From vision to execution


On April 12, 2007, San Diego Gas & Electric (SDG&E) received California Public Utilities Commission (CPUC) approval on their $572 million effort to replace and retrofit over 2.3 million meters. Here’s a look at how we got to this point and what the next steps are.

It seems all you read about today in the metering world is advanced metering infrastructure (AMI) and the host of benefits it will deliver for both utilities and customers. And yet it wasn’t that long ago that AMI wasn’t even on the radar. In California it took the energy crisis of 2000-2001 to get the energy community really thinking about peak demand, how to bring demand response to the masses and, logically, how to measure consumption on a real-time basis for all customers.

Rather quickly among policy leaders, the topic of discussion then lead to AMI – but it was an expensive proposition that had to be well thought out to make investment sense. That meant our strategy had to be scalable, future-proof and sound. So at SDG&E we set off on a lengthy but worthwhile course of visioning.


As we started on the path toward creating the best advanced metering system for our customers and our utility operations, we identified a number of key fundamental premises to keep us on track. Obviously we had to build a system that would support both SDG&E and the State of California’s requirements for reliable electric energy. We also had to design a system that would help inform our customers of the consequences of consuming energy at peak usage periods.

We’d need to work with customers to manage their electric load. We’d always need to anticipate technology changes and adapt to them when it made sense. And this all had to happen while we were operating our business efficiently and reliably.

Once we developed these fundamentals it was time to focus on the actual technology. There were three major areas we concentrated on. First, the meter technology – this would need to monitor electricity consumption and communicate with the consumer, as well as tie in gas modules to the system. Second, a two-way communication infrastructure – this would be between SDG&E and all individual electric meters, along with communications from the gas modules. And third, software that would collect meter data and integrate it with other new and legacy utility applications.

At the same time we had to keep in mind the bigger picture of a ‘smart grid’ in our service territory. Recently designated as an area of transmission concern by the US government, it would be important to ensure the smart meter infrastructure investment we were about to make considered advancing technologies to help enable our smart grid roadmap. Things like distributed generation (DG), self-healing network and so on had to be taken into account, and smart meters had to provide the foundation.


From vision to execution pic pg 37 The meter and meter communication system is the cornerstone of any smart meter system, but we would plan ours to provide the gateway between the utility and the consumer. We would add in remote connect/disconnect functionality for 200 amp service customers and below. And we would come to view the meter communication system as giving access to the consumer’s programmable communicating thermostat (PCT) and other enabling technologies like in-home display.

About the same time, the California Energy Commission had also embarked on a strategic effort to work automated demand response into new construction with their Title 24 PCT functional requirements. In this mandate, utilities would control loads by communicating with PCTs, and by providing grid reliability and price responsive demand response (DR) programmes. These Title 24 PCTs would have two-way communication so a confirmation of a DR event could be provided. In the past it was that elusive confirmation that action had been taken that was missing. So our system would have to work with these requirements as well.

Our selected meter would also need to support remote firmware upgrades, future-proofing the utility from outdated technology during the life of the project. The ability to add new features such as power quality, new markets, distribution system asset optimisation, and pre-pay functionality was seen as critical if we were to provide new customer services, medical alerts, or other value-added service in the future. And the meter also had to act as a network sensor, capable of not only recognising net metering, but also being able to participate in distributed generation (DG).


From the beginning we wanted to design for two-way information flow. We had looked at automated meter reading (AMR) and, given our efficiencies, it just never could pencil out, while it certainly wouldn’t provide the foundation we needed in the future to add new services. So we decided we would require high-speed communications, as well as a secure means of sending information between SDG&E and end points throughout the system that were tolerant of attacks.

Our communications infrastructure plan supports our long-term vision to collect power quality information, new sensor data for the smart grid, building automation designs, and grid state monitoring and automation.

As a part of our case, we also committed to adding an industry standard home area network (HAN) component to our project in order to realise greater customer value. This will require open industry standards that are non-proprietary and provide for interoperability. We are currently working with the other California investor-owned utilities on this effort, as directed by the CPUC.

We also envision some optional communications requirements that economically leverage the smart meter communications infrastructure. Smart meters also support future technology upgrades and process improvements to enhance the capabilities of company departments such as Electric Operations, Gas Operations, back-office field and mapping support, and Customer Care. The concept is that implementing smart enterprise-wide technology and process improvements make our operations more efficient.

This would also allow for micro-grid communication and control, and autonomous self-healing systems. Other potential benefits could include intelligent alarming, electronic maps, remote SCADA-based controls, restoration switching analysis and planned switching.


The keys to our software approach were determined early on. We had to have the ability to leverage outage management systems to detect outages. Ultimately the software had to enable transmission and distribution (T&D) operations to sense and review information from many data sources, either through aggregation or as finely detailed as necessary.

The system designed had to add new functionality to meet the diverse needs of our customers – for instance, provide DR and energy efficiency information to the customer via PCTs, in-home displays, or other enabling technology. We could even offer customers centralised energy management systems or allow use of the information to manage their own system. The possibilities had to remain open.


At SDG&E we are committed to providing an exceptional customer experience and smart meters have the potential to really reinvent our relationship with our customers. But we have to approach this sensibly, and we know that the success of our smart meter programme really hinges on customers embracing the data it provides. We need to figure out how to make this simple and easy for our busy customers.

From the beginning we’ve focused on the customer benefits of smart meters, researching what our customers value, and that work continues today and into the future. Enhanced customer service, improved outage management, greater control over energy usage/bills and even a reduced need to access property resonate with our customers. Expanding energy efficiency and demand response programmes, creating innovative rate programmes, offering enabling technology and educating our customers will all be critical.

But we’re also looking at what services and products we can develop that provide an exceptional customer experience with smart meters. Potential future offerings may include things like proactive notification, personal rate option analysis, or customer initiatives such as new interaction channels, offices of the future and virtual enterprises. The possibilities are endless, but we have to find the right solutions for the right customer segments.


So now that we have state regulatory approval to proceed with the project, the vision needs to start becoming a plan of execution. And we’ve already begun. Work has started on the information systems and IT systems integration front. We released a new RFP for both technology and installation in May of this year to see the latest pricing and technology available in the market. And we continue to run field tests in our service territory. Between our RFP and field test efforts we are scheduled to select our final AMI technology later this year.

From there we will start to install our communications infrastructure, layout installation plans and then begin the official meter rollout in late 2008, ending in early 2011. We expect that at the height of installation, our staff will be replacing at least 4,000 new customer smart meters each day. It’s an aggressive plan and schedule, but it’s one we believe will service our customers best now and into the future.