Q: In 1997, as Puget Sound Power and Light, you merged with Washington Natural
Gas and became Puget Sound Energy. Was it then that automated meter reading
made the most sense?

A: We were piloting different technologies in 1997, communications technologies
that would actually deliver the metering information to us. At that time, most
of the automated meter-reading technology that was available was really just
drive-by metering. And so you were able to make meter reading more efficient,
you didn’t have people running around all over the place, you could drive by
in a car, and you could remotely read the meters from a van or a vehicle.

Q: You would capture the radio frequency signals?

A: Right, exactly. It was a more efficient way of reading meters. We were really
looking at a way to get information off of the metering system in a manner in
which you could do more than just read meters with it. You could actually provide
that information to customers. They could manage the energy usage. We would
be more familiar with usage patterns and could manage our own resources better.
Customer information people would have that information available to them when
talking to customers. And our planners would be able to use it in the system
design. Simultaneously, we set about to develop a new customer information system.
We also recognized that the customer information systems that were available
at that time only had the capacity to manage the meter-reading information from
a once-amonth read and produce a bill. And we wanted a system, and then ultimately
installed a system, that would give us daily reads; and if we wanted to we could
have even done hourly reads. But even daily reads over a million-and-a-half
meters, that’s a lot of information, so we had to have a new CIS system that
was capable of managing that kind of information and then actually producing
a bill from it.

Q: What is the primary technology that is used to feed the information to
the home office?

A: The system that we installed was a Cellnet system. At the time it was a
state-of-the-art system. We had designs on making it a two-way communications
system, but it just wasn’t available then. So we installed a one-way system.
We could get the reads off it, but it was not designed specifically for the
utility to be able to control loads off of that system as well. So it was primarily
an information-gathering system, and it worked very well for that. And that’s
the one that’s in place at Puget Sound Energy today.

Q: And it’s still only one-way today?

A: Puget Sound Energy’s AMR deployment was the largest in the country when
it was installed, and we did some programs with it that were the first of their
kind. And at the time it was state of the art and we really had some fun with
it and we did differentiate ourselves. We ran some pretty important programs
on the West Coast during that energy crisis that helped the utility by the fact
that we had that system installed.

Q: Who built the CIS to go with it?

A: We developed it ourselves. We put a team of people together internally and
charged them with the responsibility of developing a system. And it went relatively
well. We completed the development through a subsidiary company we formed called
Connext. We formed Connext because when the development was complete it was
going to be one of very few systems that had this kind of capability, and we
wanted to be able to sell it to others.

Q: Who else had a hand in implementing the system?

A: There were basically two technologies at the time that were competing then,
and we piloted both of them. We put two 10,000-meter pilots in place. We tested
most of the systems and the technologies that were available at the time to
give us the kind of communications capability that we sought. We did not want
to do drive-by. We wanted it to be able to do more than just read meters. That
was a No. 1 criteria for us. So that limited us to two possible suppliers at
that time.

Q: What was the first big test for the system?

A: We were probably about a little over halfway through our deployment in 2000
when energy markets on the West Coast really began to heat up. And in the fall
of 2000 we said, look, we’ve got enough of these meters installed now and operating
– you can incrementally put them in and start using them immediately – that
we could actually use this system to do some pricing options to see if we could
get customers to reduce demand. We had our CIS system installed, so we had the
ability to take the information in and actually produce a bill based upon time
of use. Customers would get price signals four different time periods a day
and would be able to move their usage around to different times; and if they
moved it into the off-peak hours, we’d give them a rate break below what they
would pay under a flat-rate scenario. So the Washington State Utilities and
Transportation Commission noodled over that – not for very long, only about
27 days – and said OK, do it. So for 150,000 customers, they immediately got
put on this time-of-use program. If they had a computer, they could bring it
up on a daily basis and see what their usage was in each of those time periods.
A survey later showed a very high percentage of people said they were actually
utilizing the information.

Q: Was there confusion going from a flat rate to time of use?

A: We put people on a pricing mechanism. We sent information to them because
they didn’t have a choice. And all of a sudden the bills they were going to
be paying were going to be based upon time of use. We had interveners in the
hearings who didn’t like that. They thought it was too much, too soon, and it
would not be well-received by customers. That summer – we put it in place April
1, 2001 – we did some survey work with the customers, because the commission
wanted us to come back in the fall to check our results and see if the program
should be expanded. The results were in the high 80s for the percentage of customers
who said they were actually doing things to shift their usage from on-peak to
off-peak. The feedback we got from the customer surveys clearly showed they
liked it, they didn’t feel like they had been put upon, they liked the idea
that they could actually save money by shifting their usage from on-peak, and
they thought they were doing something for the environment and to help the West
Coast energy crisis.

