As the heat soared outside, the thermostats in Southern California Edison's (SCE; Rosemead, California, U.S.) headquarters were set to 75°F (24°C) and the lights were automatically set to turn off at 6 p.m. Even the utility was not immune to the state's 2000-2001 power crisis, which brought record spot-market prices and rolling blackouts to the state's deregulated electric business. Something had to be done. Enter California's Real-Time Energy Metering Program.
The Real-Time Energy Metering Program was launched by emergency legislation signed by California Gov. Gray Davis on April 11, 2001, in response to the California energy crisis. The legislation provided for US$1 billion of energy crisis mitigation measures, including $35 million to implement real-time energy metering (RTEM) through contracts administered by the California Energy Commission (CEC). Other investor-owned utilities and municipal utilities in California also participated.
The project scope was for the purchase and installation of advanced interval metering, and related metering communications and end-user information/notification systems for all commercial end-user accounts with peak demands exceeding 200 kW. Installation of such equipment and systems provided customers of these accounts with the ability to access their interval usage information, updated on a daily basis via the Internet. This was anticipated to support customers in their ability to effectively manage their loads in response to real-time pricing rates and demand responsiveness programs.
SCE had approximately 11,000 accounts that qualified for participation in the program. Since some accounts required the use of multiple meters, SCE estimated a total of 12,000 meters to be included in this project.
Figure 1 illustrates the high-level flow of data from the meter to the customer. Prior to the start of the project, SCE had virtually no infrastructure to remotely collect meter data and communicate this back to the customer. All 12,000 meters had to be replaced, and a communications infrastructure had to be built and integrated into SCE's existing manual customer data acquisition system (CDAS). SCE created a Web site — www.sceenergymanager.com, and built a link for the meter data to transfer to the Web site. Meter readers no longer read these customer accounts because this data is also sent to SCE's existing billing system for monthly customer billing.
In an effort to ensure deployment of the most cost-effective and technically feasible solution, SCE conducted a request for proposal (RFP) process to solicit proposals from 12 qualified bidders. Four bids were received and evaluated based on cost, technical merits and ability to meet schedule. One of the challenges of the project was the geographic dispersion of the 12,000 meters across SCE's 50,000-sq-mile (130,000-sq-km) service territory. Many of the then-available remote metering solutions were only cost-effective for dense and contiguous deployments. Another challenge was the project time line. SCE anticipated having to use an existing network to avoid the lengthy and costly process of building one. SCE selected the bid from Landis+Gyr's (Lafayette, Indiana, U.S. [formerly Siemens Power Transmission & Distribution Inc.]) because it solved these and other challenges, was lowest in cost, and met the technical and schedule requirements.
The Landis+Gyr S4 meter was used in all applications except for a small number of accounts where compensation metering was required. The S4 meter records real and reactive power in 15-minute intervals and has pulse output for connection to a customer's existing energy management system. The S4 comes with one of three communications capabilities — SmartSynch two-way paging module, phone modem or RS232 board — all under the meter cover (Fig. 2).
- Paging via Smart Synch and SkyTel
On a life-cycle basis, the paging solution was the most cost-effective of the three technologies and was used where SkyTel paging coverage was adequate — in about 85% of the installations. The paging S4 meter was also the easiest to install because additional site work was not required, whereas it was with the phone and RS232 solutions.
SCE's meter technicians performed all of the meter installations for this project. Prior to changing out the meter, the meter technician first determined the quality of connectivity to SkyTel's paging network at the existing meter location to ensure reliable meter data retrieval. This was done by holding a coverage validation unit (CVU) near the existing mechanical kilowatt-hour meter to check for the number of base receivers seen at the socket. Sometimes, signal strength of the network was below the minimum requirements with the internal style pager antenna. When this occurred, the test was performed with an external style antenna to enhance connectivity to the network. External antennas were used on approximately 10% of jobs.
If the minimum requirements were met, the meter technician proceeded to install the meter. The panel had to be rewired because the original metering equipment — consisting of a separate kilowatt-hour meter, a kilovar-hour meter and, for accounts over 500 kW, a solid-state Data Star recorder — was being replaced by a single, multifunction solid-state meter (Figs. 3a and 3b).
Despite using SkyTel coverage maps to avoid sending meter technicians out to marginal-coverage areas, sometimes the minimum requirements for connectivity to the network could not be met even with an external antenna. In these cases, the meter technician noted on the job paperwork that the metering site had no pager network coverage and a site assessment was performed to gather data on the feasibility of a landline phone installation and quality of connectivity to SCE's existing private radio network. The lowest cost of these alternative solutions was determined based on site information (such as whether trenching was needed to get a landline phone installed vs. the number of additional routing radios needed to gain connectivity to the private radio network), and the meter technician performed the installation with the alternate communications technology.
- Telephone-Based Communications
Where SkyTel paging service was not adequate, or the meter panel was located in a basement or was otherwise obstructed, landline telephones or radio communications were used.
The difficulty with landline phones was that three different entities were required to complete the installation. Telephone service was ordered through the local telephone company; an SCE meter technician installed the meter and phone connection junction box; and an external contractor was used to extend the phone line from the phone company point of demarcation to the junction box on the meter panel.
Occasionally, the phone company's address for the customer differed slightly from SCE's address, making it difficult to identify the correct site. In other instances, the location of the meter panel was not obvious to external personnel (“second barn on the left side of the dirt road”), requiring multiple trips to complete the installation. Meter data collection is achieved through Itron's MV-90 application. About 10% of the RTEM meters were installed with telephone-based communications.
