Main Menu7/18/2005
The differences between energy bills passed by the two different federal legislative branches are now being discussed in a conference committee comprised of members of both the House and the Senate. If all goes well, the committee will recommend a new version for both the House and the Senate to consider and if the new version were to pass both bodies, then the energy bill would be sent to the White House to await the signature of President Bush. This could take place in August or September, or not at all, depending on how things go.
Within the bill, there are a number of provisions that could have a dramatic affect on how Americans pay for their energy use at home. Each state commission is directed to investigate advanced metering for the support of demand response programs, which may result in customers paying for not only how much energy is used, but when it is used. The question for our readers today is what resources are likely to be available to the state regulators to conduct the required investigations, and what are the likely results?
Advanced Metering Potential Market Size
An issue that has arisen is what functionality is required to support residential participation in demand response programs, which might range from being placed on a dynamic pricing rate to having the utility control customer appliances. The intensity of the debate can be explained fairly simply: there are billions of dollars at stake, and not everyone can have a piece of the pie. Consider that in the state of California, the capital cost to provide advanced metering for all customers, including residential and small commercial as well as gas, is likely to exceed two billion dollars. If this were to be extended to all customers across the U.S., this would approach twenty billion dollars, more than twice Microsoft's net income for fiscal year 2004. However, the costs could easily balloon far beyond these numbers if the requirements and functionality are not carefully evaluated by state regulators during the investigations.
One approach employed by California and Ontario to establish minimum functionality for advanced metering was to engage all interested parties, including utilities, vendors, consumer advocates, and consultants in working groups that met regularly to painstakingly develop a consensus on what is necessary to support critical peak pricing for the smaller customers, and be consistent with controlling customer loads (such as air conditioners) directly or indirectly.
Some Forums Provide Bizarre Results
While the California working groups succeeded in laying out the initial guidelines for system functionality, other forums have not been so successful. UtiliPoint® participated in one recently where the functional requirements that had been developed in a prior brainstorming session highlighted the uses of advanced metering for demand response, but ignored uses that have been well documented that bring substantial benefits to utilities by reducing operational costs. In a bizarre turn of events, attention was paid to what happens to an advanced metering system during an outage, but no mention was made of using the system to detect outages, verify outages, map outages, or to complement restoration activities. Eliminating estimated bills, improving load forecasting, proper sizing of distribution assets such as transformers and feeder lines, handling bill inquiries or customers moving—all of these potential benefits were ignored as well.
Do it Right
It is clearly important that enough time is taken to understand and carefully document all potential uses of advanced metering since these will drive the required functionality, and ultimately, the sharing of costs between the customers and the utilities.
Another pitfall to be aware of is the attempt to add new requirements without providing solid justification. For example, UtiliPoint® has heard numerous times that electric meters should provide a communication gateway to customer homes, allowing utilities or other authorized parties to engage in conversations with customer air conditioners over the network through electric meters. The first question UtiliPoint® would pose is why does the signal have to go through the electric meter? Second, is it necessary to engage in two-way communication with customer air conditioners or is it sufficient to broadcast signals to customer air conditioners? These are very important questions to ask because it turns out there is usually more than one way to accomplish the underlying goals, and there can be significant cost differences in how advanced metering systems are designed.
Two Sample Use Cases: Support Critical Peak Pricing and Measure Peak Load on Transformers
Let us assume that a utility is planning to implement a critical peak pricing program with fixed pricing periods for each price level. By measuring energy usage in daily time-of-use periods, the utility could bill customers on the critical peak pricing rate. If the hours assigned to any pricing level were to change, as would be expected to happen over time or if the rate is more complicated, the utility either needs to bring back more information from the meter, or have the ability to tell the meter to change the assignment of hours to the time-of-use periods.
There are different costs associated with each method. The utility might choose to measure the energy usage for each hour, and then let the AMR data management system add them together. The utility would then be able to accommodate any critical peak pricing plan as long as the boundaries of the different periods were constrained to fall on the hour.
Another method would be to reprogram the meters to change how the data is aggregated into time-of-use periods to reflect the new definitions of each pricing period. This would relieve the utility of bringing back so many readings each day but would require the utility to be able to program the meter remotely.