Q: Is now the time for utilities to install AMR?

A: The energy markets have stayed pretty stable. At least stable enough that
utilities haven’t had the kind of changes in retail rates that utilities had
to put in place to pass those costs through to customers in the past. This is
the opportunity to get the technology in place so that when we get volatile
markets or an energy crisis because of high temperatures in California or low
snow packs in Washington or whatever it is, the mechanisms are in place to deal
with it. The longterm real key will be to demonstrate not just time-of-use but
real-time pricing. My opinion is, that’s where this needs to go: where customers
can see, in near-real time, changes in the market, and if markets are low they
can use as much energy as they want, and if markets are high they can choose
to cut back wherever they want to cut back. So I’m a real advocate for real-time
pricing, and the good news is there is technology available today capable of
delivering it.

Q: Is AMR on the verge of expanding dramatically?

A: I believe it is, but few utilities are even looking at this as a strategic
asset. They still look at their generation investments as strategic, because
there’s so much money involved. Meter-reading systems are not inexpensive, but
compared to generation they are relatively small. While I love that the name
has changed from AMR to advanced metering infrastructure, I think most executives
aren’t that interested in meter reading. But I believe that just the change
in nomenclature itself to AMI will be helpful in getting people to think more
about it and its capability beyond just meter reading. But it’s going to take
regulators and policy makers to make this expand dramatically. The good news
is, in many parts of the country, they are playing close attention and getting
involved with their utilities to make it happen.

Q: What will hinder expansion?

A: Several things. There are states that are regulated and deregulated with
no indication of which way we’re going. There are still questions about who
is going to be responsible for the metering long term. Are utilities going to
stay in the metering business, or is some third-party provider going to come
in and take over the metering business? As long as those kinds of questions
are hanging around, it’s going to be difficult for utilities given that kind
of risk potential to invest tens of millions of dollars in a new system. I’ve
believed that it makes no sense for utilities to get out of the metering business.
The metering information can be shared, but the responsibility needs to be with
the utilities. I suppose a case can be made that this is really a non-issue.
After all, even if somebody else took it over, they’d have to take over the
utility’s meterreading system, whatever it is. So the utility has someone to
buy it. Unfortunately, it’s still a question mark.

Q: Will technological advances help sell AMR?

A: Without a doubt the answer is yes. State-of-the-art systems not only remotely
gather the metering information from customers over a variety of systems, including
fixed wireless networks and power line carriers; they now have two-way capability,
allowing the utility to control utility system devices as well as customer end-use
devices. These capabilities expand the value of the systems to the utilities.
In addition, some companies are designing programs that assist utilities and
their customers in using the information obtained over these systems to drive
costs down and manage usage. When Puget Sound Energy was providing its customers
with time-of-use pricing and daily usage information, customers were pretty
much left to shift their usage on their own. Today, energy management hardware
and software exist for use inside the home or business. There are companies
designing systems that will respond to utility price signals and automatically
change home or business usage patterns to accommodate whatever price signal
is being delivered by the utility. From a consumer perspective, there’s some
really neat stuff coming together now that will include things other than just
energy management. A customer will be able to buy systems that incorporate Internet
access, TV, CD, DVD, radio and telephone in addition to energy management. When
this happens, we’ll have consumers helping to drive this market and we will
no longer have to rely solely on the utility.

Q: Do the cost benefits also help sell the concept?

A: When state commissions take a look at a utility’s investment in this, they
look at it through the window of utility only. That utility has to kind of stand
on its own, either from internal efficiency or the price it’s paying for power,
to cost-justify it. While we were implementing our system, a study was done
that showed the economic benefit to U.S. customers, just from their ability
to manage wholesale prices, if all homes in the country had AMI. It was like
$15 billion a year in savings that would accrue across the country to customers
if they had the tools in place to manage usage during times of peak pricing.
Nobody incorporates that kind of economic benefit into their cost-effectiveness
and analysis. And it’s probably one of the biggest benefits that will ultimately
happen when you have a broad deployment of these systems.