VOL 4, ISSUE 5 » SEPTEMBER/OCTOBER 2012
Where smart grid meets business—and reality.
V2G: ARE WE READY? News from the front lines
UTILITY SECURITY
BACKHAUL FROM THE BACK 40 Rural co-ops play outside the box
WIFI/BROADBAND/ PUBLIC/PRIVATE No one size fits all here
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CONTENTS S PECIAL REPORT UTILITY SECURITY
28 Information sharing around cybersecurity practices Group grows organically
DEPARTMENTS
4 5
12
This issue, we’re discussing operations topics, with a
16
special focus on communications networks, and the way in which utilities are “connecting the dots.” With that in mind, our IT Insights and Customer Focus also cast a view into other issues of import to the industry.
FEATURES // SEPTEMBER/OCTOBER 2012
V2G: Are we ready?
12 The business of V2G
W WW.INTELLIGENTUTILIT Y.COM /// SEPTEM BER/OCTOBER 2012
Technology and business case go hand in hand
2
Backhaul from the Back 40
16 Connecting all the dots, wirelessly
South Central Indiana REMC chooses scalable solution for future
18 Leveraging communications technology Illinois Rural Electric Cooperative rolls out Internet options
WiFi/Broadband/Public/Private
24 The debate continues No one size fits all here
18 36 38 47 AN E N E RGY C E NTR AL PU B LIC ATION
Drawing the line Transmissions 5
Letters from readers
8 Around the globe 10 Top 12
10 Utility champions in the small electric co-op utilities of the U.S.
36 IT insights
36 The changing face of utility IT
Dan Hill discusses IT’s evolving role
38 Using analytics with demand response
Oncor’s data analytics initiatives offer wide- scope view
39 Operational perspectives
39 Aggregating tiny loads
NY customers control window ACs by smartphone
41 The value proposition for energy storage
SCE & Duke Energy discuss what they’re learning
44 Customer focus
44 Data analysis, social media & the modern customer
Christopher Perdue discusses the changing face of utility customer service
46 Dynamic pricing set to expand in Illinois
Scaling up real-time pricing approved by regulators
47 Out the door
47 Utility analytics best practices
Yes, these words do belong together
Vol. 4, No. 5, 2012 by Energy Central. All rights reserved. Permission to reprint or quote excerpts granted by written request only. Intelligent Utility® is published bimonthly by Energy Central, 2821 S. Parker Road, Suite 1105, Aurora, CO 80014. Subscriptions are available by request. POSTMASTER: Send address changes to Intelligent Utility, 2821 S. Parker Road, Suite 1105, Aurora, CO 80014. Customer service: 303.782.5510. For change of address include old address as well as new address with both ZIP codes. Allow four to six weeks for change of address to become effective. Please include current mailing label when writing about your subscription.
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Communicating, everywhere
W WW.INTELLIGENTUTILIT Y.COM /// SEPTEM BER/OCTOBER 2012
IN EARLY AUGUST, I STOOD UNDER A BIG ALBERTA SKY AT THE EDMONTON FOLK
4
Music Festival, listening to the music from the main stage floating back at me from the hill, catching up with old friends and making new ones. What were we talking about at that particular moment? Mary Chapin Carpenter’s exquisite concert? David Lindley’s guitar wizardry? How big the festival has grown over the years? No, we were talking about power transformer repair services, and how the electric utility industry is growing and changing. That’s right, transformers. Specifically, the purchase by ABB of Edmonton-based PowerTran Company in 2007, and how electric utility industry technology and service companies have continued to grow in the years since then. For the purposes of full disclosure, we were a mixed group of friends and acquaintances: folk festival organizers, musicians, audiovisual guys (one of whom had a friend who owned PowerTran was before it was sold), and me. I’d hazard an educated guess that I was the youngest person in the group, but these aren’t old coots. They’re socially and politically active, environmentally conscious, well educated, and have taken to the Internet and social media sites like ducks to water. The discussion soon morphed into questions and opinions about smart meters and electric vehicles and, more generally, a discussion of communications networks—the theme of this issue of the magazine. It was the last place I expected such a discussion to occur, but it is one of the very places it needs to begin happening for the general electricity consumer to start to understand how the electric grid is changing, how we are using technology for better reliability and ultimately, cost savings, and that all of this is not going to harm their health or invade their privacy. In this issue, we take my Alberta discussion further. Phil Carson talked to Willett Kempton, the “father of V2G,” and two electric utilities about vehicle-to-grid technologies and possibilities. Is it possible? Are we ready? John R. Johnson sat down with two rural co-ops, South Central Indiana Rural Electric Membership Cooperative and Illinois Rural Electric Cooperative, to discuss what they’re doing to backhaul AMI, SCADA and other business-critical data from their substations, and discovered some unique outside-the-box thinking. Unsurprisingly, the debate continues between WiFi and broadband, public and private networks. The easy answer? There is no one-size-fits-all solution. And finally, with Intelligent Utility’s Knowledge Executive Summit quickly approaching, we reached out to two of our Knowledge committee chairs, Dan Hill, retired CIO of Exelon, and Christopher sue? Then Enjoy the is for free at Perdue, director of smart energy at J.D. Power and Associates, for their respective takes on the subscribe .com/ igentutility issues facing utility executives in the next few years. Their answers might surprise you. www.intell subscribe Kate Rowland Editor-in-Chief, Intelligent Utility magazine krowland@energycentral.com
TRANSMISSIONS
Letters from readers www.intelligentutility.com EDITOR-IN-CHIEF Kate Rowland
krowland@energycentral.com 250.227.8938 SENIOR CONTRIBUTORS
Phil Carson Editor-in-chief, Intelligent Utility Daily pcarson@energycentral.com 303.228.4757 FEATURE WRITERS
John Johnson, Laurel Lundstrom COPY EDITORS: Martha Collins, J. Ian Tennant ACCOUNT EXECUTIVES
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Cindy Witwer, 800.459.2233 ENERGY CENTRAL
“choice” and “control” for customers. In this current climate, giving customers more choice and control seems an open invitation to politically attractive rate reform — starting with CPP makes sense to me.
Dynamic pricing Intelligent Utility Daily, August 5/6
On the one hand, we have the traditional approach to utility rate making characterized by flat rates among rate classes. The residential class, presumably without recourse John Cooper Partner, NextWatt Solutions to understand the complexities of electricI cannot answer for ity economics, have a New York, but in the “simple” bill with a South and especially $/kWh charge, regardeNeRgy in warmer months, less of when they coneFFICIeNCy demand is lowest in sume energy. At the oththe midnight to 4 a.m. er end of the spectrum time frame. As people are competitive retail get ready for work, markets, where pricing is demand climbs and set by a marketer and a continues its upward trend until it peaks customer has seemingly infinite choice around 5 p.m. to 6 p.m. The day’s temand control. In between is an array of new rate methodologies under study by perature just finished peaking around 3 p.m. or 4 p.m., so there is plenty research groups and regulators. of residual heat, and evaporation of In the simplest analysis, the surface waters has bumped up humidregulatory challenge is to find a path ity. The electricity demand in the retail between hewing to the old ways of locations is increasing due to the influx thinking and complete deregulation, of customers, more than making up for I would suggest the range of middle the decreasing demand from the other way options lies in giving customers business sectors, and adding to the cost more control with energy informaof business that gets passed on to his tion feedback, and more choice with customers or bites into his bottom line. options to act on that feedback. What People are arriving home hoping to Ahmad Faruqui presented is highly get a break from the heat and therefore logical and is backed up by real data — turning up the air conditioning. this shouldn’t be new to NARUC. The Those are some of the people who challenge for groups like NARUC is will pay for dynamic pricing—the to step out to apply such ideas in realretailers and the working class. world applications, ideally with new Many industrial users have power rate models that individual regulatory purchase agreements, which are bodies may use for individual cases generally flat rate and still consideras they come up. I reflect back on a ably below the cost of residential or theme from last week and the words business retail rates. The only way To contribute to the time-of-use pricing will affect demand Transmissions department, is to cause the customers—in this case please e-mail your submission to mostly working-class, middle-income intelligentutility.editor@energycentral. families—to chose between a little com. Provide your name, address and relief and relaxation after a work day daytime phone number. Letters may be edited for style and space. and paying more for electricity. VOl 4, Issue 4 » July/August 2012
Where smart grid meets business—and reality.
It’s COMINg!
utIlIty ANAlytICs WeeK see page 40
DR 2.0
Pushing to the forefront
leVeRAgINg MeteR DAtA
KCP&L shares lessons learned
Integrating the utility
DA + MORe
An E n E rgy C E ntr Al Pu b liC Ation
www.EnergyCentral.com PRESIDENT/CEO Steve Drazga CHIEF OPERATING OFFICER Steven D. Solove VICE PRESIDENT, INTELLIGENT UTILITY Mark Johnson VICE PRESIDENT, DATA & ANALYSIS Randy Rischard VICE PRESIDENT, MARKETING PRACTICES Mike Smith DIRECTOR OF MARKETING Sarah W. Frazier DIRECTOR OF SALES, EMPLOYMENT SERVICES Kyle Schnurbusch
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UTILIT Y ICT PA RTN ER
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EN ERGY EFFICI ENC Y PA RTN ER
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W W W. I N T E LL IG E N T U T I L I T Y.CO M
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Verizon Wireless A Superior Communications Option for Smart Metering and M2M Utility Systems It is finally happening. Cellular service providers are finally coming into their own, earning recognition as key players in smart metering, home area networks and other smart grid applications. Long considered to be costly, technically slow relics of the bag phone era, cellular solution providers such as Verizon Wireless are now providing a new category of high-bandwidth, low-latency communications options that are revolutionizing the smart metering and grid automation technology sectors.
W WW.INTELLIGENTUTILIT Y.COM /// SEPTEM BER/OCTOBER 2012
N
6
ot so long ago, smart metering systems were classified as Automated Meter Reading or Advanced Metering Infrastructure (AMI) systems, with a principal purpose of collecting utility meter readings to be used for billing purposes. Those days are over. Today’s utility smart metering and smart grid communications systems are all about capacity, reliability and speed, as the volume and diversity of network data traffic has grown exponentially from a vast array of new utility applications. Moving rapidly away from earlier one-way AMI communications systems, the smart meters on today’s intelligent grid now require a higher-level, two-way command and control architecture using secure but scalable data transport mechanisms. With the advent of 3G and 4G networks that provide increased bandwidth for large numbers of voice and data transactions, Verizon Wireless and other cellular providers have stepped up to the plate with substantial capital investments in cellular infrastructure. Considered by many to be the fastest and most reliable cellular carrier, Verizon Wireless currently supports over 100 million wireless connections nationwide across its 3G and 4G LTE networks. Yet smart grid applications still take up
only a small percentage of the available bandwidth. And as 4G continues to roll out, an even greater amount of additional bandwidth will become available for high-speed utility data transmissions.
Cellular’s Increased Role in Smart Metering Deployment Research firm Pike Research recently forecasted that the worldwide market for smart meters will peak at just over 100 million devices in 2015. With so many devices coming on line and an increasing number of smart meter supported applications such as outage detection and time-of-use pricing now being implemented, utilities are searching for reliable, high-speed, highbandwidth communications solutions that can connect directly with meters or transfer large volumes of data from AMI networks back to utility data centers. Cellular solution providers such as Verizon Wireless are increasingly partnering with smart metering companies like Itron and GE Energy to integrate their networks within the meter or backhaul data from network data collectors when a mesh network is deployed. Rural areas have traditionally provided an especially difficult challenge for utilities where low-density meter populations have caused problems for wireless mesh systems. However,
continued expansion of cellular coverage in these areas has enabled utilities to pursue surgical drop-in alternatives that can communicate directly with individual meters or that can supplement mesh network deployments. Where network bandwidth and transmission speeds may be problematic for some rural mesh deployments, cellular connections are fast, near-real-time, and use IP-based open standards that can interact with other systems and solution providers. This is particularly important as the communications industry moves to a newer IPv6 standard that will be suitable for home area network applications and other utility uses. Greater use of two-way communications for remote disconnect functions and load control operations may require end-toend transmission speeds that cannot be supported over some low-bandwidth mesh networks. As data traffic increases, utilities may begin to experience a degradation of response times with few low-cost options if their networks involve the use of proprietary communications. Cellular communications is a dependable, scalable alternative for smart metering systems that provides a constant high-speed connection subject to a minimal effect from fluctuating data transmissions. For example, one such utility, Consumers Energy in Michigan, has opted for a full smart meter roll out using Verizon Wireless cellular technology that connects directly with GE meters for its 1.8 million customers. Consumers Energy will partner with Itron (previously SmartSynch) and use Grid Net’s software.
