VOL 3, ISSUE 2 » MARCH/APRIL 2011
THE CHALLENGE OF DEMAND RESPONSE
Where smart grid meets business—and reality.
DATA VISUALIZATION
The tools we use, and why
©©
Are utilities really addressing the needs?
INTEGRATING RENEWABLES Will better forecasting aid IT and Operations? SOCIAL ELECTRICITY NETWORKS Tips for successful microgrid participation
» WWW.INTELLIGENTUTILITY.COM
URMC delivers real-world data that lets you prove compliance and improve your operations. NERC recently issued an alert for utilities to verify that their rating methodology is based on actual field conditions. The reasoning is clear: empirical information is more accurate than estimates derived from design documents. The same logic is true for your operations. Transmission costs are more accurately determined with empirical line rating information. Vegetation management is more efficient with real-world ROW data. And safety is better assured when clearances are based on “as built” evidence.
URMC: One set of data to drive all your operational and compliance needs. As one of the utility industry’s leading innovators in engineering solutions, Utility Risk Management Corporation uses LIDAR and PLS-CADD technology to collect and input data into a single platform that can produce: • Thermal line ratings across your entire system • Proof for compliance reporting and NERC audit support • Prescriptive engineering drawings fully address Survey Point Clearances • Precise coordinates for vegetation management • Documentation of work from identification through completion In fact, since September of 2010, URMC has conducted NERC Thermal Line Ratings on over 21,000 miles of transmission systems for six different utility companies. Let us show you how we can create a customized solution that brings together engineering, vegetation and asset management, transmission systems, customer support and distribution management under a single integrated platform. Find out why URMC is a trusted advisor to utilities. Call Utility Risk Management Corporation at 866-931-8762 or email us at info@utilityrisk.com
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1 Identify: Thermal Line Rating get the facts URMC’s proprietary and patented technology uses full waveform airborne LiDAR, GPS, inertial navigation, GIS, PLS-CADD and other innovative engineering technologies to map all objects within the right of way. Identifying encroachments that impact safety and reliability is crucial – items like street lights and distribution underbuild, are just as important as tree locations. Knowing the precise location of points of interest provides you with a complete inventory of your assets.
2 Analyze: Survey Point Clearance, Stem Finder and DBH Predictor map points of interest with an operational focus Only URMC can analyze the survey point clearance data finding all potential points of interest while analyzing the growth and encroachment of every crown on or near the ROW…with limb-specific, centimeter-level accuracy…in three dimensions…for every tree…and use this information to predict future work. We create a digital model of all relevant transmission assets and the related vegetation. Then, through our patented and powerful polygon-based modeling and data analytics, we can provide powerful insights and analyses.
3 Prioritize: URMC visualizes mitigation URMC’s patented, polygon-based analysis shows key attributes including encroachment type, height, location, distances, estimated mitigation costs, priority and annual growth rate. Combining this data, with PLS-CADD models, potential threats are identified before they emerge and – you can estimate costs and choose the most efficient mitigation method before ever dispatching a work crew. You can use the same datasets to budget for capital improvements, maintenance and other internal requirements, helping you meet NERC standards for a fully compliant Transmission Program. Using URMCs powerful; engineering analytics allows you to minimize expenses and maximize the value of your capital assets
4 Demonstrate: URMC drives your data to compliance URMC is able to identify individual trees, capture key asset attributes and map all data points directly to the NERC regulations. This means you spend less time documenting and integrating engineering results into your compliance plan and more time focusing on mitigation and asset management. URMC understands the regulations and invested in implements engineering solutions that drive to the regulations allowing you to demonstrate compliance with empirical data.
How do you design for future smart grids? Advanced metering infrastructure…smart grid…automation… demand response…meter data management…stimulus grants… regulatory hurdles…customer acceptance…standards…return on investment… So many decisions, so much change. You know each choice affects the other but how do you integrate the elements, manage the risk of obsolescence, and continue to deliver reliable, quality service at a reasonable cost and a favorable rate of return? Balancing technology risks with business imperatives has never been harder. KEMA leverages 80 years of utility technology knowledge and its expertise in global business consulting to help you map a strategy, design a system, test components, deploy new infrastructure and reap the rewards. With a focus on smart integration, KEMA provides solutions that help you maximize business outcomes while minimizing future technology risks. Visit: www.kema.com/SmartGrid Call: 1.781.273.5700 Join the conversation at: www.kemautilityfuture.com
CONTENTS S PECIAL REPORT DATA VISUALIZATION
28 Situational awareness requires data visualization tools
PJM Interconnection and SDG&E share their favorites
DEPARTMENTS
16
4
Drawing the line
6
Transmissions 6
Letters from readers
10 The big picture
10 Top 11 knowledge centers 12 Grid modernization monetization
FEATURES // MARCH/APRIL 2011
Demand response 2.0
16 Facing the challenges of demand response Utilities discuss the world of negawatts
Renewables integration
20 The high-wire act of integrating renewables Bonneville Power provides within-hour balancing services for wind
W WW.INTELLIGENTUTILIT Y.COM /// MARCH/APRIL 2011
Social electricity networks
2
24 Facebook for electricity?
The microgrid concept gains steam internationally and at home
10 12 34 38
34 Grid(un)lock
34 Changing the dispatch equation
38 End of the Line
38 Using analytics to do more than crunch data
42 4D
42 A comprehensive approach to deployment
44 Connections
44 Digital data downpour
48 Out the door
48 Data privacy issues
44 Vol. 3, No. 2, 2011 by Energy Central. All rights reserved. Permission to reprint or quote excerpts granted by written request only. Intelligent Utility速 is published bimonthly by Energy Central, 2821 S. Parker Road, Suite 1105, Aurora, CO 80014. Subscriptions are available by request. POSTMASTER: Send address changes to Intelligent Utility, 2821 S. Parker Road, Suite 1105, Aurora, CO 80014. Customer service: 303.782.5510. For change of address include old address as well as new address with both ZIP codes. Allow four to six weeks for change of address to become effective. Please include current mailing label when writing about your subscription.
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Let’s open the floor for discussion
W WW.INTELLIGENTUTILIT Y.COM /// MARCH/APRIL 2011
TWO YEARS AGO, THE BUZZ WAS ALL ABOUT SMART METERING AND ADVANCED
4
metering infrastructure. Last year, the discussion turned to the influx of new data, and what we were going to do with it. With this year, and this issue of the magazine, we explore, in detail, the “evolving utility” – one in which centralized generation is only one piece of a multifaceted jigsaw of technology and ideas. This month, we set out to investigate the uptake of demand response and dynamic pricing, and the challenges of integrating it. We asked utilities in those states in which demand response has been mandated to share their thoughts on the communication and IT challenges of demand response, the system effects when it kicks in, and what they’ve found to be the backend requirements necessary to target, acquire and retain customers. And they’ve stepped up to the plate to share their challenges, and the lessons they’re learning. And while we’re talking about mandates, many states have now legislated renewable portfolio standards. John R. Johnson sought out utilities for whom integrating renewable energy–whether it’s wind from large wind farms, or solar from smaller, more distributed rooftop photovoltaic installations–has become a going concern. What issues and concerns have operations and IT had to overcome to make it all part of the mix? Finally, distributed generation is taking a turn under the microscope as utilities look at entirely new constructs to better manage the electricity needs of an increasingly energy-hungry population. The concept of a “social electricity network” is taking hold in Finland, where the goal of linking smart meters and social networks is to enable people, villages, districts and communities to create microgrids much as they form groups of friends on social networking sites–an intersection of cloud computing, social networks and smart grids. We took a look at microgrid projects here in the U.S., and similar possibilities there. These and other stories in this issue of Intelligent Utility are intended to provoke discussion. I invite you to continue the conversation via e-mail with me, or with our writers, and to head to our Web site at www.intelligentutility.com, where you will find the articles online, along with a platform for online discussion.
Kate Rowland Editor-in-Chief, Intelligent Utility magazine krowland@energycentral.com
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TRANSMISSIONS
Letters from readers www.intelligentutility.com
intelligentutility.editor@energycentral.
of those signals that should carry an emergency status no matter what the cause. Most PUCs use some method of outage management performance to grade the electric utilities under their jurisdiction and report results annually, if not more often. It is one of the most, if not the most, disruptive intrusions into daily lives. To be efficient, the utility boots on the ground need feedback quickly before they roll the trucks. If it is a disconnect for nonpayment, then it needs to be tested against billing and work management systems so you do not roll the truck. If it is due to utility operation changes, then this outage needs to be tested against the work management system to verify if it is an asset that falls under that umbrella. The other important notification, but not widely used yet, is if a restoration signal has occurred, meaning: did all the assets repower up? This information has to be fed back to the boots on the ground before they leave the area so they can efficiently restore any unknown conditions caused by the operational outage while still on site. This again is integrating the work management systems with the MDM data mining operations. Once that has been completed, then you need to notify the affected customers in a timely manner so they are aware of the situation and know that you are responding to their needs. Now, all of that happens daily and at multiple locations across the utility. The challenge is that it all has to happen automatically within minutes of the outage. Most, if any, utilities are not there yet.
com. Provide your name, address and
Richard G. Pate
Vol 3, issue 1 » January/February 2011
where smart grid meets business—and reality.
meet the 2nD annual
utiliQ winners
©©
3 utilities share strategies for smart grid success
optimizing the electricity evolution: lessons learned the changing power generation equation
scaDa/sa/Da
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Outage management systems: one size does not fit all
W WW.INTELLIGENTUTILIT Y.COM /// MARCH/APRIL 2011
(Feb. 17/Intelligent Utility Insights)
6
Advancing MDM integration with OMS systems is just one of the next logical steps needed to enhance the AMI systems. It is just one of many repositories for utility data mining activities which needs to be constantly monitored and reported for operational and customer issues. A properly implemented AMI system will become the utility’s eyes in the field for providing real-time feedback on what is happening with the distribution systems and customers. There is certain information that needs to be constantly data mined real-time and given a high priority status. AMI outage notification is one
To contribute to the Transmissions department, please e-mail your submission to
daytime phone number. Letters may be edited for style and space.
