 2, iSSue 5 » September/october 2010 » www.intelligentutility.com
» it + tHe SmArt griD
where smart grid meets business—and reality.
regulatory reflux ©
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smart grid resistance sharp security Compliance strategies developed
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preparing personnel Changing face of the utility workforce
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utility insights » Aec » Ameren » bge » centrAl HuDSon » Dte » DuKe energy » pg+e » progreSS energy » Sce » Srp » weStAr energy
A N E N E RGY CE NTR AL PU BLI CATION
An Exclusive Invitation Only Event! Fairmont Scottsdale Princess Scottsdale, Arizona November 8 - 10, 2010 Optimizing the convergence of Information Technology, Operations and Customer Service in the new Intelligent Utility In the intelligent utility of the future, true operational and energy efficiency will only be achieved through the successful synergy of three mission-critical utility operations: Information Technology, Operations, and Customer Service. It is this challenge that has driven Energy Central to create Knowledge2010 — Intelligent Utility Executive Summit, an exclusive, invitation-only, knowledge sharing event for top executives in these three utility functions.
I N T E L L I G E N T U T I L I T Y E N T E R P R I S E : V I S I O N & P R O G R E S S T O D AT E
The Knowledge2010 — Intelligent Utility Executive Summit offers a unique opportunity to: • Engage in unique, off-record roundtables with your peers in IT, Operations, and Customer Service • Compare results of pilot programs and lessons learned • Gain insight from thought leaders (industry and non-industry perspectives) on emerging trends in technology, business, operations, and consumer behavior • Network in an open and friendly environment, with no point-of-sale pressure • Attend the 2010 EnergyBiz KITE Awards ceremony for IT, Operations and Customer Service
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INFORMATION TECHNOLOGY CUSTOMER SERVICE - OPERATIONS If you are a senior executive at a utility/ISO/RTO and have ultimate responsibility for enterprise-level decisions, you should not miss this one of a kind summit. A LIMITED number of complimentary packages (registration, hotel and travel) are available to qualified utility executives. Contact E-mail Call Online
Jana Koehn at Energy Central today for additional information: events@energycentral.com 303.228.4735 www.knowledgesummits.com
Knowledge2010 Program Chairs IT Chairperson
Customer Service Chairperson
Operations Chairperson
Rick Nicholson IDC Energy Insights
Jon Brock Desert Sky Group
Christopher Perdue Sierra Energy Group
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contents SpeciAl report it + tHe SmArt griD
32
the it vs. ot debate
33
a seamless blending
At SRP, operations retains control over IT support
Power, communications + IT on the smart grid
DepArtmentS
18 FeAtureS // September/october 2010
Regulatory reflux
18 20
smart grid resistance Consumers and regulators turn up the heat on utilities
Leading the smart grid charge
w ww.intelligentutilit y.com /// Septem ber/october 2010
2
26
compliance strategies developed Utilities in good shape, industry experts say
cyber security an unending challenge Sisyphus and his boulder had nothing on utilities
Preparing personnel
28
28
Will regulators or consumers take the lead?
Sharp security
24
24 33
4 6 10
36 40 42 44 46
drawing the line transmissions 6
Letters from readers
8
Intelligent Utility defined
the big picture 10
Committed to success
12
Integrating transmission
16
IT and the Smart Grid
grid(un)lock 36
Age adds robustness
end of the line 40
Distributed resource planning
4d 42
If a tree falls in the forest
connections 44
Smart meters and the coming data deluge
out the door 46
Sharing right of ways
40
the changing face of the utility workforce A convergence of technology, communications, computing and energy systems amps up the game
44 Vol. 2, No. 5, 2010 by Energy Central. All rights reserved. Permission to reprint or quote excerpts granted by written request only. Intelligent Utility速 is published bimonthly by Energy Central, 2821 S. Parker Road, Suite 1105, Aurora, CO 80014. Subscriptions are available by request. POSTMASTER: Send address changes to Intelligent Utility, 2821 S. Parker Road, Suite 1105, Aurora, CO 80014. Customer service: 303.782.5510. For change of address include old address as well as new address with both ZIP codes. Allow four to six weeks for change of address to become effective. Please include current mailing label when writing about your subscription.
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Answers for energy.
D r aw i n g t h e l i n e
An epic win, or an epic failure? Let’s face it: Many people simply don’t like change. And if it’s change
that comes with new technology, or the potential (even if it’s simply a perceived potential) for increased costs, people like it even less. And if they find they can’t fight it on a regulatory level, they’ll find other ways in which to do so. There is extremely vocal opposition to smart meters in PG&E territory in California. But that’s not the only place in which it’s cropping up. And getting the customer portion of this equation right has quickly become one of the biggest goals of utilities rolling out their smart grid projects. As my colleague Christopher Perdue wrote in his Intelligent Utility Insights column online in early August, “We can engage in a dialogue with utility customers until we are blue in the face, but at the end of the day if utility customers do not change their behavior, our industry’s smart grid efforts will be a failure of epic proportions.” In this issue, we take a closer look at what we’re calling “regulatory reflux,” or the ongoing regulatory issues surrounding smart grid, and how they are affecting technology deployments. Consumer pressure, we found, is oftentimes fuelling regulatory pressure. As well, we’ve cast an eye in other directions: ??
New projects are up and running all over the country. H. Christine Richards visited Westar Energy in Lawrence, Kansas, and brought back the details on the utility’s SmartStar Lawrence project. Phil Johnson explored Ameren Corp.’s critical role in Missouri and Illinois as a midcontinent transmission linchpin. [See pp. 10-14.]
??
The blending of IT and OT within a utility is not always an easy mind-meld. Phil Carson focused on the efforts the Salt River Project is making to do so, and NREL’s Dick DeBlasio provided us with an overview of how engineers from each area are bringing power, communications and IT together on the smart grid to drive
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advancements. [See pp. 32-34.]
4
??
The June 1, 2010, compliance deadline for eight NERC CIP standards has come and gone. Joe Kovacs checked in with industry experts to determine how utilities have fared so far. [See page 24.]
This mid-2010 consumer pushback serves as a reminder that the move to a more intelligent utility truly is an evolution, and it won’t be without its twists and turns, as well as its high hurdles. But in the meantime, both utility projects and vendor partner technologies continue to advance, and there is much to celebrate. sue? Then In the November/December issue, we will look at the Top 11 projections for 2011. Enjoy the is for free at What do you think we should make sure to include? subscribe .com/ igentutility ll te .in w w w subscribe Kate Rowland Editor-in-Chief, Intelligent Utility magazine krowland@energycentral.com
At Montana-Dakota Utilities, our needs are evolving to meet the shifting landscape of the industry. When searching for a metering solution to read electricity and gas meters in a diverse service territory, we turned to Itron and ChoiceConnect™—the industry’s most affordable, proven and flexible advanced metering platform. With mobile and fixed network systems collecting detailed consumption information and a meter data management system leveraging the data, Itron offers a progressive blend of technologies that enable us to deploy the precise solution we need, where and when we need it. MDU and Itron—advanced metering solutions for today and tomorrow.
transmissions
Letters from readers
EDITO R-I N- CHI EF Kate Rowland
krowland@energycentral.com 720.331.3555
Meeting at ferc’s place just one subcategory of it. Wind is (july/august) like hydro when it comes to the use The transmission discussion is trapped of transmission. But unlike hydro, it in a small box and you have allowed requires either gas-fired peakers or enyourself to fall into it. Allow me to ergy storage to complement it. Where illustrate by paraphrasing one of should these be located? your paragraphs: In the 1980s the California PUC The regulatory changes could not concluded that using natural gas for come fast enough. Railroad investair conditioning on a commercial scale ment has declined in has a lower societal cost real terms—adjusted for than using electric air inflation—from 1890 conditioning. But the to 1913. While there rate structure the PUC Transmission have been increases supported, and conBrain + Brawn since 1913, the ICC says tinues to support, says that the level is still less the opposite. Nothing than what was invested changed, because in this in 1890. Over the same industry true efficientime period, however, cy—and the real fairthe demand for transness to customers that it portation has increased brings—is consistently greatly. That’s resulted in a significant sacrificed to political goals and infludecrease in railroad capacity, requiring ence dressed up as “fairness.” new lines get built. Distributed generation, be it solar Leave aside that the last sentence or gas-fired, further reduces the need must have meant to say that capacity for transmission (and distribution). has been growing, just more slowly Electric transmission has as many than the market for electricity or growing competitors today as railtransportation. The parallel here roads had 100 years ago. Real thinkers is one that needs to be considered. recognize that the first question today Hydro plants and large nuclear plants about electric transmission is how required a lot of electric transmisdoes it fit into the larger picture hinted sion to reach their markets. Coal is at above. It is unfortunate that this economical to transport by wire and industry is so lacking in real thought, there is a desire to disperse coal plants, so constrained within yesteryear’s little rather than have them ring our large boxes. You owe it to your readers to cities. But natural gas-fired power ask bigger questions. plants have a very different economic Dick Maclay geography. It is less costly and more reliable to move energy in pipelines to contribute to the than over wires. Natural gas generatransmissions department, tion is so clean, especially now, there please e-mail your submission to intelligentutility.editor@energycentral. is no real problem in having it sited com. provide your name, address and near cities. daytime phone number. letters may be An intelligent discussion would edited for style and space. address energy transportation, not » smArt meters
CHI EF CO PY EDITO R S Martha Collins, Joe Kovacs S EN I O R CO NTRI BUTO R S
Phil Carson Editor-in-chief, Intelligent Utility Daily pcarson@energycentral.com
303.228.4757
Christopher Perdue Vice President, Sierra Energy Group cperdue@energycentral.com
310.471.7396
Ken Silverstein Editor-in-chief, EnergyBiz Insider ksilverstein@energycentral.com
304.345.5777
FE ATU RE W RITER S Mike Breslin, John Johnson,
Phil Johnson, Joe Kovacs, Laurel Lundstrom, Elizabeth
VOl 2, Issue 4 » July/August 2010 » www.IntellIgentutIlIty.cOm
McGowan, H. Christine Richards, J. Ian Tennant V ICE PR E S I DENT, I NTELLIG ENT UTI LIT Y DI V I S I O N Mark Johnson
where smart grid meets business—and reality.
mark@energycentral.com 303.228.4721 SEN I O R V ICE PRE SI DENT/G ROU P PU B LI SH ER Tim L. Tobeck
ttobeck@energycentral.com
303.228.4752
©©
Smartening up the hardware
©©
Federal + state smarts
DI RECTO R O F M A RK E TI NG A N D PRO DUCTI O N
Meeting at FERC’s place
Sarah W. Frazier
©©
Where did utility R&D go? Research in practice
©©
utility insights
sfrazier@energycentral.com
303.228.4733
M A R K E TI NG CO M M U N IC ATI O N S M A N AG ER
» BPA » Duke energy
Brenda Roode
» meD » OncOr » Pg+e » sce
» sDg+e » smuD
» sOuthern cOmPAny
broode@energycentral.com
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Transmissions
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: ??
