Where smart grid meets business—and reality.
VOL 3, ISSUE 4 » JULY/AUGUST 2011
REGULATORY INTEL ©©
FERC vs NERC: A grid control showdown over cyber security
DISTRIBUTED GENERATION REDUX See how one utility proves the end-to-end smart grid concept in a “microgrid laboratory” UTILITY MOBILITY How to integrate new mobile workforce management across the enterprise
COMMUNICATIONS NETWORKS Public, Private or Combo
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electric I water I Gas I aMI I Da I Dr I MDM I outage Management I Conservation Integration I Deployment I Business Case Support I regulatory assistance
CONTENTS S PECIAL REPORT COMMUNICATIONS NETWORKS
32 No one size fits all
Network of networks requires combination of solutions
DEPARTMENTS
14
FEATURES // JULY/AUGUST 2011
Regulatory Intel
14 FERC vs NERC
A cyber security showdown in the bulk power system corral?
17 Establishing coherent policy
Ex-FERC commissioner Suedeen Kelly provides transmission insight
Distributed generation redux
20 Solar solutions W WW.INTELLIGENTUTILIT Y.COM /// JULY/AUGUST 2011
Distributed load or microgridding—or both?
2
Utility mobility
24 Integrating mobile solutions
Three utility leaders describe their challenges, successes and lessons learned
10 20 34 38
4
Drawing the line
6
Transmissions 6
Letters from readers
10 The big picture
10 DMEA finds common ground in diverse constituency
34 Grid(un)lock
34 Nashville Electric Service pursues voltage conservation
38 End of the Line
38 A new attitude toward energy consumption?
40 4D
40 Hydro One: Location is imperative
44 Connections
44 Cyber security requires organic effort
48 Out the door
48 The advanced smart grid: book excerpt
40 Vol. 3, No. 4, 2011 by Energy Central. All rights reserved. Permission to reprint or quote excerpts granted by written request only. Intelligent Utility® is published bimonthly by Energy Central, 2821 S. Parker Road, Suite 1105, Aurora, CO 80014. Subscriptions are available by request. POSTMASTER: Send address changes to Intelligent Utility, 2821 S. Parker Road, Suite 1105, Aurora, CO 80014. Customer service: 303.782.5510. For change of address include old address as well as new address with both ZIP codes. Allow four to six weeks for change of address to become effective. Please include current mailing label when writing about your subscription.
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D R AW I N G T H E L I N E
Overtaking the noise I WAS IN SANTA CLARA, CALIF., IN LATE MAY TO PARTICIPATE IN A CONSUMER
symposium and to moderate a panel for ConnectivityWeek. I arrived there armed with Benadryl (for heavy pollen) and empty notebooks (for heavy note-taking). I arrived home a few days later with full notebooks and a head full of new ideas. Since then, a suggestion made by one plenary speaker, Geoffrey Moore, has been challenging me. Moore, a Silicon Valley-based high-technology consultant and author of Crossing the Chasm and other books, opined that the smart grid has not yet achieved escape velocity in order to “cross the chasm” to a volume operations model.
W WW.INTELLIGENTUTILIT Y.COM /// JULY/AUGUST 2011
“The volume operations model doesn’t kick in until there’s enough volume for the operations model work and payoff,” Moore told us. “You’ve got to play this game as a complex systems game ... for the foreseeable future.” But it was something else Moore said that I’ve been thinking about since I arrived back in the office. “Identify the narrative that will take you to the next place. When the narrative is clear enough, the signal overcomes the noise,” he said. “As long as there is more noise than signal, the world will say, ‘Let’s wait until next year.’” Since its inception more than two-and-a-half years ago, Intelligent Utility magazine has been working to identify the evolving narrative of the electric utility industry and the smart grid. As projects and technology have continued to evolve, so have the stories within our pages. In this issue, we cover a gamut of issues and utility stories, all contributing to the narrative that will take us, as an industry, to the next place. My challenge to you, as a reader and participant in this evolving industry, is this: Where is the electric utility industry now with respect to noise and signal? Has the signal overtaken the noise? And, if not, what’s it going to take to get us there? As always, I enjoy hearing from you, and appreciate your feedback.
4
Kate Rowland Editor-in-Chief, Intelligent Utility magazine krowland@energycentral.com
sue? Then Enjoy the is for free at subscribe .com/ igentutility ll te .in w w w subscribe
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TRANSMISSIONS
Letters from readers Vol 3, issue 3 » mAy/June 2011
where smart grid meets business—and reality.
sm ARt gRiD
2020
cis/mDm
utility barriers still exist
©©
Industry experts weigh in on critical trends
tRAnsmission inteRconnection two new developments putting the brakes on buildout eneRgy eFFiciency impAct How DR + ee is more than the sum of their parts
» www.intelligentutility.com
Grid modernization monetization
W WW.INTELLIGENTUTILIT Y.COM /// JULY/AUGUST 2011
March/April 2011
6
Thank you for the interesting article on ROCs. I had not previously heard of this sort of financial instrument, although it sounds a lot like a municipal revenue bond. Those instruments are tax-free and are low risk because of the dedication of project revenues to repay the debt. I like the long-term, stable source of capital that an ROC represents so that the payment stream can be more stable. I am curious about a few things. Firstly, long-term finance and amortization is common in the utility sector, but with smart grid assets the steep technology curve dictates much shorter amortization periods like 10 years instead of the typical 30. If the underlying assets become no longer useful before the debt is repaid, how is the remaining balance paid? In utility ratemaking, utilities can only have assets that are used and useful in rate base. I understand from a credit standpoint why the instrument’s marketability and lower interest rate is tied to
the dedicated charge on consumers’ bills along with a true-up mechanism and assurance from regulators that the deal will be honored over the term of the loan. However, this very issue of providing assured cost recovery, or prudence, is a major issue for regulators as evidenced best in the initial order last June from the Maryland Commission re: denying BG&E cost recovery for its AMI project. I am intrigued by the ROC, but wonder what thought has been given to satisfying or assuring regulators relative to performance, ratepayer benefit that would convince a PUC to provide the sort of iron-clad support contemplated in an ROC? Have any ROCs been placed at this point that would be instructive along these lines? David O’Brien Director Regulatory Strategy Bridge Energy Group
www.intelligentutility.com 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 COPY EDITORS: Martha Collins, J. Ian Tennant VICE PRESIDENT, SALES/MARKETING SERVICES: Jennifer LaFlam
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Eric Swanson, Stephanie Wilson, Patricia Davis CUSTOMER SERVICE
Cindy Witwer, 800.459.2233 ENERGY CENTRAL
www.EnergyCentral.com PRESIDENT/CEO Steve Drazga CHIEF OPERATING OFFICER Steven D. Solove CHIEF DIGITAL OFFICER Joe Haddock VICE PRESIDENT, INTELLIGENT UTILITY Mark Johnson VICE PRESIDENT, DATA & ANALYSIS Randy Rischard VICE PRESIDENT, MARKETING PRACTICES Mike Smith
Changing the dispatch equation
DIRECTOR OF MARKETING Sarah W. Frazier DIRECTOR OF SALES, EMPLOYMENT SERVICES Kyle Schnurbusch
March/April 2011
We continue to look at our mounting problems through the lens that we have used since the grid was created. “We need to bring more data into the equation and find a way for dispatchers to manage it,” the gist of this article, is based on a top-down, center-based control paradigm. We need much more data, that is certainly true, but more data will overwhelm our current system. Consider how the Internet manages complexity and massive amounts of data. The communication protocols of the Internet (TCP/IP, etc.) enable massive amounts of data to self-route. They provide an appropriate network architecture to manage complexity and, in so doing, unleash tremendous potential for innovation and, importantly for
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TRANSMISSIONS the grid, this approach would enable exception-based management by dispatchers. With a shift to a bottom-up, edgebased control paradigm, potential solutions become more feasible, because now they better match the problem. The key to managing an incredibly data-rich grid will be opening up to new players and
2020 Smart Grid
Where are we going?
Gazing into the future of the new utility more hazy than others By Kate Rowland It’S generally agreed that the comIng
16
17
new possibilities, letting go of some elements of control and changing the paradigm. Managing data as it comes into the system, out at the edge, for example, reduces the data that must be carried over the communication system. Intelligent edge devices as well are needed to substitute for better equipped dispatchers. John Cooper
W WW.INTELLIGENTUTILIT Y.COM /// JULY/AUGUST 2011
Ecomergence
8
w w w. i n t e ll ig e n t u t i l i t y.co m
decade will bring more change to our industry than we’ve seen in the previous century. Industry researchers have clearly indicated they see a massive increase in smart grid spending between now and 2015. Late last year, SBI Energy was definitive in its expection that “The next five years will be a pivotal period for the global smart grid market, with grid component companies expected to leverage their sales prowess to capture long-term contracts throughout the electric grid supply chain.” But what about 2020?
data analytics on the rise In early January, Pike Research released data indicating that the software and services that will enable smart grid data analytics will represent one of the largest growth opportunities in the utility sector over the next few years, increasing from a relatively small market of $356 million last year to nearly $4.2 billion in annual revenue by 2015. And there are clear indicators this trend will continue into 2020. “Data analysis is the area which is just emerging as a need: ‘Okay, I now have the systems in place and have lots of data, but what do I do with it?’” said John Wambaugh, a vice president of Utility Integration Solutions (UISOL). “My favorite quote is, ‘I have 100 times more data, and I still can’t tell where the problem is.’” In my own conversations with utilities and vendors alike, especially over the past year, the subject of structured and unstructured data analytics has crept into the discussions more and more often. As Craig Johnston, OGE Energy Corp.’s vice president, corporate strategy and marketing, told us recently about his utility’s data
IlluStratIon by dana lechtenberg
www.intelligentutilit y.com /// may/June 2011
++Some elements are
We decided to plumb the depths of our own crystal ball, and asked analysts, researchers and national laboratory leaders where they think the industry is headed in the coming decade, and what we can expect come 2020.
needs to be put off for the sake of economic efficiency. If we’re really serious about engaging consumers in this grid modernization effort we call the “smart grid,” then consumers have to be in charge, not the dispatchers. Rather than exercising control over the grid, dispatchers monitor the grid, signal when the grid is out of balance, and only step in when automation on the edge of the grid can’t or won’t keep the grid from collapsing. I think some policymakers are very serious about engaging consumers, but they have no idea what’s required and what the ramifications are.
