Getting on the grid

The idea of smart metering is taking the utility industry by storm, and Pacific Gas and Electric Company has been leading the charge with its SmartMeter program.

“ With SmartMeter, PG&E is the largest investor-owned utility in North America committed to deploying smart metering technology to its entire customer base,” says Andrew Tang, Senior Director, Smart Energy Web, for Pacific Gas and Electric Company. We are also the largest utility in North America well into full-scale deployment of the technology. Very few smart metering programs are as ambitious ion scale and scope as ours.”

PG&E plans to deploy over 10 million gas and electric meters through the end of 2011. It has already upgraded or replaced over a million meters, and continues to deploy at a pace of between 10,000 to 12,000 meters per day.

Customer benefits

One item of good news for customers is that the program is self-funded: overall, benefits exceed costs, though this doesn’t mean the program will break even right away. The bulk of program costs are incurred upfront, while program benefits are realized over a 15- to 20-year time period. This initial capital investment is offset by benefits over time, resulting in a positive business case.

Apart from not passing on any extra costs to consumers, the program also offers a range of other benefits. “The immediate benefit that we bring to our customers would be eliminating the need to visit the customer’s premises once a month to read the meter. The network we’ve put in place delivers that information remotely and automatically. In the past we’ve had situations in urban areas where the meters are in the garage or behind a locked case, or somewhere on the customer’s premises that is not accessible without having the customer let you in or leave the gate unlocked.

“These meters also allow us to take interval data. Instead of getting a monthly read and having no idea whether or not that electricity was consumed during the day or at night, we now have the ability to know exactly when that power was consumed. Initially, we will read the customer’s electric use hourly for residential customers and in 15-minute intervals for business customers.”

According to Tang, this allows the company to be very creative with its rate plans, similar to what happens in the cellular phone industry, which offers special rate plans for customers who make certain calls at certain times of day.

“We’re thinking of all types of time-of-use rates or even prepaid rates,” says Tang. “In the cellular industry, you can buy minutes, and you can then manage your budget by saying, ‘I’ll buy 200 minutes, and when I run out of minutes, I’ll buy more subject to whether or not I can afford it.’ We’re thinking of doing the same thing with electricity. It gives people more choice.”

Meeting challenges

PG&E is using the new program as a building block towards the establishment of a wider smart grid. One of the challenges it faces is making the change from a business that is focused on manual processes – for example, meter reading. “The scheduling of meter readers is automated but the process of reading meters is manual. That’s an example of where we’re going from a manual process to something that’s automated and using technology. The entire utility sector has immense implementation challenges ahead of it.

“Another way to think about it is if we used to collect one data point per meter per month. With SmartMeter, we are now collecting one data point every hour for residential and one data point every 15 minutes for commercial customers. We’re going from one data point per month, to 24 or 96 data points per day times 30 days. The challenge is, what do we do with that data? How do we store it? How do we manipulate it? How do we data mine it? How do we design programs so that customers can take advantage of this new ability we have to know how their electricity consumption is happening in hourly or 15 minute buckets?”

The move towars a smart grid will inevitably involve extensive replacement of aging infrastructure. How can this be accomplished without causing extensive disruption? According to Tang, this depends on whether you think deployment of the smart grid is a revolutionary process that needs to be implemented in the next two years, or whether you think it’s an evolutionary process that will take five or ten years.

“Our view is that it’s more of an evolutionary process. We have regular operating and maintenance expenses we incur every year. We can leverage these ongoing expenditures to replace our aging infrastructure gradually over time. The issue then becomes: How do we ensure we can communicate with this new equipment?

“A transformer, for example, used to just sit there and fulfill the function of stepping electricity down from one voltage to another. In the new world, we want it to also have sensors that will be able to tell us what’s going on with the voltage, what’s going on with that transformer and what sort of performance it’s seeing – to be able to monitor the performance of that transformer and send that data back.

“As we’re looking at our O&M cycle, we’re looking at putting in new transformers that will have this monitoring capability. As we’re looking at replacing switches, we’re looking at replacing them with switches that have a communications aspect so we can control them remotely.”

In demand

The introduction of smart metering at PG&E has also had an impact on demand-side management – getting customers to be careful about usage, especially during critical peak periods when electric supplies are stretched thin.

Historically, companies have done this through demand response programs. PG&E has 13 demand response programs with about 800 megawatts of electric demand it can call and curtail, but many of those programs are on separate networks: islanded or point-to-point solutions. The company is now investigating how to take demand response programs and integrate them with its SmartMeter program.

“Of our 13 programs, only two are focused on residential customers. Except for very particular instances, it’s hard to run a demand response program to a residence where the residence is only consuming a couple kilowatt-hours of electricity over the course of a day. It’s hard to justify the costs that it takes to put in the infrastructure to properly run that program.

“For a large demand response customer, we put in a specialized interval meter and a separate communications link, typically a 3G data card or perhaps even a dedicated POTS – plain old telephone – line. But the minute you have to put in a separate 3G data card or a POTS line, you have resigned yourself to the fact that it will cost between $200 and $500 a year to communicate with that meter. That was the old way of doing things.

“As we deploy this new program, and as every meter is then able to deliver interval data, the cost of deploying demand response programs decreases dramatically. Because we’re already putting in that communications infrastructure to read the meter, the incremental, marginal cost to communicate with that meter is very close to zero. Our cost now to read the meter with our network versus using the 3G network drops from about $50 a month to cents a month.

“The challenge is making sure that we’re looking at our business holistically and not in silos, and that we’re generating synergies across the business lines.”

 

Andrew Tang is Senior Director, Smart Energy Web, Pacific Gas and Electric Company. In this role, Tang has responsibility for clean air transportation (including plug-in electric hybrid vehicles), demand response and the energy information network underpinning the Smart Energy Web. Tang joined PG&E Corporation in 2007 in the Corporate Strategy and Development Group, focusing on special projects.