Expanding our view of advanced metering infrastructure


By Guerry Waters

Twentieth century utilities structured themselves around the two main elements of their business. One element was the customer and associated calls, bills, and meters. The other was electricity with its networks, engineers, wires, and substations.

An oversimplification? Of course. But it contains an essential key to utility culture: Utility staff and departments tend to align either on the customer side of the business or on the network side. With a few exceptions – such as when outages must be both repaired and communicated to customers – these two groups have long tended toward separate business processes that may not come together much below the C-level.

The network view of AMI
That was the 20th century. The 21st century utility is gradually starting to move beyond this “never the twain shall meet” culture. The primary driver of this change is advanced metering.

Advanced metering and its infrastructure (AMI) have grown up on the “customer” side of the business. But the way AMI has been organised closely parallels network organisation. Both supervisory control and data acquisition (SCADA) and AMI use equipment (meters for AMI, network sensors for SCADA) to sense events and send activity reports to the utility through a variety of communications systems (see sidebar).

These two detection and reporting systems, while clearly separated within most utilities’ organisational structures, are already overlapping to some extent. Advanced meters can provide network operators with sensed voltage and power quality data along with real-time usage data that can help refine load control and other network operations. Virtually every advanced metering proposal envisions use of the data to enhance outage detection and restoration.

Small scale distributed generation
Growing concern about the negative environmental effects of fossil fuel generation has many looking at alternatives like solar panels and wind turbines. So attractive is the idea of this microgeneration that governments are already enacting supportive public policies.

From a utility point of view, the most problematic of these policies is net metering – a conceptual “two-way” connection to the grid that permits a property owner both to buy power from the grid when on-site generation is insufficient and to sell excess power to the utility at a contractual rate. Such schemes are already in place. There are few enough, however, that network operators can generally accommodate the resulting power flows as part of system “noise.”

Far more elaborate arrangements will be needed, however, if net metered microgeneration grows, as many envision, to 10% or more of total power flow.

Organisational issues in deregulated markets
If distributed microgeneration grows to this extent, will it be more efficient to regard the meter as a network sensor in maintaining grid operations?

That idea appeals to some in countries where previously integrated utilities have been separated into three parts – a competitive generation sector, a regulated transmission and distribution sector, and a competitive retail sector. If the meter is a network sensor providing network information, it makes sense for the still regulated network utility to assume responsibility for advanced metering. The network operator in this case can recover costs and distribute data using clearly established regulatory procedures.

Can the network operator uncover enough benefits to justify advanced metering? Might a separate, competitive advanced metering entity be able to maintain profitability by selling data? The answers are far from clear.

The integrated market view
Regulated markets tend to view advanced (interval) metering as springing directly from customers’ emerging needs, with side benefits accruing to the network. They have no need to segregate benefits by utility segment. They can regard advanced metering as part of a “green agenda” that extends across all parts of the electricity marketplace. As a result, a number of North American regulated utilities are already expanding interval metering from its current use with commercial and industrial customers to serve the entire customer group, residential and business alike. Through demand response and critical peak pricing, these utilities envision a metering and pricing system that encourages customers to use less power and networks to deliver more efficiently.

It is less common, however, for regulated, integrated utilities to place the meters’ potential network role at the centre of considerations about which products to choose or how to distribute data.There tends to be even less discussion about possible conflicts between metering and network data.

Structural parallels between AMI and SCADA
An AMI meter and a SCADA network sensor both detect local events. Both can report those events using a variety of communications systems (radio signals, hard wired, etc.). Both meters and sensors may be controlled remotely. Both are programmable and may thus perform some functions – like sending an alarm or turning off – when specific events occur.

Both AMI and SCADA generally use a number of different signal collectors (in SCADA parlance, remote terminal units; in AMI, this may be a head end) that convert meter/sensor signals to digital form. The signal collector may, depending on system design, take simple actions in the field. Its primary function, however, is to channel data to a central processing and repository system.

SCADA systems may channel all data into the control centre’s human-machine interface – a graphical representation of the network showing the current states of all its parts on which an operator can then act. AMI frequently envisions validated data entering a meter data management system for further processing and distribution. While AMI head ends and the MDM are closely monitored, that monitoring does not envision the type of extensive operator action typical of the distribution network control room.

