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Notes

The "advanced metering infrastructure" has less than a six percent overall market penetration in the US, and only five percent among commercial customers, according to the independent analyst firm Research Reports International.

Outside the US, smart meters are spreading rapidly. Among the main suppliers of smart meters in Europe is Echelon. In this interview I talk with Jeff Lund, a VP in the Networked Energy Services division at Echelon.

Longer than usual podcast this time. I'd like to hear your feedback.

Related article:

"Time of Use Electricity Billing: How Puget Sound Energy Reduced Peak Power Demands" case study of a short-lived deployment

Related EnergyBlog:

"Smart Meters: Jump in or Wait?" Smart Grid Newsletter 2006

Related audio:

"Energy Minute: Smart Meters" podcast

Also:

"FERC Assessment of Demand Response and Advanced Metering" staff report, August 2006"

"Start Selling AMI" Smart Grid Newsletter 2007

Transcript

Denis Du Bois, Energy Priorities: From the point of view of a commercial or industrial energy user, what would it mean to have a smart meter, and the advanced metering infrastructure behind it?

Jeff Lund, Echelon: Of course, it always comes down to the question of how smart is smart, and what is smart. I think if you look at what an energy meter has historically measured, it's a limited number of things. A smart meter is measuring more frequently, but it also lets you understand the quality of delivery to the customers.

Today utilities have no visibility into what’s happening at the other end of the wire. They don’t really know, at any given site or residence, what the power quality is and what the consumption pattern is. When they look at aggregating that across their customer base, it helps them understand how well their grid is running -- not just being able to charge you appropriately, but to keep the grid running well.

Denis: Echelon is best known here in the US for its building-automation technologies. Over in Europe, though, the utilities in Italy and Sweden have deployed Echelon smart meters nationwide -- or they're in the process of doing it. But you've just recently signed your first U.S. utility for smart meters?

"Today utilities have no visibility into what’s happening at the other end of the wire. They don’t really know, at any given site or residence, what the power quality is and what the consumption pattern is."
--Jeff Lund, Echelon NES.

Jeff Lund: Yes, we’re involved in a project with Duke Energy that they call their “Utility of the Future” project. They’re still in the early phases of validating their approach to the market.

I think what’s interesting about the approach that Duke is taking (which they’ve discussed in various conferences) is that they want to enable the smart grid.

When they look at what is connected to our grid, certainly meters are a very important part of that. There are a lot of meters that they manage, I think almost 3 to 4 million customers; but meters are only about a third of the assets on the grid, so there’s other stuff that needs to be networked as well.

The idea is that initially all the endpoints might be meters, but over time that’s going to change, and you’re going to have other things that are connected. You’re not putting in a meter network, but you’re putting in a utility network, and over time you’re going to be deploying not a single application but many different applications that consume that data.

If you think about that kind of world, your cost center is going to be related to cost of communications and integration. So you want to pick a platform that leverages standards for communication and integration -- in particular things like IP, free wide-area transport, and web services for IT integrations -- so you can drive cost out of the system.

Denis: With a utility like Duke calling this the “Utility of the Future” and just getting started with some, candidly, fairly narrow demonstration programs, more than a wide spread deployment, I might ask, What's taking so long? Is it the case that Europe is just really advanced; or is the U.S. lagging behind, and why?

"You’re not putting in a meter network, you’re putting in a utility network, and over time you’re going to be deploying not a single application, but many different applications that consume that data. "

Jeff Lund: I think there are just some structural differences between the U.S. and Europe that have caused European utilities to move first. Obviously the regulatory environment is different in Europe. The EU has been, in their energy policy, pushing for more transparency in the energy markets, so that there’s more freedom to switch between retailers, and there’s retail competition.

Distributors are still the natural monopoly, but they’re trying to break out. They have competition on the retail side, competition in generation, consumers have more visibility into not just how much energy they’re consuming, but when they’re consuming it. So you have a regulatory driver. You also have a lot of social pressure, I think, and political interest in global warming and carbon. Some of those things that are now becoming very topical in the U.S. have been big topics of concern in Europe for the last five years or more. I think that that led them to move first.

The same factors are starting to come into the U.S. Obviously we read a lot more about clean energy and global warming probably in the last six months than you did in the previous six years. I do think that’s coming here, but obviously the Europeans experienced it first.

Denis: Are utilities having trouble making the business case for smart meters for the cost of buying them and installing them? They’re, I presume, somewhat more expensive than a standard meter to begin with; then there’s all the infrastructure...

Jeff Lund: There’s a whole host of things that people consider. There’s obviously being able to better match supply and demand, which can keep them off the spot market in times of greatest need. You can actually defer, potentially, the construction of generation assets, which has an enormous payback if you’re willing to capture that in your business case. There's the idea of being able to have better visibility and control over the grid.

Actually one of the most difficult things for utilities is to sit down as a whole utility, not just as an individual function within the utility, and look at how these applications can cross functional groups. And then also to quantify things that in the past may have been unquantifiable because they were uncontrollable. It’s very difficult. In the past you would buy meter reading systems, and management systems, and customer care systems; these were vertical investments. Each one was very narrow in scope and might therefore have a limited applicability to the utility.