I agree with Dr. Harris that more gridlevel data needs to be made available. I also agree with him that knowing the state of the grid is more valuable than estimates of the state of the grid (hence the term “state estimator”). However, I’m not as sanguine about the prospects for “perfection” and “optimality” in a smarter grid with more actors. Dispatchers, and dispatch algorithms, face limitations on computing power and the availability of information. Consumers are not going to sit quietly while a faceless individual in Valley Forge decides when their air conditioner can run, and when dinner
Jack Ellis Tahoe City, CA
Smart meter manufacturers join forces Intelligent Utility Daily, June 21
I find the need for the smart meter manufacturers association both interesting and sad. I am speaking from personal firsthand experience and interaction with several of the smart meter manufacturers who have created this association. I have had extensive personal experience with different utilities from across the nation involving smart meter uses and deployments. I fully understand the needs of the manufacturers in undertaking such efforts to protect their bottom line. After all, this is their business and, as stated in the article, some have been in the business for 100 years or more. The manufacturers have maintained a product reliability record that can be easily verified and defended with astonishing results. This too is pointed out by the reports given in the article. The sadness I feel is over the lack of “clear” utility leadership in the efforts. I believe the bottom-line reason for
the consumer pushback is not because of smart meters per se, but more about consumer frustration and lack of voice. The smart meters are just the newest lightning rod attracting the pent-up anger/energy of the consumers. Utilities have done a very poor job of presenting consumer benefit cases to the public, and the consumers know that they will be charged for the deployment of these new technologies with questionable benefits for themselves. The utilities will be the ones who gain the greater benefits if the present business cases are used. The failure of utilities to understand Marketing 101 and build products that people want and are willing to pay for, I believe, is the root of the problem. It is not the smart meter that has failed, but the utility business cases presented to consumer with thinly veiled consumer benefit packages. These packages are being quickly disrobed, by the consumers themselves I might add, as another effort to raise rates and increase utility revenue. I applaud the smart meter manufacturers for trying to step in as responsible players. Their main problem is that the real players are still sitting in the stands watching the game. Unfortunately for them (the utilities), they do not fully realize the changing game rules, nor do they see the new players standing in the wings ready to run onto the field. Most of the existing utility players will not be around in the near future, and the changes will come fast and furious. Richard G. Pate Pate & Associates
To contribute to the Transmissions department, please e-mail your submission to intelligentutility.editor@energycentral. com. Provide your name, address and daytime phone number. Letters may be edited for style and space.
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THE BIG PICTURE
DMEA finds common ground in diverse constituency ++The focus: What’s in it for the members? By Phil Carson WEST OF COLORADO’S CONTINENTAL DIVIDE, WHERE THE
W WW.INTELLIGENTUTILIT Y.COM /// JULY/AUGUST 2011
Gunnison River drains a vast and varied topography, a small rural electric cooperative has maintained a face to the future since President Taft dedicated the local South Canal for irrigation in 1909. In those days, just bringing water and, later, electrification to the region were the simplest priorities. Both resources served traditional farming and ranching needs and the small towns that sprouted here.
10
Diverse constituency a challenge Today the Delta-Montrose Electric Association, or DMEA, distributes electricity to not only farms and ranches but also two large coal mines, an array of commercial and industrial customers and urban and rural homes. Commercial customers range from dairy farms to a candy factory, from snowboard and fly rod manufacturers to aerospace-related industry. DMEA serves about 35,000 metered accounts across Montrose County, most of Delta County (except the town of Delta) and part of Gunnison County. To serve this sprawling territory, DMEA has embraced strategies and technologies that drive out operational costs and prepare it for future contingencies. Its first challenge is to unite its diverse constituency around common goals. The co-op membership’s diversity was on display in recent town hall meetings led by the National Rural Electric Cooperative Association (NRECA), where co-op members ranged from conservative ranchers to latter-day hippies. One observer noted the meetings’ “heated discussions” and “highly charged” atmosphere as locals aired their disparate perspectives and concerns about DMEA’s initiatives. Yet common cause emerged around support for DMEA actions to help the local economy, promote local self-sufficiency and adopt measures to control costs over the long run. Utility side first The advent of deregulation more than a decade ago jolted this co-op. Large power providers might cherry pick the co-op’s largest industrial customers, skewing the rate base and sending bills sky high for residents and small businesses. Thus began two decades of innovation. In the 1990s the co-op began to market and install geothermal heat pumps and joined other co-ops in providing members with Internet connectivity via a fiber-optic network. In the 2000s it experimented with fuel cells and the potential of vehicle-to-grid power, drawing the interest of BusinessWeek. Today the co-op
is adding hydro power on the South Canal and offering shares in community solar arrays that will provide the limit of local generation (5 percent) allowed under DMEA’s contract for bulk power from Tri-State Generation and Transmission Association, Inc. Power from methane gas and biomass is being explored as well. But these high-profile projects shouldn’t obscure the co-op’s dedication to its membership’s fundamental need for low-cost power and a degree of control over its destiny. “Our philosophy is to drive out costs through technology, best practices and energy efficiency for us and our customers,” said Steve Metheny, assistant general manager.
“If we provide members with energy usage information, that puts control in the members’ hands,” Metheny said. “We’re testing now to determine how many members would use such a system.” Engaging DMEA’s membership and providing them with energy management tools underscores the co-op’s essential mission, according to Dan McClendon, the co-op’s general manager. “We try to give people the education and the technical tools to manage their electricity use to help themselves and the group,” McClendon said. “But education doesn’t happen overnight.” DMEA’s consistent outreach should pay dividends as the conversation with its membership becomes more complex. While the co-op has conducted a direct load control If we provide pilot program for hot water heaters since 2005, topics such as prepay, time-of-use rates, in-home members with displays and, inevitably, future rate increases are coming to the table. energy usage Smart grid 3.0 will be when the two sides interact productively, perhaps employing distributed information, that generation, energy storage, dynamic pricing, electric vehicles—you name it, co-op managers puts control in the say. Moving forward will require consensus. Mark Kurtz is DMEA’s newly hired smart grid members’ hands. coordinator. While he recognizes the co-op’s diverse membership, he says they’re not that far apart on concerns about environmental impacts and interest in energy efficiency. He knows that messaging around future initiatives will be crucial. “‘Smart grid’ has a bit of tar on it now,” Kurtz said. “We’ll build message around ‘empowering the consumer.’ So our messaging will be: ‘Your bill may increase by x amount, but if you use these tools, you can mitigate that increase.’”
“
”
Members and smart grid 2.0 On the membership side, which Metheny dubs “smart grid 2.0,” the co-op must answer the basic member question: “What’s in it for me?”
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
The utility side of this strategy has in the past included implementing a SCADA system and an AMR system with interval meters. Today it means analyzing life-cycle costs when considering technology choices in general, and adopting a meter data management system in particular. By participating in NRECA’s multi-utility, stimulus-funded project, DMEA will also assess its members’ interest in prepaid accounts, in-home energy displays and direct load control measures.
Sticking with the basics Preparing for a newfangled future is all well and good, but down at the Elk Creek Mine near Somerset, the main concerns remain cost and reliability—and predictability. Mine operator Oxbow Mining LLC uses nearly 40 million kWh per year to produce its high-BTU, low-sulfur coal, which serves power plants east of the Mississippi. Along with Arch Coal, Inc., the two mines are the co-op’s largest customers and the county’s highest taxpayers. Electricity costs directly influence Oxbow’s cost per ton and thus revenue and profit. Reliability is critical to operations; the mine has no meaningful backup power. Predictability, however, involves visibility into the future on costs and business sustainability. So the mines have vital reasons for keeping track of DMEA’s direction. “DMEA has been good to notify us of proposed changes, including rate increases, in the past,” said Rob Bowman, a financial analyst at the mine and a newly minted member of the co-op’s advisory board. Sticking with bottom-line basics, while reaching for the best practices of the future, has garnered DMEA its share of attention from the outside world. “A large part of our success is how we share and promote our experiences,” said McClendon, the general manager. “We let the world know what we’re trying to do. We build relationships at the state and federal level. They hear our story. Among our co-op peers, more and more of them are working on the kinds of things we’re working on. So I’m glad our story is getting out.”
11
THE BIG PICTURE
PROJECTS AT A GLANCE By Kate Rowland
The project list at DMEA is lengthy. Here are a few
information on the project is available here:
more salient details about each, with links to even
http://www.dmea.com/index.php?option=com_
more information.
content&view=article&id=65&Itemid=100
HOME ENERGY EFFICIENCY
COMMUNITY SOLAR ARRAY
DMEA has provided an online “Home Energy Savers”
As of April 2011, DMEA’s community solar array
booklet, offering tips to customers on saving
was fully leased, and the co-op is exploring a
energy and money at home. It can be viewed here:
potential second phase to
http://www.dmea.com/index.php?option=com_
the project. In the first
wrapper&view=wrapper&Itemid=105
phase, both residential
The co-op also offers its customers
and business co-op
home appliance rebates, explained here:
members were offered
http://www.dmea.com/index.php?option=com_
the opportunity to lease
content&view=article&id=74&Itemid=107
a portion of DMEA’s two
KILL A WATT METERS
10-kW photovoltaic solar electric arrays, with leases
DMEA last fall donated 15 Kill A Watt electricity
starting at a one-time
usage monitors to the libraries within the company’s
$10 payment, ranging up to
service territory. These devices can now be checked
$10,000 worth of capacity.
out, like any other library materials, and used by
Members leasing a portion
members at home to plug in their 110-volt home
of the solar array receive
appliances and other electronic devices to deter-
a credit on their electricity
mine their electrical draw and the resulting cost.
bills each month for the electricity their portion of the array produces.
