AMI/Demand Response: For Real This Time?


Smart metering is coming of age. Is the utility world ready for it?

Fortnightly Magazine - September 2006

When Chris Hickman left Public Service of New Mexico (PNM) in 2004, he took his practical sense along with him.

Hickman managed PNM’s capital-expense budget and led the company’s T&D automation projects. During his 15-year tenure, Hickman learned firsthand how complex and difficult it can be for a utility to make big changes—technical or otherwise. As such, he understands the industry’s reluctance to jump on the latest technology bandwagon.

“Our industry has done the same thing for 100 years,” says Hickman, now executive vice president for regulatory affairs and business solutions at CellNet Technology in Colorado Springs, Colo. “That’s because it worked very well. The U.S. utility grid was the greatest engineering achievement of the 20th century.”

The 20th century is over, however, and Hickman is not the type of guy who is happy to rest on the laurels of yesterday. He expects more, and that leads him to ask tough questions, such as: “How can it be that most utilities cannot tell if your power is out?”

The answer to this question has driven Hickman—and a growing cadre of others in business and public-policy circles—to devote themselves to advancing smart metering as a vital step toward a bigger and more important goal: the intelligent grid.

“Smart meters are the enabling technology for a huge, revolutionary step forward for our industry,” Hickman says. “It will change the way we do everything.”

An intelligent grid would allow T&D operators to analyze orders of magnitude more data about operational conditions and load-patterns, and give them system control on a granular scale. It is a very powerful idea for the industry, with tantalizing potential benefits in load management, system engineering, marketing and other areas—some yet to be imagined.

This vision is taking clearer shape, as time-based rate programs become regulatory policy in many jurisdictions, including some U.S. states (see Table 1, “Smart Meters Proliferating”). In an ongoing series of policy proceedings, Hickman and other smart-metering champions are working to move the rest of the United States toward the same vision, one state at a time.


The term “transformation” has entered the pantheon of meaningless buzzwords, alongside words like “paradigm shift” and “optimization.” Nevertheless, advanced metering infrastructure (AMI) and dynamic-pricing programs promise to transform today’s utility industry into a somewhat different business—one that understands its customers’ usage much better, and can provide service more efficiently, reliably, and securely.

“A decade ago, customer service was not high on utilities’ priority list,” Hickman says. “That has changed. And with a constrained grid and rising fuel costs, people are beginning to realize the incremental benefits of a smart grid.”

An actual transformation might occur because two-way communications and standard-metering devices, collecting data on a real-time basis, would explode the amount of network information utilities can access. With built-in control systems, they also multiply the grid operator’s ability to manage loads and control power flows. The operational possibilities are almost endless, from improvements in peak shaving and customer service to reliability management and critical-infrastructure protection.

Whether the intelligent grid would cause a business transformation or not, smart metering and time-based pricing offer benefits the industry cannot ignore—for many reasons, not the least of which is the Energy Policy Act of 2005 (EPACT). Section 1252 obliges utilities and state regulators to consider adopting EPAct policies that require time-based rates and smart meters for all customers who request them.

Given the voluntary nature of the mandate, however, utility decision makers can approach their analysis in any way they choose. Some states, including Illinois, Oregon, Pennsylvania, and Texas, have been considering smart-metering questions as part of rate cases and resource-planning discussions. The Pennsylvania PUC, for example, conducted a hearing on June 22 to discuss policies that would mitigate electricity price increases in the state, and time-of-use rates and demand-response metering featured prominently on the agenda. Other states, such as Kentucky, Louisiana, Ohio, and Virginia, have initiated EPACT Section 1252 inquiries separately from other proceedings.

EES North America

Accordingly, the tenor of the discussion also varies from state to state, with high-cost power states generally more attracted to AMI than low-cost states are.

“Almost every state is looking at the substantive issues in a different way, which is an exciting challenge,” says Scott DeBroff, chair of the energy practice group at Smigel, Anderson & Saks in Harrisburg, Pa., and formerly an attorney with the Pennsylvania PUC. “This discussion takes the 100 year-old utility and the 60 year-old regulatory process and smacks it right up against the future of technology. It’s similar to the beginning of customer choice. You have the same dynamic, with the ability to separate out the generation component and offer choice.”

Likewise, regulators and utilities understandably are skeptical about the promises of transformational change that seem to accompany discussions about advanced metering and the intelligent grid.

“Some see [EPACT Section 1252] as another unfunded mandate from the federal government,” says Michael Valocchi, a senior managing director with FTI Consulting in Philadelphia. “Skepticism around smart metering and demand response has developed over a number of decades, and it won’t be overcome in 12 or 18 months just because the federal government told states they need to look at it.”

After all, the idea of dynamic pricing is nothing new; Congress first asked utilities and regulators to examine time-of-use rates as part of the 1978 Public Utility Regulatory Policies Act (PURPA), and many utilities have provided such rate programs for large commercial and industrial customers for years or even decades. Utility decision makers generally understand the benefits of time-based rates and metering. They just question whether those benefits are sufficient to justify investing billions of dollars so they can meter energy on 15-minute intervals for every house, condo and Starbucks.

