The Information River
- Posted on November 5, 2009
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Mike Ingram, senior manager of demand response at the Tennessee Valley Authority (TVA), points out that data availability relies on the extent to which technologies are utilized. Utilities may adopt a supervisory control and data acquisition system or advanced metering infrastructure (AMI), but they do not always function as smart grid components that provide the most data possible. "It depends upon the depth of deployment," said Ingram. "If AMI is used for meter reading, it's not part of the smart grid. If it is used to improve reliability and outage management -- important elements of customer service -- then it is."
Business goals inform how utilities choose to invest in technologies. TVA is working to value the impact of implementing demand response for its distributor partners against relying on new generation to meet customer demand. The valuation considers the short-term cost of acquiring more data about customer usage against the long-term value of benefiting from that knowledge by executing energy conservation programs.
Ingram's point about various technologies is taken up by Dan Rogier, director of utility group systems at American Electric Power (AEP), who explained there is no easy way to determine how to maximize data use across a company. "You can't buy smart grid in a box," he said. "The good news is that utilities often know what data can best serve customers. The bad news is that getting it to the right people to solve the right business problem at the right time means figuring out how to integrate various technologies into a smarter grid. "Business priorities make that happen," Rogier said.
AEP has now automated many customer orders, including its outage management system, so that customer phone calls to identify a problem are unnecessary; the utility can respond more quickly, and issues can sometimes be resolved remotely.
Baltimore Gas & Electric (BG&E), which serves a capacity-constrained market, acquired valuable data in a smart grid pilot program that helped it learn how customers are willing to reduce power usage during peak hours. After deploying smart meters to 1,000 residential customers, BG&E tested two pricing strategies in response to savings incentives. "Customers were equally motivated by the opportunity to receive rebates by lowering power usage as they were about the ability to avoid higher charges by cutting usage," said Mark Case, senior vice president of strategic and regulatory affairs.
"We cut peak-time demand between one-fourth and one-third, and savings averaged $115 per customer. Ninety-seven percent said they were satisfied with the program," Case said.
Ingram at TVA wants to cut future generation by utilizing smart metering and distribution automation to acquire load information within the transmission system, and transfer it from areas of lower to higher demand. By communicating the cost savings of managing load already in the system, TVA can pay lower generation costs, and pass savings on to the distributor customers and consumers. TVA wants to cut 1,400 MW of peak demand through 2012.
Often the data utilities seek isn't entirely new. "The smart grid is a communication network laid over a power network," said Ingram. "The information has been there -- it's a matter of investing in the benefits of gathering and communicating it quickly and efficiently."
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Intelligent Utility magazine is the new, thought-leading publication on how to successfully deliver information-enabled energy. This article originally appeared in the September/October 2009 issue.