When President Bush signed the energy bill on August 8, he set in motion a chain of events that might lead to major changes in the way utilities price and meter retail electric services—and ultimately in the way they value and use non-traditional energy resources.
Specifically, the electricity title of the legislation includes three provisions that shift federal policy toward greater flexibility and price responsiveness for retail customers. Title XII amends the Public Utility Regulatory Policies Act (PURPA) to require electric utilities to offer time-based metering to all customers, directing state commissions to investigate time-based metering and decide whether to implement the federal standards. Additionally, the title requires electric utilities to provide net-metering service for any customer that requests it, and to make available interconnection service for customer-owned distributed-generation (DG) systems on a non-discriminatory basis (see sidebar “Rooftop Revolution?”).
Net metering allows customers with rooftop solar and other onsite power-generation equipment to get credit against their bills for excess power fed into the grid. While the net-metering provisions are unlikely to create a massive DG groundswell, they might prove significant for utilities operating in states like California, which is embarking on Gov. Arnold Schwarzenegger's 1 million solar roofs program.
On the other hand, the smart-metering section probably will lead many states to accelerate demand-response and load-management programs. Taken together, the titles signal a significant shift in federal policies on retail electric metering.
"It could have a dramatic effect," says Patti Harper-Slaboszewicz, director of automated meter reading (AMR) and demand response for UtiliPoint International in Albuquerque, N.M. "Not all states will decide to install advanced metering, but this will encourage many to move forward. State commissions only have to look at the policy of the United States, which says customers should be charged for electricity based on when they use it and how much it costs."
The same policy says utilities should take advantage of customer-owned DG by facilitating interconnections and allowing customers to offset their power purchases with excess generation.
"It all represents movement toward smartening the grid and optimizing customer choices," says Michael Zimmer, a partner with Thompson Hine in Washington, D.C. "It is not driven by some academic, theoretical concept that won't yield real results. Instead the drivers will be the real advantages for developing new rate offerings, accessing and using data, shifting loads off peak, and capturing efficiency benefits."
Through the metering provisions in the energy bill, Congress and the White House are telling U.S. utilities that dumb meters—even with AMR capabilities—might not be good enough anymore. To comply with federal mandates, state regulators are expected to investigate advanced metering and decide whether to implement smart-metering programs as a matter of state policy.
"It definitely is an endorsement of smart metering," says Dan Delurey, president of Wedgemere Group, which manages the Demand Response & Advanced Metering Coalition (DRAM) and the Demand Response Coordinating Committee in Washington, D.C. "The provision in the electricity title focuses state-level attention on demand response and smart metering."
Specifically, section 1252, titled "Smart Metering," directs utilities to offer time-based rate schedules and the necessary meters and communications technology to all customer classes within 18 months of the bill's enactment. Rate schedules are expected to reflect variances in the utility's costs for generating or purchasing wholesale power supplies. The legislation suggests four approaches to time-based pricing, including:
Until now, smart metering has advanced in fits and starts in the U.S. utility industry. Its development was set back, in part, by retail deregulation processes that anticipated competitive service providers would install smart metering as a business investment. That didn't happen, however, and now Congress has signaled it wants incumbent distribution utilities to install smart meters.
Most utilities have resisted making such investments, largely because studies suggest the utility business case does not justify the cost of smart metering. A recent study by Madison Energy Consultants, for example, concluded that prices aren't volatile enough in the PJM market to justify the costs of implementing a demand-response program.1 Other studies, however, have yielded more promising results—promising enough, in fact, to justify pilot projects to assess the aggregated benefits and costs of advanced metering. For example, major projects now are proceeding in several Mid-Atlantic states, through the Mid-Atlantic Demand Response Initiative (MADRI), and in California, under a demand-response rulemaking process the state PUC began in 2002.
Most states, however, have been slow to consider advanced metering. An important disincentive for smart metering has been the fact that only some of the benefits accrue directly to the distribution utility, which generally is expected to incur the costs.
"Utilities are still learning about the differences between advanced meters and the AMR drive-by systems," Delurey says. "The challenge with smart meters is that the business case and the policy case are both multifaceted. You get some benefits in system operations, outage restoration and control, marketing data and demand response. And some of the benefits leak outside the utility's service territory to other people."
Thus the demand-response pill tastes somewhat bitter, because demand-response programs ultimately reduce the utility's peak-capacity requirements, and therefore its potential ratebase.
"Cost recovery isn't enough," Delurey says. "Utilities are looking for ways to improve their earnings, or at least keep them from degrading."
Disincentives for investing in advanced metering especially are problematic in locations with deregulated retail markets, where the benefits for deploying advanced meters are spread even thinner than they are in vertically integrated markets.
"States that have introduced retail competition have to deal with the difficulty that the benefits to deploy advanced meters have been disaggregated, split up among distribution utilities and retailers," says Richard Sedano, a director with the Regulatory Assistance Project in Montpelier, Vt. "We are still seeing a debate about whether this equipment is ultimately in the best interests of consumers, and that debate is mostly happening in retail-competition states."
Some jurisdictions are tackling this problem directly. The state of Connecticut, for example, recently passed legislation that mandates time-of-use metering and directs the state Department of Public Utility Control to determine "appropriate recovery mechanisms" to ensure utilities are made whole from losses incurred implementing the requirements. And in Pennsylvania, utilities now can use load-management resources to meet their obligations under the state's version of a renewable portfolio standard.2
Such ratemaking approaches hold promise for helping investor-owned utilities overcome the angst of investing in systems that reduce their power-sales revenue. Nevertheless, the economics of building a smarter grid depend on many variables—particularly the difference between peak- and baseload-power costs. In the short term, installing smart meters might prove worthwhile in some locations but not in others.
In Ontario, for example, utility planners see rising capacity shortfalls and Kyoto-protocol requirements as sufficient motivation to deploy advanced metering in the province. Analysts expect lawmakers elsewhere to follow Ontario's lead. A recent Gartner Research study concluded, "By 2007, at least five energy markets globally will mandate the rollout of AMI. Convergence of communication, information and energy technologies will result in intelligent meters becoming the cornerstone of the intelligent grid."
The intelligent grid, moreover, might prove to be the enabling technology for a range of major changes in the way utilities manage customer demand—not just through load shifting and network management.
"At the national level, the whole area of metering and its linkage to real-time pricing and time-of-day pricing is central to the efficiency strategies in the energy bill," Zimmer says. Properly deployed, advanced metering could make it easier to value and implement conservation measures and other resource alternatives, which ultimately might revolutionize utility resource-planning processes.
"In most states, right now there isn't a clear responsibility for utilities to do what might be called integrated resource planning, balancing one option against others," Delurey says. "Until we have a more dynamic market, it's difficult to answer the question of how people value demand response and conservation."
Indeed, a recent study by the American Council for an Energy Efficient Economy (ACEEE) found that demand-response research thus far virtually has ignored the potential energy efficiency benefits to be gained through smart metering. "Simply pursuing demand response without incorporating energy efficiency would be unfortunate," stated Dr. Martin Kushler, ACEEE Utility Director. "It's critical that we design programs that both reduce peak demand and improve overall customer energy efficiency."3
As fuel-price pressures increase, such questions likely will assume a higher profile in state proceedings to investigate advanced-metering programs. To the degree the industry and its regulators can develop workable mechanisms for overcoming the business dilemmas it presents, smart metering could usher in a new era in utility ratemaking, and in resource planning.