What a difference a year makes. In 2004, automated metering infrastructure (AMI) was in something of a slump, but the Energy Policy Act of 2005, an uptick in natural disasters, and encouraging results from pilot projects have strengthened the business case for investing in AMI.
What a difference a year makes.
In 2004, the automated metering industry was in something of a slump. After the 2003 Northeast blackout, and facing rising gas prices and diminished investor confidence during a time of war, many utilities put automated meter reading (AMR) on the back burner.
Things changed in 2005.
First, Congress enacted the Energy Policy Act of 2005 (EPACT), and more specifically, Section 1252. The “smart metering” title compels utilities and public utility commissions (PUCs) to evaluate time-of-use metering. If savings can be found, regulators likely will demand them on behalf of ratepayers.
Second, Hurricane Katrina put the fear of nature into utilities and regulators—principally via skyrocketing natural-gas prices. Indeed, lawmakers in some states even are proposing rate freezes. One effect of this has been to put a premium on peak-shaving options—such as demand-response metering—as alternatives to burning costly natural gas in peak-load units.
Third, pilot projects to study the value of advanced metering infrastructure (AMI) have yielded encouraging results for many utilities. For example, at Salt River Project in Arizona, what began as a modest 500-meter test of Elster Electricity REX meters expanded in 2005 to 75,000 meters and counting. “Projected savings have exceeded our expectations,” says John Soethe, manager of revenue-cycle services for Salt River Project. “We like the fact we can not only do AMR, but automate the field-service function. Also we’re seeing the back-office benefits. We’re very pleased with the performance of our smart meters, and we expect to continue expanding the system.”
These and other factors have strengthened the business case for investing in AMI, and utilities and PUCs are coming out of the woodwork to investigate the options. “There has been a flurry of activity,” says Eric Dresselhuys, vice president with Silver Spring Networks in San Mateo, Calif. “EPACT jump-started the states, and awareness and interest nationally has increased at federal, state, and local levels.”
Nevertheless, much of the activity today is focused on gathering information rather than placing orders. How many states might adopt smart-metering regulations in the near term remains uncertain. Utilities and regulators likely will continue asking tough questions about the technology, as well as how to equitably finance investments whose benefits accrue to a mix of utility stakeholders.
AMI Business Case
EPACT Section 1252 takes a soft approach to mandating smart metering. At first glance, the legislation appears to require all U.S. electric utilities, by January 2007, to offer time-based rate schedules to all customer classes, along with the necessary meters and communications technology. But how to accomplish this—and indeed, whether to implement a smart-metering policy at all—are questions left to state utility commissions to answer for their jurisdictions.
EPACT does not prescribe any particular approach, but generally specifies that rate schedules should reflect variances in the utility’s costs for generating or buying wholesale power at different times of day. The law provides four examples of time-based pricing mechanisms to guide utilities and PUCs: time-of-use (TOU) rates for peak, intermediate, and off-peak periods; critical-peak pricing, with peak-shaving discounts for certain peak days; real-time pricing, in which rates track wholesale prices through the day; and credits and incentives for commercial and industrial customers to enter load-curtailment schemes.
Thus, in effect, Section 1252 doesn’t force smart metering on the states, it forces them to think about it—and establishes a date-certain (January 2007) by which that thinking must begin. The outcome of these thought processes will depend on a range of variables that differ from region to region. Some states and utilities undoubtedly will decide the potential of advanced metering is not worth the cost to their ratepayers.
“Some utilities are saying, ‘It’s not my issue,’” says Doug Houseman, a principal with Capgemini in Detroit. “Their ratepayers are happy. They still have low rates and surplus generation, so they can put something together at the end of the year” to satisfy EPACT.
As energy costs rise, however, and neighboring utilities begin reaping operational and strategic benefits from AMI, the technology might gain momentum even in states where the business case has been unclear. “Six months or a year ago, [the] Ohio PUC wasn’t exactly in the vanguard of demand-response and advanced metering,” Dresselhuys says. “Now the state has started proceedings, and is getting the predictable ‘ah-has’ that come with it.”
The “ah-has” come from a broad spectrum of benefits, not all of which are immediately obvious (see Figure 1, “Parsing AMI Benefits,” p. 58). Metering savings are relatively modest, for example, while collections savings can be tremendous. This is partly because remote disconnect and reconnect can occur without sending a truck, and it allows virtually instant-on response when a delinquent customer makes a payment. Additionally, a more continuous flow of metering data allows customized billing intervals that better suit some customers.
“People who struggle hardest to pay their utility bills get paid weekly,” Houseman says. “Smart metering can make it easier for them to pay, by matching bills to pay periods.”
Additional significant savings come from the combination of outage restoration, field-force management, and vegetation management. “When an outage is reported, we may be able to ping neighboring meters and use a diagnostic algorithm to figure out what components are out,” Soethe says. “This might improve the productivity of repair crews.”
Such features bring economic benefits, but they also can contribute to overall reliability and customer-service quality.
“The business case is significantly more complex than just demand management,” Houseman says. “AMI is an enabler for a lot of things utilities might want to do. The question becomes how long can they wait before taking advantage of these features?”
