Remote Resource Guide 2011 - (Page 10)

Resource Guide - Market Update Meter Data Management: Faster Decisions, More Visibility Max Gladstone, Smart Grids Analyst Aberdeen Group Electric, water and gas grids around the world are growing smarter as new regulations and rising costs drive utilities to replace meters once read by hand with “smart” meters that transmit data directly to utility systems. But smart meters are only a piece of the complex system of systems called a “smart grid.” Smart meters can report the amount of power a given customer drawn from the grid at daily, hourly or 15 minute intervals, or even (in some cases) in real time, as opposed to old manual-read meters, which provided one data point a month. At least in principal, this granular, time- and locationindexed data can support new utility applications that weren’t feasible in the old manual metering regime. Time-of-use pricing, for example, depends on customers and the utility having an accurate sense of how much power is being used, by whom and when. Robust historical data about power use can make distribution management, load forecasting and distribution automation more effective. Data from smart meters can also drive outage management and demand response programs, as well as improve business processes in the utility. However, meter data can only accomplish these feats if utilities are prepared to manage and use it. The Smart Metering Implementation Programme Statement of Design Requirements, published by the United Kingdom’s Office of Gas and Electricity Markets in July 2010, cites two scenarios for smart meter data volume within the UK: when smart meters only are deployed, the volume of data under utilities’ management rises from 1 terabyte to 27 terabytes between 2012 and 2030. Where smart meters are deployed as part of an integrated smart grid (including smart transmission, distribution and outage management systems), the volume of data rises from 4 terabytes to 127 terabytes in the same time period. In the first case, utility data volume increases by a factor of 27. In the second case, utility data volume increases by a factor of roughly 32. Nor do the projected increases stop at 2030. If utilities don’t get some control over this data, quickly, they’ll drown in a data flood, rather than riding the wave into a smarter energy future. Tools have emerged to help utilities adjust, among them the Meter Data Management System (MDMS). According to research conducted by the Aberdeen Group, companies with a Meter Data Management System (MDMS) can make meter data available to decision-makers within a day, while those without an MDMS require up to a month to accomplish the same task. When meter data is readily available, utilities can use it to improve operations and customer service and to manage outages. Utilities looking for tangible business value from their meter data must do more than acquire technology, though. Like any tool, Meter Data Management needs people trained to use it, and a good context for its use – or else it will languish on the workbench. Also like physical tools, to use an MDMS effectively, utilities must consider safety and security, as well as the nature of the job at hand. Many utilities that have already taken the first steps toward managing smart meter data have not yet dedicated personnel to securing this data, nor successfully tracked the value of meter data for their business. Moreover, Meter Data Management Systems are neither created equal, nor regarded as equal by the utilities that use them. For some utilities, the responsibilities of a MDMS are limited to the collection and validation of meter data, which is then fed into the utilities’ own back-end payment systems. For others, the MDMS becomes more of a command-and-control center for utility assets, allowing for remote connect and disconnect, sending price signals to home displays and so forth. Some users aggregate all meter information in a MDMS before patching it into back-end systems, while others feed meter data directly from their Advanced Metering Infrastructure (AMI) into billing and other operational systems. This article aims to bring some clarity to the market, discussing both why utilities adopt MDMS, and how they can do so in a manner that best serves their long-term goals. 10 www.RemoteMagazine.com In January 2011 Aberdeen asked representatives of 17 utilities that deployed an advanced metering infrastructure, and either have a meter data management system or intend to acquire one soon, to identify the top three pressures driving them to manage meter data. Figure 1 summarizes the studies results. Pressures Figure 1: Top Pressures Driving Meter Data Management *Source Aberdeen Group, March 2011 Unsurprisingly, regulatory activity and rising operational costs emerge as the top pressures driving utilities to actively manage their meter data, as these pressures are driving utilities to build smarter grids in general. In March 2007, leaders of the European Union (EU) endorsed the “2020-20” targets, pledging to reduce greenhouse gas emissions to 20 percecnt below their 1990 levels, cut primary energy use by 20 percent, and generate 20 percent of the EU’s power from renewable sources by 2020. While the US does not currently have a mandatory renewable energy target to match the EU’s goal, 30 US states have mandatory renewable energy targets in place. The People’s Republic of China, as part of their immense clean energy initiative, has pledged to increase its renewable capacity from roughly 9 percent in 2010 to 15 percent by 2015. Most renewable energy sources depend on conditions beyond human control: photovoltaic panels and thermal solar plants alike depend on sunlight, while wind turbines produce more power when the wind is strong and less when it is weak. As renewable energy sources play a greater role in power generation, due to government subsidies and feed-in tariffs, the grid must become smart enough to anticipate and compensate for a power surplus or dearth from these sources, as well as load peaks and valleys on the consumption side. Legislatures have driven smart grids investment in other ways as well. Some countries, like the US, have directly supported utilities that are working to make the grid smarter. The American Reinvestment and Recovery Act (ARRA) of 2009 contained US$4.5 billion of funds earmarked for the smart grid, and several billion dollars more for renewable energyrelated projects. Meanwhile, utilities’ bottom lines are being squeezed by fuel costs, as well as the costs associated with maintaining the aging generation, transmission, and distribution infrastructure in the US and in many countries around the world. Generators and transmission lines are costly to replace, and costly to build. Some of the advanced functions of smart grids can help avoid the capital expense of building new generators and transmission lines, providing another incentive for their construction. Since regulations and cost are the principal factors driving utilities to improve their grid, it comes as no surprise that utilities are trying to trace the potential business value of these improvements. 65 percent of Aberdeen’s survey participants site this as their top strategic action connected to meter data management. Please see article continnued on page 12  http://www.RemoteMagazine.com

Table of Contents for the Digital Edition of Remote Resource Guide 2011

Remote Resource Guide 2011
Contents
The Potential Role of Technology Transfer for Managing the Emerging Smart Grid and Other SCADA-Using Critical Infrastructure Sectors
Meter Data Management: Faster Decisions, More Visibility
Automated Operation
Communication
Data Acquisition
Lightning Protection
Network Solutions
Power Products
Remote Monitoring and Control
Security
Shelters and Enclosures
Calendar of Events

Remote Resource Guide 2011

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