Improving meter-to-cash processes is commonly used for justifying the investment in smart meters and meter data management (MDM) platforms at utilities. Because meter-to-cash (M2C) isAmerican Electric Power easy to remember, tied to a critical outcome via revenue, and well-suited for an acronym, this term has become a frequent catchphrase in the utility industry. In practice, streamlining the collection, verification, analysis, and application of meter data reaches beyond bills and into every aspect of utility operations. Energy giant American Electric Power (AEP) proved M2C’s pervasiveness with their recent revamp of four AEP operating companies’ meter data infrastructure. AEP serves more than 5 million Americans across 11 states and a 40,000-mile transmission network. Each day, they manage millions of data records tied to usage, billing, asset health and outage response. Nearly half of AEP’s holdings, represented by four companies, operated on legacy systems that required intrusive reconciliation processes to validate data quality for billing as well as daily market settlement. Efficiency and precision are critical at any company but are especially important in our industry as more data pervades energy systems. In this age of increasing data and interconnectivity, AEP enhanced their M2C operations by upgrading the software that controls it all: the meter data management system.


Each company undergoing the upgrade previously used Lodestar 1.6, a legacy meter data management solution operated by Oracle. Though functionally dynamic and highly- customizable in many respects, Lodestar lacked critical features inherent in newer systems like Oracle Utilities Meter Data Management. One of the primary needs was ensuring data quality when balancing daily consumption data for customers in preparation for market settlement and reconciliation. In addition, Lodestar calculations did not include critical elements, such as the ability to balance scalar and interval consumption on a daily basis and further display and estimate customer usage based on customer type and tariff. To meet consumers’ demands, AEP mandated that their revamped system draw on various streams of information to fill gaps and increase accuracy. Red Clay, AEP’s software integrator for this endeavor, deployed data migration tools to enhance the out-of-the-box functionality of Oracle Utilities Meter Data Management to achieve this goal. These tools leverage preconfigured transfer processes, data files, and tests to enhance system operations. Red Clay successfully converted data from AEP’s legacy MDM Lodestar 1.6 to Oracle Utilities Meter Data Management 2.1 to broaden the scope of determinants used to generate estimations.

This change led to the creation of a daily market settlement engine that drives more accurate data reconciliation each day for two of AEP’s Texas holdings. To date, these settlements have led to AEP’s highest data quality ever sent to the ERCOT settlement market. Beyond improving system accuracy and automation, AEP sought to leverage the power and value of a single system across multiple companies. Implementing a single system required balancing the compliance and performance measures of each individual entity to ensure continuous service and a smooth transition. To accomplish this, Red Clay worked closely with teams from each operating company to understand their operation, priorities, and overarching goals. Discussions resulted in the development of a master processing schedule to optimize system batch processing and operations. Oracle Utilities Meter Data Management 2.1 yielded higher quality data and more precise calculations, all while meeting or exceeding data processing service level agreement standards for each organization.

Beyond the improvement in data quality, this implementation offered AEP a consolidated and scalable enterprise platform to service existing and future AMI deployments, as well as enhanced outage management to prevent customer-facing issues.


American Electric Power is one of the largest electric utilities in the United States, delivering electricity and custom energy solutions to nearly 5.4 million customers in 11 states. AEP owns the nation’s largest electricity transmission system, a more than 40,000-mile network that includes more 765-kilovolt extra-high voltage transmission lines than all other U.S. transmission systems combined. AEP also operates 224,000 miles of distribution lines. AEP ranks among the nation’s largest generators of electricity, owning approximately 31,000 megawatts of generating capacity in the U.S. AEP also supplies 3,200 megawatts of renewable energy to customers. AEP’s utility units operate as AEP Ohio, AEP Texas, Appalachian Power (in Virginia and West Virginia), AEP Appalachian Power (in Tennessee), Indiana Michigan Power, Kentucky Power, Public Service Company of Oklahoma, and Southwestern Electric Power Company (in Arkansas, Louisiana, and eastern Texas). AEP’s headquarters are in Columbus, Ohio.

By the Numbers

  • 18.5 million records converted
  • 1.5 million meters migrated to Oracle Utilities Meter Data Management
  • 2 time zones
  • 4 operating companies impacted which comprised nearly 1.9 million meters including:
    • 1.2m in Texas
    • 550k in Oklahoma
    • 130k in Ohio
    • 10k in Indiana and Michigan


Focused solely on the utility industry Red Clay advises, delivers, and manages technical and business solutions based on their clients’ unique needs. Red Clay works hand in hand with Oracle to offer our clients the industry’s most comprehensive and flexible software platform. Red Clay’s strong partnership with Oracle Utilities provides our clients with innovative and proven solutions. For more information, visit

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Deregulation is the reduction or elimination of government power in a particular industry. The goal of deregulation is to create more competition and let the free market prevail. In the energy industry, a deregulated market is one where utility companies must divest all ownership in generation and transmission of energy. The utility companies are only responsible for distribution, operation, maintenance of the interconnection between the grid and the meter, and billing of the customer.
In a regulated market, customers can only purchase utilities from their local supplier. The price is government-regulated and since only a single distribution source exists, this is what all customers pay. This creates a monopolistic marketplace. Deregulation was introduced in the 1980s. This allowed customers to choose from which energy supplier they wanted to purchase energy. The competition between companies eventually led to competitive prices in the energy market that are visible today in deregulated markets.



