The next stop was down in Tampa. Known to some as “The Cigar City” or “The Big Guava” (attributed to the Latin-influenced festival Guavaween), Tampa is a burgeoning modern city with infused cultural characteristics. Located deep within the suburban sprawl, testament to the city’s rampant growth, one would find Tampa Electric’s Metering Operations office. And there, an early morning meeting was held with Metering Operations Engineer Wes Caldwell.
Give a brief history of the utility
Tampa Electric began operations in 1899. We serve nearly 667,000 customers. Of that number, 88 percent are residential and 12 percent are commercial, and our service territory is about 2,000 square miles. We’re an investor-owned utility that actually started out with street cars and ice.
We have three power stations that generate about 4,600 MW, so we generate most of our own energy. One plant is completely coal-powered, the second is natural gas-fired and the third is an integrated gas combined-cycle plant. All three plants have modern environmental controls and we are industry leaders in environmentally responsible generation.
Tell us a bit about yourself
I’m kind of a late bloomer in the utility industry. I spent 20 years in the Air Force as an enlisted electronics technician, and after that I attended the University of South Florida (USF) graduating with Bachelor of Science degree in Electrical Engineering. By chance, I started working with Tampa Electric as a co-operative education student while at USF and was eventually hired full-time as a senior technician in the Supervisory Control and Data Acquisition (SCADA) area until I completed the BSEE. From SCADA I moved to substation engineering, relay and control and then four years ago I moved into metering as the metering engineer for Tampa Electric. I’ve now been with Tampa Electric for a total of ten years.
Talk us through your metering program
Right now our primary deployment schedule is really focused around AMR, and we’re using Itron’s Centron meters. It’s basically drive-by or handheld devices for those readings. Roughly half of our residential meters have been converted to AMR at this point. The big reason for the AMR conversion is lower meter reading costs and O&M (operations and maintenance) costs are drastically dropping. In preparing for the future, we are trying to implement strategic pilots to test AMI technology and to identify the changes we are going to have to make to our processes and enterprise systems for AMI.
We’ve also started discussing emerging meter technology with our senior leadership. The Vice President of Energy Delivery, Bill Whale, determined the need to involve different segments of leadership in strategy development. He formed what we call the Smart Grid Initiative Coordination Team, a cross-disciplined team which includes members from telecom, IT, metering, customer service, distribution system service, security, and regulatory – everybody basically has a seat on the team. The team has been listening to presentations, gathering information, and has started to develop business cases for further implementation of AMI. It’s not going to be focused on the meter; the big cost is going to be in the infrastructure and the changes to enterprise systems.
Our first AMI pilot is small and consists of approximately 250 meters. We chose two of Tampa’s most recently erected high-rise buildings, which were built to the latest hurricane code. This means that a lot more concrete and steel were used in those buildings than might be found in other structures. We are testing the assumption that if the technology worked in these new buildings, it would work in other buildings. Eka Systems is the communication provider for the pilot, and we’re using both Centron meters and also GE KV2c meters. We are testing multiple meter forms and data streams.
What are you planning to do with the data?
In this first pilot we’re only using the data for meter reads. Storing large amounts of data will be an issue. I think it’s going to be a first-in, first-out file system; we can only keep large amounts of data for a certain amount of time before it goes to the great bit-bucket in the sky.
Most utilities will do the obvious things: restoration or outage notification, load profiling. We’re not there yet, but things could change. When we think about it, ten years ago a gigabit of data cost a few hundred dollars to store, now its a few dollars, and in a few years it could be mere cents. We could find ourselves keeping all the data and mining it for different purposes.
Tell us a bit more about the AMI program rollout
We may initiate a larger AMI pilot within the next year by utilizing 10,000 meters to test another aspect like remote connect/disconnect or demand-side management, which is a big issue in the State of Florida. One of those two are going to be major issues for us in the near future and the Smart Grid Initiative Coordinating Team is trying to build the business case: which do we do first? I think that in 2010/2011, we will probably start moving away from AMR deployment to AMI deployment.
Could you explain more about the Smart Grid Initiative Coordinating Team?
When Bill Whale took over as the Energy Delivery VP and was making his rounds through different departments, Karen Lewis, the Director of Meter, Lighting, and Fleet Services, asked me to give Mr. Whale a progression of metering leading to AMI. And of course his first question was “What do these AMI meters cost?” And the answer to that was its not what the meter costs but what the infrastructure costs to support those meters. The thinking changed from focusing on the meter to thinking more about the systems. The effect of an AMI system is corporate-wide; everyone is going to be impacted in the process. The team was formed to help educate leadership about AMI and Smart Grid and to help our leaders identify how AMI will affect their areas of responsibility as we move toward a Smart Grid.
How do you communicate change with your customers?
We communicate to our customers through a number of channels, including newspaper, radio, television, bill inserts, bill messages, the Internet (tampaelectric.com) and more. We recently activated a new energy efficiency advertising campaign promoting our free Energy Audits, Ductwork, Insulation and other energy-saving programs. The campaign includes both televisions spots and newspaper ads.
Also being promoted through the campaign is our new Energy PlannerSM program (also known as price responsive load management). With the use of a programmable thermostat, this innovative program lets customers control the operation of one or more central heating and cooling systems, electric water heaters and pool pumps when varying prices for electricity are lower than the standard residential rate.
Energy Planner offers four pricing rates for electricity (Low, Medium, High and Critical). The price customers pay for electricity is based on usage, time of day and day of the week. The Critical rate can become active at any time and reflects the increased cost of providing electricity during times of extremely high demand. The Critical rate will not exceed 1.5 percent of the total hours in a year.
Our Energy Planner program started out as a small pilot of 250 customers. If all goes as planned, the recently launched program will install between 150 – 200 customers per month.
What do you see as the vision of the utility with regards to metering?
I think that the vision of Tampa Electric has always been working from the ground level up. We will have the vision that metering is equal to our other components. In controlled systems, you have a feedback circuit, and metering has developed into that feedback circuit. It will truly give our senior management the pulse of how the entire electrical distribution and possibly transmission systems are operating.