THOUG HT LE AD E RS H I P - S P ON SOR E D BY VE R I ZON W I R E LE S S
The Home Area Network Frontier
integrated with Consert’s Virtual Peak PlantSM load management system. According to a recent press release, the utility hopes to achieve a 250-megawatt reduction in peak system demand over the next four years by controlling air conditioning, water heaters and pool pump loads.
Growing Need for M2M Communications A third area of growing cellular participation is in the control of distribution automation and substation automation system devices for load balancing, line loss reduction and automated switching functions. With the open standardsbased data protocols used by Verizon Wireless and other cellular providers, utilities can employ new Distribution Management Systems (DMSs) that control a wide range of devices to monitor and control system loads and supervise high-volume, remote switching operations that take place in near-real time. Cellular communications are uniquely qualified to meet this challenge. Automating electric grid machine-tomachine (M2M) interactions is key to achieving improvement in distribution network reliability and reducing the economic effect of lengthy power outages. Cellular communications provides the critical characteristics — secure high-speed data transmission rates and network communications reliability — that will be needed to operate the sophisticated DMSs of the future.
THOUG HT LE AD E RSH I P - S P ON SOR E D BY VE R I ZON W I R E LE S S
Major Infrastructure Investments The cellular communications industry is pouring billions of dollars into development of networks capable of delivering reliable, high-speed data communications in addition to voice. Verizon Wireless has led the way and will continue to spend huge sums to upgrade and expand its facilities, and to further increase bandwidth and speed through continuing deployment of 4G service. Few smart metering companies can match these spending levels, and utilities are best served when they look to cellular carriers for their smart grid communications needs. ABOUT VERIZON WIRELESS Verizon Wireless operates the largest high-speed wireless network in America. We work hard to provide customers with the highest level of satisfaction by offering quality products and services. Headquartered in Basking Ridge, N.J., Verizon Wireless is a joint venture of Verizon Communications (NYSE:VZ) and Vodafone (NYSE and LSE: VOD).More than 85,000 Verizon Wireless people serve over 90 million customers nationwide. Verizon Wireless is committed to helping the local communities where we work.
W W W. I N T E LL IG E N T U T I L I T Y.CO M
Many utility industry analysts anticipate that the next frontier for smart metering/ smart grid applications will be Home Energy Management. With EPA regulations forcing the retirement of large numbers of coal-fired generating plants, utilities are rightfully worried that energy prices will begin to skyrocket. Many are turning to demand response programs to reduce peak system demand and forestall the need to purchase additional energy at high on peak prices. As utilities continue to roll out their smart metering systems, many are considering home area network solutions that employ programmable thermostats, in-home energy displays and other smart appliance controls. Some are reinstituting old load control programs that support air conditioner cycling, pool pump and water heater controls. This proliferation of new grid devices will add a significant amount of data traffic to already congested utility smart meter networks, and it raises questions concerning their ability to provide the required bandwidth without causing significantly degraded network performance. Cellular communications can help to alleviate these types of latency concerns by taking over some of the high-volume data transfer requirements from overly congested mesh networks. Direct connections with certain high-volume customers, or the installation of gateways, routers and other IP- based devices, could speed up data transmission to the smart meter head-end system or to the cloud for use in various hosted home energy management networks available today. Either way, using cellular for the smart meter mesh network can relieve much of the growth in data traffic that will result from implementation of home energy management and load control systems. CPS Energy of San Antonio, for example, recently announced a major demand response deployment program using Verizon Wireless technology
7
AROUND THE GLOBE AUSTRALIA
CANADA
Benefiting from wave technology
Proposal to reduce customers’ bills
By 2050, ocean waves could supply up to 11 percent of Australia’s electricity, according to a preliminary
Ontario’s Electricity Distributors Association (EDA) recently met with the Ontario Distribution Sector Review Panel to outline a six-point plan it says will save Ontario electricity consumers more than $540 million each
assessment research study
year. The association’s 150-page submission details how the province can realize
completed by the Commonwealth
the full potential of its electricity distribution system and achieve efficiencies
Scientific and Industrial Research
that will ultimately benefit customers and communities.
Organization (CSIRO). The organi-
The plan, “Power to Deliver: Recommendations for the
zation pointed out, by way of
Future of Electricity Distribution in Ontario,” examines all
example, that this would
aspects of the distribution sector including operations, own-
be enough electricity to
ership, regulation and new and emerging technologies to
power a city the size
find ways to make the sector more efficient. “Our submission details how, with the right changes,
of Melbourne.
the government could reduce customer bills by close to
CSIRO has cautioned that,
5 percent and improve the distribution system in Ontario
as ocean energy extraction
at the same time,” said Max Cananzi, the EDA’s chair.
is an emerging technology, much further research and development is required on mapping the
Charlie Macaluso, the EDA’s president and CEO, added: “There are definitely savings to be had through mergers and amalgamations if done correctly—we estimate about $50 million worth—but it doesn’t end there. We
nature of the resource, technology
dug deeper and identified greater and more significant savings of nearly half a
performance and understanding
billion dollars that could come from improved regulation, a keener focus on
the wider economic, societal and
the customer and encouraging distributors to grow.”
environmental impacts.
The plan can be found at http://www.eda-on.ca
W WW.INTELLIGENTUTILIT Y.COM /// SEPTEM BER/OCTOBER 2012
The preliminary study involved
8
oceanographers, economists and engineers analyzing all the vari-
J A PA N
ables of ocean renewable energy.
Smart cities projects gear up
The overall aim of the work was to understand ocean energy potential and whether, as Australia’s largest resource, it could also be a part of Australia’s future energy mix.
The power shortages that followed Japan’s triple disaster in March 2011 have spawned a focus on better energy management, as well as a renewed focus on energy-efficient “smart cities.” Approximately 50 initiatives have been launched to build smart communities in the northeastern Tohoku region, which was hit hard by the disasters.
Australia’s abundant wave energy
Eight of these initiatives—in Fukushima, Miyagi
resource is concentrated along its
and Iwate—have been selected by Japan’s
southern coastline, with its east
Economy, Trade and Industry Ministry to
coast also providing a consistent,
receive subsidies by March 2016.
though not as large, contribution.
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TOP 12
TOP 12 utility champions ++In the small electric co-op utilities of the U.S. By Kate Rowland WITH THIS ISSUE, WE TAKE A CLOSER LOOK WITHIN OUR
Top 12 for 2012 at the champions of small electric cooperative utilities across the United States. Again, we had a little bit of help this time around in picking some of those to highlight in our Top 12 for 2012, thanks to a raft of independent nominations. Often, you won’t find small cooperatives in the news, but they’re working away on new projects (from distribution upgrades to smart grid efforts and more) all the same. Our choices here both honor these 12 people and the teams with which they work within their utility cooperatives. Leading Kaua’i Island Utility Cooperative’s charge to “reinvent how Kaua’i is powered” is president and CEO DAVID BISSELL. The co-op is being transformed, over time, into a renewables-based utility focused on hydropower, photovoltaic, biofuel and biomass. The co-op’s smart meter installation process began in May 2012, and will continue for approximately 18 months.
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JEFFREY EDWARDS, has been president and CEO of Southside Electric
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Cooperative since 2007, but he began working in the electric cooperative program for Union Electric Membership Corporation as an engineering aide in 1985 (and was director of operations there by 1989). The U.S. Department of Agriculture (USDA) awarded the co-op a $44.881 million loan guarantee, of which $7,352,881 will be dedicated to smart grid projects. Southside Electric, located in Crew, Virginia, serves 54,363 members. STEVE FOSS came to Leavenworth-Jefferson Electric Cooperative as its
general manager at the beginning of 2008, following 19 years with Dakota Electric Association in Minnesota. In that time, he and other staffers have worked to build communication with co-op members. The co-op began installing AMI meters for its 8,210 consumer-base in 2010, and also recently received a $7.58 million loan guarantee from the UDSA for upgrades, as well as $104,028 in smart grid projects. ROBERT HANCE, president and CEO of Midwest Energy Cooperative, is an
industry veteran who held the chief operating officer position with Great Lakes Energy from 1974 to 1999, before heading to Wabash Valley Power Association
and then Midwest Energy. In his time with the Michigan cooperative, which serves 35,007 consumers, he has developed “First in Class” organizational attitudes and built an “I Care” culture within the co-op. BOYD HUFF, president and CEO
of Whitewater Valley Rural Electric Membership Corporation in Indiana, will be overseeing building and improvements on 121 miles of distribution line in the Liberty, Indiana, area, as well as new smart grid projects, thanks to a recent USDA loan guarantee of $12 million. Whitewater Valley REMC serves 11,956 consumers in six counties. ALAN LESLEY, the general man-
ager of Comanche County Electric Cooperative Association in Comanche, Texas, has more than 8,800 customerowners to serve. He is in charge of more than 16,000 meters, and serves seven counties in North Central Texas with approximately 5,000 miles of line. And he’s about to get busier, having just received a USDA loan guarantee for $18.469 million, including $6,551,790 in smart grid project loan guarantees. Oklahoma’s Northwestern Electric Cooperative has come a long way since its incorporation in 1940 by ranchers and farmers in the northwestern part of the state who were unable to secure electrical service from any other source. And CEO TYSON LITTAU is firmly focused on the future for his co-op’s 11,218 customer-owners. Through its Peak Shaver program, participating members are notified by phone message, email or text message to postpone unneeded electricity usage, it encourages energy efficiency through CFL bulb sales, and the co-op is about to launch a new smart grid project.
Central Electric Membership Corp. CEO and general manager MORRIS MCCLELION has a big job on his hands for a relatively small cooperative, as numbers go. With more than 19,600 customer-owners including large industrial customers like Imperial Freezer, 3M and Luck Stone Corporation, this North Carolinabased co-op has undergone a lot of changes over recent years, including automated meters, in-house data processing, automated outage reporting, online bill payment, and a host of programs dedicated to improving services and energy efficiency for members.
Steuben REC Inc., might be on the small side, but it’s mighty proud. “Owned by Those It Serves: Served by People that Care” is its motto, and brand new general manager WAYNE SHERWOOD exemplifies it. Sherwood brought with him more than 30 years’ experience in the electric utility industry, and was most recently general manager for a decade for Oneida-Madison Electric Cooperative, also of New York. And he’ll start boldly: Steuben REC just received a $9.362 million loan guarantee from the USDA, including $706,050 for smart grid projects. TIM THOMPSON is Lake Region Electric Cooperative’s fourth CEO in the
75-year history of the Minnesota utility cooperative. Like his predecessors, Thompson is focused on propelling the cooperative forward into the future by creating new revenue streams, such as LREC’s geothermal program and part ownership in Carr’s Tree Service, to mitigate some of the wholesale cost of electricity for its members. The 26,169-consumer cooperative is also focused on renewables, with a full 12 percent of its power supply coming from renewable sources. And finally, a big shout out goes to Central Georgia Electric Membership Corporation’s GEORGE L. WEAVER, who has held the position of general manager (now president) since 1983, an impressive term of office. The cooperative, based in Jackson, Georgia, has grown steadily from its small beginning in 1937 to approximately 51,133 billed accounts served and 5,331 miles of line as of Dec. 31, 2011.
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Two years ago, STEVE METHENY, the assistant general manager of Colorado’s Delta-Montrose Electric Association, stopped us at the Knowledge2010 summit and told us we really needed to write about what his utility co-op was doing. He was right. In the July/August 2011 issue of Intelligent Utility, we did just that that. DMEA serves about 35,000 metered
accounts across three counties, with customers including farms and ranches, two large coal mines, an array of commercial and industrial customers, and urban and rural homes. And Metheny has earned the right to be proud of his co-op’s work.
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V2G
Are We Ready? The business of V2G ++Technology and business case go hand in hand By Phil Carson THE FUNNY THING ABOUT TANGIBLE INNO-
W W W. I N T E LL IG E N T U T I L I T Y.CO M
ILLUSTRATIONS BY ABBY ORLANDO
vation is that while doubters kick up dust, innovators move to market. In the case of V2G (vehicle-to-grid) technology innovation, a go-to-market strategy and caution’s inertia are converging as you read this article. The concept, of course, is that electric vehicles (EVs) might serve as mobile energy storage that, in aggregate, could serve as a significant resource for the grid. In fact, in certain quarters, the term V2G is giving way to “GIV,” or grid-integrated vehicle, a term that reflects the two-way, controlled flow of electricity and data. At least GIV is favored by the first market mover, thanks to control and communications innovations at the University of Delaware that will make GIV a commercial proposition this fall.
