Intelligent Utility MayJun2011

VOL 3, ISSUE 3 » MAY/JUNE 2011

SM ART GRID

Where smart grid meets business—and reality.

2020

CIS/MDM

Utility barriers still exist

©©

Industry experts weigh in on critical trends

TRANSMISSION INTERCONNECTION Two new developments putting the brakes on buildout ENERGY EFFICIENCY IMPACT How DR + EE is more than the sum of their parts

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CONTENTS S PECIAL REPORT CIS/MDM

30 Meter data management shows promise

Sierra Energy Group research provides intriguing results

DEPARTMENTS

16

FEATURES // MAY/JUNE 2011

Smart Grid 2020: where are we going?

16 Gazing into the future of the new utility Some elements are more hazy than others

20 Implementing challenging changes Utility executives discuss the issues

Transmission interconnection

22 Putting the brakes on build-out W WW.INTELLIGENTUTILIT Y.COM /// MAY/JU N E 2011

Transmission plans receiving deep scrutiny

2

Energy efficiency impact

26 The power of integration

Energy efficiency/demand response coordination momentum grows

12 22

4

Drawing the line

6

Transmissions

8

6

Letters from readers

The big picture 8

Weighing the impact and keeping it simple

12 U.S. capital gives thumbs-up to active energy savings

34 Grid(un)lock

34 Transmission’s at the epicenter

36 End of the Line

36 Keeping down with the Joneses

40 Smart grid as economic development

30 34

42 4D

42 The devil’s in the data details

44 Connections

44 Micro is mighty

48 Out the door

48 Power storage advances from unexpected sources

44 Vol. 3, No. 3, 2011 by Energy Central. All rights reserved. Permission to reprint or quote excerpts granted by written request only. Intelligent Utility® is published bimonthly by Energy Central, 2821 S. Parker Road, Suite 1105, Aurora, CO 80014. Subscriptions are available by request. POSTMASTER: Send address changes to Intelligent Utility, 2821 S. Parker Road, Suite 1105, Aurora, CO 80014. Customer service: 303.782.5510. For change of address include old address as well as new address with both ZIP codes.

Allow four to six weeks for change of address to become effective. Please include current mailing label when writing about your subscription.

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

The more things change...

SPRING HAS BEEN A LONG TIME COMING THIS YEAR, BOTH IN THE WORLD AND IN

our industry.

It’s Easter weekend, the sun is shining for what feels like the first time in weeks, the daffodils are blooming and the lilac bushes are budding, and I spent Earth Day (OK, I celebrated a day late) rescuing three 10- to 15-foot birch trees from the road right of way in front of our property and transplanting them in our backyard.

Intoxicating change is in the air, and I’m enraptured by its promise.

I’m still waiting for a few more signs that spring has come to our industry.

Late last year, I noted in this column that the mood of the industry in 2010 had been by turns concerned, excited, anticipatory and worried. I’m

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not sure that’s changed much yet. Yes, there have been landmark project announcements, exciting new products and services introduced and even some significant forward movement toward industry standards.

On the other hand, we’ve also been dealt the wild cards of consumer smart-meter pushback, federal political hand-wringing and backroom two-steps that have effectively derailed a National Energy Plan, a devastating nuclear event in Japan that could well end up being this decade’s energy “shot heard ‘round the world,” and an economy that’s not bouncing back as quickly as promised.

It’s not quite what we’d hoped for.

But, like the advent of spring, there’s enough promise in the air to hang on and wait for it to arrive.

In this issue, we’ve explored that promise. In that spirit, our cover story looks at Smart Grid 2020. Where are we going? Are we on track to get there? What are the side roads—and the superhighways—we are likely to encounter along the way?

One of those side roads is explored by John R. Johnson, who talked to regional transmission organization PJM Interconnection and the Midwest ISO about changing plans for new transmission

4

projects, based on expected loads that haven’t, as yet, materialized.

On the other hand, Laurel Lundstrom investigated the growing integration of energy efficiency and demand response programs across the country. She found, from her research, that the ability to combine both types of programs will truly enable both consumers and utilities to take full advantage of the synchronicities available.

These and the other stories in this issue are, as always, intended to provoke and encourage discussion. I invite you to continue the conversation via e-mail with us, or with our writers. I also encourage you to head to our Web site at www.intelligentutility.com, where you will find these articles, as well as our daily online newsletter, along with a platform for online discussion.

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

sue? Then Enjoy the is for free at subscribe .com/ igentutility www.intell subscribe

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TRANSMISSIONS

Letters from readers Demand Response 2.0 (Apr. 12, Intelligent Utility Insights)

A real issue of demand response is playing out in Japan and the lessons being learned there are the realities of the world we live in. The direct impact due to the loss of a major part of the base electric generation has thrown their economy into additional trouble besides that caused by the earthquake and tsunami. What is not being said out loud is that this is a reality that can happen in California as well as other parts of the U.S. and Europe.

What do you do when you have to cut 25 percent of your energy consumption right now and how do you administer this? This the challenge is no longer theory but of DemanD response reality in Japan. This also happened in Texas this spring with the winter weather knocking out 7,000 MW of base generation.

Germany has taken 7,000 MW of base generation off line because of the Japanese crisis, and this along with the possibility of unusual weather patterns could cause them demand supply problems this spring and summer.

The lifestyle of the Japanese population is one heavily based on efficiency and, over the years, they have taken many demand response measures to keep energy consumption down. Yet they are now facing even a greater Vol 3, issue 2 » march/april 2011

©©

Are utilities really addressing the needs?

integrating renewables will better forecasting aid it and operations?

W WW.INTELLIGENTUTILIT Y.COM /// MAY/JU N E 2011

social electricity networks tips for successful microgrid participation

6

To contribute to the Transmissions department, please e-mail your submission to intelligentutility.editor@energycentral. com. Provide your name, address and daytime phone number. Letters may be edited for style and space.

mandated reduction. Most of the industries there feel this reduction will be a hard reach for them even with all the efficiencies they presently have in place.

Every energy planner, PUC regulator and demand response advocate should be watching this situation with their eyes wide open.

Richard G. Pate

www.intelligentutility.com EDITOR-IN-CHIEF Kate Rowland

krowland@energycentral.com 720.331.3555 SENIOR CONTRIBUTORS

Phil Carson Editor-in-chief, Intelligent Utility Daily pcarson@energycentral.com 303.228.4757 Christopher Perdue Vice President, Sierra Energy Group cperdue@energycentral.com 310.471.7396 FEATURE WRITERS

Mike Breslin, John Johnson, Phil Johnson, Laurel Lundstrom, Elizabeth McGowan, Cate Meredith, J. Ian Tennant

Smart grid: what problem are we solving?

(Mar. 17, Intelligent Utility Insights)

The utilities, and the utility industry as a whole, needs to be able to explain the overly complex way in which electricity rates are structured and approved and educate consumers on the impact of capital investment on those rates. A concerted effort to overhaul the archaic rate structures and the opaque manner in which they are set would simplify this task enormously.

We also need to build the business case for why investments in demandside management help to curtain the growth in generation infrastructure that is a primary driver of overall capital investment. Beneficial side effects of such an approach, including reduced dependence on foreign oil, reduced environmental impact, reduced demand for new power generation and transmission facilities in everyone’s back yards, etc., would strengthen the argument.

When you put all of this together it becomes a huge challenge and one that requires an integrated and coordinated approach from all sectors of the industry.

where smart grid meets business—and reality.

Data Visualization

the tools we use, and why

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THE BIG PICTURE

Weighing the impact and keeping it simple ++NIPSCO and Dominion Resources execs discuss customer service

By Christopher Perdue MANY OPPORTUNITIES EXIST FOR UTILITIES AND THEIR

customers as a result of smart grid investments. But there is a delicate balance between the level of investment to make and the ultimate impact it will have on improving utility operations and customer service.

I recently discussed this delicate balance with Guy Ausmus, senior vice president of business planning and strategy at Northern Indiana Public Service Company (NIPSCO).

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Focusing on customers’ basic needs According to Ausmus, when you consider energy delivery in its simplest form, customers have two very basic needs when it comes to their utility provider.

“They want their power to be there whenever they need it, and they want it at a competitive price,” he said.

“As we’ve seen in many cases, having a fully functioning smart grid system is extremely capital-intensive. For the everyday residential customer, we don’t see a large population necessarily wanting to monitor real-time pricing information throughout the day, thinking about whether or not it’s a good time to run their dishwashers or turn down their air conditioning units.

“Instead, this segment of customers might benefit more from an advanced metering infrastructure (AMI), which is slightly different than smart meters,” he said. “An AMI would enable us to make the grid more reliable, because we would have the ability to capture timely information about grid conditions, utilize modeling and mitigate future failures within our transmission and distribution system. Having this infrastructure would also provide more stability in terms of electric spending—a benefit that would also be realized by our customers.”

8

Balancing large versus small On the other hand, Ausmus added, “A fully integrated smart grid system provides a two-way stream of information that enables real-time optimization and response to match our demand with supply—something that is particularly important to our largest customers in the steel industry. By adding AMI to that, these customers could also track and understand their energy use and reduce their overall electricity costs.”

I asked Ausmus what advice he would provide to other utilities as they attempt to engage their customers with smart grid solutions.

“When it comes to developing programs and engaging customers with smart grid, keep it simple,” he said. “It’s nearly impossible to gain acceptance if you make it difficult for customers—no matter their level of energy sophistication— to understand what’s available to them.”

