Smart grids: The executive view


By Jonathan Spencer Jones

Over the past year, since the announcement by United States President Barack Obama of the smart grid as a development objective, with support from stimulus funding, utility executives have been devoting considerable time and resources to thinking about and developing plans for their utilities. Right on the cutting edge, with technology and key determinants such as regulations and standards also evolving, this has inevitably given rise to numerous questions and concerns, and in order to investigate some of these an Executive Forum was convened at Metering, Billing/MDM America in San Diego in March.

Participants were George Chen, AMI Project Manager, Los Angeles Department of Water and Power; Erik Krause, Smart Meters Project Manager, Sacramento Municipal Utility District; Lee Krevat, Director Smart Grid, San Diego Gas & Electric; Stephen Nees, Technology Strategy and Planning Manager, City of Anaheim; Larry Oliva, Director of Tariffs and Programs, Southern California Edison; Dan Partridge, Chief Engineer for Smart Grid, Pacific Gas & Electric; Ted Reguly, Smart Meter Program Director, San Diego Gas & Electric; Glenn Steiger, General Manager, City of Glendale; John Xu, Project Leader Systems Delivery, Toronto Hydro Corporation.

How do you define the smart grid?

Krevat: The baseline definition is applying information technology or digital technology, i.e. communication, to the electric system. One should tack onto the end to get some sort of benefit as opposed to just for the heck of it.

A number of companies refer to smart meters as smart grid and there’s perhaps some confusion there?

Partridge: “Smart” is being overused as a word and is losing a bit of its usefulness. Smart meters are not in themselves smart grid, but are certainly a building block for it.
Reguly: Certain utilities feel that smart meters aren’t the best investment for a smart grid. It depends on where someone can get the benefit. It might be distribution automation, it might be workforce automation.
Krevat: We have two paths to the smart grid at SDG&E. One path is the cost benefit analysis, in general the better the NPV the higher we can prioritise it. The other path is the reliability of the grid – with solar on rooftops, some circuits are over 20% distributed generation and we are starting to see voltage problems, so we have to do something. It’s not a business case on cost savings but it is our business as we have to maintain a reliable grid.
Oliva: I agree that some utilities view other things, such as substation automation, as more important than metering. But there’s no question in my mind that getting hourly information from all the end-points of use has got to be useful in informing you on energy in the grid and its management. Metering is a component but a very critical one.
Nees: From our perspective as a small distribution company the smart grid has been about doing substation automation and distribution automation. We see a smarter grid as extending that rollout to additional areas, such as transformer monitoring. Smart metering is an add-on for example, for load aggregation and diversion detection.
Steiger: The way we look at smart grid is a transition from where this utility business has been to where it’s going. It hasn’t changed much in the last 80 to 100 years. We’re making a significant transition and I think we’re playing catch-up to where we need to be today to meet the technological needs, with computers, handhelds etc., the rest of society already has in place.

Normally with investments of this scale one would expect to have to put together a business case, but in this case the technology is being driven by other factors, and so where do you see your utility leveraging value?

Reguly: There’s a lot of hype and a lot of money being put into the smart grid, but going forward you’ve got to have a business case. We need to look at our smart grid investment as any other traditional investment, and shouldn’t just do it because it’s smart grid. If not, we’re being irresponsible in investing our shareholders’ money.
Nees: The approach we’ve taken is that smart grid is ranked with other capital projects. If we know we need to build a new substation because there’s going to be growth in a particular area that takes priority over some of the smart grid investments. Part of the reason we haven’t committed to a very rapid deployment of advanced metering is that we’re trying to balance that with the other needs of the business.
Chen: If you look at the rates and the differential between the peak and the base, then the pricing gives an incentive to do these kinds of projects. And the AMI and the new systems, the transformers, capacitors, switches, are all contributing some kind of intelligence as well as efficiency improvements, and all this helps on the business case.
Krevat: We got funding to do a project that internally we’re calling Gridcom, which will put a wireless communication “cloud” over San Diego. We have a lot of communication already, systems that were put in 10, 20, 30 years ago, but many of those have hit end of life. The cost to replace those systems and to put in Gridcom is about the same, but Gridcom will also bring benefits in the smart grid area.
Steiger: In our case DOE wanted to see what we were going to do in terms of leveraging smart grid for the reduction of greenhouse gases, those types of things, and what we can do for the customer. The tough part for us in the utility industry is that for everything we do the business case is based on how much we’re going to save. But we are building a system that now integrates directly with customers and effectively will interface with a private industry that is based on profit. At some point as we move ahead, the business cases have got to start looking at what we are going to make, not only what we are going to save.
Partridge: We’ve experienced situations with half a dozen solar panels on the same transformer and each one outdoes the other in terms of its voltage setting to try to drive power back into the system, and at the end of the month one customer finds out their overvoltage tripped them off and they’ve had no benefit from the solar panel and all their neighbours had zero bills. Is that my problem, and is the PUC going to let me spend money to do voltage regulation to benefit that customer’s solar panel issue? I don’t know…

How are your utilities responding to the stimulus grant conditions and requirements?