Whereas now, you’re able to put in a single system that can cross many different aspects of the utility. So it’s always a question of who pays for it, who signs up for the benefits associated with that, and how does the utility make sure that everybody is really looking at how the system can be applied to what they do. And it’s not that they necessarily don’t want to do this; they’ve never had to do it.

I think that’s one thing that Duke has done, for example, their Utility of the Future project is being led out of the office of their CTO. They’ve said, this takes a senior level person who can bring the whole business view to the problem, so that they can explore all the various aspects of the system.

Denis: You mentioned integration, which is something I’m curious about, because the smart meter is obviously not much use without the network and the back-end systems. For demand response and load control, it seems like there needs to be a fairly tight integration with the building systems on the other end of that wire. Is Duke working out how the smart meters will be integrated at both ends?

"One of the most difficult things for utilities is to sit down as a whole utility, not just as an individual function within the utility, and look at how these applications can cross functional groups."

Jeff Lund: I don’t know that they’ve discussed their plans on that. But I think there are really two ways to view what happens with load control and penetrating the wall and going into the facility, whether it’s an industrial plant or a consumer's home. There are two types of assets in the world: there are those that are owned and managed by the utility, and those that are owned and managed by the customer.

Historically it’s been the utility that wants to do load control, especially outside the U.S. where it’s more common. They might send the signal into your home or into your factory saying this load needs to turn off now. Then they’ll send in a corresponding signal when it can come back on. They’re literally reaching in and turning something on or off. That’s a very limited level of control. It’s on or it’s off. It’s not really under the control of the consumer; obviously it’s under the control the utility.

I think the next level of energy management is not directly under the control of the utility. It should be under the control of the end user. If, for example, utilities published rate information on the network, or across the grid, and that information could be received and acted upon by your customers, then their system should respond however they think is most appropriate.

I think how that information gets to a homeowner might be different than how it gets to a business. But I think in the end it has to get to both of them so that there's enough demand response across the grid.

For example, here in our building, we actually get a signal from our energy provider whenever there are different stages of alert, where they need load to be shed. Because our building is smart, we don’t have to have a human run around and turn off lights or change the operation of the system. The system itself can take that web service, through a product we have called i.LON 100 Internet Server, and then that information is published into the control network, and the control network takes action based on the severity of the energy event.

It may, for example, do simple things like dim lighting on surfaces where we’re getting ambient light coming in through the windows. But as the energy event becomes more severe, it may start doing things with the air handling system to let the rooms get gradually warmer, because of course air doesn’t instantaneously get hot. So you have some period of time where you can reduce air flow or turn off air flow, or let set points drift, where there’s no noticeable impact on the occupant, but there can be a substantial impact on energy reduction.

That’s what can happen in a commercial building. Now ones that aren’t smart may have humans that run around, or you have people like EnerNOC, which is one of our customers that provides also i.LON-based solution, that can go in and control some loads in response to energy signals.

Denis: I’ve actually been to your building and seen the demo of the system that responds to utility signals. Of course you make this stuff, so you have every conceivable device and system installed, and clear panels where you can see the stuff up in the ceiling. The possibilities are really very intriguing.

Jeff Lund: You know, it’s funny, while we have a fairly high level of automation for a U.S. building, I’d say we’re a moderately intelligent European building. A smart European building is generally smarter than the equivalent smart U.S. building. Not that they’ve got a bigger processor as the central controller, but there’s more intelligence in the building, it’s distributed deeper into the building. The more fine-grained the intelligence, the more degrees of control you have, the less impactful it can be on the end user and still have a lot of impact on the energy consumption total.

For example, if all you can do is control the circuit breakers of your lighting panel, which is what some U.S. buildings do, so it lets you switch off entire banks of lights, they can be on or off. But end users notice that, if suddenly an entire bank of lights switches off, and that could have a negative impact on the occupants.

On the other hand, if the control is more localized to either an individual light, or a small group of lights, and they can dim as well as go on and off, the impact might be much less or might not even be noticeable if there’s enough ambient light coming in. And the building is smart enough to dim such that the total illumination stays constant; so more of it’s coming in from the outside and less is being generated by the lights. That actually makes the user happier, because the light level stays constant but energy goes down.

I think that deeply embedded intelligence is much more common in Europe than it is here. Even here where we have moderate intelligence in our own building, we’re able to have a substantial reduction of energy.

Denis: The Energy Policy Act of 2005 -- well, maybe didn't light a fire under smart metering, but it shone a flashlight on it. The Federal Energy Regulatory Commission did a big report last year on advanced metering as a result of the requirement of EPAct05. Did that generate enough awareness to accelerate the adoption of smart meters here in the U.S.?

Jeff Lund: I think it certainly has generated a lot of awareness. I think that the challenge of course is, how advanced is advanced, how smart is smart? Those are terms that are obviously vague just by their nature, and there’s not an agreed-upon definition. You see a lot of things now where people look at even AMR deployments that were done 15 years ago, and on some slides those are now labeled as advanced metering deployments which, by most definitions, they’re not. You start to have this dilution of what that means, and what needs to be done differently, what benefits we’re trying to achieve, and how to go about achieving them.