Archive for the ‘Smart Meters’ Category

Electricity, gas and water meters that measure and record usage data and provide that data to both consumers and companies using two-way communication technology

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Smart Grid Introduces Big Risks to Meter-to-Cash Processes

Posted by Utilimetrics on February 21, 2012

By Eric Nelson, Synaptitude Consulting

Utilities that have successfully implemented traditional revenue protection methods, focusing on credit and collections, and energy fraud, typically minimize the revenue lost as a result of inherent inefficiencies in these processes to 3 to 4%. The disruptive technologies enabling energy smart grids will introduce new complexities to the meter-to-cash process, just as they have in other industries. Tele-communications is one such industry, which has faced and solved challenges similar to the ones now being introduced to the utilities industry, and provides an excellent source for applicable “lessons-learned”. For example, when market forces compelled telecommunication service providers to introduce new products based on next-generation networks, some of them experienced revenue losses of 15 % or more. There is no reason for utilities to suffer the same as smart grid rolls out; like communications providers, utilities can implement revenue assurance strategies and tools that ensure accurate data collection and billing and identify fraud and loss continuously.

Four Key Risk Areas
There are four main risk areas that smart grid’s complex meter-to-cash processes exacerbate which utilities ought to address proactively.

1. Revenue and Profitability Loss. Smart meter-to-cash complexity creates more potential breakdowns, service calls, and difficulties in correlating delivered and consumed energy with billed and collected revenue. Reporting breakdowns can go unidentified for weeks, compounding revenue loss over time. More complex rating and discounting drives both under- and over-billing errors. Intelligent diagnostic tools are required to ensure that all delivered and consumed energy is monitored and measured completely and that energy usage and consumption correlates accurately with billed and collected revenue.

2. Increased Customer Complaints. Smart grid introduces new pricing, services, and equipment. All invoice-driven industries experience spikes in customer inquiries and disputes when introducing new services, rates, and invoice formats. Given the associated costs and the negative impact customer complaints to PUCs have on rate relief initiatives, utilities would be well-advised to address these issues.

3. Fraud and Theft. Adding technology to power measurement and management creates vulnerabilities for thieves to exploit. For example, the wireless industry suffers new waves of fraud with each network upgrade. CBS News reported in 2009 that 70 percent of online fraud is perpetrated by organized crime. These groups recognize that fraud, across all industries, is more lucrative and less risky than narcotics trafficking, and Smart Grid creates opportunities for them. Identifying new forms of fraud requires intelligent diagnostic tools that can identify usage behaviors that should be investigated for fraud.

4. Day Demand Curve Costs. Smart Grid necessitates predictive analytics that enable utilities to analyze and respond to usage behavior and manage the day demand curve proactively. Data from many systems must be delivered reliably to enable the feedback loop that makes Smart Grid valuable. If the feedback loop is not reliable, the ability to manage demand will break down, which will in turn increase supply-side energy costs. To manage

Smart grid is technology intensive. Utilities will benefit from expertise, and should leverage the experience and expertise developed across industries that have faced similar technical challenges. Most smart grid meter-to-cash risks can be met through the expert application of comprehensive, proactive approaches to revenue assurance that deliver process and data integrity controls, intelligent diagnostics, and predictive analytics.
1http://www.cbsnews.com/stories/2009/05/05/tech/cnettechnews/main4991799.shtml

Posted in Revenue Protection, Smart Grid, Smart Meters | Leave a Comment »

The Smart Grid – more than just smart meters

Posted by Utilimetrics on January 19, 2012

By Jonas N. Olsen, On-Ramp Wireless, Inc.

Search the term ‘smart grid,’ on the Internet and you’ll get a long list of articles about smart meters. But the smart grid goes far beyond the meters. Often located in underground basements or on impossibly high rooftops, devices associated with operating the smart grid can be hard-to-reach, especially in metro or other challenging environments, where there is no hardwire Internet connection. 

Distribution Automation (DA), which has the potential to significantly improve the performance of the smart grid, also struggles to connect these “smart devices.” DA systems strive to improve reliability of the smart grid through situational awareness, outage management, and faster response times when a fault is discovered. A smarter distribution system can also assist in utility capital planning by highlighting changing load conditions over time. Utilities are interested in implementing DA because it improves their bottom line and it is an autonomous project – they don’t need to communicate with their consumers.  

Half the battle of optimizing a DA system is connecting these billions of “smart” devices cost-effectively. Utilities need to be able to deploy a secure and reliable wireless remote monitoring system throughout their distribution network to accomplish asset monitoring, fault indication to improve outage restoration, alert to power quality issues, capture power theft and act as a hub for demand-side load management, which ultimately lowers cost of operation and maintenance costs for utilities.

For electric utilities, an added challenge is the advent of distributed generation, where electricity is generated from many small energy sources, and the introduction of Electric Vehicles (EVs), which bring new pressures to utilities’ distribution grids. However, wireless remote monitoring systems can address this too, especially as they become increasingly prevalent. 

Wireless Systems for Remote Monitoring

While utilities are increasingly using wireless technology for remote monitoring applications, it should be noted that not all wireless technologies are created equal. There are significant differences, which ultimately determine their applicability (cost and performance) to a specific application.

The key characteristics of a wireless system that determine its overall applicability are:

  • Coverage: The system’s ability to transmit a signal over a long distance.
  • Capacity: This can be defined in two terms. First, there is the actual application throughput (good put) from a single end device (such as a pressure sensor) in the network. Second, the overall network capacity must also be considered. This refers to the ability of a concentrator (or Access Point) to process data from nodes in the network. This is what we call the overall throughput capacity.
  • Power consumption: In remote monitoring applications, many end points must rely on batteries as the main source of power. The preference is for lower power consumption to extend the span between battery replacements. In some installations solar or other renewable sources can be used to supplement a main battery.
  • Latency: This term relates to the time it takes for information to move through the system in either direction (from the remote device to a central collection system and the other way around).
  • Communication type: Wireless (or any communication system for that matter) operates as either simplex (communication only one way), half-duplex (communication both ways but not at the same time), or full-duplex (same time, bi-directional communication).