Ausmus also pointed out that in a regulated environment, it’s extremely important that a utility’s regulatory body share the same vision for the future of smart grid, and that potential cyber security concerns are addressed—such as the famed Stuxnet computer virus.

Lowering the cost of action He also thinks that utilities should not lose sight of labor costs. “Almost anything smart grid can do, you could do with additional labor. In other words, all smart grid does is lower When it comes to the cost of action,” he said. developing programs “And so it’s all marginal and engaging cost, marginal revenue. If the customers with marginal cost/ marginal bensmart grid, keep efit balance just isn’t there, it simple. we shouldn’t move forward so rapidly. So, I see this eventually evolving over years and years, bleeding into the fabric of our utilities, rather than just ‘boom’, one day it’s there.”

“

”

Keeping it simple Utilities are increasingly attempting to better engage their customers to ensure the success of smart meter and smart grid deployments. But how best to do this? I asked Mark Webb, director of policy and business evaluation at Dominion Resources, what advice he would provide other utilties as they attempt to engage their customers with smart grid solutions.

According to Webb, it’s important to keep your message simple. “I think utilities need to convey to the customers that they will be involved to the extent that they want to be involved,” he said. “Ultimately, the customer will have the opportunity themselves to engage and analyze their power usage, and if they’re concerned

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THE BIG PICTURE

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Like many utilities, Dominion has a diverse economy across its region, from Virginia’s high-tech corridor to the tobacco regions of southern Virginia, and each of these subregions is quite unique.

The utility is also cognizant of the generational gaps that exist in its market.

“We have many senior citizens who are very much concerned that these smart grid investments could lead to mandatory time-of-use rates that impact their lifestyle, but we also have many younger people who are not only accustomed to using new technologies, but desire them,” Webb said.

“I think that somehow utilities have to find the middle ground to prepare for the people who are the new customers coming in, and at the same time be mindful of the concerns of older customers who may be less comfortable with new technologies.”

10

about the environment, they’ll also be able to see how their energy usage impacts the environment.”

Webb thinks that the typical utility customer is smart enough to realize that all of the capabilities of the smart grid may not be known yet. “We need to show them the immediate benefits, the simple benefits, and then explain what some people think is possible over the long term. Many of those things will come true and some may not, but certainly things will become possible that we haven’t even thought of yet,” he said.

Analyze customer segmentation Customer segmentation is another area that Webb thinks utilities should be analyzing. “When we talk about customers, at least in our regulated electric territory, our customers are not a monolith in terms of their viewpoints,” he said.

Rethinking asset life I asked Webb what regulatory changes may be needed in the future to accelerate smart grid development on utility systems. He thinks that utilities and commissions may need to rethink some of the expected depreciable life of assets. “I think that some of the software and solutions that will be components of the smart grid may not last for the 30 to 40 years that we’re accustomed to,” he noted.

“I also think that we’re going to need to come up with a way for commissions to understand benefits that may be in the future, and may not be demonstrable in the near term.

Looking at models like the Internet, or the build-out of wireless networks, and trying to envision the benefits that consumers will derive, may not be provable under the tests that utility commissions are used to applying with the typical cost-benefit analysis.”

Christopher Perdue is vice president of Sierra Energy Group. These two interviews first appeared in Intelligent Utility Daily.

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THE BIG PICTURE

real chance to significantly and favorably influence their electric bills.

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U.S. capital gives thumbs-up to active energy savings

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++Pepco tests successful price-responsive structures

By Phil Johnson AMONG RECENT SMART-GRID PILOT PROJECTS, PEPCO

Holdings Inc.’s PowerCentsDC—featuring volunteer customers from all eight wards of the District of Columbia, with an additional “control” group of customers to help verify findings—stands out, if for no other reason, because it represents a pioneering study highlighting multiple pricing structures.

The collected information indicates that electric customers across a broad range of incomes in a U.S. Eastern/urban environment—specifically, the District of Columbia—may lend hearty support to price-response infrastructure if customers see quantifiable cost of energy as well as other benefits, all adding up to a

Critical peak behavioral changes Limited to Pepco’s District of Columbia constituency (through its operating subsidiaries, Pepco also serves extensive geographies in Maryland and Delaware), PowerCentsDC was designed to test the willingness of an urban crosssection of customers who have had smart meters installed at their houses, condos or apartments to change their energy-use patterns during criticalpeak events.

Those critical-peak events were to occur both under winter conditions (a total of three winter events) and during two different yearly summer periods (six events each of the two summers, for a total of 12 summer events).

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THE BIG PICTURE The three price-response plans, pre-assigned to program volunteers who were selected randomly across D.C., included a peak-energy pricing incentive, a peakenergy rebate plan and an hourly pricing structure tied to the PJM next-day wholesale-energy-cost projection.

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Overwhelming thumbs-up One of the most eye-opening indications from PowerCentsDC is the overwhelming stamp of approval given to the program by its participants, many of whom appeared, at best, to have started out feeling somewhat ambivalent about the whole undertaking. As PowerCentsDC proceeded, participants seemed to largely embrace the opportunity to positively influence their electric bills.

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“The results and learnings are pretty bold,” said Steve Sunderhauf, manager of Pepco’s program design and evaluation. “After the study, one of the questions we asked of program participants was, ‘Would you recommend the PowerCentsDC electricity project to your friends and family?’ And 89 percent said, ‘Yes.’ “And we asked, ‘Which price plan would you prefer: your former pricing plan, or the PowerCentsDC plan?’

“Ninety-three percent of those who responded liked the new plan, regardless of which of the three variations they were on. Ninety-three percent. Now, that’s really pretty remarkable.”

To what factors can such an overwhelming percentage of positive reactions be attributed?

“Honestly, there was a lot of skepticism by some of the customers when they first joined in the rate,” said Sunderhauf. “And they got all the messaging, and they began to see some sense of savings—and the fact that they could actually influence their bill.

“I think all of that drove a very high satisfaction level with the rate design— plus, I think people like doing something new. They like feeling that they’re doing something for the environment—many of them, anyway. And they like the challenge of trying to save energy.”

Across-the-floor cooperation Numerous organizations cooperated to make PowerCentsDC happen.

“Smart Meter Pilot Program Inc. is a nonprofit corporation we created involving all of the project partners,” Sunderhauf said. “These parties are usually in opposite camps—the consumer advocate and the commission staff. Then you had the Consumer Utility Board, and you had the union, IBEW. “So you’ve got this weird mix of stakeholders. PowerCentsDC basically allowed people to come behind the curtain and see what’s involved in putting programs of this type out,” he said.

Conducted over about a 15-month time frame from July 2008 through October 2009, data and numbers from PowerCentsDC have been analyzed to the nth degree, as published in a September 2010 report.

“I get a real kick out of things people did in response to the critical-peak events,” Sunderhauf said. “One of the clever things was you could pre-cool your living space just a little bit prior to one of the summer events—and make yourself more comfortable—or put more fans in the house, and don’t use appliances. And other people probably didn’t act as aggressively.

“Then there were those who took the family to the museum. The museums are free in the District, and while you’re out during the peak-energy event, you could reduce the level of the air-conditioning at your residence.

Or you basically were willing just to do things a little bit differently: turn off some lights, or turn off the air-conditioning when you’re at work.”

Program participants who had central air conditioning units received an offer to try “smart” thermostats, which could be set to automatically adjust thermostat temperatures during peak periods.

In messages transmitted and read on the thermostats, Pepco conveyed bill-to-date and kilowatt-hours-used

statistics, as well as information “Price does matter. PowerCentsDC proved prices work. People do react to price signals. People do take action. And people were much more enthusiastic regarding the next critical-peak event. about this rate compared with their prior rate. But I think the results also show This information was eventually that we can be much more aggressive in both pricing and made available to all rebate plans in the future.” program participants PowerCentsDC PowerCentsDC applied pricing of about 80 cents per on the PowerCentsDC kilowatt/hour for the critical-peak pricing events, and a Web site, and was also proved prices similar level for critical-peak rebates. mailed to participants.

“Going forward, we think we can provide an even Peak-load savings work. People do more robust price signal—in the range of about $1.25 per were significant kilowatt/hour reduction,” Sunderhauf said. “In one of Subsequent questions react to price our markets, we’ve just calculated what customers’ rebates relating to results could be—and it’s up over $1.60 per kilowatt/hour.” and ramifications signals. People Sunderhauf also noted the much greater percentage of PowerCentsDC of load reduction under PowerCentsDC on a 97-degree have drawn pointed day (43 percent) than on an 85-degree day (26 percent). do take action. responses. “One of Obviously, the higher temperature drew a considerably the commissioners in more telling response from participants. another of our jurisdictions said, “When some of those load reductions were coupled with automated controls, we ‘Well, how do we know price matters?’ were getting up around 50 percent reductions,” said Sunderhauf. “Just think about the impact that could have on peak load and the need for generation resources.

That kind of caught me off-guard,” “It’s pretty staggering.” said Sunderhauf. “I mean, isn’t this America?

Phil Johnson is a freelance writer and speechwriter.

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2020 Smart Grid

Where are we going?

Gazing into the future of the new utility

16

more hazy than others

By Kate Rowland IT’S GENERALLY AGREED THAT THE COMING

decade will bring more change to our industry than we’ve seen in the previous century.