SOUTH CANAL HYDROPOWER PROJECT The South Canal Project, a combined effort between DMEA and the Umcompahgre Water Valley Users Association, is part of the two groups’ commit-
W WW.INTELLIGENTUTILIT Y.COM /// JULY/AUGUST 2011
ment to developing western Colorado’s hydropower
12
potential. The two filed for a federal release of power privileges to use the run-of-river flow of water coming through the Gunnison Tunnel for approximately six MW of generating capacity. The hydroelectric plant, announced in September 2009, is considered one of the largest renewable energy facilities in western Colorado. The project has an historical connection, as well as the added bonus inherent in being a runof-river project: no dam construction in necessary. As far as the history is concerned, the six-mile
Each $10 block leased provides members with 2.67 watts of solar capacity in the array (an estimated annual bill credit, per $10 block, of about 50 cents). More information is available here: http://www.dmea.com/index.php?option=com_ content&view=article&id=156&Itemid=101
NET METERING DMEA’s net metering policy encourages its members to install solar, wind, hydro and other renewable generation devices up to 25 kilowatts (aggregate nameplate capacity at one metered location) to either fulfill or partially fulfill their own electricity requirements. Interconnection standards are also set, and applications must be made to the co-op. Information is here: http://www.dmea.com/images/
Gunnison Tunnel was first opened in 1909 by
stories/PDF/netmetering_policy.pdf
then-U.S. President William Howard Taft. More
—with files from the Delta-Montrose Electric Association
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Regulatory << Intel >>> is in play—within certain circumstances—in new electric utility cyber security legislation currently moving through Congress, both via the U.S. House of Representatives and the U.S. Senate. So, too, is the potential reach and control of the Federal Energy Regulatory Commission (FERC) being stretched by the proposed new legislation. It’s an issue with the potential to draw a line in the sand with regard to federal versus state regulatory control over certain aspects of the electric grid, and it’s already being met with sparks, albeit polite ones ... so far.
electric energy from generating facilities needed to maintain transmission system reliability.” It’s important to note the last part of this definition: “The term does not include facilities used in the local distribution of energy.” Nor does it apply to Alaska and Hawaii, or to some transmission facilities. On August 8, 2005, the Electricity Modernization Act of 2005 (Title XXI, Subtitle A, of the Energy Policy Act of 2005, or EPAct 2005) was enacted into law. EPAct 2005 added a new Existing pracsection 215 to the FPA requiring a FERC-certified Electric tices should be Reliability Organization (ERO) to develop reliability standards, enhanced, not which are subject to FERC review and approval. Once preempted, by approved, these reliability standards become mandatory and grid cyber secumay be enforced by the ERO, subject to FERC oversight. rity legislation. In July 2006, FERC certified the North American Electric Reliability Corporation (NERC) as the ERO.
Defining the bulk power system Let’s begin this chapter in the latest regulatory saga by assessing the current definition of the bulk power system. Under the Federal Power Act (FPA), Part 39 (Rules Concerning Certification of The Electric Reliability Organization; And Procedures For the Establishment, Approval and Enforcement of Electric Reliability Standards), the bulk power system is defined as “facilities and control systems necessary for operating an interconnected electric energy transmission network (or any portion thereof), and
Rocking the boat But there are new waves rocking the boat. Approximately two years ago, both the U.S. Senate and the U.S. House of Representatives began drafting legislation designed to protect grid reliability and to defend energy infrastructure from cyber and physical attack. New drafts of those proposals, strikingly familiar in their structure and wording to those of two years ago, appeared in Congress earlier this year, and were widely discussed in May and June, as this issue of Intelligent Utility went to press. In both cases, it was
FERC versus NERC ++A cyber security showdown? By Kate Rowland
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THE DEFINITION OF THE BULK POWER SYSTEM
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REGULATORY INTEL
clear that the federal government intends to redefine FERC’s FERC-approved critical infrastructure protection (CIP) powers and control over both the bulk power system and reliability standards are one of only two sets of mandatory “defense critical electric infrastructure” (defined, essentially, cyber security standards in place across the critical infraas anything not currently covered by the legal definition of structures of the United States today. In addition, NERC’s the bulk power system)—even if only for three-level Alert system informs the purposes of “protect(ing) the bulk industry and recommends pre(Current procedures) power system and electric infrastructure ventative actions to address critical to the defense of the United States imminent and non-imminent do not provide an against cyber security and other threats cyber threats and vulnerabilities. and vulnerabilities” (according to the Grid “These existing practices should effective and timely Reliability and Infrastructure Defense, or be enhanced, not pre-empted, by GRID, Act proposed by the U.S. House of grid cyber security legislation.” means of addressing Representatives). In the opposite corner The discussion draft proposed by the urgent cyber On the other side of the arguSenate has similar intent. ment stands Joseph McClelland, or other national In this corner director of the FERC Office of Understandably, this has created quite Electric Reliability. In a presentasecurity risks. a stir, primarily focused on the roles tion similar to his Senate testiof FERC and those of NERC, and the mony, McClelland told the House question floating above it all is quite simple: Why is FERC subcommittee that the procedures used by NERC, while being granted new, overriding powers, flying in the face of “appropriate for developing and approving routine reliabilthe established role of the ERO? ity standards ... can be an impediment when measures or In a letter to U.S. House Energy and Power Subcommittee actions need to be taken to address threats to national secuchairman Ed Whitfield (R-Ky.) and Ranking Member Bobby rity quickly, effectively and in a manner that protects against Rush (D.-Ill.), American Public Power Association (APPA) the disclosure of security-sensitive information.” president and CEO Mark Crisson said that, while the APPA The current procedures used under Section 215 for the supports new authority for FERC to issue emergency development and approval of reliability standards, orders in the event of a grid security event, provisions in the McClelland said in written testimony, “do not provide an GRID Act giving federal regulators increased authority to effective and timely means of addressing urgent cyber or regulate electric industry cyber security vulnerabilities are other national security risks to the bulk power system, par“unnecessary and overly broad.” ticularly in emergency situations. Certain circumstances, Further, he wrote, the vulnerabilities provisions of the such as those involving national security, may require immeGRID Act “could allow FERC to rewrite the entire man- diate action, while the reliability standards procedures take datory and enforceable standards the electric utility too long to implement efficient and timely corrective steps.” industry has worked on for nearly eight years.” The GRID Act, as drafted, would also allow the commission to enact Ignoring the elephant standards without first consulting with utility experts on Interestingly enough, the other elephant in the room remains unaddressed by most parties to the discussion: the reliability efforts, he noted. Gerry Cauley, NERC’s president and CEO, says that, expansion of control—no matter whose—to include not while government authority to deal with cyber emergencies only the bulk power system as currently defined, but also is needed, and NERC stands ready to assist in responding “defense critical electric infrastructure.” Distribution systems were intentionally excluded from to identified grid security threats, there are definite issues with the GRID Act, as drafted. In his written presentation the jurisdictions of both FERC and NERC in Section 215 to the House Energy and Power Subcommittee at the end of of the FPA, as Cauley pointed out in his Senate Committee on Energy and Natural Resources testimony earlier in May. May, he said: “NERC’s mission is to ensure the reliability of the North “If the intent is to expand the scope of authority for electric American bulk power system. This responsibility encom- system security into distribution systems, this is a critical passes the security of cyber assets essential to the reliable issue requiring involvement of the states, and also calls for operation of the electric grid. NERC works with government consultation with asset owners and operators and other agencies, industry and consumers to support a coordinated, stakeholders who should be included in such a process,” he comprehensive effort to address grid cyber security. NERC’s told the committee.
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Washington, D.C.-based law firm Patton Boggs—for some transmission insights.
Establishing coherent policy ++Ex-FERC commissioner Suedeen Kelly provides transmission insight By Phil Johnson ON MAY 19, 2011, THE FEDERAL ENERGY
Regulatory Commission (FERC) issued a Notice of Inquiry, or NOI, asking industry opinions on how to approach future transmission incentives. (FERC in 2006 had issued Order No. 679, relating to incentives for transmission projects.) The FERC NOI uses the phraseology, “given the significant changes in the electric industry and FERC’s experience in applying Order No. 679.” We asked former FERC commissioner Suedeen G. Kelly—who served on the commission from 2003 through 2009, and is now an energy-industry specialist at the
INTELLIGENT UTILITY
What factors should FERC consid-
er in evaluating an application for transmission buildout incentives? KELLY It depends on the objectives. When the commission announced Order 679 in 2006, it was responding to the Energy Policy Act of 2005, which authorized the commission to provide incentives for transmission. Frankly, the commission couldn’t reach a consensus in Order 679 about what the goal of transmission incentives should be. So what the commission passed was an order that simply didn’t answer that question. Effectively, what FERC was saying is, we’ll work this out on a case-by-case basis. But really, there still isn’t a coherent policy that’s come out of it. So that’s what this current commission seems to be trying to accomplish. INTELLIGENT UTILITY
What obstacles are faced by trans-
mission developers, and what incentives are best suited to addressing those obstacles?
Again, it all depends on each project. What’s interesting to me is that the industry has changed.
KELLY
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REGULATORY INTEL
When Congress passed the Energy Policy Act of 2005, it was a statute that had actually been negotiated in about 2003. So the provisions in that statute were dealing with the world as we knew it in 2003. There was concern that not enough capital was going into transmission relative to generation. Also, the concern was that we needed enough transmission to ensure that these new competitive generators could get to market, and we were seeing “congestion”—or, in other words, not enough transmission. But by 2006, when the commission implemented its order, we were starting to get more build-out of transmission. So the debate was, “Do we need incentives now for building out transmission?” And some commissioners thought, “Yes,” and some commissioners said, “It should be tailored to different kinds of projects.” As we’ve seen this incentive program implemented from 2006 till now, the industry has changed even more. The new public policy issue is transmission for getting to new renewables, to reach renewables and bring them to market. INTELLIGENT UTILITY
How should the commission con-
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sider changes in cost estimates?
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KELLY The question is: When a utility says it’s going to cost $800 million to do this transmission project, should the commission use that cost estimate? If the commission then awards “construction work-inprogress”—allowing the utility to start recovering investment costs while construction proceeds—should the commission hold the utility to the cost estimate as a cap, as an alternative way of containing costs? The argument on the other side is: If that’s the approach the commission takes, everybody’s going to say, “It’s only an estimate—you never know how much it’s really going to cost.” So if that’s the commission’s policy, you’re going to send a signal that people should highball the cost estimates. INTELLIGENT UTILITY
What other factors should the
commission consider in implementing the law?
