Joel Westvold,
AMI director,
Portland General
Electric
 
For Portland General Electric the efforts to deploy AMI are only the beginning and it sets the foundation for a broad array of customer services and cost reduction opportunities that will continue to be developed and deployed long after the system is deployed, says the utility’s AMI director, Joel Westvold, in an interview with metering.com.

Please start by giving a brief history and current overview of PGE.
Portland General Electric (PGE) is Oregon’s largest utility, with more than a century of experience in power delivery and customer service. PGE is an independent, investor-owned utility and the sixth largest company in Oregon. We receive strong oversight from state and federal regulatory agencies, including the Oregon Public Utility Commission (OPUC) and the Federal Energy Regulatory Commission (FERC).

Our service territory covers more than 4,000 square miles and we serve more than 808,000 residential, commercial and industrial customers in 52 Oregon cities. Every day, more than 1.5 million Oregonians count on us to generate and deliver safe, reliable power – at a reasonable price – to their homes and workplaces. In fact, we provide electricity to almost half of all Oregon homes and businesses; no electric utility serves more Oregonians than PGE!

What are some of the key challenges that PGE faces?
PGE faces many of the same challenges as other mid-size utilities including providing reliable, reasonably priced power using a diverse mix of resources to serve a growing customer base.

Please give an overview of PGE’s metering operations and projects that are under way.
PGE’s metering operations are performed by the Meter Services department. This team provides energy measurement services for its 808,000 retail customers. The department’s mission is to ensure timely, cost effective technological solutions to energy measurement issues, which includes evaluating and testing new technology. PGE’s current meter inventory is approximately 807,000 meters in the field — everything from high-end commercial and industrial metering to the basic residential watt-hour meter.

In recent years, Meter Services has worked closely with the business side of the utility on testing and piloting several advanced meter reading (AMR) systems. For the upcoming AMI project, Meter Services is responsible for exchange of all transformer-rated commercial meters and for acceptance testing of all of the new meter platforms being used for the AMI project. (A contract meter installer, Wellington Energy Inc., will perform most of the residential and small business meter exchanges.) Meter Services also works closely with the meter vendors to ensure proper programming of the new meters and for identifying and helping to resolve any technical and quality control issues that materialize.

What steps and plans do you have in place to implementing AMI and/or a smart grid, and what do you envisage as the key benefits?
For more than a decade, PGE has been evaluating and piloting various advanced metering technologies. Since 1999, PGE has conducted several pilots, built our meter data management system, which we call the Meter Data Consolidator (MDC), and deployed more than 6,500 automated meters in the field in various technology tests and pilots. Our – decade of work was recently recognized by Chartwell, which awarded PGE its 2008 “Best Practices in Advanced Metering and Data Management”.

PGE is now preparing for full “smart metering” deployment throughout its service territory – about 850,000 new solid state digital meters – beginning in June 2008 through December 2010. After an extensive proposal and negotiation process, we contracted with Sensus Metering Systems for a two-way, fixed network system. In May 2008, the OPUC approved our project and an accompanying 2.5-year tariff. System acceptance testing (SAT) began in June 2008 with full deployment scheduled to be initiated in January 2009. During the testing period, we will roll out approximately 16,000 meters in urban and rural settings to test the vendor’s technology, as well as our entire end-to-end, meter-to-bill system.

We have pursued AMI based on the belief that smart metering is the right choice for our customers because it enables us to (1) achieve operational efficiencies, reduce costs and improve cash flow; (2) provide new and improved services to our customers; (3) offer demand response, direct load control and other cost effective programs; and (4) prepare for the future with infrastructure that will support a two-way “intelligent grid”.

Our business case identifies $18 million in annual cost savings and other benefits to customers in the first full year of implementation (2011). Operational savings and customer benefits will result from reducing meter reading costs as well as from various business process efficiencies and improvements in distribution asset management.

I’ve included below some of the specific benefits we expect to obtain. In many instance, we have made specific commitments to our regulators to obtain these benefits:

