The latest on smart metering

Smart metering or advanced metering infrastructure (AMI) is a subset of automated meter reading (AMR) – anymetering system where the meter reader does not manually enter numbers from the meter – with three key characteristics:

• Solid-state or computerized meters that collect time-series (interval) energy use data and are programmable to support features like time-of-use (TOU) rates
• Capable of two-way communications between meters and the utility, other distribution and transmission operators, or consumer devices
• Able to support applications beyond meter reading, such as demand response programs

Smart metering, however, entails much more than just the meter. Smart metering is an entire system that supports many customer and utility uses (see Figure 1). In the case of the customer experience, smart metering assists not only with load control programs – demand response and TOU pricing – but with additional customer services, such as options for net metering, plug-in electric vehicles, smart appliances and energy monitoring and control.

On the other side of the meter, smart metering supports a broad range of utility applications that go beyond simple meter reading. Such areas include outage management, load forecasting and balancing, theft and tamper detection, and asset management.

Top drivers

Smart metering can address basic, immediate needs such as meter reader and fleet vehicle reductions, remote connects and disconnects, more accurate meter reads and more easily recording hard-to-read meters. Smart meters have already shown good return on investment based on these functions alone.

AMR can address some of these requirements, but as smart meter prices decrease, utilities find they can use smart meters to cost effectively obtain both these basic AMR functions and more advanced grid control capabilities – including demand response, load balancing and forecasting, TOU pricing and real-time pricing, and efficiencies in service crew dispatch. Even some utilities that have already implemented AMR can still quantify sufficient benefits to move forward with smart metering, using load forecasting and load reduction by offsetting new-generation capacity buildout.

Federal and state regulations can also boost smart metering efforts. We have seen some action on the federal side since the US Energy Policy Act of 2005 (EPAct). The act set forth important precedents: it requires utilities and retail energy providers to provide all customers – upon customer request – with time-based rates and smart meters within 18 months of enactment. It also requires state public utility commissions (PUCs) to investigate smart metering and determine whether or not it is appropriate for utilities to provide smart meters for each customer. In addition, the Energy Independence and Security Act of 2007 established a federal grid modernization commission and requires states to consider regulation supporting intelligent grid cost recovery.

Other bills have been recently introduced in the House of Representatives. One bill would create a special tax incentive for smart meter installations, through an amendment to the IRS code to provide for a five-year recovery period through depreciation. Another bill would mandate additional smart metering at the federal level. All of these bills reflect an increasing interest in smart metering and intelligent grid capabilities at the national level, but they are still in the very early stages of development.

Facing challenges

With California leading the way in the US and Ontario in Canada, many state and provincial PUCs are seriously considering smart metering. The most significant efforts range from mandating smart meters to assisting utilities with better understanding their smart metering options. About two-thirds of the states have utilities with some smart metering pilots or installations.

Although much of this activity remains at the pilot stage, if each of those utilities fully implemented smart meters for all their customers, that effort would include more than 52 million electric and 12 million gas meters. The utility industry is not yet at the tipping point of substantial investments – more than 50 percent of all meters in operation, but increased interest in meter data management for smart grid capabilities continues to fuel the climb.

It is important to remember that each business case will be unique. Factors that might vary considerably include:

• The growth rate of housing and industry within a utility’s service areas, which would impact avoided capacity savings
• The sophistication of outage management systems already in place
• The number of AMR meters already in place
• The regulations around energy efficiency and demand side management

Even with the bright future of smart metering and successful business cases already out there, utilities still face challenges justifying and implementing smart metering projects. When building a business case, utilities should:

• Forget overnight changes. Because of the substantial asset and business process changes, utilities need a long-term vision of their smart metering transformation. In particular, widespread smart metering deployments can take years. After deploying smart meters, utilities should plan for a five to eight year payback period , and for smart grid projects at least 10 years.
• Make connections. Utilities need to connect with many different groups when undertaking smart metering. They should involve as many departments as possible; deal with labor issues related to the availability and skill level of meter installers; consider the risk mitigation issues related to implementing new IT systems; and effectively communicate with customers about upcoming changes. Equally important is informing regulatory bodies and media to help them understand the benefits smart meters can provide to many groups.
• Get involved. Utilities can get involved with smart metering through many avenues, including consortia of utilities and vendors focused on smart metering. Another avenue is to explore the successful pilots and coalitions in place, such as the Intelligent Utility Network at Reliant Energy or the Xcel Energy Smart Grid City.

Technological advances

The meter technology itself is maturing. That, coupled with the momentum from supportive legislation and utility demand, means a greater focus on connecting the customer and the utility with meter information. As a result, research is focusing on how to better manage and move data around the smart metering system to enable operational and grid efficiencies.

