Patti Harper-Slaboszewicz, UtiliPoint International
In 2001, regulators and policymakers were aghast at the volatility of electric wholesale prices and insisted on insulating residential and small-business customers from what was perceived at the time as temporary insanity in the electric markets. Policymakers are now surrounded by mountainous prices at every turn: gasoline, propane, natural gas and fuel oil. These commodity prices will drive retail electric prices higher as well, especially prices during critical peak periods, which tend to be directly linked to wholesale natural gas prices. The era of cheap energy for Americans has ended, and, among other important solutions, we need to fully embrace demand response to lower costs.
The Energy Policy Act of 2005 stipulated that demand response is now the official policy of the United States. All state regulatory authorities are required by the Act to investigate whether offering time-based rates for all customers and the metering and communications to support those rate offerings would be appropriate for their state, and to issue a decision by August 2007, two years after the Act was signed. One of the key features of these investigations is that the analysis of the costs and benefits must include the customer benefits as well as the utility benefits. In other words, if society as a whole would be better off with time-based rates, then they should be offered to all customers.
If policymakers find advanced metering to be in the consumer’s best interest, utilities will have an enormous opportunity to recover automation costs and transform their business processes. At the same time, they will face new challenges in managing metering data. The industry has more or less adopted the standard of hourly data as fine enough to support current and future time-based rates for the smaller customers. Instead of collecting 12 meter reads per customer per year, utilities could be collecting 8,760 per year. Utilities will need to manage this data, as well as:
“- Calculate new billing determinants to support dynamic time-based rates, such as critical peak pricing, or critical peak rebates.
“- Educate customers on new rates.
“- Change the billing systems to accept the new billing determinants and calculate customer bills.
“- Provide price information to customers and possibly to customer-owned equipment, such as programmable communicating thermostats (PCTs).
“- Perform validation, editing and estimation (VEE) on hourly interval data.
“- Provide energy usage information to customers to help them respond to dynamic rates.
“- Leverage the value of the hourly interval data in operations to gain efficiencies in operations.
“- Invest in meter data management to support multiple AMR systems, demand response networks, and integration with billing systems, outage management systems, customer service, asset management, revenue assurance, etc.
how will utilities implement AMR and demand response?
The first step for any utility is to work with the policy-makers on the investigation. Utilities need to devote resources to work with policy-makers for two main reasons:
“- To make sure policy-makers understand the value of investments already made by utilities in these areas, and discuss with policy-makers how to leverage those investments to support the goals of demand response.
“- To get the functionality the utilities want rather than wait for regulatory standards to be imposed from outside.
Many utilities have made investments in demand response programs for their smaller customers. The intent of the Act would seem to be to expand opportunities for smaller customers, not to dismantle programs already in operation. If a utility, for example, already has customers signed up for a direct load control program that is working for the utility and the customers, rather than ending that program, consider enhancing the program. If the utility were to invest in a fixed network AMR system capable of providing hourly data, then the utility could tweak the existing program by offering customers the choice of participating in each event, and compensate the customers each time they chose to participate.
Providing information to customers can be accomplished in a variety of ways, one of which is to give customers a choice of when and how price signals and energy usage information is provided. It is very reasonable to limit the choices based on the hardware installed in the field. Hourly data has been identified by many utilities and policy makers as sufficient to support utility operations and price-responsive demand response programs. If we assume that customers will respond to dynamic rates, then over time, wholesale electric prices should become less volatile. This implies that if hourly data is sufficient now, it will be more than sufficient in the years to come.
We can move forward and consider benefits and costs for utilities and customers, to develop a rational plan for each electric utility, leveraging investments already made, and avoid the trap of attractive but unnecessary and costly functionality. The Act’s provisions on advanced metering and demand response provide a wonderful opportunity for utilities to work with their regulators and obtain cost recovery for automation. Since more than half the benefits of automation and demand response flow to consumers, it’s only fair that they bear some of the automation costs. In the end, with programs worked out jointly between utilities and regulators, all market participants are winners-and all of us will benefit from a small contribution to reducing the high energy costs that are likely to be a continuing fact of life for years to come.
Patti Harper-Slaboszewicz provides business case development, market research, strategic planning and consulting in the areas of AMR, Demand Response and AMR Data Management as part of UtiliPoint International’s Utility and Energy Technology practice. You can contact Patti at firstname.lastname@example.org.