Smart Energy International spoke with David Doherty, director AMI Operations, Engineering & Analytics at ComEd, about their smart meter rollout, customer engagement and what the next phase of this programme is likely to include.
ComEd has been exploring the benefits and opportunities of remote or automated meter reading solutions since the late ‘90s. Yet it was only in 2009, with an Itron (formally Silver Spring Technology) pilot that they were able to effectively and convincingly demonstrate the value to regulators.
This ultimately meant approval to move forward with a four-million meter deployment, utilising a mesh network on unlicensed frequency. This network now also serves as the communications platform for a variety of other distribution automation devices and smart city devices such as street lights.
“We’re hoping to add functionality, and capabilities and operational applications as we continue to grow the network,” says David Doherty, director AMI operations, engineering and analytics at ComEd.
ComEd covers the northern one-fifth of Illinois geographically and one-third of the population. In the areas in which ComEd owns the streetlights, the company is in the process of upgrading these with smart nodes.
Ultimately, over 100,000 streetlights will be deployed, with one of the primary benefits being remote alerts if a fixture ‘has gone dark’, thus enabling a team to be quickly dispatched to repair that streetlight. In addition to making the fixture smarter, ComEd is replacing many of the lights with LEDs at the same time.
“There’s an energy efficiency component to that, and again, we are saving on costs. The best part of it is we can pass those savings on to our customers. “Annually, we’re looking at over $100 million of savings, just from the smart meter technology deployment. By being able to disconnect the power to an unoccupied dwelling, we are saving around $40 million a year and avoided meter reading costs save us approximately $50 million.
Additionally, because we can remotely disconnect, which enables us to deal with non-payment sooner and more effectively, we have saved our customers about $30 million a year.
The best part is that we can more quickly connect a customer once payment arrangements have been made; i.e., we can connect in minutes now where it may have taken a day or more in the past. While the cost of the meter is passed down to the customers initially, the resulting savings have more than justified the expenditure. Our studies show that we are able to return over $2 for every $1 that we have invested.
“We are just wrapping up our deployment. Over the last five years, we’ve deployed over 4.2 million meters in Northern Illinois with roughly 6,000 consumers choosing not to have a smart meter. The majority of our customers accepted the smart meters, with less than 1% of our customers initially expressing any concerns,” says Doherty.
“Overwhelmingly, our customers are happy with the decision. Right now, the electric bill in Northern Illinois is their smallest utility-type bill. And, we get feedback that they appreciate the effort, and comments on the lower bills, while at the same time improving our service.” Doherty shares that the utility initially requested the go-ahead for the smart meter programme in 2007, after a few small pilots to test the technology. “The technology hadn’t matured to the level that it’s at now,” Doherty continues.
“In 2008, we were told to undertake a bigger pilot. This began in 2009 and was concluded in 2011. The results of that pilot resulted in ComEd being given the go-ahead to make the necessary investments in smart grid technologies. However, it wasn’t until 2013 that the utility was finally able to start the rollout of the programme.”
Where to from here?
Doherty shares that ComEd is now considering what happens with the meters installed in 2009. One of the questions the utility is considering is whether the meters need to be upgraded or if they are currently more than fit for purpose.
“For us, the most important consideration is this: the installation of four million meters required an investment of over $900 million. And we need to realise the benefit out of that investment. “What we are considering is how to build on top of that network. So, we continue to challenge ourselves: how do we use analytics to glean more value out of that investment? How do we layer on additional devices?
“One of the things that was front of mind when we were selecting technologies, and throughout our engagement with our stakeholders and regulators in the technology selection process back in 2009, was: how do we mitigate against obsolescence?
This is one of the biggest challenges facing utilities: with the rate of technological change occurring and a requirement for a billion-dollar outlay, how do you future proof your investment? Is it going to be obsolete by the time you’re done with your deployment?
“We consciously chose a technology based on proven standards, based on internet protocols and IPV6 compliant. Since the deployment, the devices themselves have gone through firmware upgrades, and we have that ability to keep the devices current without exchanging the hardware. That was an important feature for our stakeholders, and it’s proving to be beneficial. Here we are after our deployment, and the technology remains current, useful, adaptable and flexible toward our future needs.”
Doherty believes that the majority of the benefit to be derived now will be from the ability to dig deeper into the data and through back-end applications. He cites one of their biggest success stories as their Peak Time Savings programme. For the 300,000 customers signed up for the opt-in or voluntary programme, there is no downside – but it has generated nearly $9 million in benefits or rebates.
The question now is: What’s next, what’s the next programme that’s going to interest customers or provide benefits and that doesn’t require hardware updates? That requires the team to get creative on the back end while considering what else they can offer their customers. How is the gathered data, if used in a timely fashion, going to get sufficient information back to their customers so they can take even more control over their bills?
Smart cities are one of the options on the table.
ComEd recently opened up a smart cities’ laboratory as part of an overall investment to explore different technologies and devices. While the next opportunity may not even be commercially available today, the ComEd team is looking, talking to other utilities about commodity metering over the network, understanding the implications for distributed generation and electric vehicles. “We are putting our best minds to work figuring out what the next application is. It’s out there; we just have to go find it.”
Asked what the one thing is that he wishes he’d known before he started the project, Doherty says: “We have been very fortunate to have had minimal trials or tribulations as we went down this journey of the last five years. I do believe that one of the things that helped was the fact that we ran a 100,000-meter pilot before the large-scale rollout. This meant we learned a lot in the run-up to the deployment, and that was critical.
“My advice to anyone wanting to go ahead with a large-scale smart metering deployment: Run as large a pilot as you can afford prior to a deployment then use those learnings to frame out.
“The other thing that we certainly benefited from was others who went before us with full deployments. We learned from their mistakes.”
Perhaps the most unexpected development from the deployment for Doherty was the accompanying focus on change.
“As part of our business transformation, we started with processes. We didn’t start with the technology – we started with what we needed to do to provide the outcomes we wanted for our customers. “We asked ourselves what technologies we needed to accomplish those goals. Our business transformation started with process – and a solid effort on communicating the change and training our employees to provide them with all the tools and skills they needed to be successful.”