EDITOR-IN-CHIEF Kate Rowland
krowland@energycentral.com 720.331.3555 SENIOR CONTRIBUTORS
Phil Carson Editor-in-chief, Intelligent Utility Daily pcarson@energycentral.com 303.228.4757 Christopher Perdue Vice President, Sierra Energy Group cperdue@energycentral.com 310.471.7396 FEATURE WRITERS
Mike Breslin, John Johnson, Phil Johnson, Laurel Lundstrom, Elizabeth McGowan, Cate Meredith, J. Ian Tennant COPY EDITOR: Martha Collins VICE PRESIDENT, SALES/MARKETING SERVICES: Jennifer LaFlam
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THE BIG PICTURE
Top 11 knowledge centers ++A shifting focus By Phil Carson
W WW.INTELLIGENTUTILIT Y.COM /// MARCH/APRIL 2011
BY MANY ACCOUNTS, THE PAST YEAR HAS BEEN “THE YEAR
10
of the consumer” in the power industry. That distinction, of course, is a double-edged sword. The consumer – dare I mention “the Bakersfield effect”? – came roaring onto the national scene as pockets of discontent over smart meters made themselves known. In several high-profile regulatory cases, state utility commissions slowed the trajectory of investor-owned utilities, insisting on a balance of financial risk between shareholder and consumer and tangible benefits for the latter. Consumers themselves came under the microscope as a subject of study. What do we know about this strange animal and where does the industry need more research to better understand it? These developments demanded that knowledge centers focus on consumers and that their concerns be included in this year’s list of the top 11 knowledge centers for smart grid. The same goes for electric vehicles and storage. Electric vehicles of various stripes actually hit the market in the past few months and nearly everyone, it seems, needs information about them—particularly utilities seeking to ensure that the grid can accommodate them.
With many states on an uphill march to meet renewable energy portfolio standards or self-imposed goals, and federal stimulus dollars directed at various efforts around energy storage, that topic also gained a much higher profile than ever before. Thus the following list has shifted from last year. In an industry with a deep bench of organizations that qualify as knowledge centers, this year’s list reflects emerging hot topics. Knowledge needs are changing Of course, the nature of one’s query is what makes a topic hot. Widespread organic interest certainly makes In an industry consumers, electric vehicles with a deep bench... and storage top of mind. this year’s list But any given knowledge cenreflects emerging ter may be critical to the seeker hot topics. based on his or her needs. If you’re a utility, your staff’s needs for knowledge range across the entire
“
”
Mercurial smart grid I haven’t seen the smart grid compared to a drop of mercury, so I’ll coin that analogy here. It has been broadly defined as the addition of digital
technology, especially computing and communications, to make the grid more reliable and resilient, while creating a two-way flow of information down to the meter and, possibly, beyond. But as soon as you put your finger on it, it tends to re-form in a new shape. Defining it can be frustrating. That point carries over to the knowledge centers serving the industry and the public. Organizations listed here either focus squarely on the topic as defined earlier or they are organizations much broader in scope that happen to include smart grid technology, policy or practices. No one in the electric utility industry can escape the influence of major organizations such as the Edison Electric Institute and the Institute of Electrical and Electronics Engineers, or the steady output of fundamental research by the Electric Power Research Institute, which has become a staple for grid modernization.
TOP 11 KNOWLEDGE CENTERS EVENTS
MEMBERS
PRESS RELEASES
RESEARCH ACTIVITY
Smart Grid Consumer Collaborative
••
•••••
••
•••••
National Association of State Utility Consumer Advocates
••
••
••
•••••
Electric Drive Transportation Association
••
•••••
•••••
••
Electric Power Research Institute
••
••••
•••••
•••••
IEEE
•••••
•••••
•
•••••
Edison Electric Institute
•••••
•••••
•••
•••••
••
•••••
••••
•••••
GridWise Alliance
•••••
•
••••
••••
ZigBee Alliance
••
•••••
••
•
Electricity Storage Association
••
•••••
••
•••
Demand Response Coordinating Committee
••
•••
••
•••
United Telecom Council
Scaling system: ••••• = excellent
••• = average
• = not available
Source: Energy Central
Weights and measures This list, therefore, is not intended as a linear ranking. Instead, we provide an indication of each group’s size and output by using a handful of criteria so readers can get a quick sense of the dynamics and influence of the organization. You can weigh the apples and oranges. And with such a deep bench of knowledge resources available, providing 11 of them is an admittedly arbitrary number by which to make a cutoff. A word on the criteria and their role in this list: Quantity and quality may be the twin pillars of influence, but weighing them is art, not science. An organization with a small membership of heavy hitters may produce and disseminate more knowledge than a group with a seemingly endless roster. One influential report can produce more knowledge than a flurry of white papers. Thus we’ve applied and weighed objective criteria to develop this list of knowledge centers. But behind the numbers, as always, lies a more complex picture. Phil Carson is editor-in-chief of Intelligent Utility Daily.
W W W. I N T E LL IG E N T U T I L I T Y.CO M
spectrum of topics. If you are a newly minted state regulator, you’re standing right between those two parties, with a need to assess the pressures on utilities and the rights of consumers. If you’re that elusive consumer (let’s face it, we all are), you may be hungry to understand those smart meter-related headlines or presidential speeches on energy, and what it all means to you and your pocketbook. If you seek knowledge about consumer issues, you’d do well to consult the Smart Grid Consumer Collaborative (SGCC) or the National Association of State Utility Consumer Advocates (NASUCA). Early this year, the SGCC released the “2011 State of the Consumer Report,” which synthesized myriad, disparate studies about consumer attitudes and behaviors, while identifying significant gaps in knowledge. Last year, NASUCA released the influential white paper “The Need for Essential Consumer Protections: Smart Metering Proposals and the Move to Time-Based Pricing,” which coincided with NASUCA taking a bigger role in industry discussions in Washington and many states. Those cases in which an organization issues a report that crystallizes the discussion of the moment and advances the conversation are somewhat rare. More often, an organization’s consistent efforts continued to inform an ongoing discussion. Thus if electric vehicles are on your mind, the Electric Drive Transportation Association will be on your short list. Punch “energy storage” into a search engine and it would be hard to miss the Electricity Storage Association. If your agenda includes home area networks, you’re likely to find the ZigBee Alliance or its “coopetition” useful.
11
THE BIG PICTURE
Grid modernization monetization ++Long-term ratepayer obligation W WW.INTELLIGENTUTILIT Y.COM /// MARCH/APRIL 2011
charge bonds may provide answers
12
By Joseph S. Fichera and Michael E. Ebert MODERNIZATION OF THE NORTH AMERICAN ELECTRIC
power grids is crucial to grid security, reliability and efficiency. Doing so will provide economic, competitive and environmental benefits for the United States. However, it is also expensive. Methods must be found to easily and economically fund the investment. Fortunately, there is a time-tested, efficient way to raise funds that has survived the recent credit crisis. It is favored by respected credit agencies, investors and others as a powerful tool to lower electricity costs to consumers. In the November/December 2010 issue of Intelligent Utility, we made the basic arguments for long-term Ratepayer Obligation Charge bonds (ROCs) and thus will not repeat the fundamentals. This article covers specific measures necessary to develop and bring to market well-structured ROCs for grid modernization.
Lowest-cost financing method Utilizing ROCs for grid modernization offers many advantages over more traditional cost-recovery financing options and more closely aligns with the longer-term benefits. It’s quicker and cheaper to raise small or large amounts of funds from the capital markets. ROC bonds are a lowest-cost financing method because, properly structured, they present the least risk to investors and more affordable monthly costs to ratepayers. Nationally recognized credit rating agencies give them top (AAA) ratings. They are purchased by investors in the public bond markets and thus result in the lowest possible cost to ratepayers. Solely applying a monthly surcharge to the consumer utility bill provides a source of capital that merely trickles in. Public utilities benefit because the sale of ROCs results in quick and inexpensive capital almost immediately without using the balance sheet or credit of the utility. Consumers also benefit in the end because the costs of large, capitalintensive grid modernization projects are spread over many years. Our emphasis on properly and well-structured is intended. In most states and their public service commissions (PSCs), with rapid turnover of commissioners and thin expert staff, coupled with the desire for most investor-owned utilities to invest only in assets that earn quick returns for shareholders, there is comparatively little or no experience with ROCs. A review of the 50 states indicates that only 15 have experience in the use of utility tariff bonds; we know of no instance in which securitization has been chosen to finance smart grid. If ROC bonds potentially have the benefits that the rating agencies and many other independent observers claim, why is this so? Mostly, it is simply a lack of specific state statutes that provide the legal authorities for PSCs to have the option
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THE BIG PICTURE
of ROC financing, and expert knowledge of how to do this so that a PSC does not rely solely on utilities or Wall Street.
utility and/or any successor entity. For example, self-generation cannot dilute the charge.
Specific state authority needed PSC actions The first and most important step in well-structured ROCs for grid modernization is for states to enact specific authorities for their PSCs, which provide the required in statutes procedures for a transparent public process to determine whether securitization To be most effective, state statutes provides the least costs. require certain actions from the PSC, This state statutory authority establishes the legal framework for creation of a including certifying that ROC financnew type of intangible property right and grants the PSC authority to issue an ing is the “least cost alternative” and irrevocable regulatory guarantee to investors by ensuring timely repayment via achieves “lowest cost of funds.” This automatic true-up/down adjustment processes. Like any other utility property, means an important degree of PSC this new property can be pledged as collateral. The property created is the right involvement and oversight facilitated to bill and collect a specific charge on some or all retail electricity purchased by by expert financial advisors after the consumers in a given distribution service territory. final order through actual A well-structured statute also authorizes the utility ROC bond offerings. It’s quicker and to sell this property to a bankruptcy‑remote special Special care has to be purpose entity (SPE), authorizes the SPE to issue debt taken to ensure complicheaper to raise instruments, and requires the utility to use net proance with federal income ceeds from the ROC bond sale for specified purposes. tax rules. To avoid besmall or large Bankruptcy-remote means that the assets of the SPE ing taxed, securitization are separate from the utility in case the utility has regimes must meet the amounts of credit problems. new six-part test found in Pursuant to a special financing order, a charge is Federal Internal Revenue funds from the imposed on each customer, which is collected by the Service (IRS) Revenue utility, and given to the SPE. The collection solely Procedure 2005-62, capital markets. supports the payment of the ROC bonds; expenses 2005-37 IRB 507—colcannot be used for any other purpose. lectively, the “Revenue Given the historical regulatory uncertainty regarding changes to laws and Procedure”—issued September 12, regulations, the statute must include a state pledge of nonimpairment; the stat2005. The Revenue Procedure has the ute must stipulate that if a PSC financing order is issued for a specific project, it effect of opening up securitization to must be final and irrevocable, and “non-bypassable,” meaning that, irrespective grid modernization and a range of of future changes in the regulatory environment or the business organization other rate-reduction purposes, includof the utility, the charge must continue to be collected from customers by the ing grid modernization.