Wireless spectrum allocation is another concern that must be addressed. Wireless systems perform over a wide range of frequencies, from a few kilohertz to high frequency gigahertz systems. Many frequencies are licensed and typically bought by private companies through public auctions. Other frequencies are designated unlicensed and can be used free of charge. The unlicensed frequencies, however, are associated with rules and regulations about how the free spectrum can be used by various different private operators. An example of a rule would be guide use of popular technologies such as Wi-Fi and Bluetooth. The rules and guidelines address the amount of power output and the occupied bandwidth that can be applied in the allocated free spectrum. The rules vary from country to country, and operators need to observe and comply with local restrictions. Many remote monitoring applications operate in the free and unlicensed frequencies. This is mainly due to cost concerns, as many of these applications do not warrant the high cost of dedicated frequencies or the monthly recurring fees incurred when renting this spectrum of a third party operator.

It is important to recognize that different wireless systems mix and match these characteristics in various ways. This also means that there isn’t a “one size fits all” wireless system that is ideal for any application. The unique application requirements of a flow measurement system, for example, are very different from a low latency, factory floor SCADA application, which may require millisecond response times. Some applications will require very high data rates, while others just process a trickle of index data throughout the day. Pick any of the above mentioned system characteristics and the same kind of comparisons could be made.

Most remote monitoring applications fall into a category where range and low power consumption is prioritized. Range, in this sense, should be understood as either great distance (e.g. >10 km), or as the ability to penetrate obstacles, like vegetation, building, etc. Low power is key, as many remote devices will require monitoring without access a continuous power source (i.e. battery operated). Relatively small amounts of data are typically transmitted and capacity therefore tends to be a minor concern. What is important, however, is the aggregate data rate at the collectors/Access Points. If a wireless system has great coverage it is likely to provide coverage for many thousands of devices from a single network infrastructure point. This “Access Point” must provide sufficient throughput capacity to, robustly, receive and process data from all of the covered devices. This is where many narrow-band radio systems fail to meet the requirements of utility customers.

Finally, one needs to consider the communication type. Some applications can survive with simplex communication. This would be the case when all the application is intended to do is to collect data from a remote point. For an application where two-way communication is needed (resetting alarms on remote devices or changing configurations) a duplex system must be deployed.

Backhaul Options

An additional concern is backhaul from the remote site to a central data processing site. Most remote operation is far from the main hubs for IT infrastructure. When a private wireless system is installed (as opposed to using public infrastructure like a carrier based GMS network), it is up to the user to provide all connectivity links in the system. A wireless system that uses unlicensed spectrum will typically terminate in a set of wireless access points or gateways, which then need to be connected to the overall company network. This can be done in various was, but the most commonly used methods are a direct connection to the Local Area Network (if available), backhaul via a public cellular network (again, if available), and finally through satellite links. These options are listed both in terms of preference and cost.

Systems Integration

Integration with a process automation platform has to be considered. For a wireless remote monitoring system to be effective, it has to present the collected data in an industry standard format. An end-to-end wireless remote monitoring application will provide every step in the process, from integration of the wireless module with the remote sensor, wireless networking and networking infrastructure and conversion of the data to a standard format, such as Modbus or OPC. This allows for simple integration, both with on-site process automation systems and backend historical data storage.

Conclusion

As electric, cable, and telecom utilities increasingly work to improve their DA systems while having an eye on their bottom line; they should look at wireless remote monitoring solutions. With the right system, utilities should be able to pinpoint a problem exactly where it occurs so that their work crews can go directly to the affected area to fix it, and don’t have unnecessary downtime. In some cases, preventative maintenance system integration will even avoid failures altogether. A system should also be able to integrate fault indicator alarms with work order systems for simple and automated dispatch of workmen. Beyond the workforce, a connected DA system also leads to low power consumption by limiting peak power requirements, better capital planning, and fewer outages.

Lastly, the network should ultimately allow for a low-cost, fully-automated Distributed Grid, which enables e.g. fault indication (above and below ground), transformer monitoring, substation automation and other applications that were previously thought unfeasible to automate. When these applications come “online”, utilities will see significant enhancements in key performance metrics.

Jonas N Olsen is the VP strategic partnerships for On-Ramp Wireless, Inc., which is currently deployed by a Western utility for its wireless communication system.

Posted in Distribution Automation, Electric Vehicles, Post Deployment, Remote Monitoring, Smart Grid, Smart Meters, Systems Integration | Leave a Comment »

The Expanded Role of AMI in Strengthening Customer Relationships and Improving Water Conservation

Posted by Utilimetrics on December 8, 2011

By Matt Thomas 

As utilities in areas across the country raise water rates to fund desperately needed infrastructure repairs and replacement, educating consumers on the true value of water can act as a “shock” absorber for rate increases, according to Avoiding Rate Shock: Making the Case for Water Rates, a study sponsored by the AWWA Water Utility Council. The study found that although consumers get upset over rate increases because of misunderstandings about the true value of a safe, adequate supply of water, a consistent, structured communications strategy helps build support for rate increases.

To help build and strengthen customer relationships despite rate increases, utilities should proactively leverage advanced metering infrastructure (AMI) data to educate customers on their water usage, especially in terms of rates and the importance of water conservation. Such a task might sound laborious and costly to utilities; however, consumer portals that integrate with AMI systems can allow customers to access their water usage online in real time. Online access to water usage is a relatively simple tool that utilities can employ to help consumers learn about their rates, improve conservation through leak detection and communicate with their utility.

While adoption of consumer portals in the water industry is still in its early stages, some utilities that have started to provide this service are already experiencing significant results. Since installing an AMI system that integrated with an online consumer portal, The Village of Frankfort, NY, reported that approximately 20 percent of its customers are using the system to view their water usage.  As a result of the project, The Village of Frankfort was recognized by the New York State Conference of Mayors and Municipal Officials (NYSCOM) at the conference’s 102nd annual meeting in which it received first place in the Public Works Category of the 24th Annual Local Government Achievement Award Program.

Consumer portals graphically illustrate stored AMI data and present it to customers in charts and graphs that allow them to easily monitor their consumption rates and usage patterns. Online access to this kind of information can be used by consumers to estimate future water costs, better understand their bills and manage their utility budgets. It also enables consumers to notice or be automatically alerted of data anomalies, which may indicate household water leaks they were not previously aware of, which can result in excessively high bills. This example is just one of many that demonstrate how easy access to such information is financially beneficial to consumers.