Industry researchers have clearly indicated they see a massive increase in smart grid spending between now and 2015. Late last year, SBI Energy was definitive in its expection that “The next five years will be a pivotal period for the global smart grid market, with grid component companies expected to leverage their sales prowess to capture long-term contracts throughout the electric grid supply chain.”

But what about 2020?

Data analytics on the rise In early January, Pike Research released data indicating that the software and services that will enable smart grid data analytics will represent one of the largest growth opportunities in the utility sector over the next few years, increasing from a relatively small market of $356 million last year to nearly $4.2 billion in annual revenue by 2015.

And there are clear indicators this trend will continue into 2020. “Data analysis is the area which is just emerging as a need: ‘Okay, I now have the systems in place and have lots of data, but what do I do with it?’” said John Wambaugh, a vice president of Utility Integration Solutions (UISOL). “My favorite quote is, ‘I have 100 times more data, and I still can’t tell where the problem is.’”

In my own conversations with utilities and vendors alike, especially over the past year, the subject of structured and unstructured data analytics has crept into the discussions more and more often. As Craig Johnston, OGE Energy Corp.’s vice president, corporate strategy and marketing, told us recently about his utility’s data

ILLUSTRATION BY DANA LECHTENBERG

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++Some elements are

We decided to plumb the depths of our own crystal ball, and asked analysts, researchers and national laboratory leaders where they think the industry is headed in the coming decade, and what we can expect come 2020.

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SMART GRID 2020

analytics project, “The initial questions we asked were: Where are we going to store all this data, how will we organize it and how can we utilize the information to improve our business?”

If you can capture and analyze that data and use it in a predictive fashion, he said, “what can we do with it to improve our operations and enhance our customer experience?”

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Data analytics + DR = new revenues Demand response will be more seamlessly teamed with its kissing cousin, energy efficiency, and form a much larger portion of the intelligent utility equation by 2020. In January 2010, Lux Research noted that analysis and service revenues, led by demand response applications, could make up the largest piece of the smart grid picture by 2015. Five years further down the road, today’s $1.4-billion earner could lead to global revenues totaling much more than the $6.7 billion predicted by 2015.

Standards will also drive growth, according to our panel of grid modernization prognosticators. “Industry standards are progressing well, and will continue to progress,” Wambaugh said. “Everyone is committing to standards these days, and the same goes for cyber security.”

Dick DeBlasio, the National Renewable Energy Laboratory’s chief engineer, Renewable Electricity and End Use Systems Directorate, agrees, but says the country’s economy will play a part in the speed with which we move forward. “The economy will most likely be the impediment to moving fast versus slow in the next nine years,” he said.

“In the meantime, cost efficiencies can be developed in construction and design with standardized smart grid interfaces but having flexibility to design as the technologies between the interfaces improve and lessons learned evolve.”

18

Pushing back straight into 2020?

The energy consumer of 2020 is a bit more hazy, though.

Some think consumer pushback will continue, and others see it as a blip on the screen, one that can and will be overcome with a change in utility perspective.

“Consumer pushback will continue,” said Doug Houseman, vice president of technology and innovations for EnerNex. “If energy prices trend up—and it seems likely— then the pushback will get even harder.”

Houseman ties current consumer pushback to a larger issue. “Regulation and legislation, combined with lawsuits, will stop 80 percent or more of new generation construction (planned versus operating), up from about 50 percent in the 1990s. With the nuclear scare and global warming ... the result will be a lot of pressure to retire far more generation than we build. Then add the pressure of electric cars, and you have a scarce commodity,” he said.

“If Canada actually does build its transcontinental transmission system, Quebec and British Columbia will both send more power east and west rather than south. This will increase the anger and pushback. Only strong national efforts at training that includes pop culture folks will potentially change this pushback.” He predicts “lots and lots of lawsuits on everything from tariffs, meters, renewables, generation, etc.”

Wambaugh disagrees. “We’ve been rolling out smart communicating meters since 1994 and this is the first time that the pushback is occurring. This is a localized problem due to the utility communications and interaction with the customer,” he said. “No one else is seeing this type of problem.

This is a blip. However, it’s up to the utility industry to show the customer why they should be doing this. Customers are smart and need to know what’s in it for them and why this is a good idea.”

Changing job descriptions The biggest change, however, may be in the structure of the utility itself, right down to its very core: its staff. “We are undergoing a generational change in staff at the utilities,” Houseman said. “Most of the folks who were in the The economy will industry in 2005 will not be in 2020. How folks most likely be the think and what is ‘standard’ will change more in impediment to moving the next decade than it did in the past two decades.” fast versus slow in “What does the utility employee of 2020 look the next nine years. like?” Wambaugh asked.

“They will move to be customer advocates and actually provide service to customers to help them to use technology and services and rates to impact their bills and consumption.”

“

”

The more things change Charles W. Newton, president of Newton-Evans Research Company, predicts obstacles. “From our research perspective, the biggest obstacles to faster development are these: First, the limited amount of capital and human resources available for smart grid development, which keeps utility market acceptance and new product usage trailing the technological breakthroughs available to the industry. Second is the need to ‘keep the lights on’ while testing and piloting new technology—adding years to the adoption curve.” Newton also cited the need to develop a workable communication strategic plan, and keeping cyber security in mind as a strategic concern.

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SMART GRID 2020

Implementing challenging changes ++Utility executives discuss the issues

By Christopher Perdue A SMARTER ELECTRICITY GRID COULD FUNDA-

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mentally change the way customers pay for and manage their energy use. Smart grid investments could help reduce demand, save money and improve reliability and efficiency. But implementing the necessary changes is not without challenges.

At the annual EnergyBiz Leadership Forum in Washington, D.C., Intelligent Utility interviewed six utility executives to gauge how they their utilities are dealing with the largest reconfiguration of the utility industry in over a century. Their comments, edited for style and length, follow.

20

in order to incorporate that, how they’re going to then explain it to the consumers and how it is that they’re going to manage the system itself after it has been installed. And so it’s a fascinating subject. On one hand, you have so many things that can be done from the technology, but those who have the technology often do not have a direct relationship with the consumers and are not making the decisions with regard to the implementation. On the other hand, the consumers—and often the decision makers—only know the current business model served by the current technologies.

IN YOUR VIEW, WHAT HAS THE INDUSTRY LEARNED ABOUT REGULATORY RECOVERY AND APPROVAL OF SMART GRID INVESTMENTS?

What we’ve learned in Indiana is that the issue of benefits becomes very key for our regulatory commission.

One of our sister utilities tried what I’ll call the “big bang HOW CAN UTILITIES BEST FUTURE-PROOF SMART approach” for lack of a better term. They tried to cover the GRID TECHNOLOGY INVESTMENTS WITH SO MUCH entire service territory footprint at one UNCERTAINTY IN THE MARKETPLACE? time, and they were widely rejected by GUICE Scenario planning is helping the regulatory commission. I think the us think through the range of plausible thing that we learned from that is that THE EXECUTIVES futures we could be faced with and how regulators look at these investments to best plan to be successful despite the through very baleful eyes. They want to GUY AUSMUS Northern Indiana PS uncertainties. We’ve identified technolsee benefits and they want them to be Company/NiSource ogy innovation and energy policy as the very tangible. I think our commission major business drivers that will cause is that way on most investments, but PAUL BARHAM significant change for utilities. This has CPS Energy I think people tend to ascribe a lot of allowed us to plot out how we would attributes to this space that they don’t ANITA DECKER respond in each of the scenarios which ascribe to other assets of the utility, and Bonneville Power Authority has cleared the way for a safer path.

I rather suspect the commission sees all KATIE GUICE of them in much the same light. They MOYNIHAN I think one of the inTECO Energy, Inc. want to know what is the benefit to teresting points with regard to the JAMES MOYNIHAN the customer. entire discussion is that it raises AUSMUS

North Attleborough Electric

the question of the role of the utiliMOYNIHAN I think that’s a great point MARK WEBB ties themselves because utilities are with regard to the benefits, and I think Dominion Resources Services really the middle man. You’ve got, on when you have a small utility like the one side, the technology, and you’ve one that I represent, it’s not very clear at got the changes in the technology; and then you have the all what the benefits are to the consumer. In our industry we consumer on the other side. But in between is the utility, hear about the great technology and the possibilities that are and it’s the utility and the utility decision makers who are there inherently, but much of it is predicated upon changmaking decisions with regard to what technology to take, ing consumer behavior. The difficulty that I see from an how they’re going to change their current business model acceptance standpoint is that the consumers fail to see the

benefits. I can truthfully say that in five years in North Attleboro I have yet to have someone call me and say, “Mr. Moynihan, it would be great if you invested a good deal of money in smart meters because I’m really looking forward to getting a sense of it.” In many ways I do question at this stage whether or not smart grid solutions are really a product looking for a market as compared to a market seeking out a product.

Let me add a little bit of a different perspective.

As a municipal utility our regulator is our local board and city council. So for our situation, essentially we make the business case to the board and city council to move forward on this. And I think one thing that we see at this point is the challenge you’re talking about—what is the customer value in this now? And I think we’re trying to figure out what that is. We made this case based on a lot of operational reliability types of measures, but we know there’s a lot of ways you can leverage that infrastructure once it is there.

BARHAM

I think one of the challenges though is the aspect of actually engaging consumers. How do you create demand DECKER

for these new products and services? It will involve a huge educational effort, and I think utilities are not as adept at educating customers.

