Testing the Waters of Advanced Metering Infrastructure
Originally published March-April 2012
When contemplating the emergence of advanced metering infrastructure technology, industry insiders and onlookers may ponder: what, exactly, is AMI?
It is a nascent technology that changes from one year to the next, as new features are developed and applied to products. It has been the focus of formal study and analysis by state and federal regulators, who must understand it before they can govern its use. In its 2010 Assessment of Demand Response and Advanced Metering, (published in February 2011) the Federal Energy Regulatory Commission set forth this definition:
Advanced meters: Meters that measure and record usage data at hourly intervals or more frequently and provide usage data to both consumers and energy companies at least once daily. Data are used for billing and other purposes. Advanced meters include basic hourly interval meters, meters with one-way communication, and real-time meters with built-in two-way communication capable of recording and transmitting instantaneous data.
The It Law Wiki offers a more illuminating definition:
The advanced metering infrastructure (AMI) (also referred to as automated metering infrastructure) allows utilities to collect, measure, and analyze energy consumption data for grid management, outage notification, and billing purposes via two-way communications. AMI is the primary means for utilities to interact with meters at customer locations. In addition to basic meter reading, the AMI consists of the communications hardware and software and associated system and data management software that creates a two-way network between advanced meters and utility business systems, enabling collection and distribution of information (such as energy usage, price, and control signals) to customers and other parties, such as competitive retail suppliers or the utility itself. AMI provides customers real-time (or near real-time) pricing of electricity and it can help utilities achieve necessary load reductions.
The real experiences of municipal utilities wading into the world of AMI can be measured against these definitions. The vision of AMI is exciting. The cost is another matter.
AMI installation requires evaluation of not only an operational cost-benefit analysis; it requires a careful evaluation of the whole utility. AMI technology's operational cost savings alone rarely justify the infrastructure investment. According to The Future of the Grid, a report by the Massachusetts Institute of Technology Energy Initiative, the operational benefits per installed meter varied from $50 to $232 per meter while the average cost per installed meter can range from $157 to $484. The MIT study examined 10 investor-owned utilities, and Portland General Electric in Oregon was the only utility in the study that could justify its project based on the operational benefits-to-cost ratio alone.
When operational benefits alone do not justify the investment in AMI, utilities often consider non-operational benefits, such as two-way communication, increased accounting accuracy, and enhanced detection of theft and diversion. Distribution management is also considered when the operational cost-benefit does not justify the project. In studying non-operational benefits of AMI technology, the MIT report found that benefits ranged from $0 to $804 per meter. Working with customers and vendors is critical for choosing the appropriate technology to meet the needs of the utility because the risk of implementation without benefit is real.
A number of public power utilities are embracing AMI technology after careful evaluation and some are finding the funding to make these projects feasible through grant programs. The city of Princeton, Ill., was awarded an American Public Power Association Demonstration of Energy-Efficient Developments grant, which it used to evaluate AMI technology and its benefits. Princeton worked with a graduate student from the Northwestern University Kellogg School of Management to complete the comprehensive evaluation. Princeton serves 3,700 residential and 600 commercial and industrial customers. Princeton's size was attractive for the study, which monitored the costs and benefits of AMI technology in a small community before examining a larger city. At the same time, the study contained enough data points to have meaningful conclusions.
Princeton was also awarded a $700,000 energy efficiency grant from the state of Illinois. This grant provided Princeton with 70 percent of the necessary funding for the project. The grant was funded through the Illinois Energy Plan, which works with federal American Recovery and Reinvestment Act (ARRA) dollars to promote green sector growth and job creation. As a result of these grants and AMI technology, Princeton's electric utility is now a technology leader in the state. Princeton has utilized drive-by AMR since 1999 and anticipates full deployment of its AMI as of February 2012.
The Princeton City Council agreed to move forward with this project on the condition that the utility continued to use its existing Itron meters. When Princeton installed meters in 1999, the utility and the city were forward thinking and expected to move to AMI at a later date. Princeton is using Itron encoder receiver transmitters with its current AMR meters to make the transition to AMI.
Princeton is looking forward to advancing to the two-way communication capabilities that AMI provides. "The change from one-way communication to two-way communication will provide Princeton with real-time outage information," said Jason Bird, Princeton's superintendent of electric and telecom. Princeton also has 10 to 15 change accounts a day. The utility will be able to reduce labor costs associated with these changes and provide customers with faster billing.
The customer service benefits of this technology are attractive to many utilities, including Princeton, but some customers may have health and privacy concerns. To address these concerns, Princeton held multiple public meetings with residential and commercial customers.
Utilities planning AMI projects can find more information to address customer concerns in a Utilities Telecom Council study, "No Health Threat from Smart Meters," which questioned assertions that smart meters pose a health risk. Smart meters emit a radio frequency power density that is much lower than common consumer electronics, such as laptops, cell phones, and microwave ovens. However, this information alone may be insufficient to calm customer concerns that are based on misinformation.
Princeton addressed customer concerns, but has experienced a few challenges with data collection. Bird said data collection improved in the fall and early winter after leaves had fallen because the leaves no longer interfered with radio reception. During the spring and summer, foliage interfered with data collection. Princeton has also added a repeater to the system, which further improved data collection. In addition, Princeton's meter data management partner, eMeter, has also installed an adaptor to enhance data collection. "As of the beginning of 2012, 400 out of 4,300 meters are still not reading on the new system," Bird said.
