Intelligent Utility MayJun2010

» RENEWABLES

VOL 2, ISSUE 3 » MAY/JUNE 2010 » WWW.INTELLIGENTUTILITY.COM

Where smart grid meets business—and reality.

SMART TECH EQUILIBRIUM ©©

Piloting the Grid with PMUs

©©

Consumer conversion Communications 101

©©

Identity crisis The CIO challenge

©©

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CONTENTS S PECIAL REPORT RENEWABLES

34 Energy boxed

SCE and AEP implement radical storage solutions

36 Greening the smart grid

Renewables are moving into the mainstream

DEPARTMENTS

24

FEATURES // MAY/JUNE 2010

Consumer conversion

19 Communication 101

ComEd pilots a simpler customer message

21 Price differentiation debate

Is time-of-use pricing preparing customers for real-time costs?

22 Playing catch-up

Billing systems aren’t yet ready for real-time pricing

Smart tech equilibrium

24 Piloting the grid

Learn what WECC utilities hope to learn from 150 new PMUs

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27 Outperforming the status quo

2

UCSD plays smart grid matchmaker for campus microgrid efficiency effort

28 Beyond the meter

Customers see Tampa Electric’s third-party demand-response program as a partnership

Identity crisis

30 The CIO challenge

Smart technology is changing utility insiders’ focus

32 Racking up smart grid returns

Stalwarts weigh in on ROI for industry

14 30 36

4 6

Drawing the line Transmissions 6

Letters from readers

8

What is an intelligent utility?

10 Real-time 12 The big picture

12 Top 11 cool ideas 14 Distinctive road map

44 Grid(un)lock

44 A bigger bang

46 End of the line

46 Forget the hardware

50 4D

50 There’s an app for that

52 Connections

52 Different flavors for different tastes

55 Out the door

55 Water smarts 57 Green transmission

50 55 Vol. 2, No. 3, 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.

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

Continuing Discussions ONE OF THE DISTINCT PLEASURES OF MY JOB AS THE EDITOR OF

Intelligent Utility magazine is that I am in near constant dialogue with industry thought leaders and implementers. These conversations enlighten me, adding to my understanding of the issues facing the industry as it continues to grow and change.

In the past six months, I’ve travelled across North America, doing a lot of listening. From electric utility visits to industry conferences, people are talking, and many are sharing their thoughts with me.

Several of the articles in this issue had their genesis in just such conversations: in-person at conferences, on the telephone, and online in forums such as Intelligent Utility Daily and through LinkedIn smart grid networks and groups. ??

A colleague at Energy Central introduced me to Tom Grate and Michael Ebert. First, a bit about their background.

Grate, now an independent software architect and software intellectual property consultant, was founding team member and group program director of Microsoft Commerce server, and co-founder and software architect of the first version of Microsoft BizTalk Server. Ebert is a principal research associate with the Center for Infrastructure Protection at George Mason University. Our hour-long conversation about home area network design prompted me to ask them to share their thoughts with our readership. [page 48]

??

Back in November, I posed a question on LinkedIn’s Smart Grid Executive Forum. I had just returned from the Edison Electric Institute Financial Conference, where I had heard mixed responses from utility CFOs about whether they would use smart meter technology to effect real-time pricing. I asked if this was a beneficial use of smart metering. In the ensuing months, discussion has been lively. John Waumbaugh, a vice president of Utility Integration Solutions, e-mailed me with some cogent thoughts about my question. I asked him to explore them further in an article for the Consumer Conversion feature in this issue. [page 24]

??

I first began discussing various utility perspectives on the smart grid with Jeff Buxton of Enspiria Solutions many months ago. As the conversation evolved, I gained a better understanding of how smart grid continues to evolve, and why it is so difficult to define.

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He and Mehrdod Mohseni share their thoughts on page 54.

4

I hope you enjoy the results of these conversations as much as I enjoyed the conversations themselves. As always, I encourage you to let me know what you think about these and other issues of import to the intelligent utility.

Kate Rowland Editor-in-Chief, Intelligent Utility magazine krowland@energycentral.com

sue? Then Enjoy the is

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TRANSMISSIONS

Letters from readers EDITO R I N CH I EF Kate Rowland

G R I D (U N) LO C K serving this state and interconnected utility systems and that the facility will serve the interests of electric system economy and reliability.”

This standard is one of the most progressive among other state standards (and one of the earliest to become effective prior to 1990) because it requires that new transmission lines must meet regional (not just state) plans for expansion of the interconnected utility systems and must also meet economic and reliability standards for the overall electric system both within and outside of Ohio. out-of-state benefits?

VIsIon

s t r at e g y

realIty

Progressive interconnection ©©

transmission facility certificate standards reflect changes to system

By Ann Warren

ohio’s regional plans

The legal standard in Ohio for obtaining a certificate of public convenience and necessity for transmission lines focuses both on regional plans for expansion of the electric power grid, and on the economy and reliability of the overall electric system, thus: “In the case of an electric transmission line or generating facility, that the facility is consistent with regional plans for expansion of the electric power grid of the electric systems

CH I EF CO PY EDITO R S Martha Collins, Joe Kovacs S EN I O R CO NTRI BUTO R S

future revisions possible

Although these three states have revised their certificate standards to reflect the interconnected nature of the nation’s transmission systems, there is certainly room in the future to accommodate additional revised certificate standards to reflect many improvements to the grid that are currently under way in various states.

First, revised standards could address the need to site transmission facilities in order to deliver energy to meet renewable portfolio standards in states sharing cross-border facilities. Second, revised standards could also emphasize the need to site facilities in order to deliver renewable energy from one state to load centers in another state. Finally, revised standards could take account of upgrades to the transmission system that stretch across state lines such as upgrades to install smart grid technologies and upgrades to install extra highvoltage transmission lines.

If these trends continue, obtaining certificates for the siting and construction of new transmission facilities, especially for facilities that impact more than one state, could be made significantly easier under such revised certificate standards, which place importance on upgrades to the transmission system not just in one state but to interconnected transmission systems across the country.

Phil Carson

Editor-in-chief, Intelligent Utility Daily pcarson@energycentral.com 303.228.4757 Ken Silverstein Editor-in-chief, EnergyBiz Insider ksilverstein@energycentral.com 304.345.5777

Ann Warren is an associate with Foley & Lardner LLP in its Washington, D.C., office.

VIsIon

s t r at e g y

realIty

FE ATU RE W RITER S Mike Breslin, John Johnson,

Transmission disconnect

Phil Johnson, Joe Kovacs, Laurel Lundstrom, Elizabeth McGowan, H. Christine Richards

©©

american clean energy leadership act draws flak over language

S EN I O R V ICE PR E S I DENT/G ROU P PU B LI S H ER Tim L. Tobeck

By Kate Rowland

Illinois’ competitive market

The legal standard in Illinois for obtaining a certificate of public convenience and necessity for transmission facilities considers the development of a competitive electricity market as a whole. It states: “…that the proposed construction will promote the development of an effectively competitive electricity

thInk of the amerIcan clean energy leadershIp act

of 2009 (S. 1462) as a fence. Then think of the words ‘measurable benefits’ as the barbed wire strung at the top of that fence.

This is an argument over language, with groups lining up at the fence to debate the barbed wire. Electric utilities, transmission companies, cooperatives, environmental groups, industrial and commercial customers and more are speaking up, debating the current change in language adopted by the Senate Committee on Energy and Natural Resources. Here’s a taste of what two different groups had to say in their letters to the Senate.

44

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 a r /a p r 2 010

In the past, state law standards for obtaInIng

certificates of public convenience and necessity to site transmission facilities focused on whether such new grId operatIons facilities were necessary for supplying the next two articles discuss two power to customers in one state. By issues of increasing importance focusing the certificate standards on the in the changing landscape of electricity transmission. ann energy needs of the consumers in only warren provides an overview of one state, state lawmakers failed to recogrevised state certificates of nize that siting and constructing new public convenience. Kate rowland transmission lines is often necessary to notes the dissention regarding improve the interconnected transmission the american clean energy leadership act. system that extends beyond the borders of each individual state.

In more recent times, lawmakers in several states have revised state certificate standards to recognize that the siting and construction of new transmission facilities is necessary for more than just the provision of energy to consumers in their states.

An analysis of the revised certificate standards in three states highlights this emerging trend that acknowledges the interconnected nature of individual transmission systems.

The legal standard in Kansas for obtaining a certificate of public convenience and necessity for transmission facilities centers on regional plans for expansion of the electric power grid: “The commission shall make its decision with respect to the necessity for and the reasonableness of the location of the proposed electric transmission line, taking into consideration the benefit to both consumers in Kansas and consumers outside the state and economic development benefits in Kansas.”

This standard was approved in 2003 and is also forward-looking in comparison with other state standards because even though it still takes into consideration the benefits to Kansas consumers and benefits to the economic development of Kansas, it also considers the benefits to consumers outside Kansas state borders as well.

krowland@energycentral.com 720.331.3555

market that operates efficiently, is equitable to all customers, and is the least cost means of satisfying those objectives.”

This standard became effective in 2007 and is also a pioneering standard as compared with other state standards because it requires that the proposed transmission facility must foster the development of an effectively competitive electricity market, which is not limited to just the market in the state of Illinois but presumably refers to the entire electricity market in the United States.

ttobeck@energycentral.com 303.228.4752 DI R EC TO R O F PRO DUC TI O N A N D CI RCU L ATI O N

Sarah W. Frazier

45

I N T E LL IG E N T U T I L I T Y /// M AY/J U N E 2 0 10

sfrazier@energycentral.com 303.228.4733

6

Transmission disconnect (March/April) Let’s set aside national energy policy for a moment. Utilities and independent transmission companies would prefer legislation that clears away hurdles and spreads the cost as widely as possible because transmission construction and operation is a growth area for them. Industrial customers want more restrictive legislation because they don’t want to pay for that transmission if they don’t have to. This is going to be a particularly problematic issue in the Midwest, where large industry is concentrated and fighting for its life against foreign competitors that have lower labor, health and energy costs.

There is another way to look at this issue. Smart consumers and suppliers are very conscious of the delivered cost of goods and services rather than just the advertised price. Consumers are unable to control where they source their power supply, but suppliers do have some control over where they site plants. For this reason, it seems to me the industrial customers have a point.

In merchant power’s early days, there was a land rush to build IPPs, and developers employed

the following highly sophisticated approach. Obtain an infrastructure map. Locate all electric transmission and natural gas facilities. Put your plant where a gas transmission line and an electric transmission line either intersect or are very close together. Very often the result was IPPs located in places where the cost of hooking up gas and power were very low, and transmission congestion from nearby utility generators made it difficult or impossible for the plant to operate profitably.

National priorities are fine, but if policymakers are at all concerned about the impact on consumers, they should think carefully about which parties are best positioned to manage the risks associated with renewable energy development and make sure they have appropriate incentives to manage them properly. Consumers are clearly not one of those parties.

Jack Ellis To contribute to the Transmissions department, please e-mail your submission to intelligentutility.editor@energycentral.

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KEMA’s Utility of the Future Forum 2010 Strategic choices – striking equilibrium

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Join your industry peers in examining new approaches to balancing utility objectives, technology, business models and environmental concerns with long-term direction. Engage in executive-level discussions on the utility CEO’s perspective, the ‘smart’ energy consumer, demand response and energy efficiency, generation, carbon and environment, federal and state regulations, and financial balance.

Utility of the Future 2010 confirmed speakers include: •> Phillip Barnett, CFO, PECO •> •>

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•> •>

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•> •>

Bob Catell, Chairman, NY Smart Grid Consortium and former CEO, National Grid US

•> •>

Harold DePriest, CEO, Chattanooga Electric Power Board

•> •>

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•> •>

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Michael Mudd, CEO, FutureGen

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Jim Rogers, CEO, Duke Energy

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Hon. Garry Brown, Chairman, New York Public Service Commission Bill Capp, CEO, Beacon Power

Join the discussion: June 23 – 25, 2010 Four Seasons Hotel Washington DC Register now at: www.kema.com/UtilityFuture2010

Scott DePasquale, Partner, Braemar Energy Ventures Hon. David Lott Hardy, Chairman, Indiana Utility Regulatory Commission Ben Koch, Managing Partner, Southwest Securities, Inc.

For more details contact: Cate McCaslin Conference Manager cate.mccaslin@kema.com 360.598.3582

Hon. Philip Moeller, Commissioner, FERC Hon. David O’Brien, Commissioner, Vermont Department of Public Service Hon. Alan Schriber, Chairman, Public Utilities Commission of Ohio Ivo Steklac, CEO, GreenBox

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TRANSMISSIONS

Balancing reality with vision and strategy. This magazine

What is an intelligent utility? + It’s all about delivering information-enabled energy.

focuses on what real utilities are doing 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 grid and intelligent utility vision. Therefore, this magazine groups articles that deal with the vision, strategy and reality on key topics. Note that some articles may cover more than one area.

You will notice the following tabs

AN INTELLIGENT UTILITY APPLIES INFORMATION TO

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

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

People The knowledge, skills and abilities required in an information-enabled environment

??

Process & technology Business objectives and their impact on process and smart technology deployment

??

Finance Investment trends associated with smart technologies

??

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 direction the utility industry may be heading in or the possibilities with a new technology or a technology 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

Economic models The challenges and opportunities of new paradigms

??

throughout the issue:

Public policy

The impact of politics on energy

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

Reality: An article that looks at where utilities really are today.

For example, there may be great strategies and visions out there, but utilities today may face challenges

I N T E LL IG E N T U T I L I T Y /// M AY/J U N E 2 0 10

in heading toward the vision.

8

BUILDING A WORLD OF DIFFERENCE ®

Don’t you need a partner who understands the shoes you’re in?

There’s no shortage of consultants out there. Most of them, it seems, are ready and willing to sell you their two cents, regardless of the

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>Market Analysis

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>Rates & Financing

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>Regulatory & Litigation Support

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R E A L-T I M E

Get involved now FOR REAL-TIME NEWS

feeds on anything and everything related to smart grid and intelligent utility, please go to our new Web site at www.IntelligentUtility.com.

Here, you’ll find a daily dose of what you’ve come to expect in Intelligent Utility magazine as we cut through the hype to cover the realities of smart grid and intelligent utility initiatives. These new online resources will bring “real-time” intelligence to all of the information out there about the smart grid—and beyond. We offer a detailed view of the systems, processes and people necessary to delivering information-enabled energy.

In between magazine issues, please join us every weekday as we track how utilities and other critical organizations are forging ahead to deliver on the promise of information-enabled energy—all the way from generation to end user.

Here are some other ways to interact in real-time:

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

JUNE 8-10

POWERGRID Europe

Amsterdam, The Netherlands

I N T E LL IG E N T U T I L I T Y /// M AY/J U N E 2 0 10

Intelligent Utility Daily

10

Our new Intelligent Utility Daily e-mail publication, along with www.IntelligentUtility.com, doesn’t just cover the news, but also provides you with original daily analysis and commentary from our in-house intelligent utility experts.

Intelligent Utility Daily encourages reader response and commentary on the issues we focus on each day. We encourage you to join this growing online community of thought leaders willing to discuss and debate the topics at hand, so that we may all learn from the resulting discussion.

