Intelligent Utility JulAug 2010 by Springboard Creative

» SMART METERS

VOL 2, ISSUE 4 » JULY/AUGUST 2010 » WWW.INTELLIGENTUTILITY.COM

Where smart grid meets business—and reality.

TRANSMISSION BRAIN + BRAWN ©©

Smartening up the hardware

©©

Federal + state smarts Meeting at FERC’s place

©©

Where did utility R&D go? Research in practice

©©

Utility insights » BPA » DUKE ENERGY » MED » ONCOR » PG+E » SCE » SDG+E » SMUD » SOUTHERN COMPANY

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CONTENTS S PECIAL REPORT SMART METERS

34 What’s so smart

about my meter? SCE collaborates with partners to communicate the value

35 Oncor gets smart

Learning the difference between customers and consumers

DEPARTMENTS

FEATURES // JULY/AUGUST 2010

Transmission brain + brawn

16 Smartening up the hardware

Transmission utilities have a lot from which to choose

Federal + state smarts

20 Fed + states cooperate

A closer look at the Smart Grid Collaborative

22 Meeting at FERC’s place

The federal regulator is emerging as a vital facilitator

I N T E LL IG E N T U T I L I T Y /// J U LY/AU G U ST 2 0 10

Where did utility R&D go?

26 Don’t go it alone

R&D pathway to smart grid begs for collaboration

28 Research in practice

Duke Energy’s virtual power plant shares its efforts

12 35 39

4 6

Drawing the line Transmissions 6

Letters from readers

Gatherings

10 The big picture

10 2010 UtiliQ rankings 12 Planning transmission expansion

38 Grid(un)lock

38 Entering the automated distribution zone

40 End of the line

40 No-regrets innovator

42 4D

42 Supply chain smarts

44 Connections

44 New guidelines issued

46 Out the door

46 Public networks come courting

41 42 Vol. 2, No. 4, 2010 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.

A t D T E E n e r g y, I t r o n i s p r o v i d i n g s m a r t g r i d technologyâ&#x20AC;&#x201D;for both electricity and gasâ&#x20AC;&#x201D;that t r u l y b e n e f i t s o u r c u s t o m e r s a n d o u r c o m p a n y. It provides consumers with more accurate information about their energy usage so they can track their consumption and demand via the DTE Energy website. The system aids us operationally through remote monitoring of our distribution system and by eliminating the vast majority of our estimated bills. A smarter future for our customersâ&#x20AC;&#x201D;thanks to Itron.

D R AW I N G T H E L I N E

Organic growth in a technical environment IN THE WHOLE SMART GRID/INTELLIGENT UTILITY EVOLUTION, THE TRANSMISSION

end of the picture tends to get largely ignored, at least by the mainstream media. Pity, because there are technological advances going on in transmission every day, and they’ve been quietly occurring for many years. Advances in distribution automation, too, fall beyond the purview of the mainstream media, so that bit of the connection between generation and end use is also a mystery to the consumer. And yet, that’s the very bit that ensures an even quicker response to power outages. No, it’s smart metering that gets the bulk of the media coverage these days, for better or for worse. Lately, it’s been the latter, to the point where many utility companies are rethinking their consumer education plans and figuring out what, if anything, they might have missed along the way. In this issue, we cast a keen eye on all three areas, always on the lookout for new ideas, new developments and new deployments. ??

On the transmission front, a few days at the IEEE T&D conference earlier this year in New Orleans offered up a plentiful harvest of the true “brains and brawn” of our transmission system, and I was reminded, yet again, of how interrelated the two are. [See our feature on Transmission Brains and Brawn, beginning on page 16.]

Automated distribution takes a turn in the spotlight as Mike Breslin focuses on the efforts of a city-owned utility in Murfreesboro, Tennessee, with an industry overview provided by EPRI director Mark McGranaghan to set the stage.

Smart metering takes another hit from Texas customers, and Oncor discussed with J. Ian Tennant what the utility is doing to rectify mixed public opinion.

I N T E LL IG E N T U T I L I T Y /// J U LY/AU G U ST 2 0 10

Consumer acceptance of smart metering and all it offers in terms of demand response, energy efficiency and being able to better manage electricity use (and therefore electricity bills) is key to the success of a truly intelligent utility. But intelligent transmission and distribution initiatives are also imperative, and perhaps just as important in the consumer education equation. It’s a discussion that is going to continue to come to the fore, and I welcome your thoughts and comments.

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 EDITO R-I N- CH I EF Kate Rowland

IdentIty crIsIs

krowland@energycentral.com 720.331.3555 VISIon

S t R at e g y

RealIty

Racking up returns + Stalwarts weigh in on ROI for industry By Ken Silverstein GettInG

cOnSumeRS

leaRn

hOw

Regulatory cost recovery on assets “The bottom line on energy efficiency is that return on investment comes through as we work with regulators to get good incentives in place,” said Chris King, chief regulatory officer of eMeter in San Mateo, Calif. “We see the bigger returns in smart meters and demand response. Utilities are asking for cost recovery of these assets and they are putting together business cases to show both the costs and benefits.” Some utilities are presenting compelling evidence to illustrate that their operational savings have the potential to exceed their cost of deployment, he says. But the majority of them are demonstrating the benefits by discussing the reduction in harmful emissions and the reduced cost of power to consumers over the long run. Using such an analysis, he says that the investment will bear fruit over a 15- to 20-year time frame. Utilities must then be able to put the cost of that investment into their rate base, King noted, so that they can grow their earnings base and attract new shareholders. Most regulators comprehend this and are supportive, although most of them do maintain a healthy skepticism and want to see concrete proof that it works as advertised.

The meter itself is merely a snapshot of how consumers use energy. To increase its value, the device must have the ability to communicate with customers so they can learn how electricity is priced and thus reduce their bills. As such, government support, whether it is from direct investments, subsidies, or through cost recovery, is critical to these technologies moving forward, say advocates. “The future of controlling those electricity rates is dependent on managing peak windows,” said Gary Fromer, chief executive of CPower. “With the right incentives and the right tools, we can manage this. As we eat into that, demand response not only becomes a reliability tool but also an economic one.”

Building value Perhaps the great unknown is the time it will take consumers to acclimate to the new energy marketplace and to understand that they would have more control when it comes to their electricity bills. On the one extreme are the ones who install micro-fuel cells at their homes or businesses to avoid buying from the grid. On the other are the majority who have little interest in dealing with the issue. For their part, utilities are taking different approaches. Some are making investments in “smarter” lines that are able to redirect power flows when congestion is about The smart grid is to occur. Others are investing in meters that not only about peak reach inside consumers’ homes to enable the shaving or peak curtailment of consumption. In all cases, they are shifting. It is also asking state regulators to put their capital cost into about providing the rate base. “ T he s m a r t g r id information to i s not on l y a b out peak shaving or peak customers so they shif ting,” said Joel Gilber t, founder of can measure and Apogee Interactive in Atlanta. “It is also manage their energy about providing information to customers so efficiency efforts. they can measure and manage their energy efficiency efforts.” Automating thermostats in office buildings, for example, adds up to pretty easy savings.

Reallocation of capital But if utilities sell less electricity does that not hurt their profits? Yes, but the demand for power is expected to rise. And if utilities have a regulatory motive to invest in the intelligent utility that encourages conservation and efficiency, then it becomes advantageous for them to do so. While they will also have to build more power plants, they can avoid some of that by allocating capital to the smart grid.

CH I EF CO PY EDITO R S Martha Collins, Joe Kovacs S EN I O R CO NTRI BUTO R S Consider that a new generation unit may run close to $1 billion or a retrofit for an older one could cost hundreds of millions. If that is flowed through to end users, it then pits shareholders who expect fair returns against consumers who dislike huge rate hikes. “The smart grid with demandresponse functions is the perfect hedge for utilities,” said Sandy Williams, partner with Foley & Lardner. The transition to a society that uses electricity more wisely won’t occur overnight, and as such, the payback will take a while. But those benefits will come, which is why most state regulators are incorporating incentives. Investments in the intelligent utility are already resulting in greater reliability. Over time, they will also lead to greater energy efficiency as consumers adapt.

Phil Carson

Editor-in-chief, Intelligent Utility Daily pcarson@energycentral.com 303.228.4757 Ken Silverstein Editor-in-chief, EnergyBiz Insider

Ken Silverstein is editor-in-chief of EnergyBiz Insider.

ksilverstein@energycentral.com 304.345.5777 FE ATU RE W RITER S Mike Breslin, John Johnson,

“

Phil Johnson, Joe Kovacs, Laurel Lundstrom, Elizabeth McGowan, H. Christine Richards, J. Ian Tennant S EN I O R V ICE PR E S I DENT/G ROU P PU B LI S H ER Tim L. Tobeck

ttobeck@energycentral.com 303.228.4752 w w w. I n t e ll Ig e n t U t I l I t y.co m

I n t e ll Ig e n t U t I l I t y /// m ay/j U n e 2 010

electricity is priced is a good thing. That could lead to efficiency and conservation, resulting in lower rates. That’s understood. But do those benefits outweigh the costs and will investors step up? The issue is now before a multitude of state regulators who must decide how the assets that make up the intelligent utility will get financed. Utilities oftentimes are making the investments after getting regulatory approval to pass the cost of them along to consumers—just as power plants are handled. Indeed, constructing a grid that allows utilities and consumers to talk with one another might possibly cut down on peak energy consumption and thereby avoid the build-out of expensive infrastructure.

Rising demand a force Multiple factors are at play here that most notably include an expectation that the demand for electricity will steadily rise in the decades to come. That demand would push prices higher unless the supply of generation grows correspondingly—or utilities are motivated to encourage their customers to use less of their product. With such forces at work, it would tend to encourage investment in two-way communications and demand response that provide both greater reliability and real-time pricing. “The new business model for electric utilities must consider the advanced needs of the consumer, the ability to make the grid smarter and more responsive and at the same time build value for the shareholders,” said Gregg Edeson, a manager of PA Consulting Group’s Global Energy Consulting practice.

”

DI R EC TO R O F M A R K E TI NG A N D PRO DUC TI O N

Sarah W. Frazier sfrazier@energycentral.com 303.228.4733 M A R K E TI NG CO M M U N IC ATI O N S M A N AG ER

Brenda Roode broode@energycentral.com 303.228.4763

Racking up smart grid returns (May/June) Some years back I subscribed to Xcel’s “Saver’s Switch” program, which enables the company to cycle my two air-conditioning compressors at will, should demand control be necessary during peak load times. These systems have been completely transparent in operation, and should be one of the first features of any demand management program, as I believe that most of the summer peak is additional air-conditioning load. Simple and effective solutions are always good for business.

I N T E LL IG E N T U T I L I T Y /// J U LY/AU G U ST 2 0 10

Mick Gavrilovic

The consumers that are most likely to actively participate are already running dishwashers at night, installing programmable thermostats. They hopefully will finally benefit from reduced off-peak rates, but their reduction in energy usage is already in place. Jim Selvey

The business case for intelligent power metering can be improved by expanding the data collection system

to include additional parameters. Gas and water usage monitoring can be implemented in an analogous fashion, while including alarm functions for signaling leaks to a homeowner on his cell phone. These capabilities may be easily expanded to smoke detectors, intrusion alarms and medical alerts. The data collection infrastructure could also be used by the community for measuring air quality, traffic noise and the temperature of urban heat islands. Many of the respective functions that are being sold individually today at considerable cost would be made less expensive through this combined approach. Ultimately, reduced insurance premiums should result from the diminished cumulative risks of a networked community with comprehensive security monitoring. Jeffrey Michel

ACCOU NT E X ECUTI V E S

Todd Hagen, Alexsandra Lemke, Ken Maness, Jean Micketti sales@energycentral.com 303.782.5510 x100 A DV ERTI S I NG COO R DI N ATO R S

Stephanie Wilson, Eric Swanson M A R K E TI NG M A N AG ER Stephanie Fisher TECH N O LOGY M A N AG ER Dan Wilson CI RCU L ATI O N CUSTO M ER S ERV ICE Cindy Witwer B I LLI NG Monica Coffey EN ERGY CENTR A L w ww.energycentral.com PR E S I DENT/CEO Steve Drazga CH I EF O PER ATI NG O FFICER Steven D. Solove V ICE PR E S I DENT/CO NTENT Mark Johnson

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TRANSMISSIONS

What is an intelligent utility?

