Ask any electric utility employee about the meter-to-cash cycle, and you’re likely to elicit an informed discourse on how this time-honoured process works. For decades, the electric utility’s revenue intake has been governed by this predictable process. Monthly meter readings generate bills, bills generate payments, and customer care handles the resulting issues and questions that arise as a result of meter readings, bills, payments – as well as estimated readings, late or non-existent payments and a host of other items. Now, new technologies are starting to shake up these processes.

Meter reading and customer care converge

With the advent of advanced metering infrastructures (AMI) and automated meter reading (AMR), the distinctions between meter reading and customer care will blur even more. Instead of a cycle that often includes weeks between reading and billing, utilities and their customers will have far more rapid access to consumption data. In addition, bill data will be available in less time, shortening – in some cases, eliminating – the lag between reading and billing. And for utilities that roll out AMI, the ability to poll meters at intervals throughout the day means they and their customers will have near real-time information about usage patterns. This is likely to have a significant impact on customer behaviour in both positive and negative ways. Many utilities’ business cases for AMI rollouts include the positives of demand side management whereby customers who can see real-time usage and the corresponding spend will reduce their consumption. Offering this level of data to customers while simultaneously rolling out numerous pricing plans could initially confuse customers and make the billing process more onerous for utilities’ customer care operations. Educating the customer base repeatedly before rolling out AMI is an imperative, while at the same time making sure that systems and their related processes and people are ready to handle such a significant change.

Smart metering: Benefits up and down the line

Improved access to data and tighter reading/billing timeframes are just some of the advantages attributed to ‘smart metering’. But the anticipated benefits of AMI and AMR go far beyond data exchange. In some instances, customers will be able to initiate or stop service with a phone call – and without the need for an onsite service call. Customers and utilities should expect to be able to work together to understand usage patterns and improve conservation opportunities, and to develop creative rate plans to reward customers who adopt utilities’ new rate and conservation plans.

Ultimately, smart metering brings with it the promise of improved load management and long-range planning. Eventually, better information at the utility level could feed regional and national grid analysis, thereby giving consumers more reliable and consistent energy. Utilities will be better prepared to deal with growth, anomalies and all of the external forces that impact energy delivery.

Taken a step further, higher quality and more discrete levels of usage data could help utilities determine the location of outages far faster and roll the appropriate assets to quickly address problems by seamlessly integrating with their outage management system. When the power does go out, the handshake between systems will enable the utility to take proactive action, rather than waiting for customers to report outages. This would result in fewer ‘truck rolls’, which should reduce the cycle time on repairs and the utilities’ overall costs of maintenance.

A look at early adopters
Community-owned utility focuses on customer benefits

A number of US utilities of varying size and type are among the early adopters of AMI/AMR technology. Florida’s Jacksonville Electric Authority (JEA) is the eighth largest community-owned electric utility in the US, serving more than 750,000 accounts. JEA is well on its way to retrofitting its entire system with electronic meters. As of April of this year, JEA has replaced more than 570,000 meters since launching its Network Meter Reading project five years ago. According to JEA, it expects the $150 million project will save about $17 to $20 million a year over its current system.1 JEA anticipates its investment will also save customers money while improving service. Among the expected customer advantages, JEA cites:

  • More accurate billing
  • Proactive outage identification and real-time intelligence on failing transformers to prevent unplanned outages
  • Reduction in required visits from meter readers
  • Easier access to daily customer information for its customer care department
  • Faster identification of meter tampering
  • Lays the groundwork for future customer benefits, such as advance warning about high bills, access to usage data, flexible billing period and conservation initiatives. At the same time, JEA expects to reap the following internal benefits:
  • Virtual connects and disconnects with on-demand reads, saving about $2 million yearly
  • Expedited outage responsiveness, saving up to $1 million annually
  • Accuracy of system meter assets and installations, a savings of $5 to $10 million yearly
  • Improved tamper and unbilled services detection, saving up to $1 million annually
  •  Improved system planning and load management, with forecast savings of up to $1 million annually
  • Reduced generating plant capital investment, based on a calculated 1% reduction in system load, resulting in $30 million in deferred costs

California utility sees AMI as protection against blackouts

On the West coast, San Diego Gas and Electric (SDG&E) expects to deploy an AMI system by 2011 for its 1.4 million electric meters, as well as 900,000 gas meters. The utility has applied to the California Public Utilities Commission (CPUC) for cost recovery and rate design for an AMI deployment. In its testimony before the CPUC in March of this year, SDG&E states that “one of the most promising areas of improvement is outage response. ….”

Other expected advantages include the ability to design effective demand response programmes, which “could enhance overall system reliability and may, therefore, mitigate the extent, frequency, and duration of rolling blackouts.”2 SDG&E also anticipates more accurate and timely bills, stating that fewer billing errors and adjustments will eliminate approximately 4,000 electric re-bills per month and will reduce billing exceptions by 35%. Further, the customer service staff will have access to near real-time usage information, which will expedite bill inquiries that account for a large percentage of customer calls. In addition, customers will be able to schedule same day service orders, and start and stop service on the day of their choice.