W WW.INTELLIGENTUTILIT Y.COM /// MARCH/APRIL 2011
“
14
”
How an ROC bond is structured and sold could result in it being classified solely as an asset-backed security (ABS) and sold primarily to ABS investors who demand higher yields to invest. This must be avoided. If ROC bonds are deemed to be ABS, the bonds would need to follow the SEC Regulation AB rules, which govern the issuance and sale of ABS securities, and investors might treat them as riskier than they are. Thinking like Amazon Thinking outside the box, securitization could balance the current gross imbalance between utility and customer benefits. Tangible smart grid consumer benefits occur more quickly. The utility establishes an online “Amazon-esque” portal, including consumer education and ratings, where energy modernization goods and services are purchased in a com-
petitive market and with charges sent to the utility. The set aside has transparent and separate accounting, but the “grid modernization” charge and the itemized “home energy modernization” charge that appear on the customer’s bill is paid to the utility, with the two charges immediately transferred to the SPE. Issues of creditworthiness and equity in customer access to the set aside are not difficult to establish. Securitization pools buying power while providing default protection. Sale of a home or building, technological obsolescence, upgrading, etc., are facilitated by securitization’s automatic true-up/true-down attributes. A defining and common feature of securitization is that it is made possible by state legislation that not only specifically enables it, but that establishes a legal framework for the creation of a new type of intangible property right under law. ROC bonds, as securitized debt instruments, do not burden the assets or revenues of the sponsoring utility. ROC securitized financing is unlike any of the utility’s other financial obligations: it is effectively off-balance-sheet for credit purposes with no recourse to the utility, which is, thus, fully protected. Shareholders get an improved balance sheet and more headroom in rates for other financings that may earn an equity return. This means the utility can finance grid modernization with nearly 100 percent debt rather than its normal capital mix of about 50 percent debt and 50 percent equity, without any impairment of its credit structure. Joseph S. Fichera is CEO and senior managing director of Saber Partners LLC. Michael E. Ebert is a principal research associate at the Center for Infrastructure Protection & Homeland Security at George Mason University.
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15
Facing the challenges of demand response
16
By Kate Rowland DEMAND RESPONSE—MOST SIMPLY DEFINED AS
the decision not to consume energy in response to price and other factors—holds enormous potential to balance the power system, integrate variable-output renewable resources into the grid and increase the efficiency of the electric utility industry. The U.S. Congress has directed development of demand response as a national policy, but take-up has been limited to date in some states, and by some utilities, in part due to current regulatory constructs. In its “2010 Assessment of Demand Response and Advanced Metering” staff report, released in February, the Federal Energy Regulatory Commission (FERC) gave
OPPD adds residential curtailment to C&I In 2009, Nebraska utilities budgeted $12 million to promote demand-side management within the state. About $6 million of that was for energy efficiency (both gas and electric), with the other half designated for load management. The Omaha Public Power District (OPPD), the twelfth-largest
ILLUSTRATION BY COLIN WALSH
W WW.INTELLIGENTUTILIT Y.COM /// MARCH/APRIL 2011
++Utilities discuss the world of negawatts
demand response a slightly new definition, redefining it as “Changes in electric use by demand-side resources from their normal consumption patterns in response to changes in the price of electricity, or to incentive payments designed to induce lower electricity use at times of high wholesale market prices or when system reliability is jeopardized.” Program classifications have morphed and diversified over the years, too. This year’s FERC report lists 14 different types of programs, from direct load control (one of the most common demand response programs offered, as far back as 1968) and interruptible load to demand bidding and buyback, timeof-use and critical peak pricing, regulation service and system peak response transmission tariff. Program confusion can occur, making decision-making, especially in early planning and implementation of new demand response options, even more difficult. “The rapid evolution of demand response programs, rules and names increases confusion among respondents and staff alike,” the FERC report notes.
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DEMAND RESPONSE 2.0
public power utility in the United States in terms of customers (more than 340,000 in all or parts of 13 counties in the east and southeast portions of the state), now offers several interruptible riders, which pay its customers for agreeing to provide load curtailments or activate on-site generation for a limited number of times per Customer educayear. These riders differ, depending upon tion, clear eligibility whether the curtailment event is mandarequirements and tory or voluntary, and the minimum load balanced incentives drop ranges from 100 kW to 500 kW. assist customers in Denise Kuehn, OPPD’s manager selecting the most of demand side and sustainable manageappropriate program. ment, discussed some of the operational issues and challenges of implementing demand response initiatives within the utility. “When demand response is based on a direct signal, we have better control of the load changes,” she explained. “We have programs where we request that the customer curtail (energy usage), and the timing fluctuates, which makes it tougher.” Commercial and industrial curtailment has been in the utility’s mix for quite some time, Kuehn said. On the residential side, OPPD did some early demand response pilots in the 1990s, which got mixed reviews and didn’t work optimally. Over the past two summers, the utility has piloted new residential demand response programs with much more success, and is now launching full deployment of the program. Pilots are intended to serve as learning experiences, both for the utility and for its customers, and OPPD definitely learned some technology lessons along the way.
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Technology as a detractor When asked about the IT and communication challenges of integrating demand response within the utility, Kuehn pointed to the coordination of different technologies as a definite challenge. “Technology is required to send out the signal to turn off devices, and to verify and track results. Coordinating this with different technologies can be difficult and time-consuming,” she said. In the residential pilots, as an example, the challenges became obvious fairly quickly. “We started with condensers,
and found there was too great a temperature rise—our goal was a temperature rise of less than 4 degrees. So, we went to thermostats, and spent months trying to pull the data out of them. We’re going back to condensers,” Kuehn said. SCE an old hand at DR In California, the state’s three investor-owned utilities were preparing to file their three-year demand response funding applications as this issue went to press, according to Mark Martinez, Southern California Edison’s manager of business strategy and planning. One of the nation’s largest investorowned utilities, Southern California Edison (SCE) delivers power to nearly 14 million people in 180 cities across central, coastal and southern California, across 50,000 square miles of service territory. SCE has been designing, developing and deploying reliability and price-responsive-based demand response retail programs for more than a quarter of a century. These programs include interruptible tariffs, direct load control, capacity-based retail products and dynamic dispatchable pricing. SCE operates one of the largest comprehensive demand response portfolios in the country, with more than 1,600 MW of available peak reduction capacity from all retail customer classes, available for reliable dispatch at times of emergency and during critical peak periods. SCE has experienced substantial growth in its demand response portfolio since the summer of 2006, when California experienced a “one in 50” summer heat wave. In 2008, the same year that SCE increased its demand response capabilities across all customer sectors by almost 280 MW, there were again multiple price-responsive critical periods throughout the summer, as well as a transmission emergency event in November that required immediate load reductions. The utility believes strongly in customer choice and education in order to increase demand response efficiencies. In its comments to FERC concerning the draft National Action Plan on Demand Response, which saw early circulation in 2009, SCE noted: “To achieve effective DR, as many customers as possible should be exposed to DR options and be encouraged to participate in these programs.” Demand response programs, the utility said, should offer customer choice and be flexible and adaptable in order to encourage customer participation, so that customers can select the programs that best suit their particular situation. “Customer education, clear eligibility
requirements and balanced incentives assist customers in selecting the most appropriate program,” SCE told FERC. And there are other challenges too, according to the IOU, the largest being the effort needed to bring priceresponsive demand response to the mainstream customers. Dynamic pricing and frequent dispatching of customer-approved load reductions has not been readily adopted by customers, even those equipped with advanced metering and enabling technology. Overcoming these hurdles, SCE says, will involve education and awareness, new ideas, additional program design, system improvements and enabling technologies to facilitate customer participation. A marketing approach that combines compatible energy efficiency activities will assist, as well. RTOs have a role, as well Regional transmission operator PJM Interconnection LLC has also long been active in the demand response market. Andrew Ott, PJM’s senior vice president, markets, shared
the clear benefits of economic and capacity-based demand response to both regional grid operation and whole market operation. “The PJM capacity market has attracted nearly 13,000 MW of demand resources offered; over 9,200 MW have cleared,” he said. “There are two types of demand response: energy-based (responsive to price or environmental instruction) and capacity-based (emergency),” Ott added. “When demand response offers or responds, both types are beneficial. Having demand response come in offers more flexibility and diversity of supply. It’s beneficial from both operational and market-efficiency points of view.” Ott says that more automation in demand response means it will become more predictable as an operational tool for load balancing. As a large control area, load is balanced using economic dispatch (every five minutes), synchronized reserve (16 percent of which, for PJM, is provided by demand response), and frequency control (regulation every four seconds). Without automation, there is a gap, Ott says, in the wholesale-retail interface. “Smart grid is enabling those kinds of gaps to be jumped, but retail-wholesale coordination is still a wish.”
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Smart Grid – From Concept Through Completion
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++Bonneville Power provides within-hour balancing services for wind By John R. Johnson AS MORE EMPHASIS IS PUT ON GOING GREEN
and weaning the U.S. off expensive and dirty fossil fuels, utilities continually find themselves at the focal point of green energy initiatives. Renewable energy from the sun, wind and other sources is moving onto the grid at a rapid pace, often in response to aggressive renewable portfolio standards (RPSs) adopted at the state level. In Oregon, the latest RPS requires that the largest utilities in the state provide 25 percent of their retail sales of electricity from clean and renewable energy sourc-
Explosive increase in wind At Portland, Ore.-based Bonneville Power Administration (BPA), wind power has increased from 500 MW in 2005 to 3,450 MW of power last year. “It’s been explosive growth and heavily driven by renewable portfolio standards in Oregon, Washington and California,” said Elliot Mainzer, BPA’s vice president of corporate strategy. Mainzer said BPA’s current projections call for another doubling in wind power over the next two to three years. “It’s really just massive growth,” he said. “You kind of get the feeling that policy is passed sometimes without really understanding what the implications are.” The implications are time-consuming and costly to utilities that must make adjustments to IT and opera-
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The high-wire act of integrating renewables
es by 2025. California has one of the toughest RPSs in the nation, calling for one-third of the power produced by utilities to be from renewable sources by 2030. So although the rush to renewables ensures a cleaner environment and one that doesn’t rely as much on volatile fossil fuels, the green energy movement also puts tremendous pressure on utilities to integrate those renewables into the traditional electricity mix. There are numerous complicated issues to tackle, such as how to balance those disruptive power supplies, and the cost and load factors involved.
sure the amount of wind energy scheduled is delivered to the customer. Of course, that’s easier said than done, so BPA has begun to place a large emphasis on wind forecasting in order to gain better visibility into renewable generation. “Obviously, if we knew what the wind was going to do any particular hour, it would really impact the amount of reserve capacity that we carry on the system,” said Mainzer. “But, of course, we don’t have perfect information.”