14-17

EPRI PQ and Smart Distribution 2010

Quebec City, PQ

15-16

Smart Grid Interoperability Event

Toronto, ON

15-16

Saskatchewan Energy Symposium II

Saskatoon, SK

16-17

Realisation of the Future Grid

London, UK

23-25

KEMA’s 3rd Annual Utility

Washington, DC

of the Future Forum 24-27

Connectivity Week 2010

Santa Clara, CA

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 Create your own blog at www.energycentralblogs.com Submit your own article to www.energypulse.net

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THE BIG PICTURE VISION

S T R AT E G Y

REALITY

Top 11 cool ideas + As always, it is more than just technology

By H. Christine Richards ORIGINALLY, I PLANNED TO FOCUS ON THE TOP 11 NEW IDEAS

and technologies out there in the intelligent utility space. I envisioned this list as the “cool technology list,” but we always hear so much about the technology. So I figured I would expand the list’s horizons and account for all the other factors that fuel the success of a smarter grid and more intelligent utility.

As I got into the research, I then realized that the “new” aspect of the list was kind of pesky. There are many “old” ideas out there that turn into something new when they are placed in the context of smart grid and intelligent utility.

So this list talks about ideas—both INNOVATION UNCOVERED “old new” and “new new”—that are The next two articles feature pushing past the commonly held innovative ideas. H. Christine perceptions about the smart grid.

Richards focuses on ideas pushing Here’s the list of cool ideas that past commonly held smart grid I’d like to see go from ideas to perceptions. Phil Johnson discusses full-blown trends to necessities for statewide innovation in play in West electricity. They indicate a movement Virginia, and how one utility there is toward supporting a smarter, and moving forward with smart grid plans. more reliable, efficient, sustainable and consumer-empowered grid.

And speaking of ideas, I couldn’t think of any clever ranking scheme this time around (after using IQ for July/August 2009’s UtiliQ ranking, what else is there?), but hopefully this list will inspire some ideas for you and your company.

in technologies from customers who want to better understand their energy consumption.

Old becoming new again

Another key theme in this list is that old utility stuff is getting a fresh coat of paint. For example, asset management and designing the grid are nothing new—and energy efficiency is no spring chicken—but think about how smart grid and a more intelligent utility can transform them: ??

management, a smarter grid will bring much more asset data that can then be used to better monitor and maintain critical assets. At the same time, new smart assets will need to be maintained as well. This will require different skill sets for technicians charged with maintaining the grid. ??

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With designing the grid, engineers and designers have to account for all of these new smart components. At the same time, these components will bring new information about the grid to utility companies, so they can make more informed design and maintenance decisions in

More than technology

So you have the chart to your right that lays out all 11 ideas in no particular order, but I want to use this article to further discuss some of the key themes across these ideas. The first key theme is that cool ideas need to involve more than just technology. Essentially, how do you set up an environment to support innovation in the smart grid and intelligent utility space?

With ideas such as customer outreach, real-time pricing and democratizing power production, it is not so much about technologies as it is about the people and regulatory aspects. In the case of customer outreach, this idea is all about how to better communicate with electricity customers about what is happening in the smart grid arena—and ultimately how it will affect their lives. Effective customer outreach upfront will likely help save utilities from headaches down the road when convincing customers that the meters on their houses are not causing cancer. In real-time pricing, we’re talking about adjusting pricing structures, which has nothing to do with technology except that it may spur investments

In the case of asset

the future. ??

Energy efficiency can make a big leap in the smart grid arena with the spread of building automation systems and home area networks. With more data available to them, customers can also make better decisions about how to improve energy efficiency at their premises, such as replacing an energy hog refrigerator or identifying when it is time to service the air conditioner.

TOP 11 COOL IDEAS WHY IT’S COOL

TREND I’D LIKE TO SEE

KINKS TO WORK OUT

SMART DESIGN = SMARTER GRID

We talk a lot about smart components, but every new component could affect so many other parts of the grid. Smart design is what can successfully bring together all of these components.

As the grid gets smarter, design gets smarter, too. It won’t be just about digitizing drawings, but also improving analysis capabilities and making better connections between the grid and customer building information models.

Collecting and bringing in all of the right information to the right places for design and maintenance work.

COMMON KNOWLEDGE

Things like the Texas common portal and data repository, and the work by Google and Microsoft, are all about how to get information to the customers in a way they would actually want to use.

Data first, then display. A focus on how to make the data available to customers now as opposed to the current focus on devices to display the information.

Information available a bit closer to “real-time.” In some cases, customers can access 15-minute interval data, but have to wait a day or two to get the data.

CUSTOMER OUTREACH

My parents finally understand what I write about.

More customer outreach on smart grid and why customers should care. And pricing signals to help them care. (see below)

With PG&E and Oncor as examples, the industry needs to work through how much communication needs to happen with customers.

REAL-TIME PRICING, REALLY

Paying the real price of electricity will incentivize customers to react when utilities need it most and encourage customers to invest in technologies that will help save them money, if it makes sense to do so.

More work with real-time pricing and studying its effect on smart grid technology investments by the consumer.

Besides obvious regulatory hurdles, not having to look at energy prices constantly. What automation can help people make better decisions, well, automatically?

POWER TO THE CONSUMER, LITERALLY

Living off the grid, or at least part-time off the grid (during an outage, for example), means greater flexibility with power consumption.

More flexible options for microgrids, distributed generation and storage.

Regulatory challenges and the need to further develop some technologies, such as distributed storage.

WRANGLING ELECTRONS

The ability to store energy opens up all sorts of opportunities to make renewables practical and help utilities better meet peak demand needs without building additional power plants.

More companies like Ice Energy that are using technologies to help customers store energy at the premises and utilities that are finding ways to aggregate these storage devices.

Efficiently storing energy is not easy. As my husband points out, major advances in this space may require changing some of our fundamental knowledge about physics. That’s all.

DEMOCRATIZING POWER PRODUCTION

Empowering energy customers— large and small—to now become energy producers.

Groups like NC GreenPower that help small power producers get started. A movement toward the role of utilities as an “eBay” for transactions between power producers.

Overcoming grid infrastructure hurdles for delivering two-way power and managing a significant number of small power producers.

ASSET MANAGEMENT

There is much focus on installing smart components right now, but what about maintaining them once they’ve been installed.

Utilities discussing how they plan to maintain and upgrade smart infrastructure.

Collecting the right information and providing opportunities for linking data with maintenance systems.

SMART ENERGY ASSURANCE

Acknowledging the link between smart grid and energy assurance planning as seen through efforts by the National Association of State Energy Officials (NASEO).

State energy assurance and emergency preparedness plans include smart grid, both from the value it can offer during an emergency and the vulnerabilities of it.

Educating state-level stakeholders about the smart grid and its value.

PROJECT PAUSE

Some utilities that have multiple smart grid projects are pausing to reevaluate projects and see how they can make stronger connections between them.

Increasing connections between projects, so smart grid projects are not seen as standalone projects, but rather as a new way of doing business for the entire utility.

Established silos in utilities and regulatory limitations against different business groups cooperating with one another.

EFFICIENCY = SMART

A lot of smart grid efforts are under way, but energy-efficiency initiatives are moving full-steam ahead, too.

Stronger links between energy efficiency and smart grid, such as better connecting building automation systems with a smart grid.

Because energy efficiency is such a huge topic, can efforts such as weather stripping and insulation be connected to the smart grid?

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IDEA

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THE BIG PICTURE Dollars versus societal benefits

VISION

S T R AT E G Y

REALITY

Distinctive road map + Allegheny Power is building an advanced utility infrastructure

By Phil Johnson WEST VIRGINIA HAS STAKED A CLAIM AS THE FIRST STATE

I N T E LL IG E N T U T I L I T Y /// M AY/J U N E 2 0 10

in the nation to have what is being depicted as a legitimate statewide smart grid plan in place and is moving toward implementation.

And while other states may argue West Virginia’s status of being first, there’s no missing the indications that both Appalachian Power—a unit of American Electric Power—and Allegheny Power, the West Virginia electric-delivery arm of Allegheny Energy, are striving for substantial headway in their West Virginia smart grid plans and initiatives.

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Plan is guiding road map

Harley Mayfield, an Allegheny Power distribution engineer working out of Morgantown, W.Va.—who has been deeply involved in Allegheny smart grid strategy and progress over the past several years—figuratively overflows with information about Allegheny’s West Virginia smart grid approach.

“We’re using the West Virginia Smart Grid Implementation Plan as a road map to help guide our decisions,” said Mayfield. “The Implementation Plan was developed as a very aggressive five-year deployment plan. But I don’t think either company [Allegheny or Appalachian] feels it’s reasonable to try to do it in five years because of the massive funding it would require.”

Allegheny and Appalachian are nonetheless hitting the accelerator with their West Virginia smart grid efforts.

“The Implementation Plan is based on a business model of recovering costs,” said Mayfield. “And it also relies heavily on the benefits to the consumer, benefits to the public in general and societal benefits. Traditionally, the state public service commission will say to the utility, ‘OK, what’s it going to cost you? And what’s the benefit to the company? How much money is it going to save you?’ Or, ‘How much money is it going to make you?’

“In this case, just the straight dollars and cents don’t justify the expense. But when you start trying to assign dollar amounts to how society benefits from it, then it makes it a winner from that standpoint.”

The West Virginia Implementation Plan sets far-reaching goals within a timeframe that will evolve into more realistic estimates of progress at given budgets over specified periods.

“We realized we needed to look at it from our viewpoint—a more specific look than the Implementation Plan took,” Mayfield said. “So I’m now working with a small group within our company that’s developing Allegheny’s road map. We’ve finished our initial determination of where we are and where we would like to be.

“Now, some of the differences revolve around how quickly do you make the expenditures? And I think our Allegheny Power president [Paul Evanson] mentioned the phrase ‘spending at the speed of value’— meaning what is it going to do for the customers? What’s it going to do for the company? What’s it going to do for the stockholders?”

Allegheny’s AUI road map

The epicenter of some of Allegheny’s smart grid pilot projects is a Morgantown facility called Research Ridge, actually a commercial/ industrial-park property owned and operated by energy-consulting firm Augusta Systems.

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THE BIG PICTURE And Augusta, in collaboration with Allegheny, is working on what is defined as a version of smart grid that goes beyond AMR, beyond AMI—to a concept the two companies label AUI: advanced utility infrastructure.

“AUI is something we wanted to try to capture as a utility,” Mayfield said.

“Of course, we feel that AMI—the advanced metering infrastructure—is a component part of the smart grid. It’s not the whole smart grid, but it is an important part.

“So we did some early research. What we were originally trying to show at the Research Ridge facility was the concept that we could purchase meters from multiple vendors, and use all those meters to directly communicate with an Allegheny Power-owned and -installed communication system.”

Competition has multiple benefits

It’s largely a matter of establishing a competitive basis among various vendors— thus to reduce costs as the vendors compete for business.

“In a typical AMI deployment, you would purchase a system from Company X—and Company X, because of the way the system goes together, only its meter will work,” said Mayfield. “So if you buy one company’s system, you wouldn’t When you start trying be able to put in another company’s meter because the meter wouldn’t work with to assign dollar that system.

“And that could bring up an even bigger amounts to how logistics problem: What do you do if something happens to that company society benefits, it whose system you bought?”

Obviously, competition is intended to makes it a winner not only expand choices, but also hold every vendor accountable. from that standpoint.

“We wanted to show that you could put Meter A beside Meter B beside Meter C—and still work,” Mayfield said. “I think we demonstrated that. And I think industrywide that concept has become more important.”

Allegheny’s West Virginia ambition is having significant impact as the company further advances its smart grid initiatives.

“We’re continuing to propose a series of pilot projects,” said Mayfield.

“We want to test different technologies and different software manufacturers to see how we can best integrate the different component parts of the smart grid into something that works specifically for Allegheny Power.”

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Technology + geography = unique solutions

Coincidentally, Mayfield notes that Allegheny is keenly aware that specific strategies must accommodate the unique aspects of energy delivery in West Virginia.

“One of the hazards we have to keep in mind with the smart grid is that what works someplace else won’t necessarily work here,” Mayfield said. “Look at California, for example, where you have customer densities in the hundreds to thousands per square mile.

“That same type of implementation is simply not going to work in West Virginia, where we have customer densities in the 10- to 15-customer range per square mile.

“Also, the same technologies that work in the Midwest—where it’s flat as a tabletop—will not work in West Virginia, where you have elevation changes of hundreds of feet in less than a quarter of a mile.”

Design differences yield different approaches.

“The major circuits in some companies’ systems are all interconnected, and you can parallel one with another pretty much as you want.

They’re designed with that capability,” said Mayfield. “So if they want to transfer a load, they just push a switch, and their system is strong enough that they can transfer complete circuits and not have a problem.

“With Allegheny’s system—in which the circuits are not designed to be parallel—we need to look at what’s the existing load? And what’s going to happen to the voltage? And we’re going to have to design the system differently than those others.”

Customer acceptance crucial

Although West Virginia has yet to establish a dynamic-pricing infrastructure, Allegheny is fully aware that if dynamic pricing is eventually implemented, the relative level of customer acceptance is critical.

“We joke about some things here,” said Mayfield. “But when we start talking about an electric system that requires agreeing to give someone else control of your electricity usage, which there are automated systems out there—you know, West Virginia’s state motto is, ‘A mountaineer is always free.’

“So you find they don’t really like to give someone else control of their house. Now, when you talk about broader smart grid concepts, people realize this is something that could be important. But they’re also worried about the cost.”

Phil Johnson is a freelance business writer and speechwriter.

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S T R AT E G Y

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Communication 101 + Professor teaches utilities to walk the smart grid talk

By Elizabeth McGowan INSIDERS AT COMMONWEALTH EDISON

Nix utility-speak His first lesson? Veer away from the acronym-heavy alphabet soup of utility-speak and drop the Big Brother act. People tend to (yawn) shut down when utilities drone on about “demand response,” “load shaping”

Efforts need to resonate “This is about teaching utilities to look at everything from how to deliver a bill to how to charge an electric vehicle from a customer perspective,” Honebein said. “Utilities are essentially monopolies so the need to engage customers hasn’t been necessary until now.”

He sketched a theoretical blueprint for utility success in the June 2009 issue of The Electricity Journal. His article, “Will Smart Meters Ripen or Rot? Five First Principles for Embracing Customers as Co-Creators of Value,” offers a list of suggestions that researchers, regulators, utilities, interveners and vendors can employ as they wrestle with business cases, regulatory filings and strategic plans.

Each utility requires a champion in upper management who believes customer communication is the right way forward, Honebein said. That’s how these needs can penetrate finance, engineering, information technology and other utility departments that are more isolated from customers.

Piloting the lessons learned Jensen and his ComEd team are taking Honebein’s twoway-street lessons to heart. To forge ahead with what they proudly call the most sophisticated test of customer applications in the country, they simplified the message for the

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ILLUSTRATION BY CLIFTON ALEXANDER

figured they would ace their advanced metering infrastructure (AMI) pilot program rollout. Who, after all, wouldn’t be thrilled to delve into a survey and eight scintillating pages of intricate text detailing all the bells and whistles that automated metering infrastructure makes possible?

Their customers, it turns out. Consequently, last summer’s introduction landed with a resounding thud.