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

+ It’s all about delivering information-enabled energy.

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

Process & technology Business objectives and their

AN INTELLIGENT UTILITY APPLIES INFORMATION TO

impact on process and smart

energy, maximizing its reliability, affordability and sustainability from generation to end users.

technology deployment ??

Economic models The challenges and opportunities of new paradigms

Finance Investment trends associated with smart technologies

Public policy The impact of politics on energy

Balancing reality with vision and strategy. This magazine focuses on what real utilities are doing

GATHERINGS To view any of these events, please go to www.IntelligentUtility.com/conferences and click the appropriate link.

today to build a more intelligent utility. At the same time, however, we need to consider how today’s actions contribute to a company’s smart

7-9

Smart Energy International

San Jose, CA

grid and intelligent utility vision.

13-14

Smart Grids Summit 2010

Malaga, Spain

20-21

HSNI 2010

Washington, DC

20-21

14th Annual Power Switching Safety

San Diego, CA

V I S I O N S T R AT E G Y R E A L I T Y

Vision: An article that focuses on a utility’s long-range goals, a

I N T E LL IG E N T U T I L I T Y /// J U LY/AU G U ST 2 0 10

and Reliability Conference

direction the utility industry may be

21-23

GridWise® Global Forum

Washington, DC

heading in or the possibilities with

22-23

The Canadian Institute’s Energy Save

Toronto, ON

22-24

Metering, Billing/CRM Europe

Vienna, Austria

27-28

2010 IEEE Technologies Conference

Waltham, MA

a new technology or a technology

SEPTEMBER

that has yet to be introduced. V I S I O N S T R AT E G Y R E A L I T Y

Strategy: An article that discusses a plan of action for achieving the goal or dealing with changes in the industry. V I S I O N S T R AT E G Y R E A L I T Y

CONTRIBUTE We welcome your voice, and your thoughts, as we all contribute to the emerging intelligent utility. Here are a few ways in which you can join the discussion: Comment on team Insight articles at www.IntelligentUtility.com/Insights

Reality: An article that looks at

Create your own blog at www.energycentralblogs.com

where utilities really are today.

Submit your own article to www.energypulse.net Follow Intelligent Utility on Twitter @IntelUtil

THE BIG PICTURE VISION

S T R AT E G Y

REALITY

Demand response/energy efficiency (DR/EE) An intel-

2010 UtiliQ rankings

ligent utility allows consumers

++Top 25 Intelligent Utilities

availability of energy efficiency,

to manage their energy usage and costs (measured by the demand response and load man-

By Jill Feblowitz and Kate Rowland

I N T E LL IG E N T U T I L I T Y /// J U LY/AU G U ST 2 0 10

WELCOME TO THE SECOND ANNUAL UTILIQ RANKING OF U.S.

electric utilities—a list of the top 25 intelligent utilities based on a detailed analysis by IDC Energy Insights and Intelligent Utility magazine. We developed this ranking last year in response to a number of issues and challenges in the rapidly evolving electric utility industry. First, we wanted to separate the smart grid hype from reality. As we have learned over the years, press releases alone do not make a company more intelligent. This magazine defines an intelligent utility as a company that applies information to energy, maximizing its reliability, affordabiliCOMPANY SMARTS ty and sustainability from generation A lot has happened in the industry to end users. Becoming a more intelsince we published our 2009 UtiliQ ligent utility requires more than just rankings a year ago. Jill Feblowitz technology investments; it requires takes a second look at utilities’ a real investment in people and intelligent initiatives. In the next processes, too. article, Phil Johnson discusses Second, we wanted to provide a Bonneville Power Administration’s way for utilities to benchmark their outside-the-box thinking with intelligence and measure progress regard to transmission planning. against their stated goals and objectives. We view the UtiliQ ranking as an ongoing effort that will evolve over time. For example, should we add Knowledge Center participation as an additional metric? We welcome your input. Please give us your ideas for improving next year’s ranking at krowland@energycentral.com. The influx of $11 billion in American Recovery and Reinvestment Act funding for smart grid activities, with awards announced last fall, ramped up utilities’ plans for adding new intelligence to their operations. Although the physical results of that funding have, in most cases, not yet come to fruition, it also required significant utility investment, and has also been factored into the mix. The current ranking is based on a company’s performance using five quantifiable intelligence metrics: ??

Productivity An intelligent utility is an efficient utility (measured by revenue per employee).

Renewable energy An intelligent utility has a commitment to renewable energy as part of its resource portfolio (measured by renewable energy sales, renewable energy customers and renewable capacity defined as wind, solar, geothermal and biomass).

Smart initiatives An intelligent utility makes investments in developing smarter grids (measured by smart meter deployments and smart grid projects involving the T&D network).

agement programs as well as percent of customers enrolled). ??

IT investment An intelligent utility invests in information technology to enable business process improvement (measured by IT spending as a percent of revenue and on a per-employee basis).

We also gave extra marks for utility companies that regularly report on sustainability or corporate social responsibility, including carbon disclosure. With the popularity of smart and intelligent themes, we couldn’t resist providing the ranking in terms of a utility intelligence quotient (IQ). Taken together, the metrics are used to create a company’s intelligence quotient. Companies with IQs over 120, in our analysis, exhibit very superior intelligence compared with other U.S. electric utilities. We believe that the few companies with IQs over 140 are at near genius level compared with the rest of the industry. This year, we had the benefit of more comprehensive sources of data than we had to draw on last year. We relied on data from SNL Energy, FERC, AWEA, NREL and EEI. We were able this year to get a better handle on renewable generation, as well as energy efficiency, demand response and load management programs. In addition, IDC Energy Insights research—in particular an intelligent grid study conducted last fall—helped to round out our knowledge. There were some changes since last year besides having richer data to draw on. It is clear that some utilities rose in the ranks based on being awarded American Recovery and Reinvestment

UtiliQ RANKING BREAKDOWN DIFFERENCE

RANK 2009

RANK 2010

PRODUCTIVITY IQ

RENEWABLE SCORE

SMART GRID IQ

LM, DR, EE IQ

IT SPENDING IQ

Sempra Energy (San Diego Gas & Electric)

142

118

122

174

116

154

Austin Energy

135

118

143

142

116

131

PG&E Corporation

134

121

128

169

110

115

FPL Group, Inc. (now NextEra)

133

124

128

169

110

109

NV Energy, Inc.

133

136

108

171

115

120

Salt River Project

132

120

103

171

110

141

COMPANY NAME

Pepco Holdings, Inc.

131

130

104

161

110

126

-5

Edison International

130

117

129

160

110

121

-1

American Electric Power Company, Inc.

129

122

107

167

110

115

IDACORP, Inc.

129

117

109

166

105

135

Northeast Utilities

129

126

123

138

120

111

Alliant Energy Corporation

129

119

164

116

112

-4

Southern Company

128

119

100

169

115

114

Portland General Electric Company

128

123

113

161

115

126

Sacramento Municipal Utility District

127

119

113

171

116

Central Vermont Public Service Corporation

127

120

116

161

105

130

OGE Energy Corp.

126

117

104

170

115

109

Clark Public Utilities

126

136

142

100

110

140

-5

Xcel Energy Inc.

126

129

104

116

125

Duke Energy Corporation

125

120

102

145

120

114

-9

Constellation Energy Group, Inc.

125

113

106

161

110

109

-7

PPL Corporation

125

110

106

164

110

120

-12

DTE Energy Company

125

114

102

171

110

114

-19

Oncor

124

122

110

168

105

117

Cleco Corporation

122

121

100

167

105

116

RATINGS 90-109 Normal Intelligence // 110-119 Superior intelligence // 120-140 Very superior intelligence // Over 140 Near genius Note: Overall IQ is an average of the IQs for Productivity, Renewable energy, Smart initiatives, LM/DR/EE, and IT investment.

Act funding. We also noticed that many companies that received awards are planning on contributing more than the 50/50 match.

all major stakeholders—including customers and regulators—and what this all means to your employees on a day-to-day basis. ??

Improve processes for both “lean” and “green” Efficient processes drive down the cost of maintaining the current environment and free up resources for innovation and growth.

Make intelligent technology investments Find ways to get the best return from your technology investments by ensuring that your

Drive company cultural

spending on information, communications and energy technologies

change Becoming a more

lines up with your enterprise strategies, enables process improvement,

intelligent utility has a lot to

supports regulatory compliance and creates value for your customers.

do with people. Your employees need to understand your

Jill Feblowitz is practice director, business technology, for IDC Energy Insights.

W W W. I N T E LL IG E N T U T I L I T Y.CO M

Looking ahead Companies that want to make the list or improve their position should focus on these strategies and investments:

company’s vision, your strategy for getting there, why it’s important to

THE BIG PICTURE

VISION

S T R AT E G Y

REALITY

Planning transmission expansion ++BPA follows network open-season process By Phil Johnson

I N T E LL IG E N T U T I L I T Y /// J U LY/AU G U ST 2 0 10

OF ALL THE VITAL FACTORS IN ELECTRICAL TRANSMISSION,

perhaps none is more critical than the capacity to convey enormous amounts of energy over considerable distances to load centers and customers that depend on a transmission system as robust as their own vital daily economic activities. And interestingly, an energy marketer of the stature of the federally operated Bonneville Power Administration (BPA) has taken inspiration and ideas from energy providers of other types to bring logic and a systematic approach to a transmission grid serving the sizable Pacific Northwest. Through a process called “network open season,” BPA electric-transmission planners are now able to act with confidence and certainty when they need to augment the BPA transmission network. This network was established seven decades ago to bring electricity generated through hydro processes at Columbia River dams (a couple of which, Bonneville and Grand Coulee, are world-famous among early hydro/renewable-energy trailblazers) to load centers throughout the region. First-come, first-served “FERC [the Federal Energy Regulatory Commission of the U.S. Department of Energy] has for a number of years mandated a first-come, first-served basis for handling requests for electric-transmission service,” said Brian Silverstein, BPA’s senior vice president of transmission services. “And to make sure we establish and maintain capacity to adequately serve those entities relying on us, several

years ago we started looking at an ‘open-season’ process modeled on the gas pipeline industry, which had implemented open season about 10 years earlier.” The phrase “network open season” refers to a specifically designated window of approximately a month each year during which BPA accepts new requests for transmission service from a variety of potential applicants, including vertically integrated electric utilities, other load-serving entities, and independent power producers, marketers and brokers. BPA has two basic requirements that each service requester must fulfill in order to be included in that year’s transmission service plans. First, each requester must sign a service contract (the length of which may vary depending on individual circumstances). BPA then requires the service requesters—entities that have now signed binding contracts to accept transmission service from BPA—to make firm financial commitments by paying up front the approximate equivalent value of what is estimated to be one year’s transmission service for each entity’s specific request. “We basically want assurance that the requester is serious,” said Silverstein. “And it’s made a world of difference—

THE BIG PICTURE our planners now have something concrete to plan to. They’re also able to aggregate the requests of clusters of entities that have participated in that most recent network open season to more logically plan expansion of the transmission system, and specific locations and routes to expand.” Using pipeline smarts Again, these location and routing parameters relate fairly closely to pipelineindustry experiences—with natural-gas pipeline architects and planners having been able to effectively plan and build capacity based on knowledge they’ve gained through their own network open seasons. One of the advantages But there the pipeline/electricity analogies diverge. the pipeline industry “One of the advantages the pipeline industry has that we do not have in has that we do not have the electricity grid is they have valves,” Silverstein said. “So they can open and in the electricity grid close, and direct where the gas flows. We generally don’t have that in the is they have valves. So electricity industry—certainly on an alternating-current system. they can open and close, “Electrons don’t read contracts, and they obey the laws of physics. and direct where the So the power tends to spread out throughout the system, unlike gas gas flows. that can be directed through valves in a pipeline system.” Overcoming additional challenges, then, becomes a prevalent factor for BPA or anyone else providing electric transmission service.