Steiger: We did our homework and gave the DOE what they were looking for and we didn’t find it to be overly burdensome. Given the fact that we’ve got $20 million handed to us, and we were able to do this in the course of six months, it wasn’t bad at all. The criteria that DOE put out are reasonable. If they’re going to give us $20 million, we should be expected to meet certain criteria and be extremely transparent. But we do have to do all the things that we’ve agreed to do, and assuming that occurs, we will get reimbursed.
Krevat: I’d say, so far, so good from our perspective.
Nees: Echoing that, the other nice thing is that the expenditures we’ve made on the project since October 23rd, which was the announcement date, we get to count. We’ve spent nearly $1 million, we asked for $6 million and we got that, and that’s one sixth of our match already.
Krause: We’re certainly excited about it. We’re used to working with the DOE and California Energy Commission and having to prepare and maintain documentation and metrics, and we prepared to provide almost all of what they are asking for already. We’re looking forward to working with our partners to test out new technology and to get a better idea of how the technology can benefit our operations and our customers.
Chen: The money has given us another dimension as in the past, we haven’t had the opportunity to work with the research schools and institutions, but now we have scientists coming to help us, which we are very happy with.
Oliva: When we did our application, we factored in the fact that we knew we would need to do a lot more documentation and a lot more tracking and metrics and so forth, and we hired a grants administrator and folks to focus on this. This is a key thing that has made it easier for us, and we built it in as part of the plan.

What are the benefits of various smart grid applications, e.g. islanding, interruptables, intermittent supply, microgrid controllers, intelligent switching?

Xu: All of them give benefits. We have a big budget for our smart grid initiative, including load monitoring, e-line monitoring and smart metering. Smart grid is big in Ontario at present.
Krevat: We have a condition-based maintenance project where we are putting sensors on our 111 major substations. This got funded because the payback on the capital is very quick and also there are benefits from the reliability perspective. Recently, we had a planned replacement of a large piece of capital that we monitor for the end of summer, but data came back that made us think that it was going to fail and we scheduled an outage at night and replaced it, avoiding a potentially very large outage. Now we are not going to replace an item because it is 30 years old and one like it failed. Instead, we have confidence that we can go longer as we’re monitoring.


There’s been a fair bit of customer resistance to smart meters and complaints of high bills, and what should utilities be doing to minimise or avoid these problems?

Partridge: There are issues that are legitimately tied to smart meters. For example we had a number of customers who were worried about RF exposure, and then there are dogs that get out of the yard when you open the gate, but these are things one can manage. The situation we experienced in Bakersfield doesn’t have the same cause and effect and the things that are making people unhappy are around rates and how reliable their power is, and so are harder to work around. I think most of the Californian utilities are now talking of trying to avoid installing in the hottest months of summer.
Reguly: We need to do a better job communicating with our customers. If a customer’s bill goes up soon after a smart meter is installed the customer assumes the meter is the problem. We had an issue with a customer who had a stuck meter for ten months and when we put in a smart meter, the bill went from $5 to $20 a month and the customer was saying the meter is not calibrated properly. They didn’t see that for months they had zero consumption while their lights were on. The other thing we are learning is not to install a smart meter without giving the customer something, even a simple thing like telling them that in the past they had to wait 60 days to get their bill but now they can figure out what tier they are in right away.
Nees: We are very careful to take good care of customers. In our rollout of smart meters we sent letters to customers exactly two weeks in advance of when we would be coming to their homes, then the night before we put a door hanger on their door. If the person wasn’t there we leave another hangar saying we’d changed the meter. There is also a survey card and out of the approximately 4,000 meters we’ve changed, we had about three complaints. Also because of the issue with high bills, we test every meter we pull.
Krause: One of the best things we did was to get the highest level marketing communications person we could and put him on the core team. He’s been in every meeting and discussion and is really in tune with what’s going on. We also have a pre-installation customer letter, which has been one of the best tools for us, and anything we see pop up in the press, we add to the letter. When we started hearing of high bills complaints we added to the letter that our rates had recently gone up and could increase the bill. This way, we can be proactive and respond to customer concerns early – sometimes even before the customers call us.
Partridge: A couple more comments from experience. One is to do some retraining of your customer service reps right before deployment to make sure they are at the top of their game. The other is that I’ve talked to a number of customers on the more technical issues, but usually at the end of the conversation I find there’s something else that they’re upset about – in one case the rep didn’t knock on the door, in another we were building a 500 kV line through the guy’s barn.
Oliva: We’ve tried to do as much as we could for the customer, including some of the things mentioned, such as letters, door hangers, etc. The only thing I would add is that we started our deployment intentionally slow, so that we could get experience to perfect procedures and processes with our installation vendor and to gauge customer complaints and actions so that we could make some corrections if we went wrong. That seems to have worked very well.

Do you understand how the smart meter is being accepted by customers and are customers responding to the opportunities that smart metering represents?