But the message should be that these investments can reduce outages and lower energy costs. And it’s making that clear to customers and understanding that it can happen even without changing their behavior. Changing their behavior will just increase the benefits.

WEBB

But I think there’s a tension when you talk about reducing the costs because there are investments we have to make, and someone’s going to need to pay for those investments. So the reduced cost may come later, or it may come in a different shape than what they’re thinking.

DECKER

WEBB I agree. In our case, our approach has been that we get

immediate benefits in terms of reduced energy because our immediate focus was on the utility side of the smart grid and reducing premise voltage levels through a specific application. Tested and deployed, it leads to 3 percent across-theboard savings in energy production.

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

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Transmission Interconnection to economic rebounds, which means electricity load is still behind where it should be, even as the economy grows.

Putting the brakes on build-out ++Transmission plans receiving deep scrutiny

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By John R. Johnson

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WHEN THE ECONOMY TANKED DURING THE

recent recession, businesses were forced to carefully monitor forecasts and dramatically reduce production. Even as the U.S. pulls out of the prolonged slowdown and the economy begins to grow again, production shifts are still occurring and companies are exhibiting caution before raising output.

Although you don’t read about it as much in the newspaper, the same pattern holds true for utilities. When the economy slows down, demand for electricity follows suit.

Just like major corporations, utilities are constantly forecasting the need for production—or electricity in this case—and making adjustments in capital spending. In fact, utilities tend to lag general industry when it comes

PJM scrutinizes transmission needs So it comes as no surprise that some investments are receiving deep scrutiny by utilities and by regional transmission organizations (RTOs), which administer the transmission grid on a regional basis throughout North America.

In February, PJM Interconnection instructed its transmission owners to suspend construction on the PotomacAppalachian Transmission Highline (PATH), which would connect the Amos substation in West Virginia to a proposed substation in Maryland.

PJM had directed that PATH be built in 2007 in order to improve grid reliability and to meet projected forecast load growth. However, the outlook for a slower economic recovElectricity load is ery in that region has resulted in the line being delayed. still behind where it The preliminary analysis to put the brakes on the projshould be, even as ect took into account current economic forecasts, demand the economy grows. response commitments and potential new generation.

“When we received our latest forecast information, that’s when we saw at least the preliminary need to suspend the line,” said Paula DuPont-Kidd, director of strategic commu-

“

”

ILLUSTRATION BY REACTOR

Reaffirming and reassessing While other PJM transmission projects will continue, it is not alone in conducting exhaustive research into transmission needs. Many other RTOs are adjusting their capital expenditure based on the economic recovery.

For example, changes in the load forecast and the entry of new resources through the Forward Capacity Market (FCM) have led ISO New England to reassess the need for some transmission projects. In light of forecasts for lower growth than had been expected before the economic recession, as well as the entry of new capacity resources procured through the FCM, it was necessary for the ISO to reassess the year

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nications for PJM. “We are doing other studies on the line and expect to know more definitively when the line would be needed by the last quarter of this year. We do planning studies throughout the year and we come up with recommendations as they come in from our different members.”

Not all expansion has come to a halt. In March, PJM confirmed that its Susquehanna-Roseland power line project is going forward as planned. The company’s most recent analysis confirmed that the 500-kilovolt transmission line is needed by 2012 to prevent overloads on other power lines in the region. In addition, PJM’s Trans-Allegheny line should be in service later this year.

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TRANSMISSION INTERCONNECTION

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of need for the four projects in the New England East-West Solution transmission plan.

The ISO has reaffirmed the need for the Greater Springfield Reliability Project, Rhode Island Reliability Project and most recently the Interstate Reliability portions of the plan. However, it is still reassessing the continued need for the Central Connecticut Reliability Project portion of the project.

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Midwest ISO eyeing forecasts carefully Most RTOs are keeping a careful eye on forecasts, including Midwest ISO, which oversees electric power access for parts of 13 states and Canada. Clair Moeller is responsible for Midwest ISO’s transmission planning functions, transmission services and transmission cost allocation methodologies, and also oversees the integration of renewable generation resources.

“There has been some deferral of some reliability projects because the loads didn’t materialize, but in terms of the raw dollars of investment it hasn’t made a substantive difference to ISO,” said Moeller, who notes that Midwest ISO has just under $4 billion worth of projects pending that are either seeking state approval or are already in the building process.

“Loads bounced back pretty robustly here in the last year,” he said. “Transmission investment is a long-term game, not a short-term game. Typically, people move very slowly about making a decision to proceed with an investment. Generally speaking, the business case needs to be sound and sensitivity of lower load growth is usually part of the business case we see inside of our own process.”

Evaluation an annual process Forecasting for transmission projects was especially difficult in 2009. Aside from the economic downturn, the Midwest area also experienced one of the coldest summers on record, reducing the need for air conditioners and lowering demand for electricity. “At the time it was hard to tell how much of that was economic and how much was people not needing their air conditioner because it was so cool,” Moeller said.

“We’ve got an annual process that we go through with our members and our stakeholders where we evaluate the system against its reliability constraints and its economic opportunities. The reliability work tends to be driven by

load growth and the economic work tends to be driven by fuel cost differentials. Those are the two elements that we pay attention to in our yearly cycle.”

During the recession, Moeller says that there were a couple of fairly big reliability projects that came off the table because load didn’t materialize. “We talk individually with our transmission investor,” he said. “But the larger investments are driven more about value and have a longer horizon to the business case, and we didn’t see anything that looked like a long enough trend to change any of our decision making.”

Connecting renewables Of course, the continuing move toward renewable generation sources, sun and wind in particular, also has a big impact on transmission forecasting and needs. Midwest ISO has about 10,000 MW of wind in its footprint, and saw a peak load last year of around 100,000 MW. Of the $3.9 billion being invested in infrastructure work, $550 million is for an ongoing project in the thumb of Michigan to ensure that there is an efficient market for that wind energy to participate in.

Moeller said that Midwest ISO will continue to monitor the introduction of renewables into its portfolio, and make adjustments accordingly.

“The dilemma is always generation fleet shifts and The goal is to follow transmission,” he said.

“The goal is to follow the shift in generation, the shift in generation, but get there before the but get there before generation does, so that’s what makes transmission the generation does. planning an interesting thing. But the shift toward renewables and the need to maintain an efficient market as they enter our portfolio is driving a lot of planning and we expect that to continue.”

“

”

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

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Energy efficiency

impact

According to the report, differences in how energy efficiency and demand response programs are financed and a lack of utility staff and contractors with expertise in both fields contribute to the lag.

The power of integration ++Energy efficiency/demand response coordination momentum grows

By Laurel Lundstrom UTILITIES,

THE

U.S.

GOVERNMENT

AND

ILLUSTRATION BY MELISSA DEHNER

Financing differences problematic Despite the positive forecast, out of 2,016 U.S. and Canadian energy efficiency, demand response and load management programs identified in a 2009 report by the U.S. Department of Energy (DOE) and the Environmental Protection Agency (EPA), only 56 served both energy efficiency and demand response purposes.

SMUD melding both The Sacramento Municipal Utility District (SMUD) is working with these elements in an attempt to better meld energy efficiency and demand response program goals.

Ed Hamzawi, SMUD’s customer applications coordinator, insists that the trick to integrating the two for small commercial and residential customers is simplicity.

“Our goal is to make the terms ‘energy efficiency’ and ‘demand response’ easy to understand,” said Hamzawi. “We need to get away from making distinctions [between the two] as much as possible.”

SMUD tested the integration of demand response and energy efficiency efforts in the summer of 2008 through a

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other electricity industry stakeholders recognize energy efficiency and demand response programs as powerful tools to help customers reduce energy consumption and utility bills and assist utilities with curbing the ever-growing demand for power.

Despite the likeness of the two types of programs, utilities have been slow to tap into their synergies.

These are synergies, according to the Electric Power Research Institute (EPRI), that could dramatically curb the national demand for power. Over the next two decades, EPRI estimates that the integration of demand response and energy efficiency programs has the potential to reduce demand for electricity by 14 to 20 percent below projected levels during peak periods, when demand is highest.

Demand response mechanisms inhibiting?

The report also emphasizes a fear among energy efficiency managers that demand response mechanisms will inhibit them from meeting their ultimate goal of reducing energy in the long term. Energy efficiency guarantees energy savings over time, while demand response only encourages people to shift their use.

A disproportionate aversion among customers to demand response programs is also cited by the report. Whereas energy efficiency programs do not force customers to change the way they live, demand response programs call on customers to change their consumption patterns.

The DOE and the EPA list three elements with the potential to change the nature of demand response to bring it more in line with energy efficiency goals: smart grid technologies, widespread energy price and use information and dynamic rates.

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ENERGY EFFICIENCY INTELLIGENCE

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pilot project. The utility offered 78 of its small commercial customers programmable communicating thermostats—an energy efficiency technology—in exchange for their willingness to manually turn up their thermostats, or to have their thermostats automatically raised by 2 to 4 degrees on exceptionally hot days, when demand for power threatened the utility’s reliability as a provider.

Office buildings, retail outlets, and restaurants volunteered to participate, and agreed to one of these options in exchange for $120 and help from SMUD with making their buildings more efficient.