We have to ask: What’s the commission’s goal going to be? Should the commission look at a project and say, “How risky is this? How hard is it to get permits? How difficult is it to build? Should we give incentives to help overcome particular barriers and difficulties associated with the particular project? Or do we look at what the project is going to accomplish from a public policy perspective?” In other words, is this—from a public policy perspective— the kind of project we want to incentivize or maybe even reward? Say, reaching renewables, or bringing in Canadian hydro, or building a tie-line to Canada, or a project that has the potential to interconnect the three grids. Or a third possible way the commission could approach this is the way it approaches the building of natural gas pipelines, which is to say, “It’s all important—the build-out of pipelines is an infrastructure we want to encourage.” So the commission could say, “At this stage in the evolution of our grid, we just need more transmission, and we want to encourage it. So we’re going to give incentives to every transmission project.” KELLY
INTELLIGENT UTILITY
How do you view future electricity
transmission—in 2015, or 2020?
It has to do with, “Where are we headed?” We usually build transmission because we need more transmission. But if we don’t need more generation The new public policy or need to move generation from one place to issue is transmission another, we don’t need more transmission. for getting to new Having said that, however, there are states renewables, to reach that are pursuing renewable portfolio stanrenewables and bring dards: Texas, California, Colorado, New England them to market. to an extent, New York to an extent are pursuing bringing new generation on line. And we are also seeing the potential for replacement of existing generation with new generation. So we will need transmission. KELLY
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INTELLIGENT UTILITY
Is there one point you’d like to
make that we haven’t discussed? KELLY The one point I’d like to make is that achieving a consensus on what we are trying to accomplish with transmission is, first, the key to a good transmission policy and, second, the most difficult thing to achieve. Phil Johnson is a freelance writer and speechwriter.
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Distributed Generation Redux Solar solutions ++Distributed load or microgridding—or both? By John R. Johnson BORREGO SPRINGS, A PROGRESSIVE DESERT
community located in San Diego County, is well known as a year-round center for astronomy research. In fact, the small town situated on the edge of the AnzaBorrego Desert State Park was designated as California’s first International Dark-Sky Community to keep the star gazing sky as clear as possible. When the community isn’t looking to the nighttime stars, its residents are embracing the sun—specifically, the vast potential from solar power. San Diego Gas & Electric (SDG&E) recently received a $10 million grant from the U.S. Department of Energy and the California Energy Commission to build a complex micro-grid project based in Borrego Springs.
OMS/DMS laboratory in action “This project is a ‘laboratory in action,’ where we can see, on a small scale, a version of the smart grid all the way from customer-generated solar power, to battery storage, to automatic power restoration,” said Tom Bialek, chief engineer of the smart grid for SDG&E. Bialek said that SDG&E will also use the project to integrate outage management system/distribution management system (OMS/DMS) into the microgrid operations. The utility will also have the ability to intentionally island all Borrego Springs customers in response to system problems like outages. A microgrid is essentially a small version of an electric grid that utilizes distributed energy resources and state-ofthe-art controls and equipment to enhance grid operation enough to achieve a 15 percent reduction in feeder peak loads, while increasing reliability. Ideally, microgrids promote energy independence within a certain community, potentially allowing ratepayers to be totally sustainable and exit the larger utility grid in favor of power from their own renewables like solar and wind.
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ILLUSTRATION BY MELISSA DEHNER
Riding it through Under clear desert skies, SDG&E will test and deploy various smart grid technologies including energy storage, smart meters, energy-management systems and integrated renewable energy generation. The goal of the three-year project is to demonstrate how to maintain reliability in a more complex grid, leverage distributed resources to benefit the community and electric system,
enable more active participation by smart-meter-enabled customers, and maintain power—or “ride through” an outage—even when the larger grid is experiencing problems. In addition, the federal funding will help to install solar power generators at homes and small businesses, coordinate new peak load management technology, improve overall power quality and integrate and remotely control distributed generation storage devices to allow access to electricity in emergencies. The project will also provide research on the potential impact of electric car charging on the grid.
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DISTRIBUTED GENERATION
Challenges driven by legislation Driving the Borrego Springs project is California legislation that requires the state’s utilities to buy 20 percent of their power from renewable sources like solar and wind. That percentage increases to 30 percent by 2020. Integrating the new energy sources, as well as energy produced by homeowners with solar panels, can be a challenge for utilities, which is why the Borrego Spring project exists. Assuming that hurdles like energy storage can be ironed out, Residents are the microgrid project could have the potential to provide 15 MW embracing the of electricity, enough to power the entire Borrego Springs comsun — specifimunity. At present, 75 homes have installed solar power in the cally, the vast community, with a cumulative output of just under 800 kW. potential from While the solar conversion growth rate for Borrego has not solar power. been forecasted, the California Energy Commission’s growth forecast for the state calls for solar installs to grow 37.5 percent this year and next. There are currently about 200 MW of solar generation in the California grid.
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Coping with the challenges Like most utilities, SDG&E is trying to cope with the many challenges of smart meter deployment, like how to roll out smart meters and capture customer engagement, how to best plan for distributed resources like solar that can be intermittent at best, especially during San Diego’s foggy months, how to convert on a 10-year smart grid plan that includes items that are not even possible yet technology-wise, and how to best evaluate the slew of new technologies headed to the utility market. The purpose of the Borrego Springs microgrid project is to examine all of those issues and much more. For example, during the spring, San Diego is hampered by two months of thick fog, which creates havoc with the utility’s ability to process power generated from rooftop solar systems. “If you know anything about San Diego, we have May Gray and June Gloom coastal fog which travels pretty far inland,” said Bialek. “It tends to burn off by noon, but you get little pockets where there are no clouds, and output of PV systems increases dramatically. Then the fog closes back in, creating significant power fluctuations which our voltage regulation equipment tries to keep up with during those short periods of time. So there are issues associated with penetration of PV and we’re trying to be pro-active about that.” While the integration of all the different IT components and communication systems represents one of the larg-
est challenges in the project, “the real challenge is looking at some of the smart concepts around customer empowerment and trying to get customers to participate in the smart meter program,” said Bialek. “Based on their participation level, then you modify the output of generators to compensate for demand.” Multi-technology testing ground So far, smart meters have been deployed to all 2,800 customers in Borrego Springs. SDG&E is 98 percent complete in rolling out 1.4 million smart meters to its entire customer base. Studies show that smart meters can help homeowners to save between 5 and 15 percent on their utility bills by conserving energy. At present, two 1.8 MW diesel generators are being retrofitted and will be installed at the substation in August for factory testing. SDG&E has completed an RFP for energy storage components, with expectations that energy storage will be installed during the second quarter of 2012. Homes with existing solar and those that add solar during the course of the project will be equipped with home solar generators. The entire microgrid project is scheduled for completion during the first quarter of 2013. The Borrego Springs project will also serve as a test ground to define the future technologies needed to effectively run a smart grid and integrate renewable energy sources. Today, smart meter technology alerts a utility when a customer’s power is disrupted. Eventually, technologies will become sophisticated enough to send alerts when a system is about to fail, and remedy a potential problem before it occurs. During this self-healing process, grid switches will automatically re-route power to restore an outage without any human intervention. For now, that remains a challenge. For example, in the smart grid deployment plan filed recently by SDG&E, technologies do not exist yet to support many of the concepts included for 2015 and beyond. Bialek says that commercially available energy storage options, equipped with the functionality to run certain types of protocols or scenarios, are still a couple of years away. “There are a lot of concepts there,” said Bialek, “but not a lot of hardware or software yet to provide a solution. That’s a major challenge for a utility like us. That’s why the Borrego Springs project is so important.” John R. Johnson is a Boston-based freelance writer covering wireless and RFID technology, as well as alternative energy topics.
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Utility Mobility
Integrating mobile solutions ++Utilities describe their challenges, successes and lessons learned By Kate Rowland AN INTEGRATED MOBILE WORKFORCE MAN-
agement platform—tying in field management,
outage management, customer information, geospatial information and other systems—provides utilities with the ability to transform the way field work is performed. It can improve restoration times, increase customer satisfaction and increase overall productivity, thereby lowering cost. These were the goals of the mobile dispatch project launched by Exelon Business Services’ two electricity distribution companies, ComEd and PECO. The project was featured in the January/February 2011 issue of this magazine, and a
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a deeper dive into this project, as well as new mobile workforce management projects implemented by JEA (formerly Jacksonville Electric Authority) and Vectren Corporation. The challenges faced were different in scope, the
successes notable, and the lessons learned definitely worth sharing here. Edited for length and style, panelists Jackie Scheel (manager of water and sewer customer service re-
sponses for JEA), Mark Browning (director, IT ComEd Solutions, Exelon) and Rich Schach (vice president of energy delivery, Vectren) offered numerous utility insights. A few are shared here.
ILLUSTRATION BY KEVIN HOWDESHELL
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subsequent Intelligent Utility Realities webcast in April took
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UTILITY MOBILITY
I asked about the cultural changes associated with adding new technologies to the mix in the field, and the types of technologies being incorporated with the field services groups at each utility. SCHACH It’s kind of interesting to watch. Like all utilities, and probably a lot of industry, we’ve got an aging workforce and we’re going through quite a transition with retirements and the like. What’s interesting, and it’s probably just a sign of the times, is that as we bring in these people to our organization who have had a little more access to the iPhones and the games and things that this generation is used to, not only are we not seeing a cultural issue, but we’re seeing, “Why can’t it do this?” or “Why can’t it do that?” The whole world is changing around us, and we’re actually getting in a generation of folks that not only find it easier to use, but also are helping us find ways to make it better. Now, having said that, we still have a considerable workforce that has been around for a long time and we spend a lot of time trying to ensure that we keep their training up to speed. We are providing a lot more communication about what the value is and trying to have them recall what they used to do compared with what they do today. What we’re seeing is that even those folks who at the beginning were just dead set against a laptop in the truck, I’d venture to stay that at least 80 percent are more than happy to have it and would be upset if you took it away.
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SCHEEL Historically, prior to 2007, we used some type of Toughbook. Sometimes, this is where you ask, okay, if you come from nothing, then you can introduce folks to anything new. We did try, and then when we went to make the change to what are we going to use in the future, we tried the PDAs. The folks did not like them: they said they were too small, they couldn’t see them.