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tions procedures that have been in place for years. At BPA, about 85 percent of the 3,450 MW of wind that is interconnected to its transmission system is moved across the grid and sold to other utilities in the Northwest. BPA’s primary role is to provide within-hour balancing services for wind projects. In order to do so, BPA adjusts the output of its hydro generation system up and down to account for varying renewable generation. As a result, it must carry significant reserves in order to make
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Better forecasting = better visibility Better forecasting will help ease the visibility issue, especially considering that much of the wind power is harvested in one region—the heart of Columbia River plateau. Wind comes surging in from the coast and through the Columbia River gorge, hitting many turbines simultaneously. Likewise, wind production often drops off dramatically as wind departs the area. The wide variability is difficult to manage and requires a significant amount of reserve capacity on BPA’s hydro system. In order to achieve better visibility, BPA last year installed 14 wind anemometers throughout the Pacific Northwest to help track wind patterns and get a better view into wind history. The data provided about wind patterns 100 feet in the air aids the forecasting programs. Essentially, better forecasting allows BPA to hold less water in reserve behind the dams, saving ratepayers money and also providing a better option for the environment. Mainzer said that BPA is looking at ways to integrate the data collected from wind forecasting into its planning models and dispatch models and to develop software programs for its system operators so they can get a clearer picture of what they believe their wind levels will look like for the next hour. “So there is a lot of integration into your core system operations software from that forecasting that we are beginning to look at,” he said.
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Intra-hour scheduling challenges Another IT-intensive challenge associated with integrating renewables is the use of shorter transmission scheduling intervals, or intra-hour scheduling. Typically, electricity is scheduled on an hourly basis, which means utilities must carry reserves across the entire hour in order to make sure enough energy is provided during that one-hour window. Dramatic shifts in wind production, for example, require storing a significant amount of reserve capability to absorb those fluctuations. To lessen the impact, BPA is considering moving from hourly scheduling to 30-minute scheduling, which would ease the problem but also create many complicated changes to BPA’s scheduling systems. “There is a lot of IT involved in those traditional scheduling systems,” said Mainzer, “like scheduling the tagging of the energy between the balancing authorities. Eventually you start to get close to your core operational software—your AGC systems and your other core operation systems.” There have even been discussions around the country about requiring transmission providers to actually move
from 30-minute scheduling to 15-minute intervals, which would result in even greater infrastructure change. “We’ve just now taken the hood off the engine to try and figure out how dramatic a change that would be and how much additional infrastructure would be needed in terms of automation, scheduling and tagging,” said Mainzer. In addition, automatic generation control (AGC) systems, billing and metering would all be impacted by the shorter scheduling system. Data harvesting to assist in forecasting Mainzer says the next challenge for BPA is to harvest all of the additional data it is gathering and to put it to use in building its own internal forecasting system. That forecasting would then be channeled directly into the heart of BPA’s operation. Mainzer said that most wind generators—whether they are owned by independent power producers or utilities—forecast and schedule their own wind across BPA’s system. The resulting problem is that BPA is never quite sure whether what they are scheduling will match what they are forecasting. Improved supply chain visibility is the buzzword in many industries today, and it’s no different in this case. “We don’t have great visibility into their forecasts, which creates additional uncertainties for our operators,” he said. “So we’re talking about the possibility of all working off the same forecasting system and the same scheduling system so we won’t have to guess at what they schedule and have to carry additional reserves to deal with that volatility. “It’s about bringing the forecasting into the heart of our operations and then developing a centralized forecasting system that people can use for better schedThe green energy movement uling,” said Mainzer. “That is really the puts tremendous pressure next frontier.” As the deadlines on utilities to integrate for renewable portfolio standards draw those renewables into the closer, Mainzer believes it’s crucial for traditional electricity mix. regulators, utilities and state and federal agencies to work closely together to ensure that environmental goals can be met without causing too much upheaval to existing utility systems. “We’re experiencing massive growth,” he said.“Increasingly as we scale up, we’ll need much greater collaboration and dialogue between policymakers and the utility community about how to implement a lot of these programs.”
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John R. Johnson is a Boston-based freelance writer specializing in alternative energy and technology topics.
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soc ial
electricity networks
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Facebook for electricity? ++The microgrid concept gains steam internationally and at home By Kate Rowland FACEBOOK MAY HAVE TURNED THE SOCIAL
media world on its ear, but there’s a social electricity networking concept being floated in Finland that is gaining steam across the world, as well. The idea, essentially, is the creation of microgrids giving communities and individuals more control over their power consumption. But it’s more than that: once up and running, it will also allow individuals within commu-
Smart meters + dynamic pricing = opportunity Finland has required, by law, that all homes have smart meters by 2013. More than half of its 5.3 million citizens already have them. There’s clear thought behind the smart grid push: Finland’s per capita use of electricity is almost double the EU-27 average, and the country is moving to increase energy efficiency across the board. Its National Energy Efficiency Action Plan 2008-2010 and its Longterm Climate and Energy Strategy (first submitted in 2008, and updated in 2010) both support the increase in energy efficiency and promote the increase in renewable energy sources such as wind power. “According to the Climate and Energy Strategy, wind power production will rise to 6 TWh by 2010,” noted a June 2010 document spelling out Finland’s national action plan for promoting energy from renewable sources. “In order to promote wind power, there are plans to introduce a market-based feed-in tariff scheme in 2011, to be funded from
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nities to share power with their neighbors, and to do so easily, online.
Island wind generates power and income A similar concept is already taking shape on the island of Samso, Denmark, where a cooperative approach to wind power, both onshore and off, has allowed the island’s residents to produce more energy than they consume, providing an annual income to the wind turbines’ resident shareholders. In fact, wind power is now responsible for 100 percent of the island’s electricity needs. According to Scientific American correspondent David Biello, who visited the island, microturbines and rooftop solar panels abound in the island’s villages. As well, he reported, Samso is testing whether converting electricity generated at night by the wind turbines might be efficiently converted to hydrogen via electrolysis and then converted back into electricity for sale during the day, when rates are higher. Distributed energy management Microgrids and intentional islanding are also being tested within pilot projects closer to home. In a small desert community east of the city, San Diego Gas & Electric’s (SDG&E’s) Borrego Springs microgrid demonstration project has been
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the State budget. The feed-in tariff will be the equivalent to the difference between the target price and the market price of electricity.” As well, Finland plans to increase the flexibility of demand on its electricity market by introducing hourly metering, according to its national renewables action plan. “Hourly metering makes it possible to apply electricity tariffs which vary hour by hour. This provides incentives to use wood as a source of extra heating when the market price for electricity is high.” Support for solar heating and solar power generation systems is also provided via an energy subsidy for buildings, and a tax offset for one-family houses. The social electricity networking project—or “intended” islanding—fits in well with the country’s goals. According to Seppo Yrjola, senior principal innovator at Nokia Siemens Networks, who first discussed the idea at the Nordic Green II conference in April 2010, hosted by SRI International, cloud computing, social networks and smart grids will come together in the next few years, allowing villages, districts and communities to form their own microgrids and negotiate for less-expensive power.
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SOCIAL ELECTRICITY NETWORKS
designed to both enable more active participation by cusSome argue that the growth of microgrids at industrial tomers as a supply resource (in accommodating various sites and on college campuses—typically a playground for generation and storage configurations), and to reduce the new ideas—may help to create the groundswell needed to tip peak load of feeders and enhance system reliability. the balance. “Business and academic campuses are excellent Borrego Springs already has a high concentration of cus- candidates for microgrid installations,” Christine Hertzog, tomer-owned solar generation. SDG&E’s pilot program is a managing director of the Smart Grid Library, recently wrote. three-year program of sensors, communications and control “Microgrids can serve as living laboratories for the proliferaequipment, designed to incorporate these hometion of technologies ranging and business-based solar power generators, from generation (especially It will allow individuals coordinate new peak load management technolrenewables), transmission, ogy, leverage smart meters and remotely control distribution, building energy within communities to distributed generation storage devices to allow management and data center access to electricity in emergencies—in essence, energy efficiency. share power with their the ability to “ride through” an outage. Batteries “College campuses also will also be installed on homes with solar panels, have the added benefits of neighbors, and do so to aid in filling the gaps in power supplied from aligning microgrid projects the panels during the day. These smaller batterwith academic departments easily, online. ies could also feed emergency supply back to the ranging from electrical, grid for short periods when needed. mechanical, chemical and “In addition to microgrid technology, the Borrego Springs civil engineering to information and communications techproject will teach us about numerous technologies, from nologies and public policy, economics and behavioral scibattery storage to fuel cells, to balancing load on a circuit- ence applications,” she added. by-circuit basis. This technology has the potential to lead to Santa Clara University, in Santa Clara, California, is increased reliability,” said Lee Krevat, SDG&E’s director of doing just that with its “smart microgrid” project. Scheduled smart grid. to be finished by the end of this year, the university’s “To me, microgrid is the culmination of all the pieces microgrid would be able to remain operational in the event of a together—being able to manage everything to create your major power outage, and generate enough electricity to own balance,” he added. power not only the campus, but nearby homes and busi“That’s what our customers want. They want more energy nesses, as well. When completed, the microgrid is estimated independence, and energy security,” said Caroline Winn, to reduce energy consumption by 50 percent and save the SDG&E’s vice president of customer services. university about 20 percent in energy costs. “The university’s current system allows us to only control Compelling, but lacking policy support HVAC systems and temperatures,” Joe Sugg, assistant vice According to Pike Research, few fully commercialized state- president of university operations at SCU, said in announcof-the-art microgrids with significant generation capac- ing the project. “With a smart ity are actually up and running in the United States. In part, microgrid, we can instantly turn the research firm said, this can be blamed on the lack of a off lights and equipment in any national carbon policy. “The failures at Copenhagen in 2009 building, ration electricity during and in the U.S. Congress in 2010 have slowed down the rush prolonged outages, and all from to implement energy projects that cut carbon emissions, your desk.” including microgrids that aggregate renewable distributed energy generation,” the firm concluded. “The regulatory support for microgrid developments has yet to coalesce in the U.S. and throughout global markets, although some legislative activity is occurring with regards to military applications—one of the most promising near-term market opportunities—and within engineering circles at the Institute of Electrical and Electronics Engineers,” Pike Research noted.