One technology area receiving more attention recently is communication between smart metering components. On the customer side, research is focusing on how to best connect smart metering components throughout a customer site. For example, the Zigbee Alliance is becoming more important as companies try to figure out inexpensive wireless methods for connecting the smart meter information with end-user devices, such as smart appliances, heating and cooling environmental systems and end-user displays.

On the utility side, research increasingly focuses on better enabling communication between multiple types of meters and the utility. As a result, technology is shifting more toward standards-based communication protocols – such as ANSI C12.22.

Since meter data is the foundation for most utility applications of smart metering, meter data management (MDM) is becoming more important. Companies are focusing not only on the MDM system itself but also on how to better connect other software that uses meter data with an MDM system.

MDM is an enterprise-wide data repository of metering data collected from any customer through varying communication methods and from many different meter systems. The system rationalizes, cleans and manages meter data, which a utility can then securely use in a variety of billing, analysis and operational applications.

By working with data from many different sources in a utility – such as geographic information systems (GIS) and outage management systems (OMS) applications – MDM enables a utility to analyze and build optimal tariffs that benefit the utility and the utility customer, improve response to outages, reduce the cost of customer support and minimize energy losses from tampering and theft. It also allows the improvement pf operational efficiency, the enabling of demand response by allowing for better load control, improvement in capital planning and the provision of additional services for customers, such as remote monitoring, prepayment, and vacation/vacant services.

Although utilities have shown interest in MDM, full MDM utilization is taking years. This is because the general focus is still on the cost and logistics for ‘getting the meters in place.’ In addition, systems complexities in implementing new applications and fully taking advantage of the technology within the utility processes takes time.

Utilities are generally approaching MDM by installing one or two operational functions, such as outage management or load profiling first, and then building on that technology and process work to make additional changes. Within three years, some utilities will capture enough value from MDM to be apostles for smart metering. This three-year window gives a utility sufficient time to implement some of the applications, benchmark the differences in efficiency, and continue driving improvement.

Filling the gap

Smart meters are appealing because they offer immediate operational efficiencies – labor force reductions, more accurate meter reads, and remote connects and disconnects – in addition to longer-term grid control benefits, such as demand response.

However, the popularity of the smart meter has created a gap in the intelligent grid between the transmission network and the smart meter itself. As the top image in Figure 2 demonstrates, before the intelligent grid, utilities had very limited visibility of their distribution networks. The bottom figure shows how, as intelligent grid initiatives move forward, many utilities are pursuing smart meters but neglecting the grid between the substation and the consumer.

These meters can help identify problems along the distribution network. Before the intelligent grid, utilities had very limited visibility of their distribution networks, but as intelligent grid initiatives move forward, many utilities are pursuing smart meters but neglecting the grid between the substation and the consumer. These meters can help identify problems along the distribution network but cannot provide detailed information about the status of critical grid assets, such as transformers and lines.

As utilities continue to improve their visibility into the grid, smart meters will not be able to support all of their monitoring needs. Other sensors installed along the distribution grid can collect important real-time and historical data to improve a utility’s visibility into the grid and ultimately improve its reliability.

One key aspect of real-time sensing is fault location. With smart meters, utilities can see which customers have lost power in an outage and use that information to help narrow down the fault location, but they generally cannot tell the specific location of the fault or the type of fault. With additional sensors along the grid, utilities can more accurately determine the fault location as well as the type of the fault. This allows the utility not only to dispatch crews faster to a fault location but also to better understand what type of personnel to send. In addition, utilities can use the sensor information to quickly isolate faults and minimize damage to the system.

Additional benefits

Another aspect of real-time monitoring is not just determining fault locations but identifying impending faults. By installing additional sensors along their distribution grids, utilities, for example, could better monitor their transformers. Sensors could trigger alarms for unusual activity – such as a transformer drawing too much power – which informs utilities of an impending fault and allows them to take action.

Aside from correcting and preventing faults, additional sensors on lines and equipment can help with distributed energy. Although smart meters can allow distributed resources to put energy back on to the grid and track the amount of energy, they cannot manage the energy once it enters the grid. Excess capacity of onsite generators that is sold back into the grid introduces harmonic differences that require adjustments to be made to accommodate this power. Additional sensors can improve voltage quality and allow the utility to better size its cables and adjust for power changes on the grid.

Not only can sensors empower utilities to better react to grid events, but they also allow utilities to create richer historical databases to improve their operations. One key area is improved asset management, since utilities have limited capital that they can invest in physical infrastructure.