People The knowledge, skills and abilities required in an informationenabled environment
??
Process & technology 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 ??
Economic models The challenges and opportunities of new paradigms
??
Finance Investment trends associated with smart technologies
??
Public policy 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
w ww.intelligentutilit y.com /// Septem ber/october 2010
krowland@energycentral.com
8
together utility leaders to network with their colleagues, and a research, analysis and consulting services division. Beyond the boundaries of the magazine, we provide:
IntelligentUtility.com: A companion for Intelligent Utility magazine, this Web site provides
720.331.3555
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 pcarson@energycentral.com 303.228.4757
Christopher Perdue vice president Sierra Energy Group cperdue@energycentral.com 310.471.7396
Mark Johnson vice president Intelligent Utility Division mark@energycentral.com 303.228.4721
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 utilities and vendors to the industry.
Knowledge Intelligent Utility Executive Summit: This annual event brings together 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.
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the big picture
Committed to success ++Westar is serious about customer engagement By H. Christine Richards Ah, I love my home state of Kansas. The rolling hills
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(yes, Kansas has hills), the Wizard of Oz, the tasty barbeque—and the laid-back Midwestern humor. The folks at Westar Energy—a utility headquartered in Topeka, Kan., that employs 2,400 people and serves more than 684,000 customers in east and east-central Kansas—not only understood my humor, but also understood a critical factor in the success of smart grid projects: customer engagement. I recently visited the utility’s office in Lawrence, Kan., and learned that Westar Energy is serious about making sure that customers matter most in their smart grid project—SmartStar Lawrence.
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Project background Before diving into Westar’s customer engagement efforts, let’s quickly review the SmartStar Lawrence project. The project will install 48,000 smart meters in Lawrence—a town about 40 miles west of Kansas City that’s home to the University of Kansas. On top of the smart meter installation, the project will deploy distribution automation, smart gridenabled outage management and supporting IT infrastructure. Even though the meters only cover a portion of Westar’s service territory, the project will build out the entire IT infrastructure needed to support a systemwide deployment of smart meters. The three-year project will cost about $40 million. The U.S. Department of Energy (DOE) will cover about $19 million of that through the Smart Grid Investment Grant program from the 2009 American Recovery and Reinvestment Act (ARRA). “We knew a smart grid initiative was going to be undertaken at some point,” said Hal Jensen, who has worked with Westar for nearly 20 years in various roles and currently serves as director of SmartStar programs. “The ARRA presented an opportunity to move forward, and Westar looked at the opportunity very diligently. We had to understand the rules of the game. We became comfortable with them and ultimately made an application.” On March 26, 2010, Westar signed an agreement with the DOE to move forward with the project. Testing the unknown Through the SmartStar Lawrence project, Westar will work to prove the assumptions it laid out in its business case, but some will be more difficult than others. “We generally know how many truck rolls we’ll save and other business items like that, but what we don’t know is the customer reaction,” said Jensen. “How do we promote the project? How do we attract and engage customers? How will customers accept it?” A first step for engaging customers was rallying community leaders around the project. “We didn’t want the project to cover just a portion of a town. We wanted a communitywide effort,” Jensen said. “To that extent, we’ve worked very
closely with city and county officials, the chamber and other key organizations—like the University of Kansas. We’ve been actively engaged with all of them from the very beginning.” “I couldn’t ask for a better response from the community,” added Jim Ludwig, who’s been with Westar for 20 years and serves as the executive vice president of public affairs and consumer services. “Whether it’s elected officials, the chamber or community leaders, they’ve been very supportive and accepting.” Westar has successfully rallied community leaders around SmartStar Lawrence, but what about rallying everyday customers? Community building was key, but Westar realizes it has to go further. Other ways Westar is engaging customers include: ??
Community-based marketing
??
Immediate interactivity with smart meters
??
Employees as smart grid ambassadors
“We want to make sure there is intrinsic value for the customer and that we can effectively serve as an energy
”
advisor for the customer. Community-based marketing For customers to accept smart grid, they have to know what the term means. “It’s not a known entity we’re rolling out here,” Jensen said. “As we plan our communications effort, we realize it must start with a very fundamental message about smart grid to build awareness. Once we get past that, then we can start explaining the
project specifics and generating the excitement and enthusiasm for what we’ll be able to offer customers.” In addition to Westar efforts, the company is working on joint marketing with the city, the county and the chamber of commerce—all in the spirit of building total energy awareness in the community. This includes linking the SmartStar project with other energy projects that have been going on for a while. By tying many energy projects together, Westar expects to build a broader customer understanding and awareness of energy. Although the initial messages about SmartStar will be consistent across the service territory, Westar realizes that customers will have more sophisticated needs as they learn more about the smart grid. “Customer engagement is going to evolve and we realize that customers won’t move monolithically in the same direction,” said Ludwig. “We’ll have to build out those customer segments as we go,” added Peggy Loyd, Westar’s vice president of customer care. “Right now, as a traditional utility company, everyone’s the same. We have to spend a lot of time developing those segments and understanding the best messages and offerings to put in front of them.”
Employees as smart grid ambassadors Another key customer engagement component is Westar’s employees. “We’re a service territory of small towns,” Ludwig said. “So when consumers want to know something about us, they typically ask one of our employees. They’re our ambassadors.” Westar has numerous efforts under way to educate employees. Those employees not directly participating in the SmartStar project are getting smarter about the smart grid so they can better inform customers. These education efforts include everything from a SmartStar quiz with the opportunity to win prizes to SmartStar weekly updates to in-person employee presentations. In addition to education, the company culture is focusing more on the customer. “I’m a technical guy, and I’m looking forward to the technology,” said Kevin Heimiller, who’s been with the company for 36 years and is director for advanced metering infrastructure. “But I’m also becoming customer driven. I’m really pumped about it. I think it’s really good stuff, and it’s going to be really good for our customers. We need to do it right.” The push for the customer is also driving better cohesion within the company. “Not they we haven’t had challenges working together, but everyone is on board,” Heimiller said. “It’s like ‘let’s talk about this, let’s concentrate on the customer.’” All in all, Westar’s focus is not only on building a smarter grid, but also on truly engaging the customer, which is proving to be another reason to love Kansas. “It’s been rewarding and a lot of fun because it’s a new frontier for us. And really, in many ways for our industry and our customers,” Ludwig said. H. Christine Richards is a researcher and writer based in Colorado.
w w w. i n t e ll ig e n t u t i l i t y.co m
Immediate interactivity Westar realizes that true customer engagement won’t come through just a slick marketing campaign and a smart meter. Customers need opportunities for immediate interactivity with the new technologies. Ludwig pointed out that “it’s just not satisfactory for customers to say that their memory of a smart grid experience was Westar showing up at their house, inconveniencing them while they got a new meter installed, and then nothing else happened. That’s not a good customer experience.” Westar customers will be able to access information through a web portal shortly after their meters are installed.
The portal may not offer all the information customers could ever want, but it will help them track daily energy usage, cost information and their carbon footprint. The information offerings will evolve over time, based on customer demand. “We want to determine what information will have value for customers and that it’s something they’re interested in. If that’s the case, then we’ll look at what format they would like it in,” Jensen said. “It is important to understand that before we go too much further in deployment. We want to make sure there is intrinsic value for the customer, and that we can effectively serve as an energy advisor for the customer.”
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the big picture
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Integrating transmission
12
++Ameren is a critical linchpin By Phil Johnson Among electric utilities and their ownership
organizations, some serve extensive geographies and therefore become more involved in high-voltage transmission, moving large quantities of electricity from points of generation to load centers within their service areas, as well as transmitting electricity to other areas on a market basis. A good example of one such utility organization is St. Louis-based Ameren Corp. Ameren maintains and operates more than 7,000 circuit-miles of transmission lines in Missouri and Illinois, coursing across the sprawling service territories of its four electric utilities: AmerenCILCO, based in Peoria, Ill.; AmerenCIPS, based in Springfield, Ill.; AmerenIP, based in Decatur, Ill.; and AmerenUE, with the
“UE” standing for longtime electric utility Union Electric in St. Louis. But perhaps even more important is the fact that Ameren is a highly influential and active member organization within MISO—the Midwest Independent System Operator, headquartered in Carmel, Ind. (a north Indianapolis suburb). MISO includes utilities among its large membership roster that collectively operate in a total of 11 states—and MISO exercises nominal, “functional” control of member organizations’ assets across a huge geographic footprint from Ohio in the east to the Dakota/Montana plains in the west. So Ameren plays a critical role as a midcontinent transmission linchpin. Singular control across all four “Among Ameren’s four utilities, we operate their transmission as a single,
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the big picture integrated whole,” said Maureen Borkowsky, Ameren Services Co. vice president of transmission. “We have a single control center that operates the transmission of all four of our utilities together. “And even before Ameren became ‘Ameren,’ and acquired the three utilities in Illinois, we always had connections among ourselves. In fact, Ameren—next to AEP—was one of the most interconnected utilities in the country. “At one point, before we and others around us started buying other companies, we actually had interconnections with 23 different utilities—which is pretty impressive. And, of course, in part it’s because of our geographic location in Among Ameren’s four the center of the country.” It is therefore easy to understand utilities, we operate why Ameren’s membership in and interaction with MISO provides fountheir transmission as a dational transmission infrastructure for both local and cross-continent single, integrated whole. movement of electricity.