Examining the value proposition As every innovator knows, however, hurdles remain to realizing the potential of exciting ideas, including V2G. The launch of eV2g, a new partnership between NRG Energy and the University of Delaware, will face all the challenges to the commercialization of new technology and new ideas in place since the wheel caught on. (Who knows how long that took, or what naysayers conjured up?) But the technical innovations and the business case logic in V2G’s case underscore the concept’s attractiveness and why a variety of parties worldwide are pursuing it. And at least one utility and one RTO (regional transmission organization) in the U.S. are examining the value proposition in detail. That value proposition, simply put, would aggregate EVs whose owners have signed up to do so—they could be fleets or individuals—and at scheduled times charge or discharge their batteries to provide ancillary services such as frequency regulation and spinning reserves to independent system operators (ISOs) and RTOs. In return, they would receive a payment which, over time, could further lower the barrier to EV sales. Eventually, as the number of GIV-enabled vehicles increase to a critical mass, that aggregation could serve as an energy resource on the wholesale market, according to proponents. The key to involvement with the wholesale energy market is timing. “Whether we’re doing grid-to-vehicle or vehicle-
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V2G: ARE WE READY?
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to-grid, we’re doing it at a time when it has value to the electric system,” said Willett Kempton, professor in the College of Earth, Oceans and Environment and professor of electrical and computer engineering at the University of Delaware, who has been instrumental in conceiving of V2G and bringing about its fruition. (Kempton also led the development of three crucial patents licensed by eV2g to commercialize the GIV concept.)
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Patents propelling efforts Intellectual property is often the most crucial differentiator in high tech, and in this case, three patents held by the University of Delaware (three more are pending) will propel eV2g’s efforts. One patent is for technology referred to as an aggregator, which comprises logic on the server of an ISO or RTO and sends signals from the grid operator to participating vehicles to control charging and discharging in aggregate, so that many cars function as one virtual power plant (VPP). The second patent is an enhancement to EVSE, or electric vehicle supply equipment, and it communicates between the ISO server and vehicles in a secure manner. The third patent is known as vehicle smart link or VSL, a component which resides inside the EV. It communicates with the aggregator and EVSE. One advantage of partnering with NRG Energy, according to Kempton, is that it has legal representation in major markets where it will spearhead simple changes to existing laws to allow GIVs to be treated like net-metered solar installations. (Delaware may have been the first state to make that change, which it did last year.) “I don’t consider regulatory changes to be an impediment,” Kempton said. “All they’re doing is modernizing those laws.” Kempton also doesn’t see EV adoption rates as an impediment. He cited initial, modest market penetration numbers but pointed out that those numbers represent a doubling of EVs on the road in the United States per annum. Hurdles still exist The tangible hurdle that Kempton and others see is getting EV makers to adopt battery technology—and the patented, onboard EV intelligence—that allows EVs to discharge upon receiving a signal from the ISO. Kempton sees that as an educational challenge, more than a technical one. The short-term solution is to educate EV makers about the capabilities of their batteries. What about assuaging the concerns of EV owners regarding their vehicle’s battery life? Software will enable
EV owners to assign parameters for charging and discharging cycles, either online or via a smartphone, according to Kempton. If owners can predict their driving patterns, then an appropriate charging pattern can be programmed so that the charge or discharge cycle’s wear and tear on the battery is significantly reduced. (Major wear and tear occurs when batteries near empty and when they’re charged fully. Partial, as-needed charges and discharges produce less wear.) Similarly, the battery’s programmed characteristics will dictate whether it is appropriate for use as a frequency regulator (many shallow charges and discharges through a day) or as spinning reserve (a few dozen occurrences during the year, typically for 10 minutes at a time). Another factor, Kempton readily acknowledged: “weirdness.” GIVs essentially offer mobile energy storage and may compete for attention with stationary batteries for This (V2G) is one ancillary services. One large, 100-kW stationary piece of the puzzle battery may appear to be a simpler solution, with a in a smarter grid— swift path to market. GIVs for ancillary services have how do those pieces a few moving parts, so to speak, and like utility-scale fit together? batteries, they’re decidedly nascent. Yet the capital outlay to harness 100 GIVs is something like 10 percent of an equivalent stationary battery. That’s a least-cost path to the same service, Kempton argued.
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San Diego spots opportunities Of course, the market will be created by utilities, ISOs and RTOs, not proponents. Alex Kim, director of customer innovations at San Diego Gas & Electric (SDG&E), said his utility is focused on exploring V2G as part of its overall effort to make use of Southern California’s abundant sunshine and high EV penetration. San Diego may have one of the highest density of EVs in its region (more than 1,600) than any region in the country, according to Kim. SDG&E also may be tops in distributed solar photovoltaic panels, with more than 18,000 grid-tied systems. In combination, those two resources support a V2G business model that would focus on localized benefits in addition to ancillary services for the wholesale market that serve an ISO or RTO. When there is an over-production of renewable energy, charging an electric vehicle at that time could help to mitigate impacts on the grid, Kim said.
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Conversely, EV discharges could help balance the ramping 2007 to 2010, in which a handful of EVs owned by the caused by intermittent renewable energy production. The University of Delaware were actively charging and dischargutility has a definite interest in the potential for solar PV to ing from and to the grid. And money changed hands when charge EVs, which could serve as a backup resource for the the “fleet” provided energy on-demand to PJM, according home. Kim noted that one major Japanese car manufacturer to Scott Baker, a student at the university then, today a busihas announced it will launch a vehicle-to-home system in ness analyst in the applied solutions division at PJM. That successful project was intimately tied to the development of Japan this year. In San Diego, greater than 30 percent of EV owners the university’s patents now being licensed for commercial have solar PV as well. Meanwhile, SDG&E takes an active use, Baker said. Since that time, PJM lowered its requirement for the approach to bringing EV owners into the utility’s database, so it can assess potential impacts to the distribution system frequency regulation market from 1 megawatt down to and develop visibility into the distributed resources that will 100 kilowatts. “That’s a wholesale market rule change that lowers the help it build a smarter, interactive grid. barriers to entry for V2G,” Baker pointed out. “The 100-kiloSDG&E is working with a variety of stakeholders, including automakers and regulators, to explore how watt scale is important because it allows market participants to demonstrate real results V2G might serve local needs and without a large capital investcontribute to California’s energy ment. Now, you might only and carbon emission goals, Kim WEBSITES need 20 EVs to demonsaid. The utility has several ongoeV2G strate V2G benefits ing efforts focused on how to draw http://ev2g.com/ and that gives entremaximum benefit from V2G. It PJM FACT SHEETS preneurs clarity and has teams working on the controls http://tinyurl.com/9osfqmd confidence.” and communications technology PJM on ENERGY STORAGE Of course, those are that would allow coordination with http://tinyurl.com/9mc87sj private sector enablers. For PJM’s charging stations; it is conductpart, the main motivator is reliability. ing a demonstration project with a PJM on PHEV “From PJM’s point of view, stationary battery as proxy, prior to http://tinyurl.com/96b9d2n energy storage will be an enormoustesting mobile storage in EVs; and it ly useful tool for system reliability,” is evaluating the variables that affect Baker said. “To date, only pumped when a utility could call on V2G as a resource. Some of that work is ongoing at SDG&E’s Energy hydro has served that role effectively, but it is unlikely that much more will be built in PJM. Looking ahead, then, Innovation Center. Once EV penetration and bidirectional batteries make distributed resources may provide for new grid-scale V2G a viable resource for frequency regulation, Kim said, energy storage, such as thermal energy storage, demand there will be value for both the utility and the customer— response products with storage characteristics—and aggregations of EVs.” though that value fluctuates over time. To take advantage of V2G’s potential, of course, means “V2G is a value-driven proposition,” Kim noted, “and that that PJM will take cost-effective steps to see that V2G value will depend on the number of vehicles in the system and customer willingness to participate. So we’re study- services make it to market. And according to Baker, ing charging behavior, based on rates, with the University while technology hurdles remain, the real uncertainty of California Davis. The complicated part is understanding lies elsewhere. “The jury is still out on which business model will what customers are doing and will be able to do. “This (V2G) is one piece of the puzzle in prove out,” Baker said. “That’s the most intera smarter grid—how do those pieces fit esting part, the innovation around the together?” Kim noted. “We’re taking a business model. That business model will improve as battery costs drop. holistic approach.” The concept of using an elecPJM gets it tric car as an energy storage On the opposite coast, PJM Inter- resource makes perfect connection was intimately involved in sense. But the real chalthe Mid-Atlantic Grid Interactive Cars lenge is how the busiConsortium (MAGICC) project from ness model works.”
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Backhaul from the
Back 40
Connecting all the dots, wirelessly ++South Central Indiana REMC chooses scalable solution for future W WW.INTELLIGENTUTILIT Y.COM /// SEPTEM BER/OCTOBER 2012
By John R. Johnson
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WHEN THE SOUTH CENTRAL INDIANA RURAL
Electric Membership Cooperative was looking for the most efficient way to transport data from its new supervisory control and data acquisition (SCADA) and advanced metering infrastructure (AMI) systems to its microwave-based backbone network in 2007, the utility considered many options. Utility executives knew that settling on a solution that answered only the near-term immediate need was not the way to go. Instead, the Martinsville, Ind.-based utility wanted a scalable solution that could be tweaked and used for new and innovative concepts down the road. Own your own With more than 34,000 customers spread over seven counties, SCI is the largest of rural Indiana’s 40 electrical
membership cooperatives. Yet, it operated with a small budget for the project, and knew that a wired network would not be a cost-effective solution. The utility collaborated with an engineering firm that advised it to install an IP-based point-to-multipoint network. The consulting firm also recommended that the utility own its own network as opposed to leasing so it could define its own uses for the network. In addition, owning eliminated the need to rely on an outside third party for service and the high monthly fees they often charge. “It made sense to put in a high-speed data network to our substations, not only to handle SCADA and AMI backhaul, but just looking out into the future for other applications,” said Jack Hubbard, vice president of distribution services at South Central Indiana REMC. “At the time it seemed like there were a lot of opportunities to do more out at our substations, so it just made sense to invest in a data network.” Critical connectivity With a network of 22 substations, most of them located in very remote locations, it was important to find connectivity that could not only carry the utility’s mission-
Next steps The next step for South Central Indiana Rural Electric involves a feeder automation pilot that is currently in its
early stages. Hubbard says that the pilot calls for placing motor operators on three switches that will allow the utility to transfer three circuits between two substations. “It’s a pretty basic pilot,” he said. “We’ll be communicating via our SCADA system to down-line devices and those devices will actually be communicating over the data network back to our system, so it will be a separate end point besides just our substation. “That will allow us to do switching automatically from our SCADA system as opposed to having a person at each device operating it. We can have maybe one person in the area making sure switching occurred properly. We’re just focusing in on two substations but we’re pretty confident we’ll grow it from there.” Down the road, the utility hopes to obtain additional information from other devices like reclosers, where the data gained can provide information about load and faults that the utility can’t access now. And by monitoring regulator controls, the utility hopes to undertake voltage reduction on some longer feeders that have down-line regulators. “We’d be able to do that by communicating with the regulator and by adjusting their settings remotely,” said Hubbard.
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critical usage data, but also allow for other crucial functions such as connecting two-way radio system repeater sites, and supporting alarm and video security systems that SCI has rolled out since deploying the network. Hubbard says the system has worked exactly as planned, and that the utility plans to deploy some additional features over the next several months. “The biggest benefit is exactly as we expected— we’re able to backhaul our AMI and SCADA data,” said Hubbard. “And because we have connectivity at the substations, our technicians can get connected back to our internal network to get information that they need during a job, like product manuals. We’ve been very pleased with the reliability of the system.” Because technicians performing maintenance and other tasks can connect back to the internal network, the system has saved time and labor from driving back and forth between substations and the main office to locate information that they need during a site visit.
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Lessons learned As for challenges and lessons learned, Hubbard says that because the utility is in such a rural location, obtaining line of sight hasn’t always been easy due to the hilly terrain located throughout its service territory. “Getting the line-of-sight link has been a challenge,” he said. “We went through all of the engineering studies that said the system would work out of the box, and for the most part it did. But with seasonal changes like leaves on the trees, we were having some trouble communicating with some of our substations. We are looking at installing some relay
Leveraging communications technology ++Illinois Rural Electric Cooperative rolls out Internet options By John R. Johnson
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THE ILLINOIS RURAL ELECTRIC COOPERATIVE
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(IREC) is living a co-identity. On the one hand, it functions as a traditional cooperative electric supplier to just over 20,000 customers in a rural farming area in western Illinois. On the other hand, it serves as an Internet service provider, allowing several thousand of its customers located in extremely rural areas of the state the same fast access to Internet connectivity that those in large metropolitan areas take for granted. Listening to the need Lately, IREC’s customer base seems more excited about the ability to have Internet access than keeping the lights on, which only makes sense given that they have been clamoring for Internet connection while taking energy services for granted. “When we hold our annual meetings people tend to ask more about Internet connectivity than they do about what we’re doing about our power supply,” said
points to try and get better coverage to our substations in our more rural areas.” Hubbard says not to overlook regular maintenance that the network will require: “You don’t just put it in place and expect it to work for years on end.” For example, Hubbard says that after strong wind storms, utility crews often need to realign and adjust network equipment in the field to ensure that network coverage remains strong. John R. Johnson is a Boston-based freelance writer specializing in alternative energy and technology topics.