Providing access to detailed usage information can also help utilities partner with customers to improve water conservation. This is a valuable capability, as industry reports are showing that water conservation has become a significant concern among consumers. A recent Oracle survey found that 76 percent of consumers are concerned about water conservation. According to the report, 71 percent of those surveyed also indicated that having access to more detailed information about their water consumption would help further motivate their conservation efforts.

Consumer portals enable customers to accurately track their consumption in order to curtail water use to help meet personal conservation goals. And, by automatically alerting consumers of potential household leaks, utilities proactively help rectify necessary action to stop water loss. According to the EPA, 5-10 percent of American homes leak more than 175 billion gallons of water annually through old faucets and toilets. These portals not only show consumers that their utility provides them with the data and tools to allow them to better manage their water usage, they also show that utilities take water conservation seriously (the majority of states are predicting water shortages between now and 2013).

These systems can also help improve communication between consumers and their utilities. Besides accessing usage history, customers can view responses to frequently asked questions (FAQ) regarding billing issues, rates and conservation. And, through portals, utilities can easily reach customers with important information alerts such as water bans, leak alerts and budgetary threshold alerts. 

FAQ responses and improved communication between utilities and consumers is practical, as it helps to better educate consumers on billing and water conservation while also providing them with a means of staying informed on important service issues. And, portals give customer service departments extra support, which can help them to more quickly and efficiently address customers’ needs and concerns.

 

Essentially, integrating a consumer portal with an AMI system can give utilities the efficient means they need to help build and maintain customer relationships. As water rates rise across the country, utilities should leverage this kind of tool to provide customers with easy access to detailed usage information. Such a proactive approach can help improve consumer perception of utilities by instilling a better understanding of personal water usage and billing, and by allowing them to take a more active role when it comes to water conservation.

Matt Thomas is vice president, Sales & Marketing, for Cleveland, NC-based Mueller Systems, a leader in advanced metering solutions for water and energy systems. Mueller Systems is a subsidiary of Mueller Water Products, Inc. (NYSE:MWA), a leading North American provider of water infrastructure products and services.

Posted in customer engagement, Smart Meters, Water utilities | Leave a Comment »

Empowering Customers to Take Control

Posted by Utilimetrics on December 7, 2011

AMI deployment is a hot-button issue. Negative media attention has conveyed the wrong message to consumers, and utility companies are working to rectify misconceptions. By initializing strategic communication plans, utilities can show their customers they have more options, and ultimately more control with smart meters. By communicating the benefits of smart grid, utilities will have engaged and satisfied customers.

This article highlights the Consumer Engagement Session at Autovation. Read on to learn best practices for customer outreach and learn how early communication plans push deployments to succeed.

Empowered Customers, Smarter Grid

San Diego Gas & Electric (SDG&E) is working to give over 1.4 million electric and gas customers’ visibility into their energy usage habits, empowering their consumers and open energy markets. By taking a unique approach to the smart grid, SDG&E is improving grid reliability, resiliency, security and efficiency in the face of increased complexity.

Farrell Cox, smart meter deployment manager, SDG&E shared the strategic components of the program:

  • By using smart energy devices, new products and services, SDG&E is encouraging customer participation in energy management.
  • Incorporating and enabling all generation and storage options to support customer choice, improving grid stability and power supply options while reducing GHG.
  • Enhancing the grid to reduce customer disruptions, resist attack, improving workforce and asset optimization and improving efficiency.

Cox described the factors that are driving the need for energy system changes:

  • Customer empowerment: Choice, control and convenience.
  • Centralized renewables: Increased volume threatens grid stability.
  • Distributed renewables (rooftop solar): No control, can’t see it and no communication.
  • Electric vehicles: Current electric grid cannot manage potential volume.

As SDG&E installs smart meters it is increasing customer empowerment. The customer benefits of the deployment are:

  • Enhances reliability and outage detection, and speeds restoration.
  • Gives customers more control over every day energy usage, opportunity for lower bills.
  • Reduces need to access property, more privacy.

SDG&E uses online tools, demand response, dynamic pricing and Home Area Network pilots to empower its customers, giving them direct control over their data. Customers can track problems and rectify them on their own. By observing their energy spend, they can compare day-to-day energy usage and manage their bill.

A Smarter Path to Smart Meters

Pepco Holdings, Inc. (PHI) works to supply power to over 1.5 million customers through Atlantic City Electric, Delmarva Power and Pepco. The company is working to advance the smart grid with the utilities it serves. Jay Demarest, PHI and Susan Komornik, The Cadmus Group, Inc. shared lessons learned in early deployments. New technologies often bring an anxiety and a vacuum of misinformation, so it’s extremely important to communicate the benefits of smart grid deployment to customers early on.

Smart meter installation has been under way in Delaware since 2009, the District of Columbia since 2010 and in Maryland since June 2011. Delmarva Power’s aim with its communications plan was to strike a balance:

  • Don’t overpromise.
  • Keep stakeholders involved in planning.
  • Be flexible in timing and execution.
  • Provide good communications/not noise.
  • Offer credible benefits customers can understand.
  • Answer all questions factually.
  • Simple message in customer language/not utility speak.

Where did the communication play into the project lifecycle? For Delmarva, the planning began early:

  • In 2007, PHI announced its “Blueprint for the future” plan to meet the challenges of rising prices and the impact on the environment.
  • In 2008, the Commission approved installations.
  • In 2009, Delmarva initiated research, surveys and field testing to measure customer awareness and understanding.
  • In 2010, deployment began and meanwhile, marketing teams were selected to develop strategies for educating customers on smart meter benefits.

Customer research on smart meters showed positive indicators that 80 percent feel neutral to positive and half see smart meters as an advantage. Research showed the key benefits customers recognized are:

  • Tool to monitor usage.
  • Provide accurate readings.
  • Better customer service.

The challenge was that about one-third of Delmarva customers surveyed know little to nothing about energy efficiency, and while customers are aware of the online tools, most were not enrolled.

And when deployment began, the marketing team developed and implemented a phased plan with creative execution, focus group testing of messaging and communications planning.

Komornik described the goals of an education and outreach phased approach:

  • Introduce and educate customers about proactive energy management.
  • Position smart meters as key to their energy empowerment.
  • Activate customers in energy management with a phased approach.