“Our focus groups were totally confused,” said Val Jensen, vice president of marketing and environmental programs at the CHARTING NEW PATHS Chicago-based The consumer is going to be the one investor owned who makes or breaks smart grid utility. “When we progress. Here, Elizabeth McGowan tested our protolooks at ComEd’s work, Kate type, we found Rowland examines California, out we completely and John Waumbaugh discusses missed the boat.” back-office catch-up.

Enter Peter Honebein. Call him the smart grid “demystifier” for the common man. As carbon constraints and digital technology revolutionize electricity delivery, the energetic marketing professor and entrepreneur is intent on teaching ComEd and others how to engage, enlighten and educate customers.

and “price signals.” But they perk up when talk turns to incentives, saving money and comprehending their Sanskrit-like power bills.

“Customers haven’t been doing this all of their lives,” said Honebein, who teaches classes in fields such as marketing and customer experience design at the University of Nevada, Reno. “You can’t expect them to reduce energy use right off the bat. But over time, small steps can shift their behavior.”

Don’t wait for customers to absorb terminology such as critical peak pricing and time-of-use rates via osmosis, he continued. Instead, explain them in practical terms so customers understand they are beneficial, not punitive.

For smart meters to become more than sleek, beautifully mounted hunks of metal and plastic, utilities have to ditch their paternalistic patterns and offer convenience, choice and control.

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CONSUMER CONVERSION

8,000 households who would eventually participate in the ible rate structures beyond the pilot stage. “The whole value yearlong AMI pilot. proposition is something we’re trying to understand better.

Indeed, ComEd’s pilot rollout is complex. Through May That is kind of the Holy Grail with this.”

2011, it will test five different rate structures in combination Ultimately, Honebein said, matchmaking between the with three types of in-home energy measuring devices. smart grid and customers boils down to utilities changing At Honebein’s direction, ComEd slimmed down the how they introduce products, services and programs. introductory packet, rewording it so customers would imme- Turning a marriage of convenience into a partnership is a diately understand that these changes could literally give matter of coordinating efforts with outsiders such as market them more power over their electricity bills. Those wholesale research firms, project managers and vendors of changes registered with a second focus, Jensen pointed out. specific products.

“Usually, when people hear they are going to be under a new rate structure, they think you are Interaction allows cool things to emerge. raising their rates,” Jensen said.

“But what people took away this Customers begin to explore and experiment, time is that they could save money with different rates.” nature takes its course, and some of T hat ’s t he whole poi nt, Honebein emphasized. Such those results can be evolutionary.

Peter Honebein adaptations will be an abysmal failure unless utilities tune in to the knowledge, skills and attitudes of their customers. Understanding lifestyle types Utilities need to learn details such as how customers want Honebein’s observations indicate customers fall into four to be billed and how they want to be notified about energy basic lifestyle categories—frugal, green, convenience and conservation measures. technophile. Utilities need to understand what drives ComEd listened and responded in other ways, too. each type before they can figure out a mutually beneficial Several more mailings are planned, including a postcard approach to energy savings. mailer to remind customers about the pilot start-up For instance, a technophile might likely be an early this spring. Participants have access to a Web site where adopter who drives a plug-in hybrid electric vehicle. As a they can log in to monitor their personal energy use utility customer, that person will want to know if they have and a special call center operated by the local Center for the proper infrastructure for charging a PHEV, prime times Neighborhood Technology where representatives can for charging at the lowest cost and how much money he can answer any queries. save by doing it then.

“Over the course of all of this, we learned a lot and “The idea is to translate these types of situation into a changed our mind a lot as a result of what stakeholders scenario and tell a story,” Honebein said. “When you tell were telling us,” Jensen said. “This pilot was collaboratively a story, you transition from the rational to the emotional, designed and the results will be collaboratively shared.” and the emotions and desires of the customer come to life. Technophiles have an emotional bond with data.

Concerns remain Engineers at a utility might ask who needs to know all of Still, Jensen has a number of concerns. One, ComEd is a that, but utilities need to figure out how to contribute to summer peaker and he’s curious if a pilot rollout so close that customer’s happiness.” to the warmer months gives participants enough time to In Honebein’s ideal world, utilities will either adapt or adjust to a new utility model. lose out on a once-in-a-century opportunity.

And two, though the public utility commission “What you don’t want to say as a utility is, ‘Here’s your approved ComEd’s experimental plan, Illinois is a new rate, it’s critical peak pricing. We’ll talk to you later competitive retail state so marketing anything beyond this summer,’ ” he concluded. “Interaction allows cool a flat rate is a squishy arena. Who, he wonders, will fill things to emerge. Customers begin to explore and experithat “behind-the-meter” niche? Will it be Google with its ment, nature takes its course, and some of those results PowerMeter or some other entity? It’s a major policy issue can be evolutionary.” that each state needs to solve, he said.

“It’s important that somebody has a business model that Reporter Elizabeth McGowan writes about a plethora of energy delivers value to customers,” Jensen said about taking flex- and environment issues from Washington, D.C.

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Price debate + California pushes forward, but are consumers ready?

By Kate Rowland THE

OLD

ADAGE

THAT

RESIDENTIAL

consumers don’t truly understand electricity pricing has come back to haunt electric utilities as they begin to introduce smart metering and dynamic pricing.

Reliability, on the other hand, is a concept consumers have no trouble getting their heads around. The trouble, to date, seems to be the ability to interrelate the two.

In fact, consumer acceptance and adoption are among the top challenges intelligent utilities currently face with regard to smart grid initiatives.

Education remains essential In the face of vocal residential pushback and more than 600 complaints to the CPUC—mostly from the PG&E service area—the commission at the end of March selected an independent evaluator to test and validate meter billing and accuracy of PG&E’s smart meters.

Andrew Tang, PG&E’s senior director of customer care, welcomed the independent evaluation. “We continue to wholeheartedly support the CPUC’s independent thirdparty evaluation,” he said, and added that the utility is committed to its customers, and is continuing its education efforts around the benefits of its SmartMeter technology.

“As with any initiative rollout of this magnitude, one would expect to run into challenges, whether physical, technological, customer acceptance or human error,” he added. “As we address those challenges, we will identify any issues and make them right with our customers. When customers have questions about their meters or bills, we will work with them to address their questions.”

Consumer engagement is key As California continues moving along its intended path to establish dynamic pricing statewide, the CPUC has also requested commentary on the state’s smart grid deployment plans, and the best methods for providing access to electricity prices and usage.

And what it is hearing so far reflects current industry thought on the ability for utilities to engage their consumers.

As one company focusing its efforts on consumer-driven energy management and efficiency wrote in its submission to the CPUC: “[We] argue that consumer engagement is fundamental to the next generation of energy efficiency and demand response applications, particularly in a smart grid environment.”

But price of electricity alone may not completely engage the consumer to change behavior, which is one of California’s goals in its dynamic pricing plan. It continued: “Price as a lone motivator may overlook the significant potential of other factors, such as improving the environment, competition, cooperation, peer comparisons, learning and recognition and rewards.”

Answers uncertain Clearly, the answer to full consumer engagement is out there. Whether dynamic pricing alone will be enough to facilitate the necessary change in electricity usage behavior remains to be seen.

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California turns to economic incentives In California, where recent consumer pushback has been both vocal and litigious, the California Public Utilities Commission (CPUC) is moving to establish dynamic electricity prices for the entire state, including residential consumers as well as commercial, industrial and agricultural customers.

In a concerted effort to move in this direction, the CPUC recently approved new rate structures for Pacific Gas & Electric Co.’s (PG&E) commercial, industrial and agricultural customers. The new dynamic pricing scheme will charge varying rates for peak and non-peak times, with an initial opt-out option for the approximately 12 peak-day events.

Customers will be given one-day notification of these events, so they can plan to switch electrical usage. All customers using peak-day pricing rates will be given bill stabilization for the first year, as well as a hedging option to reduce bill volatility.

On May 1, PG&E’s large commercial and industrial customers were automatically switched to the dynamic pricing scheme, unless they proactively chose to opt out. Small and medium commercial and industrial customers default to the peak-day pricing plan beginning Nov. 1, 2011.

Michael R. Peevy, CPUC’s president, feels this move will increase customer involvement. “By providing real economic incentives to reduce electric demand during peak periods, we can increase customer involvement in managing California’s energy supply, reduce greenhouse gas emissions, and manage future power plant development costs,” he said.

In agreeing to the new rates, the CPUC also ordered PG&E to conduct outreach and education activities and measures to ensure that customers are aware of and understand the new rates and options.

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CONSUMER CONVERSION

VISION

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REALITY

Playing catch-up + Are we ready for real-time pricing?

By John Waumbaugh

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IT’S A REAL-TIME WORLD OUT THERE, BUT

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the electric utility customer can’t participate.

The utility customer can only change his rate plan on his next billing cycle and, in many cases, only when the meter is replaced. He can change his cable TV plan at any time via the Internet and this change takes place immediately.

The electric utility customer can cancel or start service at 1:33 p.m. on March 30; however, the bill must start whenever the meter can be read (if manual reading) or, effective midnight. A cell phone customer can establish or stop cell phone service via the Internet and this occurs immediately. Telecommunications providers can roll out a new rate plan in a short time, but it can take up to a year or more for an electric utility to make a new rate plan available to its customers.

The electric utility industry is experiencing an upheaval with the focus on smart metering and smart grid. With this upheaval, the concepts of dynamic pricing and real-time pricing are being discussed as we are creating a smart metering infrastructure capable of measuring and reporting hourly energy consumption and providing price signals to the consumer.

However, the back office systems and processes of the electric utility are not capable of supporting the customer who is savvy about technology and communications.

These systems and processes were constructed for the days when the meter reader tromped through the daisies once a month and the rates were simple (TOU, or time of use, is considered a complex rate, yet is really just the monthly consumption divided into two different time periods).

OK, I’ll acknowledge that utilities are presently billing some of their commercial customers on very special and complex rates, but this usually takes unnatural acts conducted in special-purpose systems and they are not available to all customers.

Billing system needs to change For the mass market to take advantage of this new smartmetering technology and offer consumers rates and tariffs that allow them to be charged based on the real price of energy and, consequently, change their behavior to reduce or shift consumption, all the systems involved in the meter-to-cash process must have the flexibility to

make it happen. Advanced metering infrastructure (AMI) and meter data management(MDM) have changed meter reading and meter data processing to meet this flexibility, but the billing has not changed.

The concept of meter reading routes and billing cycles is heavily embedded in the back office systems and processes and limits the ability of customers to change rates. Most billing systems cannot support splitting the billing period with two different tariff programs. Many billing systems don’t even track time, only dates. Consequently, everything is assumed to happen at midnight. This is also a limitation of some MDM implementations because they are based on

CHANGES NEEDED

These same sweeping changes are going to be necessary in order for the utility industry to offer the new dynamic and real-time pricing plans that are envisioned as part of the overall smart metering initiatives. These are going to include: ??

??

??

REGULATORY CHANGES The regulations must support the flexibility needed for the business processes and systems to support these new rates and services. As an example, some states have regulations that require residential customers to only change rates on the billing cycle or require the display of the actual billing determinant on the meter face. Any regulation that limits the consumer from changing tariffs, or limits the flexibility of tariffs and offerings, will need to be updated to eliminate these barriers.

BACK OFFICE SYSTEM CHANGES The systems (MDM and CIS) must be able to be change quickly and easily (e.g., yearlong software development should not be required) to support new tariff structures and allow a customer to change any day and at any time. All systems must remove the cycle and day boundary limitations.

These systems should support variable-pricing mechanisms where price of power or credits for reduction can change daily.

BACK OFFICE PROCESS CHANGES Processes also need to change to become more adaptable in order to allow flexible programs and customer participation. This includes providing more information to the customer about pricing and energy consumption quickly and accurately (faster than yesterday’s data today).It should not be inconceivable that a consumer could purchase a home energy-management system (with smart thermostats and in-home displays) and be able to access the utility Web site to select a rate that provides for unlimited usage during weekends and evenings and four-part TOU during the weekdays, as well as an opportunity to participate in a demand-response program that would credit the consumer for every kWh reduced during critical peak periods, which could occur at any time. We should expect more of our systems and processes.

the assumption that activities occur from midnight to the As a point of reference, in Finland, as of March 1, following midnight. Many billing systems still expect to 2009, every residential customer can change suppliers receive a register read as if someone (and therefore rates) on a daily has read the face of the meter, which basis. The consumers will never makes the new dynamic rates with be billed on an estimated meter Smart metering is here changing pricing and baseline calcuread and anyone can sign up for lations difficult. real-time hourly pricing rates. and smart grid is coming.

Many utilities have built their Now that’s a goal! own special purpose applications to Smart metering is here and The technology that is pre-process the interval data and pass smart grid is coming. The techline item values to the billing system nology that is being implemented being implemented is to allow billing of these complex is flexible and can be upgraded, rates, but these applications are typiand communication is becoming flexible and closer to cally limited in capacity as well as faster and closer to real-time. riddled with manual processes.

Market forces are emerging real-time.

The telecommunications industry to begin offering consumers a underwent a similar upheaval in variety of options that enable the 1990s to replace equipment, information systems them to lower their consumption and become active and business processes. These changes were necessary to participants in the dynamic world of electricity pricing and meet the market needs for flexible communication and a demand response. Utility back office systems and processes multitude of rate options. These changes now allow the need to step up to meet this changing environment and not industry to react to consumer needs and competition become the weakest link in the chain. No one wants to hear quickly. (I just changed my cell phone plan last month “We can’t bill that.” online to take advantage of a new rate offering and allow my kids to text more.)

John Waumbaugh is a vice president of Utility Integration Solutions.

“

”

“We need partners that

understand our vision for the Smart Grid.”

Aclara understands that utilities need to do more than collect data. We are driving a future that integrates AMI, SCADA, distribution automation, and more into an Intelligent Infrastructure™ with the capability for communications and control. With the strength of our solutions for electric, gas, and water utilities, we understand your vision. With our network we will take you there. Aclara Leads.

Create Your Intelligent Infrastructure™ Find out more at Aclara.com 1.800.297.2728 | info@aclara.com

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Aclara leads.

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Smart Tech EQUILIBRIUM VISION

S T R AT E G Y

REALITY

Piloting the grid + Western synchrophasor efforts promise improved visibility

By Phil Carson

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YOU’RE

FLYING

A

PLANE

IN

BAD

weather, you can always switch from piloting visually to depending on your instruments.

For those piloting an electric grid, there is no precise analogy. Grid operators have lacked sufficiently detailed data for realSMART VIEWS time, situational This section looks at how utilities are awareness that balancing new technologies with that can allow them to already existing. Phil Carson looks at prevent blackouts. the addition of synchrophasers to In programs the Western Interconnection. Laurel just getting under Lundstrom explores UC San Diego’s way, however, unique technology partnership. And the nation’s three Mike Breslin puts third-party demand major interconresponse under the microscope. nections are upgrading their grids by adding synchrophasors, communication networks, and data analysis and presentation technologies to give operators an unprecedented view into the grid’s health.

In t he c a se of t he Wester n Interconnection, the Western Electricity Coordinating Council (WECC) has established the Western Interconnection Synchrophasor Program (WISP), which holds the promise of delivering actionable intelligence. A look at two participating utilities reveals how they have prepared for this moment,

Wide area visibility enabled The advent of civilian use of the global positioning system (GPS) in the early 1990s has turned phasors into synchrophasors and vastly expanded their usefulness, according to Jeff Dagle, chief electrical engineer at the Pacific Northwest National Laboratory.