Utilities typically do not have enough capital to invest in replacing aging infrastructure and building new capacity to handle the growing demand for more, higher-quality energy. Instead, they must spread their investments over a longer time period. To do this, utilities need to have informed decisions support. This support includes data about the operation of an asset, as well as analytics applied to those data, so that utilities can make the right economic decisions about asset operations and maintenance.

Expanding a utility’s sensing capabilities along the grid can address many needs, but adoption is slow because of several factors including:

• Cost justification. Although many sensors are not particularly
• expensive to install, utilities face difficulties in justifying the costs. Ambiguity about what to monitor. Utilities still face many questions about what assets to monitor and how often to monitor them as well as what information would provide the most value for a specific asset.
• Dealing with the data tidal wave. Sensors can collect data, but the data will not provide much value unless a utility can effectively store and process large amounts of information.
• Lack of communications networks. Communications networks are the backbone of an intelligent grid. To benefit the utility, each sensor must have some method for communicating with the utility.

Differentiating the adopters

The intelligent grid is an evolution and not a revolution. Although many sensing technologies are relatively mature, no utility today has significant real-time visibility across its entire distribution network.

Utilities can take steps toward greater grid visibility by prioritizing their sensor investments. Customer complaints and regulatory pressure can push utilities to take action on particular parts of their service territory. Even in high-priority areas, it may not make financial sense for a utility to deploy sensors for every possible asset.

In some situations, it may make sense to target a particular area of the service territory with a higher density of sensors. On the other hand, utilities may find it more beneficial to cover a broader area of their service territory with fewer sensors. Some other utilities find ways to combine their smart metering projects with other distribution network sensors or leverage existing investments that could support additional sensors.

Some utilities are achieving savings with targeted approaches, but widespread deployment of sensors other than smart meters along distribution networks has yet to demonstrate significant benefits. As a result, most utilities will slowly implement distribution network sensors.

Future planning

The next few years will likely involve many pilots and targeted applications of these sensors. As utilities gain confidence in the benefits of these sensors, they will likely begin more widespread deployments. Initiatives such as the increased use of distributed energy will likely push utilities to use more sensors to deal with more complicated power flows.

Utilities should consider how short-term efforts can help build company confidence in distribution network sensors. At the same time, they still do need a long-term vision to ensure that today’s investments will contribute to longer-term goals.

When creating their short- and long-term investment strategies, companies should consider better leveraging existing infrastructure. This includes existing communications networks and existing control devices – such as recloser controllers and sectionalizers – that already contain digital processors and can collect power line data.

They should also tiedistribution network sensors to important utility initiatives. Utilities may be able to introduce more sensors on their distribution networks by tying them to high-priority company initiatives. Such initiatives may include smart metering or distributed energy.

Different parts of a utility’s service territory will have different communication needs, and the same holds true for sensors. Utilities should consider how different parts of their service territory vary in terms of the criticality of providing service, available communication capabilities, age of assets, and outage history.

Prioritizing initial investments based on where sensors would provide ‘the biggest bang for the buck’ is also important, in order to achieve quick wins and build company confidence. Finding the balance with initial investments is also important:to make initial investments, utilities will likely have to scale back some elements of their sensor deployment. These include the size of the target area, the density of sensors within that particular area, and whether to install permanent or moveable sensors.

Companies also need to remember the importance of collaboration by sharing their knowledge with other utilities, building partnerships with their chosen vendors, and remembering that customers and employees are key in a successful smart metering implementation.

Karen Blackmore is Research Director of Energy Customer Operations Strategies at Energy Insights , an IDC company. In this role, she leads the charge in providing research-based advisory and consulting services that assist executives involved in the energy enrollment-to-cash processes to drive technology-enabled business innovations that maximize the value of their technology investments.

As Senior Research Analyst for Energy Insights, H. Christine Richards provides research-based advisory and consulting services that enable executives from energy companies to maximize the business value of their technology investments and drive technology-enabled business innovation.

A utility using smart metering can better satisfy its customers through:

• More information for customers to manage their energy use
• Faster customer service related to meter reading and connection or reconnection of services
• Energy supply and availability through outage management, pinpointing outages and potential tamper situations
• The ability for customers to make personal choices that can affect societal change
• Improved bill accuracy and flexible options for billing programs

Issues utilities should address when implementing a new smart metering system:

• The need to establish a new system and process for managing two-way communications with meters
• The requirement to rapidly process large volumes of data – utilities need to consider how to easily extract and transport this data to various systems
• How to best automate processes and share data with other market participants
• The need to have a data retention and retrieval strategy in place to accommodate the massive amounts of data that must be stored for interval reading and billing