The Delmarva marketing plan was all about empowering the consumer, with slogans like “Stop Guessing,” “Now you know that your smart meter can help reduce energy bills” and “Take Control of Your Energy.”

It’s vital to reach your consumer. Delmarva send a newsletter to customers. “A QR code is a very effective tracking tool,” said Komornik. And social media is vital because that’s how utilities can integrate themselves into the daily lives of their customers: “Get on the train or get off the tracks,” said Komornik on social media strategy.

Having a well-designed website is key. Easy navigation will help spread your message. Delmarva used a microsite approach which had different pages for:

  • Smart meter definition.
  • Understanding smart meter data.
  • How to start saving energy.

Using TV commercials, online banners, billboards, radio announcements, press releases and print advertisements, Delmarva got the message across that smart meters help curb energy spend, empowering customers to engage with their online tools and manage their energy usage.

Customer smart meter education can be successful if executed with:

  • Research and testing.
  • Careful planning.
  • Proactive partnership.
  • Phased messaging and an integrated media approach.

Please share your customer engagement experiences (challenges and successes) with your peers. There are several ways you can do this:

We look forward to hearing from you!

Posted in Autovation, customer engagement, Deployment, Smart Grid, Smart Meters | Leave a Comment »

Improvisation is Key for Some Gas Utilities

Posted by Utilimetrics on November 9, 2011

Gas utilities are considering advanced metering infrastructure programs to enhance operational efficiencies, customer service and safety and energy conservation. However, some utilities have to improvise when it comes to making the switch to AMI.

 In some cases, leveraging existing technology has proved most beneficial to the deployment of new technologies. In other cases negative media attention has caused several utilities to reconsider how they communicate the deployment to their customers. The goal is the same, but the path to deployment can vary.

This article highlights the Autovation Gas Session from Monday, Sept 26. Read on to learn how two resourceful utilities used improvisational methods to get the job done efficiently and effectively.

Leveraging the Value of Gas Datalogging

Brad Anderson, AMR project manager, Alabama Gas Corporation (Alagasco), shared how advanced AMR systems bring value beyond periodic meter reading. Anderson explained how Alagasco leverages additional information collected during the readings to better serve the customers.

Alagasco is a natural gas distributor, providing clean-burning, energy-efficient natural gas to roughly 440,000 homes, businesses and industries throughout Alabama. Beginning in March 2010, Alagasco partnered with Itron for a three-year deployment to implement AMR within the territory to approximately 497,000 meters.

Anderson described the datalogging collection components and their capabilities:

  • The datalogging module is capable of transmitting up to 40 days of daily or hourly read data.
  • Utilities can collect 40 days of daily consumption data at normal drive-by speeds.
  • Utilities can request a specific day’s read for a move-in/out scenario at normal drive-by speeds.
  • Utilities can collect 40 days of hourly data, which doesn’t slow down speed.

Anderson said that in order to store the data being collected, Alagasco’s existing data warehouse system was used for storage of the meter reading data.

How does this datalogging work? It’s actually “built in” so “no additional configuration is needed to enable datalogging of hourly and daily data,” said Anderson. Each meter receives a datalogging gas module programmed for its unique configuration. Then, a mobile collector vehicle is utilized, which requires no additional configuration for monthly reading sessions.

Once the data is collected, it is viewable from within the software client along with the periodic (SCM) reading used for billing. Utilities can organize the datalogging per individual route or universally on all meters.

When implementing this, utilities can reap the biggest benefits if they leverage existing data warehousing, business intelligence infrastructure and staff experience. According to Anderson, in choosing the data collection system, Alagasco was able to specify the datalogging class module as its standard module to be deployed company wide. There was “no noticeable impact to drive-by speeds.”

Datalogging collection allows Alagasco to leverage daily consumption data comparable to AMI systems while enjoying the ROI of an AMR drive-by system:

  • Datalogging returns important information regarding ERT configuration with every drive-by read.
  • Verification of BPI/ Electronic Correctors by comparison of daily readings and consumption of the corrected module vs. uncorrected module.
  • Back office and customer service groups use daily read data for various customer accounting tasks.
  • Datalogging gives the commercial marketing group access to daily consumption information on all of the commercial and industrial customers.

Anderson closed with important information to consider for those interested in leveraging datalogging. Here are a few of his points:

  • MDM (meter data management) software application or a third party warehouse/data analytics package will be required.
  • Work with the IT department to determine what is the best solution for long-term data storage needs.
  • Set accurate expectations for stakeholders in regards to datalogging.

Building the Business Case for AMI and Natural Gas

Atmos Energy Corporation, the nation’s largest pure natural gas distribution company, serves 3.2 million customers in 12 states. David Anglin, director regulated operations, Atmos, explained the differences between gas AMI and electric smart meters:

  • Gas meters are decades old, proven measurement devices.
  • The same meter remains in place with a wireless transmitter attached to the meter.
  • The index from the existing meter is reinstalled on the AMI device.
  • Ultimate use of data differs substantially from electric AMI.

Anglin explained that negative media coverage of AMI deployment in Texas led to a new way of implementing changes for Atmos: “We created a new term for the technology” that was self-explanatory. Whenever referencing the new technology in public, they said Wireless Meter Reading (WMR) instead of AMI. This term, according to Anglin, covers a broader range of technology and takes away nothing from the features and capabilities of the system.

So how was the WMR utilized for Atmos? Anglin described the data collection model:

  • SmartPoints collect hourly readings
  • Transmit every four hours
  • Daily reading success rate was 99.4%
  • Post one daily read to CIS

The benefits to using this system are:

  • Bills are produced with readings from the day of the bill
  • Customer access to daily usage online allows for more control, leads to higher acceptance from customers

This new technology also has a great benefit to utilities, said Anglin, because it allows for smaller, tactical deployment. In the near future, utilities will enjoy remote gas shutoff, pressure monitors communicated across WMR network, and cathodic protection voltage collection across WMR network.

Attention gas utility professionals: please share your technology experiences (challenges and successes) with your peers. There are several ways you can do this:

  • Submit an abstract for Autovation 2012, Sept. 30-Oct. 3 in Long Beach, Calif. The Call for Speakers deadline is Jan. 13, 2012.
  • Provide a byline article for News Link or agree to be interviewed by News Link staff for an article. Or, submit a blog post. Contact Janice Greenberg.
  • Consider hosting a regional learning lab or participating in a webcast. Contact Debby Scheck.
  • Start a discussion on the Utilimetrics LinkedIn Group

We look forward to hearing from you!