Supervisory control and data acquisition (SCADA) systems have limitations because the data they produce is not synchronized, is taken at relatively low sample rates and has some latency between occurrence and visibility in the control room, Dagle explained. This data can be massaged to reflect conditions on the grid but not in real time.

Today’s synchrophasors, as their name implies, can produce GPS-enabled, time-stamped (and thus able to be synchronized) data up to 60 samples per second. This higher quality measurement can provide the much sought-after real-time visibility into key elements of the wide-area grid’s power flow. Where SCADA systems can monitor local areas, synchrophasors give visibility into wide areas such as an interconnection. Thus today’s synchrophasors supplement traditional SCADA functions, but do not replace them.

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IF

leveraging long-running smart grid efforts and balancing old and new technologies.

Keenly aware of the historical shortcomings of traditional phasor measurement units, or PMUs, the Salt River Project and Idaho Power­—among a handful of much larger utilities—will upgrade their transmission intelligence over the next three years. The result is expected to open a window onto a wide area of the grid and turn what was once only post-event, forensic data into real-time visibility of power flows.

This work will also aid these utilities and their peers in the project—and, eventually, across the entire interconnection—with insights for mitigating transmission congestion, integrating renewable energy and system network modeling and planning.

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Synchrophasor development was accelerated, in part, by the establishment of IEEE synchrophasor measurement and data standards in 1995 and 2005 and, not incidentally, by blackouts on the Western Interconnection in 1996 and the Northeast blackout in 2003.

“

Salt River Project jumps in feet first In Phoenix, the Salt River Project serves about 930,000 electric customers across 2,900 square miles of service territory.

The SRP has had a smart grid road map for years, anticipating new technologies that could, among other things, improve visibility, data analysis and real-time decision-making.

“We’ve been doing the right thing in transmission (sensors and controls) for decades,” said Joseph Nowaczyk, SRP’s manager for electronic systems. “Now we’re interested in (advanced) visualization tools. We have points in our 500-kV transmission system where we’ve already invested in PMUs and now we’re adding more Leveraging existing points to monitor.”

In SRP’s case, the protective relays utility had invested over the years in fiberallows us to install optic and Ethernet networks that connect a greater number its substations to its control center, anticiof PMUs in a pating the massive data flows that will cost-effective way. bring PMU-based visibility to dashboards for decision-makers.

The utility had also developed a smart grid road map and inter-disciplinary team to allow the integration of future “smart” technologies.

“We’re ready to jump in feet first,” Nowaczyk said.

SRP’s participation will help all grids in the Western Interconnection, though historically, locally, it has been keenly interested in understanding the behavior of its tieline to Southern California Edison (another WISP participant) to the west.

“We’d like to see how their grid is behaving and vice versa,” said Kristian Koellner, engineering supervisor in SRP’s system protection department.

SRP will be moving from a data sample rate of perhaps once every four seconds to samples taken 30 times per second, Koellner said.

“It’s fairly straightforward to get PMU data from our substations to our control center,” he continued. “How we share that data to provide a wide-area view of the Western Interconnection is the question to be resolved” by the WECC WISP.

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One area WECC is particularly concerned with is “power system modal oscillations,” which can lead to grid instability and, ultimately, blackouts, Koellner added. PMU data can provide system operators and planners with a view of this potentially damaging condition.

In another complement between old and new, ubiquitous protection relays on the transmission grid can deliver PMU data identical to discrete PMUs. “Leveraging existing protective relays allows us to install a greater number of PMUs in a cost-effective way,” he explained.

Idaho Power has local concerns too About 700 miles to the north, Idaho Power, Inc., is also participating in the WECC WISP (as are the Bonneville Power Authority, Southern California Edison, Pacific Gas & Electric, the California Independent System Operator, Electric Power Group, NV Energy, PacifiCorp and the California Energy Commission). Idaho Power serves about one million people spread across 24,000 square miles of southern Idaho and eastern Oregon.

Apart from the interconnection-wide benefits of the WISP, Idaho Power also has local concerns.

“There’s one main transmission line running from Idaho to Oregon and when it’s forced out due to a fault, it’s difficult to get it restored,” said Dave Angell, manager of delivery planning for Idaho Power.

Although Idaho Power had installed five PMUs in its transmission system in 2004 and connected them to a phasor data concentrator, the resulting data, crunched by existing software applications, could not be analyzed and presented to the utility’s grid operators for real-time decision-making, according to Angell.

In the current project, Idaho Power will install a number of additional PMUs at three substations along its 230kV and 345kV high-voltage lines in southern Idaho most relevant to the Western Interconnection. That will require a fairly major effort in building additional communications infrastructure, Angell added.

Three years + 150 PMUs The current WISP project is slated to run for three years.

That will require installing about 150 PMUs across eight utilities, each providing data samples at up to 60 times per second. A few utilities will host phasor data concentrators (PDCs), which in turn will feed application platforms such as the Real Time Dynamics Monitoring System.

The application platform will feed actionable intelligence to dashboard displays for grid operators. A wide area network will connect all the utilities, so operators at their dashboards have the same data. Redundant PDCs will sit at WECC reliability coordinator offices in Loveland, Colo., and Vancouver, Wash.

As this article went to press, the North American Electric Reliability Corporation was busy signing up utilities, independent system operators and data-handling vendors in data-sharing agreements that must precede interconnection-wide projects such as the WECC WISP. (The $108 million cost of WISP is split between the U.S. Department of Energy and WISP participants.)

Data-sharing in the past was on a one-to-one basis, which represented “an Achilles heel and logistical night-

VISION

S T R AT E G Y

REALITY

Outperforming the status quo + A California university teams up with smart grid software partners

By Laurel Lundstrom

mare,” according to Alison Silverstein, project manager for the North American Synchrophasor Initiative (NASPI), whose mission is to accelerate the advancement and commercialization of the various technologies.

Meanwhile, many of the utilities involved in this effort have long prepared themselves for the moment, now nearly nigh, when they could see for miles and miles.

Phil Carson is the editor-in-chief of Intelligent Utility Daily.

how it should economically optimize the microgrid each hour of the day. The smart grid software continuously monitors the data points it receives. “If it starts to see a divergence from the economic and physical ideal, then it can self-heal to bring the system back in line with the way it should be performing perfectly,” Washom said.

Although the modeling platform isn’t new—it is installed on mission-critical facilities across the United States from the Federal Aviation Administration’s (FAA) control center to offshore oil rigs to some nuclear power plants—the partnership between the two companies and the university is unique.

“WHAT I LIKE MOST ABOUT MY JOB IS

University played matchmaker “We were the matchmaker between [the two],” said Washom. “The idea is if we demonstrate it here on campus through performance improvement and cost reduction, one would think that the commercialization of those two products, as individuals or as a suite, would go forward.”

“Other companies are trying to build the system from the ground up,” he said, but that is a mistake.

“More product developers need to recognize that microgrids are a very large market, and that software can be installed on a microgrid much more easily than at a regular utility.”

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that I cannot exceed the imagination of my colleagues,” said Byron Washom, the University of California at San Diego’s director of strategic energy initiatives. “I bring in former utility colleagues of mine, and the first thing they say when they visit the [UCSD] campus is time travel.”

However, for UCSD insiders like Washom, the innovations his colleagues refer to are not futuristic. They merely form the backbone of a university that predicates progress on the sustainability of its campus.

The university’s most recent venture is the advancement of its internal smart grid through a software partnership with two companies: one focused on virtual power generation, and another providing UCSD with the software to manage and optimize the information it is receiving from the first.

The university’s microgrid can be monitored and re-optimized hourly, depending on pricing signals, congestion constraints, operating efficiencies, solar forecasts and weather reports. UCSD’s microgrid has distributed generation, renewable energy, energy storage, energy efficiency and demand-response capabilities.

Here’s how the partnership works. The first company’s software integrates weather, load and price information and sends the second company’s power systems engineering modeling platform new instructions for

27

SMART TECH EQUILIBRIUM

“We are self-permitting,” Washom continued. “We don’t need local building permits for innovations, whereas regulated utilities have to … and we are not subjected to a 20/20 hindsight prudency review like a regulated utility has for their rate base.”

Microgrid enables sustainability According to Washom, UCSD’s microgrid enables it to self-generate 82 percent of its power from two 13.5-megawatt gas turbines, one 3-megawatt steam turbine and one 1.2-megawatt solar-cell installation, and to produce electricity, heat and cooling at a higher degree of efficiency than the local utility and at a lower cost.

“We are outperforming the status quo of society,” he said.

The university also operates an impressive energy storage system that allows it to shift 7 to 14 percent of its daily on-peak cooling load to the night by charging a 4-million-gallon thermal energy-storage tank. The storage tank employs chillers that can recover the waste heat from the cogeneration system, or chillers that use the electricity that would have been throttled back during off-peak hours.

Reducing costs by increasing efficiencies Between 1993 and 2008, the university completed more than $60 million in projects that increased efficiencies and reduced costs by more than $12 million annually, including a high-voltage substation, cogeneration, thermal energy storage, comprehensive digital building controls and HVAC retrofits. In 2009, UCSD received funding approval for a three-year, $72 million program, which will include projects to upgrade laboratory HVAC, campus-wide lighting and comprehensive monitoring-based commissioning.

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S T R AT E G Y

REALITY

Beyond the meter + Exploring the Middle Kingdom of demand response

By Mike Breslin WITH

PRESSURES

ON

UTILITIES

TO

reduce peak loads and integrate variable renewables, third-party demand-response (DR) solution providers are playing an important role as a bridge

“We have about 12 million square feet on campus and we are about the size of a city of 45,000 people. Our energy density per square foot is twice that of a regular office building due to our research and patient care operations,” said Washom. “Since we have this diet for high energy we are all the more sensitive to consumption and to the nature of how it is produced and delivered.”

Because UCSD is in a statewide partnership with the California Public Utilities Commission and San Diego Gas & Electric (SDG&E), the university is able to do all this at little cost.

“We are provided with a financial incentive from SDG&E for each kilowatt-hour saved, and whatever the first-year incentive doesn’t offset or pay down, we are allowed to borrow at prevailing low-interest rates for the remaining value,” Washom said.

Due to continued interest and investment from both the public and private sectors, the university keeps adding to its laundry list of accomplishments.

“Being a living laboratory, we have a number of companies that come here with a request to demonstrate their technology in this advanced environment to bring a higher profile to their product,” Washom said. “We enjoy being that incubator.”

Washom only sees continued incubation in the future.

“We have an interesting administration here at UCSD, where we have the chancellor and four vice chancellors who compete to outperform one another when it comes to sustainability initiatives,” he said. “There is this little intramural between them as to who can raise the bar just a little bit higher.”

Laurel Lundstrom is a freelance writer based in Washington, D.C.

between the power supplier and commercial, industrial and institutional customers to manage peak demand.

Whether utilities see third parties as competitors or helpmates, they are an expedient route to getting DR quickly and cost efficiently. Over the past decade, as a consequence of providing a much needed service, they are an industry force forging partnerships with utilities around the world.

“It’s fair to say that some utilities see us as a competitor.

The fundamental reason is because every utility I have ever met cares very deeply about its customer relationship, and some may be reluctant to have a third party between them and their customers,” said Gregg Dixon, senior vice president of marketing for EnerNOC. His company is a third-party DR provider with more than 35,000 MW under management for more than 100 utilities serving over 6,500 commercial, industrial and institutional consumers in the United States, Canada and the U.K.

Partners in savings Al Grinnell, manager of commercial and industrial customer service for Tampa Electric Company (TEC) sees it this way: “I do not consider third-party DR providers as a competitor to utilities. We don’t consider them a vendor either, rather as a partner because they are providing a service with specific expertise that we don’t have in-house.”

Cutting peak demand drove TEC to seek a third-party solution. TEC is the principal subsidiary of TECO Energy Inc. and serves over 670,000 customers in a 2,000-squaremile area in west-central Florida.

“They know that if there is ever any issue whatsoever, my accountmanagement team is only a phone call away, day or night.

”

DR performance favorable In October 2008, a two-hour test was run from the DR solution provider’s network operations center in Boston. During the event, customers more than delivered their contracted

Mike Breslin is a freelance writer and novelist based in New Jersey.

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In 2006, TEC began exploring the possibility of adding DR to its demand-side management portfolio, which already included interruptible rates, residential direct load control and other offerings. After researching several solution providers, TEC made its choice in 2007 and worked with its third-party DR provider over six months to enroll nearly 100 commercial and industrial customers to participate in the first test. “Their enrollment checklist walked us through the whole process.

Their people were incredibly helpful and answered all our questions,” said Robert Garcia, vice president of new business development for Ybor City District Cooling. His plant has a 2,450-ton chilled water system that supplies more than 800,000 square feet of Tampa buildings including a college campus, office and retail complexes, a cinema center and a hotel.

Before TEC could proceed with the program, however, it had to get approval from the Florida Public Service Commission. The commissioners were concerned about turning over DR to a third party, getting capacity when needed and if a third-party could provide reliable performance. The program underwent strict regulatory scrutiny and was approved in late 2007.

reduction targets and dropped nearly 32 MW from the grid.

“I went to the network operations center in Boston and sat in the control room. When we hit the button I was tied into my dispatch center in Tampa and I could see real-time load on the system and what we were dropping. I needed to understand everything to protect my customers and make sure we are offering a superior level of service,” Grinnell said.

To participate, the nearly 100 customers in the program agreed to trim a minimum of 100 kW between 7 a.m. and 7 p.m. Some curtail several megawatts. The program runs year-round with an event notification of 30 minutes and duration anywhere from one to eight hours. The DR solutions provider’s network operations center is used to control the end-use customers’ load for those customers who have signed on. Some loads are curtailed automatically and remotely. Others are done manually based on automated communications to the customer. And customers use a Web browser to access their data.

Grinnell characterized DR performance as very favorable. Customer survey results and feedback have been very strong. Customers get a quarterly check from the thirdparty DR solutions provider in exchange for curtailing their load. “With checks ranging from $1,000 to nearly $100,000 in an economy like this they are very happy about that,” Grinnell said.

“Our customers perceive the program as a partnership.

Tampa Electric has an offering, but [the DR solutions provider] runs the program. They know that if there is ever any issue whatsoever, my account-management team is only a phone call away, day or night. But we have never had any issues. It’s mutually beneficial to all stakeholders,” Grinnell added.

Sales are easy when you have a good product that everyone wants. That is apparently the case with thirdparty demand response. The third-party DR solutions provider brings a value proposition to a customer that is simple and, in this example, installed the technology for free, simplifying what would otherwise be very complex for a customer do. There is zero risk. If a customer does not perform during a DR event they are not penalized.

The DR solutions provider works as a partner between the utility and the customer to make it work and ensure the maximum amount of DR is obtained out of a particular territory.

All in all, DR makes a solid case for being a much cheaper, faster, reliable and environmentally friendly resource than peaking power plants.

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VISION

idEnTity crISis S T R AT E G Y

REALITY

CIO challenge + Smart technology is changing utility insiders’ focus

By Ken Silverstein

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is undergoing radical change. One industry executive recently summed up the changes impacting utilities as the most dramatic since the days of Edison.