“
We have a single control
MISO monitoring “What the Midwest ISO basically does center that operates the is monitor the flows on the system, the reliability of the system, the system transmission of all four loadings,” said Borkowsky. “And it can use the generation in its footprint of our utilities together. to manage the flows by reducing or increasing generation in certain areas. “We coordinate closely with MISO. We, too, are monitoring the loadings and the flows, as well as the voltages and the system frequency on our transmission system. So it’s kind of a ‘partnership’ in that regard.” Among the results of the close monitoring of transmission by MISO and its member utilities, hiccups in transmission are usually dealt with and remedied quickly and efficiently, without trauma or often even knowledge on the part of customers. “Any kind of disturbance or contingency that happens anywhere within the entire Eastern Interconnection [from the Atlantic Ocean all the way west to the Rocky Mountains], we all experience it in some way or another, either due to system frequency or if a line goes out, basically the flow on that line, then, shifts to the other lines in the network,” Borkowsky said. “Regardless of who ‘owns’ them, it basically follows the laws of physics in terms of where the flow on those lines is going to move to—to adjust and keep the system in balance.” Effectively and efficiently accommodating new generation, largely in the form of renewables—especially wind—is a challenge the utilities and MISO are working diligently to meet. With more than 7,500 megawatts (and rising) of generated wind power within MISO’s footprint, making maximum use of renewables is a priority.
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Transmission’s early smarts And as “smart” electrical devices continue to develop and evolve, transmission systems are generally early adopters. So with these things in mind, could transmission operations take a page from distribution in the area of “self-healing” or reconfiguration of circuits to avoid outages?
“It’s actually kind of the other way around,” said Borkowsky. “We’ve had ‘smart’ devices on the transmission system for a long time. From my control center, in many instances a guy sitting at a computer console can operate breakers and switches that are out on the transmission system. “Now, sometimes we actually do have to call a guy up and have him go out there. But there has been a lot of development on the transmission side in the way of ‘remote operations.’ We do have some of this out there, too—where you can set certain tolerances, and the devices will operate on their own—and, obviously, for system protection, which has been out there for a long time. “But with the newer technology, the idea would be to have the systems intelligent enough to kind of do their own load balancing, and to manage the system in a way that’s safe, reliable and secure. “And there’s quite a bit of technology out there on ‘new’ transmission. The older transmission lines—as their devices age and are replaced, more
of that newer technology is being installed, but certainly as more investment in new transmission occurs, the smarter and smarter the system becomes.” Phil Johnson is a freelance business writer and speechwriter.
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.
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IT and the smart grid ++Xcel CIO discusses IT’s evolving relationships within the utility By Phil Carson
w ww.intelligentutilit y.com /// Septem ber/october 2010
Recently, I had an opportunity to interview
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Dave Harkness, vice president and CIO for Xcel Energy, Inc., which serves 3.4 million electricity customers in eight Western and Midwestern states. Harkness, who will be participating in Energy Central’s Knowledge 2010, talked about IT’s evolving relationships within the utility, about transforming data into actionable intelligence and about the advent of electric vehicles. “The technology is just a piece of what we need to talk about,” Harkness told me. “IT organizations need to have the correct relationships with other aspects of the business, so they can collaborate with, for instance, the legal, regulatory, environmental and business parts of the utility. “You have to be prepared to interact with those groups differently than in the past,” he said. “The solutions we reach need to be more collaborative. It’s not going to be cut-and-dried as in the past 100 years. You need those relationships in place so you can engage in give-and-take [with your colleagues]. Traditionally, [other business units] told us what they needed and we’d go build it.” Collaboration Today’s challenges require a whole new level of collaboration between IT and the utility’s business units, Harkness told me. “This affects everything from the transmission and distribution side of your business to customer care, from your regulatory group to your pricing group,” the Xcel CIO said. “Take the regulatory group, for example. We might not have
a whole lot of interaction with them during a typical rate case where they work with a public utilities commission. But they return with new rates we need to implement, sometimes with complexities such as time-of-use rates.”
“Today’s challenges require a whole new level of collaboration between IT and the utility’s business units.
”
After “collaboration,” it’s not long before terms such as “flexibility” and “architecture” enter the conversation. Future proofing “IT is also responsible for preparing itself to be more flexible,” Harkness said. “From an architectural perspective, we’re a big believer in the `enterprise service bus’, so our systems can interact with one another. You have to have the right technology in place to monitor key applications such as business analytics, so you can under-
stand how those different systems are performing. That enables you to make business decisions closer to real time. “So there are a lot of things we can put in place on the technology side, long before the business decisions have been made, to ensure we have an open architecture and we’ve got reporting capabilities and dashboard capabilities for real-time decisions.” Business modeling tools are in place, at modest cost, to work out how various business decisions might play out in terms of revenue, customer interface systems and other business units, the Xcel CIO said. When those models provide direction on business decisions to take, then the utility can address the necessary IT investments. “As you determine which decisions make sense, whether legal or regulatory or business decisions, that’s when
you make investments in new technology,” Harkness said. “Either way, investments in architectural flexibility and business analytics need to be made up front.” EVs and IT Switching the topic to electric vehicles, which will hit the market this fall, Harkness talked about “big changes.” “Depending on the technology, one plug-in electric vehicle is like plugging another entire house on your street,” he said. “Your local transformers, your infrastructure, aren’t built to handle that.” As for the challenge of keeping track of mobile charging by customers, Harkness’ professional experience points the way. “It’s not something that hasn’t been done in other industries,” he said. “I actually came from the telecom world, so the roaming model doesn’t necessarily scare me. We’ll figure those things out.” Asked how a CIO can possibly keep track of the myriad societal and technical issues that may present themselves as an IT challenge, Harkness mentioned his “network of peers” and the work of the Edison Electric Institute, representing investor-owned utilities, and the National Renewable Energy Laboratory. “We count on them to be out front on these issues,” Harkness said. Phil Carson is editor-in-chief of Intelligent Utility Daily, where this article first appeared.
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regulAtory
reFlux
found in and around homes, to ensure adequate protection from adverse health effects.”
Smart grid resistance ++consumers and regulators turn up the heat on utilities by Kate rowland
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ways than the obvious one. At both ends of the country, consumers and regulators have been turning up the heat on their electric utilities’ smart grid projects. In southern California, Pacific Gas & Electric Corporation has most recently seen pushback from customers in the town of Fairfax and in Marin County (the greater area in which Fairfax is contained). In early August, the Fairfax town council unanimously passed a controversial “urgency ordinance” that placed a temporary moratorium on the deployment of smart meters (specifically PG&E’s SmartMeters) and related equipment within the town, citing concerns about accuracy, data security, health questions and more. Around the same time, California Assemblyman Jared Huffman (D-San Rafael) announced he’d issued a request to the California Council on Science and Technology “to determine whether Federal Communications Commission standards for SmartMeters are sufficiently protective of public health—taking into account current exposure levels to radio frequency and electromagnetic fields—and further to assess whether additional technology-specific standards are needed for SmartMeters and other devices that are commonly
“
bge gets regulatory pushback In the meantime, Baltimore Gas and Electric (BGE) found itself embroiled in a situation with the Maryland Public Service Commission that had the rest of the industry watching closely, wondering what potential relevance the outcome would have on future regulatory decisions across the country.
iLLustration by abby orLando
w ww.intelligentutilit y.com /// Septem ber/october 2010
it’s been a Long, hot suMMer in More
pg+e explains In the wake of all of this, Peter Darbee, PG&E’s chairman and CEO, appeared at a California Public Utilities Commission (PUC) thought leaders event, where he was asked why the public reaction to PG&E’s SmartMeters is it is normal to have so much more negative than to smart meters and AMI systems being some initial pushback installed by other utilities across the country. “As I said in major transformabefore,” Darbee answered, “I don’t think we’ve done as good a job of extional efforts, such as plaining and communicating to the public the benefits of smart meters what smart grid and to begin with.” As well, he said, there was a conami deployments offer. fluence of events in Bakersfield—an earlier base of PG&E smart meter contention, and the one which prompted both PG&E and the CPUC to undertake independent studies to verify the accuracy of the SmartMeters—that included 17 days in July 2009 that were over 100 degrees Fahrenheit, versus only six days the previous July. So, those who used air conditioners over those 17 days would, by virtue of increased electricity use, have bumped themselves up to a higher-tiered, more expensive per-unit pricing, given California’s tiered rate structure.
”
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Regulatory Reflux
In a nutshell, BGE last fall won the U.S. Department of Energy (DOE) nod for a $200 million smart grid investment grant, one of the largest handed out, for its proposed smart grid project. In the meantime, the project was being vetted for approval by the state’s public service commission. In June, the commission said no—it wasn’t impressed with a “tracker surcharge” for cost recovery, mandatory time-of-use pricing and a business case that placed the most project risk on the consumers’ backs/wallets. It did, however, suggest that BGE resubmit an amended proposal. With the DOE grant at risk, BGE went back to the drawing board and quickly resubmitted a proposal the public service commission was able to approve. BGE was quick to point out the consumer benefits in its announcement of the win. “BGE is pleased to move forward with our ambitious smart grid program and deliver the significant transformational benefits to each of our 1.2 million customers,” said BGE’s president and CEO, Kenneth W. DeFontes Jr. “Those benefits include at least $2.5 billion worth of savings for BGE customers over the life of the project, as well as major new enhancements in customer service and reliability. In addition, BGE will be able to take advantage of $200 million that the U.S. Department of Energy awarded BGE for its innovative program, reducing the cost of the project for BGE’s customers by 80 percent.”
w ww.intelligentutilit y.com /// Septem ber/october 2010
Leading the smart grid charge
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++Will regulators or consumers By Ken Silverstein transformation
may
of the New Jersey-based consulting firm Cognyst Advisors. “To level the playing field, it is likely that utility commissions will then force all utilities to offer smart grid services. Thus, the marketplace will begin to influence the rules governing how electric utilities will operate.” A smart grid, for example, can make possible greater integration of renewable generation resources and more deployment of plug-in hyFor every dollar spent brid electric vehicles. A more efficiently run system would on the smart grid, make room for alternative energy sources as well as any addition$4 or $5 is returned. al burdens that would be placed on it from newer innovations. It’s all about reducing costs, maximizing efficiency and empowering consumers—all of which increases a nation’s environmental and economic stature. According to Scott, the advanced metering industry that permits those advances grew by 40 percent from 2008 to 2009. That was in large part because of $4.5 billion in federal stimulus monies—an endeavor that Scott says will lead to 40-50 million smart meters getting deployed by the end of 2011. That would be a third of all meters in this country.