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For me as management, I love the PDAs. But they did not like them. We even tried the tablets. I have to give kudos to our IT department. They said, okay, here’s what you have; take them and use them. But we voted on just a regular laptop. You can buy three laptops versus one Toughbook, and not all the trucks are so rough that they require a Toughbook. Now as far as field services, which is where I came from, I would strongly encourage the PDA if you can. But we have not engaged our employees enough. They are a little resistant to it, and right now, we’re not pushing that venue. We just use regular laptops with aircards that go into base mounts installed in the vehicle. But I would love to use PDAs. If it could start out that way, I would never give another option. We started out thinking that we were going to deploy a lot of different form factors, a lot of different tools. Early on in the project, we quickly realized that the majority of users viewed the tool as something that was going to remain in their vehicle and that they wouldn’t be carrying it around. And it was really the taking it out of the vehicle and using it in various ways that we thought—in terms of collecting information in substations, making rounds and the like—would drive the need for different form factors. But we didn’t see that big push to drive to multiple form factors. So, we really took a one-size-fits-all approach for the project, and now, almost two years post-project, we’re starting to see maybe a revitalization of this drive for new form factors. I view it as a maturity and an evolution of the technology. The ruggedized laptop in the vehicle is probably something that solves 80 percent of our business problems, and now that 20 percent is driving the need to start to look at different form factors, in the form of smart phones and PDAs, that maybe synch with the device to go out, collect some form information and come back and sync with the vehicle’s MVT and push the information back up. So a lot of evolution, I think, is going to occur there over time. BROWNING
The field worker was
I asked each panelist about guiding principles or key les-
provided the same
many that were discussed.
level of functionality and capability that an office worker in our environment would have. MARK BROWNING
sons learned with their deployments. Here are a few of
BROWNING We approached this project as an extension of the edge of corporate network. This is an important piece in that we did not set any limitations or boundaries over what the field worker could do. The field worker was provided the same level of functionality and capability that an office worker in our environment would have. A fully enabled Web browser would allow them to leverage the corporate intranet and the Internet to perform their various work functions. And this was a key component that I think really helped our project gain traction with the field workers. It demonstrated trust in the field workers, trust that management had in their ability to use the tools, and it gave them an opportunity to look at how they could do their job in
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UTILITY MOBILITY
a way that was most effective for them versus how I think management and the project team might have viewed how they would use these tools. And then finally, with deploying a mobile solution to 3,000 users who are all mobile, constantly changing, moving around, a lot of tools and technologies need to be put in place around software management and software distribution to keep the platform current, secure, and up to date at all times.
You’ve got to test each one of your field activity types and let it write back to the system to see how it’s going to come across. JACKIE SCHEEL
I’m from the business side, but sometimes in the IT world, people say, “How important is testing?” Well, you can never contradict or even contemplate what the system’s going to do, so you have to test each one of your scenarios. You’ve got to test each one of your field activity types and let it write back to the system to see how it’s going to come across. A lot of testing is what people seem to want to cut out of their timelines, and I highly recommend you do not cut your scenario testing out. Also, a major factor to having a successful mobile workforce unit is to get your front line employees engaged and ask them exactly what it is that they want to see or they don’t want to see. They’re the ones who are going to be using the system the most. When we added the meter service agency on [Ed. Note: JEA has been building its mobile workforce management platform in stages since 1988], we more than tripled the number of users. We added 200 users, and I will tell you one of our lessons learned here was, during the testing, during the project, we did as much load testing as we could, but what we did not realize was that most of these
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users would all be signing on at the same time. So what we did realize was that, at about 7 a.m., we had about 400 users hitting the machine. So we had to go back to our IT department and add a couple of different servers. We called it “morning sickness.” I would advise anyone that, when they do their testing and they do their load testing, they consider when and how many users will be on the system at the same time. SCHACH We spent a lot of time upfront establishing the right data into the tool, and that’s proven to be just a huge part of the success for Vectren. We do a lot of work managing by performance metrics dashboards and what not. If the data’s not in there correctly in the first place, it’s tough to get buy-in from your field management. If they just don’t believe the original data, (then they won’t) believe the data the system’s now spitting out. We spent so much time early on that we’ve gotten buy-in, and now we can just move on to managing the actual work.
Panelists also discussed changing business processes with the new mobile platform.
Another key piece of the project was really looking at taking our current manual business processes and looking at how they would be implemented with the new technology. We certainly didn’t want to take a current manual process, put technology around it, and still do it the same way. There was an opportunity to leverage technology and redesign the process and we tried to do that wherever we could. A big piece of this was focusing on handoffs between work groups and ensuring the right data got out to the field at the right time for each of our users. BROWNING
SCHACH Meter order management was my largest activity, and as such, we spent a lot of time trying to figure out how we could better manage that area. One problem we had was that our labor contract had originally, some years back, forced us to treat our various operating centers across our service territory as individual operating centers—everybody sort of did their own thing, if you will. The workers were tied to those areas or depots and they couldn’t cross boundaries, and it just didn’t make sense. You could have an emergency where somebody might live literally across the street and they were not allowed to work that emergency because of the labor issue. So once we were able to break that model through contract discussions, it opened the gamut of flexibility for us to then focus on this category of work.
And finally, more keys to success, and overall benefits:
Since 2004, this cost category saved about $3 million. So, we’re operating at $3 million less than we would have then, and obviously that’s a number that’s going to continue on in the future and hopefully even get better. We’ve SCHACH
also improved the number of orders per FTE and, in some cases, multiple more orders per FTE.
(As we’re bringing in
Another key success factor during this project was around deployment. This was a program that was cutting across six departments across two companies. We wanted to ensure success by doing a slow roll, trying it with one group, piloting where we could, gaining learnings and experience from that group and then expanding to really build momentum. And that was something I think we found was very successful. So piloting, and soliciting feedback and incorporating that into the next phase was key to ensuring that anything that was working we build on and things that weren’t working so well we tried to address as we moved through the project. BROWNING
Everything is tied in [with regard to vehicle tracking]. In fact, we’re in the middle of a GPS project, too, that will tie everything back in together into this one. We do have the vehicles tied into the laptops. We have to do that for anyone who lives in a hurricane area, for FEMA recovery. We have to be able to track the vehicle that went out there with the work order. I believe you could only do that with some type of workforce management. I don’t see how you could do that on a piece of paper. SCHEEL
new people) we’re seeing, “Why can’t it do this?” or “Why can’t it do that?” RICH SCHACH
The webcast, “New Mobile Workforce Management: Insights to Increase Your ROI,” is free for viewing http:// intelligentutility.com/ resource/demand-webcast/ new-mobile-workforcemanagement-insightsincrease-your-roi
Smart Grid Easy Rider Scott Stein – Motorcycle enthusiast, swimmer, father, golfer, Project Management Professional, AMI implementation expert
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» COMMUNICATIONS NETWORKS
No one size fits all ++Network of networks requires combination of solutions By Kate Rowland THE DISCUSSION HAS LONG BEEN BREWING: SHOULD OUR
smart grid networks be public, private or a combination of both? Within utility projects and deployments, we’ve seen very clearly that one size doesn’t fit all, no matter what the technology, software or system being implemented. Just as the smart grid is a network of networks, so, too, are the network needs within it.
W WW.INTELLIGENTUTILIT Y.COM /// JULY/AUGUST 2011
Dispelling myths But as the debate continues, the Utilities Telecom Council (UTC) opted to discuss the issues and dispel some myths in a February 2011 document titled “The Truth About Utility and Other Critical Infrastructure Industry Telecom Capabilities and Needs.” “CIIs (critical infrastructure industries) will ultimately choose to build their own networks or buy telecom services based upon technical requirements, costs and levels of service required. CIIs have and will continue to utilize others to provide telecom services for certain aspects of their operations and smart grid deployments based upon these criteria,” the UTC paper noted.
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Based upon its unique needs, the distribution utility chose a two-way mesh radio network that would allow it the flexibility to accommodate cellular, broadband or fibre WAN backhaul capability. More specifically, Hydro One’s AMI solution architecture is comprised of a two-way self-healing mesh radio network based on the global 2.4 Ghz IEEE 802.15.4 standard. The solution provides the utility with the futurelooking flexibility to accommodate cellular, broadband, or fibre WAN backhaul capability. By integrating standards-based mesh radio and WiMAX wireless technology, the utility will be able to implement a broad spectrum of initiatives, including distribution automation, outage management, theft detection, remote disconnect, mobile work dispatch, twoway communication home thermostats and real-time energy monitors, and more.
Avista chooses broadband route Subtle issues at play Historically, the issues that have come up in the public/private network debate Others have gone the private route, have centered around cyber security and standards issues. Public carriers point to as well. In Pullman, Wash., Avista the fact that they have already solved the very same issues utilities are now facing Corp.’s smart grid demonstration project will incorporate an advanced in both areas, and can offer both best practices and state-of-the-art technology. metering infrastructure But while utilities may be exploring public net(AMI), smart grid comworks in certain areas, such as distribution, the arOne size doesn’t fit munications and distribueas of transmission and generation still tend toward tion automation devices private networks, for a number of reasons. all, no matter what using a private wireless Regulatory structure also plays a part in utility broadband communicanetwork decisions. While in the United Kingdom, the technology, tion network. According the regulatory structure really favors the public to Jim Corder, Avista’s market, there is still a real incentive for utilities in software or system director of IT infrastructhe United States to own their own networks, takture, the choice will aling the private approach. being implemented. low the utility to bridge Hydro One chooses mesh solution the two network techAs but one example, Hydro One Networks Inc. opted for the mesh network nologies while reducing the number route for its communications. Owned by the province of Ontario and the prov- of devices the utility has to manince’s largest electricity distributor with a service territory land mass twice the age and support. “We’re expecting size of the state of Texas (123,000 kilometers of distribution lines and a 640,000 the network will meet or exceed all square kilometer service territory), Hydro One’s customer base of 1.3 million of our performance requirements for is a mix of urban, rural and remote customers, some accessible only by air, rail, the initial smart grid applications,” boat or snowmobile. Corder said.