Oliva: The problem is that a lot of the functionality in the smart meter is not yet available. We don’t have a home area network available yet because we don’t have a standard – Smart Energy 2.0 is there but is not yet ratified.
Reguly: We aren’t going to time differentiated rates until almost the end of our deployment, and we probably won’t be able to offer HAN devices until a year after that, so I’m almost going to be done with my rollout and touched all my customers and all I’m going to be able to show them is a digital meter on the side of the house. That’s why I think getting them simple useful things today is beneficial.
Nees: The complexity we add is that we’re not just a single service utility. In terms of providing information it is difficult because electricity is one of six or seven services on the bill and then if we give them some online or some little display that says “Your electricity usage to date is this much,” they will be calling customer services going, “How come my bill was $70, not $16?”
Krause: Something that we’ve been doing since before we started deploying meters is to get involved with community engagement. We have employees who are ambassadors for SMUD, who talk to customers in off-hours. We’ve completed some thirty odd presentations to Rotary, Lions, homeowners associations etc., on what we’re doing and why and it’s proved really helpful to answer the questions before you install smart meters in a particular neighbourhood. Of course you get the concerns and the negatives too, and we wrap the feedback into our communications. The other piece is the customer satisfaction survey, which we do by phone.

So at this stage the only way you know how the smart meter is being accepted is if bills suddenly go up and you get complaints?

Xu: Yes. We have installed 600,000 meters and about two years ago we started billing customers from smart meter reads and last year we cut over to time-of-use billing. We have a website built so customers can go to there and see their consumption and a comparison of what their bills would look like under different tariffs. We now have over 250,000 customers who are receiving more than one bill and by next month it will be 500,000 customers, and all the feedback has been quite good. We’ve had very few questions or problems with the smart meters.
Oliva: Part of the stimulus funding is for the customer behaviour feedback and the response to what we’re doing with the smart grid. But it takes a lot of time and one needs to get the features up and running. We’re still manually reading our meters, so a problem is “Why are you here reading my meter? You just installed a smart meter but it’s not very smart if you still have to read it!”
Krevat: We’ve had under 800 complaints in 600,000 installs, which works out to about 0.13%. I’ve seen two videos on the news, one was a guy who loved his new smart meter and was telling the reporter all the great things you can do with it and the other was a complaint customer, and this gives the impression that half the people like it and half don’t but in reality this is only 0.13%.

Do you have a grasp on the organisational impacts of this technology – are you keeping your IT up to date, are you ready to use all the data, do you have strategies that are understood throughout the utility?

Nees: We put together a five-year smart grid roadmap and are using that as a communication tool so the rest of our departments understand what we’re doing and what the components are and how it’s all going to glue together. We spent probably 7 or 8 months preparing that document and we’ve shared it with the city council and city manager’s office – it’s not secret and we’re trying to get the word out.
Steiger: With us, it impacts pretty much every part of our utility and that includes our water division because we’re also doing automated water. What we’ve seen is the extent to which IT is involved and with us, IT is not only a GWP function, but also a city function, and the city has had to greatly expand its involvement and understanding. If I had to single out any area that has required additional funding over and above what we originally thought, it would be that.
Krevat: We had a programme, Opex 20/20, in which we upgraded and replaced a lot of our back office and operational systems, and before there was a lot of paperwork but now a lot of that is automated. You have to get close to IT because if they’re implementing with a common vision of where it’s going and they’re going to use service-oriented architecture, you’re going to think about how these things are related. If you have them taskmaster they’re going to build silos and you’re not going to be able to have those systems work together.
Reguly: From a smart meter perspective, each one of the utilities is just starting bringing back tons of data and we’re just starting to figure out what to do with it. There’s going to be a tremendous amount of value in that data, from sizing transformers to predicting outages to helping customers understand how they utilise their electricity, and that’s the next nut to crack. It’s going to take us a lot just to figure out what we can do with all the data and I think one’s going to see demands from areas of the company that one hasn’t even thought of.
Chen: We started in the rates with the load profile, then we started to deploy the smart meters in the field ten years ago, and now we are pushing more on the operations and customer service sides. They are all going to use more real-time data to analyse and to improve efficiency. At the end of the day, the technology is going to help us to reduce the manual work and help us know exactly what’s going on in the field.
Xu: We get very high demand from outside the smart meter group. Every day we have 15 million records coming and now for example the business intelligence groups want to pull on the database so they can connect to our GIS data, outage interval data, transformer data, etc.
Krause: We’re already using information to get efficiencies out of the system. With information technology being more advanced and the speed and amount of data that’s available, as mentioned we’re going to be able to get efficiencies from things we don’t even know yet. Some of the obvious things are planning the distribution system, what to replace and what not to replace and doing that efficiently.
Oliva: In the industrial society we just threw capital at building plant and building the system, but there’s only so much efficiency you can get out of a turbine. Now there are tremendous efficiencies to get out of information on how customers use their electricity and how we can incentivise them to use less energy at peak times.
Partridge: At PG&E we’re really just starting to learn what we can do with data. We’re also developing an IT architectural vision, as like other utilities we have huge legacy issues, and so one has to be willing to work on an incremental and evolving basis. Having that IT vision is critical and we could probably spend five years just making the data useful.