When Eastern Utility Associates (EUA) in West Bridgewater, Massachusetts, U.S., began installing an automatic meter reading program in December 1993, we still had a few reservations about the up-and-coming technology. Would the relatively new technology help us substantially lower meter reading costs as promised? Would the system be easy to implement and provide reliable, accurate meter readings? Would the system remain a sound investment over time? And, would customers accept the new meter-reading methodology?

Now that deregulation and retail access is in place in Massachusetts and Rhode Island, a whole new set of questions and issues regarding metering and meter ownership has been raised. Should metering be open to competition or remain with the utility distribution company? Who will own the meter? How will automated meter reading (AMR) play in the restructured environment?

For the first phases of our AMR program, we decided to use the dial-inbound, telephone-based AIMetering System from American Innovations, Austin, Texas. Our goal was to begin eliminating the approximately 20,000 hard-to-read meters spread throughout our service territory. We chose this system because using the telephone line as the system communications network gave us the ability to strategically identify where and when we placed modules within the system. We were able to target and eliminate hard-to-reads without implementing an all or nothing approach.

The investment for an all-encompassing system is extremely large in comparison to strategically identifying and installing the modem-equipped devices. With the AIMetering System there is no need to build or maintain a separate system communication infrastructure.

EUA's utility subsidiaries provide electric service to about 334,000 customers covering 597 sq miles (1546 sq km) of southeastern Massachusetts and northern and coastal Rhode Island. Ninety percent of the customers are residential and reside in rural and suburban areas and a handful of more densely populated towns and small cities. Much of the population commutes daily to work in the metropolitan Boston and Providence areas. Several college campuses and thousands of apartments in the Newport and Brockton areas also mean that we must deal with heavy seasonal move-ins and move-outs. Additionally, a large number of meters in our territory were installed inside basements or elsewhere in residential homes long before locking doors was commonplace. This, in addition to the fenced yards and dogs, contributed to a seemingly never-ending cycle of difficult meter access.

"We consider any meter to which a meter reader cannot gain access between the hours of 8:00 a.m. and 4:00 p.m., Monday through Friday, to be a hard-to-read meter," explained John Markley, EUA customer service manager. "We had an individual that only read hard-to-access meters. He may have read 2000 meters in a year, but the hard-to-read list never diminished.

"It's just a vicious circle. One of the selling points of the new system was that the money being spent reading these meters would go on forever unless you solve the problem. So, that was what we would address with our initial installation," Markley said.

Before our initial installation and during the planning stage we quickly realized that implementing a cross-functional AMR system would require input and buy-in from a number of departments within the utility. A working group was assembled which included representatives from Meter & Services, Engineering, Customer Service, Information Services and Billing. The group was focused and committed to the success of the project. The teamwork exhibited by this group contributed greatly to avoiding many problems, one of which was reaching and educating the customer.

We introduced the new service to 1000 targeted residential customers via direct mail. The letter and brochure explained the need for the AMR system and answered questions about the installation process. Residents were asked to call or mail a reply card to schedule an installation appointment. Only four of the originally targeted residents did not want the automated device installed. The overall response was extremely positive.

"When word got out on the streets that we had a means to read these meters without disturbing the customers, many of those we hadn't even targeted would call up to request the service," recalled Markley. "We only had 1000 modules initially, so we put those customers on a waiting list. We have identified another 600 potential candidates and will begin installing these units later this year."

Install Pilot System in Four Months We were able to complete our pilot installation quickly considering that the pace of the installations was determined by our ability to schedule appointments with customers who were inherently not at home during regular work hours. To accommodate our customers' lifestyles, we developed an alternate schedule, which included 10-hour shifts. Generally our installers worked Tuesday through Saturday from either 5:00 a.m. to 3:00 p.m. or from 10:00 a.m. to 8:00 p.m. Within four months, all 1000 modules were installed with very few problems and the system was running routinely. Daily maintenance of the database was then transferred from the Meter & Services Department to the Customer Service Department.