Sean Middleton, manager of engineering for Illinois Rural Electric Cooperative. “That’s how important it is to people.” Internet connectivity has become extremely important to IREC as well. The utility initially set out to deploy its scalable wireless mesh network to bring Internet connectivity to its remote substations located throughout its 2,200-mile service territory. “That was the top priority,” said Middleton. By doing so, the utility could do away with the costly and often unreliable leased lines or low-bandwidth radio dedicated connections used for its SCADA system that were proprietary and limited in scope. “We have already facilitated getting high-speed connections to our substations, which has given the cooperative a wealth of communication opportunities,” said Middleton. “That was the original goal. Now that we’re there, we can continue adding smart grid enhancements and all kinds of things because we have that portal to our own substations.” New opportunities The cooperative has already integrated its AMI system with the wireless connectivity at its substations to manage the transfer of meter data, and the office can “talk” with just about all assets at the substations. The SCADA system has also been converted to the system and transports data in a much safer and more secure environment. “Now that we have connected IP network to the substation, it’s kind of like we can do whatever we dream up,” said Middleton. “We just keep thinking of new things.” For example, the utility has added video surveillance equipment and contact monitoring on doors for building enclosures. Middleton’s staff thought of this idea when a thief attempted to break into one of their substations to steal copper. With substations in such remote locations, video and door monitoring devices alert company personnel to any unauthorized people at the facility.
Leveraging the network for customers The biggest advantage, however, has been rolling out Internet service to customers. The availability of additional bandwidth spawned the idea to leverage IREC’s network for other purposes, including the distribution of high-speed Internet service. The low population density of rural communities in Illinois has prohibited most Internet providers from delivering high-speed services. Therefore, Middleton says that most of the utility’s customer base remained unserved, relying on time-consuming dial-up service or on satellite systems. In the early going, IREC researched a number of delivery vehicles for broadband. Key to the success of the program was working around the unique geography of utility’s service area— a Midwest farming region where customers are often separated by miles. On average, townships in the service area have about 2,000 residents. Due to the rolling terrain typical of the area, line of sight would only work for a very small percentage of potential subscribers. Satellite was an early consideration, but the IREC soon realized that satellite lacked the scalability to meet demand as their systems reached capacity. That’s when IREC began to focus on wireless technology. Demand for broadband access was exploding, and IREC saw the excess capacity in its network as a solution to a severe customer need as well as an opportunity to broaden its revenue stream. “Our co-op’s main mission is to improve the quality of life for our membership and one of the ways we can do that is through Internet connectivity,” says Middleton. “The fact that we could push that out to people who didn’t have any other options has been huge. For the rural population in this area, no [other providers] are coming because we’re in an underserved demographic. But how long should people have to wait for Internet connectivity? That’s why we jumped in. We saw an opportunity to fill that niche.”
John R. Johnson is a Boston-based freelance writer specializing in alternative energy and technology topics.
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A springboard for other utilities IREC rolled out different pricing structures for the amount of broadband consumed. Middleton wasn’t specific about the revenues generated from the new service offering, but indicated Internet connectivity is ramping up quickly. “Obviously, it takes time for it to build on itself and to pay its own way, but it is definitely headed in the right direction and that was our main goal,” he said. Other small cooperative utilities in Illinois have used the Illinois Rural Electric Cooperative model to roll out similar services to their customers. “We definitely have had lots of calls from folks wanting to know how to do this,” said Middleton. “Two or three other utilities in Illinois have followed suit and are doing the same thing. We feel like somewhat of a springboard when it comes to getting this off the ground and demonstrating to other utilities that it’s a good fit. “We continue to expand our coverage and make it available to anybody in our service territory who wants it.”
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From Purpose-Built to Multi-Purpose The Changing Face of Smart Grid Networks
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Gary Kessler, Itron Inc.
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ith smart grid use cases growing in complexity, the past five years have seen a rapid evolution in the concept and purpose of communication networks for utilities. From advanced metering and demand response applications to plug-in electric vehicles and beyond, smart grid decisions are becoming more strategic, and smart grid network infrastructures are increasingly required to meet the needs of these diverse applications. Hence, achieving flexibility in network choices and implementation, while keeping consistent system behavior, is key for successful smart grid
deployments. As utilities often cannot foresee what business, regulatory or environment changes may arise in the future, it is important that they build a future-forward network that is adaptable. These complex use cases often have conflicting impacts on the cost, availability, reliability, latency and bandwidth needs from networks. Thus, utilities must make decisions that allow them to leverage private and public networks, include existing assets, and ensure the expected performance and security at the field devices is adequately met. With diverse use cases specific to each utility, today’s network infrastructure needs are
just as unique as the utilities themselves. Utilities don’t need a network platform that is purpose-built for one application, but rather a multi-use network that can accommodate current and future applications. In the past, utilities built networks to a specific use case, or set of use cases, that pertain to one application. Any single network option doesn’t singularly offer substantial benefits over others while fulfilling all the plausible applications of the smart grid. A customized network gives utilities the most flexibility to deploy a solution that fits their current operational and business requirements,
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regulatory mandates and service territory geography without having to compromise with limited options of future growth. Network infrastructure plays an important role in solving business problems like increasing operational performance, extending capital asset life, enhanced efficiency of the grid and improving transmission assets. The important aspect of evolving any network is to ensure that it meets the utility’s needs today and can evolve to meet the business requirements for tomorrow. The most critical aspect of network evolution for today’s utility is to evaluate market conditions and plan for what’s next. As the smart grid evolves, utilities will continue to refine business uses that involve M2M relationships and peer-to-peer communications. Having a network architecture that is extensible, coherent and uses open standards makes network evolution less costly and more reliable.
A Multi-Use Approach
Since utilities are solely responsible for the performance of their systems and customer satisfaction, many prefer to run an optimized private network they can maintain themselves. These network
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that this multi-use approach to networks is the best course of action for the everevolving utility.
A utility may also opt to tailor their network by adding solutions that can enhance certain performance areas. Layering a private infrastructure with cellular, IPv6 (i.e. Cisco’s Connected Grid Router) or another technology is a reliable way for utilities to integrate secure, standards-based communication for endpoints and support multiple applications across the grid. Additionally, while cellular has traditionally been used as a “gap-fill” solution, utilities are now finding value in full cellular deployments with IP at every endpoint.
Defining Multi-Use Infrastructure
As utilities’ needs differ, so do the appropriate communications technologies and applications. When considering smart metering deployments with random, opt-in programs related to innovative tariffs or demand response (especially when rolled over large periods of time), a public network makes the most sense. Similarly, mission critical activities like near realtime feeder switching may best be deployed using application-specific communication networks. It is apparent that certain business needs are better met by private networks and some by public, yet utilities may want both capabilities (and more), now and into the future. It is for this reason that networks should not be built for one application. By implementing a multiuse network that leverages a variety of communication technologies, utilities can extend the reach of the network and the breadth of applications available. As the smart grid advances and business requirements grow, it’s increasingly clear
The adoption of a multi-use network approach encourages solution providers to develop innovative platforms that meet market demands and encourage interoperability. And a true multi-use network is not simply defined by a utility having multiple communication technologies dwelling in the same service territory. A few key guiding principles can help define a multi-use system.
1. Standards Using a standards-based application layer protocol that provides a clean abstraction from the physical layers is a necessity for a grid that transitions well into the future. The adoption of standards-compliant technologies, regardless of what specific network type the utility chooses, helps avoid hurdles they may experience as they customize their communication network. “In 2010, only three percent of global shipments of radio frequency-based communications nodes for distribution automation and/or AMI applications were based on fully standard technologies. This figure will increase to more than 70 percent by 2015, the market intelligence firm forecasts, and to 85 percent by 2020.” Pike Research- July 2012 As utilities continue to build communication infrastructures that are less application-specific and more strategic, solution providers must
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The case for a unified smart grid network evidences itself in utility environments throughout North America. The network used by the “mega” utility that covers several states and millions of square miles would not be appropriate for the co-op that covers a few counties and a few thousand customers. Scale, flexibility and coverage are key aspects of network capability and performance.
architectures often satisfy regulatory deliverables and can offer 99.99 percent of availability at an attractive price.
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adapt. Next generation technology means standards-based solutions. It will unquestionably be where utilities will continue to invest.
2. Performance Consistency In an effective multi-use system, smart grid endpoints should operate consistently to provide the utility with maximum performance across the grid. And this should occur regardless of the physical media for the network communications. For example, devices on one network should not respond to a request in four hours while others perform the same in 30 seconds. Similarly, it should be possible to universally operate certain core behaviors. A multi-use system should send demand response messaging to all devices the same way. The utility operator should not need to know what physical substrate to which the device is connected, and a common, consistent response would be expected back.
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3. Head-End Consolidation
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Alongside performance consistency is the need for a single point of consolidation for all devices, regardless of communications technology. An ideal, multi-use network is one in which the headend treats all endpoints the same so that the functionality of a particular device and communications technology becomes irrelevant, and the information profile is the key differentiator. This opens the door for a network to provide precisely what the utility needs for their business case – now and in the future. And
it allows devices to be appropriately classified by information class, regardless of communications technology, thick or thin client and product manufacturer. While there’s still room for further definition (as will likely always be the case), these key guidelines provide something to build upon. We can strive for the ideal – a network architecture built for the utility’s needs, using standards-based communication that provides ultimate performance consistency and an integrated head-end.
Finding the Value in a Multi-Use Network In addition to finding a network that best fits a utility’s business case, there are many reasons why a multi-use network positions the utility for growth as the smart grid continues to evolve. For example, the following applications thrive in a multi-use network scenario:
Diverse Service Territories When a utility has a service territory that is grouped in small geographic areas or has different terrains within its service territory, it’s obvious that the network infrastructure will be as diverse as the different areas demand. One single service territory can contain urban, suburban and rural geographies that have different infrastructure challenges. In many cases, where there the population density becomes sparse, the cost per metering point for installation of a private network becomes very expensive and impractical. In these instances, use of an existing cellular network can improve the business case outlook and significantly lower the cost per metering point for the utility.
Volt/VAR Applications A utility may choose to manage VAR levels in an attempt to minimize technical losses and ensure delivery of quality power to customers. Historically, this has been done by changing voltage levels at the point of regulation. Often utilities will add capacitor banks along the distribution line to maintain the highest power factor possible in order to reduce losses. Controlling these capacitor banks to provide the most efficient reduction in losses requires near realtime communications, which a multi-use network can efficiently provide by using the communications path best suited for the application.
Demand Response One mode of Volt/VAR optimization is demand response. Smart meters are extremely useful for the implementation broad demand response programs across a utility’s grid, and a multi-use network can provide a broad range of demand response capabilities as well. With a variety of data paths, endpoints can help a utility build efficient demand programs
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where certain network infrastructures provide significant value with speed and others can offer more depth and breadth.
Opt-In Programs Customizable programs are increasing in popularity throughout North America, giving end customers the ability to “opt-in” for monetary incentive. In this scenario, smart meters are spread across multiple paths and not all endpoints are not necessary truly “smart.” Therefore, manual meter reading is still required for some end users. A multi-use network scenario allows utilities to incorporate solutions for those locations that have intermixed AMR/AMI and use a mesh network where there are dense concentrations of AMI opt-in customers.
Grid Element Management Grid element management use cases revolve around the ability of the utility to remotely control grid measurement and control devices. A multi-use network can provide the ability to reach all grid control devices within their service territory in a concise and consistent manner. Cellular provides them the ability to reach remote or high bandwidth devices, and mesh covers those devices that are with dense urban or suburban areas.
