Houston, 10 February 2010

The Smart Grid Investment Grant (SGIG) program funded by the American Recovery and Reinvestment Act of 2009 (ARRA) has raised the bar for smart meter projects.

Grant or no grant, UtiliPoint International feels that utilities looking for investment approval must now meet the raised expectations of customer and regulatory organizations for Smart Grid projects.

ARRA is a $787.2 billion economic stimulus package that is intended to provide additional jobs and to help shorten the recession. Spending on energy programs is a significant part of the American Recovery and Reinvestment Act. Much of the spending is filtering through the Department of Energy ( DOE), and this includes over $3.4 billion for the SGIG program.

The overall purpose of the SGIG is to accelerate the modernization of the nation's electric transmission and distribution systems and promote investments in smart grid technologies, tools, and techniques to increase flexibility, functionality, interoperability, cyber security, situational awareness, resiliency, and operational efficiency.

The requirements requested by the DOE were not that surprising, but they are incredibly comprehensive. The requirements are light on specificity, and are rather quite broad. Requirements are typically noted in the opportunity as follows:

“Such projects will support…”

“Projects will also enable…”

“Careful consideration should be given…”

“It is expected that…”

“Special consideration is given…”

It is clear that the DOE was looking for projects that provide a clear and comprehensive approach to their smart grid endeavors.

UtiliPoint feels that utilities might have difficulties meeting the standards put forth by DOE. The Smart Grid opens a whole new channel of communication between utilities and consumers, but this new communications channel is fundamentally different from the past. Transmission is conducted real time. The need to broadcast pricing alerts to smart thermostats, email addresses, and text messaging devices happens instantaneously. Responses from customers can be immediate, as in the case of a consumer who pushes a "budget button" on a thermostat or website to inquire about their charges-to-date.

Legacy system platforms were not designed to handle real time events such as the ones noted above. They were designed to operate on regularly scheduled cycles of batch processes. From a utility's perspective, modifying or replacing those old reliable cycle-and-batch systems is an incredibly daunting prospect.

Another challenge that utilities will face is customer recruitment. Most demand response (DR) programs will be opt-in programs. Utilities need to reach out to eligible customers and convince them to participate. Eligible customers might be defined as customers with central air conditioning or all residential customers, depending on the nature of the DR program. This will require new software functionality to handle DR recruitment, enrollment, customer management, as well as DR program management. In addition utilities will need functionality provided by some meter data management (MDM) systems: management of communications to field devices, tracking of devices and their relationships to customers and premises, and provisioning of devices upon installation. The new software will have to be able to scale, allow multiple users, and interface with the DR call center, an integrated voice response unit, and the Internet. It will also need to interface with the billing system, MDM, the DR equipment installation company, and various DR communication systems.

Utilities will also need to re-examine how they provide customer service to smart metering customers. The utility call center will need to be able to effectively work with customers to take advantage of more detailed information on energy use and spending and how to apply it to customer concerns. This includes performing customer education needed to increase the understanding of smart metering and reducing the fear and distrust of the changes.

Call center representatives must also have a strong understanding of the end-to-end business process and changes. Once the systems and processes are implemented, the utility must be prepared to answer and handle a complicated set of questions and issues. This requires call center agents to have training and access to the applications and information to provide quality responses.

The Smart Grid also results in a paradigm shift regarding metering data. Today, utilities create monthly files of meter reads (using manual collection) and submit them to the billing system. With the Smart Grid, utilities become communications companies that handle millions of data transactions every day. For a utility with over a million meters, just the simple transactions involved in the Meter-to-Cash function are completely transformed. When the numerous other functions are considered—from Meter Provisioning to Outage Management to Demand Response Events to Charging Plug-In Hybrid Electric Vehicles—the potential enormity of the challenge becomes clear.

To illustrate, every day a smart meter operations team must support—per million meters:

 - More than 1,000 customer moves per day (25% yearly turnover)

 - 10,000 missing reads per day (99% daily read success)

 - 20 meter failures per day (0.5% annual failure rate)

 - 10,000 data changes per day

 - More than 97,000,000 meter reads per day (assumes 15-minute interval data)

One certainty about the Smart Grid is that applications and data uses will evolve and change over time. The solutions to support Smart Grid initiatives must not only accommodate, but thrive on such change. By planning for the full range of DOE functionality from the beginning and selecting the solutions with the right architecture, a utility can ensure not only that it meets today's broad requirements, but that it also can meet inevitable new requirements down the road.

Ends--

By Christopher Perdue, Senior Director, Market Research, Utilipoint

©2010, UtiliPoint® International, Inc.