“
take the lead?
The
Looking to the future Is this summer’s increased consumer and, therefore, regulatory pushback the tip of the iceberg, with alarming, belowthe-surface ramifications for the future? “We do not see this as a troubling trend,” said Rob Wilhite, senior vice president of intelligent networks and communications for KEMA Consulting. “It is no secret the utility industry is a very conservative industry. “It is normal to have some initial pushback in major transformational efforts, such as what smart grid and AMI deployments offer. We just need to ensure that we sufficiently develop leading practices for leaders to follow in the next sequence of events.” PG&E’s Darbee would agree. “We’ve been a pioneer in smart meters. But the question is, are we going to be punished for that?” he asked. “Pioneers get a lot of arrows, they got a lot of arrows when they were breaking into America, and we’re getting a lot of arrows here. “The fact of the matter is, those people who come second or third can look at the path that’s been created, and they can see where people did things better, or did things worse, and they can, of course, correct. And they can look smarter and better. “But it takes a pioneer to break that initial ground.”
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regulatory reflux
w ww.intelligentutilit y.com /// Septem ber/october 2010
collaboration necessary Many issues remain unanswered, issues that center on both public policy and technical innovation. Which ideas will get federal help and what are the tax implications for business developers? What will be the standard protocols for running systems, and what incentives will utilities have to participate in this new energy paradigm? Achievement requires collaboration, said Katherine Hamilton, president of the GridWise Alliance, which acts as a consensus-based forum and advocate for the smart grid. The state of Vermont and the city of Austin, Texas, have succeeded because all stakeholders discussed their goals and concerns up front, she said. Building out a smart grid and wishing for the best will not work. “We are just learning,” Hamilton said. “We are at the very beginning and we have a long way to go. There will be a variety of outcomes. We are doing this by trial and error. If you have 100 grant projects, some will be successful and some will face challenges. We will have to learn as we go. We will learn a lot from the stimulus grants.”
22
exercising restraint The smart grid’s relevance is becoming increasingly clear as Congress grapples with renewable portfolio standards, climate mitigation strategies and energy efficiency goals. Indeed, the Electric Power Research Institute in Palo Alto, Calif., says that deployment of a highly automated system could severely cut carbon dioxide releases and at the same time limit electricity consumption by reducing sales by 1.2 to 4.3 percent by 2030. For their part, state utility commissioners, generally, feel they must exercise restraint: Rushing headlong into something that is unproven and so expensive might later be regretted. Their concern is that smart meters that can facilitate energy conservation have yet to bear fruit. And if those meters are unable to do so, then it would be consumers who pay the price for any failures. Kurt Yeager, executive director of the Galvin Electricity Initiative in California, disagrees with that apprehension and says that regulators hold the keys to progress. Utilities are now rewarded based on the amount of electricity they sell. Instead, they should be rewarded on the quality of service they provide, he said. To that end, smart meters are critical and provide the price signals to consumers to tell them when to cut their energy usage. The technologies are already working and would only improve as more technology providers jump in.
But those utilities with monopolies over their electricity markets are reluctant to evolve, meaning that today’s innovators are being shunned away, says Yeager, who adds for every dollar spent on the smart grid, $4 or $5 is returned. That’s not just from the marginal savings of electricity. It’s also from job growth and productivity. no time to wait and see Yeager said that regulators cannot just wait and see how consumers adjust, maintaining that such a strategy will keep key technologies at bay and prevent the United States from winning a competitive edge. Collaboration is instrumental, although Yeager warns that some interests can deflect progress because they are unable to set aside their agendas.
“We have to change policies to enable innovation,” he said. “Utilities will not do this by themselves. They will want more power sources and to make more money. They have no incentive to empower consumers. Until the incentives for utilities change, they will block the door and the public utility commissions will keep the status quo.” Yeager likened it to the days before telecommunications reform: Innovation will remain pent up in a regulatory model that has no motivation to change. And nothing will happen unless regulators force utilities to adopt those smart grid technologies. All utilities, though, are now forced to cut their emissions and to increase their efficiencies. As such, they are making investments in the smart grid. More needs to be done, but whether that comes as a result of consumer demand or a regulatory mandate is still up for discussion. Ken Silverstein is Editor-in-Chief of EnergyBiz Insider.
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Sharp Compliance strategies developed ++utilities are in good shape, industry experts say by Joe Kovacs We aLL face deadLines, and utiLities
faced a major one in June as they were required to achieve compliance with a range of cyber security standards passed down by the North American Electric Reliability Corporation (NERC) more than two years ago. The eight critical infrastructure protection (CIP) standards 002-009 are intended to ensure the protection and reliability of critical cyber assets within the bulk electricity system (BES) by calling for utilities to identify and document such assets and develop strategies to secure them from vulnerabilities to cyber warfare or else face fees to the tune of up to $1 million a day. Utilities have faced the prospect of security cyber asset compliance ever since a voluntary set of standards was first developed by NERC in 2003. The first set of mandatory standards was approved by the Federal Energy Regulatory Commission (FERC) in 2008.
cip limitations apparent But as the integration of utility operations with IP grows more complex, the limitations of the CIPs become apparent. CIP 002 now classifies specific facilities and assets deemed critical in the BES including substations, some generation resources, load-shedding systems and special protection schemes; their associated cyber security assets have been the targets of CIPs 003-009, which articulate the full breadth of processes and methodologies utilities must execute to ensure their reliability. “But CIP-002 does not provide enough specific guidance on how to classify all BES facilities or systems,” said Baker. The CIP language is not definitive enough about the types of assets to be secured. One industry blog suggests less than 5 percent of existing generation facilities are adequately classified. “More assets should be classified,” added Brattini. “From a risk-assessment perspective, many now unclassified assets could have a medium- or high-severity impact on the BES if they are compromised by cyber breaches.” A NERC standards drafting team has adopted proposals for two new cyber security standards (CIP 010 and 011),
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iLLustration by MeLissa dehner
experts comment With the June 30 deadline now behind us, Intelligent Utility spoke with two industry experts to determine how utilities have fared. Sam Brattini, executive consultant and director of compliance services at KEMA, says most are in good shape. “Even before FERC gave final approval, utilities were developing strategies to identify and document critical assets for which they were responsible,” he said. Utilities also identified and secured the physical and electronic perimeters within which critical cyber assets were located. The successful implementation of policies governing management
security and access controls, permissions granted industry vendors and other external stakeholders, and personnel training in new policies and processes means many will not face significant fees. David Baker, Director of Services at IOActive, agrees that many utilities have complied with the standards or have selfreported on existent shortcomings to demonstrate a good faith effort to acknowledge risks yet to be addressed. But he also believes the standards have been something of a ‘bitter pill’ to swallow due to a required investment of finances and time. “The people who manage the BES and who concentrate on reliability have benefited significantly from a greater awareness of corporate IT,” Baker said. Part of the growing vulnerability of utilities to cyber risk is their increasing reliance on IP networks and the Internet. Consequently, to comply with the CIP standards, utilities have had to develop IT expertise to understand the nature of risks to their cyber assets and adequately address them. “IT specialists understand firewalls, protocols, internet security standards and other strategies to ensure the integrity of assets and systems,” Baker said.
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Sharp Security
which are intended to replace the current ones. Like all standards, however, the language must be open to public comment, revisions considered by the drafting team and approval required from FERC. As a result, Baker said, the final shape of CIP 010 and 011 is as yet unknown. Final passage of the new CIPs may come sooner or later, depending on the nature of the comments and the length and extent of FERC’s approval process. An ongoing process “Utility compliance is an ongoing process more than a one-time success,” Brattini said. The scope of the new standards could be ambitious if the intent is to identify
Cyber security an unending challenge ++Sisyphus and his boulder had nothing on utilities By Kate Rowland
w ww.intelligentutilit y.com /// Septem ber/october 2010
A quiet but undeniable truth: electric
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utilities don’t like to discuss cyber security incidents. But with the emergence this summer of the Stuxnet SCADA worm, apparently spawned by USB sticks used as the attack vector to spread the malicious code targeting Siemens SCADA (supervisory control and data acquisition) management systems, it’s become even more imperative that some kind of discussion be had. Whether it be the federal government sharing with utilities, or utilities sharing with other utilities, it’s clear that cyber security is an ongoing issue that continues to require yet more discussion. Achieving the best balance Larry Castro, a 44-year National Security Agency veteran who is now managing director of the Chertoff Group, told an Energy Central webcast audience in August that the Stuxnet threat, a multi-step insertion of malicious code, “is a threat that is representative of what we can expect in the future.” Castro advised electric utilities seeking to protect their cyber assets that cyber security is “a matter of achieving the best balance between security features one would like
and create security processes for the large number of BES assets not classified by CIP 002. Many utilities now comply with CIPs 002-009 and have avoided hefty fees (many not in full compliance face less significant penalties). But with more stringent requirements on the horizon, the prospect of greater demands on utilities is real. It’s not simply the number of facilities that will need to be accounted for. Under CIPs 002-009, documenting compliance was sufficient. Under CIPs 010-011, a real-time demonstration of reliability may be part of the requirement. Utilities aren’t out of the woods yet. Joe Kovacs is a freelance writer based in Washington, D.C.
to invoke and the operational flexibility one would like to have.” It’s a matter of looking at it from a risk analysis point of view, he said. As well, he noted, “Security is something that has to be baked in from the outset. It’s very, very difficult to patch in security features after the fact.” Tyler Williams, president of Wurldtech Security Technologies, would agree. Often teaming up with Ward Pyles, a security analyst for Southern Company, he has travelled the country talking about the cyber security issues associated with smart grid implementation. One of the biggest issues, both Pyles and Williams have indicated, is the question of how utilities develop their own needs and still meet future standards. In the absence of standards, security as a business driver is key—it’s got to be embedded in the system, not layered on top. “There are tons of security requirements you’d love to have, but the key is to understand what the business needs,” Pyles stressed at a remote communications conference in San Antonio, Texas. Challenge worthy of Sisyphus Williams, a self-professed cyber security education advocate, calls industrial cyber security “a Sisyphean challenge,” likening the utilities’ task to the role of the Greek king punished by the gods for his trickery by being forced to roll a huge rock up a steep hill. Unfortunately, before he could reach the top of the hill, the rock would always roll back down, and he’d have to begin again. Garry Brown, chairman of the New York State Public Service Commission, described the task similarly. “The deeper you get into it, the more layers there are to it,” he said. Even the upcoming introduction of plug-in hybrid electric vehicles is going to provide a new security challenge, Brown noted. “This is a never-ending task. There isn’t going to be a set of standards we can come up with where we say, ‘OK, we’ve got it’ and people can go home and implement them,” he said.