Texas-based Bluebonnet Electric Cooperative and Pedernales Electric Cooperative, in partnership with the Lower Colorado River Authority, piloted a public carrier solution using 3G and 4G LTE networks to provide real-time communication from their consumers’ electric meters to a central data center, empowering Central Texas residential and small commercial members to actively monitor and control their energy usage through a smart home area network (HAN) installed within their homes or businesses. Two-way communication is critical to enabling viable load management while still enabling consumers to maintain control of their energy use. Both co-ops were able to combine third-party demand response technology with a public carrier solution, leading to the potential for a broader-scale use. “Our tests on the technology during the winter load events showed the enormous potential of a load management program that benefits both consumers and utilities,” Bluebonnet CEO Mark Rose said upon completion of the pilot project.
Capx issues play a role Investor-owned utilities (IOUs) looking for rates of return might not opt for public network solutions in which the recurring expense of the public network passes through to the consumer. Large IOUs, in the current regulatory atmosphere, are motivated to be very conservative, based on their regulatory structure. As well, the historical culture of On Sept. 1, the Intelligent the electric utility industry has been one of Utility Reality webcast “build it, own it, manage it.” series will address the public/ Alternately, small utilities might find the private network question with public network solution to be the one that three utilities in the trenches, best fits their business cases. Running a identifying challenges, opportunities and lessons network is complicated, especially with learned in their deployments. a minimal number of employees already stretched in other responsibilities.
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Texas co-ops opt for public communication with homes On the other side of the coin, public networks are also being used by utilities to manage certain two-way communication aspects of the evolving grid. According to a recent EPRI white paper, “Communication Modularity: A Practical Approach to Enabling Demand Response,” an important part of the smart grid vision is “enabling communication-connectedness with residential devices so that they can be informed of grid conditions, including energy price, critical peaks and other curtailment events.” Communication to intelligent devices, the paper’s authors go on to say, rather than cutting power off with a remotely managed switch, “provides more flexibility for consumers and allows manufacturers to innovate, discovering creative ways to maximize energy savings while minimizing user inconvenience.”
No either/or necessary? Riding the wave of diverse needs, some vendors have opted for both public and private solutions for utility clients, depending upon specific yet diverse needs. With approximately 3,200 utilities across the country comes the potential of 3,200 individual needs. As standards continue to be set, these standards will allow utilities to make their own decisions based on their business cases and their individual needs. In fact, many vendors and utilities alike are no longer seeing communications networks as an either/or solution. One major player explained it this way: “I believe it’s a blended solution between private and public networks. Communications consists of a network of networks stretching across all seven domains. The bottom line? I believe there’s a place for both technologies.” Utilities, he said, need to look at a variety of factors when deciding what solution is best, and for what uses. First, it’s important to look at the actual use case. Add into the decision the cost of the particular application, the regulatory environment, latency and through-put, availability and reliability of the solution and cost and longevity, and the answer is complicated and utility-unique. Some utilities have opted to use both public and wireless, with collection points served by both, using the private network as the primary network (especially with regard to the “last mile” to the meter), and the public network as the failsafe, or the backhaul network.
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GRID(UN)LOCK
Nashville Electric Service pursues voltage conservation ++TVA’s new “demand charge” W WW.INTELLIGENTUTILIT Y.COM /// JULY/AUGUST 2011
calls for “solution on a shoestring”
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By Phil Carson THIS STORY IS A GREAT EXAMPLE OF WHY “SMART GRID”
means vastly different things to different people. It also illustrates why challenges and solutions for electric utilities tend to be utility- and location-specific. The Nashville Electric Service (NES) is employing what Vic Hatridge, vice president and CIO, calls a “solution on a shoestring” to deal with changes in how the Tennessee Valley Authority (TVA) charges for its wholesale electricity to municipalities in the Valley. Energy charge vs. demand charge TVA has traditionally levied an “energy charge” and a “demand charge” for commercial and industrial (C&I) customers within NES’ service territory. That means those customers pay for their electricity use (energy charge) and also pay
a demand charge based on their peak use during a 15-minute interval during a given month. That demand charge, of course, goes to pay back TVA for capital expenditures needed for the capacity to meet those peak electricity demands. Thus, NES’ larger C&I customers have always had demand meters that take a single high-demand reading to gauge their peak electricity consumption. Residential peak demand charge problematic Starting in April 2011, TVA began to bill NES and its other distributors a demand charge based on the peak usage during a month for all residential customers combined. This created a problem for NES and all other distributors because they were being charged for peak demand but had no way to equitably recover these costs from residential customers. Smart meters on every home could provide a means to bill each residential customer for energy charges based on their time-of-use (TOU) demand
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GRID(UN)LOCK and/or demand charges reflecting their peak use, but that’s too expensive for this municipal, distribution-only utility with about 360,000 customers. (Although modest on paper, that profile makes Nashville one of the nation’s top dozen municipal utilities, by size.)
“We need consistency and predictability of revenue and profit so we can bill our customers equitably for what they use,” Hatridge said.
Shoestring solution Instead, NES will implement a voltage conservation program on a systemwide basis to reduce peak demand and, therefore, mitigate the impact of demandbased wholesale rates on residential customers. The American National Standards Institute (ANSI) standard calls for 114 to 126 volts per residential end-user. We need consistency During peak load, NES will narrow that range to about 116-120 volts. It will use smart meters and predictability of as “continuous voltage sensors” at key sample points on every circuit. revenue and profit In this manner, NES can reduce its cost for peak-time energy use without the need to so we can bill our install a smart meter at every home in its entire service territory. Ultimately, the utility would customers equitably. like to install smart meters on every home to ensure that every customer’s voltage stays within the ANSI standard and to achieve the many other benefits that smart meters provide. TVA and NES are cooperatively involved in this solution, which should be fully operational by this time next year. “Over the past 20 years, our retail rates have been what they call ‘end-use rates,’ which means that we paid TVA for wholesale power in the same way we billed for retail power,” Hatridge told me. “For example, retail customers paid a flat rate per kilowatt hour, so we reported to TVA how many kilowatt hours we sold to retail customers and paid TVA a flat charge per kilowatt hour for that power. For those large commercial and industrial customers that we billed for a demand charge, we reported that customer’s demand to TVA and paid TVA for that demand.” For residential customers, because NES only collected and passed through costs for energy consumed in kilowatt hours, NES received a guaranteed margin.
Cost-effective win-win solution These changes may mean that NES sells less electricity overall, though ideally it would like to maintain the amount it sells, just shifting consumption to off-peak hours. “On a hot summer day when we’re trying to conserve power, we can actually turn down your voltage to, say, 116 volts,” Hatridge said. “This won’t affect the performance of a customer’s electrical equipment, but it will reduce peak load. It will maintain a more consistent margin for NES and it will save the customer money because they will consume slightly less energy. We’ve prevented a brownout by making a slight adjustment in voltage that’s within the acceptable range.
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W WW.INTELLIGENTUTILIT Y.COM /// JULY/AUGUST 2011
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Changing the face of the Tennessee Valley “What happened to us, as of April 1, is changing the face of the Tennessee Valley,” Hatridge said. “TVA is now going back to an old system of charging us demand charges for the energy we sell to residential customers. “This puts us at risk because we are billing residential customers at a flat rate per kilowatt hour but our wholesale cost for that power will vary. If we happen to have a really hot day near the end of the month, like we did in May 2011, our wholesale power bill from TVA shoots up much more than what we bill to our residential customers. We are concerned about how such an unpredictable profit margin will affect our financial stability.” In effect, NES will use a smart grid technique—in general, distribution optimization, in particular, voltage conservation—to manage retail rates to reflect wholesale rates from TVA.
“We think this is a very cost-effective solution,” Hatridge concluded. “We can achieve some very significant reductions in peak energy demand at a reasonable cost and without requiring customers to change their energy usage habits.” This article first appeared in Intelligent Utility Daily.
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to increase their electricity use even as the economy improves.
A new attitude toward energy consumption? ++Deloitte study suggests new customer diligence By Christopher Perdue
W WW.INTELLIGENTUTILIT Y.COM /// JULY/AUGUST 2011
AS UTILITIES LOOK FOR WAYS TO ENGAGE THEIR CUSTOMERS
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with new products and services, a new study from Deloitte suggests they may find an eager audience. The study, “reSources 2011,” conducted by Deloitte, polled 3,200 household decision makers and more than 400 business decision makers responsible for their company’s energy decisions or energy policy. Let’s take a look at some of the results of the study, and their implications for utilities. The study from Deloitte suggests the emergence of a diligent new attitude toward energy consumption in the United States. According to the study, 52 percent of companies are working to lower their energy costs by 25 percent on average over the next two to three years, and 68 percent of consumers are taking extra steps to cut their electric bills because of the recession. Profound grassroots movement emerging The results of the study show American businesses and consumers are in the midst of “the birth of the resourceful energy user,” said Greg Aliff, vice chairman and U.S. energy & resources leader, Deloitte LLP. “We are seeing a profound and, in many ways, grassroots movement toward energy conscientiousness among businesses and consumers.” In addition to the almost 70 percent of consumers who said they reduced their electricity bills during the recession, 95 percent said they do not intend
Energy management goals set by businesses Energy use at businesses also appears to be receiving renewed attention. Ninety percent of the companies polled for the study were setting specific goals regarding electricity and energy management practices, and nearly three-quarters of businesses now have goals related to reducing electricity cost and consumption and improving the efficiency of the buildings in which they operate. Furthermore, slightly more than half of companies have goals aimed at improving profitability through electricity reduction and nearly one-third of companies have goals to self-generate electricity through measures like installing solar panels. With utilities increasingly seeking to engage their customers with new products and services, the results of the study should be encouraging. And the proliferation of smart grid investments will provide a means to deliver and display consumption data directly to the customer. More energy use knowledge needed The news from Deloitte is encouraging, but I must admit to being a bit skeptical of some of the results. While 68 percent of consumers in the Deloitte study claim they are taking extra steps to cut their electric bills because of the recession, the reality is that annual residential kWh sales in the U.S. for 2010 were the highest on record according to the latest Electric Power Monthly report from the Energy Information Administration. This represents growth of more than 6.3 percent from 2009. This discrepancy is telling, and could speak to the lack of knowledge that utility customers have about their energy use.