SMUD installed the communicating thermostats in participant premises, conducted energy audits, taught customers how to use the thermostats and informed them about the new rates that would be applied when demand was highest. Participants received notification of the 12 peak events that occurred during the life of the project one day prior to each event and, as result of thermostat adjustments, realized energy savings of 20 percent and bill savings of 20 to 30 percent.

According to an assessment of the project, about 80 percent of participants said that the program met or surpassed their expectations, and 75 percent said they would probably or definitely participate again without the small financial incentive. The assessment called the pilot “a threeway win” that benefited SMUD, participants and society at large through energy efficiency savings.

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Embracing new technologies Through SMUD’s smart grid project, the utility continues to explore new technologies that may further blur the line between the two. “We are looking at what technological offerings and pricing signals will make integration more feasible and interesting in the future,” said Hamzawi.

The Federal Energy Regulatory Commission, in its National Action Plan on Demand Response, forecasts that demand response technologies like these will enable customers to sustain energy reductions by allowing the utility or another third party to manage their appliances.

“The technology has to take care of it for the customer,” said Richard Oberg, SMUD’s supervising demand-side specialist, noting that new technologies, such as smart phone applications, have the potential to provide information

about pricing so that customers can decide remotely whether they want their appliances to be directly regulated.

A growing trend SMUD is just one of several utilities working toward integration, with a focus on technologies to better meet customer needs.

“We feel our focus on customer engagement is what has driven our success with our smart grid program, and that this same focus will drive our success with integrating energy efficiency and demand response,” said Craig Johnston, vice president of strategy and marketing for Oklahoma Gas & Electric (OGE) Corp. “In addition, the technology platform put in place to enable demand response can be leveraged to increase the effectiveness of energy efficiency programs.”

Like SMUD, OGE is still in the initial phases of integration, assessing the best way to make the merger.

Austin Energy, Duke Energy, Otter Tail Power, Xcel Energy, the New York State Energy Research and Development Authority and all of Texas’s electric utilities have also initiated the process by marketing energy efficiency and demand response together in an effort to focus on broad objectives that resonate with customers— saving energy and money, and helping the environment.

Several of these utilities have also started to use the term ‘energy efficiency’ to describe the full breadth of their demand-side management programs.

California’s Energy Action Plan II, for instance, jointly issued by the California Energy Commission and the California Public Utilities Commission (CPUC), supports SMUD’s emphasis on integration, listing the combination of demand response and energy efficiency programs among its “key required actions.” And in 2007, the CPUC directed California’s three investor-owned utilities to include integration in a comprehensive, statewide long-term energy efficiency plan. Since 2007, the three utilities have proposed a number of pilot programs that would test the efficacy of integration.

Long-term cohesive vision Historically, SMUD’s funding for energy efficiency programs has been tied to concrete goals for reducing demand, while demand response has only been included as an emergency reliability resource. The utility now has “planned targets for the amount of demand response we want to see over the next few years, so we can start to figure out where we need it, what it costs, and from that, how much it is worth spending,” said Olberg.

From there, he said, energy efficiency and demand response can be combined into a “cohesive plan for a longterm vision.”

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

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» CIS/MDM

systems, and VEE capabilities are crucial to ensuring a utility’s business and regulatory process needs are met.

Meter data management shows promise

Key drivers VEE, perhaps not surprisingly, was also cited by half of Perdue’s research respondents as the most prevalent business driver for MDMS selection.

Analysis of AMI information for operational applications was cited as the least important of five posSierra Energy Group research sible business drivers, falling just beprovides intriguing results hind another less important business

By Kate Rowland driver, the orchestration of two-way AMI processes.

SMART METERS ARE DELIVERING A TIDAL WAVE OF INFORMAThat’s not to say that AMI/MDMS tion to utilities. Accessing, analyzing and managing the information processes aren’t important to utility flowing in, and providing the necessary information to customers, is proving to respondents, however. According to be a daunting task for old-world customer information systems (CIS).

Perdue, “A high-priority area for many With new meter data management systems (MDMS) being put into place, AMI implementations is real-time the onus is on a utility’s CIS to enable intelligent use of the new data being support to outage management. The collected. But are electric utilities seeing the the MDMS/CIS connection as basic process is simple. The MDMS mission-critical yet?

Late last year, Sierra Energy vice president Christopher Perdue set out to receives and processes as many lastdetermine what was most important to utilities employing new MDMS, includ- gasp statuses from individual meters ing business drivers that influence MDMS selection, the value realized from as possible and supports verifying restoration to individual currently deployed systems, the operational areas meters prior to closing of the utilities that will require integration with Utilities want the MDMS the outage.” the MDMS and the benefits of that integration, Perdue’s research and more. In late January, he published the results to filter known service also found that utiliof his research. ties want the MDMS orders to reduce false to filter known service Mission-critical aspects orders to reduce false “MDM systems are not only critical to the success positives and to filter positives and to filter of a utility’s demand response programs, they now serve as a data repository and integration point momentary outages. momentary outages. for a number of other mission-critical utility As well, he said, utiliapplications such as distribution management, ties want the MDMS outage management, customer information and service, business intelligence to be able to throttle last-gasp and, of course, billing,” Perdue said. messages so that processing the events “According to survey respondents, the three most critical aspects of a meter does not impact OMS performance, data management system are: validation, estimation and editing functionality; while still tracking all messages for collection system integration; and interval data management,” Perdue said. asset history.

“It is interesting to note that while validation, estimation and editing func“The collection of meter data tionality was the most critical aspect of MDM, it was still only cited as being enables new and better business proone of the three most critical aspects by 37.1 percent of respondents. This sug- cesses that cut across departments and gests that, while important, no one aspect remains the most critical across organizational boundaries,” Perdue all utilities. Each utility seems to come with a unique perspective on what is said. “Implementing MDM is as much critical in an MDM.” about business process re-engineering It’s not surprising that validation, estimation and editing (VEE) functional- as it is about technology. However, ity was ranked as mission-critical: VEE is a process that identifies problematic integrating the MDM remains a chaldata coming from meter data collection systems before it reaches other utility lenge at most utilities.”

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» CIS/MDM

Perdue feels that outage management system (OMS) integration will ment and continuing to improve remain a high-priority area for many AMI implementers. “The MDM with time, with some also indicating obtains and processes as many last-gasp statuses from individual meters as they would await further development possible and supports validating restoration to individual meters prior to before considering implementation. closing the outage, but subtleties can improve an AMI system’s capability to “Further,” Perdue said, “there support outage management,” he said. “Utilities need seems to be disthe MDMS to filter known service orders to lower false agreement (among Implementing MDM positives and to filter brief outages. Utilities also need utilities that have the MDMS to throttle last-gasp messages so that pronot yet implemented is as much about cessing the events does not impact performance of the MDMS) as to what an MDMS should OMS.” business process provide. The responLooking to the future dents were nearly re-engineering as it Utilities that have implemented MDMS are already equally divided as looking to future uses for it. “Respondents were asked to whether analytics is about technology. about their future plans for their MDM system. The and other support majority indicated that they will definitely use the functions for AMI MDM to support smart meter operations,” Perdue said. The acceptance of belong in an MDM system.” more data (such as types, frequencies, meters, etc.) was the second most These are but a few of the high points of definitive area, with just under half indicating definitive plans to use their the Sierra Energy Group’s MDMS research.

MDM in this capacity.

More information about the research, But it’s not an MDMS sweep across the utility board. and about the report, can be found at Utilities that haven’t yet implemented MDMS indicated some skepticism http://www.sierraenergygroup.net/reports_ about system benefits, noting their feeling that MDM systems are still in develop- detail.cfm?rrid=103357

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”

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Transmission’s at the epicenter ++Key renewables questions not yet answered W WW.INTELLIGENTUTILIT Y.COM /// MAY/JU N E 2011

By Bill Opalka

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SHOULD RENEWABLE ENERGY BE DEVELOPED LOCALLY,

regardless of cost or efficiency, or should it come from where it is created most efficiently, with expensive transmission lines built to move the energy?

Will the policies that expedite transmission development and determine who pays for it be clarified?

I recently discussed these questions with Dave Raskin, a Washington, D.C.based partner and head of the Electric Power Practice at Steptoe & Johnson, who is immersed in Federal Energy Regulatory Commission (FERC) policy.

His key clients include the Tres Amigas project in New Mexico, which is seeking to link the three transmission interconnections in the United States, and Northeast Utilities, which is in a partnership to build a line in New Hampshire to connect Quebec to New England.

Is electricity local, regional or national?

“There are two things that have been around a while and haven’t been resolved,” Raskin said. “The first: Is electricity a local business or is it a regional or national business? Seems to me we haven’t made up our minds yet which one it is.”

He cited the still-evolving rules around open access to transmission that has been a policy question since the regional transmission operator model was created in the late 1990s.

Raskin said people in the industry seem to change their minds on this question fairly regularly.

“The second issue is to what extent are we going to rely on renewables?

We have 30-plus states with renewable portfolio standards, so do they really believe in them, and even when they believe in them, are they going to

support transmission to move renewable (energy) from one part of the country to another, or do they really hope to create jobs locally, just to get renewable built within their own states, even if they’re not efficient?” he wondered.

Transmission vs. RPS mandates These questions have not been addressed sufficiently, but the answers will have to be determined fairly soon. Although many states’ mandates have been attained while the requirements have been fairly small, other At some point states have requirements for 10 percent or more of electricity sales to come from we’re going to renewable sources within a few years. And that doesn’t even consider what happens have a national if a national mandate is ever enacted.

