Seizing the end-of-life smart meter opportunity

It is time to move beyond the benefits of first-generation AMI

The original business case for smart meters in Ontario was not driven by potential use cases. The utilities simply needed to get remote reads and support time-of-day (TOD) pricing to comply with provincial regulations. While this goal was realized, it came at a cost of foregoing additional value-added services to both operations and the customer. What utilities have come to realize is their advanced metering infrastructure (AMI) investment lacked critical functionality to help enable new use cases and options, which turned out to be a missed opportunity. As the first generation of AMI meters reach end-of-life, utilities need to start planning their AMI 2.0 strategy and what features will drive a real business case beyond the first-generation AMI value drivers.

The next generation of AMI has the capability to provide significantly more granular data, and utilities need to understand the value of this to the customer and utility operations . And, beyond that, bring in the distribution operations side of the business, which was mostly left out of the original conversation on AMI 1.0 . Utilities now have the opportunity to leverage new metering technology that includes computing capabilities with analytics and decision-making at the edge, and boost return on investment, reliability, and customer experience .

New opportunities

It is time to look at the value of services such as remote disconnect and reconnect capabilities, power outage notifications, and leveraging new types of data to identify opportunities through analytics. This could include monitoring voltage, power quality conditions, and momentary interruptions.

The original mandate for smart meters in the province of Ontario began 17 years ago. While the life of the smart meters were approximately 17 years, technology has changed dramatically, enabling a myriad of new features. But smart meters are even more complex than modern smartphones and the guidelines around them can also be complex. Utilities need to comply with rules and regulations set by Measurement Canada, ANSI, and FCC and need to coordinate with these groups on all changes. Also, meters are required to be electronically and physically sealed and self-contained in Canada, so upgrades are not as simple as swapping out parts. And while these factors may slow upgrades, the lifespan of the units themselves can be shortened by Canadian weather conditions.

Since utilities are funded through investment capital dollars, they are able to pass this cost onto their rate base once approved by the regulator through approved applications.

End-of-life planning

For the end-of-life, billing is key. If a meter has an expired seal, utilities are required by Measurement Canada to sample and verify they comply with accuracy requirements for billing. If a utility has a million meters and one percent need to be sampled, that is a huge undertaking. The seal can be extended for a number of years if the meter sample set continues to meet Measurement Canada compliance. If the sampling fails, the utility may have to broaden its sampling batch. Whatever the outcome of that process, it is a manual and expensive process.

While utilities face similar challenges, their individual situations are quite different. A utility’s situation and its ability to take on large capital projects versus a moderate-sized one will drive the decision for a rip-and-replace AMI approach versus a gradual replacement.

For many smaller or mid-sized utilities, gradual meter upgrades over time can be more appealing. As first-generation meters begin to fail or their seals expire, they would naturally be replaced with technology of equal or greater value . While this approach requires a moderate and incremental capital investment upfront, there is a proportionate delay in realizing the full benefits of the new technology across the entire population. Likewise, a decision on the type of network in the field (i.e., point-to-point versus mesh) can add complexity to the overall decision process.

Operating first-generation AMI equipment to failure increases the likelihood of operating in a crisis mode rather than being strategic and incorporating an orderly technology transition to preserve the billing process.

Capgemini is working with utilities to determine the best path forward. The change is going to happen and we can guide utilities on how to embrace the journey and use it to drive transformation. A technical assessment and gap analysis helps form a business and implementation plan focused on manageable scope, cost, and resources.

Next-generation AMI

AMI 2.0 is an exciting opportunity for utilities, but much depends on where they are in the technology lifecycle. Utilities can define a path forward by assessing the current environment and identifying barriers that could prevent them from looking at a next-generation AMI investment. Transitioning this technology is not simply just installing new meters; it represents a foundational layer of sensors and data that can be used to drive transformation for a utility.

AMI 2.0 can provide customer benefits, and that experience should be part of the conversation as utilities transition from a retail business model to a services one that is more customer centric. Taking the time to identify value-added use cases that support immediate and long-term company objectives is key. The next generation of smart meters will be so much more than just time-of-day readings.