Recap of AMI & Smart Grid Call Seminar: A Conversation with Keith McAlister

IREC’s latest telephone seminar on “How Will Smart Grid and AMI Impact Solar”, held on August 21, 2008, drew its largest crowd yet. “We had more than 200 people on this call, the most since IREC started offering telephone seminars in 2003,” said Larry Sherwood.” According to Sherwood, this topic was chosen because of the feedback received from Solar ABC stakeholders.

For this seminar, Dan James of Xcel Energy discussed how a smart grid works, opportunities for solar, and the smart grid pilot Xcel is implementing in Boulder, Colorado.

Keith McAllister of the N.C. Solar Center at N.C. State University, an IREC partner and wicked smart, discussed Advanced Metering Infrastructure (AMI) and how to adapt net metering policies to the AMI technology.

While he made (and ate) lunch, I grabbed Keith for a more detailed, less technical explanation of AMI and Smart Grid technologies. Here’s our conversation:

IREC: So Keith, Dan gave this definition of Smart Grid at the seminar as “…an intelligent auto-balancing, self-monitoring power grid that accepts any source of fuel, transforms that into a consumer’s end use with minimal human intervention.” If you could break this down and help me understand why Smart Grid and AMI are considered transformational technologies. I get the feeling that they would radically alter current utility practices.

KM: That’s absolutely correct. I like Dan’s definition of Smart Grid. But let me explain why this is such a big deal.

What we have today are a number of central station plants where distributed generation (DG) plays a small role in supplying power needs of the country. The transmission grid is a highly monitored, controlled system that interfaces with the outside world. These systems are monitored and controlled for a reliable source for power.

Contrast this to a utility’s distribution system. In most cases, the utility has very little knowledge of the conditions on its distribution system once past the substation.

Let’s say a squirrel gets cozy with a transformer. Maybe a fuse blows, and a sectionalizer operates. The customer will have a momentary outage but the utility will know about it only when the customer calls and complains. Some of the more advanced utilities (i.e., Progress Energy, which happens to be one of the leaders in distributed automation), have systems that will capture those kinds of events at the substation level, figure out which feeder it was, and tell their line person where to go and what to look for. But the bottom line is that many utilities won’t know what happened unless a customer calls.

Now let’s talk about AMI.

Here you’ve got a two-way communication between customer and utility. So with AMI, the house meter says, “hey, I’m out of power,” and then communicates back to the utility to let them know. With AMI, the capability is there for events at customer sites to be logged and communicated back to the utility so they know what happened and how widespread it was. Smart Grid takes it a step further. The system includes intelligent software and other devices that can automatically “heal” the grid so that outages or other power quality events are minimized.

This is just one example, but there are many more technical benefits of Smart Grid.

IREC: So is AMI a transitional technology to Smart Grid?

KMc: I’m not sure that’s absolutely the case. You could certainly go straight to a smart grid model from the conventional 50s, 60s, 70s utility technologies. But you could also take pieces of Smart Grid technology and make a less sophisticated system. Automatic Meter Reading (or AMR) is one example. A solid state meter with limited communications ability replaces the old 1950’s style electromechanical meter. Instead of someone coming to your house to read the meter, a utility meter reader just has to drive by. AMI also has solid-state meters but adds a data management system, a really strong communications platform and an operating system software package. Interestingly, this technology was coming of age in the mid-to late 90’s, thanks to the Internet revolution and the PC world.

IREC: Just this Spring, Austin Energy switched out my old meter to a new digital one. I was so excited. You’d have thought I just received a new PV sytstem. So how does a utility decide to go with AMI or smart grid technology?

KMc: To switch to AMI or smart grid, a utility would make the case for it to its public utility commission. If the PUC approves it, or the legislature mandates it, then it’s implemented system-wide; it’s not on a customer-by-customer basis.

IREC: is it easy to go to a smart grid once AMI is in place?

KMc: It depends on the features of the existing AMI system. Think about it in terms of when you buy a computer. You build it with a certain amount memory and RAM, DVD or CD player, external keyboard, 20” monitor…whatever. Newer PC’s now have built in video capability on the motherboard. It works great for most applications, but if you decide later that you want to play high-end games or do high-end video graphics it might not be adequate. AMI is like that.

The meters, software, and communications systems themselves have different capabilities that control different functions. To think that just because a utility installs a digital meter it’s now an easy transition to Smart Grid or AMI, it’s not necessarily the case, but neither does it have to be a difficult transition either. The real issue is how much planning and forethought went into the choice of the particular AMI system.

I’ll use Progress Energy as an example again.

