Headquartered in San Francisco, Pacific Gas and Electric Company (PG&E) is one of the largest combined electric and gas utilities in the United States. Downtown San Francisco is dominated by a bold green banner with the slogan “letsgreenthiscity”! Metering International found out more from Jana Corey, Director, AMI Initiative, PG&E.

Tell us a bit about yourself.
Jana Corey: I came from the aerospace industry and have an electrical engineering education. I’ve done a lot of things at PG&E – I’ve been here for the last 16 years – but for the past four or five years I’ve been working on advanced metering. Our AMR project was approved in July 2006, so it’s now active. We are also monitoring technology in the market, which makes it a very exciting time to be involved.

And tell us about the utility.
JC: Well, we celebrated our 100th anniversary a few years back. We’re an aggregation of many smaller utilities, with a service territory of 70,000 square miles in northern and central  California, and we serve 5.1 million electric and 4.2 million gas customers. We have 20,000 employees involved in generation, transmission and distribution, and we also serve retail customers. We are regulated by the California Public Utilities Commission.

We got into advanced metering because energy prices were rising and technology prices declining simultaneously, so we reached a wonderful point where it became economic to launch a remote meter reading project. As an outcome of the Energy Crisis in California, the California Public Utilities Commission wanted the ability to deliver energy on a real-time pricing basis. Some kind of advanced metering was needed to do that, and the Commission asked all of the big utilities to come forward with a proposal.

What are some of the key challenges your utility faces?
JC: Once you have selected your technology, the big areas of effort are in the actual field deployment - getting 10 million devices out in the field plus all the related network infrastructure. We have a varied geography, and we’re dealing with many cities, so there are a variety of deployment challenges. But I’m glad to say things have been going fairly smoothly.

Another challenge is the system integration – going from just one meter read per month from every customer to interval data from each meter.  We will be collecting daily usage data for gas and hourly usage gas for electric. Our primary concern is the exponential amount of information coming in.

We architected our system so that there was another process between field meter reading and our billing system – a meter data management system, or MDMS. The MDMS is designed to take the data from the field and ensure it interfaces with our legacy systems. So we’ve had to put together a separate team to integrate the metering reading data. There is also an outage team that will take the outage information from the field and input it into the outage information system. In other words, there are different teams working on different components of the system.

What is happening regarding actual meter deployment?
JC: It’s a five-year program that started last November. We began slowly while we worked the kinks out in the field deployment, but now we are ramping up to full deployment. From a couple thousand meters a day at present, we expect to be installing 10,000 to 12,000 meters a day by the end of 2008. So far, we have just over 240,000 gas and electric meters in.

We are doing our deployment geographically, focusing primarily on residential customers at the moment. In December, we started remote reads for billing purposes down in the Bakersfield area, so those customers will no longer have meter readers coming to their homes.

We chose a powerline carrier system for the electric meters, and radio frequency (RF) for our gas meters. The RF networks have more capability and we are looking actively at advanced RF solutions for possible deployment. The costs continue to decline and functionality continues to increase.

We also have an attractive demand response tariff design rolling out next summer that will allow customers to realize the value of having these meters.

What strategies have you implemented to strengthen your relationship with customers?
JC: We alert our customers to the fact that we will be deploying meters in their areas. Added to that, we have a significant marketing plan for promoting a demand response tariff that will allow customers to take real advantage of time-differentiated electricity pricing. Customers will be able to sign up for this tariff. In exchange for a lower rate overall, customers will agree to higher rates during certain hours on up to 15 critical peak days each year. The utility will notify customers of the critical peak day in either an email or a phone call on the day before. This will give customers time to plan for reducing their energy usage on that day. .

How do you manage energy theft, and what measures do you have in place for data security?
JC: All the new meters and the communication network being used have tamper alarms, so there is a good system in place to guard against theft.

As far as security of data is concerned, many companies are moving towards internet protocol, so we are all well aware of security on data transmission. The system we have certainly has adequate security measures in place, primarily because we don’t combine customer data with usage data. The industry itself is moving towards highly secure communications like IP, which has the ability to manage security issues with regular updates and patches.

What R&D activities will you be looking at in the metering area?
JC: The first is the meter. Today, the vast majority of our meters are electromechanical meters. We would like to move away from these meters to solid state meters, which have the ability to store information in the meter itself and provide greater functionality. For instance, solid state meters have the ability to time-stamp outages and to store time-of-use information. It used to be that the residential meter was a very simple device and the commercial meters had a lot of functionality. Now meter manufacturers are offering residential meters with greater functionality. Being able to remotely turn the meter on or off is another advantage; the meter industry is moving more towards these connect/disconnect capabilities.

Something else we are looking at is providing real-time data back into customers’ homes. This capability will advance home area network adoption. The existing systems are very expensive, but we’re excited about this opportunity as it will allow customers to monitor their own usage, although what is even more exciting are devices in the home that respond to a home energy management system.

The third area is the networking capabilities. A couple of things are happening in this space, one being the increased availability of systems that rely on open standards. Then  you can use your communication network to manage your own in-home energy network – for example, being able to integrate other devices such as solar panels onto your own home network.

What is the vision for the utility as far as metering is concerned?
JC: We have expanded our vision of our communications network so that it becomes an enterprise-wide network for all utility data, including meter reading. Maybe today you use it for meter reading, but you have to expand it to include other purposes. We have to ask ourselves what network capabilities will we need in five to ten years? We started down this path five years ago, with limited choices in terms of what was available. Now the industry and the market have expanded so much, we are able to develop our network and our technologies.

Thank you for your input.