“At some point the country is going to conversation have to move in one direction or another on this. If we’re going to have a 20 percent before we hit or 15 percent RPS nationally, we’re going to have to build a lot of transmission, a wall. there’s just no way around it,” Raskin added. “At some point we’re going to have a national conversation before we hit a wall. Nuclear is off the table and coal is not going to get built.”

So if a transmission build-out is the answer, how does that occur?

There are no any easy answers there, either, Raskin noted.

“

”

Bill Opalka is editor-in-chief of RenewablesBiz Daily. This article first appeared there.

Submit your paper now to: http://mc.manuscriptcentral.com/pes-ieee

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

Overwhelming issues As discussed recently, FERC has embarked on a rulemaking proceeding with the emphasis on regional planning.

“That’s controversial because, for the first time, FERC is talking about regional and interregional planning in parts of the country that have not done that previously,” Raskin said. “I think it’s going to be difficult to get the rules in place and actually put (them) into effect.

“The second aspect is cost allocation. That’s a very difficult issue because there’s no right answer.”

How broadly costs are spread has been tackled regionally, but the concept has been under attack in the U.S. Senate.

The third issue is siting, with federal “back-stop authority” under the Energy Policy Act of 2005 coming under attack in the courts.

More explicit legislation from Congress may be necessary, an idea that has not gained much currency.

“Hopefully, at some point, Congress will realize that by not expanding the authority that FERC already has, they’re creating a situation that is inefficient,” Raskin said.

Not yet, so far. But it seems that Raskin’s questions about sourcing renewables have to be answered first.

Get the Recognition You Deserve

35

END OF THE LINE

Keeping down with the Joneses ++Xcel Energy turns energy savings into a neighborhood affair

By Mike Breslin IN 1597, FRANCIS BACON COINED THE TERM “KNOWLEDGE IS

power” in the ethereal philosophical sense. Today, however, knowledge about power, in the practical customer sense, is at work in a pioneering pilot program at Xcel Energy in Minnesota.

Called the Energy Feedback Program, it goes beyond the traditional realm of mailing or advertising energy-saving tips to the utility customer. Rather, it is attempting to personally engage each household through an interactive process aimed at reducing electric and gas consumption. The program is based on a concept of enhanced customer communication combined with behavioral modification techniques through a neighborly competition: Keeping down with the Joneses in terms of energy usage.

Measuring results Launched in late 2009, this intriguing three-year pilot has been operational for 17 months and is beginning to show results. Nate Huso, energy efficiency product developer at Xcel Energy, explained: “After six months, we ran our first analytics, which is a multi-varied regression analysis with a fixed effect, and looked at the differences between the participants and the control group. We were able to show a 1.8 percent savings for electric usage and a 0.7 percent savings for gas.”

Getting beyond the technical jargon, Xcel Energy employed sophisticated analytics to randomly By helping our profile and target 50,000 customers use combination gas and electric energy more customers in its Minnesota efficiently, it also service area.

That represents increases their approximately 10 percent of satisfaction with the 485,000 combination our service. customers.

Customer data was extracted from county property and census records. “One of the selection criteria for the participants is we had to have at least 18 months of usage history,” said Huso.

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W WW.INTELLIGENTUTILIT Y.COM /// MAY/JU N E 2011

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Detailed home-by-home energy-usage analysis Xcel Energy launched the program by mailing each customer a Home Energy Report that ranked the household’s energy consumption for the previous month with 100 neighbors with similar-sized homes served with electric and gas. Each report showed a detailed analysis of the individual home’s monthly energy usage compared with similar households within the same geographic location, both by the most efficient neighbors

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END OF THE LINE and by all neighbors. As well, it recommended specific efficiency based on household characteristics.

Interactivity was encouraged by referring the participants to a program Web portal (www.eXcel Energyenergy.com/energyreport). There, the customer could register by e-mail address and password to view their reports electronically and delve into all things energy-savings related.

The Web site features six pages with 92 advice items to save energy. Many are linked to details of Xcel Energy’s discount and rebate programs such as Saver’s Switch, a program in which Minnesota customers can save 15 percent on their electric energy charges during four summer months by allowing the utility to remotely cycle their air conditioners off 10 minutes at a time on peak days.

Participants get the discount whether or not the utility turns off their units.

Customers can also click on whichever energy-saving steps they have taken, or plan to take. Each step has an estimated savings amount as well as a tally of how many customers have implemented that step, with neighbor comparisons again boosting competitiveness. “They can also set goals through the online system, for instance, to use 5 percent or less energy,” Huso said.

“

E-delivery and e-communication next “From the original mailing of 50,000, about 35,000 continue to receive the printed report six to seven times a year. Of that, we are testing 15,000 trying to establish methods for e-delivery of the report and establish an electronic group We were able to show so we can communicate through e-mail.

So far only a small percentage of particia 1.8 percent savings pants have set up accounts on the Web portal. I would say approximately five to for electric usage seven percent,” he added.

Xcel Energy first began investigating and a 0.7 percent various in-home devices, communications, behavioral and customer feedback programs savings for gas. geared toward energy conservation back in 2005. An investor-owned company, Xcel Energy serves 3.4 million electricity and 1.9 million natural gas customers in eight Western and Midwestern states.

So shaving a percent or two (and hopefully more) off consumption through customer efficiency was a major enterprise goal.

W WW.INTELLIGENTUTILIT Y.COM /// MAY/JU N E 2011

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Myriad motivations “We had several motivations,” Huso said. “Our regulators expect us to implement conservation programs. We want to make sure we implemented a costeffective program so our ratepayers and stockholders are not disadvantaged.

“Another motivation is simply avoiding the need to build more power plants.

Over the past 20 years, with the help of businesses and residents, Xcel Energy has avoided building 12 medium-sized power plants in our eight-state service territory. By helping our customers use energy more efficiently, it also increases their satisfaction with our service.”

The Energy Feedback Program chosen by the utility was the only one identified with the capability of quantifying actual savings, and was rigorous enough for acceptance by its regulators.

“After 15 months the savings have been holding pretty steady, close to expectations, about two percent on electric and one percent on gas,” Huso said. At pub-

lication time, the utility’s last report covered through November 30, 2010, with another report due out in April that would cover December through March. “We’ll be able to see if the things we did last fall on the natural gas side have been effective,” he said.

Early results are positive Xcel Energy is considering a Phase II expansion of the program. Field research is currently being conducted on the program’s first-year performance. Thus far, experience has shown two major indicators for savings. First, customers who use a lot of energy generally have more opportunity to save, and save a higher percentage. Second, customers who engage with a Web account, review their home energy reports, follow energy-saving advice and join the rebate programs save more energy than those who do not.

“We’ll know a lot more in the next six months to a year. We are setting up pilots in our other jurisdictions and looking at how it can be more effectively rolled out,” Huso said.

It is one thing to preach to people about energy efficiency, but entirely another to get customers personally involved, motivated and connected to better tools to manage efficiency.

Programs like Xcel Energy’s are bound to be part of brighter energy future.

Mike Breslin is a journalist and author living in New Jersey.

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END OF THE LINE

Smart grid as economic development ++Kansas City highlights customer engagement

By Christopher Perdue KANSAS CITY POWER & LIGHT HAS PURSUED AN INNOVATIVE

W WW.INTELLIGENTUTILIT Y.COM /// MAY/JU N E 2011

approach to grid modernization: make it part of urban revitalization by engaging disadvantaged customers.

The utility, based in Kansas City, Missouri, has targeted a “Green Impact Zone” in a blighted part of the city and is performing aggressive outreach as it installs 14,000 smart meters in homes and businesses, which will also receive new rate options, energy use displays and educational materials.

This Midwestern, investor-owned utility’s approach confirmed that early stakeholder involvement and face-to-face engagement may be crucial to success.

Kansas City Power & Light (KCP&L) also offered other lessons learned in a presentation at the 2011 American Gas Association/Edison Electric Institute (AGA/EEI) Customer Service Conference and Exhibition earlier this spring.

Gail Allen, senior manager of strategic initiatives at KCP&L, discussed the utility’s smart grid demonstration project.

40

Location-based plan to transform neighborhood KCP&L’s smart grid approach, obviously, is different. First, it focuses on applying smart grid technologies to help disadvantaged customers in an area of the city now targeted as a “Green Impact Zone.” The zone is a comprehensive, location-based plan to invest public and private funding to transform a neighborhood plagued by high rates of poverty and violence, unemployment and abandoned property.

Second, the project is broad and being rolled out at a brisk pace. It includes advanced renewable generation, storage resources, distribution system automation, in-home customer systems and digital technologies, and innovative rate structures. The programs will benefit about 14,000 commercial and residential consumers, while providing the critical energy infrastructure required to support the urban revitalization efforts of the zone.

Aggressive outreach goals KCP&L set an aggressive goal to touch base with the customer 10 times before the day a meter is installed. It used outbound call campaigns, letters and e-mails to help achieve this, combined with energy fairs and outreach partnership with the Mid American Regional Council. In the future, it plans on using block parties, segmentation marketing and social media.

The day the meter is installed, customers are offered an in-home display and access to an energy management portal. Participating customers received welcome kits with a reusable bag, welcome card, DVD, a compact fluorescent light bulb,

a collateral booklet, a reprint of the introduction letter, a public workshop schedule, a pen, a magnet and information on the computer access sites—all hand-delivered by local “ambassadors.”