That statement carries a lot of weight given that Edison’s lightbulb is now well over 100 years old. However, smart grid and other RADICAL CHANGES invasive technolThese articles look at the massive ogies will likely changes facing utilities in the 21st change the face of century. John R. Johnson talks to the utility as we utility CIOs about the industry know it forever. changes brought about by smart Gone are the technology. Ken Silverstein discusses days of the utility the ROI of smart grid, and determines a s a s t o d g y, the payback will take a while. slow-to-react enterprise. In are the days utilities lead the charge into some of the coolest emerging technologies. With that, the role of the chief information officer is changing dramatically. Just the fact that utilities are turning to emerging—and often untested—technologies creates new challenges for CIOs. Becky Blalock, senior vice president and chief information officer at Southern Co., which provides electricity to 4.4 million residential and commercial customers, says it’s not enough to be a technology expert anymore.

Nowadays, she says, CIOs must possess solid business knowledge to understand how new technology can drive business efficiencies.

Greater security challenges Aside from the added time and effort required to evaluate a seemingly endless supply of new products is the emphasis on security challenges that some new products present.

“Security is such a huge issue for us now,” said Blalock.

“In my opinion, a lot of these new products are not as well tested as they need to be. Smart grid is on the hype cycle, and these products are very immature. As an industry, we don’t have a good process in place yet to rigorously test these products before we deploy them on our network. It’s one thing to roll out software and then patch it on PCs. It would be impossible for us to roll out security patches for thousands of devices out on our electric grid. So we need security baked into these products.

“When it comes to electricity, if something happens and people don’t have it, nothing works. Water systems don’t work. We see this after hurricanes. So we have to take very seriously our fiduciary responsibility to making sure that what we put out on that network doesn’t put the network at risk. Reliability is the most important part of our business.”

Maturity counts Patricia Graham, division vice president of information technology and CIO at CenterPoint Energy in Houston, Texas, concurs with Blalock in that it is crucial to install mature software that complies with industry standards.

“We have worked very hard collectively across operations and IT to ensure that what we implement is standard within the industry,” said Graham. “We don’t want to install solutions that require us to be a niche player. We want to install what is going to be mainstream. It’s very important we not be in a one-off environment.”

ILLUSTRATION BY MELISSA DEHNER

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IT’S NO SECRET THAT THE UTILITY INDUSTRY

“The great thing is that there are a lot of great products out there that can help our business to be more efficient,” she said. “The difficult thing is sorting through and determining the best products that truly drive value to the bottom line.”

Graham first started to see a noticeable difference in her role as CIO about three years ago, when CenterPoint Energy’s smart meter program was coming into focus.

“It was when we began to look at what the architecture was going to be for all of this and to frankly lay out the vision and look at what requirements would be out there,” she said. “When we determined that this was all about the customer and improving the customer experience through enhanced reliability and availability of the grid, suddenly IT becomes a very big partner in rolling out a smart grid environment.”

John R. Johnson is a Boston-based freelance writer.

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Graham also says there has been a big change when it comes to dealing with operations departments within utilities, and the fact that they are no longer just partnering with vendors of equipment that is expected to last 20 to 30 years.

“The operations side of the utility is becoming very IT-oriented, so information technology is suddenly playing a very big role in an area that until now has been mechanical and manually intensive,” she said. “In terms of the CIO role, our challenge is to educate our operational peers with respect to how to interact with technology companies.

Dealing with companies that provide mechanical equipment that lasts 30 years is very different from dealing with companies that provide hardware or software with an 18-month shelf-life, or three years at best.”

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IDENTITY CRISIS

VISION

S T R AT E G Y

REALITY

Racking up returns + Stalwarts weigh in on ROI for industry

By Ken Silverstein GETTING

CONSUMERS

TO

LEARN

HOW

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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.

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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.

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.

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.

“

”

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.”

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. hp-ad-1.qxd

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8:01 PM

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.

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

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SPECIAL REPORT: RENEWABLES

VISION

S T R AT E G Y

REALITY

Energy boxed + SEC and AEP implement radical storage solutions

By John R. Johnson

BY THE END OF THE YEAR, MANY COMMUTERS WILL BE

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adding a new twist to their daily routine. When they pull into the driveway at night, they’ll plug their new electric vehicle into a conventional outlet and let it recharge for the next day.

The Nissan Leaf and Chevy Volt electric cars will be introduced in the United States this year, luring drivers who have become wary of gas prices that once again seem headed toward $3 a gallon GRID GREENING and beyond. As drivers gobble up these ultra-efficient electric vehicles, more These articles discuss the integration and intelligent and more demand will be put on the management of renewables on nation’s electric grid. the grid. John R. Johnson explores That scenario—along with the radical storage solutions being emergence of net-zero homes and an employed by some utilities, such overall increase in solar and wind as lithium-ion and sodium-sulfur generation—is driving utilities to storage. And Mike Breslin discusses investigate innovative grid storage renewable options available today. options. As renewable energy sources such as wind and solar are integrated into the smart grid, the ability to manage and store energy becomes essential because of the intermittent nature of those power sources—the sun never shines constantly, and energy-producing wind gusts can be unpredictable and die off quickly.

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Storage solutions even the playing field While many utilities are just starting to research grid storage technology, progressive firms like American Electric Power (AEP) and Southern California Edison (SCE) are implementing radical storage solutions that will even the playing field when it comes to renewables and the power grid.

“Energy storage will definitely facilitate the integration of renewable energy,” said Janice Lin, director of the California Energy Storage Alliance. “Our belief is that storage will accelerate growth because storage can help to increase the value of renewables.”

Solar power, for example, is an immensely efficient generation source, given that it tends to produce highly coincident with peak demand. However, even the sun isn’t an endless resource. A storm cloud that lingers in the sky at midday for 30 minutes reduces solar output during that peak demand period, thereby limiting solar’s ability to capture top demand charges. Grid storage systems can smooth out those bumps and help to fully capture demand charges, increasing the value of solar generation.

Similarly, storage can increase the value of renewable generation that occurs during periods when there is less value—such as from wind power produced during the evening. Instead of selling that energy at nighttime low prices, wind energy can be stored and sold during peak demand periods when power prices are higher.

SCE addresses renewables issues “Increasingly, as we look at distributed solar and [wind], we are looking at the impact and how storage might be able to accommodate and address some of the issues that come from fast dropouts from solar, or the variability from wind,” said Paul De Martini, vice president of advanced technology at Southern California Edison.

SCE is one of the most advanced utilities in the world when it comes to storage research. The firm is in the process of unveiling several demonstrations, including one intended to show the viability of lithiumion energy storage to support the integration of wind energy to meet California’s aggressive Renewables Portfolio Standard. At its Tehachapi Wind Energy Storage Project, SCE designed and built an 8-MW, fourhour (32-MWh) battery system and

“ Energy storage will definitely facilitate the integration of renewable energy. Our belief is that storage will accelerate the growth because storage can help to increase the value of renewables.

”

smart inverter, which is connected to its substation in Monolith, Calif. De Martini says the substation is ideal for the demo because the site is challenged by intermittent wind generation.

When complete, the project is expected to demonstrate how lithiumion energy storage can enhance grid

operations and wind power integration by measuring performance under 13 operational uses, including load shifting and enhancing ramp rate control to minimize the need for fossil-fuel-powered backup generators.

“We continue to look at all forms of technology, including supercapacitors, super-conducting materials that might be applied for storage, as well as flywheel technologies,” says De Martini, noting that SCE has battery storage research partnerships with Stanford, MIT and CalTech.

John R. Johnson is a Boston-based freelance writer specializing in alternative energy and technology topics.

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AEP seeks to reduce outages Southern California Edison’s efforts are closely mirrored by AEP, another grid storage pioneer. AEP is looking at grid storage for a number of reasons, chief among them a desire to reduce outages. However, the utility admits that grid storage can help it to remain competitive when it comes to net-zero or near-zero customers with their own power generation and energy systems.

AEP has been experimenting with battery-powered grid storage for many years. In 2006 it installed its first storage unit, which resulted in three years of successful load leveling during peak demand, effectively postponing the need for a new substation for several years. AEP has since rolled out 2 megawatt, 14.4 MWh units in West Virginia, Ohio and Indiana. In April, AEP deployed the largest grid storage facility in the country, a 4 megawatt sodium-sulfur system in Presidio, Tex., near the Mexican border.

Like Southern California Edison, AEP is blazing a trail into what it calls community energy storage (CES) systems, which are much smaller battery systems than those found at substations. The intent of these smaller units is to provide the utility and its customers with many benefits, including load leveling, backup power, support for plug-in electric cars, and grid regulation and improved distribution line efficiencies. AEP is in the process of deploying 80 of the units at homes throughout Columbus, Ohio. The pilot will be fully deployed by the end of 2012. Each battery unit services four to five homes. While the substation battery storage units are still subject to outages from storms, getting closer to the grid edge means customers are less likely to be impacted by outages.

“The larger batteries at substations can still be impacted by an outage from overhead lines,” said Emeka Okafor, program manager for energy storage systems at AEP’s Distribution Research Group. “When the unit is closer to the customer and in their own back yard, there is less ability to effect reliability. You are providing backup power much closer to the customer.”

In addition, having grid storage so close to the customer will make it much easier to integrate renewables. “One of the concerns for utilities today is what the impact will be on the grid when everybody comes home at 5 p.m. and starts to charge up their cars,” Okafor said. “You can use energy storage to deter part of that.”

The emergence of electric cars represents a much bigger story line than just the drain on the power grid.

Okafor actually expects utilities to benefit from a cost reduction standpoint when the electric car sector ramps up. Utilities plan to use batteries similar to those used in electric cars.

With the auto industry buying in huge volumes, the utility sector is banking on lower battery prices in the future.

But the utility-electric auto connection doesn’t stop there. “In the long term, we believe we’ll be able to utilize used car batteries and integrate them into the storage system,” Okafor explained. “After a car battery has been in use for five to 10 years and is no longer good enough to use in cars, we hope to still see enough capacity to utilize them for grid benefits. We’re really hoping to play off the auto industry.”

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SPECIAL REPORT: RENEWABLES

VISION

S T R AT E G Y

REALITY

Greening the smart grid + Renewables are moving into the mainstream

By Mike Breslin

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RENEWABLE GENERATION, IN MANY FORMS, IS NO LONGER

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the new and untested addition to the electric grid. Wind and solar generation, in particular, have moved into the mainstream. Based on long-term potential, effective siting advantages and other variables—such as state-by-state Renewable Portfolio Standards (RPS)—some renewable energy sources will continue to accelerate, while others may level off in the short-term.

As of June 2009, 32 states and the District of Columbia had mandated RPSs, according to the Department of Energy. The group accounts for more than half of U.S. electricity sales. In addition, five other states have set voluntary targets for renewables and utilities in other states have their own goals.

Meanwhile, states are upping the ante. In February, an Oklahoma Statehouse committee passed a bill mandating that 15 percent of all generation would come from renewable sources by 2015. A month later, Colorado raised its RPS from 20 percent to 30 percent by 2020.

10x12, 25x25 What’s next for a national RPS law? The Obama administration wants 10 percent of the country’s electricity generated by renewable sources by 2012, and 25 percent by 2025. With billions of stimulus dollars invested in energy, and a

renewable agenda, the federal government now has even greater influence affecting portfolio standards.

According to the Energy Information Administration, 7 percent of all electricity consumed in the United States is generated by renewable sources. Biomass is responsible for 53 percent of renewable energy consumption, followed by 36 percent from hydroelectric sources, 5 percent from geothermal, 5 percent from wind and 1 percent from solar.

Many standards only allow incremental improvements upon hydropower—greater efficiencies or additions to existing facilities. “That’s why we don’t count standard, traditional hydropower in our renewable equations,” said Joe Verrengia, spokesperson for the National Renewable Energy Lab (NREL).

Wind is mature now “Wind is a mature, utility-scale power source now. Among the common renewable categories, it’s by far the farthest along in terms of a utility option for large, fairly reliable power generation,” said Verrengia at NREL.

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SPECIAL REPORT: RENEWABLES

OTHER RENEWABLE ENERGY OPTIONS Biomass energy, landfill gas and geothermal offer promise, but have limitations. ??

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??

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BIOMASS SMALL YET CONSISTENT Biomass energy comes from solid waste, paper, wood, landfill gas and alcohol. Ethanol, the driving force behind biomass generation, accounts for more than half of renewable power. The U.S. is the world’s largest producer of ethanol fuel for transportation, making over $9 billion gallons annually. Aside from a valuable role in co-firing, biomass is not a serious contender for utility-scale generation, but there are promising technologies emerging from the waste-management industry designed to reduce landfill operation costs while generating electricity. These are small yet consistent producers—distributed sources not requiring heavy transmission costs.

LFG + GEOTHERMAL MORE LONG-TERM Recovering landfill gas (LFG) and burning it as fuel in a reciprocating engine or a turbine is a proven technology and has been growing on its own economic merits, without subsidies. But LFG may be further spurred by the U.S. EPA’s proposed Tailoring Rule. Designed to regulate greenhouse gas emissions from light-duty vehicles, it may also require the control of greenhouse gas emission from large, stationary sources including thousands of solid waste landfills. Large landfills can produce gas for decades and burning it to create electricity is a logical solution.

Geothermal holds a long-term promise, but must be limited to those states that can access heat economically. Despite such containment, the U.S remains the global leader in geothermal for electric generation. California produces more than 2,500 MW annually, representing aproximately one-third of global production. Alaska and Hawaii hold huge potential; Idaho, Nevada, New Mexico and Utah are producing small amounts, a few hundred MW combined. Advances in deep drilling to reach heat suitable for steam generation could increase the potential in these areas.

“The wind industry broke all previous records by installing nearly 10,000 MW of new generating capacity in 2009, bringing total U.S. wind power capacity to more than 35,000 MW,” said Jeff Anthony, director of business development for the American Wind Energy Association. Anthony said utilities are becoming more sophisticated in integrating larger amounts of wind energy into their portfolios although it takes changes in grid operations to accommodate larger amounts of a variable output. But getting large output wind or solar from point of generation to large consumption centers remains the challenge.

The Southwest Power Pool (SPP) offers a good example of strategic planning to integrate more wind on a regional scale. SPP covers 370,000 square miles and manages transmission in Arkansas, Kansas, Louisiana, Missouri, Nebraska, New Mexico, Oklahoma and Texas.

In January, SPP released a wind integration study showing that enhanced electricity reserves and major transmission reinforcements are needed to bring higher levels into their energy markets. It found that increasing wind-penetration levels causes changes in power flow patterns, particularly increased flow from the western to the eastern part of their region requiring transmission upgrades and reconfigurations. To increase wind production by 10 percent, new transmission lines totaling 1,260 miles of 345-kV and 40 miles of 230-kV lines are needed. “We are working with our members to determine what percentage of wind we can feasibly integrate into the grid. We think the SPP region can accommodate up to 30 percent wind penetration,” said Emily Pennel, SPP spokesperson. “Renewables

drive a need and an opportunity for better grid management as well as smarter consumption from customers.

As such, smart grid becomes more and more a requirement to integrate renewables,” she added.