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» DATA VISUALIZATION
Situational awareness requires data visualization tools ++PJM Interconnection and SDG&E share their favorites By Kate Rowland EVERYTHING COMES DOWN TO DATA: ITS AVAILABILITY, ITS
reliability, and the ability to be able to monitor and control everything from electricity flow and metering data to utility enterprise management information, costs, budgets and rates. And now, there are computerized dashboards for all of it. From distribution and transmission operation control rooms to customer billing systems and more, data flow from numerous sources is optimized via software solutions to provide the information necessary to operate today’s up-to-the-moment utility functions. Add geographic information system (GIS), supervisory control and data acquisition (SCADA) and phasor measurement units (PMUs) to Google Earth, WeatherBug and more, and the internal and external data available to electric utilities is diverse. Utilities are leveraging these new and not-so-new tools to assist them in visualizing the big picture.
SDG&E adds anemometers On the other side of the country, San PJM uses PMUs for situational status Data visualization is playing an ever-growing role in a utility’s day-to-day and Diego Gas & Electric (SDG&E) is findhour-to-hour functions. For PJM Interconnection LLC, visualization tools play ing visualization tools extremely iman important part in the role it plays as a regional transmission organization portant to its operations, too. A subsidiary of Sempra Energy, (RTO) that is responsible for managing the high-voltSDG&E is a regulated age electric grid and the wholesale electricity market Data visualization public utility that provides that serves all or parts of Delaware, Illinois, Indiana, electricity and natural gas Kentucky, Maryland, Michigan, New Jersey, North is playing an everto 3.4 million consumers Carolina, Ohio, Pennsylvania, Tennessee, Virginia, in San Diego and southWest Virginia and the District of Columbia. growing role in a ern Orange counties, with In April 2010, PJM and 12 member transmission a coverage area spanning owners received a U.S. Department of Energy fedutility’s day-to-day 4,100 square miles. eral stimulus grant for a project that will see PMUs Wind and weather (in installed in more than 70 substations in 10 states, as and hour-to-hour particular, Santa Ana well as 17 corporate phasor data concentrators, coverwinds) are pivotal inforing about 60 percent of PJM’s total transmission load. functions. mation points for this To date, 14 PMUs are installed within PJM, so this is a utility, and mapping, situhuge step for the company and its participating memational awareness, SCADA switches ber transmission owners. “The whole penetration of phase-angle measurement units helps us better and even their own weather aneunderstand the status of the whole system,” said Andrew Ott, senior vice presi- mometers have proved imperative for dent of markets for PJM. The organization has, he explained, five operators to operational awareness. “In 2003 and schedule and dispatch a thousand generators. Therefore, visualization tools are 2007 there were some devastating fires (in California). Some were attributed extremely important.
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Broad system perspective is imperative “The most effective visualization tools are the ones that give us a broad system perspective,” Ott said. “Operators can use interactive displays to selectively migrate down to different levels.” Another characteristic he says is extremely useful to operators within the interactive dashboards is the ability for each operator to customize their own display, so that the information they need to monitor is best displayed for their own particular needs. “You can save all of that as a parameter,” Ott said. “Customization seems to have been a dramatic boon for us–operators are able to determine how they best like and adapt to visualizing their own data,” he added. But it’s not all plug-and-play for the RTO: PJM has also purchased visualization tools for specific projects, and then customized and adapted them to fit the needs of the project itself.
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Real-time weather tools And the data, which is being collected by SDG&E and verified every 10 minutes by a weather information service based in Houston, is being used for real-time operations. “For example, last year we had a circuit that tripped, and it was during a storm that hit us during the time when fire danger was still high,” Zaragoza said. “Well, in those cases, we don’t like to test our circuits, we want to patrol them to make sure we find any problems. But in looking at the relative humidity, and looking at what the temperature was, our meteorologist knew that it was raining—so basically the fire danger was nonexistent. We closed the circuit. It held. And the problem was attributed to lightning.” SDG&E also subscribes to real-time lightning data. “Within our 500 kV line that is an interconnection between San Diego and out to the east in Arizona, we have two segments that are just over 80 miles long. Two years ago, we had a lightning storm come through, and the line tripped. We were able to go in, because we get real-time lightning data, and pinpoint exactly where it was—it gives us a GPS coordinate. We gave that to the pilot, he zeroed in, and he found the problem within two structures,” Zaragoza said. The real-time lightning data is overlaid on a Google map, and will pinpoint lightning strikes on the line. As well, if lightning strikes away from the line, a ruler tool can measure the distance from the strike to the line, to better determine potential problems. “What it does is expedite the patrol. We can get the line in a lot quicker, and that increases the reliability of our system,” he said. “That is a major interconnection for us, and we only have two right now. So one being out puts us at risk with the remaining interconnection.” Weather awareness tools aren’t the only data visualization tools SDG&E uses in its operations, either. As Caroline Winn, the company’s vice president of customer service, said: “We’re trying to get the most amount of intelligence on our grid to help our operators to have that 24/7 situational awareness of what is going on in the system.”
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to power lines. So we now have a fulltime meteorologist on staff, and we’ve gone out in remote areas where even the National Weather Service did not have information to get specific weather information,” said Daniel Zaragoza, SDG&E’s director of electric distribution operations. “The (National Weather Service) would run a model and take estimated information based on weather they’re getting from weather stations that are miles and miles apart. We’ve brought in and installed anemometers in pockets in the most wind-prone areas adjacent to or right on our circuit, to be able to tell specifically or within a certain area what the winds and the weather are doing,” he said. Right now, SDG&E has a total of 93 anemometers/wind meters installed on its lines. “It’s the fourth-largest weather-monitoring infrastructure in the nation. We believe we have the densest network of weather stations of anywhere in the United States,” Zaragoza said of the system. “We have instruments where data was never collected before.”
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Delivering Demand Response Removing barriers to realize the full potential of DR
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The emergence of the smart grid has created many opportunities for the electric grid to deliver energy more efficiently and reliably. Among the most exciting capabilities of the smart grid is the ability to implement demand response programs. Demand Response (DR) generally refers to any action taken to reduce customer energy demand based on a financial incentive. This definition encapsulates a broad spectrum of programs which target various customer segments with different desired outcomes. DR programs are generally defined by three common characteristics: • Financial incentives for participants • Actuation methods (automated control or consumer notification) • Desired objectives (peak load reduction, load shifting, reserve capacity, etc.)
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DR programs targeted at residential consumers typically provide participants with a combination of event notifications and control equipment to effect changes in energy consumption. These changes may be directly initiated by the utility, as in the case of direct load control programs, or initiated by the consumer, in response to price thresholds or spikes. Control equipment can be used for different types of DR programs. For example, a load control switch connected to a hot water heater could be controlled by a utility-sponsored direct load control program event, or could be owned by the consumer THOUGHT LEADERSHIP - SPONSORED BY ITRON
and controlled by an energy management system in the home. The power contribution of a single in-home appliance may in itself be insignificant. However, adoption of multiple appliances and devices capable of changing electric consumption behavior results in significant energy savings, and
operators can be dramatically increased. In order to make this a reality and achieve broad residential participation, certain barriers need to be removed.
empowers homeowners to reap the benefits of utility programs in a comfortable, controllable manner. Through a combination of policy initiatives and technology innovations targeted at residential consumers, the demand response capacity available to utilities and system
programs. The majority of DR programs include a financial incentive to motivate participation. For example, incentives could be a special utility-supplied service, which requires participation in DR events, or an application of a tariff which exposes the customer to fluctuations in wholesale
Demand Response Programs Each regulatory and grid management jurisdiction imposes different requirements on how a utility can structure DR
energy prices. The following matrix represents the spectrum of DR programs typically offered.
Demand Response Program Matrix
Automation of demand reduction through the use of programmable communicating thermostats and load control switches and/or “smart plugs” may be linked to DR programs sponsored by a utility, or may be part of an energy management strategy that is separate from the utility or retail energy rates. The diversity of customer engagement technologies illustrates the importance of enabling an ecosystem of innovative customer-facing products through the adoption of open standards, such as ZigBee Smart Energy™.
Policy Issues Impacting Residential Demand Response Residential participation in demand response programs continues to accelerate, yet barriers to adoption still remain. Some barriers are technological, such as lack of standards or incomplete deployment
of two-way smart grid communications technology. However, regulatory policy and market structure also shape the design and scope of demand response programs. Policies must ensure that DR participation is fairly compensated, and that residential participants are offered programs and technologies which ensure their full participation. For residential participants in particular, it is important that standards and communications support the aggregation of available load, such that multiple participants can combine to create unified measurement, control and verification of load curtailment to a utility or third-party Energy Services Provider (ESP). The DR Program Matrix shows that although enabling technology can achieve peak load reduction or load shifting for any residential consumer, some programs are not currently targeted at residential participants. The guidelines for participation in programs vary by region and state, and in some jurisdictions, policies limit participation of demand resources in certain programs. This is especially true of residential
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Residential availability of programs varies by geography, but generally speaking, direct load control programs tend to target residential participants and are fairly common. Time-based rates, such as TOU, CPP or PTR, typically accompany the deployment of smart meters and Home Area Networks (HAN) for residential consumers. Other programs, such as interruptible load and real-time pricing, are currently targeted at C&I customers and wholesale market participants. Some regulatory jurisdictions—particularly those with decoupled rates—encourage energy efficiency and reductions in consumption for their own sake, regardless of available generation supply. Still other jurisdictions have strict requirements mandating the maintenance of spinning and non-spinning reserves which can be met with demand management resources (such as a DR program). The point here is while rate tariffs may often define DR programs, they will not always. This highlights the need for infrastructure which can accommodate any number of programs, which may run concurrently and may change over time. Likewise, for home area networks offering automation and customer engagement, there will not be a single model for ensuring customer participation in programs. Some customers will rely on web presentment and SMS text messages to stay informed about events and incentives; others will rely on dedicated in-home displays.
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adoption of multiple appliances “ The and devices capable of changing electric consumption behavior results in significant energy savings.
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demand resources, as many guidelines are targeted at larger market players exclusively. Thus, to fully realize the potential of residential demand response, barriers to demand response in general must be addressed, in addition to barriers specifically limiting residential participation.
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General DR barriers stem largely from the operating environments and market mechanisms of various Regional Transmission Operator (RTO). Some RTOs include forward capacity markets, which provide price transparency, and allow demand resources to directly participate. Where these markets are absent, DR cannot be bid alongside traditional generation resources. Stringent communications requirements also prevent some programs from utilizing DR, such as some spinning reserve programs, which require near-real time verification of load curtailment. As federal and state regulatory policies continue to evolve, and especially as DR programs and technologies continue to mature, these general barriers will gradually be removed. Even as general DR barriers are removed, residential participation in DR must overcome a different set of obstacles. Not all residential consumers are equipped with smart meters, and many who have smart meters are not yet on time-based rates nor are they equipped with the HAN technology needed to fully realize the benefits of DR. THOUGHT LEADERSHIP - SPONSORED BY ITRON
HAN devices, including automated control devices and consumer feedback/data presentment devices, are only deployed in pilot quantities today. Finally, residential consumers are not eligible participants in some DR programs, such as interruptible load programs, which are only targeted at loads greater than what a typical household could reasonably provide. However, as adoption of smart meters and related technologies continues to increase, and the installation of HAN devices grows, the potential increases for residential consumers to not only take advantage of dynamic rate programs, but also more load management programs. The evolution of enabling technologies and open standards is key to achieving this potential.