Distributed Generation
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PHEV Most plug-in hybrid electric vehicles (PHEVs) exist in non-contiguous areas and charging stations often require financial transactions for customers to charge their PHEVs. A multi-use network offers the utility a simple and convenient way to choose the appropriate network technology to support the PHEV or charging station without having to build new network infrastructure.
on building a network platform that is not purpose-built for one application, but rather multi-use to allow more applications to be put on the network. The industry has seen a recent shift, and major smart grid players are now enhancing their product portfolios to provide metering, communications and software solutions that offer utilities the best of every network available. Keeping the key elements of an effective multiuse network in mind, these solution providers can continue to build products to enhance performance of utility’s assets. Basing buying decisions on what business use cases the utility intends to meet and what regulatory environment is available to meet those use cases is the smart grid network reality. As the next phase of smart grid evolves with ever-advancing technology and new applications, utilities can move at their own pace for their own unique environment. And the perfect technology for them will be right there waiting to take them into the future. Gary Kessler is focused on product marketing for
Looking Ahead
Itron Cellular Solutions. Kessler has more than a
It’s important that utilities and technology providers understand that the key to smart grid success hinges
His work has covered a broad range of products
decade of technical project management experience.
and technologies, from cellular telephony to robotic inspection and power line phasing techniques.
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Distributed Generation use cases are similar to Opt-In use cases. Distributed Generation (DG) is generally never installed in a contiguous footprint. This necessitates having the ability to create flexible network paths to support data collection and control of the DG asset where there may not be existing network infrastructure. Much of the DG today is
around solar, residential and utility grade. The residential DG installations of solar panels often create the most difficult network requirements. Often solar has regulatory requirements for monitoring panel generation for renewable energy credits and/or solar inverter generation information, which creates extra burden on the network bandwidth. Multiuse networks allow for integration of applications that support DG without having to purpose-build a control network to support point installations.
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WiFi / Broadband / Public / Private The debate continues ++No one size fits all here By Kate Rowland WE’VE OFTEN HEARD THE TERM, “IF THE SHOE
A new player And there’s an interesting new player gaining ground. Historically a last-resort technology for grid operators, satellite communications are now playing with the big boys, according to two different research reports.
Case in point Rio Grande Electric Cooperative (RGEC), based in Brackettville, Texas, provides electric service to more than 10,000 metering points in Texas and New Mexico.
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fits, wear it.” Just as we all have different-sized feet, utilities of different sizes and different geographic issues need different network communications solutions to fit individual needs. For a long time, the debate—and it was a debate—between the use of WiFi or broadband and public or private communications networks seemed to be more about trying to find a one-sizefits-all solution, rather than a variety of solutions (sometimes used within the same utility) in which everyone wins. These days, that is less the case. Back in February 2001, the Utilities Telecom Council (UTC) opted to discuss the issues and dispel some myths in a document titled “The Truth about Utility and Other Critical Infrastructure Industry Telecom Capabilities and Needs.” “CIIs (critical infrastructure industries) will ultimately choose to build their own networks or buy telecom services based upon technical requirements, costs and levels of service required. CIIs have and will continue to utilize others to provide telecom services for certain aspects of their operations and smart grid deployments based upon these criteria,” the UTC paper noted.
In April of this year, the UTC released the results of a new study indicating that satellite technology is now a growing component of utility telecommunications, with the majority of utilities using satellite communications. The study, “Strategic Assessment of Satellite Usage in the Utility Industry,” found that the greatest benefit to utilities from satellite technology is that it enables ubiquitous network connectivity across the utility’s service areas. According to the research, “satellite’s portability—its ability to bring communications connectivity where needed—is a related key benefit. Around 60 percent of utilities use some form of satellite communications today. In addition, about one-fifth of utilities that are not currently using satellite communications plan to do so within the next two years.” Pike Research agrees. In a study released at the beginning of July, it said that, thanks to a number of technology advances as well as dramatic declines in the price of equipment and monthly services, “satellite communications are emerging as a viable and attractive means of connectivity for many smart grid applications, including substation automation, distribution automation, advanced metering infrastructure backhaul, remote monitoring and mobile workforce applications.” Revenue from satellite services and equipment for smart grid applications will reach $368 million by 2020, increasing from just under $67 million in 2012, the Pike Research report said. But, just as the issues that have come up around the public/private network debate have historically centered around cyber security and standards issues, questions are being asked about satellite’s latency, interoperability, security and bandwidth efficiency, according to Pike, which says that many of these concerns are in fact based on outdated perceptions.
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Remote substations across 27,000 square miles of difficult terrain where telephone coverage was sparse and cellular reception was, in many cases, nonexistent, made substation monitoring and service a job that could only be done by maintenance crews driving for long periods of time. Satellite was an obvious answer, according to Mike Wade, RGEC’s technical services manager. “We realized that the high cost of running a phone line to each of these remote substations, plus the ongoing fees for using each line, would not present an affordable solution,” Wade explained, “and because cell phones aren’t supported in most of these locations either, a satellite link was the clear choice.” The meters continually monitor electrical conditions at each substation, and communicate by satellite via highspeed Ethernet link to the software. RGEC’S technicians can instantly check the status of any substation, a procedure that used to require a long drive of several hours each way to and from the substation. And that’s for a full-time Ethernet connection by satellite between the meters in the field and the energy-management server in the head office. The result: an enterprise management system that provides real-time power monitoring and control capability across the entire distribution network. The new satellite system offers 24-hour access to real-time and logged system information for each substation, on a fast connection. The new system provides detailed power quality information, and includes an alarm feature that instantly notifies key personnel of any power outages, sags or swells. Plus, the meters automatically record consumption as interval data logs, and distribute this information as reports, both to the cooperative’s power supplier and to the local independent system operator, ERCOT. WiFi and hybrid approaches The hybrid approach still holds a great deal of sway, though. Burbank Water & Power, with a confined 17-square mile service territory, opted to use an RF mesh network, with data collectors throughout its territory to aggregate neighborhood data, to create its meter LAN. These networks then interface with a WiFi Wide Area Network (WAN), which communicates with the automated switches throughout the distribution system. The WAN then integrates with a fiberoptic ring that links all 20 of Burbank’s substations back to the head office.
Duke Energy, with a five-state, 50,000square-mile service territory, has also taken a hybrid approach to its communications network. It has set up communications nodes, which can either manage data locally or route it to another location for analysis, and these nodes act as the main contact point between the LAN and the WAN network back to the home office. A public cellular WAN sends data from the communications nodes back to the home office, and Duke plans to use a combination of RF mesh and PLC for its LAN to connect customer meters, distribution grid sensors and distribution automation equipment back to the communications node. PowerStream, in central Ontario, also chose a hybrid route for its communications system. According to Ed Chatten, PowerStream’s senior vice president of smart grid and strategic support, his utility opted for a fixed RF (radio frequency) system for its relatively dense service territory. “We were hoping for a single technology solution, because we’ve come to learn that being able to use a single interface is hugely advantaged,” he said. “We also knew that we needed high signal strength, which caused us to choose a licensed spectrum, and we needed high success rates in terms of polling frequency.” He added: “We also were looking for the opportunity to exploit the infrastructure we already had in place. PowerStream has had a SCADA system in place for at least the last 20 years, and we had an outage management sysBecause cell phones tem. We have extensive fiber deployment, which we viewed aren’t supported ... as the likely candidate to form the backbone to carry our a satellite link was data, and we were looking for an opportunity to better inthe clear choice. tegrate or best integrate what we already had, not so much in terms of new investment, but to fully integrate the AMI with our existing infrastructure and improve the usage and improve a lot of those other things—outage management, outage dispatch and service delivery to our customers.” PowerStream was also seeking a multi-utility solution for AMI, meaning an infrastructure that could support in early stages electricity, but in longer term, potentially water and gas, as well.
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SPECIAL REPORT
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» UTILITY SECURITY
Information sharing around cybersecurity practices ++Energy utility industry group grows organically By Kate Rowland THE RISK LANDSCAPE HAS EXISTED FOR ELECTRIC UTILITIES—
and has been well managed—for many, many years. It did not, as some would think by the buzz in the past few years surrounding the North American Electric Reliability Corporation (NERC) Critical Infrastructure Protection (CIP) standards, begin with NERC CIP. As Patrick Miller, president and CEO of the Energy Sector Security Consortium, Inc. (EnergySec) and principal investigator of the National Electric Sector Cybersecurity Organization (NESCO) recently told the Congressional Cybersecurity Caucus: “Make no mistake. The electric industry is not waiting for regulation to secure their environments. Successfully responding to and preparing for threats and risks and rapidly restoring the grid to a safe state of operation are
industry-wide responsibilities that are taken very seriously. This is evidenced by the fact that even though the North American power grid is by far the largest, most complex system built by humans, it is also the most reliable. Our utilities already respond to catastrophe with the skill and aplomb that only comes from years of experience and refined maturity. They do this every day and they do it very well.” He went on to note, “Cybersecurity is another important variable in their risk landscape, but it doesn’t significantly change the overall risk management approach. Like all other risk mitigation efforts, cybersecurity protections should support the mission of delivering safe, reliable power to the consumer.” It started with a simple lunch EnergySec is a community of information security, physical security, audit, disaster recovery and business continu-
“Cybersecurity protections should ity professionals from being held at the time, promoting open and honest support the mission energy industry utilities dialogue, creative ideas and collaborative solutions established more than a appealing to the “boots on the ground” security pracof delivering safe, decade ago as a group titioners within the industry. of professionals in these Now, participation in EnergySec is international, reliable power to areas in the Pacific including all regions throughout North America, Northwest. Initially, said South America, Europe, Asia and Australia. The the consumer. Stacy Bresler, vice presigroup is now (as of 2008) a United States 501(c)(3) dent of outreach and nonprofit organization, with the mission to supoperations for EnergySec and the co- port organizations within the energy sector in securing their critical technolprincipal investigator for NESCO, a ogy infrastructures. “We’re all about information-sharing around cybersecurity small group met for lunch to discuss practices,” Bresler said, “and we recognize compliance is one part of that. The the security challenges they were all more we can talk among ourselves, the more we will continue to refine our risk facing. The idea was simple: share com- management practices.” mon security practices for the purpose Today, EnergySec has more than 1,000 members from over 322 unique of learning from one another. organizations. It covers 75 percent of North American generation, 65 percent of The E-Sec NW, as it was called then, distribution and 70 percent of transmission. “We have members in every state, “started with a couple of guys and a and in Spain, Australia, Brazil, Canada and Great Britain,” Bresler said. “It is one lunch,” Bresler said, and grew from of the larger information-sharing organizations in the industry.” there. As the lunch table grew, and NESCO also evolved from this organically growing group. In 2010, the U.S. the group outgrew the ability to meet Department of Energy announced a funding opportunity to build NESCO, meant in a restaurant, an online forum and to be a public-private partnership focused on security-related information sharquarterly meetings were established. ing in the electric sector, bringing together utilities, federal agencies, regulators, In 2005, an annual summit was added researchers and academics. EnergySec was awarded partial funding over three to the mix, the only meeting of its kind years for the project.
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SPECIAL REPORT
» UTILITY SECURITY
This group, along with domestic and international experts, developers and users help to focus cybersecurity research and development priorities, to identify and disseminate effective common practices, and organize the collection, analysis and dissemination of infrastructure vulnerabilities and threats. NESCO works to identify and support efforts to enhance cybersecurity of the electric infrastructure.
continual monitoring of access. The purpose of CIP-004 is to safeguard against weaknesses within utility company practices, and its primary focus is on proper training for personnel. “With CIP-004, security training for your staff is really key,” Bresler said. “One utility Devote aware trained all its employees on how to protect their people to the own data, even at home. Once you understand systems you that, you can relate that back to work. And some are deploying. utilities have taken security and made it function like a small business, then marketed it years,” Bresler said, throughout the company.”
Protection vs. compliance As a former employee of the Western Electricity Coordinating Council (WECC), where he was part of the team of NERC CIP auditors that helped establish the regional reliability audit program, Bresler has been involved in his share of NERC CIP audits. “The WECC region did the first audit in the country of the first 13 requirements,” he said. At that time, the guidance surrounding audits wasn’t good, and so WECC did a full-day show on each CIP requirement in order to provide utilities with the additional information they needed to prepare for their scheduled NERC CIP audits. “There have been quite a bit of lessons learned over the stressing that the NERC CIP guidelines continue to evolve and be refined. Bresler also stressed that being “compliant” is different from being “protected” and both are important. Compliance, as proven by an audit, is all about documentation that supports the requirements. “When you’re doing an audit, documentation is everything,” he said. Most utilities understand the need for clear documentation and the need to manage it, and have created a NERC CIP compliance program manager position, but there are still utilities out there trying to determine the skill set necessary for that particular role.