- Private Radio Network
The third alternative communications solution, used for the remaining 5% of the project scope, was SCE's existing private radio network, which is used for distribution automation, limited remote meter reading and various other remote telemetry applications. In this case, the S4 meter with RS232 output was connected to an external radio mounted on the panel.
SCE's UtiliNet radio network is a wireless data communications network of spread-spectrum radios operating in the license-free 902- to 928-MHz area of the radio spectrum. Each radio in the network is both an end-device counterpart and a repeater in the wide area network. In about 10% of the installations, a second routing radio was needed to gain connectivity to the network.
For all three communications solutions, the interval meter data is brought into SCE's CDAS during the night and processed for display by the next morning on the SCE EnergyManager℠ Web site.
Itron (formerly Silicon Energy) was chosen as the provider for customer access to usage information via the Internet. This was done via an integrated software package, including supporting hardware and software and professional services. The system is known to SCE customers as SCE EnergyManager (Fig. 4).
|Reasons for Using SCE EnergyManager||Percent of Users|
|To compare energy usage for different time periods||70%|
|To develop strategies for reducing monthly bills||60%|
|To associate daily load patterns with specific equipment or operations||58%|
|To evaluate the effect of modifying equipment or energy usage patterns||55%|
|To produce reports for management||48%|
|To investigate questions about a monthly energy bill||43%|
Meter data from the previous day is sent to SCE EnergyManager for display to the customer the next morning. Customers have a variety of preformatted reports from which to choose. These reports can be generated for specific time frames, such as the last 24 hours, the last month and the last year. Customers can view charts comparing two different time frames for a single facility (such as July 2002 vs. July 2003) or two different facilities in the same time frame (Fig. 5).
Following the meter installation and confirmation that the Web site is reliably receiving data, the customer is sent a User ID and password along with sign-on instructions and fact sheets of the various energy rates and load management programs available.
One of the main objectives of the implementation was to make it easy for the customer to use the system with little or no training. However, for customers to maximize the use of the system, SCE conducted hands-on training sessions throughout its service territory. In addition, SCE staffs a program management office during business hours to assist customers with the Web site.
According to a recent survey, customers who use the system report that they are satisfied with it. The survey specifically found:
Three-fourths of users say the software is easy to understand and use.
About 40% of users say they have shifted energy usage away from on-peak hours and/or reduced their overall energy usage by using SCE EnergyManager.
Almost half of users say they have reduced their energy costs using SCE EnergyManager.
“I use SCE EnergyManager to share our successes and to present energy-saving opportunities to management and our supporting contractors. I find greater understanding from those involved when I can graphically present energy savings opportunities. It's a great tool for tracking results of our efforts to improve our energy efficiency and maintain those results.”
“The SCE EnergyManager program is simple and fast. Anyone with a computer can log on and benefit from it,” says Bob Harvey, district facilities manager for Sears, Roebuck and Co.
The table above shows the top reasons SCE EnergyManager users gave for using the system.
“I use SCE EnergyManager to track daily performance at several of our Sears retail stores,” says Harvey “I look for anomalies in the usage charts, such as after-hours or overnight usage. I can see when AC units or lighting have been left on. I also use the program to track our progress with energy savings programs when we've installed a new device or made programming changes. After normal maintenance of AC units I track usage, looking for additional opportunities.”
While the CEC and SCE hoped at least some of the meters would be installed during the summer of 2001, several technical and regulatory challenges delayed the project start, and the majority of the project was completed in 2002. Despite conducting a 50-meter proof-of-concept test prior to deployment, start-up issues arose with both hardware and software, including a manufacturer recall of the first shipments of meters and system problems at a couple of distance thresholds (3000 and 10,000 meters), requiring extensive troubleshooting of both internal and external systems and processes.
Through the perseverance and dedication of the SCE project team and exceptional cooperation of the suppliers, this system is fully operational today and ready to be put to the test with the new demand response programs created for California electricity customers.
Now that the advanced metering is in place, the state and participating large customers can benefit by the new energy rates and load management programs currently available. SCE's Demand Bidding Program (DBP) is an Internet energy-bidding program offering bill credits for load reductions during DBP events, which are triggered either by high prices or by a transmission system emergency. SCE's Critical Peak Pricing program is a summer season program designed to encourage customers to shift peak power usage to mid- and off-peak time periods by offering lower mid- and off-peak prices, but significantly higher prices during Critical Peak periods. These and other programs are expected to play a major role in SCE's energy procurement plan in 2004.
In addition to the energy cost-management benefits, SCE realized some less-tangible benefits, such as fewer and timelier pick-up reads for this RTEM meter population; the ability to monitor customer generation into the transmission grid on a real-time basis; and the ability to quickly accommodate new energy rates and load-management programs for customers under 200 kW, should they be mandated by the state or otherwise desired.
SCE believes that more load-management and demand-response programs will be a strategic component of SCE's future as the utility continually strives to save energy, keep prices down and preserve the environment.
The RTEM project was a significant step toward that future.
Kevin Wood is the manager of Meter Technology Deployment in the Customer Service Business Unit at Southern California Edison. She is responsible for the technical specification, selection, procurement, deployment, reliability and quality of all metering products used on the SCE system. Wood has worked in the electric utility industry for 22 years and holds a BSME degree from Cal Poly, San Luis Obispo.