Technology Evolution for Residential Demand Response Smart meters equipped with two-way HAN communications offer consumers the potential to understand the current price of energy, what they are currently using, and how they can participate in utility incentive programs. When combined with enabling technologies, insight can be translated into action, and energy management can be automated to take full advantage of financial opportunities. Technically-savvy consumers may also be motivated by environmental and societal benefits, such as greenhouse gas reduction, and deferred generation due to decreased energy demand. Increased consumers awareness of technical capabilities of smart meters will create demand for compatible control
devices and feedback mechanisms to capture these benefits. Some of this demand will be met by utility sponsored programs, but as the DR Program Matrix shows, there is currently a tight linkage between utility programs and enabling devices. For example, a programmable communicating thermostat deployed as part of a critical peak pricing program could provide demand management benefits related to other DR programs. Similarly, a load control switch deployed as part of a direct load control program could also be controlled by transitions into on-peak pricing periods if the home is on time-of-use pricing. Beyond utility sponsored programs and devices, adoption of smart appliances and Electric Vehicles (EV) will add substantially to the level of control and load management in a homeowner’s energy management profile. To combine these various enabling technologies into a consolidated resource portfolio, the challenge is twofold: first, standards must ensure that devices can communicate relevant information to extend control to as many loads in the home as possible, and secondly, transactions with utilities and third-party ESPs who sponsor DR programs must be decoupled from individual devices.
notion of an Energy “ The Management System has emerged, which controls consumer devices on behalf of the utility or ESP.
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The first challenge requires a common protocol between devices to enable DR control signals, price signals and related confirmations to flow between devices without requiring special translators. Some of these signals will originate from the
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smart meter, but some may come through IP-connected devices provided by ESPs or other entities. The organic adoption of devices and appliances illustrates the importance of open, common standards. A washer and dryer will be purchased independently from programmable communicating thermostats and electric vehicles, yet to fully realize the promise of residential DR, they must all be able to communicate with each other without introducing specialized translator devices. ZigBee Smart Energy is an application protocol supported in many smart meters, as well as HAN control devices and smart appliances. Recent efforts to expand ZigBee Smart Energy to enable communication over multiple transports, including IP networks, will result in the common protocol needed to allow disparate devices to participate in residential DR programs. Addressing the second challenge requires a common interface between devices and appliances in Facilitating communications between in-home devices and external third parties with an EMS a single home to the outside world, including utilities and ESPs. Not only standards-based for reliable execution of this creates powerful Measurement & must an external interface be maintained, critical programs. Verification (M&V) capabilities, which but that interface must be abstracted from Secondly, an EMS must not use proprovide third parties with an instant snapindividual devices in the home. prietary protocols or be bundled with shot of load available for DR programs. While the diversity of enabling devices single-vendor solutions. It is not realistic maximizes potential demand reduction, Conclusion to expect that consumers will purchase all utilities will not communicate directly The possibilities of demand response are appliances from a single vendor. Also, as with each one of the consumer’s conquite exciting. By addressing the regulatory DR program requirements evolve, some trollable devices. Thus, the notion of an and technological barriers outlined here, intelligence is required at the premise to Energy Management System (EMS) has the full potential of DR can be realized. emerged, which controls consumer devices augment MDMS and DRMS calculations Interoperable devices, common systems which estimate available load. on behalf of the utility or ESP. The ideal interfaces and a clearly-defined energy Monitoring energy consumption EMS remains elusive and has yet to be fully management system will be instrumental throughout the home in near-real time defined by the market. If the full potential in expanding the possibilities of DR. With will be an important feature of EMS of residential DR is to be realized, it is these pieces in place, utilities and consumplatforms, especially as EV charging important to have a clear idea of what an ers alike will be able to enjoy the benefits stations and other enabling technoloEMS is and how it operates. of demand response. gies will increasingly be equipped with First and foremost, an EMS must broStephen Johnson is a Product Line Manager for metering technology. ker communications between in-home Itron and is responsible for consumer energy When combined with whole-home devices and the utility or ESP. These management solutions. Stephen can be reached at metering data from the smart meter, stephen.johnson@itron.com. communications must be secure and
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we know. The load is not measured in real time, but it’s forecast, and our transmission grid is set with predetermined limits. These limits are often the manufacturing limits set on the various equipment. And, as we now know, a lot of that equipment is 50-plus years old, so our transmission system is modeled in the real-time grid today based on old Using transmission intelligence + flexibility empirical data. Now what’s happening as we move forward into the future is, “I THINK WITH TRANSMISSION, WHEN WE LOOK AT WHAT’S with the smart grid, the load is being going to be happening over the next 10 to 15 years, we have to go back more and more measured in real time. to the basics.” As a matter of fact, the Department With these words, Phil Harris, CEO of Tres Amigas LLC and former head of PJM Interconnection, opened a provocative discussion about the future of transmission in of Energy had a study that said North America. Speaking as a panelist in a recent EnergyBiz Leadership Series web- presently less than 20 percent of the information from a generator to the cast, “Game Changers: What you thought you knew about transmission,” Harris use of electricity is under the use talked about the opportunities available in a more efficient transmission grid. Here of power electronics—i.e., are some of his comments, edited for style and length. where we know everything In transmission, the changes that are taking place are GENERATION about it from the source to on the security-constrained dispatch of transmission. If + where it’s actually used—and we look at the dispatch equation for 100 years—and this in 20 years, 80 percent of that is important to understand—we’ve dispatched our system IMPORTS (OR – EXPORTS) electricity that is generated, (this way). As you know, an electric grid, as long as it is in to the point where it’s being balance, it is reliable, as long as generation equals load. = used, will all be controlled Let’s look at the parameters behind that dispatch equaLOAD under power electronics. That tion. We know the generation. The ties (import or export),
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is a massive game-changer, and this is where smart grid is going, and this is why elephant companies such as Cisco and IBM, GE’s ecomagination and so forth, are all involved. So the future’s leading us into the actual dispatch, which keeps the grid reliable, where we know all the generators, we know the ties, and we’re leading to the future in which we know, real-time, what’s happening on the load. And now we have to look at what’s happening with transmission. It’s the last unknown in being able to optimize the grid dispatch for the future. To look at that, we have to look at the security-constrained economic dispatch. If we look at the way that works, we have to account for all the transmission limitations because we know that not all generation can reach load. This is the security-constrained economic dispatch. So in that security-constrained economic dispatch, we have the known, and then the estimated, inputs into that model. The real-time generation is known, the real-time flows are known. The load forecast is changing in our world because of smart grid, and we will know all the elements that lead to that. We have to get beyond the engineering limits with assumed conditions and understand all the known conditions that are taking place on the transmission grid. These are things like transformers, real-time status, the sag of the line, whether there’s ice on the line or not, whether the lightning arresters are working—the entire status of everything on the transmission system. When we know that, and we tie that with the knowns of the use of electricity so it’s not forecast, then we can have a perfect and optimum dispatch of the electric grid. When that happens, we have the capability of making huge potential improvements in transmission. If you look at just the congestion cost alone—and a lot of that is driven because we’re using estimated numbers on what the status of the transmission grid is— congestion costs alone, for example, in PJM were published to be $1.3 billion last year and over $12 billion since 1998. Now a large part of that, of course, is physical constraints, but a lot of it is due to modeling because we simply don’t know the status of the grid. So putting the smarts in the transmission system, so that the transmission system is a known in the security-constrained economic dispatch equation, along with the elements that are taking place in the smart grid, that allows us to know real-time what the use is, and will enable us to get a huge efficiency in this machine called electricity, and the ability to be able to move it forward. The interesting thing about this is why aren’t we doing more of it right now? You’re really talking about trillions of bits of information that are out there from all the different elements that are taking place on the transmission grid, and to (be able to) do things with that data, transform it into real-time, and make it available for information to be used for the dispatcher and others during the buying, selling or trading of electricity. This gets in everything from the demand side all the way to the generation side. And again, this is why these elephant companies—the Ciscos, the IBMs, the GEs, the Microsofts—are still so interested in electricity today.
I think this is one of the biggest challenges that we have in operating the electric grid of the future: the dispatchers are going to be faced with a large volume, a hundredfold increase over what they’re seeing today. I also think that this is something that NERC should really take quite seriously in its strategy for the future:
“Dispatchers are going to be faced with a vast volume, a hundredfold increase over
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what they’re seeing today. how are the dispatchers going to deal with all this data and information that is coming in from all these real-time measurements on the demand side, the use of equipment, and on the transmission side, and transform that into capabilities? This is certainly doable. If, when we look at the aerospace industry, and look at the vast amount of information that is needed to fly in space today, and maintain these relationships, there are a lot of models for how you can do that so you can fly this ship and maintain it. And, as you know, in the electric grid, we fly an airplane that can’t ever land. So as we make these changes and this data comes in, understanding how that works in the dispatch equation, how that transfers to the appropriate signals for the dispatchers, and how that transfers into public information for trading and use is a big challenge. The Tres Amigas project will be connecting a 600,000 MW eastern grid with a 240,000 western grid as well as a 70,000 MW grid in Texas. The challenge: what will it take to enable up to 30 GW of power to move in and between the three interconnections. Tres Amigas plans to break ground this year.