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”

Challenges with the user-finance model “A few years ago—prior to when we implemented network open season—we tried a user-finance model with a transmission line we were planning to build through a region on the Columbia River,” Silverstein said. “We had folks lined up who wanted to use this proposed transmission line, and we identified power that we can move from Point A to Point B, in this case being the areas around the John Day and McNary dams. “We said, ‘OK, we’re at the point where we need to confirm who’s interested,’ and we sent out agreements to folks that said, ‘Dear Sir, please send us your share of $200 million, and we’ll build the line.’ That didn’t work.” Potential users of the proposed expanded transmission capacity simply balked at shouldering the substantial building costs. “So we knew there’s a real challenge with the user-finance model,” said Silverstein. “But I said then, ‘I think this is the right project for the wrong reasons at the wrong time.’ And to really understand that statement, you have to look at subsequent developments.” When it was first proposed and planned, the McNary-to-John Day transmission line was largely intended to serve, as ironic as it may seem, natural gas-generated electricity that then had the most potential for growth in the area. Today, the same routing of McNary-to-John Day has again proven a good transmission line routing, but now it’s due to rapidly expanding wind-generation capacity in the area.

BPA has three other major linebuilding projects in the midst of environmental studies prior to construction. Because environmental analysis had previously moved forward for the McNary-to-John Day line, that line is first up for construction. But that is happening now largely due to the greater certainty that’s been interjected into BPA’s evaluation process through network open season. Expansion finds roots in renewables An overwhelming percentage of BPA’s current transmission expansion efforts can be traced back to renewable energy standards across the Pacific Northwest (and all along the West Coast, very prominently south to California), with resultant windgeneration capacity being planned and implemented by utilities and independent power providers at an accelerating pace. The expanding renewable generation, however, creates its own set of challenges. “Our transmission planners often wonder where all this power is going to go,” said Silverstein. “And the windproject developer will say, ‘I’m going to deliver the power to a hub.’ The big hub in the Northwest is called the Mid-C—the Mid-Columbia Region hub. “Well, that’s certainly allowed by the FERC rules. But simply saying you want to route your generated energy to a hub is not necessarily helpful for transmission planners. There’s no load at the Mid-C—the power is going to go to consumers somewhere in the Northwest or down to California. So we have to make further assumptions, and we do that to better plan where transmission capacity needs to expand.” Phil Johnson is a freelance business writer and speech writer.

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Transmission Brain +BRAWN VISION

S T R AT E G Y

REALITY

Smartening up the hardware ++Technology is racing ahead to support the transmission sector By Kate Rowland TRANSMISSION IS THE “QUIET GIANT” OF

Federal investment But thoughts are changing federally with regard to transmission. While AMI projects are being heavily supported by the American Recovery and Reinvestment Act (ARRA), there’s also stimulus funding going to grid storage and synchrophasor projects. Both of these will, ultimately, benefit both the transmission and distribution portions of the grid. And while there are still some issues to be settled, regional planning in transmission is moving quickly in the United States. According to Greg Scheu, president of ABB North America’s power products division, interconnection has not yet been optimized in the United States, but talk of more of a federal role for transmission planning has caused the regions to move more quickly. “There are a couple of drivers,” Scheu said. “The first is renewables, and how far you have to go to connect them. The second is congestion. These two things have caused the need for change.” Trends pushing technology There are a number of trends pushing the technology too, he said. High-voltage circuit breakers are but one of them. HVDC, or high-voltage direct current, cable is another. The Tres Amigas SuperStation project currently under development in Clovis, New Mexico, is one such example of the 21st century Goliath in action. Voltage Source Converters (VSCs) will be installed at the point of interconnection of

W W W. I N T E LL IG E N T U T I L I T Y.CO M

ILLUSTRATION BY COLIN WALSH

the electric grid. Tasked with carrying heavy loads from points of generation to load centers, the transmission system has always been the transportation workhorse of the electric grid, its Goliath—a brawny giant, its warrior champion. But this modern Goliath also has David’s smarts. Though there QUIET GIANT OF THE GRID is a popular noThere has been a lot of focus on the tion out there smart-meter end of the grid lately, that “smart grid” but not so much on the grid’s true equals “smart Goliath. Kate Rowland turns a keen meters,” in fact eye to intelligent developments in the transmission electric transmission and distrisystem has been bution, and discusses what’s needed growing ever for new investment to go forward. more intelligent for many years, worldwide and— more quietly—in the United States. A recent discussion with Enrique Santacana, chief executive officer for ABB North America, brought this back into focus. “In Europe, the focus in smart grid is coming from the high-voltage side,” he explained. “In the U.S., the focus is on

smart meters and AMI [advanced metering infrastructure]. And although the AMI discussion is very active, now discussions are happening in substation automation, as well.” Bernhard Jucker, ABB’s head of power products worldwide, further explained the distinction between the two countries (ABB is active in both) in terms of smart grid development. “The starting point is quite different,” he said. “In Europe, distribution is a circular topology. In the U.S., it’s a feeder topology.”

TRANSMISSION BRAIN + BRAWN

each of the United States’ three power grids, and will transition the alternating current (AC) electricity flowing from each interconnection into the SuperStation into DC (direct current) electricity, and will then transition the DC power back into AC power at the adjacent grids. Below-ground superconductor cable will carry the gigawatts of DC electricity between each of three converter stations, acting like a highway roundabout. This effectively creates one supergrid out of the three interconnections. “Superconductor cable has three to 10 times the handling capability of regular cable,” Jack McCall, American Superconductor Corporation’s (AMSC’s) director of transmission and distribution systems, told Superconductor cable me. “They have no electromagnetic field has three to 10 times signal, nor are they affected by magnetic the handling capability fields.” As well, they have of regular cable. They significantly lower impedence than convenhave no electromagnetic tional cable, meaning they can be strategicalfield signal, nor are ly placed in the grid to draw flow away from they affected by overtaxed conventional cables or overhead magnetic fields. lines, relieving network congestion.

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Conventional no longer conventional Even “conventional” has taken on new meaning. We may recognize the product, but technology is transforming it as we speak. Composite cores for conductors, bio-based cable plasticizers and oil-free single-phase submersible transformers are but a few of the new applications on the market, all designed to be better for reliability and better for the environment. We’re seeing additional smarts coming on board in terms of automation, as well, what some have even termed a “huge convergence.” Peter Terwiesch, ABB’s chief technology officer, echoed this in a recent conversation with me. “A smart grid requires scalable protection and control,” he said, “from secondary distribution applications to more complex transmission applications.” And it is here that the role of power electronics—from devices and assemblies to applications—continues to grow. (See Mike Breslin’s story, “Entering the automated distribution zone,” page 38, for more on this convergence.) Smart towers The other “brawn” of the system—the tower itself—is getting smarter, too. I spoke with Jim Wiederholt, president, and

Jim Palmer, marketing director, of the Meyer Steel Structures division of Thomas & Betts recently about advances made in their tower configurations. From single-shaft poles in use by San Diego Gas & Electric and Bonneville Power, to H-shaft towers used by PPL and PECO, the options are nearly limitless. And there are Y-frame and X-frame options, as well. Citing issues from tight transmission corridor rights of way or the utility’s wish for a cleaner visual line for the line’s neighbors to the need to “drop” the tower in via helicopter in environmentally sensitive areas, Wiederholt emphasized the utilities’ need for flexibility in design to accomplish their goals. “In order to accommodate new generation, you have to have the infrastructure to carry it,” he said. “But you can have environmentally responsible transmission at the same time and achieve significant environmental benefits while still being cost-effective. You have to ask, ‘Where does it make sense?’ and ‘How do you optimize it?’” Energy policies needed But while there are new transmission and distribution technologies appearing every day, the ability for utilities to make a good business case for investment still needs a little work. Some new technologies are more expensive to deploy than others, and energy policy is lacking in some of these areas to support the investment. Don Douglas, CTC Cable’s vice president of external affairs, presents a good argument for establishing state and federal rate and public policies encouraging the reduction of line losses. “Improving the efficiency of transmission and distribution lines can provide a sizeable contribution to the reduction of greenhouse gas emissions,” he noted. “For that to happen, however, state and federal policymakers must be willing to establish policy encouraging the reduction of line losses; and rate-makers must be willing to approve the return of and on prudent investments in energy-efficient and ‘oversized’ conductors specified in the interest of reducing electricity losses and the costs of supplying them. “Unfortunately, if state and federal rate and public policies fail to recognize that losses can be reduced through a reasonable trade-off with first-time investment in transmission and distribution line infrastructure, then the owner/operator can be penalized for doing the right thing,” he said. (Douglas has written an editorial on this subject, which will appear in the September/ October issue.)

Federal + State

smarts VISION

S T R AT E G Y

REALITY

Regulatory teamwork Smart Grid Collaborative

In the Energy Independence and Security Act of 2007, Congress asked the Department of Energy to create a smart TRANSFORMATIVE ROLES grid advisory committee. It’s clear that regulatory bodies are Was the Smart Grid going to have to work together to Collaborative a result of drive smart initiatives nationwide. that legislation?

By Joe Kovacs

BROWN

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++A closer look at the

Grid Collaborative since its inception in February 2008. Intelligent Utility recently interviewed him about federal and state collaboration.