Posted in Autovation, datalogging, Gas, Smart Grid, Smart Meters | Tagged: , | Leave a Comment »

Water Management: It’s Much Easier With AMI

Posted by Utilimetrics on November 7, 2011

While much of the utility technology attention seems to circulate around efforts by electric utilities, some water utilities are implementing AMR/AMI solutions to increase revenue, control expenses, comply with regulatory mandates and increase infrastructure spending without burdening customers. The most common reasons for implementation are:

  • Improve understanding of water consumption and flow patterns
  • Ability to track and predict changes in trends and demands
  • Highlight anomalies
  • Warn of high or low flows
  • Identify leaks or other waste minimization opportunities
  • Shift water consumption to other parts of the day

The demand is higher, particularly among public or city-owned municipal utilities—More than 25% of water meters in the U.S. are now equipped with AMR.

The most common benefits to water smart meters are:

  • Leak detection
  • Reacting to billing disputes
  • Remote turn-off
  • Better water use prediction
  • Determining time of water use

An Aclara water AMI case study reveals a network system for meter reading, implemented in Leesburg, Va., has reduced unaccounted-for water from 15 to seven percent. In addition, the system provides daily data that helps Leesburg identify service-line breaks where water use increases suddenly and remains elevated, as well as intermittent spikes.

More benefits: A Sensus water AMR case study shows how advanced metering systems can grow water revenue. A progressive water authority in Lockport, Ill., treating 1.4 million gallons a day from its own wells, saw a 12 percent increase in revenue with AMR deployment. Prior to the AMR system, it would take 16 days to read all of the city meters, compared with just four days after the installation.

Responding to requests from members about the need for more water programming, Autovation 2011 included an AMI Water Vendor Panel Big Picture Session.

The panel, moderated by Charles Kiely, DC Water, featured:

  • Paul Lekan, Aclara
  • Thomas Butler, Itron
  • Doug Neely, Sensus
  • David Hanes, Neptune Technology Group
  • Akeyma Broden, Elster AMCO Water
  • Morrice Blackwell, Badger Meter

“We are having conversations at Autovation that we were not having four years ago,” said Lekan, who described how providing solution options to collect and manage usage data benefits large and small utilities.  According to Lekan, meter readings from AMR/AMI provide the data and information needed to conserve resources, reduce theft and improve customer service.

Butler described how smart meters for residential customers have the ability to integrate into an existing water metering program smoothly. AMR/AMI offers functionality and remote configuration, which streamline operations for water utilities, resulting in real cost savings.

“[Water management] is much easier with AMI,” said Neely, who agreed that AMI for water significantly helps in conservation efforts, as well as distribution automation, home area networking , demand response and smart grid operations.

Driving Client and Customer Relations

Hanes stressed the importance of a true partnership between water utilities and vendors. Vendors can assist water utilities in moving from mobile to a fixed network AMR, acting to cater to the specific needs of the utility.

AMR/AMI systems give more power to the consumer, as customers are encouraged to access their own information online. Panelists noted that their utility customers see improvements in customer service efficiency and complaint resolution on a daily basis.

Panelists also explained how some industry products meet the current and future needs of water utilities. For example, today’s advanced equipment has up to a 20-year battery life, with the ability to operate with one- and two-way communications.

Everyone on the panel agreed that water utilities should start investigating AMR/AMI. A visit to the Utilimetrics Smart Utility Marketplace is the first step in the process. This online product and service guide will help you identify potential consultants and services providers.

Utilimetrics wants to hear from water utilities that have deployed AMR/AMI.  Share your best practices and lessons learned with peers from all over the world.

There are several ways you can do this:

We look forward to hearing from you!

Posted in Autovation, Smart Meters, Water utilities | 1 Comment »

DTE Energy and PECO’s Experiences With Outage Management Systems

Posted by Utilimetrics on October 27, 2011

With AMI deployment comes the benefit of having real-time information. New and advanced outage management systems (OMS) collect automatic messages for alarms and outages. But as utility companies adjust to the advanced levels of maintenance that come with AMI, AMR and OMS, do they have field operations, dispatch teams and call centers ready for all of this data?

This article highlights the Outage Management Systems education session at Autovation 2011 Monday, Sept. 26.

DTE Energy has been working to integrate AMI into its OMS agenda, starting with internal workshops, which explain the benefits of OMS for utilities:

  • Obtain early outage detection.
  • Receive notification of momentaries.
  • Receive improved restoration information.
  • Send the right crew the first time.
  • Reduce okay on arrivals (OKA).
  • Prevent/ reduce customer callbacks.
  • Detect trouble behind trouble.
  • Improved customer satisfaction.
  • Reduce call center volume

Bob Sitkauskas, DTE Energy manager of AMI, reviewed DTE’s implementation of AMI data into their outage systems and the use of their Complex Event Processor (CEP).   Items to be considered in the implementation include:

  1. Collection Engine
  2. AMI/MDM
  3. Enterprise Service Bus
  4. Complex Event Processor (CEP)
  5. Outage Processor Interface (OPI)

The CEP successfully filtered out over 12,000 momentaries incorporating the “brother/ sister” concept in CEP where PONs received after 10 minutes are matched against PRNs (Power Restoration Notification) received on the same transformer in the previous two hours. If found, the late PONs are dropped to avoid creating an outage and an erroneous field visit

The advanced OMS also identifies problem meters in the field and intentional interruptions that were not properly reported by field personnel.

Although the integration has proven successful for DTE Energy, Sitkauskas outlined several challenges that come with interfacing to a legacy OMS. For example, the CEP could not handle the volume of PONs in a timely manner. In addition:

  • Work that was planned and scheduled through DTE’s customer service billing was not processed through the CEP and into OMS resulting in false outages.
  • Electricians were performing work for customers which required them to remove the meter, thus resulting in an outage.
  • Line crews were performing intentional interruptions without following established process of notifying Central Dispatch prior to an outage.
  • The Power Restoration Notification was received after five minutes resulting in an outage. A circuit breaker opened for 30 seconds and then closed resulting in an erroneous truck roll.