Internal benefits that will accrue include employee safety, since fewer service personnel will be required in the field and on the roads. SDG&E also expects its cash flow to improve, since, historically, 15 to 20% of meter reads have not been available on the day the account is to be billed. Cost reductions will include the elimination of hand-held devices and mobile data terminals by 2014-2015. By 2010, SDG&E forecasts total benefits from AMI at more than $15 million annually, increasing to more than $22 million annually by 2011.

Other utilities across the nation are moving forward with AMI projects as well, including Pacific Gas and Electric, which received CPUC approval to launch its $1.7 billion plan to install 9.3 million Smartmeters™ for its 5.1 million electric and 4.2 million gas customers. The CPUC also approved PG&E’s proposal to offer customers a critical peak pricing option, giving enrolled customers a nearly 3 cents/kWh reduction in rates during specified periods.

AMI: One size does not fit all

The AMI/AMR business case will vary depending on utility type, geographic area, customer profiles, state PUC’s, local governments, and a host of other variables. Therefore, every utility should identify its own unique objectives, be they improved customer service, healthier cash flow, cost reductions, or other factors. For example, the pressures on a municipality to take a personal interest and provide the best customer service while working within a fixed budget are different than those of many investor-owned utilities. A utility with a far-flung service area may choose to implement AMI and/or AMR to a subset of customers in areas where it can achieve the greatest and most rapid return on investment. What works for one area may be different for another, even within a single utility. Add state-by-state rulemaking to the mix and the possible models are endless.

New pressures on the customer care process

While AMI will provide greater awareness and control to consumers and utilities, these technologies will also be the catalyst for new best practices. Regardless of utility location or type, the act of deploying AMI will lead to new pressures on the customer care process. There are some common denominators that will, by necessity, drive adoption of new best practices. Utilities will need to prepare their employees, processes, and systems as well as their customers for the impacts of AMI and AMR.

Increased training for customer service representatives

SDG&E estimated that its regular billing employees would require 80 hours of training when AMI meters are installed.4 Customers may be confused and wary about the new technology. Customer service representatives will face questions about technology and processes, such as time-ofuse and peak demand rate schedules, that are new to them as well as their customers. Consumers that participate in demand response programmes may be challenged to understand bills that provide details about usage, peak and off-peak rates, and more. The average consumer already finds their electric and gas bill calculations confusing and the advent of hourly reads and subsequent numerous rate plans will only exacerbate this challenge. Call volumes could spike during the rollout, and customer care managers should be prepared to provide extra resources to maintain the level of service customers expect.

Recruiting employees with more sophisticated billing analysis skills

With meters generating readings every hour, there are potentially 720 data points to capture for each customer every month. When billing adjustments are necessary – and adjustments may temporarily increase during implementation – staff must be qualified to analyse and interpret complex rates. SDG&E, for example, anticipates much of the exception bill processing to shift from clerical staff to billing analysts, generating a 20% increase in salaries for this group.

Establishing processes for ‘instant’ services such as connects and disconnects

Initiating a service order for field crews to connect and disconnect service may become a thing of the past. Customer care departments will need to develop and implement new processes to ensure due diligence is exercised in processing customer requests in a more real-time environment. And keep in mind that no utility of any significant size will be able, or even choose, to roll out all of their new smart meters in a single instance. Therefore, the transition from old processes to new will take place over a significant amount of time and will increase process complexity and in many cases, cost.

Providing customers with more tools to manage and understand their usage and options The utility website will become an even more critical component of customer care. To avoid overburdening the call centre, utilities will need to offer online tools to help consumers analyse their usage, identify conservation opportunities and understand how selecting new types of billing options can save them money and impact their lifestyle. Proactive communication of the process and its options is critical to making an AMI rollout deliver on the financial promises outlined in the original business case.

Using detailed consumption data for marketing and long range planning

Utilities will have the opportunity to gain more insight into customer behaviour than ever before. The marketing department will need to adopt best practices for interpreting, managing and using the wealth of data that will flood in from AMI and AMR deployments. Utilities can take a proactive stance toward serving customers based on their usage patterns. At the same time, they could, for example, generate new revenue streams by partnering with home security and appliance monitoring vendors to ‘rent’ use of their network infrastructure. It is important to keep in mind that historically, utilities have not been able to use a ‘business intelligence’ capability from the data that their customer information system (CIS) could produce.

Reducing call centre load with automated outage information

As AMI implementations mature and integrate with other systems (MDM, CIS, etc.), utilities will be positioned to pinpoint failing segments of the delivery system and notify customers in the affected area. Developing a protocol in advance of an outage will allow a more streamlined and customer-friendly process.

Conclusion

While the Energy Policy Act of 2005 has been the main impetus for many utilities to look more closely at AMI/AMR, the momentum is also driven by the rapid advance of communication technology in all facets of daily life. In an era when an airline can send a message about a flight delay to your wireless email device, the days of onsite, manual meter reads are numbered. In this new AMI/AMR world, the meter-to-cash cycle will quickly accelerate, and customer care leaders must be prepared to manage and leverage the new challenges coming their way.