By the beginning of April, the utility had 397 customers using the energy management portal, 765 customers using the in-home display and 100 customers signed up for smart thermostats. KCP&L is now focusing on customer education and the usage and adoption of the energy management tools to improve adoption rates.

One of the challenges: Internet access in the Green Impact Zone is only around 40 percent.

Learning lessons along the way Allen recommends that utilities ensure their technology partners are aligned with the utility’s vision and that data-tracking tools are able to keep pace with incoming information.

Allen touted the utility’s dedicated smart grid support staff, and said KCP&L found a need for nontraditional support tasks, such as marketing and customer outreach.

Other lessons learned by the utility included: ??

Utilize grassroots outreach efforts

??

Talk to customers early

??

Have community stakeholders engage up front

??

Constantly look for opportunities to engage customers face-to-face

??

Manage a technology-focused project from a customerfocused viewpoint

??

Overcome the “apathy gap”

??

Scale the knowledge gleaned from pilot projects for the broader service territory

Christopher Perdue is vice president of Sierra Energy Group, a division of Energy Central. This article originally appeared in Intelligent Utility Daily.

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The devil’s in the data details

both AMI and/or other meter data; and ??

(PMU) monitoring, data logging and analysis, shared among neighboring regional trans-

++Utility data depth and breadth

mission organizations (RTOs) and utilities.

will continue to increase

Enabling data exchange Utilities are faced with key strategic decisions with regard to the infraTHE SMART GRID IS A SYSTEM-OF-SYSTEMS PROBLEM BOTH structure they construct to underlie deep and wide, demanding solutions across power distribution and the data exchange. power storage, computing and—with implementation of data in and data Though the applications are out everywhere throughout the electrical-delivery system—data management unlikely to be bandwidth-hungry at and control. levels approaching, say, large-file tranBillions and billions of data points will be processed instantaneously in the fer or streaming video, utilities nonenext-generation smart grid, rendering the management and control of that data theless will be handling more data an overwhelming proposition. Among the primary drivers of new data volume generated by more sources at more for utilities will be plug-and-play devices across home area networks (HANs) frequent intervals than ever before. that link into the smart grid via advanced metering infrastructure (AMI) So, in constructing a sufficient smart gateways, as well as new distributed-generation power sources. grid communications infrastructure, Optimization, simplification, manipulation and coordination in management utilities will have to satisfy basic and control and the ability to efficiently understand, process, interpret and take performance requireaction on data will grow critical as smart ments such as bandgrid rollout intensifies worldwide.

Billions and billions of data width and latency parameters.

Data, data everywhere points will be processed Beyond that, data Utilities already manage petabytes of security will be a operational data—both real-time and instantaneously in the nextprime area of conarchival, both static and dynamic—but cern. Security conthe breadth of data that will have to be generation smart grid. siderations include accounted for in the gathering smart grid ensuring the confiis unprecedented. dentiality, integrity This fact has been illustrated in the and availability of sensistive data; work of the IEEE P2030 Working Group, launched in March 2009. As part of its mitigating risk with regard to the effort to bring together commmunications, information technology (IT) and value of information and assets; power engineers in defining the smart grid’s functional elements and needs, and identifying threats and vulnerIEEE P2030 has worked to inventory requirements in terms of interoperability abilities. Cybersecurity will not be interfaces and interconnections among data exchanges, computer-network sea one-time solution for a utility to curity and integration with existing and future systems and applications. As the identify, purchase and deploy at a smart grid rolls out globally, utilities will be sharing more data across: single point in time. ?? customer portals into energy usage; Data reliability will also be a high?? demand-management applications that pair usage and pricing profile issue, given that an area of the data in order to incentivize customer-initiated load control; grid potentially could be shut down ?? distributed energy resources, including storage technology at if operational data is inaccurate or customer sites; compromised, and that power is fun?? damental to everything we do. outage-management systems that communicate among customers, The stakes are very high. utility workforce and partner distribution entities;

By Dick DeBlasio

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W WW.INTELLIGENTUTILIT Y.COM /// MAY/JU N E 2011

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phasor measurement unit

Managing data for maximum benefit In addition, there are questions for the utility to answer in terms of what to do with the array of data made newly available by the smart grid.

Meter data management, for example, introduces new storage, operational and analysis requirements. The utility will be gathering more data from head-end servers to be stored, validated, synchronized and edited, and therefore, data storage and processing footprints must be accommodated. Then, there’s the task of extrapolating useful business intelligence from event records. Back-office applications will be needed to glean meaning from data and fuel utility-asset and customer-relationship management.

Not only could effective handling of smart grid data enable powerful new business capabilities such as moni-

toring for service theft, anticipating high demand and leveraging distributedgeneration sources in wide scale, it also could transform whole competitive strategies. Utilities have tended to not share their data relative to utilization of the grid (how many kilowatt hours they sold, the reach of their customers vs. local customers, etc.). But, depending upon how regulatory decisions play out with regard to ownership, privacy and security of data, distributed-generation operators, for example, might be better positioned to market their resources.

With utilities consumed with strategic questions about how the smart grid will be implemented market to market around the world, the global standards community is simultaneously at work on ensuring that the integrated power, communications and IT elements work together seamlessly.

The IEEE P2030’s “Draft Guide for Smart Grid Interoperability of Energy Technology and Information Technology Operation With the Electric Power System (EPS), and End-Use Applications and Loads,” for example, was released for sponsor balloting within IEEE in March 2011. The IEEE P2030 guide will seek to establish a consistent definition of the elements and functional requirements associated with two-way communications and control across the grid.

Gaps demanding additional standards work are sure to present themselves as the smart grid rolls out over the next decades. The smart grid’s unprecedented volume of data and dependence on it figure to form one of the primary sources of ongoing development.

Dick DeBlasio is chair of the IEEE P2030 Working Group, a member of the IEEE Standards Association Board of Governors and chief engineer with the National Renewable Energy Laboratory.

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CONNECTIONS

Micro is mighty ++Why two grids can be better than one

By Elizabeth McGowan

W WW.INTELLIGENTUTILIT Y.COM /// MAY/JU N E 2011

DON’T LET THE DIMINUTIVE NAME FOOL YOU. A MICROGRID

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might sound like a tiny achievement. But designing an affordable, reliable integrated power system that can seamlessly isolate from the nation’s power grid during a blackout or sag—and then reconnect just as smoothly— is no small feat.

And, as is the case with any brainy and brawny idea, the microgrid concept didn’t materialize overnight.

Congress, jittery about the reliability of national electricity transmission, turned to the U.S. Department of Energy (DOE) for guidance in the late 1990s.

What started as a conversation about maximizing distributed generation to relieve stress on an overtaxed grid has evolved into on-the-ground applications.

Proponents envision limitless industrial and commercial applications.

“We like to say we bring good ideas to life,” DOE senior program manager Steve Waslo said about the government’s key role in guiding technologies such as microgrids from the laboratory to the marketplace. “Our philosophy is that when a technology such as the microgrid is ready for prime time, you need to get

it out there and test it. That’s part of the value added by the Department of Energy.”

Deployments beginning After years of tinkering, toiling and thorough research, DOE has recently started deploying microgrid technology in school districts, universities, jails, hospitals, laboratories, military bases, industrial parks and a variety of businesses nationwide.

For instance, one California utility will begin testing what it calls a full-fledged microgrid at its corporate headquarters this spring. The Sacramento Municipal Utility District (SMUD), a longtime pioneer with advanced technologies, will be operating a 310-kilowatt baseload microgrid.

It couples three 100-kilowatt (kW) reciprocating generators with a 120ton chiller combined heat and power system and a 10 kW photovoltaic system. The project will also integrate

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CONNECTIONS storage technology in the form of a 500kW zinc bromine flow battery. SMUD’s system is based on DOE and California Energy Commission (CEC) research and development on microgrid control technologies.

W WW.INTELLIGENTUTILIT Y.COM /// MAY/JU N E 2011

Not just any microgrid Those initial meetings at the DOE led to the 1999 creation of a microgrid research and development team. Funding for this R&D effort, called the Consortium for Electric Reliability Technology Solutions (CERTS), came from DOE’s Office of Electricity Delivery and Energy Reliability and the CEC’s Public Interest Energy Research program.

The consortium drew on a list of nationwide specialists, including researchers from DOE’s national laboratories and industry, and was led by Bob Lasseter, a professor of electrical engineering at the University of Wisconsin-Madison with a penchant and passion for thinking outside the box.

“We started from very modest origins and have made major contributions to the definition of the microgrid landscape,” explained Joe Eto, a staff scientist with the DOE’s Lawrence Berkeley Laboratory in California. “The idea was to articulate the basic concepts and then develop and put in the public domain the tools required to advance them.”

Early on, these researchers coined the term “microgrid” to describe their project. Just because they had named the idea, however, didn’t mean they owned it. Soon, other power system specialists were engineering their own versions of microgrids. Understandably, that prompted the consortium to christen its own unique invention as the CERTS Microgrid.

“We’re not claiming to have the only way to organize or control a microgrid,” Eto emphasized. “It’s the idea of system integration—treating load and generation as a single, distributed system that can operate both connected and as a stand-alone electrical island—that’s the umbrella under which all of this fits.”