110+ projects in solar pipeline The Southwestern Public Service Company (SPS) dba Xcel Energy, is an SPP member operating in parts of Texas and New Mexico. SPS spokesperson Wes Reeves commented on its renewable mix, which is currently 6 percent wind: “Wind energy still offers the best opportunities in the SPS area. Solar power is developing faster in New Mexico than in Texas, but we believe policy making in Texas will start to tilt toward solar in the coming years.”

In December, SPS announced a contract with SunEdison to supply about 50 MW of photovoltaic-derived solar power from yet-to-be-built installations in Lea and Eddy counties in southeastern New Mexico. “We also are seeking to put together a biomass deal for New Mexico,” said Reeves.

Preliminary numbers from the Solar Energy Industries Association (SEIA) show that at the end of 2009, total installed utility-scale capacity was 517 MW. “We expect more than 200 megawatts of utility-scale projects installed in 2010. What’s most interesting are 100 or so projects totaling 17 GWs in the pipeline, many with utility power purchase agreements. And we expect announcements about permit approvals for 14 fast-tracked projects on Bureau of Land Management property, a first ever on public lands,” said Monique Hanis, SEIA director of communications.

Building wind and solar generation on public land and, more importantly, building transmission across it would greatly expedite the delivery of renewable energy.

Mike Breslin is a freelance writer and novelist based in New Jersey.

An Exclusive, Invitation-Only Gathering of the Utility Industry’s Executive Leaders in Information Technology, Operations, and Customer Service As the intelligent utility continues to evolve, the customer experience will drive operational efficiency, energy efficiency and cost control. It is critical at this juncture for leaders in utility Information Technology, Operations and Customer Service to come together in a constructive forum to share the lessons they are learning and avoid the costly stumbling blocks that create barriers to success.

The Knowledge2010 Executive Summit will provide utility executives with a “roadmap for success” — you will: • Gain insight from thought leaders (industry and non-industry perspectives) on emerging trends in technology, business and consumer behavior • Engage in unique, off-record roundtables with peers in IT, Operations, and Customer Service (no recordings or media) • Network in open and friendly environment, with no point of sales pressure

For information on summit participation or sponsorship, email jkoehn@energycentral.com or visit our website at www.knowledgesummits.com.

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Implementing Effective Demand Response Programs to Gain Control over the Grid W

hen the U.S. Congress passed The Energy Independence and Security Act of 2007, it required the Federal Energy Regulatory Commission (FERC) to conduct a national study and determine the potential for demand response. For this study, FERC used the same definition of demand response as the Department of Energy (DOE):

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“Changes in electric usage by end-use customers from their normal consumption patterns in response to changes in the price of electricity over time, or to incentive payments designed to induce lower electricity use at times of high wholesale market prices or when system reliability is jeopardized.”

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Or, looked at another way, Congress was asking FERC to determine how much energy could be saved if we, as a nation, achieved more efficiency with our allocation and consumption of power. The study demonstrated that the potential opportunity is significant and, in many respects, it became the impetus for the increasing interest in demand response programs.

The FERC report is titled, “A National Assess-

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ment of Demand Response Potential” and is 254 pages of insightful analysis about the total potential opportunity and benefits. There are, of course, several ways regulators and utilities can pursue demand response programs, each with pros and cons.

In the utility industry, opportunities are measured in several ways. Those that are measured in Gigawatts (GW) attract a lot of attention — and rightly so. Building and maintaining power generation is an expensive endeavor, especially when changes in utility and consumer practices may make such expenditures unnecessary. The FERC report captured a lot of attention when it stated that “the 2019 peak load could be reduced by as much as 150 GW, compared to the Business-as-Usual scenario... [and that] this reduction would be equivalent to the output of about 2,000 such [peak] power plants.”

Although the informed reader can debate the specific conclusions of the FERC report, it remains clear that demand response represents a significant opportunity for a society concerned about energy availability, price and usage. But, how do we best capture the opportunity?

Smart grid technologies such as “Smart Meters” and Advanced Metering Infrastructure (AMI) have captured much of the industry’s attention. Many believe these technologies to be the cornerstone upon which other consumer empowerment and energy efficiency technologies will be built – and rightly so.

The benefits that are unlocked by smart metering, such as time of use pricing, are seen as key enablers to effective demand response programs. With that said, though, it is also important to note that much can be achieved in the area of demand response and energy efficiently without having to wait for these technologies. In fact, much has already been accomplished.

Over the past few years, significant progress has been made related to energy efficiency.

Small things such as compact fluorescent lights, weatherization initiatives and more energy efficient appliances have become relatively common with utilities and consumers across the country. Beyond those, regulators, utilities and consumers are turning their attention to higher hanging fruit such

as structured demand response programs, new pricing mechanisms to encourage efficient use of energy and more transparency with consumers so that they have visibility into their usage and pricing impacts. In short, we are entering an era of consumer empowerment enabled by enhanced communications between utilities and their customers. This enhanced communications, coupled with properly structured demand response programs, will help to achieve the savings outlined in the FERC report creating a symbiotic relationship between utilities and the customers they serve.

There are two primary ways to develop that symbiotic relationship. Some utilities and consumers currently participate in direct load control programs. In those types of programs, commercial or residential consumers agree to allow the utility to control certain aspects of their load, particularly during peak times. In exchange, the consumer usually achieves some sort of financial benefit. While good, this approach is largely initiated at the utilities direction, without a

Source ource:: FERC Assessment of Demand Response & Advanced Metering 2009 assumptions: smart meters, dynamic pricing default, enabling technologies

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Source: FERC Assessment of Demand Response & Advanced Metering 2009 assumptions: smart meters, dynamic pricing default, enabling technologies

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point in time reference to consumer needs.

In short, it is a blanket approach of sorts. A more consumer friendly approach is to provide transparency about pricing and load to the consumer so that they are empowered to make the best decision about if and how to alter to their consumption patterns. These are referred to as price based programs.

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Consider this simplified example to demonstrate the differences between the approaches. A family of four is having a birthday party for one of their children on a sweltering August afternoon. The house is full of relatives and friends and everyone is thankful for air conditioning. Under the direct load approach, the consumer may very well experience a shut down in their air conditioning under the pre-arranged agreement simply because the utility needs to conserve on peak power. Such a situation may very well result in the party breaking up early and a frustrated consumer. Under the price based approach, the consumer would receive a signal about the high cost of electricity due to peak demand and their current high load and perhaps even a suggestion to reduce demand in order to save money. Because of the birthday party in progress, the consumer very likely would elect to take no action to curtail their load. On a different day, without a house full of company, the consumer may very well elect to shut down their air conditioning, save money and help the utility to better manage peak power demands. The price based approach depends on a near real-time information exchange about pricing and consumption and is generally believed to be friendlier to consumers because it allows them to better understand their usage, save money and, of course, allows them the freedom to exercise personal decision making.

The technology that enables this information exchange will be a critical part of the relationship between utilities and their customers in the years ahead. In fact, most an-

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TENDRIL PL ATFOR

TENDRIL RETAIL APP 3 R D PARTY APPS

UTILIT Y BACK OFFICE

IP NETWORK

UTILITY APPLICATIONS

CONSU

ENERGY ANALYTICS

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ticipate that it will be the catalyst for increasing consumer engagement and the successful implementation of demand response programs. The technology that is utilized must be simple to understand and use, secure from threats, able to operate on multiple network types, scalable and, of course, compatible with other technologies used by utilities and consumers. These technologies will become a key enabler of demand response programs and help usher in a new and better approach to the provisioning and consumption of energy for utilities and their customers.

When properly implemented, the benefits of such solutions extend well beyond the consumers. Utilities, regulators and, of course, society in general all benefit from successful demand response programs. Included among these are: • Reduced and deferred generation and energy supply costs. When energy is consumed more wisely and demand is more properly controlled, less power is needed. • Reduction in carbon footprint. Less power generated through fossil fuel sources results in a decrease in carbon output.

utilities and their customers the power to solve today’s energy challenges [and] consists of both utility and in-home products and applications.”

RM

MER APPLICATIONS

ERGY MANAGEMENT

HAN

ERGY AWARENESS

ECTRIC VEHICLE

ENDRIL TRACKER

IP NETWORK

INSIGHT

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SET POINT

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• Reduced System Maintenance. Operating the electrical system at peak capacity for long periods of time stresses the assets on that system.

Reducing demand helps to reduce maintenance costs. Similarly, line losses attributed to peak capacity are reduced.

When implementing demand response programs and the technologies that enable them, utilities need to be mindful of regulatory requirements, consumer needs and their existing business processes, as well as the technology systems that underly them.

Tendril™ out of Boulder, Colorado has been leading the innovation and development of energy management technology and is well positioned to facillitate the symbiotic relationship between utilities and consumers that is envisioned in the FERC report on demand response potential.

The FERC report provides a great view into the vast potential and many benefits of demand response programs. Turning the potential into achievement and capturing the benefits will require a coordinated effort between regulators, utilities, consumers and the vendors who serve the utility industry.

Real-time information about consumption and pricing is at the core of these opportunities. The solutions pursued must support a secure, dynamic dialog between utilities and their consumers. Equally important is an open standard based approach to provide consumers with simple devices delivering information empowering them to exercise prudent decision making in their daily power consumption. The Tendril Platform is just such a solution.

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The Tendril platform is based on open standards, can work with virtually any communication network, is simple to understand and use and is highly secure. It represents a great solution for utilities and consumers looking to capture the many benefits associated with demand response programs. It is “a proven energy management technology that provides an end-to-end solution giving

A consumer who has easy access to consumption and pricing information is more likely to take action beneficial to their interests, including reducing consumption to save money. Utilities seeking to engage consumers in these programs will be well served to provide a solution that helps consumers easily understand how they can personally benefit. Because of its simplicity, security and interoperability, the Tendril platform promotes this ease of understanding and helps consumers understand – and achieve – their potential benefits.

Tendril info@tendrilinc.com 303.951.4360

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GRID(UN)LOCK “I truly believe there’s a bigger bang for everybody involved in updating the distribution system.”

That’s precisely what DTE is working on in the Bloomfield Hills area of Oakland County, Mich., about 20 miles northwest of Detroit.

There, the utility is implementing ambitious near-term plans to upgrade four circuits involving two substations.

“We’re through the design phase,” Dow said. “We’re trying to get all the material in and lined up to start installation. And we’re also installing smart meters in the same area.”

Improved communication

VISION

S T R AT E G Y

REALITY

A bigger bang +DTE Energy enabling last-mile upgrades

By Phil Johnson

I N T E LL IG E N T U T I L I T Y /// M AY/J U N E 2 0 10

WITH THE RAPID GROWTH OF DISTRIBUTION TECHNOLOGY—

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including more effective sensors, volt-VAR control and dynamic feeder reconfiguration—the distribution end of numerous electric utility systems offers considerable near-term potential to advance the smart grid.

In fact, GTM Research recently published findings showing that 77 percent of the more than 50 North American utilities within its survey sample view distribution automation as today’s top smart grid application.

Distribution, particularly within DISTRIBUTION UPGRADES the “last mile” from the substation to Distribution automation has been the customer, represents a major area ranked as today’s top smart grid in which smart grid is in the process application by many utilities. In of actually happening across a broad this article, Phil Johnson discovers geography of utilities. the rationale behind improving and And within that broad geography, upgrading electricity distribution a very good example can be found corridors, with help from DTE in DTE Energy’s current efforts Energy’s Vince Dow. to improve and upgrade its distribution corridors.

Reliability and engineering improvements

“In the whole smart grid area, the biggest opportunity we have is making the distribution system smarter in terms of operation and engineering,” said Vince Dow, DTE’s vice president of distribution operations. “It can improve the reliability of the system. It can improve the engineering.

Dow’s enthusiasm for the engineering aspects of the distribution equation is infectious, as he talks about improved communication within distribution circuits that allows for more and more information to be processed and analyzed, leading to improved, more predictable service for the benefit of the electric customer.

“That’s the really cool part for distribution engineers,” said Dow. “Now we’ll get information not only down at the meter, but through the various devices along the distribution system.

“And you can start accumulating and analyzing the data to say: What’s really happening out on this circuit that’s causing this type of performance? So you can look at it and say, ‘Well, maybe if I configured it this way, I’d have better service.’

Or, ‘Here’s the root cause.’ Or, ‘Here’s where the main issue is.’

“So you really can do a much better job of engineering the reliability and performance of that circuit.”

Not an overnight addition

Among the distribution realities Dow is quick to point out—as illustrated through DTE’s system of approximately 650 substations, from which numerous circuits serve a total of approximately

2.1 million customers—is that the ingredients of smart grid didn’t just crop up yesterday.

“We’ve had smart distribution system technology for a long time,” Dow said. “It’s all been in its infancy, but there are places where we’ve looped circuits together, and even developed some fairly advanced loop schemes and did automatic controls.”

In making his best effort to explain the benefits of a distribution system interwoven with smart grid technology, Dow presents vivid illustrations that sometimes exude not only logic, but considerable entertainment value.

“Now I can direct someone to a pretty close proximity to where that fault occurred, rather than having them go patrol a five-mile circuit.

”

Geeky knowledge

“Here’s another thing smart grid will offer you. Based on having sensors out there and the information they provide—and this is really geeky—but I can tell, based on the impedance that’s coming across my line, about how far out that fault occurred,” Dow said.

“So now I can direct someone to a pretty close proximity to where that fault occurred, rather than having them go patrol a five-mile circuit. And I try to explain to people: It’s sort of like when you drive around on GPS, and it triangulates and says, ‘You’re here.’ Well, we do the same thing to locate faults with impedance readings. And I can monitor all this from one central operation center, rather than having to always rely on people to drive out there and check on them.”

The efficiencies in fuel savings and reduced pollution as well as improved abilities to handle load swings and keep the system humming represent enormous gains over years past in the electric industry.

Accompanied by other large improvements in capacitance and capabilities to more closely monitor and exercise greater control over voltage all the way to the customer, the distribution system would currently appear to be more in tune with smart grid intent and aspiration than perhaps any other single element of electricity delivery today.

“In addition to determining more precisely where a fault has occurred, we can also take a better educated guess as to what the fault actually is,” Dow said.

“We get a good analysis based on the information we’ve received back from the general area of the fault–which can tell you, let’s say, this looks like a transformer fault. And it’s this far out on the circuit. Well, we know that that far out on the circuit there’s a 50-kVa transformer—so you’d better take one with you when you go. Again, it helps us be more efficient in sending the right person to the right place with the right equipment to quickly and completely correct the fault.”

A connected model

“One of the keys to doing this is building what we call a ‘connected model,’ which means you’ve connected from your substation all the way out to each individual customer,” Dow said. “So you know–in your database–here’s the phase that you’re on. Here are the devices you’re connected through to get to that individual customer. And you keep expanding your basis of information.”

Dow also notes that DTE is looking forward to distributed-generation scenarios through improved storage and battery technology, although he admits that substantial storage progress is not yet in the offing.

“We’re probably a ways away from having a good, economical method of energy storage,” he said. “Depending on who you talk to, ‘a ways’ varies in terms of years. One of the reasons why we’d look for that is because when we start going into solar- and wind-type generation, they’re not what we call ‘dispatchable.’

“When the wind blows, it works—if the wind doesn’t blow, there’s nothing.

If the sun shines, you get energy—if there’s no sunshine, you don’t. In the future, when storage technologies allow it, you’re going to have to be managing these. And storage will give you a way of buffering that—which will really help solve a number of problems.”