This lack of knowledge was somewhat evident in the Deloitte study. One of the questions asked whether the respondent was in a deregulated environment where more than one electric company competes for your business. Over 60 percent of consumers answered that they were not sure. Additionally, consumers did not seem particularly enthused about purchasing either a “smart energy application” (18 percent said “yes”) or paying a small amount for a meter or timer control system (25 percent said “yes”). But the youngest generation (“Gen Y”) was twice as likely as the oldest (“Matures”), with 33 percent of Gen Y saying “yes” to a small amount for a meter/timer control system and 16 percent of Matures saying “yes.” That would suggest that the wholesale behavioral changes around energy practices may indeed be a generational affair.
Community education a necessity These points provide a clear indication that utilities need to invest in a solid, on-the-ground community education. Utilities cannot become so preoccupied with the implementation of physical infrastructure that they do not think through the implications of new technology and products on customer relationships or the business process. And they should not wait for their smart meter deployment to start the education push. Now’s the time We are seeing a to let customers know, in advance of the viral spread of misinformation by anti-smart-meter profound and, in lobbying interests, what smart grid efforts are really all about. Further, utilities should not assume that many ways, grasscustomers know anything more than the basics of electricity as it applies to them, and make it roots movement easy for customers to obtain the information they need. Otherwise, they will go elsewhere, and fill toward energy the information void with whatever they can find. I hope Deloitte is right, and that we are seeing conscientiousness. the birth of “the resourceful energy user.” But let’s keep in mind that there is still a lot of customer education that will be needed to supplement these new attitudes. Therein lies an opportunity.
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Christopher Perdue is vice president of Sierra Energy Group.
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4D
Location is imperative ++Geospatial data is central to Hydro One smart grid By Nargis Ladha and Erik Shepard
W WW.INTELLIGENTUTILIT Y.COM /// JULY/AUGUST 2011
HYDRO ONE IS THE ELECTRICITY PROVIDER FOR A LARGE
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proportion of Ontario and serves approximately 1.3 million rural customers, with a service territory nearly twice the size of Texas, comprised of 17,771 miles of transmission circuits, 76,429 miles of distribution circuits and more than 2 million poles. Because of this large service territory, field inventory of distribution assets or conversion of paper maps was deemed cost prohibitive, and the geographic information system (GIS) has historically focused largely on transmission assets, with some tactical support for distribution assets (predominantly focused on new designs and maintenance of a simplified schematic power system model for grid operations). New topographical model for distribution assets Hydro One has regulatory requirements to field-inspect all distribution system assets on a six-year asset condition assessment cycle. At the initiation of the last cycle, in 2005, determination was made that for a marginal additional cost, field collection could also collect GPS location and asset attributes to form the foundation for constructing a GIS for distribution assets as well. GIS technicians perform
post-processing on this field data to integrate network topology, resulting in a spatially and topologically accurate model for distribution assets. At present, more than 95 percent of the distribution system has been completed. The biggest challenge to leveraging the existing asset condition assessment program has been that the fieldcollected data used to construct the distribution model may be as much as six years out of date. Fortunately, Hydro One has current data, albeit with spatial accuracy and completeness challenges, in the tactical design and grid operations distribution GIS databases. The design database is spatially accurate, but only reflects new construction work and is not a complete representation of the network. The grid operations database is complete, but focuses on the network connectivity, excludes structures such as poles and pads, and is not spatially accurate. The consolidation of these two tactical
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W WW.INTELLIGENTUTILIT Y.COM /// JULY/AUGUST 2011
systems with the field-collected backbone is currently under way; this consolidation, together with completion of remaining feeders to be field collected, is scheduled and on target for completion by end of this year. In addition, Hydro One has nearly completed deployment of approximately 1.2 million smart meters across the province. Each of these meters is also GPS-located, as are collectors and repeaters, and will be fully integrated into the distribution GIS in 2012.
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characteristics, protection and control settings, and connectivity to the transmission system. While each of these data elements is critical, accuracy of the power systems model represented in the GIS directly determines the ability of the DMS to produce accurate results from power utilization and Driven by value power quality applications. While Hydro One has had a mature GIS for transmission To ensure data currency, completeassets for a number of years, until recently the expected ness and accuracy, Hydro One is also return on the significant investment cost for distribution completing as part of the ADS initiaGIS was found to be less compelling. Hydro One is a valuetive an assessment of distribution data driven organization that continually reassesses the technolchange control processes to ensure ogy landscape to gain new efficiencies through innovation. that all data sources are maintained, With increased emphasis on the distribution business in line and updated proactively according to with smart grid initiatives, the strategic road map for GIS business triggers rather than reactively now comprises development of a spatially accurate distribuwhen problems occur. These recomtion power system model and development of geospatially mendations will lead ultimately to enabled enterprise asset management for distribution assets implementation to protect Hydro to form a core for emerging smart grid applications. One’s significant investment in source In 2010, Hydro One initiated the Advanced Distribution data for the DMS. System (ADS) project, an initiative in support of Ontario’s Hydro One’s investment in geoforward leading Green Energy Act. The ADS project builds spatial technology directly supports on top of the successful smart meter deployment that is and is a key dependency for the sucnearing completion, and seeks to implement a distribution cess of the ADS project as well as a management system and substation automation to enable number of other strategic initiatives. the connection of distributed generation sources, including The approach currently being taken renewables. In 2010, business case development and RFP selection was underto perform full field inventory, to taken, and Hydro One is currently engaged in consolidate legacy tactidesigning and building the first project release. cal GIS systems, and to There has been a formalize and optimize More data needed distribution data change Many utilities are now finding that the data renaissance of field control policies and collected 20 years ago is not sufficient for smart procedures will ultigrid, and there has been a renaissance of field collection to improve mately support Hydro collection to improve the quality of geospatial assets One’s strategic goals as represented in the GIS. Often, only basic attribution the quality of geoa geospatially enabled on assets deployed in the field has historically been intelligent utility. collected—in some cases, only what was required spatial assets repreto drive automated mapping and facilities manageNargis Ladha is manager ment programs. sented in the GIS. of geospatial systems GPS accuracy has also significantly improved with and technology projects at Hydro One, and is higher precision collectors at lower price points. responsible for setting strategic direction Because Hydro One deferred its investment in distribution GIS, significant investfor GIS and coordinating corporatement cost savings have been realized by only doing it once. In addition, evaluawise initiatives. tion of required data completed by the selected distribution management system (DMS) vendor found that “Hydro One’s initial data availability, accuracy (for DMS Erik Shepard, of Waterbridge Consulting, is supporting Hydro One’s Advanced data model validation) and completeness is well above the industry average.” Distribution System (ADS) project as the
Populating distribution data DMS data will initially be populated by five key systems: network topology from the GIS, selected customer and load information, power system equipment
project lead for the GIS data consolidation project and as the lead for the DMS Data Change Control workstream within the ADS project.
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CONNECTIONS
Cyber security requires organic effort ++Strategist Annabelle Lee shares thoughts for utilities and regulators By Phil Carson
W WW.INTELLIGENTUTILIT Y.COM /// JULY/AUGUST 2011
IN JUNE, INTELLIGENT UTILITY DAILY EDITOR-IN-CHIEF PHIL
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Carson held a wide-ranging discussion with Annabelle Lee, a technical executive for cyber security at the Electric Power Research Institute (EPRI). Lee was formerly a senior cyber security strategist at the National Institute of Standards and Technology (NIST), where she guided and coordinated the creation of the NISTIR 7628: “Guidelines for Smart Grid Cyber Security.” Framed within the context of electric utility cyber security discussions ongoing at the time in the U.S. Congress (detailed in part on pp. 14-16), Carson’s interview spanned three days’ columns in Intelligent Utility Daily. We excerpt portions of those columns here. At the outset, I asked Lee: What can you tell utilities and regulators about implementing cyber security when standards remain in flux? Her candor was bracing. Lee referred to the enabling legislation, the Energy Independence and Security Act of 2007 (EISA 2007), which required NIST to create an interoperability framework for the smart grid. The EISA 2007 said that when NIST developed “sufficient consensus,” the Federal Energy Regulatory Commission (FERC) would post standards and invite comment. According to EISA 2007, FERC could then “adopt” standards without enforcing compliance with them. So, much hinged on what “adopt” meant, according to Lee. In a Jan. 31 meeting with panelists from utilities and the private sector, FERC Chairman Jon Wellinghoff explored whether there existed “sufficient consensus” around standards identified by NIST. The answer: “No.” “This left everyone up in the air,” Lee told me. Subsequently, FERC sought two rounds of comments on the issue (on April 8 and 22) in order to resolve the issue, but Lee acknowledged that this state of affairs has left state public utility commissions pondering how to move forward. Non-prescriptive strategy important This anecdote merely underscored Lee’s argument that a non-prescriptive approach to cyber security is an important strategy. The NISTIR 7628 is guidance that requires heavy lifting by every utility to protect critical assets. Guidance allows flexibility and innovation, while mandates tend to be inflexible. A one-size-fits-all approach cannot account for the variation among individual utilities’ legacy systems and unique risk profiles. It’s difficult to deploy tools while utilities watch as standards are developed and vendors race to provide solutions, Lee acknowledged. “This is another area where the IT, telecom and electric sector communities need to come together to figure out how to use these standards in the electric
sector,” she said. “There are some real restrictions in the electric sector that you don’t have in IT. The electric sector has remote devices, limited bandwidth and processing constraints. When you consider IT/telecombased solutions, you have to think about that. Looking end-to-end “To correctly address cyber security, one needs to look at it end-to-end,” Lee continued. “It requires examining the technical, physical, and administrative procedures. Even if FERC had adopted a specific family of standards, that would not have been the entire solution. Those would be standards designed to be applied in very specific ways. One needs to look at the entire range of security that’s needed. One may have a good technical solution; however if a person is allowed to enter your building and log onto your system, you don’t have good security.” In Lee’s view, it is most effective for each utility to designate a cyber security leader, who may have to educate upward to develop executive support for protecting critical assets. “Part of the problem in approaching cyber security is that many organizations don’t have people who understand this,” Lee said. “Utilities don’t always know the questions to ask when vendors and integrators get involved. It helps to have a person dedicated to this task, and clearly this is not something one learns overnight.” One argument that’s both substantive and convincing is that cyber security addresses business-continuity vulnerability, which is a reliability and productivity issue. “Reliability is No. 1,” Lee said. “And cyber security supports reliability. I like to tell people ‘We think we’re at the top of the totem pole, but we’re not.’ We need to support cyber security. Typically, when organizations do a generic risk assessment, cyber security is one component, not the
only component. Utilities need to look at the business case, the cost, and make business-based decisions.” “The point that I emphasize about a risk management framework is that business continuity is a form of risk management,” Lee concluded. “You have to make decisions on where to spend resources. What’s most critical to maintain the operation of the business?” In the initial column of the series (above), Lee pointed out that effective security includes components such as physical security, personnel and administratative security, operations security, communications security and computer security. She also pointed out the efficacy of thinking in terms of systemwide, end-to-end measures. “When we interconnect these systems, if there’s an entry point that’s not protected, that’s a great way to access a critical system,” Lee told me. “That means that we need to look at the security of all systems,” she said. “That doesn’t mean you spend millions and millions. The priorities should be set based on an impact level. I like NIST’s low-moderate-high approach to impact assessment where one can take a qualitative approach. In contrast, using a quantitative approach, I’ve observed people argue whether we’re at 6.1 or 6.2, and I don’t understand the difference between 6 and 7, let alone 6.1 and 6.2.” Taking the steps But, you may be asking, how does one begin taking actual steps? Don’t reinvent the wheel, Lee suggested. “Begin with your existing risk management framework and an overall security strategy,” she said. “Take that as the starting point and begin tailoring that for control systems. Does your risk management framework make sense? Does your security strategy make sense? Then put together a risk assessment. Inventory your assets. Weigh the risk of a compromise of confidentiality, integrity and availability. Determine which of those that need to be addressed first.”