AS THE ELECTRIC GRID CONTINUES TO

evolve, the roles of state and federal government in driving smart initiatives is definitely shifting. One state regulator leading the collaborative approach is Garry Brown, chairman of the New York State Public Service Commission and of the National Association of Regulatory Utility Commissioners’ (NARUC’s) Committee on Electricity. Brown has also been a member of the NARUCFederal Energy Regulatory Commission (FERC) Smart

INTELLIGENT UTILITY

For this issue, Joe Kovacs talks with

In early 2008, out NARUC’s Garry Brown about state and federal cooperation, and Ken of recognition among fedSilverstein discusses a growing eral and state regulators that federal facilitation role with FERC our power infrastructure Commissioner John Norris. was moving toward smart grid, we came together to identify and increase our understanding of a variety of smart gird issues—technology, interoperability standards, cyber security, to name a few. NARUC and FERC believed a focused collaborative would position us as a source of information for public and private

ILLUSTRATION BY BRIAN EVERETT

sector entities. It was largely through our desire for ongoing communications and knowledge sharing that we came together, not because of legislation. INTELLIGENT UTILITY

So what does the Smart Grid

Collaborative do? The collaborative meets three times a year at NARUC’s annual meetings. In addition to federal regulators and state commissioners, different external entities present us with what they’re doing in the smart grid space. On our website, you’ll find links to dozens of presentations. We serve as a clearinghouse of information about smart grid, what people are doing, what they’ve learned and various success stories. Our participants benefit by being there, but because the presentations are publicly available, anyone can access them. BROWN

What makes collaboration between FERC and NARUC effective? INTELLIGENT UTILITY

What do you mean when you say these terms are more complex now? INTELLIGENT UTILITY

The pace of our increased understanding of smart grid is astonishing. The questions we’ve asked since 2008 haven’t changed much but the answers are increasingly complex due to the knowledge we’ve accumulated. What can we learn from NIST? Are cyber-security standards advancing to protect the grid from hackers? What new smart grid technologies are developing? What can we learn from stimulusfunded smart grid pilot projects? BROWN

Is the collaborative engaging greater numbers of stakeholders? INTELLIGENT UTILITY

Absolutely. I would even say that due to the rapid advancement of smart grid we have stakeholders we never could have imagined back in 2008. The collaborative has always attracted groups you would expect. Our meetings are open and you’ll typically find state government representatives, utilities, people from GE, Itron, IBM and the like. When stimulus funding became available for smart grid projects, the Department of Energy spoke with us. The Federal Communications Commission now has a smart grid unit. And we’re hearing from groups such as Google, which is developing smart grid applications, and Best Buy, which is interested in developing energy efficiency and smart products. In 2008, the easiest association we would have made for smart grid was with a talking meter. But with all the emerging ways it can operate to enhance our power infrastructure, smart grid is growing more abstract and different interests are engaging in the dialogue. BROWN

How can the collaborative keep pace with the rapid advancement of innovations? INTELLIGENT UTILITY

W W W. I N T E LL IG E N T U T I L I T Y.CO M

We’re both regulators with common interests. But because our electricity infrastructure is complex, it is inevitable that jurisdictional debates will emerge between federal and state regulators over who should be regulating what. The debates aren’t contentious; they’re the result of two distinct sets of regulations that leave an unintended gray zone. With this in mind, as a new 21st century concept like the smart grid emerges and takes on an increasingly integral role in our electricity system, it makes sense for regulators at both levels to collaborate to ensure we’re on the same page moving forward. When FERC regulators and 16 state commissioners first came together in 2008, our discussions focused on developing a common understanding of terms such as smart grid, interoperability standards and cyber security. These terms are more complex now than they were two years ago but they were large enough even back then that, if we wanted BROWN

to develop a foundation for future discussions, the states and federal government thought it wise to agree upon some common definitions.

FEDERAL + STATE SMARTS

I don’t think a single entity can. But the diversity of participants at our meetings ensures we have a lot of different voices increasing our knowledge. As I mentioned, the knowledge sharing that goes on is critical to what the collaborative does. If you don’t have enough stakeholders in your dialogue, you risk missing some important bit of information. I’ll give you an example of what I mean by that. There are a lot of smart grid technologies, but it’s beyond the scope of a small group to know which ones provide the best value in the long term. Which ones will provide the most robust cyber security and which interoperability standards will support the most useful technologies? Having the collaborative means our regulators don’t have to be independent experts. We share information and provide insights that help us keep pace with innovations. It’s helpful to know that the collaborative is not a love-in. We all know the smart grid is uncharted territory and everyone knows that sharing information is good. But new ideas are not always or quickly embraced and there is a healthy cynicism in the electricity industry. Power regulators are conservative. Any smart grid investment you make has rateBROWN

VISION

S T R AT E G Y

REALITY

Meeting at FERC’s place I N T E LL IG E N T U T I L I T Y /// J U LY/AU G U ST 2 0 10

++The federal regulator is

emerging as a vital facilitator By Ken Silverstein KEEPING THOSE AIR CONDITIONERS FLOW-

ing is a summer necessity. But getting the most out of them has become a national priority. The long-term goal is to equip utilities and consumers with the technologies they need to make better energy decisions. Although private entities are the most integral part of the mix, the Federal Energy Regulatory Commission (FERC) is also emerging as a vital facilitator. When it comes to establishing intelligent utilities, the national energy regu-

payer dollars on the line so you want to ensure that whatever decision you make is well-informed and you’re going to get things right the first time. What other state-federal collaborations have been successful? INTELLIGENT UTILITY

FERC and NARUC participated in two earlier collaboratives—one focused on demand response and another on competitive procurement. What’s interesting about the demand response collaborative is that their discussion items recently began overlapping with smart grid issues and vice versa. And so, at NARUC’s last winter meeting, we joined smart grid and demand response discussions into a single collaborative. This is a good example of two things. First, you can see federal and state regulators benefiting from knowledge sharing, especially when other stakeholders participate in the dialogue. Second, we have begun to see the complex interconnections between smart grid and other considerations in our power infrastructure. I see an important role for the Smart Response Collaborative for years to come. BROWN

Joe Kovacs is a freelance writer based in Colorado.

lator’s role is to set the agenda and to become a meeting place so that the stakeholders can advance their ideas. As such, FERC has said that improving reliability, increasing the use of green energy and enticing investors are among its highest objectives. “In the end, the goal provides overall benefits to educate consumers,” FERC Commissioner John Norris said. “That improves efficiency and increases reliability. It produces an ultimate cost savings and gives customers choices. I do think regulators at the state and federal levels need to continually ask questions about costs and benefits—and whether we are moving forward at an appropriate pace so that our decisions are prudent.” FERC’s role has grown Although it is a relatively obscure federal agency to most Americans, FERC’s position in American society has never been greater than it is now. For years, the country had neglected the expansion of its high-voltage transmission network that the agency is responsible for regulating—a fact that became crystal clear to citizens across North America during the 2003 summer blackout.

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After that event, Congress set out to make the grid more dependable and to encourage more investment in it. Among the steps that have been taken over the years are those giving federal regulators more siting authority while allowing them to grant investors more certainties and higher returns. FERC, for example, has the power to step in and mandate construction if state regulators fail to act within a year. The regulatory changes could not come fast enough. Transmission investment has declined in real terms— adjusted for inflation—from 1975 to 1998. While there have been increases since 1998, FERC says that the level is still less than what was invested in 1975. Over the same time period, however, the demand for electricity has doubled. That’s resulted in a significant decrease in transmission capacity, requiring that new lines get built. “The investment community wants to know the smart grid will work,” said Commissioner Norris. To move things along, FERC has proposed giving early adopters favorable treatment. Pacific Gas & Electric, for instance, is now able to recover some of the $50 million in costs associated with its transmission rates in a smart grid project aimed at increasing reliability and integrating renewable resources.

National health The demands of a modern grid and a digitized society are pushing technology developers to create new efficiencies that will minimize blackouts and that will make room for more wind and solar electrons. With the appropriate tools, system operators can know in advance when lines are congested and thereby re-route the flow of electricity to prevent problems. The added efficiencies mean that alternative energy sources get bid into the system, especially during peak periods. Without a doubt, it’s not a risk-free endeavor. Commissioner Norris, however, said that unlike the promises made during the era of deregulation and in the middle 1990s, the assertions made from the architects of the intelligent utility are based on technology and not free markets. The skepticism is not targeted at those utilities that are adding software to determine if their transformers are overloaded and whether the flow of power needs to be redirected. Rather, it is aimed at the installation of “smart” meters that alert consumers when it is most cost-effective to begin conserving energy and whether customers will even engage. “It will add cost to the system and consumers will have to pay for it,” said Commissioner Norris, referring to the entire smart grid enterprise. “The ongoing question will continue:

What is the value of these systems? This is still in its infancy and we are not able yet to accurately project the cost savings.” Others, though, are quick to respond that a trustworthy electrical system could save at least $100 billion a year by avoiding periods of lost productivity. Smaller investments made today in both the wires and the meters will therefore reap much larger dividends down the road. Ongoing work No question, the effort to increase reliability and to encourage investment in transmission is a work in progress. But it has become a top policy goal that the current White House says is central to the development of green energy and the reduction of emissions. To that end, miles more of highvoltage transmission lines are necessary to accommodate an expected increase in generation demand of 1.5 percent over the next decade. The North American Electric Reliability Corp. expects 260,000 additional megawatts of renewable power to be added to the mix during this time. Of that, wind will make up 229,000 megawatts, or 88 percent. Solar, Green energy needs it adds, will comprise 20,000 megawatts. adequate access to If critical lines are able to get permitted and open and competitive then to subsequently get the investments they markets so that it can need, a smarter grid is expected to form. The be part of the supply resulting improvements would then enable green source. More sophistienergy producers more access to crowded netcated information and works and thereby give consumers more choica smart grid are at es. Although any renewable portfolio standards the core of integrating or tax laws are set legislatively, it is the role of renewables. federal energy regulators to create the rules by which all parties play. “Green energy needs adequate access to open and competitive markets so that it can be part of the supply source,” said Commissioner Norris. “More sophisticated information and a smart grid are at the core of integrating renewables.” Today’s electrical system has served to catapult the country forward. But the demands of a 21st century economy necessitate even greater efficiency, reliability and flexibility. FERC is creating the platform to deliver the changes that it says will result in a healthier economy and environment.

“

”

Ken Silverstein is editor-in-chief of EnergyBiz Insider.

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Where did

utility R+D go?

VISION

S T R AT E G Y

REALITY

Don’t go it alone ++R&D pathway to smart grid begs for collaboration By Elizabeth McGowan

enough, even for the polished entertainer. But add four more pins to the mix, then light one or two on fire, and you might grasp a clearer understanding of the daunting demands facing California’s investor-owned utilities as they navigate toward the smart grid of the next decade. “If you look at all of the policies and directives, 2020 is a really important year for us,” said Mike Montoya, director of grid advanceSHARING THE SMARTS ment at Southern California Edison As budgets get tighter, utilities are (SCE). “We’re gogrowing more creative in sharing ing to have to do R&D projects and costs. Elizabeth McGowan explores the shared work a lot of things four California utilities are doing. differently than Then, Laurel Lundstrom takes a look we are today. at Duke Energy’s smart technologies It’s going to be pilot project in North Carolina. a challenge.” Thus far, however, the IOUs seem to be up to the task. As expected, those involved in this transformation are broaching the topic in a no-drama, orderly fashion. For several months, Montoya and other SCE representatives have hunkered down with engineers and other professionals from the Electric Power Research Institute (EPRI),

Devising a state road map The California Energy Commission (CEC) spurred these technology-heavy conversations by introducing a project titled “Defining the Pathway to the California Smart Grid of 2020.” That was how commission officials asked IOUs to collaborate on devising a road map that supports the state’s energy targets for energy efficiency, renewable portfolio standards, demand response and curbing greenhouse gas emissions. Their report is morphing through several stages before a completed vision emerges by the end of the year. “This whole road map process will give the commission a long-term view of what research we all need done,” Montoya said, adding that the CEC will ultimately decide which R&D projects are funded. Major R&D priorities identified by the IOUs fall into general categories that include interoperability, cyber security, compliance and testing, communications technology, information technology (IT) infrastructure, integrating renewables and upgrading workforce skills, said Mark McGranaghan, director of distribution and smart grid research for EPRI. As is the case with other California utilities, SCE has been drafting its own internal smart grid plan. That blueprint serves as a useful guide for Montoya when he brainstorms with representatives from other IOUs. “We’ve been doing smart grid strategy for several years now,” Montoya said. “So for us, this is an extension of that. That puts us in a fairly good position to help the whole road map process along.” California 2020 “Our goal is to achieve a common vision of where we want to be in 2020,” McGranaghan said. “It flows from policy mandates already in place in California. We have to make sure these are accommodated.”

ILLUSTRATION BY PATRICK SULLIVAN

I N T E LL IG E N T U T I L I T Y /// J U LY/AU G U ST 2 0 10

JUGGLING FOUR BOWLING PINS IS DIFFICULT

Pacific Gas & Electric, San Diego Gas & Electric and the Sacramento Municipal Utility District (the sole municipal participant) to spell out key smart grid research and development priorities.