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The changing face of the utility workforce ++a convergence of technology, communications, computing and energy systems amps up the game by Kate rowland the siMpLe days are Long gone.
The electric utility industry is in a period of dramatic transformation, and for its personnel, this means a thorny balance of more complex systems, an aging workforce and an aging infrastructure. The new knowledge, skills and abilities (KSAs) required are far different from those of even a decade ago.
More reliance on technology, as well as the convergence of communications, computing and energy systems, means a daunting new skills list is necessary for every utility’s workforce. Last year, the U.S. Power and Energy Engineering Workforce Collaborative of the IEEE Power and Engineering Society issued an action plan entitled “Preparing the U.S. Foundation for Future Electric Energy Systems: A Strong Power and Energy Workforce”. The plan noted that aging workforce trends are creating a shortage of experienced engineers in the field. “The departure of this engineering expertise is being met by hiring new engineers and by using supplementary methods, such as knowledge retention systems,” the report noted. “The future engineering workforce will supplement traditional power system knowledge with new skills, such as in communication and information technologies. Traditional and new skills will be necessary to successfully deploy advanced technologies while maintaining the aging infrastructure.” According to the collaborative, solving the aging and changing workforce issue begins in the schools. Its research indicates that approximately 45 percent of engineers in electric utilities will be eligible for retirement or could leave the industry for other reasons by 2014, while the need for new power engineers could grow two to three times in that same period in order to satisfy the needs of the entire economy.
iLLustration by darren Moore
w ww.intelligentutilit y.com /// Septem ber/october 2010
preparing personnel
At the same time, while enrollment by university students in power and energy engineering courses is increasing, the overall number of students interested in electrical engineering is declining. Add to that the statement made by the collaborative that “there are less than five very strong university power engineering programs in the U.S.,” and the conundrum facing utilities, even before new workforce hires walk in the door, becomes apparent.
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In-house apprenticeships For its part, the Toronto Hydro Electric System has taken the matter into its own hands, and launched its own in-house apprenticeship training proForty-five percent of gram. The magnitude of its workforce chalengineers in electric lenge was delineated clearly in the comutilities will be eligible pany’s 2009 corporate responsibility report. for retirement by 2014. It noted: “Despite the challenges of the global recession, with the approval of the Ontario Energy Board, Toronto Hydro continued to add to its workforce in order to deliver on its goal of modernizing the utility and also to replace ‘baby boom’ generation employees, 600 of
whom are expected to retire in the coming nine years. Over 40 percent of the potential retirements will occur in supervisory, engineering, skilled electrical trades and technical system planning positions. “To fill this gap, approximately 115 new hires were made in 2009, and approximately 100 more new employees are expected to be recruited in 2010. Since 2003, approximately 120 trades workers have been hired and are part of a four- to five-year apprenticeship training program.” Earlier this year, I spoke with Blair Peberdy, Toronto Hydro’s vice president of communications and public affairs, about the training program. “We have an interesting situation where we’re quadrupling the capital budget and the capital construction program, but we’ve got a workforce with an average age of close to 60 years old, and something close to 40 percent of the workforce will be retiring within the next six or seven years. So clearly, we have a workforce renewal issue,” he said. “So about three years ago we again went forward as part of a rate application to the regulators and said, ‘Look, we’re facing this problem.’ We argued for an increase in head count, which many utilities going before regulators are loathe to do. “But we said it’s critical for us to start to recruit younger employees specifically into the electrical trades, the skilled trades,” Peberdy said. “This is a four-and-a-half-
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Preparing Personnel
year apprenticeship. We’ve got to have these younger employees on the job while these older workers are still here so that we can have a knowledge transfer and a safe transition from an aging workforce to a younger one.” The Ontario Energy Board agreed with the utility’s approach, and Toronto Hydro set up its own trades training facility and gained certification as such from the Ontario government, likely the only utility in the province to have gained that certification, Peberdy noted. Recruitment is ongoing in many different areas of the utility.
Government support for retraining Duke Energy, too, has requested and received financial assistance in retooling its employees’ KSAs. In early April, it was awarded $3.5 million by the U.S. Department of Energy for workforce development and training. As a result, the utility is currently developing training plans and programs to equip both its existing and new employees to support its grid modernization plans.Other utilities awarded training grants included: ??
Florida Power & Light, which received $5 million to work with local academic institutions in retraining the utility’s workforce in smart grid deployment.
w ww.intelligentutilit y.com /// Septem ber/october 2010
??
30
Pepco Holdings, which received $4.4 million to train its workforce in smart grid equipment and to advise its customers about changes brought about by smart grid.
??
Mississippi Power Company, which received $2.6 million to train its workers in transmission line automation, substation management and new metering infrastructure.
As well, in late 2009, Duke Energy Carolinas announced plans for a corporate training and support center to be built near Kings Mountain, North Carolina. This generation support center, said Duke Energy Carolinas president Brett Carter at the time the announcement was made, “will be important as we continue preparing and training a skilled workforce to maintain system reliability.” Construction began this year on the complex. The training and support center occupies a 30-acre site
within the Cleveland County Business Park. When finished, it will be about 188,000 square feet in size, and will include training rooms, an auditorium and employee meeting rooms. It will serve as a multi-use support center for the company’s power plants in the Carolinas, and employees should start relocating to the facility in July of next year. Maintaining development despite downturn In its action plan, the Power and Energy Engineering Workforce Collaborative also offered other suggestions to utilities. First and foremost, it recommended maintaining development and hiring activities in spite of the economic downturn to avoid future power system reliability problems due to massive delayed retirements. While easier said than done, the Department of Energy’s recent grants, both to community colleges and universities, as well as to a handful of utilities, might make the job, for some, a little less difficult. As well, the collaborative also advised that utilities can provide research support to undergraduate and graduate students by offering data, allowing testing of innovative ideas, enabling access to company engineers for information and guidance, and providing financial sponsorship through fellowships and research project support. The collaborative also advised utilities to seek We’ve got to have beneficial opportunities through cooperation younger employees with universities. “Talk with faculty about workon the job while older force needs and major business and technical workers are still here challenges; listen to their so that we can have a education and research plans,” the plan noted. knowledge transfer. “Find ways to work together.” Across-the-board collaboration—among industry, government and educational institutions—is going to be essential, both in the short-term and in the long-term, to address workforce issues. “In assuring future prosperity, there is work to be done by industry, government and educational institutions,” the plan concluded. “To build from a position of strength, action is required now. The choice is ours to make; the future is ours to lose.”
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» IT + THE SMART GRID
ing more dependent on information technology to do almost everything. So operations has faced a dilemma. Either operations plunged into its own IT support role or worked with IT so we can support ongoing, incident-driven At SRP, operations retains control over IT support needs. That has meant an evolution By Phil Carson largely on the IT side.” One of the closest collaborations between IT and operations is in data At the Salt River Project, operations tends to keep storage and management. Operations information technology under close control. And that stance—whether representative of large numbers of utilities or specif- relies on corporate IT to identify and ic to SRP—appears to reflect an IT evolution yet to reach fruition and the rigorous purchase hardware such as servers that will support all utility functions. demands of the operational mandate for safety and reliability. “The model SRP has used for many years is one in which there’s a corporate Software for specific operations tends IT organization, and then there are IT subgroups of varying sizes in the genera- to be evaluated and implemented tion, transmission and distribution chain,” said Gary Harper, SRP’s manager of by the various operational IT subgroups, which also system operations. “Operational IT groups really are integral design specific apto all aspects of operations. They really do understand 24/7.” The operations plications, accordThat picture is evolving as corporate IT gradually steps into ing to Harper. real-time support for operations. Anecdotal evidence suggests side is becoming It’s not yet clear that some utilities have moved to a model in which a single whether pursuing IT organization serves both the business and operations—and more dependent a smarter grid will some suggest that a few of those utilities have reverted back to bring the two areas SRP’s model. But at SRP, corporate IT and operations IT work on information of corporate IT and in parallel but separate universes. operations closer technology to do together. Drawing a line “We embarked “A big part of how we demarcate between the different IT funcalmost everything. on a program with tions at SRP—in other words, the corporate IT function versus EPRI on a road map operational IT—is around the networks they both use,” said Joe Nowaczyk, SRP’s manager for electronic systems. “Historically, utilities have for what we call ‘smart grid,’ the definiinstalled a lot of communications networks to handle their operations. We’ve also tion of which evolves over time,” Harper leveraged that infrastructure for corporate purposes. We have a great fiber-optic said. “That program has a myriad of network and a microwave network used for operations. But the physical layer of higher technology applications. One is the meter on the residence, implethose networks is the responsibility of the operations side. “So we separate the networks,” Nowacyzk added. “Corporate functions belong mented by our customer service group, to corporate IT, while everything to do with operations runs on a separate net- which has its own small, operational IT organization. So that group is in the work. They ride together on the physical layer maintained by operations.” In-house IT support groups exist within the utility’s energy management system, lead on developing a data management its customer service group in charge of advanced metering infrastructure and for system to manage all that data.” Of course, “all that data” is of little outage management, among others. Meanwhile, the corporate IT side, run by Kevin Nielsen, manager of information technology services, is evolving at an accelerated use unless it can be analyzed and presented to decision-makers in a timely pace to meet demands driven by smart grid technology, particularly for security. manner. Turning data into actionable Traditional rivalries intelligence is “still one of the tricks in “In the past, the relationship between IT and operations was somewhat distant,” the business,” according to Harper. “Most of our IT analysts [in operaNielsen said. “IT wanted to be a five-day-per-week, eight-hour-per-day organization and, obviously, electricity doesn’t take a break. So IT has had to learn that it’s tions] are interacting with someone at an operating desk or someone in a 24/7 business. IT learned it had to be responsive. “That disconnect between operations and IT had long caused contention,” charge of maintenance or someone in Nielsen continued. “That’s starting to be resolved. The operations side is becom- a control room at a power plant to
The IT vs. OT debate ++
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enable the latter to make timely decisions,” Harper said.