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Two best practices I asked Bresler to define some best practices for utility cyber and physical security risk management, given his experience in the industry, as well as his experience as a result of leading and participating in more than 30 NERC CIP audits. First, he said, “devote aware people to the systems you are deploying. Log management is your bread and butter, and you need people who understand that role, and the potential cybersecurity implications, and can take the information they are reviewing and be able to act upon it.” Second, “the security team isn’t your security front line,” he said. The key mandates of CIP-004 require the staff with access to critical cyber assets to have a true understanding of security risks, in addition to understanding effective and
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NERC CIP standards still evolving “We’re seeing an ongoing maturity of NERC CIP standards,” Bresler added. “Version 4 has been released, and we’re moving into Version 5, and with each version, the requirements are getting clearer. “The maturation of standards is going to continue. I think what’s important, really, is that these standards have set us forward tremendously. I’ve seen the improvements on the front lines. I have done over 30 audits, and utilities are really trying to do the right thing. Without the NERC standards being put in place, I suspect the industry would not have improved as much as it has over the past several years.”
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Getting More Insight into Demand Response Steve Pascoe Product Marketing Manager Aclara
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Increasingly, utilities are relying on demand-
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response programs to curtail energy consumption by consumers and potentially save energy. The Federal Energy Regulatory Commission, in its 2011 Assessment of Demand Response and Advanced Metering, estimated that the total contribution by demand response to regional transmission organizations (RTOs) and independent system operator (ISO) alone grew by more than 16 percent from 2009 to 2010, reaching 31,702 megawatts. As a result, these programs lower costs to consumers and reduce peak-demand charges to utilities from power suppliers. Utilities that employ demand response programs also can delay or avoid construction of new capacity.
face penalties in the form of demand charges or fines. In fact, a number of states are adopting legislative and regulatory rules that require utilities to deploy demand response. For these reasons, demand response systems can be complex to own and operate. With a variety of potential approaches ranging from direct load control to consumer-directed efforts via smart devices in homes, the world of demand response will continue to grow in complexity and capacity.
Utilities have deployed a variety of different programs, from consumer engagement to direct load control to address their demand response requirements. These programs can be used for a variety of reasons, including peak shaving, load shifting, load-congestion management, regional supply shortages, system reliability, financial issues, and more.
Determining which demand response programs to use and when to schedule demand response events, executing events across diverse systems, and completing post-event settlement can be challenging. Utilities must have the ability to identify what level of participation is needed and which resources should be used to meet the required reduction. Sending the appropriate commands to consumers, devices and systems requires solid integration, ideally based on standards such as OpenADR and Multispeak, but also the ability to integrate to legacy systems.
Depending on the situation, a utility also may be contractually obligated to create and execute demand response events – or
In addition, it is critical to understand how well an event worked after the fact – not only for future forecasting and load-control
purposes, but also to ensure program participants are properly rewarded. What’s more, load reduction is also necessary to understand the financial impact of executing events. These preand post-analytics as well as command and control capabilities are critical to ensure that demand response programs can provide the desired results.
Swivel Chair Effect Many utilities typically manage multiple, utility-driven demand response solutions. As utilities roll out additional programs, including those that allow consumers to actively participate in managing their consumption, the complexity of handling the associated data inputs and devices will increase. Plus, new technologies such as AMI, mobile devices, loadcontrol units, home area networks (HAN) and electric-vehicle charging stations will create an avalanche of new energy-use information that must be managed, controlled and analyzed. It can be overwhelming to maximize the effectiveness of multiple demand response programs – there is just too much information involved. Plus, the number of sources and data exchange formats makes it difficult to correlate relationships and understand what’s really going on. As a result, most utilities will face a so-called swivel chair effect from administering multiple disparate systems, translating and comparing data sets, and verifying the accuracy of information. Managing multiple demand response programs can be complicated; so many operations teams employ one system at a time until the desired load threshold levels are met. In many
instances, this piecemeal approach can result inefficiency, grid instability, and increased potential for outages. Compounding the technology problem is the fact that there are fewer people with the skills required to conduct complex utility analyses. A report by KEMA indicates 46 percent of the people with the skills necessary to analyze demand-response data positions will need to be replaced by 2015 due to retirement or attrition. In addition, utilities would prefer to leverage existing investments in demand response, and not completely upgrade to new technology in order to improve results. In fact, if wholesale replacements were even considered, the cost to create the needed demand-response programs may be prohibitive.
One View of Demand Response What utilities need today is a system that manages the data from multiple systems, provides command and control across multiple platforms, and allows the utility a holistic view on how programs work together to manage load prior to and following an event. Ultimately, this system should: • Be economical to own and operate, and leverage existing demand response systems including direct load control, potentially from multiple vendors. • Provide a standards-based integration bus that allows the system to be device and network agnostic to take advantage of new solutions, developments, and programs.
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The Aclara Demand Response Management System (DRMS) captures information from inside and outside of the utility, providing valuable insight into how demand side programs and assets affect utility and grid performance.
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The Aclara DRMS represents a true, holistic view of the demand-side utility environment by integrating different types of data, such as customer, grid, economics, and weather, to allow for intelligent decision- making based on relevant utility metrics.
• Provide a single, easy-to-use dashboard that offers a unified view of the demand forecast including the timing, scope, and resources that will provide the necessary load savings and financial impact.
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• Offer unified analytics for estimating the available energy for demand response events, and evaluating actual savings once the event is executed.
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Fortunately, innovations in information analytics have made it possible to automate the process of collecting, normalizing, aggregating, and analyzing information from a broad variety of sources and formats. It is now possible to automate a large portion of day-to-day decisions through a unified operations center (UOC) and dramatically reduce the burden of manually collecting and analyzing information for demand response management. The UOC presents the results of demandresponse analyses in a configurable, self-service dashboard. Through centralized reporting, this hub enables intelligent decision making around demand response, and lets utilities control targeted energy resources and grid assets. Dispatchers working within the UOC can explore “what if” scenarios and develop a better understanding of operational issues by connecting different data sets and bridging gaps in information. In a very real sense, this unification and insight provide by the UOC creates an advanced demand response
management system that allows operators to confidently implement a broad range of strategies and load- management programs. In addition to analytical engines, a demand response system needs to provide a command and control dashboard that offers a single point of entry for execution of all programs and events across diverse networks and consumer-focused solutions. Integrating disparate networks and solutions into a single integration point is a key aspect of a total demand response solution. Real-time event feedback ensures that operations have executed the necessary demand-response programs and other operational changes, enabling operations teams to meet their demand response requirements more effectively. It provides a centralized control center for controlling systems – from devices to software engines to applications. The benefits of this advanced technology are clear. A demand response management system allows utilities to: • Reduce administrative costs and optimize demand response events while saving on technology costs by leveraging currently deployed systems. • Enable centralized analytics that help utilities to deploy diverse program strategies to meet operational needs, business goals, and regulatory requirements.
• Discover new opportunities to optimize energy, reduce costs, and quantify the impact of energy-management programs by using diverse data that includes weather, real-time pricing feeds, loads, remote generation, mapping data, baselines, grid infrastructure, and demographics. • Enhance consumer-engagement programs and involve customers in energy efficiency by delivering detailed usage information, conservation options, and education. • Provide a single point of integration to demand response programs.
Managing energy resources requires a complex mix of existing systems, third-party applications, energy-rate systems, customer programs, and hardware devices. A demand response management system can help a utilities unify the information and control into a single solution. It also allows the utility to better understand the effectiveness of programs, providing a single view into energy usage and control while at the same time improving reliability, reducing costs. Steve Pascoe has been a product marketing manager at Aclara for the last five years in the areas of demand response, AMI and meter data management. Prior to Aclara he has worked with companies providing outage management, distribution analysis, GIS and customer information system. He is an electrical engineer with over 15 years of experience in product development and marketing, technical sales, development, customer support, and training in the electrical utility markets.
A unified operations center architecture integrates data from a wide range of sources, devices, and advanced applications into a single contiguous platform. The result is measured, positive impact at the utility that spans traditional program and operations barriers. W W W. I N T E LL IG E N T U T I L I T Y.CO M
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IT INSIGHTS
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The changing face of utility IT ++Dan Hill discusses IT’s evolving role By Kate Rowland AS INFORMATION TECHNOLOGY CHANGES THE ELECTRIC
utility industry, IT itself is changing, too. Dan Hill, former senior vice president and CIO of Exelon, has seen a lot of those changes occur since he took on the role with Exelon back in May 2003. Hill was responsible for managing all aspects of information technology (IT) and telecom across the corporation. His focus: leveraging the most effective technologies, processes and resources to help enable Exelon’s business strategies and plans. As the IT committee chair for Energy Central’s Knowledge2012 Executive Utility Summit, Hill is now leading the discussion with utility IT executives across North America about those changes and other emerging issues within
the electric utility industry today. With a committee including representation from such IT leaders as Branndon Kelley from American Municipal Power, Cathy Ellis from Wabash Valley Power, KCP&L’s Chuck Tickles, Xcel Energy’s David Harkness, Katherine Kountze-Tatum from NSTAR, Lawanda Parnell from CPS Energy, Bluebonnet Electric Cooperative’s Leslie Barrios, SCANA Services’ Randal Senn, Scott Buchholz from Blackhill Corporation, Wanyonyi Kendrick from JEA, the Edison Electric Institute’s Jeanny Ho and the American Gas Association’s Jim Linn, pertinent and compelling issues have been identified for peer-to-peer, closed-to-the-media discussions during Knowledge 2012. In past years, the summit has put utility leaders in close company with fellow innovators in order to share
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ideas, develop strategies and build relationships to achieve new goals moving forward. Again this year, attendees will interact one-on-one with other participants in a relaxed, open atmosphere, gain insights from thought leaders both inside and outside the industry on emerging trends in technology, business and consumer behavior, share best practices, lessons learned and the results of pilot programs, and more. To this point, we asked Hill, in advance of the Knowledge 2012 summit, to comment on workforce and other challenges and issues, from his perspective upon retirement.
A “dream team” will always be a diverse group of technically competent IT professionals with strong business skills and absolute commitment to the success of their internal clients. Diversity of a team is critical in multiple dimensions: not only gender, race, ethnicity, etc., but also background, experience, personality and work style.
What are the overriding issues of 2012-2015 for electric utility IT executives? What is changing, and how rapidly?
Workers, their tools, and even the work environment, all of it has changed. How has this changed the way the IT group works within the utility organization?
I see three overriding issues. The first is smart grid, both the successful deployment and operaCustomers’ tionalization of the smart grid. Development of operational processes for this new technology is key, expectations and there are often organizational issues related to the coordination or integration between IT and OT of service and embedded in the challenge. The second issue is cyber security. The threat engagement are landscape continues to evolve and become ever more challenging, requiring constant attention and shaped by their appropriate adjustments to one’s defense posture. In addition, there are many legislative and political retail experiences challenges that require the attention and engagement of utility IT leaders. The third challenge is customer engagement. Customers’ expectations of service and engagement are shaped by their retail experiences and utilities must work to continuously evolve the technology that supports multiple engagement channels with customers. HILL
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What about data analytics? What part is playing in the changing role of electric utility IT? Data analytics is becoming much more important to utilities. The volume of data created by smart grid offers tremendous opportunities to mine both customer and operational-related information, often requiring sophisticated data analytic tools. Effective mining of smart grid operational data should provide enhanced preventative maintenance and storm response capabilities. Their are multiple ways to provide customers with useful data that continue to be explored as well as privacy and ownership issues to be sorted out. HILL
HILL I believe that flexible work options are something for which employees are looking and which CIOs should embrace and very thoughtfully introduce (if they haven’t already). When I was at Exelon we rolled out a structured Flexible Work Options program to IT several years ago and consistently received very positive feedback from employees and managers alike.
You mentioned cybersecurity as one of the three issues facing utilities. Can you expand upon that a bit? HILL Every utility CIO that I know (and I know many) understands the critical importance of cybersecurity to their company and the industry; they “get it.” The cyber threat landscape continues to evolve and become more challenging and CIOs and their staffs must continuously monitor the environment and adapt their defense postures accordingly. It is also important for utility CIOs to be actively engaged in the multiple legislative and political challenges involving utility cybersecurity and represent the depth of the utility industry’s response. Designed to create community and stimulate dialogue, Knowledge2012 Utility Executive Summit gathers senior leaders in customer service, operations and information technology from top investor-owned, municipally owned and cooperatively owned utilities for two days of interaction and collaboration addressing the pressing topics most important to utility executives. It will be held this year in Houston, TX, from Nov. 12-14. To find out more about Knowledge2012, or to register, go to http://bit.ly/Pe9LWJ.
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What are the workplace and personnel issues CIOs are facing now? What would be your definition of the “dream team” in IT? What is the definition of the ideal candidate?