R&D challenges looming In interviews with Intelligent Utility, McGranaghan and Montoya offered perspective on half a dozen of the

R&D challenges they will have to overcome to meet California’s mandates and comply with upcoming smart grid requirements. ??

Customer Connections: How can utilities maximize energy efficiency and demand response in a new world of smart appliances, home area networks, plug-in hybrid electric vehicles, microgrids and renewables? This requires not only properly sizing distribution circuits and transformers but also being vigilant that systems for necessities such as outage management, geographic information and customer information systems can “talk” to one another via a utility’s communications backbone.

“Whether charging an electric vehicle or enabling an air conditioner to respond to demand response, all of these systems have to be effort-free on the part of the customer,” McGranaghan said. “It has to work and it has to be built-in and automatic.” ??

Integrating Renewables: On distribution lines, utilities want to know how inverters hold up when power from photovoltaic panels, windmills or geothermal sources travels both ways between

W W W. I N T E LL IG E N T U T I L I T Y.CO M

In addition to a law that launches smart grid innovation to the forefront, other advanced legislation has set the enterprising Golden State apart as a leading force on the energy front. Measures include categories such as bulk power integration, distributed power generation, transportation electrification, energy efficiency and demand response. For instance, by 2020 California is supposed to be on track to generate one-third of its energy from renewables such as wind, solar and geothermal sources; have a million functioning solar roofs; incorporate roughly 600,000 plug-in electric vehicles on its roadways; save thousands of gigawatt hours of electricity through energy efficiency; and ensure that all new residences qualify as zero-energy homes. In addition, another piece of legislation requires the state to slice its emissions of carbon dioxide and other heat-trapping gases 25 percent—to 1990 levels—by 2025. While all of these initiatives are admirable, each of them requires electric utilities to explore new technologies and find inventive ways to coordinate services with their customers.

WHERE DID UTILITY R&D GO?

a home and a substation. That means studying how efficiently microprocessor relays on circuit breakers—ones that communicate via a high-

pumps, thermostats, refrigerators, water heaters and other devices and appliances so load con-

want to explore how they can use high-speed data

tinues to match generation requires finding and

from synchrophasors to monitor the health of their

installing the correct “system of systems.”

Interoperability/Compliance and Testing: Starting with smart meters, all software and hardware has

that is open but defines security requirements in a

to allow for “plug and play” architecture. The

robust manner.

National Institute of Standards and Technology

Outfitting the workforce of the future: With half of its employees able to retire within the next five years, SCE is worried about bridging the knowledge gap with new hires.

“With all of this change, what kind of employee do we need in the future and how do we train them?” Montoya said. “And we have to look at safety technologies if we have inexperienced folks.” Those concerns have prompted SCE to start experimenting with “wearable computers” and streaming video that would allow a worker in the field to solve problems by

VISION

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“More and more, the IT world is colliding with the grid world,” Montoya said. “All of these devices could be a part of how we operate the grid.”

Cybersecurity: The need exists for an architecture

“It’s a buzz word and should be because it’s so important, especially for applications that involve control of the power system,” McGranaghan said, adding that encryption is a vital piece.

IT Infrastructure: Managing the millions of pool

the distribution grid “self heal.” In addition, utilities

“A lot of this is about storage and balance,” Montoya said. “We are developing our own models and planning with computer simulation.”

speed wireless signal—can locate faults to help

transmission lines.

communicating in real time with an experienced employee back in the office.

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Research in practice ++Duke Energy’s virtual power plant shares its efforts By Laurel Lundstrom YOU CAN’T MISS IT—213 SOLAR PANELS AND

a battery the size of a tractor trailer sit alongside one of Duke Energy’s electric substations on Charlotte, North Carolina’s Highway 51.

has taken the lead on this aspect of the smart grid.

“This is number one on everybody’s list,” McGranaghan said. “We haven’t even thought of some of the applications that will eventually be invented, but we need to make sure all of this works together.” He is confident that IOUs can deliver a sensible R&D road map that meshes with California’s needs, and that could serve as a model for other states pursuing a clearer course to the smart grid. “It’s a big, complicated system with lots of different technologies,” McGranaghan concluded. “Managing the migration is a tremendous effort. The value propositions have to be created one at a time.” Reporter Elizabeth McGowan writes about a full range of energy and environment issues from Washington, D.C.

And that is intentional, said Paige Layne, Duke Energy’s corporate communications manager. “We found because the solar panels are out there on one of the busiest highways in Charlotte, people call in and ask us about them.” The solar arrays, the battery and 100 customers now hooked up with free home energy management systems create a virtual power plant, capable of supplying a reliable source of clean energy when demand is at its highest. The three parts make up Duke Energy’s McAlpine Creek project, one of the utility’s pilot projects, which tests smart technologies that allow customers to monitor their daily electricity usage and to create an online “energy profile.” The giant zinc bromide battery also allows the utility to store 500 kilowatts of solar energy that can be tapped into during peak times. “It was a concept of taking an area and concentrating all the digital technologies in this area toward grid optimization,” said Melanie Miller, the McAlpine Creek senior project manager.

Testing new ideas Duke Energy, which serves approximately 4 million electric and 500,000 gas consumers in North Carolina, South Carolina, Ohio, Kentucky and Indiana, is making many investments to reduce demand and to make the grid more efficient, and McAlpine Creek is just one way to test a new idea. “[Duke] is moving forward with complete grid modernization, so what we are testing and learning can be applied in other areas,” said Miller. In Cincinnati, Ohio, and Hendersonville, N.C., for instance, Duke installed what it calls intelligent “self-healing” switches on power poles to reroute power during an outage. The switches help to minimize the number of customers affected by power outages. “If we can learn what it is that our customers want and find valuable and deliver that on a larger scale with distributed generation, we can get to a level of sustained energy efficiency,” said Layne. “This can then help us to delay building power plants.” Learning more about customer demand Through the McAlpine Creek pilot, Duke is learning about customer demand by the energy profiles it sets up through the utility’s Web site. Duke Energy sends a pricing signal to participating customers when energy is in high demand, and is most expensive; customers can then choose to adjust their profiles accordingly to use electricity when it costs the least. When demand drops, Duke Energy again notifies its customers that they can return to their original energy preferences. “For the past 100 years, we built the grid to deliver energy, and our way of responding was to forecast demand and build power plants to meet the need. As the game has changed, we have had to find ways to balance the affordable, reliable and clean. Energy efficiency is one of the cheapest ways of doing that,” said Layne.

Self-serve educational opportunity “We have opened McAlpine as a self-serve educational opportunity,” said Layne. The McAlpine site is comprised of a walking path in front of the solar panels and informational booths to encourage residents to visit and learn more. “If you go on to Duke Energy’s Web site to sign up for online services, customers with digital meters can see their energy usage in increments from the day before. Consumers have never been able to know how much energy they have used until they get the bill. That information piece is so powerful,” she said. The utility is realizing a growing desire among customers to know more about how they are using their energy. This is why Duke Energy has an active YouTube stream where customers can learn about the company’s smart energy initiatives, including the McAlpine Creek project, which is empowering customers to make smart energy decisions, and how intelligent sensors on power poles are helping to prevent power outages. The utility will continue to gather data from the McAlpine Creek project through 2013, so that it can determine what it is that customers want and what will keep them engaged, if that’s what they want to do. “We know not all customers are going to want to play,” said Layne, “but we can learn what they want and deliver tools, information and technology so that they can do that.” “[The pilot project] is really evolving as technologies are changing,” said Miller, who noted that Duke is constantly issuing requests for proposals for new ideas to make the grid smarter. “We want to make sure we capture all the data and all the components work together as we add apartments, multi-family and small businesses to optimize what we need moving forward.” Laurel Lundstrom is a freelance writer based in Washington, D.C.

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Residential participants first For the pilot, Duke Energy offered volunteers free energy management systems; to complete the digital communication, smart meters, intelligent sensors and communication nodes on utility poles were also installed. The utility gauged interest by asking customers served by the McAlpine Creek Substation to participate through a letter of invitation, said Miller. McAlpine Creek was chosen “for its dense population and mix of residential, small business and commercial customers,” she said. Currently, the pilot only includes residential customers, but it will soon spread to multi-family housing units, apartment buildings and small businesses, and will include

the incorporation of 2.3 kilowatts of solar energy on rooftops, plug-in electrical vehicle chargers and several different battery technologies. “The pilot started last year, and since then we have gathered a lot of data on how customers are using the system,” Miller said. For instance, the company can tell how actively engaged customers are by how often they interact with their energy management system and participate in high energy demand events. In its first year, the utility saw 5- to 15-percent reductions in energy savings during peak periods.

Wi-Fi: A Keystone of the Smart Grid

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By Greg Ennis, Technical Director, Wi-Fi Alliance and Mark Thompson, Vice-President of Strategic Development & Standards, Aclara

Arguably, the massive electrical grid that covers the United States and Canada is the world’s largest machine, with transmission and distribution lines providing the lifeblood of modern society. But for the most part, it is an extremely old and inefficient machine, a cacophony of smaller systems joined together like a Frankenstein’s monster. When any part of the grid breaks, the fault that occurs can cause cascading failures, an effect witnessed on August 14, 2003, when a downed power line caused by untrimmed trees triggered a blackout that affected 55 million people across eight U.S. States as well as Ontario, Canada.

+ THOUGHT LEADERSHIP

One way to prevent such massive failures is to build a Smart Grid that can react more quickly to faults, limiting the damage they can cause. Another reason to build a Smart Grid is to make power delivery more efficient. As our economy and population grow, the demand for electricity outstrips our capacity to produce it. Plus, an efficient Smart Grid is more ecologically sound. According to a Department of Energy report, The Smart Grid: an Introduction, if the grid were just 5% more efficient, the energy savings would equate to permanently eliminating the fuel and greenhouse gas emissions from 53 million cars. To make the grid more intelligent

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SPECIAL REPORT: SMART METERS

the real positive things that SCE did for the industry is that they shared their use cases with the whole industry, and they really did a lot for pushing the topic of interoperability and standards forward in the whole industry. And that one act of sharing those use cases has really created a whole atmosphere in the industry that electric utilities are working together. That process of starting from scratch and actually documenting what they expected to get out of advanced meters and sharing, rather than keeping it to themselves, has really opened up this whole discussion.

conscious approach to keep the customer in mind, communicate to customers that functionality, if you would, a kind of very strategic approach where we’re trying to really communicate and educate customers based on what functionality we’re delivering right now, and where we’re going. So we’re trying to stage (deployment) so we can manage expectations, and hopefully we can manage what they think about the company in terms of our reputation. We have installed about three-quarters of a million meters so far. A key milestone that we’ll come to The new energy this fall is when we basically turn future is going on most of the back office and to give you opporwe bring interval data gathering tunities to get to life, we bring remote service information, to switching to life, and a lot of make decisions, those features that really are and to do busithose basic use cases that built ness in new and the premise in the beginning, different ways. the real value. And we will stage our education and communication process hand-in-glove with that process of bringing that functionality to the market. So far, I think customers really reacted positively to that— either positively or with a little bit of indifference (they don’t know what to think yet)—but certainly I think we’re bringing them along on a journey that is a step-by-step journey. That has been very valuable. We’ve really been working in partnership with Itron to do that with key stakeholders and industry partners as well as end-use customers.