Phil Carson is editor-in-chief of Intelligent Utility Daily.
A seamless blending ++Power, communications and IT on the smart grid By Dick DeBlasio The smart grid promises varied and unprecedented
benefits, ranging from consumer choice and utility efficiency to electricity reliability and environmental impact. All of them are predicated on the coming together of power, communications and information technologies. Moving from today’s fragmented electrical delivery system to the next-generation smart grid is not, however, simply a story of integrating innovative technologies. The challenge of overcoming the culture clashes among the industries involved is considerable. Power engineers normally haven’t had much reason to interact with their communications and IT colleagues, but the smart grid demands seamless collaboration across disciplines. How will power, communications and IT come together on the smart grid to drive advancements, and how are engineers from each collaborating to make it happen? Missing links Most power, communications and IT systems that will enable the smart grid are available today. Linking them seamlessly within and among utilities and users is the great frontier of development. Interoperability, standards and cross-jurisdictional regulations are largely new territory for the power industry around the world. In the United States,
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Security a common issue Security needs are driving both sides to collaborate more, but security demands limit resources and options in some cases, Nielsen said. “There’s a balancing act,” he said. “The security requirement is causing more rigidity in the IT world. That, in turn, limits flexibility. Some of the neat things we see on the horizon that might be possible could be inhibited because of security concerns—that’s the tough thing.” “The more money and time we spend on security, the less we spend on new functionality,” Nielsen concluded. “From my perspective, corporate IT and operational IT are integrating more and more on a day-to-day basis,” Harper added. “We’re all grappling with security. We do a very good job of using firewalls to isolate the operational network from the corporate IT network. But over time, economies of scale and the value of bringing those two sets of data together—common uses—is making it harder and harder to keep the two isolated. I don’t know where that’s going in the future.” Still, there are aspects of operating a high-voltage generation-transmissiondistribution system that may place limits on the IT-operations collaboration, Harper said. “I’m real comfortable with a corporate IT person working on my desktop applications,” he said. “I’m not as comfortable sending that person into a high-voltage environment with which they’re not familiar.” “Ten years ago, we didn’t talk about these issues,” Harper concluded. “Today, Kevin and I discuss this all the time because of where the technology is going. How do we leverage all the technical skill and experience at our disposal?”
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» IT + THE SMART GRID
proprietary distribution systems operated by about 3,000 separate utilities have historically comprised the electric delivery infrastructure, and regulation of electricity distribution and retail is fragmented across independent public utility commissions of separate states or regions. This is why interconnection and intra-facing frameworks and strategies with design definitions have been key areas of focus for the IEEE’s P2030 Working Group. Formed in March 2009, the working group is creating a knowledge base addressing terminology, characteristics, functional performance and evaluation criteria, and the application of engineering principles for smart grid interoperability of the electric power system with end-use applications and loads. The guide is intended to inform the creation and/or enhancement of interconnection standards. Already, the group has identified more than 70 standard interfaces that engineers will need to properly link smart grid components. There are key questions that will have to be addressed in standards activities for the smart grid to achieve its potential, including:
Each of the separate task forces—Power Engineering Technology, Information Technology and Communications Technology—has dovetailed its efforts with the rest. In broad strokes, the job of deciding what information will be traded among which devices has fallen to power engineers. Communications and IT engineers then build on that work to consider the techniques and ramifications of data exchange. The task forces are striving to establish common criteria across their disciplines. Along the way, they have identified many instances in which the different communities of engineers have not shared the same language. The words “reliability” and “network,” for example, mean different things in power engineering than they do in communications and IT. Behavioral differences exist, too. ?? What are the data-exchange requirements (in terms of billing, reportStandards development, for example, ing and boundary crossing, for example) created by migration to has been a shorter-duration, more freelectric-vehicle infrastructure? quently revisited activity that involves ?? more hands in communications and IT What is necessary for data and physical security, than in power. given that a breach could compromise human Smart grid demands Resolving safety and/or national security? these cultural ?? How can the smart grid connect utilities at seamless collaboration d i s c re p a n c i e s different degrees of modernization, and how will is a key step toit support today’s consumer appliances, meters across disciplines. ward bringing and other systems as they are rendered “legacy” together power, by eventual innovations? communica?? tions and information technologies on What is entailed by support for utility service restoration, software the smart grid—and eventually realizupdates and troubleshooting services? ing the full sweep of its benefits. ?? As power generation becomes widely distributed across a utility’s The smart grid is bringing together customers, what will be required from manufacturers of generation power, communications and IT. To technologies in terms of common interfaces? ensure the varied technologies inter?? link seamlessly and successfully over Where are the best opportunities for “load shifting” by business and the long term, the smart grid today consumer users of power, and what will such a scenario mean in demands a meeting of diverse engiterms of time-of-day pricing, application of credits, remote billing, etc.? neering minds.
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Meeting of the minds One reason that the smart grid is regarded as such a revolutionary and exciting engineering challenge is because of the uncommon diversity of engineers involved. Within the working group, however, engineers from each of the industries primarily impacted have worked in concert from the outset of smart grid planning.
Dick DeBlasio is chair of the IEEE P2030 Working Group, and chief engineer and principal laboratory program manager for electricity programs within the National Renewable Energy Laboratory.
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Grid(un)lock
Age adds robustness ++AEC continues to integrate SCADA after 30 years w ww.intelligentutilit y.com /// Septem ber/october 2010
By John R. Johnson
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There aren’t many technologies that stick around
long enough to improve with age. In today’s fast-paced digital world, technologies change rapidly and often become obsolete in months. Just witness the electronics market, where cell phone upgrades occur on what seems like a 24-7 basis. But like a fine wine, SCADA—which stands for supervisory control and data acquisition—seems to get more robust with age. SCADA technology has been the backbone of many utility information systems for years and is still going strong. Many liken the technology to barcodes, a decades-old technology that has persevered despite the rising popularity of RFID technology, which has far greater capabilities than barcodes. So while advanced metering infrastructure (AMI) technology and other high-tech solutions quickly transform the utility sector, SCADA has held its own as a crucial part of the utility IT infrastructure. Make no mistake, SCADA has changed over the years and will continue to evolve as AMI takes hold. But the technology shows no signs of fading into the sunset.
Holding its own “We may not be the most advanced utility in terms of technology, but our SCADA system is pushing 30 years and is still an instrumental tool,” said Greg Williams, vice president of engineering and operations at Appalachian Electric Cooperative (AEC). “SCADA is an instrumental tool. It’s integrated into what we do every day and we would be blind without it. I don’t think SCADA will go away by any means.” AEC is a nonprofit coop serving 45,000 members in East Tennessee. The Tennessee Valley Authority furnishes electric energy to the coop at wholesale rates. Despite AEC’s relative smallness, the coop prides itself on exploring and utilizing cutting-edge technology, and has a well-thoughtout wish list for how AMI technology can tie in with SCADA in the future. By its very nature, SCADA requires rapid response times. The technology usually operates as a real-time communications system. When a command is issued to open a breaker in a substation, for example, the order needs to be carried out immediately. “I need a response back that the breaker did open, and I’ve got to know that very quickly,” Williams said. “I’m looking at voltage readings, amp readings on feeders, and other status information on substation equipment, so any kind of delay built into it would actually degrade the system.” Reaching farther With that in mind, AEC has actually physically extended its SCADA system outside the fence of the substation by connecting substation breakers and transformers, and, in some cases, relay systems and by creating a local area network. Beyond the substation fence, AEC started to connect down-line three-phase reclosures and down-line single-phase regulators. “We would like to communicate to capacitor stations and things of that nature, which may or may not require
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griD(un)lock
w ww.intelligentutilit y.com /// Septem ber/october 2010
the speed of communications like a substation would,” Williams said. “For instance, I just need to monitor a capacitor station. In my opinion, that’s one place where AMI possibly could cross over into more of a SCADA or distributed automation type of function. But where speed of response is needed, I don’t envision the AMI system being able to produce that kind of speed just because of the nature of its communication structure.” Williams notes that utilities that are installing fiber networks to the home will likely have the required speed and response time for that type of automation. However, if a power line carrier or an RF solution is utilized, the speed and throughput will be too slow. “I think that in the future, AMI can still provide some kind of enhancement of SCADA, where you reach beyond the fence, so to speak, of SCADA opportunities,” Williams said. For example, he envisions an AMI vendor developing a “black box” that can be hung on a pole out in the field and used perhaps to communicate to a smart switch like a Goab or a motoroperated disconnect. “Rather than putting in a remote terminal unit (RTU) that is connected directly to my SCADA, which is a very expensive alternative, maybe I can use my AMI system to communicate to it. But obviously there needs to be an interface,” he said. “This is the type of thing I see happening in the future. It’s not there yet, or at least I haven’t seen it yet. But I see some of those very low-level functions where there is not a lot of control or data being transported that could be done by using AMI.”
