Advanced metering infrastructure (AMI) allows utilities to take a large step forward in the way they interact with customers—at least in theory. In practice, few utilities actually have closed the loop and combined smart meters with smart rates—and a smart billing and customer information system (CIS). The biggest example so far is north of the border in Ontario, Canada.
During the past three years, Ontario has instituted a full-scope AMI program that will bring smart metering and time-of-use (TOU) rates to 90 licensed distribution companies (LDCs) and, cumulatively, some 4.5 million residential and 500,000 commercial and industrial businesses by the end of 2010.
Most important, several small LDCs already are billing TOU rates to residential customers via their existing CIS. By the end of this year, roughly 55,000 residential customers will be receiving electricity bills based on Ontario’s TOU rates (see Figure 1).
Indeed, the Ottawa program already is addressing CIS-related issues facing U.S. electric utilities looking to implement an AMI and smart-grid program, including:
• How to set up the meter data management system (MDM) most experts say will be needed to collect and process the smart-meter data;
• How to incorporate the technical standards needed to ensure the smart meters can send TOU data to the MDM; and
• How to process and move the TOU data from the MDM into an existing CIS.
Experts agree that in many cases a utility will need MDM to gather the AMI-use data, place it in a batch format and deliver it to the utility’s CIS. That’s what Ontario has done. Ontario law requires each LDC to provide TOU billing. Many are still in the process of installing smart meters throughout their service territories, which range in size from 3,000 to 1.2 million meters.
However, instead of each LDC implementing its own MDM, the government created a single MDM to gather and integrate TOU data from all 90 LDCs in the province. Development of the MDM was overseen by Ontario’s Independent Electricity System Operator (IESO), which chose IBM Canada to build and operate the MDM system in 2006. The system was designed around an eMeter EnergyIP platform and is now a central hub for all 90 LDCs in the province
Key to the MDM design is its customized gateway software, which: 1) supports the data delivery formats of six metering technologies and the central MDM system; and 2) also provides a single set of uniform interfaces for providing TOU billing quantities and synchronizing customer data to each LDC’s CIS.
Simply put, the MDM places the data in off- mid- or on-peak rate buckets. The buckets are then delivered to each LDC’s CIS, which calculates the charge for each rate period and ultimately spits out a monthly invoice that includes a breakout of the TOU charges.
Not surprisingly, a project of this magnitude has generated plenty of challenges, both for the Independent Electricity System Operator (IESO) in Ontario and the LDCs themselves.
“There were a number of software vendors that said they were already doing automated meter reads, but they weren’t actually using the hourly consumption data,” says Bill Limbrick, CIO and vice president of IT at the IESO.
The fact that there are no industry-accepted standards to link the smart meters to the MDM, and the MDM to each utility’s CIS, didn’t help either. But the standards issue, which is often portrayed as a potential difficulty in many AMI discussions, hardly was insurmountable.
“Right now we have four different meter technologies delivering data to the MDM and that will probably grow to five or six. Each technology requires a different MDM interface,” explains Steve Mullins, an associate partner with IBM’s global business services group. “We’re using CMEP (California Meter Exchange Protocol) for most of the meter technologies, but each applies it a slightly different way. You have to understand how each meter technology deals with different situations. One may use a certain signal or protocol for an outage, while another may signal the same condition differently. So we had to account for all that. But that’s a level of complexity most IOUs in the U.S. probably won’t face. Unless they acquire another utility, most will work with only one or two meter vendors.”
Structuring the MDM to deliver the usage information to each LDC’s CIS was more straightforward. A standard interface was developed to communicate with 90 customer systems provided by 20 different vendors.
“With the CIS, we have one interface that we’ve defined and everyone has to comply with it. But we still had to synchronize the way the use data is transmitted from the MDM to the CIS. There are different rules associated with different tariffs, so we had to synchronize how we process the meter data and aggregate it into the TOU billing determinants,” Mullins says.
There were other CIS-related challenges as well. For example, steps had to be taken to protect each utility’s smart metering data from being accessed by other utilities. That may sound like an obvious requirement, but a number of the LDCs outsource their billing to vendors who need to access the data on their behalf.
Furthermore, some LDCs allow the billing vendors to access the data and, when necessary, make changes to it on the utility’s behalf. Others can access the billing but only utility staff can make changes. And if that’s not confusing enough, a number of utilities retain the same vendor.
“We have a range of vendors accessing data on behalf of utilities. And in some cases the same organization is working for multiple utilities, but the access privileges are different,” Limbrick explains. “That means we have the same organization but different privileges from one utility to the next, all of which required an extra layer of logic.”
The system is not yet capable of handling net-metering requirements—another future issue often referenced by experts. “We won’t be able to handle that right away, certainly not on day one,” Limbrick says. “But we do expect to handle net metering in the future. You could, for example, have two meters, one to record incoming power, and one for outgoing power. We’ll have to see.”
A handful of LDCs already have begun billing TOU rates. First out of the gates is Newmarket-Tay Power Distribution, which serves roughly 30,000 residential customers just outside of Toronto. As of April 2009, the company had converted about 16,000 of its residential customers to hourly TOU billing. It expects to have all of them switched over by November. Industrial and commercial customers enter the fray next year.
“We’re switching customers over to TOU billing gradually, so I guess you could say the phase-in process is more of a whimper than a bang,” says President and CEO Paul Ferguson. “The smart meters record and store the hourly data and then report it to the MDM once a day. Then we withdraw the data from the MDM into our CIS.”
Switching to the TOU rates was a four-step process. The new smart meters were installed and began reporting into the LDC’s existing meter-data collection system. At the same time, business processes were mapped to determine what changes would be needed under the AMI program. The meters were then registered with the MDM, which began accepting TOU data. The data was then processed and sent to the CIS for billing.
Newmarket-Tay was fortunate in that its CIS system, which Ferguson says is nearly 20 years old, already was capable of retrieving the data from the MDM without any major upgrades.
“Our strategy was to minimize the changes to the existing system. We wanted the MDM to take over as much of the new function as it can,” Ferguson says. “We had to work with our CIS vendor to modify the system to retrieve three buckets of data, instead of one, from the MDM and do so when we need it and in the form we need it. As long as the MDM identifies those three buckets, our CIS is quite happy with it.”
The biggest challenge, he says, involved revamping Newmarket’s business processes to meet the needs of the new system. Ferguson notes two particular issues.
First, accounting for an “exception” or malfunction in an electro-magnetic meter historically was a relatively simple process. Any gap or delay in the meter reading (past the billing deadline) involved estimating the use data for that time period, re-examining the data for that time slot during the following month’s reading, and then balancing the charges accordingly. Such cases are common to any electric utility. But with AMI, exceptions or gaps in the meter data register in the MDM system on an hourly basis (for every affected hour). Though the MDM can, and often does, self-correct such exceptions, the LDC must step in and correct them manually in certain instances. Hence, what was once a monthly review now has become a daily task.
Second, when replacing an electro-mechanical meter, the meter reading was taken, the new meter installed and a second reading was taken from the new meter. Several days later, the replacement meter and readings were entered into the CIS. At the end of the month, the monthly reading and use charges were calculated. With the new system, the AMI, MDM and CIS immediately must be alerted to the new meter. Otherwise the hourly use data that’s being delivered won’t be attributable to any LDC account until the MDM is made aware of the meter change.
“The CIS must know, the AMI system must know and the MDM system must know,” Ferguson says. “If there’s missing data on a new meter, the system doesn’t know the customer and reports the exception. Then we have to identify and clear that account. It takes time to update the system and correct that. Changing our business processes has been a huge challenge.”