At that time, daily calls were being received from the modules and meter data was being downloaded directly into our billing system. Each individual meter calls in once a month coincidental to the resident's billing cycle. The ability to collect accurate meter readings on a timely basis has a direct effect on our bottom line.

Before implementing the AMR system, our billing system would generate up to three consecutive monthly estimates before an actual read was required. If an actual read was not available the next month, however, we would run into problems. Hard-to-read customers would receive three estimated bills, then no bill until an actual read could be obtained. In some cases, actual reads could not be obtained before six months had elapsed. When an actual read was acquired, the customer would owe for one to six months of electric consumption. This generated customer concerns.

Using the AIMetering System has helped us reduce the number of estimated bills and customer inquiries. Currently, 1100 meters are calling in to the system. Because we use the flexible scheduling ability of the software to coordinate meter call-ins with the appropriate billing cycle, billing occurs more regularly than without the AMR devices. Our cash flow has improved because customers receiving timely bills are more prompt with payment.

Reading Cost Is Plunging In addition to shortening our accounts-receivable cycle, the AMR system is helping us lower the cost of collecting hard-to-read meter data. Our hard-to-read meters cost upward of $13.00 per read. Our goal is to reduce the cost of reading a meter to 84 cents. With the AIMetering System, we're now paying eight to ten cents per call and an additional eight to ten cents for miscellaneous operating system costs. The average cost per read now ranges from 16 to 20 cents per read where the system devices have been installed.

Our experience with the AMR System has been beneficial in other ways for both our vendor and ourselves. While we were learning about the system, our vendors were learning from us. For example, our experience helped identify a communication issue that ultimately contributed to the development of the AIModem. The slower modem has greatly improved system communication.

"There hasn't been any issue that we haven't been able to fix by working as a team," said Carol Roach, customer service section supervisor. "At first, being so far away from our vendor was a worry, but whether we have a technical service or hardware issue, there's always somebody at AI that will help us out."

In addition to contributing to system refinements and improvements, we've also noticed increased departmental cooperation with EUA, which can be directly attributed to the interest in our AMR system.

"Having the system in place," Roach explained, "makes the Meter Reading Department's job easier when they don't have to roll a truck. It makes our jobs easier because we don't have to estimate the bill. We all have a vested interest in making this system work."

Making the system work means that we continue to experiment in the meter shop. Earlier this summer, we retrofitted, tested and initialized our 600 newest modules in just 10 hours. Originally, our retrofit and test schedule called for 20 hours. We were ecstatic about how smoothly the entire operation went.

"We were testing to see if we were capable of retrofitting that volume in that amount of time while maintaining our quality standards," explained Paul LaFrance, EUA senior technical specialist. "We have always taken a high level of pride in the quality that comes out of our Central Meter Test (CMT) facility, and this was no exception."

The first-time production run included random sampling tests to ensure that the meter's accuracy remained within specifications after the retrofit process. Meter technicians checked that the bearings had not been disturbed and that the installation had not caused any binding to occur. The entire package, once assembled, was ready to be pulled off the shelf at a moment's notice for field installation.

"We may have the opportunity for this type of work in the future when deregulation kicks in," said Dave Allen, EUA meter engineer. "This could be a service we could make available to others at an appropriate fee."

Deregulation Considerations for Future The advent of deregulation in our area has heightened attention to meter reading. For some time, EUA and other incumbent utilities have been in the process of selling their generation assets. Once fully divested, EUA will act solely as a distribution utility. Meter ownership, however, remains a question that has yet to be answered.