46

Letting shareholders kick the tires Taking any new technology from idea to fruition can be a dicey venture. That’s why DOE has an overarching strategy that emphasizes teamwork. The strategy is strong on open communication, effective partnerships and common goals.

“The Department of Energy creates strategic teams of technology owners, universities and labs really well,” said Waslo, who has more than two decades of experience with the department. “Our strategy is to encourage buy-in, give all stakeholders a voice and focus on problem solving.”

With the CERTS microgrid, Waslo said, utilities and other businesses needed to be at the table so they could explain how and why the research needed to be tailored to meet their specific needs. “Those stakeholders have a crystal-clear understanding of their businesses so they can optimize the technology,” he said.

“That makes for a more efficient use of resources.”

DOE’s strategy can keep research projects moving forward when they encounter inevitable hardships, such as technical or sponsorship issues or projects that

just have too much risk for the private sector to tackle alone. “But the government can bring resources to bear,” Waslo said. “We can keep worthwhile projects alive that might not have thrived otherwise.”

Microgrid pioneer advances technology Traditionally, connecting multiple sources of distributed generation to the grid is complicated, expensive and laborious. Not only do utilities require that each connection be separate and meet particular standards, but all distributed generation also has to be automatically shut down if the grid’s voltage wavers.

How could the CERTS team overcome these obstacles? Enter microgrid pioneer Bob Lasseter. The University of Wisconsin at Madison professor took the lead in engineering a solution that allows all of the distributed generation to connect to the grid at a single point and to operate 24/7.

First, all distributed generation and local load are tied together on its own feeder using unique interface controls so it presents to the main grid what Lasseter calls a single, well-behaved energy system. In addition, newly developed automatic switching technology lets the intra-connected distributed generation and load disconnect from and reconnect to the grid without a hitch. This feature allows the microgrid to provide high levels of quality power to local loads.

“Our goal is for this to be plug and play,” Lasseter said. “That way, you plug it in and it works, without a control system on top of it.”

These advances let the researchers move from an economy of scale to an economy of numbers, Lasseter said, because it allows microgrid users to buy dozens of smaller machines instead of a single large one.

It could also eliminate an industry’s need to invest in backup generators or batteries.

“I do this because I see it as exciting,” Lasseter said about his 11 years of CERTS involvement. “The way it’s structured, I get to handle the technical part and think about the subjects I enjoy. That’s what keeps me engaged.”

ties in the country and one with a long history of path-breaking R&D success, such as the deployment of the nation’s first 765-kV transmision lines. Once AEP expressed interest, the CEC and DOE stepped forward with funding. The investor-owned utility ran the initial round of field tests at its John E. Dolan Engineering Laboratories in Groveport, Ohio, from 2006 to 2007. The original CERTS Microgrid Test Bed featured utility inverters and engines manufactured by a company that specializes in small natural-gas-powered generators.

Passing the ultimate test To gain acceptance by What’s next? the appropriately con“We came up with the grain of the idea,” Lasseter We can keep worthservative electric utility said about nurturing the CERTS Microgrid beindustry, Eto and the rest yond the incubator stage. “Coming through that while projects alive of the CERTS team recstruggle, we’ve watched it grow to be implemented ognized that microgrid and commercialized. And today, we are seeing it that might not have technologies could only almost reach a tipping point.” be proven through demOther possibilities the team will be tracking thrived otherwise. onstration at a full-scale include easing the integration of direct connected test bed and that the synchronous generation, wind, solar and other most rigorous evaluations would be renewables and giving utilities the opportunity to meet peak needs with offthose conducted by an electric utility’s peak storage. testing staff.

Elizabeth McGowan, a subcontractor for the U.S. Department of Energy’s Office of Electricity CERTS was fortunate to find such a Delivery and Energy Reliability, writes about a full range of energy and environment issues research partner in American Electric from Washington, D.C. This article is excerpted from a larger feature, which can be found in full at http://www.oe.energy.gov/DocumentsandMedia/CERTS_Article_May2011.pdf.

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OUT THE DOOR

Power storage advances from unexpected sources ++Renewable energy storage kicked into high gear

By James Cahalin WHAT DO YOU THINK HAS A GREATER IMPACT ON SOCIETY, A

Bugatti Veyron Super Sport or a Tesla Roadster? Both have spectacular performance reviews, with the Super Sport setting top speed records. Both will turn heads driving down any road or even through any parking lot in the world.

Both are truly engineering marvels.

However, the engineering accomplishments behind both vehicles will be dwarfed by the advances Tesla has made with its power storage devices. Let’s take a look at a few numbers for both vehicles (see table).

These numbers are astonishing. As a “car guy,” the opportunity to drive either of these vehicles would be amazing. However, as an energy professional, these numbers are even more astonishing.

W WW.INTELLIGENTUTILIT Y.COM /// MAY/JU N E 2011

PRICE

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BUGATTI VEYRON SUPER SPORT

TESLA ROADSTER S

$2,975,000

$110,000

FUEL CAPACITY/ 26.4 Gallons RANGE

240 miles per complete charge

ENGINE

16 cylinder, 4 turbo 1200 horsepower 4,486 lbs.

Full electric motor 288 horsepower 2,723 lbs.

PERFORMANCE

0–60 mph: 2.6 seconds 1/4 Mile: 9.87 seconds Top Speed: 267 mph

0 – 60 mph: 3.7 seconds 1/4 Mile: 12.6 seconds Top Speed: 125 mph (electronically limited)

Amazing heat output The Bugatti Veyron Super Sport was designed and built for one purpose—to set a new speed record. It is also what I like to refer to as a “straight-line car.” What I mean by that is simple: Even with that much horsepower and amazing technological advances, there are cars (and some cost under $100,000) that can beat the Super Sport around a road track.

But the most amazing statistic about the Veyron SS is its heat output. We have had the technology to turn heat into energy for a long time. This vehicle requires 10 radiators; your car only has one. Some experts say that driving this car the length of time it takes to go through one full tank of gas produces enough heat to power 10 homes for a year! The engineers at Volkswagen have truly created an amazing accomplishment and a flat-out ridiculous automobile, and I greatly applaud their accomplishments.

Storage cell range astounding From the beginning, Tesla’s vehicles have been groundbreaking. In the past few years, the company has racked up even more amazing accomplishments.

It shaved two full seconds off its 0-to60 time on the roadster. The range on its storage cells has greatly increased.

In fact, a fully charged Roadster S can go about six times farther than the Veyron, assuming the Veyron is running at top speed. That is theoretical, of course, because there are only a few roads on the planet where the Veyron can travel at top speed for that long (it takes the vehicle 12 minutes to burn through a tank of gas at top speed).

This year’s model of the Roadster can get about 240 miles per charge.

The 2012 Model S Sedan will get 300 miles per charge, showing just how quickly this technology is advancing. (For those of you wondering about recharging, the car uses the same outlet as mostly everything else in your house and, if hooked up to the same voltage your refrigerator is plugged into, it can fully recharge in four hours.)

I recently asked Tesla a few questions about its storage devices.

To date, the company has no plans to adapt its batteries to other industries, but is actively sharing the technology with other automobile manufacturers.

Tesla isn’t able to say how quickly these storage devices are going to advance and become more efficient, but all signs point to an incredibly rapid advancement.

Energy industry connections Relating this to the energy industry is pretty simple. President Obama’s direction for energy independence is calling for 25 percent of our national power to be renewable power by 2025.

Renewable power is bountiful in our country; harnessing it and connecting it to the grid is the challenge. Storing it is also another challenge. This is where Tesla’s advancements fit in.

How would you like to not have an electric bill each month? Better yet, how would you like to receive a check each month from your utility? I live in Denver, Colo., where we experience more than 300 days of sun each year.

Wind power is also very accessible here due to our geographic terrain.

I have many neighbors with The astronauts solar panels on their roofs and aboard Apollo 13 the sun is out long enough survived for days to power their homes for the on less power than majority of the peak hours.

I use in my office Now, if we look toward the fuin one hour. ture and picture a single or a few small storage cells in your garage or basement with solar panels on your roof, your home can be 100 percent self-powered.

“

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Portable power The astronauts aboard Apollo 13 survived for days on less power than I use

in my office in one hour. Imagine if they had one of these advanced storage cells.

Hospitals utilize uninterrupted power supplies for good reason, but their power supplies are inefficient and don’t last very long. Imagine if they all had advanced storage cells. Last summer I saw portable solar panels designed to use for camping. Imagine if they designed a storage cell that could power a campsite for days.

How about portable wind turbines with storage cells used to power a water purification system in Africa? The ability to have continuous portable power that doesn’t require fuel has an unlimited number of potential uses, all of which can make the world, and potentially even other planets, a better place to live.

Societal impact To answer my initial question, Tesla will have a much greater impact on society because of its storage cells. The advancements in these storage cells have the potential to reach across numerous industries.

Although the Bugatti Veyron SS is a real engineering accomplishment, it is just a car.

Records were meant to be broken and I’m sure that Michael Hennessey, Jerod Shelby and Dusty Dronet will be beating the Veyron SS’s record in a very short time period.

Tesla isn’t gunning for production car land speed records. It is not designing vehicles for a single purpose. Instead, the company is designing a line of completely electric-powered high-end automobiles. However, its impact on society will be greater than any other automobile manufacturer and, in my opinion, will surpass what Henry Ford did for the world.

James Cahalin is an employment services account manager for Energy Central.

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