Progress Energy made the decision that AMR would be beneficial to their customers and shareholders. The utility commissions in the states they served agreed. They switched out their customer’s meter with ones that could be read by driving by. To minimize cost, they chose a meter that did not have the capability of reading which direction the power was flowing. At the time, there wasn’t a lot of DG on their system, nor was there a net metering tariff in place in any of the states they served. They made a sound financial decision for their customers and their shareholders, which is good, but in terms of DG, if I’m generating PV power, the meter wouldn’t be able to distinguish that it was my power. With this arrangement I’d actually be charged for the electricity I generated with my array. Fortunately, those meters can be upgraded.

If you didn’t have net metering in place, you’re not thinking of a bi-directional flow of power. This is clearly a case of planning; the utility and the commission did a good job of looking at the facts in front of them but failed to consider what would happen if DG became more prevalent.

But its not just meters. Smart grid also has the architecture—the software and communications systems–to actually make decisions as events happen; it can also predict events before they happen, and make the changes on the distribution system to reduce the impact on the fewest number of customers.

IREC: This is all sounding pretty sophisticated but enormously amazing.

KMc: It is. Smart grid does this all automatically, so on the reliability side, it makes a huge difference. On the power quality side, there are all sorts of reasons why there’s power loss, all kinds of issues that can be relatively difficult to figure out, and as I said before, most utilities won’t know they’re running into problems until their customers call them. A Smart Grid, on the other hand, has the potential to know instantly what went awry and to do something about it.

IREC: I’m beginning to see how elegant this can be. So besides Boulder, which is Xcel’s pilot project, who else is buying into smart grid, and how are they working?

KMc: Well, in Dan’s presentation, Xcel announced in May that the design phase of its Smart Grid plan for Boulder was complete and construction was underway for the system’s control and operations center. Phase 2, which begins this month (September 2008) and runs through December 2009, will offer Internet access for all customers and begin the initial integration of plug-in vehicles and solar and/or wind distributed generators.

A grassroots group in Illinois, the Illinois Smart Grid Initiative, has support from Chicago Mayor Richard J. Daley and other community leaders. The Illinois effort, funded by the Bob Galvin Electricity Initiative, came about because citizens felt that electricity prices were too high and utilities should be cutting costs through strategies like smart grid technologies.

IREC: Any others?

KMc: In May, Duke Energy Indiana recently filed a petition with the Indiana Utility Regulatory Commission to use smart grid technology, advanced metering infrastructure (AMI), and time-of-use pricing to its 780,000 customers in Indiana. Duke intends to eventually deploy the smart grid across its five-state territory.

Also in May, Portland General Electric got the green light from the Oregon Public Utility Commission to use AMI across its territory. The meters will be installed over a two-year period, costing $130-$135 million, while generating some $18 million in annual operational savings, beginning in 2011.

IREC: So some utilities, big ones like Xcel, must recognize the business impact for them, for their consumers and for the technologies.

KMc: Yes, all of those. Utilities see smart grid as a way to better manage their loads, aka DSM. There are cost savings with the AMR capabilities, reduced billing errors, and a better capability to detect fraud. And as I said before with Smart Grid technologies, reliability and power quality will improve because the utility will know that there’s a glitch somewhere.

IREC: DSM’s not new, but this sounds like a totally improved, 21st Century version.

KMc: There are a lot of ways to do DSM, a lot of different programs, like TOU rates, were developed in the 70’s and 80’s to do just that. One of customers’ biggest complaints was that the time of use (TOU) rates were difficult to manage; they forgot about Daylight Savings Time or a timer on an appliance had the wrong setting; next thing they knew they got hit with a ratchet charge. AMI’s two-way communication capability can take away the headaches of trying to manage these programs.

Let’s take a more advanced scenario.

A typical DSM program in the past reduced loads by controlling customer’s AC units. The utility would typically send out a signal that would cut off your air conditioner during peak load conditions that also generally corresponded with the hottest days of the year! A lot of customers got upset with that kind of program.

But what if instead of cutting off the AC, the utility went to 50 thousand customers and raised the thermostat set point by three degrees for a short period of time. After the clock expired for those customers, their thermostats would return to their original settings and another group would have theirs raised so that everyone was contributing, sharing the increase of that slight temperature change. Imagine what a huge impact that would have on the system while really having a small impact on the individual customer. AMI and smart grids can do this.

IREC: Same thing for water heaters and electric dryers? Ask the customers not to use these during peak times?

KMc: With these smart appliances that are being developed under DOE programs, the utility can interact with the customer and say, “hey, don’t call your serviceman; we’re switching off your dryer or water heater between the hours of 4-7 p.m”. The customer could override this command, at a cost of higher electricity charges or lost savings; a perfect example where the customer has a choice to participate and become involved. It’s the same with green power sources.

Some utilities are talking about programs that let the customer choose her rate structure. She may want to be on a flat rate, TOU or even RTP or may want to support renewable technologies. The customer would actually be able to tell the utility, “I’m willing to pay a little more/kWh to be assured that my power comes from solar, wind, or some other DG source,” so for the first time, the customer becomes involved in the generation dispatching decision making of the utilities.