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END OF THE LINE Star schema and beyond This goes far beyond the star schema approach to data, which is the simplest form of a dimensional model in data warehousing and business intelligence. In it, data is organized into facts and dimensions, with a fact being an event that is counted or measured, and a dimension containing reference information about the fact. As a simple utility example, a fact could be a usage OGE plans to use the whole brain of energy within a certain time frame, rather than separate neurons and the dimension, then, might include By Kate Rowland the date and time the energy was used, and the customer who used it. A star IT’S THE OLD CHICKEN-AND-EGG CONUNDRUM, UPDATED. schema works well if you know what New grid sensors, from smart meters to phasor measurement units you want to measure. and more, are providing a slew of new data for utilities to use to increase the reliBut what if you aren’t sure? ability of their product—electricity—while also enabling them to shape electricIn his book Data Mining: Concepts, ity consumption and better optimize the grid’s performance. Models, Methods, and Algorithms, The science of data analysis and analytics has been successfully applied to the Mehmed Kantardzic writes: “Data banking, oil, insurance, telecommunications, travel and retail industries, to name mining is an iterative process within but a few. Now the electric utility industry is turning its eye to data analytics, as which progress is defined by discovery, well, in order to best mine the new information now coming in in droves. either through automatic or manual methods. Data Building an information factory The electric utility mining is most useful in an For OGE Energy Corp., it’s a brave new world exploratory analysis scenario the company is exploring with a vengeance. industry is turning in which there are no prede“The initial questions we asked were: where termined notions about what are we going to store all this data, how will we its eye to data will constitute an ‘interesting’ organize it and how can we utilize the inforoutcome. Data mining is the mation to improve our business?” said Craig analytics in order to search for new, valuable and Johnston, vice president, corporate strategy nontrivial information in and marketing, for OGE Energy Corp. best mine the new large volumes of data.” OGE is the parent company of Oklahoma Or, to put it more simply, Gas and Electric Company (OG&E), a reguinformation now as many within the industry lated electric utility, and Enogex LLC, a midhave explained it: “This is: stream natural gas pipeline business. OG&E coming in in droves. ‘we don’t know what we serves more than 780,000 retail customers in don’t know.’” Oklahoma and western Arkansas, and a number of wholesale customers throughout the region. Held back by regulation OG&E has approximately 6,800 MW of capacity. Its electric transmission and and lack of detail distribution systems cover an area of 30,000 square miles. According to authors Rasheed Joshi Johnston noted that other utilities are going through a similar exercise with and Diego Klabjan, who wrote a white regard to analyzing their new data. “If you can capture and analyze that data, paper about the subject in late 2009, and use it in a predictive fashion, what can we do with it to improve our “Such approaches have been dormant operations and enhance our customer experience?” he asked, summing up the in utilities mostly due to the regulated crux of OG&E’s new “Information Factory.” Working with OGE chief informaenvironment and lack of fundamental tion officer Reid Nuttall’s enterprise architecture team, the Information Factory detailed data streams.” They noted is adopting those tools other industries have already found invaluable. “What that smart sensors, including smart information do you want, and how would you use that data?” defines the meters, will provide what they call initial focus. “power streams” that can be mined for
Using analytics to do more than crunch data ++
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customer relationship management, targeted energy efficiency programs, local forecasting and dynamic pricing. “Techniques such as data mining, pattern recognition, consumer choice behavioral modeling, and optimization form fundamental blocks in market segmentation, targeted marketing, price optimization, supply chain management, management reporting, and various other applications,” Joshi and Klabjan said. The utility values available from analytics-based applications for smart grid include superior customer service, operational efficiency, optimized delivery of power, smart energy procurement, demand response and dynamic pricing, as well as being able to predict equipment failure and outages, using pattern recognition to detect revenue leakage and theft, and optimization techniques for Volt/VAR control.
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An analytical journey On the ground, what this means for OGE is an utterly new approach to data. “I look at the journey,” Johnston said. “Today, we’re pretty happy if we get standard reports and occasional customer reports.” But, given that OGE has espoused a goal of not adding new fossil-fuel generation at least until 2020, using detailed data analytics will definitely provide an active assist in reaching that goal. Johnston said that, for the company, it means looking at how to start to apply statistics on top of data, and use that to improve forecasting. And then, he said, “we can take that and do some ‘what ifs,’ or predictive analysis. “Utilities are heading into a period of increasing costs [associated with upgrading aging infrastructure and adding new technology]. We need to understand what those drivers of elasticity are,” he said. Add to that the question of “how well do we know our system?” This will be imperative to the utility when deciding how to support electric vehicles and other changes on the distribution system.
“Once you start using the smart system, you can look over the entire system and better manage load and demand and generation,” he said. Detailed data analysis will provide the structure for looking at trends, as well as at asset management based upon the history of the asset. Building short-term wins Johnston says the first step for OGE—getting the Information Factory up and running—is complete. Along with standing up the technologies, it included information that allows a geospatial look at the utility’s customers, revenue and load. The next step? “We have to build some short-term wins: what can we do on a measured scope and scale within the next six months?” Some data analytics business cases within the company will have a clear win, and others, Johnston said, will be more marginal, but will serve to build upon the business case necessary for other projects. The final step in the project, what Johnston calls the “key missing element,” will require longer-term thinking and focus throughout the industry, not just at OGE and its utility companies. “We have to have an analytical skill set. It’s not the same as reporting,” he said. “Analytics is a field of very specific talent. You have to be able to use the tools and be able to look at specific scenarios. “We as business leaders are not really familiar with storing frequency data.” Then there’s the issue of migrating data from legacy systems to one central source, as well as the issues of data stewardship and data governance. It’s a tall drink of water for any electric utility to swallow. “As we continue to develop our capabilities, we will be recruiting a different talent set—data analytics. It’s an exciting place to work, and it resonates with a lot of the college recruits,” Johnston said.
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4D The advantage of a matrix management approach is that it enables team members to share information more readily across task boundaries. It also allows for specialization that can increase depth of knowledge and allow better professional development and career progression. However, when using this approach, utilities have to be careful that employees do not become confused due to conflicting loyalties.
A comprehensive approach to deployment ++AEP tunes into cross-functional teamwork By Christopher Perdue THERE ARE MYRIAD CHALLENGES UTILITY COMPANIES FACE
as they build a smarter grid. Providing the proper people, processes and systems are only part of the challenge. Utilities also need to provide the management structure needed to ensure that all of the moving parts of such an undertaking are successful. Most utilities are using cross-functional teams to lead their smart grid transformation. In a recent survey conducted by Sierra Energy Group of more than 140 smart grid utility professionals, more than 53 percent of respondents indicated that they are using cross-functional teams for key smart grid decisions.
Communication a key element A key challenge of smart grid governance is to satisfy all of the internal stakeholders involved, and achieve their idea of success. I asked Vegas how a utility can best address the risks of corporate misalignment, organizational silos and scope creep. His response? Communication, communication, communication. According to Vegas, an effective project management office (PMO)
A cross-functional approach Pablo Vegas, chief information The impact to utility business officer at American Electric Power (AEP), confirmed that his utility is processes resulting from smart grid using such an approach. “AEP leads its gridSMART program using an exdeployments is extensive and requires ecutive steering committee consisting of business leaders from the utility a comprehensive plan and leadership operations, corporate communications, finance, environmental, regulafocus in order to be successful. tory and IT organizations,” said Vegas. “The impact to utility business function is important to ensure that processes resulting from smart grid deployments is extensive and requires a comprehensive plan and leadership focus in order to be successful. The executive the risks inherent in a smart grid investment program are managed approcommittee approach builds broader ownership and accountability across the priately and to help define communiorganization for the success of the program.” cation and decision-making pathways AEP is using a matrix management structure to oversee its gridSMART that will ensure the program is sucprogram, which encompasses specific utility company projects in addition cessful. “Additionally, communication to research and development activities. Accountability for specific projects internally, with external stakeholders, within the utility falls within the purview of each of the company’s eight utility companies, while the central support systems are governed by the utility support and with customers throughout the lifecycle of a smart grid program is and IT organizations. critical to ensure that expectations are For background, matrix management is a technique of managing an orclear and that each group’s interests are ganization (or, more commonly, part of an organization) through a series of considered,” said Vegas. dual-reporting relationships rather than a more traditional linear management Indeed, arguably one of the most structure. In contrast to most other organizational structures, which arrange managers and employees by product or function, matrix management combines important aspects of a smart grid implementation is a standard apfunctional and product departments in a dual authority system.
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proach to the project methodology and a centralized PMO that consolidates risks, schedules, cross-project dependencies and documentation standards. “Business as usual” does not always suit itself to the imposed structure of the PMO. As a result, a utility can often encounter organizational pushback. Change management should include not only the projects in the smart grid program, but also operational changes. Employing a PMO-level decision process can help formally record all of the different executive-level decisions that cross organizational boundaries. Utilities should consider investing in behavior change programs, so that they can utilize the processes in the rollout of smart grid initiatives. Change is difficult for most, and can be met with stern resistance, threats of taking retirement, organizational withdrawal, low morale, lost productivity and issues with quality. One must keep in mind that many of the utility functions impacted by smart grid initiatives have not changed much over the past 50 years.
Christopher Perdue is vice president of Sierra Energy Group, a division of Energy Central.
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Comprehensive, not departmental I also asked Vegas about the critical skills and experience needed for the person or persons who govern a utility’s smart grid efforts. Vegas feels that the leadership of a smart grid program needs to recognize that the project is a comprehensive business project. “It is not an IT project, it is not a metering or distribution operations project,” said Vegas. “It is a comprehensive and disruptive business initiative that will require involvement and leadership from all core business areas—utility operations, IT, customer services, finance, regulatory, risk management, human resources, etc.” In addition to the internal stakeholders, utilities need to also satisfy their customers and their regulatory bodies. Each one has a vested interest in the success of the smart grid and each one of them has their own set of expectations as to how it will work. “It is key that the leadership team of the smart grid program focus appropriate attention on each of these stakeholder groups and not lose sight of the significance of any one of them,” said Vegas. Developing the proper smart grid governance structure for a utility requires a significant investment in time and resources. A successful smart grid implementation requires clear strategy, clear definitions and requirements to support that strategy, appropriate lines of demarcation concerning roles and responsibilities and well-defined ownership. Without these cornerstones of quality management, deployment and ongoing success will be at risk, no matter how well technology decisions are made. But with the proper governance structure, utilities can make certain that they have a framework of rules and practices to ensure accountability, fairness and transparency with all of the stakeholders involved.
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By Mike Breslin IT’S RAINING ONES AND ZEROS, AND UTILITIES ARE DUCKING
for protection just like every other business, institution and government in the world. Data that used to have protective shelter under lock and key with limited employee access is now whizzing about in an ever-increasing mix of wire, fiber and wireless transmissions and storage technologies. Information is constantly being aggregated and distributed in new and different forms. And, as soon as people get a handle on what’s happening, newer technologies quickly emerge to further complicate the challenges. More portals for such data over power lines, smart meters, smart phones and tablet computers used by utility field personnel, cloud computing and point-to-point microwave transmissions further widen exposure and open risks. There are few certainties in this new storm. One is: if there is valuable data being transmitted or stored, then someone will inevitably attempt to disrupt or steal it.