DEVORE We’re

INTELLIGENT UTILITY

VISION

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What’s so smart about my meter? ++SCE collaborates with industry partners to communicate the value By Kate Rowland IT IS BECOMING INCREASINGLY CLEAR THAT CONSUMER

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empowerment will be one of the most powerful forces shaping industry change in the coming decade, and this trend will continue to become even more significant into the future. This new engagement that needs to occur with consumers, or end-customers, represents a tremendous shift for utilities, both in operations and in thinking. Back in late May, I had the opportunity to moderate a media roundtable discussion about the fundamental change this kind of two-way communication means to how utilities will do business in the future. Entitled “Helping Consumers Understand What’s ‘Smart’ About Their Smart Meter,” the roundtable featured a lively discussion between industry media and Ken Devore, director of Southern California Edison’s SmartConnect™ program; Russ Vanos, Itron’s vice president of marketing; and Mark McGranaghan, a director with the Electric Power Research Institute (EPRI). The discussion was wide-ranging, and delved into what this massive shift means, not only for the utility, but for its vendor partners, as well. All three of the roundtable speakers stressed that collaboration—from initial research and pilot programs all the way to deployment CONSUMER CONNECTIONS and consumer education and communication—is key to the ultimate sucAs smart meters begin to make their cess of the smart grid. mark, consumers aren’t convinced. Kate Rowland explored, with SCE and I’d like to share some of the highindustry partners, how important lights of this discussion, as it percollaboration is in giving consumers tained to Southern California Edison’s the complete message, and J. Ian SmartConnect™ planning and deployTennant talks to Oncor about lessons ment, and how the utility and its partlearned in its Texas rollout. ners see the industry moving forward.

McGRANAGHAN One of

moving through our stages fairly deliberately. We’re not the first, we’re not going to be the fastest, but we actually think that we’re taking a very

“

”

As an industry vendor, the utility itself is your custom-

er, not the end-use consumer. Can you tell us how this role is changing in the new energy environment? VANOS We’re focused on the customer.

VISION

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Oncor gets smart ++Learning the difference between customers and consumers By J. Ian Tennant DALLAS-BASED

ONCOR

LEARNED

VALUABLE

LESSON

earlier this year: it has “customers” not “consumers.” A snowstorm hammered the Dallas-Fort Worth area in February, dropping 17 inches, the second-largest snowfall ever recorded in the region. It was also the fifth-coldest winter on record. As the company responsible for ensuring power gets to its 3 million residential and business customers, Oncor Electric Delivery, a unit of Energy Future Holdings Corp., pressed its workers into action. Bad weather is anticipated in Texas, said Oncor spokesperson Carol Peters, but not extremely cold weather for days on end and a freak snowstorm on Valentine’s Day. Storm of another sort Alas, a public relations storm was also brewing on the horizon. Electric bills arrived and Oncor customers were not impressed, some reporting an increase in their monthly average from $400 to $700 to nearly $1,800. The culprit? Many pointed to the smart meters Oncor has been rolling out since 2008. The new meters read electricity usage in 15-minute intervals, giving the user the ability to monitor real-time use, in addition to measuring a home or business’s carbon footprint. Customers can also log on to the Smart Meter Texas Web site, set up by a group of electric transmission and distribution service providers, to get reports on their electricity usage. But the cry rang out: “The meters are inaccurate!” Not so, replied Oncor. Perfect storm at play Peters said three factors were responsible for the high bills. The bitter storm and sustained frigid temperatures had a greater impact on people using electric heat as

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Our customer is the utility—in this case, Southern California Edison and some of the other utilities we’ve mentioned. The end customer was never really much in our purview, and so this is new ground for us. So we are trying to be very collaborative with these utilities. We’re trying to focus here initially on the end consumer, focus mostly on [questions like] how do we educate the end consumer, how do we share information on what utilities and their customers can do with technology in the new energy reality we are all encountering. You’ve heard of the smart grid referred to as like the Internet in the fact that it’s going to offer new ways for consumers to interact with their utilities, much as the Internet has done. The new energy future—with smart grid and two-way communications down to end consumers—is going to give you opportunities to get information, to make decisions, and to do business in new and different ways. And so our focus is to work with Southern California Edison and all of our customers to help them with media, speaking engagements and white papers, but more importantly to really collaborate with them and their consumers on “What are the applications that consumers want? What are the things that they’re interested in, in terms of managing and using energy differently and more effectively?” We’re only at the beginning of this. It really is going to be generational. It won’t be completed this year or even this decade. It’s going to take lots of time. Clearly the big thing here that’s different is this notion of collaboration and partner systems, because it won’t be built by one party alone.

SPECIAL REPORT: SMART METERS opposed to those using natural gas to heat their homes. “Anyone with electric heat is really in a bad way,” she said, adding a regulator told her that relying on electric heat “is like heating your home with a hair dryer.” The third factor at play, she said, was the fact that many customers had not searched for the best rate from retail electricity providers (REPs). Many were paying 12 cents per kilowatt hour (kWh), while if they had shopped around, they could have locked in at a rate of 9 cents per kWh. And the reality is that if homeowners see a big spike in their electricity bill, they automatically blame the utility company because it is visible—and in Oncor’s case, its workers were in the streets fixing downed lines in the thunderstorms— even though the company has nothing to do with an REP’s rates. “We get the blame,” Peters concurred.

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Dealing with perception However, Oncor quickly realized that perception is reality, in the customer’s eyes. So, although the utility had been proactive in its public relations campaign surrounding its installation of smart meters in central and north Texas, it also established, in response to the backlash from the storm, a rapid response team. The team received more than 4,000 calls, and established that about 3,000 of those customers had not yet even received a smart meter. It’s understandable, Peters noted: Customers turn on a switch and don’t care where the power comes from or who is responsible for each leg of the journey from power generation to the light bulb. “It’s just not something you think about,” she said. But when customers get angry, they seek answers. Oncor realized “we do touch customers,” Peters said. “We learned some lessons about ourselves during the smart meter response and the snowstorm. Customers want to hear from us. They want responses.” There was a growing realization within Oncor that “we can’t do our job if we don’t have some engagement with the customer,” Peters said. Indeed, one small but perhaps meaningful change: “Instead of consumers, call them customers.”

Increasing customer engagement Oncor called the media to watch side-by-side tests between digital smart meters and old analog meters. Company representatives visited homes and discussed shopping for electricity rates. The company also found that roughly 1,800 smart meters were not installed correctly, which it reported to the Public Utility Commission of Texas (PUCT). The PUCT launched its own review in early March, hiring Navigant Consulting to test smart meters that Oncor and other power companies installed. Peters said all of the 1,400 Oncor smart meters tested were on the mark. (On April 1, the PUCT said Navigant should also look into usage and customer complaints.) “We believe our meters are accurate, but what’s most important is customers believe that they are accurate,” Peters said. Not all customers agree. One lawsuit was launched in late March against the utility. At the time the legal action was launched, Chris Schein, Oncor’s director of communications, told Greentech Media it was “full of misstatements and untruths. It’s clear that it’s a lot of hyperbole designed to get media attention rather than address the facts that are out there.” Even in Waco, where Oncor installed its 1 millionth smart meter on June 2, the company still faced skepticism. The Waco Tribune-Herald reported that while some homeowners were looking forward to closely monitoring their electrical usage, other neighbors were reluctant to have the smart meters installed

because they “had heard” high electricity bills soon follow. It is this perception that Peters said Oncor is working to overcome. Interfacing with consumers Prior to entering a community, Oncor will advertise what it is doing, leave messages on door handles and roll out its “Smart Texas mobile experience,” an 18-wheeler that transforms into what Peters calls “a rolling smart house.” It expands to 1,000 square feet, complete with kitchen, laundry facilities, a living room and all the state-of-the-art appliances and electronics imaginable. “There’s lots of communication that goes on around the smart meter installation,” Peters said. Part of the communication process is convincing customers that the $2.19 monthly rate the PUCT allows Oncor to charge to cover the costs of installing 3 million smart meters by 2012 is not prohibitive. Although Oncor can apply the fee for 11 years, the total cost to a homeowner or business of $26.28 a year, nearly $290, those dollars can be recouped, said Peters, by replacing old technology with new energy-saving items such as LED lights. Peters noted they would have even more dealings with the public as the company processes, protects and analyzes the mountains of data the smart meters will generate. Meanwhile, the utility is building a transmission line that requires 800 miles of right of way. That is a whole mess of landowners with whom they’ll communicate. Now the Texas heat is rising, air conditioners are humming and Oncor is bracing for more questions. They anticipate more customers receiving high, unforeseen, electricity bills. They anticipate scrutiny. “We are not going to get everything right, but I think we are getting a lot of it right,” said Peters. J. Ian Tennant is a freelance journalist based in Austin, Texas.

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Entering the automated distribution zone ++MED goes underground with new commercial development By Mike Breslin IN A PERFECT WORLD, THE DISTRIBUTION SYSTEM HAS

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intelligent equipment that easily handles two-way power flow and receives distributed generation like renewables. Operators have advanced voltage control integrated with smart meters to manage energy, reduce losses and lower customer bills. Distribution quickly heals itself from assaults by nature and equipment failures while limiting outages to as few customers as possible. Power surges no longer destroy expensive equipment. What’s a dream at most utilities is becoming a reality at others and being built out in various stages. “Substation automation is getting to the point where operators can view status, performance and loading of all major substation equipment and control it for improved relability, AUTOMATION ON THE LINE efficiency and asset management,” Substation automation is coming said Mark McGranaghan, direcon strong. Mike Breslin talks to the tor of distribution research at the Mufreesboro Electric Department Electric Power Research Institute in Tennessee about distribution (EPRI). “The penetration of substaautomation in a major city tion automation is between 40 to development project, and to 60 percent and growing. Going out EPRI’s Mark McGranaghan about to automated distribution circuits, the bigger picture. (it’s) probably 10 to 15 percent of the circuits in the country.”

Underground distribution driving automation A major force driving automation is underground distribution, especially for large, new commercial developments where outages can cause serious financial losses. While more expensive than overhead distribution, the aesthetic advantages and fewer faults of underground are cursed with the problems of pinpointing faults when they do happen. Take the case of Murfreesboro, Tenn., one the fastest-growing cities in the country, with a population that mushroomed from 46,000 in 1990 to more than 100,000 today. Murfreesboro Electric Department (MED), a city-owned utility serving more than 50,000 customers, was asked to provide extensive underground service for a major city development project. “A few years back, the town fathers decided to build a new gateway into Murfreesboro—a new access highway off the interstate called Medical Center Parkway—with plans to do a business park, hospital, hotel and convention center, a 100-acre mall and a lot of restaurants, retail and commercial buildings. And they wanted all electric service underground,” said Mark Kimbell, MED’s chief engineer. “We wanted a good way to protect it, isolate it quickly if we had

a problem and a way to keep as many customers on as we could.” Kimbell pointed out that the area is a very busy one, so traffic is a problem if there is an outage. “If traffic signals go down, we couldn’t get into the area quickly. We looked at all the factors and decided we would invest in automation. We’ve spent upward of two million dollars on it to the present day,” he said. Early adopter MED was one of the earliest utilities in Tennessse to implement automated distribution on this scale, over six miles of underground infrastructure. The system has been operational for three years and Kimbell characterized performance as “great, outstanding.” Two of the utility’s 10 substations are automated over several circuits that generally cover the new commercial area. “In general, there are some advantages to pulse closing in terms of not exposing the circuit to multiple faults when you are reclosing,” McGranaghan said. “That helps other customers by not exposing them to multiple voltage sags and it is less damaging to transformers due to a reduced fault current exposure. But there are a lot of companies that make automated switch gear that are part of these automated systems for reconfiguration. There’s a lot of competition in this market right now.” Restoring power quickly MED started with underground, expanded to overhead and now has about half of each with approximately 10 percent of its entire distribution automated. The utility currently uses radio communications but is working on a fiber loop to speed up response time. “We had a fairly large tornado here a little over a year ago that destroyed both feeds of a 46-kV transmission to a substation,” Kimbell said. “With automation, we could have restored power to 5,000 to 6,000 customers

within a minute. Without automation, it took several hours. Because of that we are looking at automating transmission lines to all of our 46-kV substations. We are also looking to expand automated distribution to the rest of our commercial areas.” He added: “Before, we would have a circuit go out to 2,000 customers and we would have to rely on someone calling in to say we have trouble. Then we would have to go to that spot and it could take a long while to ride out the circuit to find the problem. With automation it narrows it down. We break down the circuit to about five or six 100-amp sections. You can concentrate more people to find a fault quicker and fix it. I would say it’s about 75 percent faster to find a fault.” Managing the distribution system connection McGranaghan takes a broader view of smart grid development: “Automated

distribution is absolutely critical because that’s the connection to the customer, and the smart grid is all about making the customer integrated with pricing, being able to use demand response to control loads and allowing customers to provide generation. It’s not possible unless we manage the distribution system connection to the customer.” Leading the industry toward a more intelligent automation is the Institute of Electrical and Electronics Engineers (IEEE) Smart Distribution Working Group and its task force on volt/VAR control. The group is working to advance the design guidelines for the optimization of smart overhead and underground distribution, and looking at how volt/VAR control needs to change. The march toward automated distribution appears inevitable. As protection equipment ages, it will naturally be replaced with digital relays with capabilities that can be integrated with automation systems. Meanwhile, utilities are building automation from both ends of the line. Some are concentrating on advanced metering and are building outward. Others are focusing efforts on advanced control systems for reconfiguring substations and circuits and waiting for the latest meters. Mike Breslin is a freelance writer and novelist based in New Jersey.