IT only exists to enable the enterprise’s success. People do want to bring their own devices and IT organizations should devise infrastructure components that allow employees to connect with their own devices securely and safely. HILL
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IT INSIGHTS
Using analytics with demand response ++Oncor’s data analytics initiatives offer wide-scope view
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UTILITIES OFFER SO MANY PROGRAMS—INCLUDING ENERGY
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efficiency and demand response—and directing these numerous programs to the right target markets would ensure greater participation and help utilities save on marketing costs. Data analytics can be a useful tool in doing so. But it’s more than target markets that have Oncor working on data analytics initiatives within the company. In an August Intelligent Utility Realities webcast on the subject, Oncor’s Jeff Reed, senior program manager, energy efficiency, and Donny Helm, director, technology strategy and architecture, discussed their utility’s demand response and energy efficiency programs, and the ways in which data analytics assists, both within the initiatives themselves, and for the entire company. In this excerpt, Donny Helm explains the Oncor components supporting demand response analytics. “If you look at some of the components, just from how to manage the complex environments here, we have several initiatives going on within Oncor. The first one, around the AMI, is simply how to manage more than three million AMI meters with 15-minute interval data. We’re storing 25 months of 15-minute data, to look at current year and prior year. There are lots of analytics that you can do from what prior year profiles look like as compared to this year. “But then you get into how do you use the AMI information across the traditional business units around the transmission and distribution (information), so we have some specialized activities on how to integrate that along with our transmission and distribution SCADA data, weather data, and any other types of information that we’re pulling together, to not only look at how we manage and measure a demand response, but how it will affect our grid. “If you’re doing energy efficiency programs, or you’ve got electric vehicles and those other activities, how is that going to affect it, and how can we manage that, because we don’t have the full insight into all the programs that are going on all around the Oncor business. “Looking at transactional and aggregated data values—again, I talked about the 15-minute data stored for 25 months—we’ll aggregate that and probably store information up to seven to 10 years, so we can get a better profile of how our activities are improving over time, and how we can improve our overall operations with this activity going through our network from here.
“We likewise have a distribution network analysis application that’s integrated with our SCADA solution that allows us to, in more real time, understand how the grid is performing in response to a demand response or an energy efficiency program as well as our traditional outage applications. How do you combine all this information to actually provide a more reliable service while we’re performing these activities? “One of the things we’ve also learned is to move to more time-series data stores for current analytics, and we’re building the traditional relational and time-series data warehouse that gives us historical performance as well. So we’re finding out now if there are some things we need to know immediately and how to share that information. If you’re moving somewhere around 2.5 terabytes just on AMI meter data each month through our solutions, that becomes very significant when you’re talking about billions of rows of data, and how to do the calculations on the fly, and provide information back to where it’s needed. And recognizing all of this, how do we integrate it across the overall transmission/distribution asset model? And so we’ve got an aggressive program under way today for how to leverage similar types of information. It’s no longer my information because I’m in the metering group, or in the transmission group, it’s how to take that and push that analytics back to the end user, the business, so they have more information to make better decisions.” To hear the entire webcast, Demand Response and Energy Efficiency Analytics, go to http://bit.ly/OwAFKP.
O P E R AT I O N A L PERSPECTIVES “It’s down to what we call the network level, running out of a substation,” he added. “The size of those networks can run from 60 MW up to about 250 MW and there are about 70 substations in our service territory.”
Aggregating tiny loads ++NY customers control window ACs by smartphone By Phil Carson NEW YORK’S CONSOLIDATED EDISON (CON EDISON) IS LOOKING
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for the proverbial low-hanging fruit, not in a street vendor’s offering but in energy efficiency. And Con Edison wants the customer to pick and enjoy that fruit, with secondary benefits for the utility. “I firmly believe that there has to be an obvious customer benefit from which the utility gains a resulting, secondary benefit, not the reverse,” Colin Smart, section manager for commercial customer solutions in Con Edison’s energy efficiency and demand management programs, said. “Our approach is to try to take the conversation to customer empowerment and control.” That conversation, which primarily involves energy efficiency and demand response, encompasses four customer classes: commercial/industrial, small business, residential and multi-family dwellings. Because Con Edison is a transmission and distribution company, its main concerns focus on flattening the load curve and deferring capital investment on capacity-constrained circuits, Smart said.
Pull versus push Of course, there are other drivers. New York state regulators also have established an energy efficiency portfolio standard in association with the state goal of “15 by 15,” which means cutting 15 percent of the state’s carbon emissions by 2015. That requires cutting peak use as well as overall use. Smart had responsibility for commercial, residential and multi-dwelling demand response programs until last year, when he took over the utility’s efforts in the commercial/industrial energy efficiency and demand response sector. He described programs in all these areas, but the “multi-dwelling” (apartments) were the most interesting. In the residential and multidwelling sector, the “pull” rather than “push” strategy is particularly important, as price signals that might otherwise move customers to shave peak load and flatten the load profile on key circuits are “deafened” by aspects of life in New York City. High real estate values—and thus, high rents—and high salaries, relative to the cost of electricity bills, tend to undercut messages such as “saving money” on electricity bills, Smart said. “While we are in the early stages of this type of engagement, in New York we have seen real price signaltype solutions have minimal, if any impact,” he said. “I do not believe this is surprising. I have my thoughts on price elasticity and I believe the price signal conversation is best left to a machine-to-machine conversation. The economics of such a solution, in most cases, is still a ways off. For humans, talking about price signals only makes the energy subject less interesting.”
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Cool technology aggregates small savings Instead, in a relatively new program, Con Edison’s message to apartment dwellers, for instance, is that the utility can provide the tools to control their window air conditioners and thus manage electricity use and costs. This is through CoolNYC, a Con Edison program in partnership with a New York City-based energy efficiency start-up, and it involves some “cool” technology, pun intended. The CoolNYC program is interesting because it illustrates the power of aggregating small loads and the innovation that makes addressing those small loads possible. New York City has about 6.3 million window AC units, with another million expected over the next five years, according to Smart. Individually they don’t consume much. Together, however, operating at the same time, a few million of them consume about one-fifth of the city’s peak load. The customer engageTraditionally, window AC units have been hard to address. But CoolNYC ment piece is all involves a remote-controlled “modern outlet” that sits between the appliance about empowering and the wall socket, and controls the AC setting. Customers can manipulate it from the customer. It’s an app on their smartphones. Formerly customers would leave the AC on high not about what all day because of lack of control. The suggested notion is that the customer can Con Edison needs. set the temperature up, lowering the AC draw, during the day, and turn the temperature setting down before returning home from work. A smart thermostat is positioned elsewhere in the room, so it’s unaffected by the heat from the AC unit. Con Edison can control the smart thermostat as part of a demand response agreement, though customers can override that command as needed. Con Edison connects to the thermostat via broadband wireless to the customer’s Internet router. The utility is pursuing a “carrier solution,” meaning that the signal would be picked up by a major carrier’s cellular coverage rather than the router. During a demand response event, or period of high demand, Con Edison turns the unit on or off, until the ambient temperature set by the company is reached. This differs from traditional plug load management where units are turned on and off based on time, with a set temperature. Thus, customers are more comfortable during an event. So there’s a range and Con Edison uses on/ off to hit the high or low end of the range during a demand response event. At all other times the customer sets his or her own control choices or makes decisions based on his or her day and/or planned and unplanned activities, so that rooms are only cooled when they need to be cooled. Con Edison is in the process of deploying 10,000 of these modern outlets as part of the pilot.
In a house you have more choices because you have a better economy of solution, Smart pointed out. You might have several options for curtailment in a home with a 1-, 2-, maybe 3-kilowatt load. A window AC unit might represent a load of perhaps a half-kW. How will Con Edison measure results? A power chip, basically a semiconductor, measures electrical current and voltage, via a reader in the modern
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Not the fridge! Around the country, Smart added, people talk about 2,000- to 3,000-square-foot houses. In New York City, people live in 500-square-foot apartments with two big devices: a window air conditioner and a fridge. “And they won’t let me near their fridge,” Smart said, chuckling. “So we have to adapt to our unique environment.”
outlet to know exactly how the AC unit is behaving. “We’re learning a lot about how people use window air conditioners,” Smart said. “The customer engagement piece is all about empowering the customer. It’s not about what Con Edison needs. Give the customer some control and choice and make it sexy and fun. That’s what the customer is drawn to—being able to control that unit and save some money,” Smart said. “My philosophy is that we (the utility) have to look at getting secondary benefits, not the primary benefit,” he added. “Because it’s too hard to sell that to the customer. Electricity by its nature is an enablement tool. And when you take away enablement, I think it’s very difficult to really partner with them (the customers). You have to create a pull instead of pushing it.” Phil Carson is editor-in-chief of Intelligent Utility Daily. He can be reached at pcarson@intelligentutility.com
The value proposition for energy storage ++SCE and Duke Energy discuss what they’re learning RIGHT NOW, MYRIAD UTILITIES ARE TESTING THAT VALUE
Challenges inherent REES There’s a very wide range of costs out there. I think one of the challenges with looking at storage devices and evaluating them is that there are very different applications, and certain technologies are better suited to different applications. If you look at a generation resource like a combustion turbine
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proposition regarding what role energy storage could play for them and whether it’s technically and financially feasible. Two of the nation’s utilities—Southern California Edison and Duke Energy— are among those utilities implementing specific energy storage technologies for a widely sought application: the integration of renewable resources. In a July Intelligent Utility Realities webcast on the subject, Mark Irwin, director of technology advancement at Southern California Edison, and Chris Rees, strategic planning manager at Duke Energy, discussed their utilities’ projects, as well as the early lessons learned. Here, edited for length, are excerpts from their comments.
facility, you think about that at a dollars-per-kilowatt basis. It’s very easy to compare apples to apples and say that this facility costs $X per kilowatt and another facility costs $Y per kilowatt, and make that comparison. With energy storage, where you’re looking at different applications, making that comparison of apples to apples, it’s a little bit more tricky. And so, with our most recent project, for example, the project cost is $45 million for a 36 MW output project, and for us, that output was key to being able to generate capacity revenues in the ERCOT market. So we look at that on a dollars-per-kilowatt basis, 45 divided by 36 generates a cost of roughly $1,250 or $1,300 per kilowatt for that project. Now, if you’re looking at a longerduration project, you compare that on a dollars-per-kilowatt basis, that might look like several thousand dollars per kilowatt, and so you would say, “Well, clearly, that asset is cheaper.” Well, it’s cheaper for that application that you’re looking at, being a short-
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O P E R AT I O N A L PERSPECTIVES duration application, but for a longer-duration application, you might want to look at it on a dollar-per-kilowatt-hour basis instead. Again, you’d see very wide ranges on that, as well. Another thing is the life cycle each battery might have. Some batteries may have fewer cycles that you can use per the life of that system. And so, even though it may be cheaper up front, you may not be able to use that system for as long, and so the life cycle cost might be a little bit higher, as well.
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Early learnings IRWIN One of the things that continues to be a challenge is that there’s lots of work going on out there in the market so that people can now tell you how their batteries have performed under different lab testing and such, but I think at the end of the day, what we implement into our system, whether we’re a utility or a competitive business (like this Duke project is), we integrate systems. And so seeing people with proven systems that operate is not a small step. It’s not a small What are the variable step from the technology to the actual integrated system. I think that’s one important costs of maintaining thing that we’ve seen, and I’d say we’ve seen that not just necessarily at Tehachapi, but that system, and what across all our battery projects. That’s been critical. And I think the other thing for us, are the maintenance which is more Tehachapi specific, is seeing how we can have a device that integrates costs for that system both into systems operations—a lot of our purposes are system—and also has some going forward? activities in the market at the same time is not a small challenge. And I think we’ll go through that in the testing process and we’ll show that. But I think doing that on a long-term basis is difficult. Because, in our company at least, and probably in a lot of larger utilities that participate in a market, we have one group in our company that participates in the market, and we have another group in our company that participates in transmission, and we have very clear FERC regulations about communication. And so getting a device that crisscrosses those groups is something that will be interesting moving forward, and be a good challenge.