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speed not critical In a substation environment, AEC and other utilities bring back hundreds of data points to its main system—everything from amps and volts to varied control information. The bulk of that information needs to be timely, essentially delivered in real time, whereas applications originating in the field may transport minimal data, such as one or two voltage levels, a single amp reading or control point. “The amount of information is dramatically decreased so the speed by which that has to be responded to is not as critical by virtue of the fact that there are not as many bits of information,” Williams said. “That’s where I see AMI crossing over into the SCADA world. AMI will never replace it, but I feel that it can enhance it or broaden it. “SCADA is changing. Early on, you used to hardwire contacts for status and hardwire into transducers to get analog values. All that has changed and it’s now all digital information coming out of a smart relay.” Williams said that SCADA’s future will also be impacted by how AMI relates to distributed automation. “When I want to truly automate my distribution system and I’ve got multiple motor-operated disconnects and devices out there for automatic sectionalizing and fault isolation, how will I communicate that back to my headquarters? Well, I can use my SCADA system, which means I’ve got to
use RTUs and radios, or can I do it using my AMI system, which is actually another communications system? I’m sure there are utilities out there dealing with this, and it’s something we’ll be looking into in the future,” he said. key in integrating renewables Williams also sees SCADA technology playing a key role when it comes to integrating renewables into the grid as alternative energy from wind, solar and other sources continues to grow.
“scaDa technology has been the backbone of many utility information systems for years and
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is still going strong.
“This will be another opportunity to use SCADA for monitoring those types of installations,” he said, noting that a 2-megawatt methane gas landfill generation project is in the works in Tennessee. “If it happens, we’ll want to connect its ‘brain’ to our SCADA system because I want to know how much energy it is generating and what it is pushing back into my distribution system. That needs to be real-time data. I could not depend on my AMI to give me real-time information because it’s just not designed for that. We pull our AMI meters once an hour and our SCADA system is updated about every 10 seconds. Those amp readings are changing instantaneously.” So too, it seems, are the use cases for SCADA. John R. Johnson is a Boston-based freelance writer specializing in alternative energy and technology topics.
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End of the line
Distributed resource planning ++DTE + SCE turn to solar opportunities By John R. Johnson Utilities continue to find innovative ways to avoid
w ww.intelligentutilit y.com /// Septem ber/october 2010
building out new infrastructure—or at least to delay the cost of doing so. More often than not, those strategies involve turning to renewable energy sources such as solar, wind, fuel cells and advanced energy storage. Utilities are discovering that it pays handsome dividends to delay or outright eliminate capital expenditures for things like transmission lines and substations and even new power plants that might be necessary if not for aggressive distributed energy and distributed generation programs. Some, like Detroit Edison (DTE Energy) not only have solar generation plans in place, but also rely on innovative programs such as diesel and natural gaspowered mobile trailer-mounted generators that act as microgrids and can be moved to remote areas to keep the lights on for customers while they conduct maintenance and repairs on substations. In some cases, the 1- and 2-megawatt units are being permanently mounted on a partition in rural areas, a lower-cost option than rebuilding a new substation.
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Opportunities in the sky But the sky is where the real opportunity lies. DTE’s SolarCurrents program calls for photovoltaic systems to be installed on customer properties or rooftops over the next five years. The program hopes to generate 15 megawatts (MW) of electricity throughout southeast Michigan. The ultimate goal of the SolarCurrents program, which saves some residents more than half the cost of installing solar, is to determine the feasibility of using renewable energy as part of Detroit Edison’s generation portfolio. Currently, DTE officials say it’s hard to determine whether renewables will be a cost-effective way to defer distribution infrastructure. Short-term, it will help Detroit Edison meet the state’s renewable portfolio standard of 10 percent by 2015. In addition to solar, DTE is looking to other resources to meet the 2015 mandate, which will require adding about 1,200 megawatts of renewable power. In August, the utility signed a pair of contracts totaling 20 megawatts of renewable energy capacity—or enough to power nearly 14,000 homes. The deals will add to DTE’s renewable energy portfolio by tapping energy to be generated from landfill gas and wood waste biomass. However, DTE expects the majority of its renewable energy to come from wind resources, and has acquired easements on more than 75,000 acres of land in Huron County in Michigan’s Thumb region for development of large-scale wind farms. Harvesting California sunshine In California, where the movement to harvest energy from the sun is the greatest, the three investor-owned utilities in the state have a goal of 3,000 megawatts of solar-produced reconnected electricity by the end of 2016. The primary driver
is the California Solar Initiative (CSI), a three-year-old program designed to spur interest in solar energy. In addition, the California Public Utilities Commission’s SelfGeneration Incentive Program (SGIP) provides incentives through California utilities to support existing, new and emerging distributed energy resources, providing rebates for qualifying distributed energy systems installed on the customer’s side of the utility meter. Qualifying technologies include wind turbines, fuel cells and corresponding energy storage systems. Solar was covered in the initiative until the CSI initiative passed the California Senate, therefore eliminating the need for solar to be in both plans. To date, California’s three publicly owned utilities have received more than 45,000 CSI applications for a total of 801 megawatts, which equates to about $1.4 billion in incentives. “That 801 megawatts will go very far toward reaching our 3,000 megawatt goal statewide,” said Jeff Lidskin, a project manager in the California Solar Initiative program at Southern
California Edison. “These programs promote energy resource diversification, and reduce the need to build power plants because solar electricity is usually produced when electricity demand is at its highest.” Aggressive commercial development The California Solar Initiative isn’t the only way that utilities plan to meet the 3,000-megawatt statewide goal. Southern California Edison (SCE) has its own aggressive plan to harvest another 500 MW of solar power from rooftops of commercial buildings through what is being called the nation’s largest solar power project. SCE will own and operate 250 MW of the solar array, while independent solar project developers will operate the rest. SCE’s first two solar installations already generate enough power for homes and businesses in Fontana and Chino, Calif.
The race to install solar as a way to reduce U.S. dependence on foreign oil will rely greatly on lower costs, government incentives and consumers’ desire to reduce utility bills and help the environment. Of course, the end result is less infrastructure costs for utilities, as well. One of the hurdles in developing more renewables is transmission, but these projects usually don’t require new transmission lines because they feed directly into the distribution circuit. That’s a major benefit for utilities, since nobody wants transmission lines in their own back yard, and since it can take 10 years to permit, plan and construct a transmission line. Lidskin stresses that recent advancements in solar technology, coupled with the unprecedented size of SCE’s project, should result in a cost per unit roughly half that of common photovoltaic installations in California. SCE believes the project could help drive down installation costs for solar generation everywhere. In fact, between the CSI rebate and the federal tax credit, the average homeowner can save as much as 45 percent off the average cost of an installed solar system. Of course, energy conservation is the best practice. SCE and other utilities urge consumers to perform an energy audit of their homes before installing solar. Switching to energy-efficient appliances, for example, and limiting the use of incandescent lightbulbs can result in dramatic energy savings. Then, the cost to install solar drops because less energy generation is required for the home. “We’re busy making sure that customers are aware that the cheapest megawatt is the one that you don’t have to produce,” said Lidskin. John R. Johnson is a Boston-based freelance writer specializing in alternative energy and technology topics.
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4d
If a tree falls in the forest… ++Progress Energy implements automated vegetation management system By Mike Breslin
w ww.intelligentutilit y.com /// Septem ber/october 2010
If a tree falls in a forest and no one hears it, does it
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make a sound? That riddle was posed by the 19th century philosopher George Berkeley to explore questions about observation and the knowledge of reality—two subjects close to the heart of vegetation managers. If a tree falls on a transmission line, the utility operator will immediately experience the reality of complaints. Not just from industry partners through cascading events and angry customers, but possibly from the North American Electric Reliability Corporation (NERC). Those not complying with NERC right of way (ROW) vegetation standards can suffer the painful reality of fines up to $1 million per day, per violation. NERC FAC-0031 regulations were an outgrowth of one of the main causes of the 2003 Northeastern blackout, which affected 45 million people in the U.S. and Canada—overgrown trees. Automation and human observation These are a few of the reasons Progress Energy was among the first large investor-owned utilities to implement a full-scale, automated vegetation management system to protect its transmission infrastructure. Progress operates two major electric utilities in Florida and the Carolinas serving more than 3 million customers with a generation capacity of more than 22,000 megawatts. In vegetation management, professional human observation is critical. But the reality is that observation is useless unless accurately documented with maps and data, readily available to right of way crews tasked with preventing tree-related disasters, doing maintenance or making emergency repairs. Located in the deep Southeast, Progress faces severe environmental conditions—dense, fast-growth vegetation in a 10-month growing season and killer winds from tropical storms and hurricanes that knock down trees. “In Florida
we have such a sandy soil base and a very high water table, so we are limited to what herbicides we can use on our right of way floors,” said Paul Hurysz, Progress’ utility transmission forester. In early 2007, Progress’ IT and vegetation departments began investigating technology to replace its paper-based system. By year’s end, the utility chose its software partner. In December 2008, its new integrated vegetation management platform went live. Data utilization increases Progress can now combine vegetation history with data acquired from ground patrols, helicopter flyovers and call-ins—all aimed at improving transmission reliablity, ensuring NERC compliance and optimizing resources. “We are fully implemented with the program, but as we use it in the field, we develop and discern different ways of wanting to collect and reproduce the information we are gathering. We are probably up to 80 percent in utilization and 20 percent in the development mode to make the program better,” Hurysz estimated. Prior to automation, Progress conducted helicopter patrols of its transmission ROWs three times a year using a paper-based system. With automation, it’s doing two aerial inspections, one in the spring before the storm season and one in the fall after the storms. In between, the utility added an annual ground inspection of NERC lines.
“Ground patrols are three to four times more accurate than aerial. In the air we are moving at 50 to 60 mph. On the ground, you have the opportunity to document everything as you move along. It’s much slower but a lot more accurate,” Hurysz said. Progress is experimenting with voice recognition in helicopters. While there are ambient noise issues to be resolved, Hurysz is optimistic: “It’s a real benefit because when we take our eyes off the right of way we may miss potential vegetation issues. Voice is input to the tablet computer. From there we can take observations and download them directly into our system, sort the data and get it out to the contractors in a much more efficient and effective manner.”
hp-ad-1.qxd
More boots on the ground Getting down to the weed level with electronically supported 10/5/04 8:01 PM Page 1inspections has many advantages over aerial
besides accuracy. With the paper-based system, information was often lost or shuffled around. Hurysz explained: “One challenge we have as a large company is you have folks transitioning in and out of business units, so many times you lose local knowledge. If a line goes down at night, having a database that tells a If a line goes down at lineman or arborist exactly how to access a structure saves a tremendous amount night, having a database of time to evaluate a situation or make repairs. One of our goals is documenting that tells a lineman or and capturing access points to improve safety, the reliability of our operations arborist exactly how and restoration time.” Another benefit of more boots on the to access a structure ground is better customer relations. With information at the arborists’ fingertips, saves a tremendous they can run reports on private property access, encroachments, or when a cusamount of time ... tomer asks to be contacted about a tree trimming or animal-related issues. “We are more effective. We have not had any outages since we installed the system, so it’s had to measure exactly how much savings the system is generating, but it’s helping us maintain compliance, which is the total objective of the program,” Hurysz said.