Sixty days after the initial installation, AMI was reinstalled in the OMS process flow. The installation consisted of creating additional CEP/ OPI filters, implementing OMS enhancements, reinforcing process with Central Dispatch and Field Operations. This implementation was restarted in phases, from station to station.

After working to re-tie the AMI to OMS, DTE Energy has been able to prevent false outage and erroneous truck runs, perform on demand reads in OMS, utilize AMI data for system outage data and analysis (SODA) reviews, utilize supervisory control and data acquisition (SCADA) data to validate sustained outage, and provide a daily status report.

“Start small,” recommended Sitkauskas. Prior to implementation, it’s important to test the installation.

Outage Management with AMR at PECO

PECO completed integration of its AMR and OMS systems in 2006, and eight years later, the Exelon Corp subsidiary that served the southeastern region of Pennsylvania revisited the journey to integrate and reviewed the benefits.

Kevin Cornish, Enspiria Solutions and Glenn Pritchard, PECO discussed the opportunities that have resulted from advanced OMS:

  • Improved customer satisfaction
  • Power status verification
  • Reliability analysis
  • Future outage prediction

Today, this system provides significant benefits daily, and specifically during storm restorations.

Pritchard explained that “pinging” is a valuable tool in outage verification. Pinging refers to querying the AMR network to determine if a meter has recently communicated. (PECO received roughly 125,000 pings annually). Whether you’re checking to see if a customer is truly out, the validity of a job packaged prior to dispatch or that a job is complete, pinging will save your company a lot of headaches, according to Pritchard.

If an automatic assessment outage lasts longer than 20 minutes, it is automatically pinged. If the ping responds with “Power On,” the outage is cancelled. In the instance that it indicates “Power Off,” a transformer analysis is performed to potentially escalate the event into a larger outage. PECO’s results show that since 2004, 64,205 pings were cancelled, 19,550 were not.

The outage is identified, dispatched and resolved before any customers notify PECO of the event.

As an example, Pritchard described a “Summer Slam” event in July, 2006. Thunderstorms caused nearly 400,000 power outages. Twelve hundred customer outage calls were cancelled without crew dispatch due to the meter pings. Seven hundred fifty customer calls were escalated into primary events via pings to neighboring customers’ meters. Conservative estimates indicate AMR helped save in excess of $200,000 in avoided labor costs during this storm alone.

With the success of the simple meter pinging application, several enhanced tools were developed:

  • Transformer analysis
  • Fuse analysis
  • Circuit analysis
  • Batch pinging

PECO’s AMR and OMS implementation project was a transition from concept to success, and now AMI. The project has created daily benefits well beyond the original estimates. The success of this project has advanced the metering industry as a whole by proving that meter-based outage management benefits are real.

If your utility has an OMS story to tell, please share your experiences (challenges and successes) with your peers. There are several ways you can do this:

  • Submit an abstract for Autovation 2012, Sept. 30-Oct. 3 in Long Beach, Calif. The Call for Speakers will open soon.
  • Provide a byline article for News Link or agree to be interviewed by News Link staff for an article. Or, submit a blog post. Contact Janice Greenberg.
  • Consider hosting a regional learning lab or participating in a webcast. Contact Debby Scheck.
  • Start a discussion on the Utilimetrics LinkedIn Group

We look forward to hearing from you!

Posted in Autovation, Meter Data Management, Post Deployment, Smart Grid, Smart Meters | Leave a Comment »

Beyond the Meter

Posted by Utilimetrics on October 25, 2011

Lessons Learned from Oncor and Portland General Electric

For many years attention has focused on pre-deployment and deployment of advanced metering systems (AMS).  As utilities enter the final stages of deployment they face new challenges as well as tremendous opportunities for integrating technology within the utility and improving operations. 

Autovation 2011 covered the entire utility technology lifecycle. This article highlights the Beyond the Meter education session Tuesday, Sept. 27.

Oncor, the sixth largest utility in the U.S. began deploying fully functional AMS in late 2009. About two million of Oncor’s 3.2 million meters have been deployed with full deployment scheduled for 2012. This fully integrated system provides:

  • 15-minute VEE (validate, edit, estimate) data to customers, REPs and ERCOT (for settlement).
  • 2-way transactions (disconnects/ reconnects, on-demand reads, etc.).
  • Secured connections and services to home area network (HAN) devices via ZigBee SEP 1.0 radio frequency interface.
  • A common Web portal for REP, customers and customer authorized 3rd parties (GUI and APIs)

So how does it all work?

“You need a robust testing environment,” said Mark Carpenter, CIO of Oncor, Texas’ largest regulated transmission and distribution utility that serves 7.5 million people statewide. Carpenter is also a newly-elected Utilimetrics board member.

“In theory,” he said, “it’s nice to specify exactly what you want before you actually start building it.” Carpenter explained that when inventing the system in a dynamic environment, clarification and modification contribute to a continuous and repetitive process.

“Remember, [AMS] is not just a meter reading system,” said Carpenter. “This is a SCADA system.”  And as Carpenter specified, “It’s extremely important to know and understand your market.” According to Carpenter, the Public Utility Commission of Texas-led Advanced Metering Implementation Team process has worked well in Texas.

When designing the system, Oncor adhered to solid design principles, factoring in security from the very beginning. In an effort to make the systems most efficient, Oncor:

  • Included performance monitoring;
  • Designed the system for ease of upgrade/ modification;
  • Planned for evolving CIM interface changes;
  • Considered multiple software/ FW changes in advance; and
  • Provided robust system synchronization

In the testing/ building phase, Carpenter said that the two most important things to consider are:

  • Establishing robust development and test environments will help to maintain strict version control; and
  • Maintaining strict version control

“Managing data is a big deal,” said Carpenter. He explains that utilities must be continuously monitoring these large integrated systems, which require “constant care and feeding.” Oncor generates about one terabyte per month, within the two million meters. “Don’t wait to establish data retention policies.”

And continual performance improvement is imperative: “It’s important to always remember to continually validate the end-to-end production system,” said Carpenter, “especially after modifications.”

As a utility, your main focus on customers and stakeholders is key: “There are stakeholders in this business,” says Carpenter. “This isn’t just about technology—it’s about everybody.”