Phil Johnson is a freelance business writer and speechwriter.

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

“The term ‘self-healing’ is kind of being thrown around,” said Dow. “More accurately, it’s called ‘reconfiguring.’ But what the circuits do is loop around and interconnect, and that design allows us to get around a fault by feeding electricity from a different direction.

“So when an outage occurs on one section of one circuit, you can remotely or automatically have the circuit reconfigure itself. In other words, you’ve put out devices–you put switches out there, you put sensors out there that can sense this, then they automatically operate to reconfigure the circuit. It won’t repair the damage—you’ll still have to send someone out there to repair the damage—but it allows you to serve the customer much more efficiently,” he said.

That efficiency is shown not only in being able to provide a better overall quality of electricity delivery to the customer, but also in more rapidly isolating and repairing faults, shortening outages when they occur.

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END OF THE LINE VISION

S T R AT E G Y

REALITY

Forget the hardware +HAN solution lies in the software design

By Tom Grate and Michael Ebert

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WIDESPREAD CONSUMER ACCEPTANCE OF THE HOME AREA

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network (HAN) is crucial to the success of the smart grid. There are a myriad of issues why consumer uptake has been disappointing, even in SmartGridCity in Boulder, Colorado.

In most American households, the home network itself already exists based on multiple compliant technologies, be SIMPLE HAN it wired or wireless. The inhabitants of Sometimes, it takes looking outside such households may not think they the box for a simpler solution to gain have a “home network,” but in fact consumer acceptance. In this article, they do—often, it is home entertainTom Grate and Michael Ebert explore ment system-centric. However, the the idea of building a simple home current home network needs more area network solution using hardware intelligence and integration to serve already in most homes, and adding as the HAN for smart grid. appropriate software to the mix.

Wired home networks, implemented on CAT-5 or Powerline, and the Internet, implemented on DSL, cable, or even plain old POTS, are based on the Internet (IP) and/or legacy protocols like RS-485. In the wireless realm, the home network is based in WiFi, which is also IP-based or implemented using other wireless protocols such as Z-Wave, ZigBee (using 802.11g) or RadioRA. The key point about all of these technologies is that they are inexpensive, if not downright cheap. IP-connected Blu-Ray DVD players are less than $125, while ZigBee or Z-Wave modules can be added to retro devices for a few dollars. For example, Z-Wave chips can be purchased in small quantities for between $4.50 and $13.50; large orders would significantly reduce prices.

In a nutshell, there are multiple physical ways that the home network may be implemented using many network software protocols, existing or emerging, including new “wireless electricity” technologies and software—such as WiTricity or WiPower. However, existing home networks are insufficient to implement the smart grid HAN as most envision it.

Consumer + utility HAN requirements

Before delving into the functional design of the HAN, it is important to understand the requirements for consumers, utilities and new entrants. Consumers will push back—fiercely—if smart grid does not protect their in-premise privacy and help slow the rate of increase in their bills. Consumers will respond to requests from utilities only if those requests save money, reduce outages, and their ability to understand/respond to price signals is very easy and quick.

HAN information collected from consumers must be protected across several data networks and regulatory environments, which currently have overlapping,

inconsistent, or non-existent cybersecurity and electronic privacy policies.

Numerous proven technologies exist for protecting data that is being transferred over the Internet between the HAN and the utility, such as Secure Sockets Layer (SSL) at the connection level, or Triple DES, Blowfish, or Public/Private key mechanism at the data level. These encryption technologies have been implemented in operating systems in both consumer and business spaces.

Software design is key

The important thing is for the industry to allow forward migration of encryption as the technology evolves, and not get hung up on hardware. The magic genie is all software.

The hardware does not matter as long as it uses compliant protocols. It’s all in software-user interface (UI) design.

The key concerns for power utilities with respect to HAN are implementing demand response (DR): ??

Strategically over a long period

??

Tactically in a short-notice time period such as three to four hours

??

Quickly in an emergency

Additionally, the utility would like to acquire a complete, timely understanding of consumer power outage for its business modeling, planning and marketing (ideally without third-party data sharing).

Aggregated data—meaning data that does not confer or infer identity of each individual household—is all that is necessary for these purposes.

Having considered both the consumer and utility requirements for the HAN, a model for the HAN can be designed to meet those requirements, including the ability to: ??

Plan power usage based on average time-based demand curve produced by power utility and provided to HAN on a regular (e.g., daily) basis.

??

Plan near-term DR upon request (e.g., within a threeto four-hour time frame) and provide the electric utility with applicable data.

??

Respond to emergency demand requests.

??

Provide usable data to the power utility to build better models for servicing consumers and a better DR curve model to be provided back to the HAN.

In addition to implementing the model, the HAN has the following functional requirements: ??

Be easy to use, and work with both “smarter” and “not-sosmart” appliances (cheap retrofits for cash- or creditstrapped households)

??

Be secure, both for internal premise communication and for communication with the power utility as well as for accessing the premise devices through a user interface

??

Communicate between and among all the devices within the premise that consume electricity

??

Communicate bi-directionally between the HAN and the electric power utility, and between the internal premise aggregator and the external smart meter is a DMZ—a software firewall that protects both the household and the utility

Premise controller

The Premise Controller is a software module that “speaks” on applicable network protocols (IP, ZigBee,

“

Premise user interface

”

of increase in their bills.

The Premise User Interface aggregator (PUIa) provides the consumer the ability to configure the P-controller and set the consumer’s desired power usage pattern. The usage interface can be implemented as a Web server in the P-Controller able to serve Web pages to a Web browser on a personal computer or smartphone.

Additionally, the user interface can be served by the premise controller software to Xbox, Wii, or PlayStation-based browsers for control over the home entertainment system and television. Not all households, particularly those of senior citizens and lower-income demographics, have personal computers or 3G smartphones, but few households lack video displays. More than 40 percent of U.S. households have some form of applicable home entertainment devices.

Kids get this stuff. Properly incentivized, “GenTween” with their game consoles may motivate their parents to HANs and smart grid. Today’s youth will be far more into smart/green grid as adults.

Premise user interface

Easiest is the best user interface. Those who think most consumers will be bothered with real-time or near-real-time data forget that when most families return home after work and school, they want to unwind and enjoy some entertainment. They also have to do homework—not just in the academic sense.

Think laundry, dishwashing and more. The places that HAN “decision-makers” gravitate to after work is the place where the greatest HAN demand response uptake can occur if the interface is right, such as home entertainment systems.

Gravitation points can also be homework-based and elegant in their simplicity of use. For example, a smarter washer, dryer or dishwasher could be as simple as three LEDs and a Z-Wave communicator: green LED means cheap electricity; yellow, the consumer’s price set-point to think about time-of-use; and a red LED means you will pay dearly for this load of laundry. Consumers retain the choice to go ahead and activate the appliance regardless.

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To implement the model, the HAN needs several elements: a premise controller; a premise user interface; the Internet and/or other networks; and “HAN servers.” Each of these elements will be treated separately through software.

Z-Wave, etc.). It implements the model, communicating upstream with the power utility to query for model data for the average time-based demand curve for planning strategic power usage. The P-Controller receives and responds to demand requests including near-term and emergency demand requests and responds with power usage reduction data (how much usage can be reduced).

The P-Controller communicates omni-directionally with in-premise devices that consume power over a secure protocol to request the devices to pause/delay for a time period, provide devices with the optimal time period for running, or request the devices go offline or indicate that the device can come back online intelligently or remain in standby mode. P-Controller Consumers will push software can be implemented in a very small standalone box connected to the back—fiercely—if smart network via IP, or it can be implemented inside of other devices within the grid does not protect premise such as a network-connected Digital Video Recorder (DVR), home their in-premise privacy network router, or in just about any other device with a microprocessor and and help slow the rate a home network connection.

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END OF THE LINE Electric utility HAN servers

The electric utility’s HAN servers are the utility’s end point on the links between the HAN and the utility, allowing both the HAN and the utility—with the smart meter as the demarcation line between households and their utility—to communicate using the Internet and/or other networks. These HAN servers are data aggregators, aggregating the data sent by numerous P-Controllers, including but not limited to responses from HANs to requests from utilities.

HAN servers provide data analysis and create the average time-based demand curve data models needed by the P-Controller for strategic planning.

HAN servers also are the primary system used by the utility to communicate nearThe important thing term and emergency demand requests to consumers. Additionally, and as an added is to allow forward service to consumers, the server may act as an emergency weather alert system, migration of encrypbuilding stronger relationships between the utility and the consumer. tion as the technology One of the key elements of the model is the average time-based demand curve evolves, and not get data. This data can be broken down into 15-, 30- or 60-minute increments hung up on hardware. and provides the HAN with a predictive model of the relative cost of power within each of those increments so that the HAN plans for when it will use power.

Using the electric utility’s HAN server to analyze demand data, the model(s) may be refined and updated by the utility on a regular basis, thus giving HANs optimal information.

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HAN uptake critical

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Our foundational concern for the HAN is uptake: Will households opt in, or will we have smarter AMI connected to lots of not-smart households? If consumers are burdened by HAN cost and complexity, they will not use it. The promise of the smart grid will not be realized, and yet consumers will end up paying significantly higher electric bills through regulator-approved costrecovery for smart grid investments.

In most utility regulatory worlds, smart grid investments utilities make must be reasonable and prudent; they also must demonstrate that investments in smart grid equipment are useful and used. To that end, any HAN user interface must be easy to use. The technical design of the HAN must support ease of use, but technology alone will not build a good user interface. Sadly, many companies that are great at technology and develop tons of features fail when it comes to “easy.”

The keys to easy user interface are hiring good human interface and visual designers in addition to the software developers, then test candidate user interface with focus groups constituted from demographically valid target population samples. Good HAN user interfaces will provide users just what they need and no more. A good user interface makes sure that all consumers are covered, from bare-bones easiest to use all the way to full-featured user interfaces for the “HAN gamer” and serious energy conservationists.

allows devices to communicate with each other within the home. This P-protocol is: ??

“Omni-directional” with requests/responses

??

Provides information broadcast without response

??

Provides device enumeration and polling

??

Allows for device capabilities inheritance for the requests/ response language

Second, we need a Premise for Utility Protocol that also is evolutionary and secure by design, robust, sits above home network protocols, and allows the P-Controller software to communicate with the utility’s HAN server. This protocol allows for end-point identification (verification that the sender is the sender), message consistency checking, request/response and information broadcast without response, and is compact for processor and network efficiency. We need a great user interface—and we need compliant devices within the premise that speak the premise protocol.

The HAN is more than just networking technology and hardware.

At the highest level, HANs are intelligent systems implemented in software that speaks two or more languages—those within the premise, and between the premise and the utility. Intelligently designed, customer-driven HANs enhance relationships between utilities and consumers, conveniently saving consumers money while meeting business, environmental and reliability goals of electric utilities. Easy consumer adoption of HANs that are secure helps us more fully realize the vision of smarter, greener grids.

Tom Grate is an independent software architect and software intellectual property consultant. Michael Ebert is a

Connecting the points

principal research associate with the

So what is needed in order to see this vision implemented? First, we need a Premise Protocol that is secure, robust, sits above the network protocols and

Center for Infrastructure Protection at George Mason University.

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subscribe to receive them all! magazine Subscribe today and join our community of innovators who are transforming smart grid vision into reality with Intelligent Utility magazine. Subscriptions are FREE to qualifying professionals:

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An Energy Central Publication

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4D VISION

S T R AT E G Y

REALITY

There’s an app for that +Con Edison’s mobile Web outage reporting application is a hit with customers

By Elizabeth McGowan THIS WINTER STORM SEASON, CON EDISON DECISION

makers confirmed what they already suspected—customers are certainly apt with their apps.

Smart phone users took to the investor-owned utility’s newly launched mobile Web application like penguins to ice and ducks to water during especially wild February and March weather that walloped their neighborhoods.

“I don’t think anybody has as much functionality with mobile devices as we do,” said Robert Sherman, WEB APP SUCCESS Con Edison’s customer operations Utilities are reaching out to their department manger. “A couple other customers in some new and utilities are doing this but we’re forward-looking ways, as Elizabeth leading the pack.”

McGowan found when she talked to Con Edison about its success with a new mobile Web outage reporting application. The result: Con Ed’s

The first surge occurred during the last four days of February when 7,567 customers gravitated to their smart phones to report outages or check the status of a power disruption after a Feb. 25 storm dumped about two feet of heavy snow in New York City and Westchester County, N.Y. Records show that storm caused at least 50,000 outages.

Not to be outdone, March released a lion-like roar mid-month when it unleashed two days of highly destructive rain and wind. Following the March 13-14 blast, another 21,691 customers turned to their smart phones. At least 173,000 customers lost power during that stretch.

The mobile application has pulled like a magnet at Con Edison’s three million customers since its December launch. It attracted 13,000 visitors who clicked on it to pay their bill, check their payment history, update their accounts or submit a meter reading.

That figure more than doubled to 26,669 distinct visitors in February and grew to 35,458 distinct visitors in March. A year ago, 4 percent to 5 percent of customers reported outages electronically. Mobile access has boosted that figure to 16 percent to 17 percent.

“Our goal is for the customer to report outages in whatever way is the most convenient,” Sherman said. “As people migrate to smart phones, this is a different way of communicating that’s visual, not verbal. Some people would prefer texting to talking.” customers took to it like penguins

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to ice.

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Customers turned to smart phones

Delving into their homework

Con Edison is no rookie with digital advances. Customers have been able to report outages and update their accounts online for the last decade.

So the jump to a mobile application wasn’t exactly a blind leap.

Of course, the irony with computers is that customers can’t report power outages online without electricity. Smart phones, Sherman said, allow customers to be in touch with the utility from any location, including roadways blocked by downed wires.

“The more information in the report received, the better you can pinpoint where the trouble is. We can respond to the customer to let them know when service will be restored, and yes, that it

”

was restored.

“The more information in the report received, the better you can pinpoint where the trouble is,” he continued. “We can respond to the customer to let them know when service will be restored, and yes, that it was restored.”

Con Edison leaders executed its due diligence before embarking on its mobile mission about two years ago. Ultimately, their pursuit of a customer-friendly application that could stand the test of frequent use led them to a 10-year-old mobile company with offices in New York and Italy.

“When we started the project, we didn’t limit the research to the

utility industry,” said Fred Leich, a Con Edison public affairs manager.

“We looked at industries that depend heavily on transactional business such as hotels and airlines.”

Employees served as beta testers

Reporter Elizabeth McGowan writes about energy and environment issues from Washington, D.C.

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Though the utility didn’t call in specific focus groups before this rollout, Con Edison employees served as “guinea pig” testers for the mobile application. Press announcements and the Web site highlighted its availability.

“With any Web application we let customers play around with it and give us feedback about information and features,” Leich said. “Their

input is important because we’re on the inside and we see our business in a certain way.”

The mobile company Con Edison turned to for its new customer application also serves Central Hudson Gas & Electric (Poughkeepsie, N.Y.), Entergy, Commonwealth Edison (Chicago) and Orange & Rockland Utilities (Pearl River, N.Y.).

Its four core tenets are: companies won’t need additional information technology resources to make mobile applications work; applications can support all mobile phones; any aspect of a Web site can migrate to mobile; and turnaround time is quick.