Since there are at least two methods of accommodating future rate designs, it would make sense then to set the requirement that advanced metering systems should be able to accommodate a variety of rate designs that might be employed now or in the future rather than specify a requirement to collect hourly interval data or to remotely program meters, at least as far as billing is concerned. This is important because the utility will not need both features to support billing of critical peak pricing rates. If regulators are not aware of these different methods they could specify one without realizing the benefits of the other.
If we move onto sizing of distribution transformers, one method for calculating peak load on transformers is to measure the hourly load of all customers served by the various transformers, and sum up the loads for a period of time which should include periods where transformers are likely to be stressed, such as during hot or cold weather. But, once again, there is more than one way to accomplish the collection of hourly data. The utility could collect hourly data for all customers, and calculate the loads of transformers routinely or as needed using that hourly data. Another way would be to only collect hourly data for customers served by selected transformers, and once the utility is satisfied with the peak load calculations, could choose to stop hourly data collection. The tradeoffs for this use of the advanced metering system are similar to that of collecting billing data: collect hourly data for all or only for some for a period of time. One method involves collecting and processing more data on a routine basis, and the other requires the ability to remotely change how energy usage is aggregated at the meter.
Requirements Rarely Linked to Just One Use Case
The key points to note from consideration of the requirements posed by these two distinct cases are that system requirements arise from more than one use of the system, and that there is almost always more than one way of achieving similar results. A utility is likely to consider a number of different uses of the system before deciding what would work best in meeting current and future needs of the utility and its customers. Similarly, any working groups convened by state commissions need to consider enough “use cases” to capture a fairly complete picture of how the system would be used.
Use Case List for State Commissions to Consider
The following use cases should be considered by state commissions in their investigations into the benefits of advanced metering. In some cases, the capability may be provided directly by the advanced metering system, and in other cases, the advanced metering system may work in parallel with other utility systems or networks to provide the capability. For example, some systems may be designed so that pricing information is transmitted via the advanced metering system, or utilities may select other communication channels for this purpose, such as the internet or cell phone networks, or both.
- Measure and collect energy usage information to support billing of customers
on critical peak pricing plans.
- Collection and measurement of energy usage should accommodate changes to
the pricing period definitions, and the number of pricing periods.
- Support providing information to customers to allow the customers to understand
their energy usage.
- Support sending signals to customer owned equipment to allow for automatic
response to price changes.
- Support customer service departments of utilities to handle customer bill
inquiries, starting and stopping of service, single call outage verification,
and customer bill date choice.
- Eliminate or reduce the need for estimated bills.
- Lower Unaccounted for energy, UFE.
- Outage management, including outage detection, outage mapping, and outage
restoration.
- Asset management, including sizing of distribution equipment such as transformers,
feeder lines, substations.
- Asset management of meters.
- Supports remote connect/disconnect.
- Improve Load forecasting.
- Support prepay metering.
- Improve power quality.
- Improve system reliability.
- Reduced cost of energy procurement.
- Avoided distribution costs.
- Avoided costs of new peaking plants.
- Avoided transmission investment.
- Lower regional energy costs.
- Reduce local congestion.
- Increase spot market sales.
- Assist in vegetation management to identify problems that might lead to
future outages.
- Verification of load reduction during demand response event.
- Balance loads.
All of these use cases listed above are supported by research into the benefits provided by advanced metering and demand response by surveying North American utilities within the last year by UtiliPoint®. Numerous use cases could be accomplished using hourly interval data, not just critical peak pricing. The use case discussions should focus on the desired functionality rather than specific system architectures or technical solutions, allowing utilities and vendors to provide the most innovative and cost-effective solutions for consideration. The upcoming energy bill provides an opportunity for the industry to showcase how their products will help customers reduce their energy bills and utilities to reduce costs. Let's make the most of it by supporting state commissions with balanced and comprehensive information.
UtiliPoint's IssueAlerts are compiled based on the independent analysis of UtiliPoint consultants. The opinions expressed in UtiliPoint's IssueAlerts are not intended to predict financial performance of companies discussed, or to be the basis for investment decisions of any kind. UtiliPoint's sole purpose in publishing its IssueAlerts is to offer an independent perspective regarding the key events occurring in the energy industry, based on its long-standing reputation as an expert on energy issues. Copyright 2005. UtiliPoint International, Inc. All rights reserved.