Revenue Protection with Smart Meters

Eric Spack and Steve Sprague are leading a unique mission at Portland General Electric (PGE). The PGE team is taking revenue protection to the next level and beyond, utilizing new technology to work more efficiently.

A proactive approach to revenue protection utilizes alarms and generates leads based on interval data and primary metering. A major part of the team’s workload consists of confronting marijuana growers whose operations result in huge losses for the utility.

“We had 45 meters, from which we were missing about 1,400 kilowatt-hours,” said Sprague, “and at the end of the month, we had 20,000 kilowatts missing.” Utilities are facing huge losses from thefts like these, and at PGE, in a state where growing medical marijuana is legal, these operations are oftentimes extended beyond legal limits, and utilities are paying the price.

Over the last three years, AMI has dramatically improved energy recovery for PGE, from 32 Mwh in 2007 to 44 Mwh today and 75 percent of leads for the Lost Revenue Protection are generated by readers:

  • Tampers & Diversion;
  • Stopped/ Damaged meters;
  • Multiplier errors;
  • Lost meters;
  • Drug houses; and
  • Safety issues

These smart meters maintain current capability, allowing for real-time usability. What specifically can the meters do?

  • Tamper alarm: If the meter is pulled or removed, an alarm is generated with a date and timestamp.
  • Alarms scored: Leads are automatically prioritized.
  • Lead generator: All the leads are sent through a portal to Energy Recovery where they are reviewed and assigned to ERU Investigators or meter men.
  • Leads filtered: Without filters, alarms are useless and “we are filtering out 68 percent of the alarms and leads coming in.”
  • Filtering against: WMIS, Service Link, Outage, which avoids wasted time on wasted trips.
  • Added benefit: Not only generates leads but allows PGE to use the information on existing cases and leads from other sources.
  • KWH analytics: Low use, high use and zero use, it reads abnormal usage patterns

Once the norm is established, Point of Passage metering installations are screened to prevent from losses. Meter failures and alarms, however, do not cause the largest losses. The problem therein lies with theft and particularly, grow houses.

When marijuana grow operations overload transformers and connectors, it’s at the expense of PGE.  “Houses are not meant to be greenhouses,” said Sprague. The usage thefts are typically in the range of $1,500 to $2,500 per month, according to Sprague and Spack. Ninety percent of power thefts supporting grow operations are done by splicing in ahead of the meter.

“[At PGE] we have a 100 percent success rate in criminal grow diversion cases,” said Sprague. In 80 percent of those cases, money was recovered.

By learning how grow operations work, PGE adjusted to them and hunted them down, and by the time they were done, according to Sprague, they worked about 60 grow sites and billed roughly $620,000.

If your utility is near completion or has already completed deployment, please share your experiences (challenges and successes) with your peers.  There are several ways you can do this:

  • Submit an abstract for Autovation 2012, Sept. 30-Oct. 3 in Long Beach, Calif. The Call for Speakers will open soon.
  • Provide a byline article for News Link or agree to be interviewed by News Link staff for an article. Or, submit a blog post. Contact Janice Greenberg.
  • Consider hosting a regional learning lab or participating in a webcast. Contact Debby Scheck.
  • Start a discussion on the Utilimetrics LinkedIn Group

We look forward to hearing from you!

Posted in Autovation, Post Deployment, Revenue Protection, SCADA, Smart Grid, Smart Meters | Leave a Comment »

Opening General Session Sets a Fantastic Tone for Autovation 2011

Posted by Utilimetrics on October 11, 2011

Change and innovation were at the forefront of several informative presentations at the Autovation Opening General Session Sept. 26 in Washington, DC.

AMI Deployment and Smart Metering Initiatives

Today, 26 states have some type of government regulations requiring implementation of smart meters. These projects demand significant cost and resources, and as William M. Gausman, senior vice president, strategic initiatives at Pepco Holdings, Inc. explained, are much more than meter-to-meter deployment projects.

“This is a comprehensive initiative,” said Gausman.  Pepco is implementing new technologies, including a 300,000 meter deployment in Delaware. He specified that looking at the deployment holistically from the very beginning, to how data is managed, to educating the customers, is the key to successful deployment.

Pepco received $170 million in federal funding to invest in the smart metering project, and $4 million from a smart grid workforce training provider to assist in re-training meter readers. Smart planning is “under the umbrella of change management,” said Gausman. “We have to change the way we operate internally, from the skills and technicians…. Which impacts our whole design…. To be able to accommodate the data that’s coming back from all of these devices.”

AMI deployments lead to significant change, and companies must be willing to accept this challenge. “What we’re faced with,” said Gausman, “is being able to take the new technology and past technologies and integrate the system… that is really based on designs that are 80 to 90 years old.”

The challenge is making these systems operate in a way that works, and as Gausman described, this is not a program where “you wake up one day and decide that you’re implementing smart meters,” he said.

Gausman said it took a couple of years to develop the concept, then achieve approval. “It is a long path, and without the proper planning, you cannot have a successful program,” he concluded

Measuring and Managing Energy Spending

Paul Feldman, past chairman of the Midwest ISO, displayed data readings from a 24-hour period to present how energy demand varies from hour-to-hour, and how retail price for energy doesn’t properly mirror the real price.

By using a movie generated by the grid operator of the Midwest ISO, Feldman took attendees on a tour of how prices swing during one day, fluctuating from a price point of $0 or less MW/h to over $200 per MW/h. 

“The constant price motivates how you actually use electricity across the day,” says Feldman.  “What the movie shows is the actual price is moving around more than any other commodity on earth, and certainly shows that retail price bares no practical relationship to the real price.”

As the movie played, in just a few hours the prices shifted dramatically from one region to the next.

Exciting Innovation at DC Water

George Hawkins, DC Water general manager is involved with many ambitious projects designed to enhance and improve the water utility.

A repeated theme during Hawkins’ presentation was his passion for conservation.  He concluded his presentation by stating, “It is my strong conviction that you all are at the forefront of protecting human civilization.”

The Opening General Session was also an opportunity for Utilimetrics to recognize industry and association leaders and supporters.

Autovation Sponsors and Exhibitors

Dozens of exhibitors packed the expo and provided information, product and service demonstrations and advice to attendees. Click here for a list of all exhibitors and links to their websites.

