It’s a mid-summer evening and you’re just arriving home from work. You pull into your driveway, get out of your car and plug it in. You take a second to wipe the sweat from your brow. It’s hot out.
Inside, the first thing you notice is a blinking light on your in-home display. The grid has recognized that your car, which has been charging all day from the solar panels on the roof of your company’s garage, has a nearly full battery. Demand is high and your utility is offering to purchase that electricity for a premium price. You’re not going out that night, so you touch the screen to authorize the transaction. You note that your account is instantly credited.
You take a minute to scroll through the rest of your appliances. Your dishwasher ran at 4 a.m., when power was cheapest. After you went to work, the hot-water heater cycled off, just as you programmed it. At noon, as demand rose, the grid turned your thermostat up a few degrees per your price plan. It’s warm in the house, but not uncomfortably so. Still, you have dinner guests that evening, so you click to override. It might cost a few bucks extra, but the power you just sold from your car will offset the expense.
This scenario could become a reality in the not-too-distant future. In fact, most of the technology required already exists. Just how far we are from actual implementation, however, is another question.
The face of tomorrow’s utility might be the in-home display—a robust interface that provides real-time cost and consumption data, allowing consumers to maximize efficiency and make informed decisions on conservation. In-home displays also will allow retail utilities a much broader field for competition on price and products, and will open the gate for an entirely new generation of wireless-controlled appliances and controls.
This technology promises benefits for all stakeholders in the industry, but disincentives to innovation inherent in utility business models and the U.S. regulatory patchwork are making for slow progress.
“The analogy for the way things are today is the car without a fuel gauge,” says Ahmad Faruqui, a principal at consulting firm The Brattle Group. “Imagine going to the gas station and not knowing how much gas you’re putting in the tank, or how much it costs. Then at the end of the month you get a bill that says you pumped 100 gallons of gas and you owe $500. That’s where we are with electricity. There is no connection, no feedback between behavior and cost.”
With demand on the rise and sustainability concerns driving public policy, the need for that connection is obvious. What’s less apparent is who will fund the infrastructure upgrades needed to close the loop. Advanced-metering technology is the lynchpin of any meaningful consumer interface. But at about $300 a pop, hundreds of millions of smart meters represent a massive investment.
“Who pays for that? Is it the customers? Is it the utilities? Is there a regulatory mandate? These questions have no easy answers,” Faruqui explains. “There are no federal regulations, and manufacturers are confused because of the different markets around the country. Technology is expensive because the economies of scale have not kicked in, and they won’t kick in unless an industry standard emerges. It’s a catch-22.”
But just as with high-definition TV, another technology that took longer than expected to reach the affordability tipping point, consumers are keenly interested in the features offered by in-home displays.
“We’re in an interesting time in the market,” says Barb Ryan, a senior research manager at consulting firm Energy Insights, who focuses her research on customer opinions and desires. “Household budgets are stressed and prices are going up. I don’t think a lot customers are aware of in-home displays yet, but when they are presented with the idea, large percentages are interested.”
According to Ryan’s research, when the technology is explained to them, 70 percent of consumers have a high level of interest in advanced displays, and 20 percent more have a moderate level of interest. The more information the device provides, the better. Consumers are most interested in real-time cost displays and programmable thermostats. And they want the information on the wall, not on the web.
“Customers are not at all excited about going online to see their energy use,” Ryan explains. “The big thing people really want, although it isn’t available yet, is having their use display segregated by appliances.”
A recent Energy Insights study shows that even the most rudimentary in-home displays lead to conservation rates of 4 percent to 14 percent. Other studies show high rates of customer satisfaction with in-home displays.
“When consumers have the choice, they like it,” says Chris King, chief strategy officer at meter data management vendor eMeter. “You constantly see satisfaction rates of 80 to 90 percent for people who have participated in pilot programs. The other measure that’s been studied is how many customers will sign up voluntarily. You get response rates of 30 to 50 percent.”
Still, most utilities are loath to take the plunge, at least quickly. About half the cost of installing smart meters is offset by operational efficiencies, such as remote meter reading, advanced diagnostics and exact outage mapping. But in some jurisdictions, other returns—like efficiency gains from demand response—don’t feed back to the utility. The result for most utilities is a lot of prognostication and pilot programs, but not much meaningful action.
“Once the will appears, both political and regulatory, it won’t take long,” Faruqui asserts. “You don’t have to dig up roads to do this. Once you reach the tipping point, it becomes inevitable. In two or three years the cost drops dramatically and everybody gets one. But some sort of market consensus has to occur. Someone has to step up.”
No place in North America may be farther along in this process than Ontario, where the government has mandated that the entire province be converted to smart meters by the end of 2010.
“We started with a pilot back in 2005 and are now moving into full implementation,” says Rick Stevens, director of the smart metering initiative at Hydro One, the largest of Ontario’s 90 distribution utilities. The company already has 500,000 smart meters up and running, and is on pace to have all its 1.2 million customers converted by 2010.
“We have a long-range supply plan in Ontario,” Stevens says. “We have an aging nuclear plant, and coal facilities that our government has chosen to take off line. We’re looking at a total investment in the area of $70 billion over the next 20 years. We could build more generation, or we could try to balance supply and demand by creating a culture of conservation. Smart meters are one element of that, because it provides price transparency to customers.”