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END OF THE LINE VISION

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No-regrets innovator ++Duke Energy’s Jim Rogers cuts to the chase regarding customer needs By Kate Rowland

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DUKE ENERGY CEO JIM ROGERS DOESN’T MINCE WORDS.

It was early May, under stormy skies, when Rogers gave the opening keynote, “Smart Grid: The Catalyst to Transform the Energy Sector,” at the Smart Grid Roadshow in Cincinnati. Later that morning, he followed up with a sit-down chat with a half-dozen of us about his vision for the utility industry. One of his key messages: keep educating the customer, and pay attention to the customer’s wants and needs. “As we design products for customers, it’s important to listen to what the customer wants,” Rogers said. “But it’s also important to notice that the customer doesn’t necessarily know what he wants yet.” It’s important to listen, he reiterated, but it’s also important to see the future and to see the technology, and then to create the products and services that customers will want and need. “In a sense, we stand in a place today where we have the opportunity to totally reconfigure our business,” Rogers said. To give his listeners a better vision of where the industry is going, Rogers spoke about its past. A few salient points: the price of electricity for the past 50 years in real time has been flat, and is going to AN INDUSTRY RECONFIGURED rise in the future, and the only transDuke Energy’s Jim Rogers has never forming technology we adopted in the been known to mince words. When it 20th century was nuclear technology. comes to his views of the intelligent And while the current state may electric utility of the future, and feel like “death by pilot,” the chalthe industry in general, he doesn’t lenge for our industry, he said, is to disappoint. Kate Rowland met do more pilots to test the technology with Rogers in May. Here’s what we’re adopting. Along the way, we will he had to say. be building the demand to move the pilots to deployment and bring the costs down. “To me, adaptation of technology is really critical. Our role is to be a distributor of those technologies, but we also play the role of integrating the technology into our system,” Rogers said. Interoperability and open architecture are both important keys to thinking about technology going forward, and cyber security is also critical. “As we deploy this technology, we’ve got to continuously make the business case. We have to continually educate our customers about the benefits of the technology,” he noted. It is this idea of continuous education of customers that has become a stumbling block for some utilities as they implement and deploy new technology. “Smart meter pushback” has become a front-of-mind term following deployments in California and Texas, despite the minute numbers of malfunctioning meters.

The way Rogers sees it, “Before you can move to the technology solution, you have to make customers understand their usage. Electricity is so back-of-mind for people. Turning on a switch is a pretty mindless experience.” Duke Energy’s goal, and Rogers’, is to make energy efficiency just as mindless as turning on a switch. Rogers is no stranger to energy efficiency; he walks the talk in an extremely visible fashion. He is the current chairman of the Institute for Electric Efficiency, past chairman and ex officio member of the Executive Committee of the Edison Electric Institute, chairman of the Edison Foundation, and co-chair of the National Action Plan for Energy

“As we deploy this technology, we’ve got to continuously make the business case. We have to continually educate our customers about the benefits of

”

the technology.

Efficiency and the Alliance to Save Energy, and he was inducted into the inaugural Energy Efficiency Forum Hall of Fame by the U.S. Energy Association and Johnson Controls Inc. Last year, Newsweek magazine named him one of “the 50 most powerful people in the world.” “I believe there will come a day when the boundaries of our business will be redefined,” Rogers said. “Right now, it goes from generation to meter.” There will come a day, he said, when the boundaries of the electric utility business will go beyond the meter to the end use. “I believe we will under-

stand the algorithms in the end home and end business,” he predicted. Again, though, that will take customer awareness. “We have to make sure we’re not operating in a motherknows-best situation. We have to give them both the plusses and minuses of the system,” Rogers said. Demonstrating to customers the key value of rolling out technology innovations is key to the success of the project. Comparatively, he said, every dollar Duke Energy invested in rooftop solar in its McAlpine Smart Energy Pilot project in North Carolina is the same as a dollar invested in transmission. (See page 28 for a closer look at what this project intends to accomplish.) “Having that same investment thesis in investing beyond the meter will incentivize us,” he added.

“What we will enable with a smart grid and applications that are extended to homes and businesses … we cannot even envision what we will enable. That’s one of the reasons I’m still hanging around,” Rogers said. “The next five years will be far more interesting, far more transforming, than the past 20 years. I’m really confident that we’re in a period of great transformation.” And energy efficiency is a bottom line here, if we are to take Rogers’ exhortations to heart. While some may describe him as somewhat evangelical, I think it’s long past time for a bit more evangelism in our industry. And with that, I’d like to share two final quotes from Jim Rogers. “My belief,” he said, “is that we have a better chance of increasing the standard of living for future generations if we are energy efficient.” And finally, in answer to a question posed after the keynote, in our small group meeting, Rogers explored his “no regrets” approach to piloting new technology, and moving forward in advance guard: “In terms of ‘no regrets,’ you have to think that way. You have to push the edge of current innovation. But you also have to be mindful that you are. “There is a great West Texas expression: the pioneers get the arrows, the settlers get the land. I don’t mind being a pioneer in regulation … but I think we need more people in our industry, regulators and industry leaders, who are willing to pioneer new ideas.”

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4D VISION

S T R AT E G Y

REALITY

Supply chain smarts ++RFID technology will add new utility intelligence By John R. Johnson THE ELECTRIC UTILITY INDUSTRY HAS NEVER SEEN A LARGER

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influx of new technology. As smart meter technology and advanced metering infrastructure continue to infiltrate utilities, the task of dealing with so many new technologies can be daunting. The utility’s newfound role as a technology trailblazer is only just beginning. The techno-spin is about to become even more challenging. As if smart meter technology wasn’t enough to keep track of, radio frequency identification (RFID) technology is about to make its presence known in the utility field. Although utilities have been slow to adopt RFID, which is often defined as bar codes on steroids, industry analysts say that electric utilities have perhaps more to gain than any other industry when it comes to the benefits of RFID. By affixing either passive or active RFID tags to its products, utilities stand to increase efficiencies, lessen labor needs, improve customer service and even increase response time to outages and cut down on their carbon footprint by having fewer trucks on the road making unnecessary service calls.

Supply chain sweet spot However, one of the sweet spots for RFID—and the place where the technology seems to be getting the most use in overall industry—is within supply chain operations. Industries such as retail, aerospace and pharmaceutical are embracing RFID in their supply chains to increase visibility and provide better inventory control and asset tracking. Using RFID in the utility sector to track expensive items like transformers and wiring TAGGING THE ASSETS and even replacement parts makes perfect sense. RFID technology, or “bar codes on steroids,” has significant “We are doing some RFID, mostly benefits for electric utilities. John on the supply chain side of our R. Johnson takes a broad-scope business where we have asked view, and discusses the uses other suppliers to put tags on items so industries have found for the we can use it for inventory managetechnology, and the inroads it is ment,” said Becky Blalock, senior making in our industry. vice president and chief information officer at Southern Company. “We have some supply chain pieces that are very expensive, like transformers that cost millions of dollars, so having that tag that tells you where it is and provides all kinds of information about it can be very helpful.” Hydro-Québec pilot The supply chain was at the heart of an RFID pilot program completed at Hydro-Québec in 2007. Specifically, the research initiative studied how the use of RFID could improve Hydro-Québec’s supply chain to reduce power outage downtime and reduce the overall cost of operations.

Ygal Bendavid, Ph.D., a professor at the University of Quebec in Montreal and a doctoral student at the time of the research study, began by building a living lab to test and simulate the utility supply chain. The next step was to begin tagging pole transformers at the point of manufacture, allowing visibility into transformers through the entire supply chain so that the utility knew immediately when the transformer was put into use on a pole. “We found a real improvement in inventory levels throughout the supply chain, and were able to drastically reduce inventory levels, not only at the supplier level but at distribution centers and the regional stores that are closer to the area where the problem might be located,” he said. “There was also a reduction in procurement time and in down time for the grid network.” Bendavid notes that by converting remote stores into automated selfservice facilities, the utility could save hundreds of thousands of dollars annually by reducing labor costs required to staff the facility and to track inventory. In addition, moving from laborious weekly inventory updates entered into an SAP system to real-time information provided by RFID could free up a month’s worth of inventory in the supply chain, representing millions of dollars worth of frozen capital and space management. The biggest improvements from the use of RFID at Hydro-Québec would likely occur in the area of optimizing efficiencies and process improvements when it comes to receiving, putaway, packing, cycle counts and shipping. Tagging and tracking expensive assets “There is tremendous potential, especially considering the amount

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and the value of the material that is being moved in the supply chain,” said Bendavid. “You have hundreds of trucks traveling the country with thousands of dollars worth of inventory inside them, and nobody knows which trucks have what products. When you start tagging some of those expensive items it becomes real interesting. Normally, people compensate for not knowing how much inventory they have by over-ordering. Then you have more inventory and millions and millions in assets frozen everywhere. That’s the kind of business case we built for them.” Aside from supply chain benefits, RFID can also be used to help utilities track workers operating at dangerous and remote locations, such as substations and power plants. By embedding RFID tags into name badges, for example, and outfitting substations with RFID readers, utilities can keep 10/5/04 8:01 PM Page 1 track of when workers enter and exit

facilities, and can detect if a worker has been inactive for a specific period of time, which might indicate the worker is in trouble. In addition, asset tracking has huge ramifications for utilities, not just for expensive parts that are used in power plants and substations. The aerospace industry, for example, has made great use of RFID for tracking and maintaining tools. Complicated tools that require maintenance and recalibrating can be tracked with RFID, providing an easier way to provide an accurate maintenance history that is free of human error. Operational efficiencies RFID, and other combined sensor technologies, can help with a host of other operational issues in the utility industry. Blalock points out that Southern Company is using sensor technology to keep track of the blinking lights on the top of transmission towers and stacks at power plants. The FAA requires the blinking lights, and can levy expensive fines if the lights are out for longer than two days. “RFID is just one form of sensor technology that we are taking advantage of,” she said. “We’ve found that by using sensors with the lights, we know when they are out and when we need to change them.” Still, RFID adoption remains somewhat slow in the industry, as utilities— often slow to adopt new technologies to begin with—either wait for the technology to mature further or simply watch and learn from other industries. However, growth in the use of RFID will likely explode as more use cases become public and the benefits and return on investment become clearer. John R. Johnson is a Boston-based freelance writer specializing in alternative energy and technology topics.