Bold steps to defend infrastructure Bold steps are being taken across the industry by IT professionals to defend vital generation, transmission and distribution infrastructure. IT departments are constantly fighting hacker onslaughts and internal breeches by controlling access, building stronger firewalls and implementing encryption. The Salt River Project (SRP) provides electricity to more than 940,000 retail customers in the Phoenix, Arizona, area and has already deployed more than 600,000 smart meters. Mike Lowe, SRP’s manager of customer services, explained precautions his utility is taking. “We’ve got the traditional firewalls around the various networks and continually monitor them for penetrations. We do background checks on all hires and restrict employee access to systems on a need-to-know basis.
“We tightly control access to buildings as employees are reassigned or leave. Employee access is periodically reviewed and modified or revoked as appropriate.”
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download proprietary data to external storage. In the wrong hands, a tiny, 32gigabyte flash drive could cause embarrassment or millions of dollars in damage. “At SRP a review on the use of USB flash drives is coming very quickly. We expect to have it implemented in the next 12 months,” said Lowe. “There is going to be encryption available for those that need to use USB ports and, depending on the if there is valuable operational area in the company, ports may be shut down.” data being transmitted
$100 drive can lead to million-dollar leak Often the enemy Mitigating risk resides within. or stored…someone will “I always tell utilities that as much effort as they As the U.S. State spend on mitigating external threats, they need Department learned from inevitably attempt to to spend twice as much effort on internal risks the Wikileaks scandal, an because that’s the greater risk,” advised Roy E. employee with low-level disrupt or steal it. Hadley, Jr., a partner in the Atlanta law office security clearance and a of Barnes & Thornburg, and co-leader of the USB flash drive caused worldwide chaos by releasing sensitive firm’s cloud computing and cyber security practice team. “Customer information held by a utility is considered a trade secret. A documents. In December, it led the customer list is one of the most valuable trade secrets a company has, not only U.S. Department of Defense to block computers holding classified files from personal customer information, but usage patterns as well as personnel data. It’s a valuable intellectual property, the basis of a business, the source of profit,” being downloaded to external drives Hadley said. and USB media. Mike Lowe commented on SRP’s customer protections: “In our customer A greedy or disgruntled employee system we’ve gone through the National Security Administration Information should never have an opportunity to
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CONNECTIONS Protection is more than an IT function How can utilities best protect themselves? “Where most companies fall down is they think that this type of risk management, protecting the information, falls squarely in the IT function, but it’s typically more than an IT function,” said Hadley. Liability issues explored He recommends the formation of Who is liable if customer information is compromised? a of a multi-dimensional informaThe utility is the victim in the sense that the information was stolen from the tion security committee to regularly utility, but under most state data protection and privacy laws the customer is address the issues and establish a set considered the victim. Under most state laws, the utility is required to notify a of policies and procedures to protect customer that his or her confidential information has been breeched. the company. As of November 2008, all utilities were Members should required to implement the Red Flag rules by include, but not be the Federal Trade Commission to protect their limited to, governance, DATA SECURITY customers from identity theft. Under the rules, IT, compliance, operaTIPS utilities were mandated to develop a formal tions, finance and program to detect warning signs that fraud may human resources. It starts with a cultural “You really have to be occurring such as unusual account activity. security ethic and it has to have a multi-dimenRed Flag programs must also describe appropribe enterprisewide. sional approach because ate responses to prevent and mitigate crimes. You have to take security very, everyone has to fully If a utility is negligent, fines of up to $2,500 very seriously. understand where the per customer may apply. “We are fully Red Flag data is, how it’s stored, compliant,” Lowe said. Recognize that there are risks. used and transmitted. Now a new world of exposure emerges as milPlug all the risks you can. New technologies will lions of smart meters are installed and utilities come on board and are cope with meter data management (MDM). You may decide that some risks often implemented very “As utilities have access to more information are not that great and accept quickly,” Hadley said. through smart meters and smart grid techsome, but keep a careful eye “Utilities must be adept nologies, there are certain types of information on them. and agile to take advanthat utilities never had to deal with before,” Work with your tage of those technolowarned Hadley. “You have not vendors to increase gies, but also understand seen many cases on it yet, but security in the the risks and put in place arguably some types of inforsystems you buy. mechanisms to mitigate mation could become private those risks.” information that would then It takes constant The Salt River Project become subject to privacy and vigilance. appears to be ahead of data protection laws.” Source: Mike Lowe, SRP the curve on Hadley’s Here’s how SRP protects its advice. SRP has an execusmart meters: “We have internal tive security leadership security over the head-in systems committee chaired by so we restrict who has access,” executives over physical security and Lowe said. Our system has a high information security as well as key level of encryption, communication through frequency-hopping spread specoperating managers enterprisewide. trum and only certain meters can talk to certain other meters so you cannot
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security assessment methodology and classified the data for the levels of confidentiality, availability and accuracy. Some things you have to hold sacrosanct like customer social security numbers and we lock down those types of things very tightly and control access. “We also log access to every screen in the customer system so we know who looked at a screen and when. And we are currently investigating the encryption of key variables in our customer database. We have a desire to maintain control over our data and networks and have limited interest in cloud computing for that reason. We maintain all our own servers, which are locked down,” Lowe said.
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break in just anywhere and have access to the network. There are also tamper flags. If there is a physical violation of a meter we know about it.”
Mike Breslin is a journalist and author living in New Jersey.
An Exclusive Invitation Only Event! Amelia Island, Florida November 7 - 9, 2011 Optimizing the convergence of Information Technology, Operations and Customer Service in the new Intelligent Utility In the intelligent utility of the future, true operational and energy efficiency will only be achieved through the successful synergy of three mission-critical utility operations: Information Technology, Operations, and Customer Service. It is this challenge that has driven Energy Central to create Knowledge2011 — Intelligent Utility Executive Summit, an exclusive, invitation-only, knowledge sharing event for top executives in these three utility functions.
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The Knowledge2011 — Intelligent Utility Executive Summit offers a unique opportunity to: • Engage in unique, off-record roundtables with your peers in IT, Operations, and Customer Service • Compare results of pilot programs and lessons learned • Gain insight from thought leaders (industry and non-industry perspectives) on emerging trends in technology, business, operations, and consumer behavior • Network in an open and friendly environment, with no point-of-sale pressure • Attend the 2010 EnergyBiz KITE Awards ceremony for IT, Operations and Customer Service
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OUT THE DOOR CAVOUKIAN To be honest, I haven’t
Data privacy issues ++A conversation with Ontario’s Ann Cavoukian By Phil Carson ANN CAVOUKIAN, INFORMATION AND PRIVACY COMMISSIONER
for Ontario, is on a mission to raise awareness of the fundamental importance of consumer data privacy and to embed it into smart grid systems early on. She calls her approach, which has been “operationalized” at Hydro One in Ontario, “Privacy by Design.” INTELLIGENT UTILITY Tell us your view of the fundamental notion of privacy
and its importance. CAVOUKIAN Privacy is considered a fundamental human right because it’s at
explored that yet. That’s why we’d like to partner with a major U.S. utility. For the most part, however, we’re advising what not to do. First, preserve the status quo. Do an assessment on how data is used within your operation. Presumably that’s documented. Then adopt a policy stating you’re not going to release personally identifiable information to third parties without the customer’s consent. You can ask your customers whether they’re interested in promotional offers; that’s the opt-in model. The initial costs are minimal. You’re not putting in expensive new equipment. You’re assessing current practices and adopting a policy. Beyond that, I can’t address the cost, but I’d love to do so.
the core of all our freedoms. It’s the ability to go about your business without fearing that someone, including the state, is looking over your shoulder. The first thing to go when a democracy sinks into a totalitarian state is privacy. INTELLIGENT UTILITY To be fair, In the energy context, ask yourself, how is information going to be used? you’re not just advocating a policy. Let me be clear: security is essential to privacy. You can’t have privacy without In your case study on Hydro One security. But you can have security without privacy when information is used in in Toronto, you’re advocating an IT ways that hadn’t been envisioned, without the consent of the individual to whom architecture and systems approach it belongs. Fast forward to today, with all the online social media. How can we that would gather, store, analyze and, control our data in this environment? That’s a good question. ultimately, dispose of customer energy Let me draw this distinction for your readers. There’s use data in such a mana big difference between user-generated informaner that the utility gets The smart grid is tion and people who choose, perhaps foolishly, to put the granularity it needs to information out there about themselves. That’s their efficiently operate the grid at a nascent stage, choice. They have control. They may regret it, but you while keeping individual have to respect their choice. If it’s not your information usage data private. so it’s the easiest to give out, you should be held to a higher standard. CAVOUKIAN Exactly. INTELLIGENT UTILITY How has your message possible time to INTELLIGENT UTILITY been received? Let’s talk about the CAVOUKIAN This is a new area for the energy sector, build ‘Privacy by ownership of data and so I try to be respectful in explaining the issues. For related issues. data relating to operating the power grid, you don’t Design’ into what CAVOUKIAN A lot of have to worry about privacy. The issue matters when utilities say they own the there’s linkage between energy usage and someone’s you’re developing. data. They collect it, they name, address or personally identifiable information. analyze it, they use it to Fortunately, the smart grid is at a nascent stage, so operate the grid. I want to suggest that it’s the easiest possible time to build ‘Privacy by Design’ into what you’re devel‘ownership’ is not the best language to oping. You will not only save a lot of grief by avoiding data breaches, but you will use. I’d prefer the language of ‘custody’ gain the trust of your customers. And you need customer trust and buy-in for and ‘control.’ Who has custody of this them to participate in energy conservation reform. information? Clearly the utility does. INTELLIGENT UTILITY Managers of investor-owned utilities must report on With that custody comes enormous how they spend or invest money. Are investments in privacy measures recovercontrol and a duty of care. If you are able through rate cases? collecting this data, you have obliga-
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tions to protect it. But if people insist on the concept of ownership, then it belongs to the individuals who are identified with it or by it. Privacy is about control. People think it has to do with secrecy. Your customers have an existing trust relationship with their utility and they don’t want that model to change. They don’t want third parties entering into this relationship without their consent. If you want to provide access to third parties, who may have very valuable offerings, you ask the customer. INTELLIGENT UTILITY In your
view should ‘Privacy by Design’ be legislated or adopted as a self-imposed industry standard? CAVOUKIAN You could do both.
I’m okay with the self-imposed model because I think utilities understand this is good for business. In California, Senate Bill 1476, signed into law last year, says to utilities: ‘Thou shalt not give this information to third parties without the individual’s consent.’ [Editor: The California Public Utilities Commission has also required disclosure of current practices and future plans from the state’s largest utilities. The National Institute for Standards and Technology issued security and privacy guidelines last September.]
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