Autovation sponsors helped support Autovation and its activities. We are very grateful to our sponsors:

Diamond Sponsor: Itron

Gold Sponsors: Neptune, Sensus and SilverSpring Networks,

Silver Sponsors: Aclara, at&t, Elster and Trilliant

Bronze Sponsors: On-Ramp Wireless, Siemens and Sprint

Autovation Host Utilities
Autovation 2011 host utilities Pepco Holdings, Inc. and DC Water were thanked for their hospitality and assistance in planning Autovation. 

Utilimetrics Awards
Utilimetrics presented four awards during the Opening General Session:

Utilimetrics Excellence in Project Management Award

Presented to Hydro One and accepted by Rick Stevens, Hydro One vice president of asset management.

Utilimetrics Consumer Outreach Award

Presented to San Diego Gas & Electric (SDG&E) and accepted by Farrell Cox, SDG&E smart meter deployment manager.

Ed Malemezian Utility Professional Best Practices Award

Presented to Charles Kiely, assistant general manager of consumer services, DC Water.

Robert J. Green Distinguished Service Award

Presented to Steve Hadden, SAIC.

After the Opening General Session, hundreds of attendees made their way to education sessions, networking receptions and the expo where they had numerous opportunities to learn, share, explore, experience and celebrate this great industry.

Thanks to everyone who participated in Autovation 2011. Autovation 2012 is Sept. 30-Oct. 3 in Long Beach, Calif. Make plans now.

 

Posted in Autovation, Change Management, customer engagement, Deployment, Grants, Smart Grid, Smart Meters, Water utilities | Leave a Comment »

Three Critical Factors for Successful AMI Deployment

Posted by Utilimetrics on September 19, 2011

By Jeff Trampleasure, vice president of operations, Metadigm Services

 Today, 25 states have smart metering legislation or policies, and utility companies across the U.S. are updating their infrastructure to adhere by the mandates already in place, or inevitably on the way. There are roughly 150 million electric meters in the U.S. and the total installed base of AMR units in the U.S. is estimated between 75M-80M units, or more than 50 percent of all approximate 150M electric meters. However, only a small fraction are replaced with smart meters.

The investments utilities are making in smart grid services are substantial –$50B in the U.S. alone according to authors Marcy Lowe, Hua Fan and Gery Gereffi’s 2011 report, U.S. Smart Grid.

As utilities upgrade the technology, they seek out masters in advanced metering infrastructure (AMI) deployment. Quite a few firms specialize in meter installation. Some install the meters and move on to other projects while others remain involved after installation to ensure the systems work accurately, safely and successfully—and that’s a big issue. 

Working with the right smart asset solutions company makes the critical difference in post-installation, continuing support for your customers, and cost-efficiency.  In choosing asset management partners for smart grid upgrade projects, keep in mind that each time you change companies—for example, installers vs. maintenance—you can open the door to data errors, billing errors and transactional costs.

For example, just last month Alabama Power, a Southern Company subsidiary, updated 1.4 million meters over a three-year period throughout the state. Southern Company started deploying meters in 2008 and completed deployment in 2010. The utility planned on a 36-month project, but completed it in 33 months, three months ahead of schedule. That’s a story most utilities would like to repeat. In order to achieve successful full deployment, there are three critical factors to keep in mind as you plan AMI deployment and post-AMI operations. 

Critical Factor #1—Tell end users what to expect up front

Communication may not be visible in the “utility belt,” but all utilities agree it is of the utmost importance in customer satisfaction. Smart meter installation is a hot-button issue across the U.S., and utility companies are conscious of the responsibility to ensure customers understand why their bill might seem to be adjusted after the deployment.

A glance at headlines in local papers proves that people can be confused that digital meters are causing their bills to increase because they read the electricity usage incorrectly. Often, what’s really causing the rise is the fact that mechanical meters are so incorrect and newer technologies are far more accurate in measuring consumption. Unfortunately, many utilities have also discovered that wiring technicalities and switching a smart meter from one address to another without proper procedures can also create a billing nightmare. Expelling rumors about what happens with smart meter technology upfront is a good practice before the installation begins.

“People want to blame the utility company,” says Angela Taylor with Metadigm Services. “But what we’ve seen in our work with Cobb EMC, Georgia Power, and others is that a proactive customer communications campaign can help the end user see the benefits from better monitoring.”

But the communication efforts shouldn’t stop with pre-installation outreach. End users have questions or concerns during and after the installation process, too.

“Making yourself available before, during and after the deployment makes a big difference in customer service,” says Steve Hallock, senior vice president of product innovation at Metadigm.  He suggests live person assistance to the utility company’s customers during business hours, and 24/7 assistance via web.

Critical Factor #2—Be rigorous about post-AMI expertise

Installation is more than just a meter-for-meter exchange-it involves pre-planning to post-AMI deployment.  For most utilities, a meter upgrade project is a completely new undertaking.  Look for service companies to support you with a lot of experience not just in installation, but in post-deployment. Going from a labor-intensive manual meter reading system to a high-tech two-way communicating system involves more than just a shift in technology for utilities—it’s a culture shift as well.

Utilities are challenged with how to respond to meters that now convey a stream of information.  How to respond to all this data is beyond the role of data analysts and IT operators. The right firm with a focus on proactive asset management can help make the transition from traditional metering to the new paradigm a smooth transition.   Post-AMI deployment represents a critical phase that involves careful consideration of many variables including compliance to safety, reaction to meter alarms and verification of accuracy to name a few.

Critical Factor #3—Plan for data collection and management

When an installation company is not involved following deployment, the utility often has to figure out how to respond to the stream of data from every meter. Ted Masters, VP of sales for Metadigm suggests selecting a company that is willing to work with you as a long-term partner rather than one that finishes your project and moves on to the next one.

As utilities are aware, preventative strategies must be in place to address safety during a storm, vegetation and other intrusive factors. Utility companies are flooded with customer demands when disaster strikes. And beyond blackouts and severe storms, day-to-day meter readings take manpower and expertise.  The new technologies provide real-time interval data that needs to be monitored and managed properly.

“Now that we have deployed smart meters, we’re better able to take care of our customers and manage our power grid, and that’s what it’s all about,” said Reginald Murchison, Manager-Metering Services at Alabama Power.

Posted in Change Management, customer engagement, Deployment, Project Management, Smart Grid, Smart Meters | Leave a Comment »

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