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CONNECTIONS VISION

S T R AT E G Y

REALITY

VSL assignments should not have the unintended

New guidelines issued

consequence of lowering the current level of compliance. ??

++FERC approves violation severity levels

ensure uniformity and consistency in the determination

for CIP reliability standards By Pamela J. Anderson and Edward C. Lin

VSL assignments should

of penalties. ??

A VSL assignment should be consistent with the

ON MARCH 18, 2010, THE FEDERAL ENERGY REGULATORY

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Commission (FERC) approved, with modifications, certain Violation Severity Level (VSL) assignments for Critical Infrastructure Protection (CIP) Reliability Standards as proposed by the North American Electric Reliability Corporation (NERC).

Implications for registered entities The VSL assignments approved in the order were effective immediately, and NERC will begin using them as a factor in determining future penalties for violations of the cyber security CIP Reliability Standards. Because FERC’s new guidelines require NERC to take an all-or-nothing approach where a weakest-link vulnerability is present, registered entities have an increased incentive to ensure strict compliance with the CIP Reliability Standards. Similarly, registered entities should ensure their compliance procedures that address requirements identifying both implementation and documentaVIOLATION GUIDELINES tion include specific provisions coverThis spring, FERC approved specific ing those interdependent tasks. Violation Severity Level assignments Although the order addresses for the CIP reliability standards VSL assignments for Version 1 of the proposed by NERC. Guest columnists CIP Reliability Standards, the two Pamela J. Anderson and Edward C. additional guidelines are not limited Lin explore what these assignments to the initial version. VSL assignmean for electric utilities. ments for subsequent versions of the standards must also comply with these new guidelines. Thus, registered entities should take the new guidelines into consideration when designing, revising or implementing a compliance program that addresses the CIP Reliability Standards. Moreover, the order confirms the need for registered entities to have a robust compliance program that covers reliability compliance and includes written procedures that specifically address the requirements in the reliability standards. VSL revisited The VSL is a measure of the degree (lower, moderate, high or severe) to which a reliability standard requirement has been violated. NERC considers the VSL together with a “Violation Risk Factor,” which represents the potential risk to reliability, to establish a base penalty range for a violation of the reliability standards. The Commission previously approved VSLs for requirements and subrequirements of 83 non-CIP Reliability Standards. In the Non-CIP VSL Order, the Commission provided four guidelines that it will apply when reviewing proposed VSL assignments:

corresponding requirement. ??

A VSL assignment should be based on a single violation, not on a cumulative number of violations.

In a subsequent order, Order No. 706, the Commission approved eight CIP Reliability Standards proposed by NERC and directed NERC to file VSLs corresponding to the CIP Reliability Standard requirements and subrequirements before July 1, 2009. On June 30, 2009, NERC proposed 118 sets of VSLs corresponding to the CIP Reliability Standards. FERC’s review In the CIP-VSL Order, the Commission approved the proposed VSLs for the CIP Reliability Standards, issued additional guidance for determining appropriate VSLs in the context of cyber security requirements and ordered NERC to revise 57 sets of VSLs within 60 days. The approved VSLs were effective immediately and will be used by NERC to determine penalties for violating the CIP Reliability Standards. In addition, the Commission provided two additional guidelines specific to cyber security VSL assignments. FERC said: “Requirements where a single lapse in protection can compromise computer network security, i.e., the ‘weakest link’ characteristic, should apply binary VSLs.” In adopting this all-or-nothing, or binary, approach, the Commission explained that the control systems supporting bulk-power system reliability are “only as secure as their weakest

links” and that a single lapse of computer protection can have systemic critical infrastructure consequences. Thus, while FERC generally prefers a gradated approach for VSLs, it concluded that a binary approach was appropriate for cyber security standards involving “weakest link” vulnerabilities. FERC also said: “VSLs for cyber security requirements containing interdependent tasks of documentation and implementation should account for their interdependence.” FERC explained that often in the cyber environment, implementation of security measures depends on complex plans, policies and procedures that must be repeatable and verifiable. These interdependent tasks require documentation of both the procedures to be followed and verification that the procedures were followed as directed. If the responsible entity documented the control processes and mechanisms but did not implement them, or

conversely if the entity attempted to implement controls but did not document the control processes and mechanisms, the desired security would be inadequate. Therefore, for certain reliability standards the interdependency between documentation and implementation should be recognized in the corresponding VSLs. In addition to the new guidelines, FERC believed that some of the proposed VSLs needed revision as they were too permissive and could have the unintended consequence of lowering the current level of compliance. Finally, FERC had consistency and clarity concerns with specific VSLs and ordered revisions to remove ambiguities. Rehearing requested On April 19, the American Public Power Association, the Edison Electric Institute and the National Rural Electric Cooperative Association filed a joint request for rehearing of the CIP-VSL Order. In their rehearing request, the trade associations requested that the Commission reinstate the gradation approach instead of the binary approach for certain VSL assignments and recognize that the successful implementation of electronic-access controls for purposes of CIP VSL Guidance does not depend necessarily upon the documentation of such controls. On May 17, NERC submitted its compliance filing as required by the CIP-VSL Order. At press time, the FERC had not acted on the rehearing request or the compliance filing. Pending action on the rehearing request, registered entities should address all six of the VSL guidelines in their procedures governing compliance with the CIP Reliability Standards. Pamela J. Anderson is a partner in the Environment, Energy & Resources practice of Perkins Coie LLP, practicing in Bellevue, Wash. Edward C. Lin is an associate in the practice.

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OUT THE DOOR VISION

S T R AT E G Y

REALITY

Public networks come courting ++Telcos have a value proposition they’d like to discuss By Phil Carson WHEN THE PHONE RINGS IN THE EXECUTIVE SUITES AT

I N T E LL IG E N T U T I L I T Y /// J U LY/AU G U ST 2 0 10

electric utilities these days, it may well be the public network operators calling, asking for a date. The network operators have a value proposition they’d like to discuss. That proposition, of course, extends far beyond equipping utility field crews with cell phones and wirelessly connected laptops. In fact, a handful of the largest network operators in the United States say they have the expertise to serve nearly every segment of the utility operation, either as a project leader or as a partner in a project-specific consortium. At one end of the spectrum lies meter data management, at the other is strategic business transformation and regulatory CROSS-CULTURE PROPOSITION reform. In between, there’s a vast array Public network operators recognize of utility operations with communicathe need for solid communications tions, controls and sensing and secunetworks for electric utilities as rity themes running through them. smart meters are deployed. Phil With the advent of third- and Carson discusses the telcos’ value fourth-generation networks—“3G” proposition, and the commonalities and “4G” in the vernacular—public they see between the two industries. network operators have developed or are launching networks with high capacity and big bandwidth. Even as they battle for the consumer’s voice and data business, the evolving sophistication, capacity and cost of their networks has led network operators to look for growth opportunities. Enter the electric utility, now buffeted by pressures from regulators, consumers, stimulus funds and technological innovations to make rapid changes. Just as the public network operators have pursued vertical industries such as health care and finance, they see mutual benefits to their involvement with electric utilities.

Message received This message seems to be getting through to utilities, according to both sides. In fact, network operators and utilities are in many instances already working closely together—a relationship not always apparent from public rhetoric, at least on the utility side. “Six months ago we faced a lot of opposition,” said Rilck Noel, vice president and global managing director for energy and utilities at Verizon. “But we’ve gone from ‘No, I don’t want to hear about it,’ to acceptance of the concept of hybrid communications networks that combine private fiber and public wireless.” Rita Mix, senior marketing manager for utilities at AT&T, concurred. “Utility attitudes have changed,” she said. “They’ve gone from ‘We’d never rely on public

wireless,’ to issuing RFPs [request for proposals]. In the past 12 months, I’ve heard more concerns about data management, for instance, as the utilities deal with astronomical amounts of meter and billing data. We’re used to dealing with data—that’s our job.” Utility-telco commonalities Still, at recent industry conferences, the two sides appeared engaged in a bit of a circle dance. The network operators appeared cautious not to oversell, aware that their audience is wary of so-called “public networks.” So the network operators like to describe their industry’s commonalities with the intelligent utility. Both serve vital public needs and, thus, are heavily regulated; both must embrace the digital revolution and other rapid technological innovations. And network operators openly acknowledge that utility-network operator matchups are limited by where it makes sense, according to Bob Gustin, industry solutions manager for utilities at Sprint Nextel. Due diligence The network operators themselves echo the utilities when they frankly acknowledge that a specific utility need must be met by an analysis of a network operator’s geographic reach in both wireless and wireline environments in a specific locale. Indeed, most network operators tout a consortium approach that can include their rival telcos, if that’s what serves the utility. Sprint’s Gustin offered one mantra on evaluating a network operator’s network reliability, availability and coverage: “Match your application needs to the bandwidth capabilities of carriers for your service territory,” because no carrier has ubiquity. Meanwhile, actual use cases have been touted to the industry. One concrete example of the public network operator’s value proposition is

neatly captured by a use case involving Texas-New Mexico Power (TNMP), a subsidiary of PNM Resources.

come down radically. For instance, in 2000 a public network might have charged as much as $16 per meter per month for data traffic; today that figure is less than a half dollar.

Utility Trial Gary Kessler, director of operational technology for PNM Resources, said that TNMP now uses a public wireless network for two-way communications with its advanced metering infrastructure (AMI). After an 18-month trial, the utility expects the Public Utility Commission of Texas (PUCT) to approve the first public wireless AMI deployment by an investor-owned utility in the country. “We’re the smallest IOU in Texas,” Kessler said. “We’re capital constrained and we wanted to avoid the cost of building an expensive private network. Plus, the TNMP service area is hardly contiguous; it’s scattered all over the state of Texas. After going out to a lot of vendors with a request for proposal, we received only two. The winning offer was plug and play, literally. We plugged in the meters and 30 minutes later we were collecting data, at or below the cost of sending readers physically into the field.” That’s another argument public network operators tout: costs have

An Overview Wayne Longcore, director of enterprise architecture and standards at Consumers Energy, takes a more conceptual overview. His utility routinely uses geographic information systems (GIS) to obtain a granular view of its application needs in order to select the appropriate network operator for each piece of its communications puzzle. Longcore may surprise some as an advocate for the public network operators. But he calls it hubris for electric utilities to believe that their teams can provide the same depth and redundancy of data security that so-called public networks provide. “If utility data at some point goes over the public network, you have what we call ‘defense in depth,’ various layers of security,” Longcore said. And the devotion to reliability, while laudable, needs frank examination, he suggested: “One hundred percent reliable? I don’t know of any such thing.” Acceptance and Caution Utility-to-utility conversations sometimes include grudging acceptance coupled with a tinge of defiance. At the UTC Telecom 2010 conference in Indianapolis in early summer, Richard Bertolo, project director for distribution business development at Hydro One, said, “Despite what carriers say, they cannot meet all your needs.” “An SLA [service level agreement] does me no good,” Bertolo added. “Giving me back a nickel under an emergency scenario does me no good.” But Mix at AT&T pointed out that public network operators have worked directly with electric utilities under disaster recovery scenarios by hardening cell sites and providing backup power. The network operator needs electricity, too, she said, which leads to “an exchange of prisoners” conundrum. Phil Carson is editor-in-chief of Intelligent Utility Daily.

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