The Massachusetts Department of Telecommunications and Energy (DTE) is charged with determining whether or not metering and billing information services (MBIS) should be deregulated. The department will conduct a study into the matter. The study is to begin no sooner than Jan. 1, 2000. Findings from the study and proposed legislation drafts will then be presented to the Massachusetts Legislature by Jan. 1, 2001. This legislation may dictate who, in a deregulated environment, will own the meter. Current deregulation in Massachusetts allows all customers (residential, commercial and industrial) to choose their power supplier. Each customer received what is known as a "standard offer" entitling them to a 10% discount as of March 1, 1998. On Sept. 1, 1999, customers will receive an additional 5% price decrease.

Power suppliers who choose to compete in the market must contract with EUA or another distribution utility to report hourly interval data on a daily basis to the region's Independent System Operator New England.

Generally, a New England electric utility will offer three metering options for recording consumption:

-Use the existing meter or estimate consumption with an estimated load shape. -Install a modem meter for larger commercial and industrial customers that could be polled daily. -Install a recorder that interfaces the utility meter through a customer interface device (CID). The modem-equipped recorder receives pulses and records hourly data, which is then polled daily via the modem.

The recorder is connected to the meter through the CID. The CID provides surge protection and also a clear line of demarcation between the recorder and the utility meter.

All of the supplier's external recorders interface our meters with a DayMetrix's CID.

"We have an approved products list for these external load recorders," explained Allen. "AI's commercial module is just one of our approved external load recorders; however, it is one of the more cost-effective solutions. So, there's a lot of interest in the device and potential for energy suppliers to opt for a less costly solution."

As a retail utility, EUA reports usage via actual reads and estimates to ISO New England, which uses the information todetermine monthly energy settlement and billing. Data is then trued up at the end of the month for reconciliation and billing.

Although not required at this time, a 24-hour reconciliation period could necessitate installing a system-wide AMR application. Even though customers are billed only once a month, power suppliers would be reconciling with the ISO on a daily basis using hourly interval data. In that case, a system-wide AMR solution could be justified and additional value-added services could be derived from the system.

In the meantime, our focus remains on strategic elimination of our hard-to-read meters using the AIMetering System and on developing methods that meet alternative supplier information needs. Continued progress toward these goals will give us a head start on full automation. The variety of metering situations that we or any utility encounters in a given service territory is unlikely to be fully met using only one type of AMR technology. Even with a system-wide implementation, we would still have isolated meters or pockets of meters that are best reached via the telephone infrastructure. We estimate that these situations would encompass approximately 20% of our meters. In addition, the AIMetering System offers advanced features that we plan on using in the near future.

With deregulation of the supply component, energy suppliers will require hourly or internal usage information to aid in the design of an alternative rate schedule and development of attractive pricing plans. Using actual internal meter data provides the ability to avoid relying on estimated rate class load shapes for ISO reporting and reconciliation. Another benefit that we could derive from a system-wide AMR implementation would be the ability to transfer or disconnect service without a site visit.

In most cases, an account name change means two site trips: one to read and seal the meter; a second to reconnect service. We could eliminate most of that expense with the on-demand read feature. We are continuing to test the flexibility and applicability of the AIMetering System. Our experience thus far has proven extremely gratifying.

We have started to whittle down our hard-to-read meters, cutting our meter-reading costs and improving our accounts-receivable cycle. We have identified an inexpensive product option for advanced metering in the first phase of deregulation. We have installed a system that will grow with us over time, offering us new options for implementing value-added services.

We have developed a working partnership that benefits not only ourselves, but also our customers, the vendor and other utilities. All, in all, we think our customers were right: We are on to a good thing.

Frederic E. Whaley is meter and services manager at Eastern Utilities Associates, West Bridgewater, Massachusetts, which he joined 19 years ago. He is responsible for meter installation and maintenance, field-collection activities, and administration of the Utilities Revenue Protection program. He also manages central meter testing and retrofitting and coordinates residential and small commercial service installations. He is a member of the Electric Council of New England Meter and Revenue Protection Committee. EUA is the holding company parent of Blackstone Valley Electric, Eastern Edison and Newport Electric, which provide electric service in southeastern Massachusetts and northern and central Rhode Island.