Need for executive leadership
Before utilities venture much further in designing and deploying advanced metering systems, it would be wise to put onto the table and reconcile the roles that both customer-focused and network-focused business processes will play in the future of the system. Both the customer and the network parts of the utility should have input into this discussion. Obtaining that equality will undoubtedly require executive leadership.

Asserting leadership – bringing all parties to the table – may be a considerable challenge in utilities that have already permitted one part of the business to take ownership of AMI.

One way to gain balance between customer and network needs in AMI design is to examine how various ways of organising advanced metering might affect AMI’s potential to lower various utility costs. These costs, which will vary significantly from utility to utility, might include:

  • Cash flow and associated earnings on revenue. Advanced metering permits utilities to read meters and send the data directly to the billing application. Bills go out immediately, cutting days off the meter-to-cash cycle. How many? For what potential gain?
  • Collections from customers moving out of the area. Advanced metering offers a particularly high return on investment in processing final bills. Customers can request disconnects as the moving van pulls away. When a utility also permits online or credit card payments, final bill collection occurs in a matter of seconds rather than weeks or months. Are such collections a current problem? To what extent?
  • Bad debt collection. Advanced metering helps prevent bad debt by facilitating the use of prepayment meters. It also reduces the size of overdue bills by enabling remote disconnects; unless required by local regulation, there is no need to wait for crew availability. Would these positives outweigh potential negatives in public response, and how might those negatives be minimised?
  • Connection and disconnection. Advanced metering can virtually eliminate the costs of field crews and vehicles previously required to change service from the former to the new residents of a metered property. Is this a current issue? Communications services. Is there potential to consolidate the carriers involved in AMI and network telecommunications?
  • Data reconciliation. If the metering network remains largely separate from the grid’s control centre, how will the utility reconcile potentially conflicting data coming from each?
  • Application integration. Will the meter data management application favoured by the meter or customer service department meet the processing, timing, and data retention needs of the network side of the business?

This list is only just the beginning. Additional issues needing executive attention include:

  • Customer contact centre operations. Advanced metering provides customer representatives with the solid information they need to resolve high bill complaints during the first call. Some utilities have reported a 40% call reduction that can translate into a near term end to overtime and a longer term reduction in staff.
  • Insurance and legal costs. Field crew insurance costs are high. Remote disconnects, when permitted by law, lower these costs. Remote disconnects also significantly cut the number of days employees and lawyers spend on perpetrator prosecutions and attempts to recoup damages.
  • Vegetation management. Advanced metering can pinpoint blink-outs, reducing the cost of unnecessary tree trimming.
  • Grid related capital expenses. With advanced metering, network managers can analyse and improve block-byblock power flows. Distribution planners can better size transformers. Engineers can identify and resolve bottlenecks and other inefficiencies.
  • Supply costs. Supply managers use interval data to fine tune supply portfolios. More closely matching procurement and delivery reduces supply costs.
  • Fuel costs. Many utility service calls are “false alarms.” Checking meter status before dispatching crews prevents many unnecessary “truck rolls.”
  • Theft. Advanced metering can identify illegal attempts to reconnect meters or to use energy and water in supposedly vacant premises. It can also detect theft by comparing flows through a valve or transformer with billed consumption.
  • Micro-site generation. As explained above, techniques for handling power inputs from many very small generators are only in their infancy. Utilities may be able to save very substantial amounts in planning costs and network changes through a near term evaluation of the role advanced metering might play in this issue.
  • Ways to re-evaluate all these issues in light of technology changes. As both advanced metering and network technologies advance, utilities will undoubtedly need to refine processes and reassign tasks.

Risks in the current approach
Today, only a few utilities are examining advanced metering from a truly all-utility point of view. And unfortunately, when advanced metering remains primarily a metering or customer issue rather than an executive issue, utilities risk losing many of the potential benefits.

Advanced metering deployments that meet long term goals across the utility are possible only through executive guidance at the highest level. C-level executives are far better positioned to weigh and balance the various business and technical considerations raised during the consideration of advanced metering systems. They can ensure that business cases include benefits across the utility, presented in realistic terms. And they can prevent an overemphasis on day one customer benefits when, in fact, day two and day three network benefits may have far greater long term significance.

Without that leadership, tomorrow’s utility is all too likely to face a poorly conceived, poorly designed advanced metering system that must be ripped out and replaced, leaving in its wake a pile of stranded assets for which stakeholders will be liable long into the future.