Although Hydro One’s smart meters have the ability to interface with in-home displays via a ZigBee wireless connection, the company is probably a couple of years away from implementing the technology on a wide scale. It’s currently testing in-home displays in just 25 homes, and plans a larger 1,000-home pilot within a year.
The company, however, has demonstrated the conservation impact of real-time displays.
Hydro One installed 30,000 displays—it calls them “power cost monitors”—in 2005. The monitors are connected wirelessly to the older analog meters and feature LCD displays that show real-time cost and use information. They also have a light strip that strobes faster as consumption increases. The strip changes color according to peak rates: green when power is cheap, yellow in the mid range and red at peak cost.
“It gives the customers information so they can make the direct connection: red and fast is bad, green and slow is good,” Stevens explains. “It’s basically an electricity speedometer.”
The tool has proven effective. The displays, combined with time-of-use rates, have resulted in a 6 percent to 7 percent conservation rate. But as a government-owned utility, the company’s smart metering is driven by conservation policy, not competition, so the move to in-home displays likely will wait until the entire province has been converted to smart meters and time-of-use rates.
A couple thousand miles to the southwest, the Salt River Project (SRP) also is constrained in its development, albeit for totally different reasons. Despite moderate attempts, meaningful deregulation has not taken off in Arizona, so direct competition is not a driver for utilities there. Efficiency is the main imperative behind SRP’s smart-meter program.
Since 2005, the company has upgraded 300,000 meters, and plans to have all its 935,000 customers on smart meters within 5 years. The transition already is paying off.
“Last year we avoided 169,000 field trips,” says Jennifer Collins, a customer service analyst at SRP. “We saved about 56,000 labor hours, prevented about 339,000 miles driven and conserved about 33,000 gallons of fuel.”
With no need to compete on products, SRP has no current plans to offer a robust in-home display. Interested time-of-use customers are limited to checking usage patterns online. The company does, however, have a modest type of-real-time display; it operates the largest prepaid metering program in North America.
Prevalent in Europe and Australia, prepaid meters are most commonly associated with low-income customers in North America. Customers buy up to a $500 electricity credit on a card at one of 72 centers around Phoenix, take the card home and swipe it in a meter that displays cost and usage.
The fully elective program, which started in the 1990s, is on its third generation of meters. SRP currently has 54,000 prepaid customers.
“We’re finding on average these customers save about 12 percent a year, so they are conserving,” Collins relates. “They see how much they are spending each day, how much they have left, and based on their last seven days of usage, it calculates how many days energy they have remaining.”
That’s half the battle—providing the connection between behavior and cost. But basic prepaid meters don’t offer the advanced efficiencies possible via a home-area-network (HAN) enabled meter.
Texas is the deregulation frontier in America today, so if competition-driven advances happen anywhere, Texas will be first, right? Well, not exactly. Because of the way the Texas market is segmented, the benefits of advanced meters don’t accrue to the companies whose duty it is to install them.
Consider the predicament of CenterPoint Energy. A wires company, CenterPoint is taking a cautious approach to its rollout of HAN-enabled smart meters. The state’s scores of energy retailers, meanwhile, are champing at the bit. The meters will allow them almost unlimited creativity in the products, prices and demand-response options they can offer customers, and presumably will increase their profits.
Texas regulators are pushing hard for smart meters, too, but wires companies are struggling to figure out the economics. Distribution companies’ profits are regulated, so their smart-meter costs must be covered by operational efficiencies, or via approved rate changes. Without certainty about how the market will evolve, CenterPoint wants to test the waters gradually. It has proposed a phased rollout that would deploy 250,000 smart meters starting in September 2009.
“We just want to make sure everybody’s sure. We don’t want to look back and ask, ‘why did we spend all that money?’” says Don Cortez, CenterPoint’s vice president of regulated operations technology.
Texas retail utilities are so eager that they have offered to advance the cost of the first 125,000 meters just to get the ball rolling. That proposal is awaiting regulatory approval.
So if not Texas, where?
“Once again California will be the crucible,” Faruqui says. “Other states like New York, Florida, Texas, Wisconsin and Illinois are all looking at California.”
In fact, Southern California Edison is poised to roll out a fully HAN-enabled meter in January, with demand response coming online a year later. California is a partially deregulated state, but SCE is still vertically integrated from generation to its bundled customer base, so it has better prospects for return on investment. The company expects an almost perfect cost offset.
“Roughly 60 percent of the benefits will come from operational savings, including labor,” explains Paul De Martini, SCE vice president. “About 10 percent comes from energy conservation as a result of the information feedback. The remaining 30 percent of the benefits are from demand response, both through the communicating thermostat load-control program and new dynamic pricing options.” Those are the direct benefits. SCE also expects an additional $295 million in what it calls societal benefits—things like meter accuracy and theft reduction.
The company originally intended to start the rollout in 2010, but found that the vendor community responded to its needs faster than expected. SCE now expects total conversion by 2012, a year ahead of schedule.
“We’ve turned the corner,” De Martini says. “The system architecture has coalesced. Standards around the home area network are fast coalescing. Security hasn’t gelled yet, but we expect it within the next 12 months. A lot of progress has been made. We’re working on the finer points now.”