  • Meter reading savings. About 60 percent of the AMI cost benefit results from a significant reduction in labor and associated vehicle, fuel and maintenance costs as meter read routes are converted over to the network.
  • Reduced customer contact center costs. The system will provide the “most recent” meter read (usually prior day or early same day) for customer service representatives to resolve high bill complaints, complaints about missed or estimated reads, meter access problems, etc.
  • Reduced billing costs. Savings in the area of customer billing are primarily related to reducing the number of service order dispatches to customer premises when customers wish to close their PGE account.
  • Customer selected due date. The new system will enable meters to be read for billing purposes on the day that best coincides with the customer’s preference for their payment due date.
  • Load monitoring and forecasting. AMI will provide daily inputs to the load forecast, versus monthly. Since all smart meters collect interval data and can be used for load research, varied samplings and many load studies can be undertaken.
  • Transmission/distribution/generation planning. Accurate, geographically specific usage data will enable our operations personnel to more effectively plan and manage transmission, distribution and generation systems. Data can be assembled at the individual customer or feeder level up to the transmission level. Better data enables more effective utilization of existing resources, including individual transformers.
  • Service connections from the office. The capability of the system to perform remote service connects and disconnects will significantly reduce the number of field visits we need to perform.
  • Outage detection, mapping and restoration. Once we’ve integrated AMI with a planned new Outage Management System (OMS), we will be able to identify the extent of outages and monitor the progress of restoration activities. This will help us minimize unnecessary dispatching and crew costs, and speed up service restoration.
  • Tamper and theft detection. The technology includes tamper detection alarms and other capabilities to detect the possibility of energy theft or diversion. Once the system is deployed, PGE can also perform data analysis on interval meter data to help determine possible theft.
  • Reduced field service calls. The new system will enable operators to “ping” a meter to determine whether there is power at the meter. This aids in faster resolution of the customer inquiry and can save an expensive service call.
  • Access to interval data. We are recording interval data on all AMI meters in either 60-minute or 15-minute (most commercial) intervals. The availability of interval data enables multiple new services for customers as well as improved load management and system planning capabilities, as described below.
  • Demand response/direct load control programs. The ability to support demand response or direct load control programs – either through price signals or direct control over the power supply to equipment or appliances – is an important capability of the new system. We have not committed to a specific plan nor included quantified benefits in our business case, but the OPUC is very interested in having PGE evaluate and propose these types of programs in the future.

The customer service benefits are:

  • Improved service. Two-way communications with every premise and interval data from every meter means that we can offer not only improved metering and billing services, but also a number of other service improvements for customers. These include real time pricing, customer selected due date, remote premise monitoring, usage alerts, energy management, remote home control, power outage notification, etc.
  • Faster transactions. The ability of a customer representative to order a final meter read without having a meter reader make a special visit to the customer’s premise makes it possible to prepare the customer’s final bill and close out, as well as open, an account more quickly.
  • Customer privacy. Many customers object to having meter readers on their properties. Automated meter reading virtually eliminates this source of customer complaints.
  • Energy management. The capability to deliver interval data to customers, which we expect to be able to implement within the next several years, will enable us to help customers make informed decisions about ways to better manage their energy use. The availability of this data also enables the customer service representative to deal efficiently with customer calls that require current meter data to resolve.
  • Rate design. Since we can collect interval data or time-of-use (TOU) register reads every day, we can offer our customers advanced rate designs, such as an extension of existing TOU pricing and critical peak pricing, or demand response programs. Customer will be able to choose the option that best meets their needs.

What strategies have you implemented to strengthen your relationship with customers?
PGE has an extensive AMI communications plan using a balance of internal and external communications tools including newsletters, advertising, website, media relations, customer service training, etc. The communications plan, which will be implemented throughout the smart metering program – from test phase through system-wide roll out – was developed to support PGE’s commitment to provide for future energy needs at a reasonable cost while taking good care of Oregon’s environment.

Smart metering and related programs can also support the customer communications theme “Powered by Oregon.” As they receive detailed usage data and take advantage of customized advice from us about how to save energy, customers themselves will be “powering Oregon.” As we develop communications to support smart meters, we need to look beyond operational details and focus on the big picture benefits represented by the meters, the information they can provide and the positive implications for the customer relationship with PGE.

In our current AMI test phase, we are also testing varying levels of customer notification. As part of our research into smart metering, we were interested to learn how different utilities have handled the task of customer notification in different ways. Some have undertaken major efforts to notify customers, while others simply switch out the meters and leave a door hanger behind. We're testing the concept of communicating with our customers in advance, with a personalized letter explaining smart meter benefits, a “knock-and-talk” with the meter technician, and a series of five door hangers developed to handle various situations. Our hope is that a thorough approach to customer communications will not only pre-empt any concerns about smart meters, but strengthen the relationship between the customer and PGE. As a control group during system acceptance testing, some customers will not receive the advance letter. Survey research following the test will determine the satisfaction levels of each group.

What R&D activities do you undertake in the metering area?
We are working with industry partners on an initiative that seeks to encourage appliance manufacturers to adopt standards and implement technology that will facilitate widespread implementation of demand response programs. We were unsuccessful this year in obtaining a U.S. Department of Energy grant for this initiative, but are moving forward with other efforts to participate in existing industry organizations to encourage the market to adopt a communication device/standard that will gain widespread acceptance within the appliance industry.
 
The specific goal is to create a low-cost interface at the appliance (i.e. a “demand response-ready” appliance). This interface would allow the customer to install a communication device at the interface socket thereby permitting the utility to provide control assistance via price and/or direct load control signals. We hope to be able to:

  1. Demonstrate greater customer acceptance of a demand response program with a DR-ready appliance
  2. Demonstrate a lower marginal cost in $/kW controlled, than is possible with conventional programs where the utility installs a control switch at the existing appliance, such as a water heater.

What is your vision for PGE?
As it relates to AMI, the efforts we’re undertaking to deploy the system and capture the benefits are only the beginning. AMI sets the foundation through the collection of interval data and the two-way communication capabilities for a broad array of customer services and cost reduction opportunities that will continue to be developed and deployed long after the system is deployed.