One sign of a clean rollout of a new technology at Con Edison, Sherman explained, is a lack of complaints from customers.

“This has been an amazingly quiet one,” he said. “We’re absolutely happy with the way it is performing. Now we’re looking at what else we can bring to the mobile environment. This isn’t the first. My hope is that it won’t be the last.”

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CONNECTIONS

VISION

S T R AT E G Y

REALITY

Different flavors for different tastes +The smart grid from various utility perspectives

By Jeff Buxton and Mehrdod Mohseni SMART GRID IS A TERM THAT IS USED REGULARLY IN

today’s utility lexicon. Like many often-used terms, with broader use it begins to lose its precision in defining something specific and universally understood. In fact, as smart grid programs continue to evolve, the definition of what a smart grid is meant to accomplish may become more unique with each particular utility.

The underpinning electric transmission and distribution infrastructure will experience numerous changes as countless new technologies are developed, tested and deployed. This influx of new technology, combined with new regulatory drivers and network DIFFERENT STROKES standards, will shape the new utility The definition of smart grid has landscape. Figuring out how to best been discussed and debated in play and compete in this new landconvention halls, meeting rooms scape is key to success; but the answer, and utility board rooms across more often than not, will be different the nation. Here, Jeff Buxton and for each utility.

Mehrdod Mohseni posit the theory that the definition of what a smart

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A range of integrated systems

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grid is meant to accomplish may

become more unique with each A smart grid implementation includes utility as smart grid programs a range of integrated systems such continue to evolve. as advanced metering infrastructure (AMI), meter data management systems (MDMS), home area networks (HAN), supervisory control and data acquisition (SCADA), distribution management systems (DMS), distribution automation (DA) systems and other essential utility systems. Yet each utility has its own focus—or areas of prioritization—for its smart grid initiatives, based on its unique business drivers and starting point. For example, regulators, legislators and utility managers are promoting smart grid initiatives that focus on: ??

Renewable energy

??

Customer empowerment

??

System reliability

??

Deregulated markets

??

Operations excellence

??

Energy efficiency and demand response

The driving impetus for each smart grid initiative forms the basis of business case elements, program design, and technology selections.

It is important to ensure that these drivers are satisfied and the goals of the programs supported. A balanced smart grid program is a complex weighing of many competing drivers, stakeholder interests and financial considerations.

Although each utility may arrive at the doorstep of a smart grid initiative from a different starting place, they must all consider and incorporate both short-term needs and longerterm opportunities to provide the greatest benefits to the utility, the ratepayers and society at large. The overall smart grid strategy may need to include a long-term phased approach with appropriate consideration for technology selection, program rollouts, functional competencies and business case elements to ensure that the starting point is fully satisfied while not unduly prohibiting the long-term goal.

There are various utility objectives.

Renewable energy focus

In many states, legislators and regulators have instituted progressive requirements for utilities to incorporate significant portions of their generation portfolios as renewable resources. Hence, dozens of states are moving rapidly toward implementing renewable portfolio standards (RPS). For example, California’s RPS mandates 33 percent production of energy from renewable energy sources by 2030 while Maine’s RPS requires 40 percent production by 2017. Some states have set voluntary goals for adopting renewable energy instead of portfolio standards with binding targets. Smart grid initiatives focused on increasing renewable energy will concentrate on enabling the incorporation of dispersed renewable energy into the supply portfolio and

Customer-focused utilities and regulatory bodies view the smart grid as holding great potential in changing the public’s relationship with their individual energy usage.

the complex transaction management systems required to support it. The challenge utilities may face will be with the manner this integration takes place such that it does not become disruptive.

Customer empowerment focus

But this alone will do very little to alter the consumer’s behavior. Continued advancements in information presentment, through the full breadth of media and communications channels, will make the availability of information ubiquitous and the ability to control usage convenient. The next wave of technology deployments around advanced home energy management systems, home area networks (HAN), consumer communications, automated controls and other new applications, must first take place, before benefits can be achieved for both the consumer and the utility. Thus, utilities focused on the customer empowerment objective will need to consider the incorporation of these technologies into their smart grid architecture as well as the business model implications of extending their responsibilities into the consumer environment.

System reliability focus

The deployment of intelligent devices to the far reaches of the distribution system provides visibility and insight into the operation of the grid. This greater awareness of the grid provides utilities with improved knowledge of potential grid failure points and enables proactive maintenance and reliability planning practices. This is particularly valuable when one considers that the average age of most grid equipment in the United States is already around

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Customer-focused utilities and regulatory bodies view the smart grid as holding great potential in changing the public’s relationship with their individual energy usage.

The objective is to equip the end user with enough real-time signals, such as market prices, consumer load, environmental impacts and comparative information, to influence the consumer’s usage pattern.

But this type of smart grid program must provide consumers with tools to provide easy-to-understand information, innovative rate designs, and customer empowerment to affect load patterns. The first steps are well under way with the deployment of smart meters, providing real-time energy usage.

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CONNECTIONS

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40 years. Furthermore, by leveraging embedded sensors and high-speed communication networks, utilities can better detect network disturbance, outages, power quality and power flow problems. Finally, with the advent of electric vehicles and grid storage technologies, the potential evolution into the distributed utility paradigm, with distributed generation, distributed storage, and distributed load management will dramatically alter the operation of a traditional utilities distribution system. Utilities that are operations driven may focus on the microgrid architecture or a self-aware, self-correcting distribution system to manage this new dynamic grid.

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Ohio’s Senate Bill Number 221, signed in May 2008, stipulates that each electricity distribution utility shall implement “peak demand reduction programs” that reduce peak demand by 1 percent in 2009 and by an additional 0.75 percent each year through 2018.

Pennsylvania’s Act 129, signed in October 2008, directs the PennDeregulated focus sylvania Public Utility Commission Electricity is currently deregulated in 13 states and the District of Columbia. to require that electric distribution Eighteen states and the District of Columbia have deregulated gas, and another companies meet established elecfive states have instituted partial choice for gas. In states with competitive tricity consumption reduction targets energy markets, smart grid technologies can further enable the richer, and of 1 percent by May 31, 2011, and more real-time, information that will allow more liquid and better informed 3 percent by May 31, 2013. market decisions and market participation Utilities deploying by third-party suppliers and contracting smart grid systems with Greater awareness of the energy users. Utilities that participate a focus on EE and DR in these markets will focus on the must determine the mix grid provides utilities with data types, data volumes, data formats of programs to deploy and data-quality requirements of using dedicated systems improved knowledge of supporting the various market players versus those that are and their ratepayers. expected to leverage potential grid failure points smart grid technologies.

Operations excellence focus Further, the developand enables proactive Utilities’ traditional responsibility is the ment of voluntary distribution and delivery of power to programs, automated maintenance and reliability consumers in the most efficient and programs, load shifting reliable way possible. This includes programs, rate-based planning practices. investing in significant physical assets to programs or energyenable that delivery. Smart grid technoloreduction programs all gies enable dramatic improvements in the planning and utilization of those become part of the planning of the grid assets. Utilities that are focusing their smart grid investments on operasmart grid strategy and the sequencing tions excellence are tailoring their smart grid architectures around using grid of technology deployment. sensors and improved grid measurements to re-examine their distribution planning processes, asset management improvements, distribution manageStrategic plan ment and preventative maintenance programs and, ultimately, improvements needed in all cases to their overall operational efficiencies. This will drive a specific initial system No matter which perspective drives architecture, integration plan and data availability approach for their smart a utility’s smart grid program, a grid initiative. targeted, specific and measurable strategic plan is needed. Utilities EE + DR focus need to build smart grid strategic Many regulators and legislators have implemented stringent energy efficiency plans that are designed to satisfy requirements for energy utilities. These include both energy efficiency (EE) and near-term drivers, capture mediumdemand-response (DR) requirements. Examples of state legislated energy and term benefits, and also position for demand reductions include: long-term opportunities.

The EmPOWER Maryland Act, signed in April 2008, sets a target to reduce energy consumption by 15 percent by 2015. It directs the Maryland Jeff Buxton is an executive consultant Public Service Commission to require each electric utility to achieve 5 percent with Enspiria Solutions. Mehrdod Mohseni demand reduction by 2011, 10 percent reduction by 2013, and 15 percent reduc- is Enspiria’s senior vice president and tion by 2015 (from 2007 per capita peak demand). general manager of smart grid practice.

OUT THE DOOR VISION

S T R AT E G Y

REALITY

Water smarts +Generation utilities faced with driving water efficiency, as well as energy efficiency

By Joe Kovacs MAINTAINING CLEAN WATER RESOURCES ISN’T AS

compelling a public concern as curbing greenhouse gases. But the challenge will have a solid impact on the future of electricity generation.

While smart grid technologies enhance power utilities’ communication with customers to increase awareness of consumption and provide demandresponse programs and energy-efficiency incentives, fewer opportunities exist for encouraging such efficiency measures for water use.

“Per capita, our national water consumption is 10 times Europe’s,” Geoff Zeiss, director of technology at Autodesk, an engineering and architectural design company, said. “The reasoning behind that discrepancy is that North America does not meter much of its water consumption—water simply does not get as much attention or notoriety EFFICIENCY MATTERS as, say, the current awareness of Water and electricity are inextricably carbon emissions.” tied together, as Mike Breslin learned Yet the issue is real. The Energy when he looked at the issues facing Policy Act of 2005 called for an inveselectric generation utilities with tigation of the energy-water nexus. regard to water conservation. The The Department of Energy (DOE) federal government is looking the is performing research and developissue of the energy-water nexus, ment to enhance the efficiency and as well. environmental performance of more than 300 GW worth of coal-fired plants to reduce power plant freshwater consumption and minimize the impact on water quality. And siting permits have been denied to new generation plants because of concerns about water use. The power industry must consider how to meet future demand in alignment with concerns facing the water industry.

Thermoelectric generation high-water draw

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Thermoelectric generation plants demand significant cooling water to condense steam created to drive turbine generators. In 2005, the United States Geological Survey claimed that generation plants withdrew 201 billion gallons of water from freshwater and saline sources— the most among all sectors. Most is restored to its source (a lake, river or reservoir among freshwater bodies) but at a higher temperature, which contributes to water-quality problems via thermal pollution and makes aquatic organisms prone to disease.

This is particularly true of oncethrough cooling, according to Chips Barry, manager at Denver Water.

“These systems withdraw significant water for condensation and restore heated water to its source at greater rates than other cooling systems,” he said.

Wet recirculating cooling systems, which serve approximately half of coal-fired plants and more than 40 percent of all generation, withdraw less water but consume more. Water passing through a condenser is routed at a higher temperature to a cooling tower where evaporation occurs.

What water remains is passed back into the source as described earlier.

With the Energy Information Administration (EIA) anticipating thermoelectric generation growth to 824 GW in 2030 from approximately 700 GW in 2005, rates of withdrawals and consumption will rise and clean water resources will be more severely constrained. In 2008, DOE projected multiple conceivable scenarios for future withdrawal rates. The scenario anticipating the least withdrawal hinges on retrofitting plants that now use once-through systems with wet circulating systems.

But today’s consumption levels are already alarming. In a congressional survey of water managers in the early

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OUT THE DOOR 2000s, 36 states said they anticipated water shortages in the next decade, with 46 states claiming vulnerability to shortages if faced with drought-like conditions. This increases the perceived threat of new plants.

Electric industry power smarts

So what is a site developer to do? The power industry can increase its smarts by understanding more about the environments in which to site new generation plants. The coasts offer saline water sources not available inland, and this is where many plants are constructed (as well as around the Great Lakes). Cooling ponds can help curb environmental outrage by separating cooling water from natural aquatic ecosystems, while cogeneration makes secondary use of steam created for turbine generators. And it also helps to understand where the prospect of new generation could face the greatest threat from water constraints due to current and projected regulation. But at the end of the day, few considerations hold as much water Per capita, our for new generation as the prospect of population growth. Where people go, electricity must follow. national water Since the early 1990s, the Southwest has witnessed significant growth, with the highest consumption is rates in Nevada and Arizona—two of the most arid states in the country. (They are followed 10 times Europe’s. closely by Utah and Colorado, also among the drier climes.) Will this trend continue? EIA thinks so and projects significant increases in new generation in Arizona, southern California, along the Wyoming-Colorado border and in southern Nevada. So how will new capacity be developed given severe water constraints in the Southwest and, in some cases, where water management practices are already deemed unsustainable?

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Dry-cooling vs. once-through

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It’s already happening. The blistering sunlight in southern California’s Mojave Desert is driving significant solar generation, including a well-known largescale solar thermal project under development in Ivanpah, Calif. This consists of three plants projected to generate 400 MW for Pacific Gas & Electric and Southern California Edison. The Ivanpah project will, according to developer BrightSource Energy, avoid producing 400,000 tons of carbon emissions annually. From the perspective of water management, the project will utilize a dry-cooling technology, utilizing significantly less water than once-through and wet recirculating systems. DOE says that dry-cooling systems are utilized for less than 1 percent of all generation plants. Developing plants with such systems tends to drive up capital costs while generating less-efficient power.

However, a lack of sufficient water resources in arid climates is leading to some unfortunate but necessary trade-offs.

Geography also limits the amount of power that can be generated by cleaner hydroelectric systems, which consume no water. “Most advantageous sites have been built on,” Barry said. Denver Water has seven hydroelectric units including two at Boulder’s Gross Reservoir that cumulatively generate close to 25 MW. But there are challenges associated with finding rivers with large enough elevation differences for a dam to route water down to a turbine while also benefiting from acceptable ROI from generation.

“Environmentalists concerned about water quality also aren’t thrilled with the idea of storing water and impacting ecosystems, and you’re seeing resistance

there as well,” Barry said. But as states drive renewable portfolio standards to cut greenhouse gas emissions and develop off-grid distribution generation, an additional boon often unconsidered by customers is the lessened impact on rivers, lakes and reservoirs. Less generation from a fossil-fuel plant means more water.

So what does this mean for siting, designing and building a smarter generation plant? There is no silver bullet, just considerations—environmental, technological, geographical, regulatory and financial. As population swells and some regions grow faster than others, unique circumstances will inform how new generation can coexist with existing and future water resources.

Climate change plays a particularly ironic role. There is renewed interest in nuclear generation because it produces clean power and for plants that may eventually be retrofitted with carbon-capture technologies. Yet both systems demand greater water resources than today’s plants.

Smart grid technologies make it easier for power utilities to influence customer behavior and drive energy efficiency. Similar top-down programs that encourage water efficiency among individual customers will have limited impact as new generation’s demands will be exorbitant. But expanding research devoted to dry-cooling technologies (and determining how to minimize adverse impacts), encouraging clean generation and accepting trade-offs between the benefits and drawbacks of new generation are all important ways to help the power industry move forward. One thing is certain—as access to water resources becomes more restrictive, power plant developers must learn more than how to generate power; they must also learn how to solve complex puzzles.

Joe Kovacs is a freelance writer based in Colorado.

Green transmission ACROSS THE COUNTRY, PLANS ARE BEING MADE AND

proposals are being considered for the best ways to connect more green generation to the nation’s electric grid. The transmission routes from green generation sources to often distant consumers will cross all degrees of terrain, from the rolling hills of central California (seen here) to inland plains and mountain ranges. But before new lines are built, the question of who will pay is still being hotly debated.

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