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Some of our lessons learned have been more about what do we need to do to get a storage resource like this registered in ERCOT and be able to participate in the market, what the stakeholder process in ERCOT is like in terms of being able to make some of those changes that would accommodate a storage resource being able to participate more fully. So we’re still trying to work through what some of those market rule changes are going to be that might accommodate the storage device, understanding more what the potential pilot opportunity might look like with ERCOT. So as that becomes more clearly defined, I think we’re continuing to learn and we’ll continue to establish how we want to move forward with testing the devices and how we’re going to optimize it in terms of participating in the ERCOT market. As well, a big piece of it is understanding what the application is you’re going to be using (energy storage) for. Certainly if you only need 15 minutes of storage for an application, putting in a lithium ion solution may not be the most costeffective solution for that. REES
Applications question essential IRWIN In one of our slides, we listed 13 applications or so. The comparison depends on what you’re doing. The reason I see the complexity is, it’s which application, so what device can do that, and then with the storage device, when you say we’re going to do four or five applications, you have actually multiple devices you have to compare it to. So one thing for variable resources might be a peaking plant. But it really depends. In addition to thinking through what the specific applications are and what the requirements of those applications are, what is the true life cycle cost of that going to be? What are the variable costs of maintaining that system, and what are the maintenance costs for that system going forward? How long will you need that system to last? How long do you need it to last for the application? So as we considered the project and as we looked at other potential investment opportunities for storage in other markets, we really looked at that combination of factors. At this point, each project almost has to be evaluated on the usual basis, and there’s not really a great resource out there for making a true apples-toapples comparison across multiple different projects or multiple technologies. REES
To hear the entire webcast, Putting Energy Storage into Action, go to http://bit.ly/Ne5imd.
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CUSTOMER FOCUS
Data analysis, social media and the modern consumer ++Christopher Perdue discusses the changing face of utility customer service By Kate Rowland CHRISTOPHER PERDUE, J.D. POWER AND ASSOCIATES’ DIRECTOR
of smart energy, and the chair of the customer service committee for Energy Central’s Knowledge2012 Utility Executive Summit, is no stranger to the changes occurring in electric utility customer service. As we approach the Knowledge Summit, to be held Nov. 12-14 in Houston, Texas, we asked Perdue to discuss some of the big issues facing utility customer service executives today.
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What part is data analytics playing in the changing role of electric utility customer service?
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PERDUE A key challenge in today’s smart grid environment is dealing with the large amounts of data that it generates. The utility needs to not only decide what to do with it, but also who should see it. In order to drive service excellence, delivery of the right data to the right people in near real time will be critical. As a result, I think business intelligence (BI) solutions are going to become quite important to our industry. Employees need to be able to access customer experience feedback information in an easy-todigest format through a user-friendly BI solution. The solution should organize results according to the utility’s structure, ensuring that employees receive only the information relevant to their purview of responsibility. The solution should also automatically notify your organization of customer issues as well as incidents of service excellence through an alert management system. This allows the utility to measure and track customer issues, as well as recognize employees for providing exceptional customer service.
How is social media impacting utility customer service? PERDUE Social media as a channel of communication and feedback presents a unique set of challenges and opportunities that didn’t exist even 10 years ago. Consumers are not shy when it comes to posting online comments about their service experiences, good or bad. In fact, one bad experience can be broadcast on a blog or spread across Twitter, Facebook, YouTube, and beyond. Because social media remains new to many utility executives, and because there are many ways to measure its impact, there’s still a lot of confusion about it. However, utilities that ignore it do so at their own peril.
clear and positive feedback. The reverse is also true—and dissatisfaction travels fast via the Internet. Beyond providing you with information on customer praise and complaints, listening to what consumers say in social media also helps your company better understand customer needs and motivations. What should companies watch out for with regard to their social media efforts? PERDUE Utilities must remember that they have no control over the conversations in social media. The control lies squarely with consumers. Once they engage and participate in social media, utilities need to be prepared for anything and everything. Additionally, utilities must realize that once they use social media, consumers can take the conversation in a completely different direction. Utilities should also be wary of assuming they can sway and turn online consumer opinion. Social media is not about selling, but rather engaging in two-way converUtilities must sations that sometimes leave two parties agreeing to disagree. Honesty, transparency, and a remember that they utility’s willingness to remain accountable are critical in all customer relationships, especially have no control over those built online in social media.
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What can utilities do to contribute to their success in engaging the customers with smart grid solutions?
the conversations in social media. The
PERDUE One thing utilities can do is to control lies squarely better understand the inclination of the diverse customer populations that they serve to engage with consumers. in new and different energy management behaviors. The days of a one-size-fits-all approach are over, and especially in challenging economic times, it is essential to be as efficient and effective as possible in getting the proper solutions in front of the customers most likely to desire it. Last year J.D. Power and Associates’ smart energy practice developed an ambitious behavioral segmentation program that surveyed more than 38,000 U.S. households nationwide. The study was designed to segment the electric residential customer population according to energy usage behavior patterns and arm the industry with a segmentation scheme focused on enabling targeted behavior change. The result yielded six diverse behavioral segments, based upon the types of smart energy activities and levels of control that diverse customer populations will undertake to manage their energy consumption, costs, and environmental impact. While there were a number of fascinating takeaways from the research, one of the more interesting was that by varying degrees, all segments are motivated by both cost savings and the environment. Not even the “greenest” segment selects green benefits over cost benefits. Depending on the segment targeted, smart energy messaging and service offers will emphasize either cost or environmental benefits, but not at the exclusion of the other.
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To find out more about Knowledge2012, or to register, go to http://bit.ly/Pe9LWJ.
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According to recent research conducted by J.D. Power and Associates, residential customers of electric utilities are significantly more satisfied when they see information on their utility’s social media sites. In our 2012 study, the overall customer satisfaction index is 744 (on a 1,000-point scale) among customers who recalled information on their utility’s social media site, but only 625 among all other customers. Consumer blogging is more than just cathartic for consumers—it can directly impact your utility’s image and influence customer behavior and advocacy. When your customers experience positive service, they promote you to others, providing
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CUSTOMER FOCUS
Dynamic pricing set to expand in Illinois ++Scaling up real-time pricing approved by regulators By Phil Carson TWO DYNAMIC PRICING PROGRAMS INVOLVING 22,000
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customers in Commonwealth Edison’s and Ameren Illinois’ service territories are set to expand, with the blessing of the Illinois Commerce Commission (ICC), as the two utilities roll out advanced metering infrastructure (AMI). The Ameren program has been branded as “Power Smart Pricing,” which provides day-ahead prices for residential electricity including alerts via text, voice The goal is behavior mail and email, with information also available by phone and online. The cost change. We believe is $2.25 per month. The ComEd program is Residential you have to engage Real-Time Pricing, which provides realtime hourly prices for residential electricity customers if you want and also includes alerts and phone and online price information. The cost is behavior change. 39 cents per month. On average, those 22,000 opt-in customers saved 25 percent on the electric supply portion of their bills or about 15 percent on their overall bill, said Anne Evens, CEO of CNT Energy, a nonprofit which is administering the pricing project.
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Net benefits increased as project grew The ICC, in its nod, determined that its criteria for maintaining and expanding the ComEd project had been met. Those criteria included whether the net benefits to customers exceeded the costs incurred by ComEd, an assessment of direct and indirect benefits to participating customers and society at large, and the associated cost of marketing and education. According to a third-party assessment by Navigant Consulting, Inc., “during the first three years of the program, the estimated net benefits to residential customers were negative. [A ComEd representative] testified that this was largely due to the investment needed to develop the processes and information technology systems required to commence the program, and the cost of recruiting new customers into the program.” The impact of fixed start-up costs diminished after two years, however, “when net benefits increased as more customers enrolled in the program, resulting in positive net benefits in 2010,” the report stated.
Customer savings came in two categories, according to Evens. One was a drop in overall energy use over the monthly billing cycle and the other was a drop in peak use. She also noted that changes in customer behavior persisted over the course of the fouryear study, from 2007 to 2010. “We’re developing a measure of how responsive to price customers are,” she said. “The goal is behavior change. We believe you have to engage customers if you want behavior change. We provide tips on how to do that. Some customers in the program are adopting pre-cooling strategies. Some are changing the hours in which they charge their electric vehicle. “And most are not using technology like automation,” she added. “Most get a general education on price patterns and how they can shift aspects of their lifestyle to off-peak periods.” Grid impacts to be measured The demographics of project participants so far have been skewed toward older families with 2.4 residents to a household. Typically, someone is home most of the day, thus participating households had the ability to take steps in real time without automation, such as pre-cooling a house and turning up the thermostat a few degrees during peak hours when electricity prices are high. As for the original driver of improving local, feeder-based reliability, Evens pointed out that the 22,000 customers in the Power Smart Pricing program are geographically scattered across Illinois, thus reliability impacts have to be modeled. When ComEd and Ameren Illinois begin their AMI roll outs, CNT Energy will apply the dynamic pricing program to neighborhoods in the wake of interval meter installations, which will allow direct measurement of any impacts on grid reliability. Phil Carson is editor-in-chief of Intelligent Utility Daily. He can be reached at pcarson@energycentral.com.
OUT THE DOOR the influx of real-time smart grid and smart meter data, utilities are moving toward predictive analytics that leverage real and near-real-time data. Although utilities are leveraging more real-time information, they are still in the early phases of grid optimization. In terms of best practices, look at the possibilities to leverage existing systems and data and work with vendors of your existing technologies to improve their analytics capabilities and data support. Be prepared to handle other business processes that will be affected by the need to operate and maintain a smart network and advanced analytics. Leverage newfound analytics capabilities to identify and evaluate new opportunities and pursue only those options that provide tangible value and that make economic sense based on your analysis. And be prepared to address concerns in-house staff may have about relinquishing control of the grid and turning it over to automation.
Utility analytics best practices ++Yes, these words do belong together By H. Christine Richards WHEN I MENTIONED THAT THE UTILITY ANALYTICS INSTITUTE
Grid optimization Grid optimization analytics assist with optimizing the operation of the grid in order to minimize power losses and maximize efficiency and quality. With
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was working on the Analytics Case Study and Best Practices report, some folks quipped, “Utility analytics best practices? Isn’t that an oxymoron?� Despite the naysayers, we managed to pull off a report that does indeed discuss best practices in utility analytics. Of course, most utilities are still in the early stages of advanced analytics, so the best practices today may not be best practices tomorrow. Effective practices will evolve over time as utilities gain increased confidence and capabilities with advanced analytics. The full report gets into all of the details along with multiple case studies, but here is a quick snapshot of key best practices utilities should consider for various analytics initiatives, including grid optimization, asset optimization, customer operations and customer engagement.
Asset optimization Asset optimization analytics assist with optimizing the performance and reliability of grid assets. With asset optimization, the analytics focus centers on getting the right data in place and ensuring its quality. Ongoing smart grid and grid optimization analytics efforts may move utilities into more advanced stages of the analytics, but for now, most utilities are squarely focused on asset data and its organization and accessibility. In terms of best practices, ensure that assets are categorized in a way that can be maintained effectively and that your technologies can support the level of granularity needed. Analysis must be applied to information to make it useful, but you must ensure that the quality of the information is good. You also should make plans for maintaining and analyzing new digital assets. To help gain traction, tie your asset manage-
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OUT THE DOOR ment analytics work into smart grid efforts, if possible. Change management is a particularly important component for asset optimization analytics, with buy-in from the field being paramount. Customer operations Customer operations analytics focus internally on improving the efficiency and effectiveness of a utility’s customer operations. Essentially, meter data rules, and companies are figuring out how to best manage the onslaught of meter data. However, even though data and data integration are important, customer operations efforts are also focused on the predictive and realAnalysis must be applied time uses of analytics. In terms of best practices, meter to information to make data is important, but also consider other data sources and technologies it useful, but you must that support customer operations analytics, including those in engineerensure that the quality of ing, operations, dispatch and so forth. Determine what really requires a “set the information is good. of eyes,” and use analytics to automate that analysis so employees are freed up to focus on more complex customer cases or problems. Customer satisfaction rates are important. And, although you may be early in the process, aligning the right team and dedicated resources will be important as customer operations analytics efforts expand. Customer engagement Customer engagement analytics support utility interactions with customers and improve their relationships with the utility through improved service, lower costs and better customer experiences. As with customer operations, some utilities are actually on the cusp of a significant business transformation
as they change the way they engage with customers. Data is important for customer engagement analytics, but many companies are massaging data that they already have and are drawing upon outside data resources. In terms of best practices, analytics should help determine precisely which combination of attributes is most predictive for customer behavior. In addition to internal analytics, look at technologies that empower consumers to access and use analytics the way they want, in the format they want. No more mass mailings. Determine the best possible target customers for each enrollment-based program and service offered. This will take more time and resources up front to invest in these areas, but over time, you can expect operational efficiency gains. View analytics not as a strategic goal, but rather as a useful tool for supporting strategic goals. Consider not just the cost, but the effect that such things as unwanted email can have on customer satisfaction. H. Christine Richards is a director of Energy Central’s Utility Analytics Institute. She can be reached at crichards@energycentral.com.
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+ ©© ADVERTISER INDEX
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