“The jury is still out on the efficiency gains that voluntary time-based rate structures can provide, especially for residential customers,” states a recent report commissioned by the Edison Electric Institute (EEI). “While it is difficult for economists not to believe that better pricing of electricity can benefit society, it seems unlikely that voluntary time-based rate structures can fully realize those benefits.” (Responding to EPACT 2005: Looking at Smart Meters for Electricity, Time-Based Rate Structures and Net Metering, NERA Inc., May 2006).

Selling Smart

The growth of smart metering might depend more on political factors than it does on the technology itself.

For example, most utilities’ time-of-use rate programs thus far have been offered to customers on a strictly voluntary basis. And EPACT Section 1252 only requires smart metering for those customers that request it; nowhere does it suggest utilities require customers to accept time-of-use rates. Yet engineers and policymakers agree that extracting the true benefits of smart-metering and time-of-use rates requires large-scale adoption.

“One of AMI’s most important premises is that you collect interval data on substantially 100 percent of your customers,” says Kevin Cornish, DCSI Inc.’s project manager in charge of the Pacific Gas & Electric (PG&E) smart-metering initiative. “There are differences of opinion on the level of granularity you need, but in general the market is settling on hourly interval data for the mass market, and 15-minute intervals for mid-sized and larger commercial customers.”

Additionally, some time-of-use rate structures might prove ineffective because they do not reflect the real cost of power in the market. Few demand-response programs directly are tied to real-time market prices, and some utilities, such as Nevada Power, go so far as to guarantee time-of-use subscribers will pay no more for their monthly energy usage than they would under standard rates.

“At the present time, because of price caps and rate protocols, prices don’t rise high enough to provide adequate signals,” says Paul Joskow, professor of economics at the Massachusetts Institute of Technology (MIT) and director of MIT’s Center for Energy & Environmental Policy Research. “It’s always a good idea to provide consumers with better price signals, so they can increase or decrease consumption accordingly. But if you give consumers prices that are wrong or too low, they won’t react to those prices. Until you integrate the system-operation protocols with prices and demand-response systems, you won’t get the incentives you need.”

The implications go beyond efficiency and customer service, and into areas affecting grid reliability and security. A key selling point of the intelligent grid is the control it gives to system operators, who need the ability to call upon demand-response resources in an emergency, for example. But without broad deployment and transparent price signals, smart metering won’t give system operators the tools they need to predict and manage power loads.

As a result, smart metering suffers from a classic chicken-and-egg problem. Until smart meters and time-of-use rates are adopted by virtually all customers within a utility’s territory, they cannot deliver on the promise of greater resource efficiency and network control—to say nothing of business transformation. And until utilities and regulators are convinced smart metering will deliver on its promises, they will not invest in broad AMI deployments.

To overcome this dilemma, metering vendors and consultants are working to clarify the business case for smart metering. For example, member companies in the AMI/MDM Working Group recently commissioned McKinsey & Co. to develop a model business case for utility decision makers to use as a starting point in their cost-benefit analyses. And in July, the Demand Response and Advanced Metering (DRAM) Coalition hosted a Web-based seminar that examined the business rationale for smart metering. But whether such efforts prove convincing will depend on utilities’ and regulators’ disposition toward the assumptions in the economic calculus.

“If you run the numbers and include things that may not be, strictly speaking, quantifiable, it is generally a positive business case,” says Rick Nicholson, vice president of research for consulting firm IDC Energy Insights in Framingham, Mass, “But there is a lot of uncertainty about how it will get treated by regulators.”

Managing Demand

The way regulators add up the costs and provide rate recovery largely will determine how utilities and their shareholders perceive AMI investments. A public utility commission might easily justify rate-basing capital costs for new metering hardware, but less certain is how a utility should bear the costs of retooling its internal processes to pursue the smart-grid vision, as well as marketing the new program and educating customers to ensure maximum benefits continue flowing.

“If the utility’s costs outweigh the benefits, why should they do it?” asks Dean Maschoff, a managing director with Navigant Consulting in Chicago. “That’s where the regulator has to come in—to consider the big picture and find the middle ground with rate recovery that makes sense.”

Both utilities and regulators are uncertain about how AMI costs should be recovered. The California Public Utility Commission (CPUC) recently approved PG&E’s proposal to rate-base $1.4 billion in AMI investment, plus nearly $400 million more in rate recovery for business risk, marketing and other expenses. In Texas, however, TXU told the state PUC that it would prefer AMI costs to be hived off in a separate surcharge. “The costs should not be shifted to base rates,” TXU stated in its response to the PUC’s AMI inquiry. “Having all such costs be recovered through the surcharge will make it easier to track the recovery of advanced metering costs as compared to other metering costs that will still be incurred.”

In the public-policy calculus, regulators also must consider the fairness of allowing utilities to rate-base the costs of programs that will not benefit all stakeholders equally. “They are concerned about the distributional impacts,” Joskow says. “If they make major changes in rate design, how will it affect customers with different levels of consumption and income, and how will it affect various commercial and industrial customers?”

These economic and political dimensions complicate the effort for regulators, and make it difficult for them to confidently define the importance of AMI investments in the broader energy policy context.

“I think regulators have the toughest job in the world,” Hickman says. “As an industry, we have done a pretty poor job of communicating with regulators. We have not given them the information they need to understand how critical of a component this is. AMI is not an end state, but an enabler.”