In some cases, the answer might depend on strategic business factors. For example, consolidation trends could affect how utilities evaluate AMI investments. “With the repeal of PUHCA, you will either eat or be eaten,” says Jana Corey, director of PG&E’s AMI initiative. “Running the utility as effectively as we can positions us better strategically in the market.”
Other key factors include rate schedules and regulatory policy changes needed to implement smart metering. “It takes a lot of time for a utility to get to the point where they can get a new time-of-use rate structure approved,” says Bud Vos, a vice president with Comverge in East Hanover, N.J. “Utilities need AMR and demand-response today, but they don’t have tariffs or the business case built yet.”
In some states, ratemaking structures make it harder to build the business case. Many utilities’ rates are based on power sales and the generation and transmission assets that go with them. For these utilities, investing in load-management can be a losing proposition, even if it breaks even or generates a modest positive return, because the investment could be more accretive to earnings if it were spent elsewhere. EPACT’s mandate directs PUCs to evaluate such structural disincentives, and eliminate them where possible.
In many situations, however, AMI is proving to be a solid investment—either because ratemaking authorities act to reduce disincentives, or the business case is strong enough in spite of them.
Florida Power & Light (FPL), for example, has been developing and expanding its smart-metering program in pursuit of greater load control for nearly 20 years. Today FPL’s demand-response systems shave peak load by 1,300 MW, with an additional 2,000 MW available in emergency situations.
The business case for AMI has improved in recent years as a result of advancements in hardware and software technologies, offering a broader range of features that can save costs. PG&E, for example, has seen the economics of AMI improve steadily since it brought its first proposal to the California PUC in 2002. “At that time, the business case was very uneconomical,” Corey says. “We refined our cost estimates and found additional benefits, and over the next 2-1/2 years the economics got better and better.” As a result, the CPUC recently approved $49 million in rate recovery for PG&E to advance its AMI plan, which envisions bringing DCSI smart meters to all 9.3 million of its gas and electric customers over five years.
The decisions utilities make about AMI investments often arise from how they approach the business case. “Some utilities build their business case around load control, and are using AMR to keep track of data,” Vos says. “Others are starting with an AMR business case, and are building toward load management. Either way it leads you toward greater efficiency and control.”
AMI vendors have developed their technologies to be both technically sophisticated and flexible enough to serve different utilities’ strategies, while accommodating growth and development. But while these technological advancements have strengthened the AMI business case, they also have led to a balkanized field of proprietary technologies.
“As an industry, we haven’t been very successful in moving toward standardization,” says Jim Fisher, director of product marketing with Itron in Spokane, Wash. “For AMI to be successful, we must implement standards. That will be the biggest challenge.”
Metering vendors have put forth significant efforts to develop uniform standards. Several industry groups, such as the OpenAMI Task Force, are working to forge standards for open architecture and interoperability that will allow the greatest possible degree of flexibility, manufacturing efficiency and forward compatibility as new features and technologies evolve. However, these efforts themselves have revealed persistent schisms over what functions, communications protocols, and data-management approaches should be included in AMI standards.
“The difficulty is that if it’s not an open-architecture system, utilities will be forced to accept one type of technology and live with it,” Fisher says.
But even defining “open-architecture” and its role in developing AMI standards can spark debate among various stakeholders. Some emphasize the importance of standardizing certain features and functions, while others focus on communications technologies and data protocols.
“It’s important to embrace broadly supported standards,” says Stephen D. Johnston, CEO of Smart Synch in Jackson, Miss. “For example, Internet Protocol (IP) is a key standard. The Internet is here to stay, and IP means you can talk to any device in the field. The same principle applies to GSM or GPRS wireless standards. We know they will be around for a long time.”
Others are skeptical about the potential for standards to bring uniformity to the industry. “This industry is in a state of evolution,” says Sharon Allan, chief knowledge officer at Elster Electricity in Raleigh, N.C. “There’s a gravitation toward IP, for example, but IP has overhead, and most people encapsulate it and encrypt it. Having IP in a meter doesn’t make it universally interfaceable.”
As a result of diverging interests and perspectives, utilities are challenged to weigh the functionality of systems today against the risk those systems might become outdated sooner than their owners would prefer. Such is the curse of technology in general, of course. And thus while questions of open architecture and durable platforms merit considering, utilities who are serious about AMI will not be paralyzed by this curse.
“Utilities are considering their metering investment plans in context of where they are going strategically and tactically,” Allan says. “Based on that, they can reasonably predict what functions they will need.”
Even amid differences in perspectives and technical approaches to smart metering, one common thread is the trend toward a more intelligent and powerful distribution network. One factor driving the success of AMI arises from the fact that it brings intelligence all the way into the customer premises, where it can serve many practical purposes. In the wake of EPACT, companies are evaluating those purposes carefully, and trying to identify technologies that might help them achieve their smart-metering goals.
“I don’t think any one technology is a silver bullet,” Soethe says. “Differences in geography and customer types, and customer needs, require different solutions. Utilities just need to consider what’s right for them, and pick one.”