To make the transition from AMR to AMI, Princeton needed to procure vendor services to address cyber security, meter data management, readings, and in-home devices. The utility issued a request for proposals to coordinate with vendors. "HD Supply won the contract and serves as Princeton's project manager and handles all vendor management. This is good solution for a small utility. All invoices are coordinated and processed by HD Supply. Princeton holds weekly conference calls with vendors to stay updated but HD manages the relationship," Bird said.
Hutchinson Utility Commission in Minnesota, completed in 2011 an AMI project that will meter gas and electricity. Hutchinson, like Princeton, examined the benefits of this technology and recognized possible benefits for its customers, improvements to grid management, and increased billing accuracy. These benefits were evaluated along with customer concerns and the cost of the infrastructure investment.
"One of the many drivers for Hutchinson Utilities was the ability to read meters automatically," said John Webster, Hutchinson natural gas division director and AMI project manager. "Hutchinson, which partnered with Groebner & Associates and HD Supply in the AMI and smart metering selection process, will utilize FlexNet across its eight-square-mile service area to improve record-keeping accuracy and theft detection, take advantage of current smart grid development initiatives, and better manage and balance their natural gas purchases and sales."
Hutchinson has installed 5,492 natural gas AMI modules and 7,118 electric meters, which are capable of two-way communication. Hutchinson chose Sensus FlexNet because the communications network works with both electric and gas meters.
"While many technologies can support two-way communications for electric meters, we sought a solution that could also serve our gas needs with one system," Webster said. Hutchinson wanted to secure accurate and timely communications with its meters, Webster said. Hutchinson's "gas utility meters are now equipped with SmartPoint GM transceivers, the utility has also deployed iCON A electric residential meters. Both meters communicate via the FlexNet two-way communications network. This system included radio communications devices that interface with gas meters and enable our utility personnel to receive reading and diagnostic information from the meter on a predetermined schedule, or on demand, per our preference," said Webster. "In addition to the FlexNet system, Sensus will provide Hutchinson with more than 7,000 iCon electric meters and more than 5,000 natural gas meter SmartPoints that will enable remote readings for both utility types," Webster said.
Hutchinson has been using near-real-time meter data to manage the accounts of a local community college student population that has a large number of change accounts. "With the old system, a utility employee had to drive to the residence to read the meter," Webster said. Now the meter readings are instantaneous as the customer accounts change. Hutchinson also enjoys the reduced labor cost of resolving some customer service issues, such as helping a customer differentiate between a power outage and a tripped main breaker in the home. Such issues can be easily and quickly resolved over the phone by a customer service representative.
In an AMI product description on their company website, Sensus, Hutchinson's AMI vendor, makes a case for the increased safety provided by remote shut-off capabilities. "When access to a meter involves some type of risk—such as dangerous conditions, gas leaks, protective pets and upset customers—the value of remote shut-off capabilities increases."
The electric utility in New Bern, N.C., is in the planning stages of an AMI project. New Bern now uses a mix of "walk-by" Itron electric meters and manual reads for the 35,000 electric and water meters read each month. The city has 10,000 Itron electric meters and 400 Itron water meters; the rest of its meters are manually read and keyed into handhelds for downloading.
Demand-side management is one of the most attractive attributes of AMI for New Bern, said Jon Rynne, director of utilities. Data from interval metering can be used to manage distribution system assets. Precise metering can alert distribution operators to an overloaded distribution transformer. "AMI technology will be a large benefit to New Bern's demand-side management program, which helps to keep power supply costs and rates as low as possible," Rynne said. Customers in New Bern are highly sensitive to rate increases and so New Bern works diligently to lower costs.
"We are hoping to use the technology to determine which load management switches have failed or have been disconnected by customers from appliances the city controls to reduce its peak demand," Rynne said. "We have approximately 11,000 of our 17,500 residential customers participating in our load management program and verifying that the 24,000 switches are operating and lowering demand is critical to our power supply costs," Rynne said.
"This technology will allow us to see if energy consumption at a participating residence drops during load management periods, when the switches have been activated. This type of detection will help us focus our inspection efforts to keep the switches in operation and lower our costs," Rynne said. In addition, we hope to provide more information about energy usage to our customers, enhance our outage management capabilities, and offer new programs such as ‘pay as you go' with the AMI technology."
New Bern found the "pay as you go" option especially attractive. AMI's near-real-time metering and two-way communication give utilities the ability to offer customers pre-pay billing, similar to cable, Internet, and wireless phone service providers. This technology allows for accurate and timely billing, which may encourage conservation, reduce delinquencies and may improve utility cash flows.
New Bern has hired Power Services of Raleigh, N.C., to assist with the specification and implementation of AMI technology. New Bern used a request for qualifications process to select a consulting service.
When AMI cannot be justified purely based on operational cost benefits, the non-operational benefits to the utility must be carefully considered and evaluated on a case-by-case basis and may justify the project, depending on the infrastructure that is in place. Public power utilities find AMI to be worth the investment for a number of reasons, including customer service, real-time meter data, and distribution management, but these benefits may not always justify an AMI project. Grants and other sources of funding may be needed to make an AMI project feasible. The study of Princeton conducted by Northwestern University also suggested that utilities work together to gain economies of scale and share some of the cost of this technology, which may make AMI accessible to a greater number of public power utilities.
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