Dealing with privacy Finally, Lee touched on the privacy issue regarding customer data. “Utilities have had to deal with privacy for decades,” she said. “They have customer information. The difference, moving forward with smart meters, is the granularity and frequency of the information being collected. What will utilities do with that data? Third-party organizations want to get involved, particularly from an energy management perspective. How is information shared with those vendors? Who will be responsible for the integrity of that information? “Most states have privacy-breach laws. How are those addressed by a utility? Ownership of energy use data depends on the state. It is a vexing issue that at some point will have to be dealt with,” Lee concluded.
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Applying requirements Once a utility has determined its high-priority risks, it can review and apply the “requirements” in the NISTIR 7628, “Guidelines for Smart Grid Cyber Security.” “Requirements” offer guidance to effectively address certain vulnerabilities on a systemwide basis, Lee explained. The individual utility assesses its risks and prioritizes them. To mitigate those risks, the utility selects the applicable requirements from the NISTIR 7628 and tailors them to the specific system, in order to effectively address the risk.
“When examining the ‘requirements,’ assess the ‘requirements’ for a system,” Lee said. “That’s important, because risk from a system perspective may have certain requirements that need to be implemented in some components and not in others. If one implements every requirement in every component in a system, it won’t function, performance will drop. For instance, if a firewall is required, it is typically installed at the boundary, not between every single device. Intrusion detection is also typically installed at the boundary, which is why risk must be assessed from a system perspective.” Returning to the theme that required standards may be inflexible and, therefore, less effective than guidelines, Lee said: “Standardization is important to ensure interoperability. But each utility must decide how it’s going to address cyber security. In part, the approach depends on a utility’s system architecture, the types of protocols that are being used, and the communications medium they use. The answers are specific to the technologies you’re using.”
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OUT THE DOOR
The advanced smart grid ++Viewing the trends By Andres Carvallo and John Cooper JUNE MARKED THE RELEASE OF THE ADVANCED SMART GRID:
Edge Power Driving Sustainability, a new book by Andres Carvallo and John Cooper. The following excerpt comes from Chapter 6, “Today’s Smart Grid.” State smart grid dockets The year 2010 saw progress on many state fronts in implementing smart grid plans of electric utilities. In many cases, the utilities and regulators worked well together to launch projects without major issues. In others, regulators saw themselves repeatedly put in the position of reacting to unintended, negative impacts of smart grid implementations. Viewed together as a trend line, these separate cases help us draw some conclusions.
W WW.INTELLIGENTUTILIT Y.COM /// JULY/AUGUST 2011
Oklahoma and OGE Oklahoma Gas & Electric (OGE), the recipient of $130 million in DOE FOA 58 smart grid investment grants, successfully maneuvered the regulatory process from June to August 2010 and received approval for its Positive Energy Smart Grid program. The OCC preapproved up to $366.4 million in program costs for the system, with the principal focus on smart meters. From June to August 2010, the OCC approval for a large smart grid project shone as a bright light in comparison to the other cases documented in this section.
46
California and PG&E In September 2009, California utility giant Pacific Gas and Electric Company (PG&E) faced a challenge to its multibillion-dollar AMI deployment, at the time one of the largest and most ambitious rollouts of the new technology in the world, kicking off a trend of consumer backlash to smart grid that has only grown as the year progressed. As if to prove the adage that pioneers are the ones who get arrows in their backs, PG&E was sued by consumers in the San Joaquin Valley over abnormally high electric bills that they attributed to their new smart meters. As many insiders suspected all along, the results of an official inquiry revealed in September 2010 that the meters worked perfectly all along, but PG&E had dropped the ball in helping its customers understand the changes underway. CPUC Commissioner Nancy Ryan put it succinctly, “Better communication and customer service will help ensure that consumers see smart meters as something that is done for them, not to them.”
Texas and Oncor Similarly, Texas utility Oncor came under fire for its AMI rollout a few months after PG&E did. With the benefit of going second, Texas regulators reacted much quicker than their California colleagues, hiring Navigant to investigate to identify root causes. Investigation results in July 2010 likewise found the technical performance of the meters impeccable, but those consumers had high bills because of an unusually cold winter and that communication and education could have helped consumers better understand the changes, underscoring the lessons of the California case—consumer awareness will be critical to the success of the smart grid. Public opinion on both of these cases appears likely to influence the longterm future of smart grid initiatives and, as the following cases show, the funding for such initiatives as well. Hawaii and HECO In Hawaii, there was yet another challenge to smart grid in June 2010, but this time it did not concern a consumer issue per se. The Hawaii Solar Energy Association (HSEA) challenged plans for the pilot, claiming that Hawaii Electric Company (HECO) was “putting the cart before the horse,” since the pilot’s principal goal was to ratify technology decisions around a smart metering system, but it used a network approach that HSEA claimed would be incapable of supporting future longterm utility needs to integrate applications beyond smart metering, notably, solar PV systems and other forms of renewable energy. When it comes to renewable energy integration, Hawaii is a bellweather state—nearly 90 percent of its electricity is powered by imported oil, their electricity rates are the highest in the
United States by a large margin, and a DOE ARRA grant, required matching funds to complete the contract and launch its project, for which they would need regulatory approval in a rate Hawaii also leads the nation with case. The trend line emerged ever more clearly in June 2010, as local consumer an ambitious 70 percent renewable advocates challenged both the costs and cost energy goal by 2030. The grid recovery mechanisms in the rate case, leading will need a major overhaul Better communication the commission to veto the deal and send the to accommodate a shift to utility back to the drawing board. 30 percent renewable energy, and customer service For a time, it looked like Maryland might much less 70 percent. For be forced to turn its back on $200 million, but now, the pilot is back on will help ensure that cooler heads prevailed and the utility found track, but Hawaii remains a a way to revise its filing to win regulatory state to watch as it upgrades consumers see smart approval in August 2010 and allow federal its grid. funds to flow. meters as something Maryland and BG&E Two issues became even more apparent in Maryland is the “M” of PJM, the aftermath. First, consumer groups now that is done for them, one of the most had the attention of utilities and regulators congested grids and would likely have a seat at the table of not to them. any future smart grid hearings nationwide. in the nation. Second, state regulators would not be expected Baltimore Gas to blindly follow the lead of the DOE; there would be no automatic state regula& Electric (BG&E), the tory approval of large smart grid rate cases, with or without federal funds to fortunate recipient of sweeten the pot. $200 million in federal largesse from
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OUT THE DOOR Illinois and ComEd In a case that now resembles the proverbial Gordian knot, Illinois utility Comonwealth Edison learned in November 2010 that making it past consumers and special interest groups isn’t enough—a utility can stub its toe on procedure, when an Illinois appeal court ruled on a motion by the state attorney general to deny smart grid cost recovery for ComEd. It is not enough to try to reduce costs with innovative programs; ComEd was going to deploy over 100,000 smart meters linked to home energy management systems to lower costs and give customers more control. However, it also matters how a utility seeks cost recovery; ComEd made the mistake of using a special “rider,” which carries specific restrictions, which the court deemed inappropriate “single-issue ratemaking.” The net-net of this decision will most certainly be to slow smart grid deployments still further and likely to shift more of the burden for installation from utilities to vendors, making it still more difficult for small companies to compete in this industry. It will be hard to challenge other utility managers for being highly methodical and deliberate regarding innovative approaches to industry reform after ComEd’s experience and public wrist-slapping. Colorado and Xcel Energy One of the earliest, most ballyhooed examples of smart grid innovation though has to have been the Smart Grid City pilot in Boulder, Colorado, where Xcel Energy promised in 2008 to showcase the potential of smart grid with a solution cooked up with a bevy of vendor partners. However, in an outcome described by various parties as pioneer trial and error, miscalcu-
lation, hubris, and tragedy, the project suffered from excess press and challenging delivery conditions, running into multiple project cost overruns along the way (some attributed delays to the decision to lay fiber line through granite in the Rocky Mountains). In November 2010, the utility received preliminary approval for $44.5 million in cost recovery for the project originally budgeted at $15.3 million (March 2008), $27.9 million (May 2009), and then $42.1 million (February 2010). At the time of this writing, the case was under review by Colorado regulators, but based on arguments so far, prognosticators expect the full recovery to be whittled down to a partial recovery. Among the ultimate lessons learned here for utilities may be the value of setting achievable expectations and the wisdom of gaining cost approvals up-front, before proceeding to break ground on a smart grid project. The book is published by ARTECH HOUSE (http://www.artechhouse.com).
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