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Mike Breslin is a freelance writer and novelist based in New Jersey.
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Connections
Smart meters and the coming data deluge ++Managing the information is key to realizing full smart grid benefits By Christopher Perdue Christopher Perdue joined the Intelligent Utility team in July, and has been adding to the smart grid discourse online in Intelligent Utility Insights on Mondays in his role as vice president of Sierra Energy Group, a division of Energy Central. Here, he shares his thoughts on dealing with metering data.
The move to the smart grid results in a paradigm
shift regarding metering data. Currently, most utilities create monthly files of meter reads (using manual collection) and submit them to the billing system. With the smart grid, utilities are transformed from distributors of power to brokers of information that handle millions of data transactions every day. For a utility this means that the simple transactions involved in the meter-to-cash function are completely altered. When the numerous other functions are considered, such as outage management and demand response events, the impending scale of the challenge becomes apparent. To illustrate, for every million meters that a smart meter operations team serves, the team can expect to support: ??
More than 2,000 meter exchanges per day during deployment
??
More than 1,000 customer moves per day (assumes 25 percent
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yearly turnover)
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??
10,000 missing reads per day (assumes 99 percent daily read success)
??
20 meter failures per day (assumes a 0.5 percent annual failure rate)
??
10,000 data changes per day
??
More than 97,000,000 meter reads per day (assumes 15-minute data intervals)
Utilities will be inundated with data not only coming from smart meters, but also intelligent assets on the grid, weather systems, energy traders, customer patterns, social medias, participants throughout the energy community and other sources. Clearer view of typical behavior The amount and frequency of this new data will provide utilities with a much clearer view into how the end-customer utilizes their service by revealing their typical behavior and usage patterns. The next evolution in the smart grid is to utilize this influx of data and associate it with key action items that can be applied and communicated to customers to help modify their behaviors. To minimize costs and maximize benefits, utilities need a long-term, structured plan that provides a clear and coordinated map of where data originates, where it goes, what processing takes place along the way and how every department that touches it extracts its full value.
To do this, utilities need to determine their data strategy. This will require a substantial amount of education, research and knowledge development. Having a clear line of sight on what the end purpose for the data is, and what intelligence the utility, the regulator and the customer needs to create real, tangible value, is critical for such a strategy. By having a structured plan, utilities will make the management and storage of data much more focused. Faced with the prospect of dealing with enormous amounts of data, such a step will ensure that the volume of data and associated costs will be effectively managed. Serious thinking about CIS enhancements Massive amounts of data to manage requires serious thinking about how to architect, secure, segment and deploy the data centers that accommodate it. That may also require looking at other, peripheral systems to determine what other enhancements may be needed to accommodate smart grid technology, such as changes that may be needed in the customer information system (CIS). With new advanced tariffs and communications requirements, many legacy CIS systems will not cope with the increased demand. Utilities will need to consider how “ready� their CIS solution is. Utilities will also need to consider items such as customer Web portals to analyze the metered data to support demand response programs as well as other value-added services. The existing systems and prospective systems will also need to provide adequate security measures. Readings will need to be checked for validity when compared with reading estimates. Where reading data is rejected, or gaps exist within the reading data provided, this data would be repopulated by estimation
and substitution algorithms. Utilities need to ensure their readings management system is scalable and supports multiple units of measure. Seeking best solutions Utilities will also need to ensure that they are working with information technology vendors that both deliver on their value proposition and, perhaps more importantly, integrate seamlessly. With proper planning, utilities can define a set of vendors that provide the best solutions for their specific needs, ensuring that the vendors work together to provide an integrated solution that fits their needs. As utilities go through this process, they will also need to consider the customer demands and regulatory requirements that will need to be met in the future. Managing that information is the key to realizing the full benefit of
their smart grid investments. If a utility can successfully manage and exploit the data, it can improve customer service, decrease costs and reduce the risk associated with infrequent, outdated and inaccurate data. Christopher Perdue is the vice president of Sierra Energy Group, a division of Energy Central.
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out the Door Texas is willing to share a ROW with another company.”
Sharing right of ways ++an attractive two-way street for utilities by mike breslin as cities and toWns across the united states struggLe
w ww.intelligentutilit y.com /// Septem ber/october 2010
with budgetary problems, the concept of shared services is proving to be a useful tool. Crossing jurisdictional lines is often difficult for political reasons, but when intelligently managed, sharing can result in dramatic savings without denigrating services, and can even improve them. Municipalities that have pooled into a county purchasing department, for instance, have been able to save substantially on overhead costs while increasing purchasing power. What is the potential for sharing transmission right of ways (ROWs) among electric, gas and telecommunications companies? There are hosts of technical, regulatory and safety issues to be overcome, but the cost savings and potential new revenue streams are intriguing.
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Maximizing resources benefits all Everyone in the utility industry is painfully aware of the hurdles that must be overcome to site a new transmission line. It’s a Catch 22 of the 21st century— electric consumers insist on a reliable and an ever-growing supply of electricity (preferably from renewable sources), yet many vehemently oppose building the new transmission corridors needed to deliver it, and go to extraordinary lengths to delay or stop construction. Other issues such as viewsheds; rights over federal, state and municipal lands; paths through dense residential areas; heritage zones and conservation easements compound the problem. That is why maximizing resources of existing ROWs could benefit everyone. “In the future I definitely see more shared access of ROWs. That philosophy comes and goes and depends on pressure from the public,” said John Chan, program manager of transmission for the Electric Power Research Institute (EPRI). “It looks like the pressure is high in recent years as building has picked up. The normal time from inception to build a 230-kV line is probably about 10 years (and) 765 kV could be even longer, 15 to 20 years. It depends if you are going through residential or senstive areas where there is a lot of opposition that holds up the process.” Yet, in Texas new transmisson lines are being built in Competitive Renewable Energy Zones (CREZ) at breakneck speed compared with other parts of the country. Bradford W. Bayliff, a partner in the Austin law firm of Casey, Gentz & Magness, represents landowners in easement cases. “On one case that I was dealing with yesterday, the application was filed on July 28th. The commission will issue a final order on or before January 24 … 180 days! And they expect to build it by the summer of 2013.” Under CREZ, approximately $5 billion worth of transmission has been or will be filed this year that will be approved and built by the end of 2013. “I like the idea of shared access to transmission corridors. It requires less ROWs from landowners, allows them not to have their property affected by utilities, and it doesn’t require clear cutting of wide swaths of land,” Bayliff said. “In practice, when a utility owns and has access to an existing ROW, it’s rare that an electric utility in
sharing access sometimes difficult We asked John Maserjian, spokesman for Central Hudson Gas & Electric, about sharing. Central Hudson is a transmission and distribution utility serving approximately 300,000 electric customers and 74,000 natural gas customers in New York State’s Mid-Hudson River Valley. “There are instances where facilities owned by us and another utility share a portion of a transmission corridor as a convenience, either crossing or running parallel for some distance, but
“ municipalities that have pooled into a county purchasing department, for instance, have been able to save substantially on overhead costs while increasing purchasing power.
”
these were built many years ago,” he said. “In looking at our future projects, I can envision using existing corridors for new facilities developed jointly by two or more companies. However, not all corridors are owned in fee by utilities, meaning the title to the land is owned by the utility. Sections may include landowner easements, and these must typically be renegotiated to include the new facilities.” Whether for power interference or safety reasons, electric utilities are generally reluctant to share access with other power or gas companies, but
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sharing is on the rise with telecommunications providers. Installing a cellular antenna on a transmission tower is often not the first choice of a wireless carrier. But when zoning restrictions make it difficult to obtain an approval for a freestanding tower, or when the permitting process is too slow for a carrier to provide service, approaching a utility is becoming more and more common because of increasing resistance by local jurisdictions to approve new cellular towers. Some utilities have set up separate business units as profit centers to handle antenna leases, expedite application-to-install times and solicit business from carriers. Other utilities have not recognized it as a business and have no dedicated staff for cellular, so approvals are slower. “It’s difficult to get carriers to express what they pay, but it’s typically $1,000 to $2,000 a month for antenna space,” said Don Bishop, editor of Above Ground Level, a magazine for owners and managers of antenna sites, wireless services and networks.
Most utilities require that their employees or subcontractors perform antenna installations and maintenance, particularly if the antenna is mounted above the high-voltage wires. In areas where elevations are high enough, antennas can be mounted below the power lines, and in some cases, cellular technicians do the work. For most installs, antennas are bolted directly to the tower, but where higher elevation is necessary a supplementary monopole can be added to raise the antenna above the tower structure. Co-location another option Another way the utilities are sharing with the wireless industry is by co-locating freestanding cell towers on substation property. Zoning authorities are often receptive to these applications because a gray steel tower, while high, does not look much different than other gray steel equipment already on site. Running fiber-optic cable for telecommunications over transmission corridors is another sharing opportunity. “In the past, it was more of a problem because the communications cables were mostly metallic, but today they are fiber optic, and interference is almost zero,” said EPRI’s Chan. There is also potential for installing wind and solar generation on ROWs having compatible characteristics. Land use issues are red hot topics at public hearings. Finding ways to share resources can ease the way for new transmission corridors and better justify ones already in service. It will require some out-of-the box thinking by utility executives and regulators, but the rewards could be enormous, not only conserving land but also increasing efficiency on hard-won infrastructure. Mike Breslin is a freelance writer and novelist based in New Jersey.
w ww.intelligentutilit y.com /// Septem ber/october 2010
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