IREC: This sounds quite radical, empowering even. What do the utilities think about this?

KMc: Some like it; some don’t. Xcel was the one who wanted smart grid technologies. From a utility side, using smart grid strategies in their tariff programs, they’ll see significant ability to shift peak loads. Most of the opponents of Smart Grid (utilities and others) find excuses that AMI or Smart Grid technologies are too expensive to implement, or they’re too complicated, it’s really that they don’t understand the leap in technology that these strategies represent.

IREC: Maybe opponents argue that these capabilities already exist. I mean, utilities already collect billing information, they’ve got digital meters in place or they have TOU rates. Why can’t they use what they already have without spending more money?

KMc: Certainly the capability exists if they want to spend big bucks to mine the data and implement software that can analyze that data and communicate it to other groups within the utility, like system planners or system operators. But even then it won’t be in real time and it won’t have the capability to communicate with customers.

IREC: Because?

KMc: Because the current technology and communications systems weren’t designed that way. Billing software doesn’t communicate with other systems and there’s entirely too much data for people to deal with. Utilities are still reading meters, even digital ones. Who wants month-old data if you’re trying to operate an electric utility system? With AMI and smart grid technologies, the data retrieval can be almost instantaneous. It makes an enormous difference for utilities in how they manage their systems.

IREC: You’d think they’d be all over this, especially when large utilities like Xcel take it on. How does this affect vendors and distributors of DG?

KMc: This blows the doors off. Over the past few years, there have been many articles in power industry trade journals discussing the tremendous impact that DG can have on the grid’s power quality and reliability, especially for those utilities that own DG. One day, that capability will become available to the small DG owner like you and me. This will allow the small DG owner to sell the power quality benefits of DG along with the kWh and RECs.

One other thing.

Now that we have the capability of two-way communication with these technologies, if we set up policies correctly so that we maintain customer privacy while having that information available, we can have better information for equipment designers, and from a business perspective, this opens the door for aggregators to play. Let’s say I’ve got a 5kW system, and I’m interested in selling my RECs. Aggregators aren’t really excited about buying this small amount of RECs, but if my 5kW is aggregated with, say, 2000 other 5kW systems, it becomes a more attractive deal. AMI and smart meters can make that happen so much easier, as long as utilities don’t have complete control of that data.

IREC: This sounds like a big battle brewing. Data is so highly prized.

KMc: I’m not so sure. Currently, there are some utilities with third-party data management, under certain conditions. Think about the Health Insurance Portability and Accountability Act (HIPPA). The standards are meant to improve the efficiency and effectiveness of the nation’s health care system by encouraging the widespread use of electronic data interchange in the US health care system.

IREC: I asked earlier about early adopters of AMI and smart grid. If a biggie like Xcel is the poster child for this, won’t others follow?

KMc: Well, it’ll probably follow the typical technology-acceptance curve where there are early adopters, then those who see the technology works and they sign on, then the major adopters who jump in when they see the financial benefits, and finally, there are the last adopters. There’s lots of inertia with this group. Remember, utilities are a culture that says, “we’ve been successful this way so far, our shareholders are looking for reliable profits, and our consumers are looking for consistency and reliability; we really don’t need to change our format.” Unfortunately, this is somewhat naive; it doesn’t take in the realities of how we need and use power.

IREC: Inertia…not an inconsequential challenge. Are you optimistic about the potential for the technology to advance quickly beyond where it is now?

KMc: Without a doubt. I’ve been around this industry for a long time, and what’s curious to me is how people fail to recognize how much disruptive technology causes such dramatic change. Think about it: some 15 years ago, it was a rare thing to see a PC on a desk. Now, that PC is the size of a credit card. It’s stunning to think about how much this disruptive technology has changed all of our lives, and how we continue to demand more innovation. AMI and Smart Grid technologies have the same capability to change the way we live our lives. Whether it was the automobile or the PC, enormous change is around the corner.

IREC: Maybe it’s because people, bureaucracies, are inherently afraid of change.

KMc: Perhaps. But think about it from the consumer’s perspective. New technologies bring with them tons of innovations and features we’ve not even begun to imagine. This has the potential to change everything. As long as the consumer gains the benefit of these innovations without having negative impacts on their lifestyles, there will be a demand.

IREC: This sounds like it will have a dramatic effect on the electric utility industry.

KMc: Unquestionably, and I haven’t even begun to talk about the technical advances happening with the distribution equipment yet.

IREC: Sounds like the perfect topic for the follow-up article to this one. You interested in Part 2?

KMc: Sure. There’s a lot going on these days. It remains interesting.

IREC: Thanks, Keith, for the English major translation of a highly technical issue. See you in San Diego in October.

If you missed this telephone seminar, you can download the audio file for your MP3 player.

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