The United Kingdom’s (UK) energy market is deregulated. This process of deregulation, or privatization, began in 1989 with the Electricity Act of 1989. This act provided the foundation for privatizing the electricity supply industry in the UK.

Prior to the decision to deregulate, the UK had three state-owned electricity transportation grids that covered the following regions: England and Wales (responsible for 90% of demand), Scotland, and Northern Ireland. England had one main generation and transmission company and nine regional distribution companies, which provided the power to the majority of the UK (England and Wales). The Central Electricity Generation Board (CEGB) owned all of the transmission rights and controlled the production and distribution of electricity in England and Wales. The remainder of the market was split between the South of Scotland Electricity Board (SSEB) and the North of Scotland Hydro-Electricity Board (NSHEB).

After the UK chose to deregulate its energy market, the CEGB was divided into four different companies. Three of these companies were generating companies: PowerGen, National Power, and Nuclear Electric. PowerGen and National Power were privatized, while Nuclear Electric remained under public ownership. The fourth company that was created from dissolving CEGB was National Grid Company (NGC). National Grid Company was privatized as well and is responsible for all transmission activities.

The nine regional distribution companies were privatized with the legislation that dissolved the CEGB and these companies covered twelve distribution regions. During privatization, the regional distribution companies had to make an accounting separation between their distribution and retail activities. This was because the distribution rights gave these companies a regional monopoly and the profits needed to be monitored to ensure fairness for the customers. Initially in the 1989 legislation, the twelve regional distribution companies were given joint ownership of the NGC, but the 1995 legislation required the companies to sell this ownership.

The Scottish portion of the market was divided into three companies following the 1990 legislation. SSEB was divided into two companies. The nonnuclear assets were privatized as Scottish Power whereas the nuclear assets were renamed Scottish Nuclear and remained public. The NSHEB was privatized and renamed to Scottish Hydro.

The Electricity Act of 1989 also established a regulatory agency named the Office of Gas and Electricity Markets (OFGEM). The OFGEM is a government department, and they are governed by the Gas and Electricity Markets Authority (GEMA), which is a board of appointed members that monitor the running of the OFGEM. The primary duty of the OFGEM is to protect the interests of existing and future electricity and gas consumers by promoting competition between the various private energy companies.

Following the deregulation of the energy market in the UK, the OFGEM established price controls to help new competitors break into the market. In 2000, the Competition Act was implemented. With this act, the price controls were removed and competition between the energy suppliers was allowed to occur without interference. The OFGEM released a review of the markets and concluded that supply competition had delivered substantial price benefits for all customers.



After deregulation in the UK, four key areas of competition for energy companies remained: electricity generation, transmission, distribution, and retail. Before deregulation took effect, three major power producers in England accounted for 75% of the UK’s total electricity generation. The highly concentrated market became more diverse throughout the deregulation process, and now over 38 major power producers operate in the UK with a growing number of small power producers. Market diversification in the electric industry has helped the UK transition from a primarily coal-powered country to a country with various means of producing energy.

The electricity that is produced by generators goes on the national transmission network. The NGC controls this transmission system and is the sole system operator. As the system operator, the NGC is responsible for regulating the supply that exists on the national transmission network. Three transmission operators fall under the system operator to develop, operate, and maintain the high voltage grid. They are the Scottish Power Transmission Limited for southern Scotland, Scottish Hydro Electric Transmission plc for northern Scotland and the Scottish islands groups, and the NGC. Since only a few of these groups exist, the OFGEM has to regulate the NGC, as it is a natural monopoly. To regulate the NGC, the OFGEM sets a maximum revenue that the NGC can recover from users of the grid.

The national transmission network is a grid of high voltage transmission lines. From these lines, the electricity is passed to distribution networks, which run at lower voltages to the industrial, commercial, and domestic users. Fourteen licensed distribution network operators (DNOs) are in Britain. These DNOs are responsible for providing electricity to regional areas, and each one is assigned a regional area to service. In addition to the DNOs are Independent Network Operators (IDNOs). The IDNOs are smaller networks that will operate in an area covered by the DNOs. Both the DNOs and IDNOs must hold a license to be able to distribute electricity. The licenses have limits on the amount of revenue the company can recover from their customers, which allows the OFGEM to regulate the DNOs and IDNOs from imposing unfair monopolist prices on the customers.

The last key area for companies to compete in is the retail market. This is the area where consumers can see the changes from deregulation. Customers are now able to shop around and compare electricity suppliers to get the best deal. The retailers buy electricity from the wholesale market or from generators. The retailers then set prices for this electricity, which is what they will charge their customers. The customers’ ability to shop around for the best price from the suppliers places pressure on prices and drives better customer service. In addition, competition for customers incentivizes the suppliers to create more innovative products and services to gain a competitive advantage. The OFGEM monitors these retailers to ensure fairness to the customers.



While deregulation has been implemented in the UK for a little over two decades now, the OFGEM is always looking for better ways to improve the energy market to ensure fairness for the customers. Despite the growing number of players in the generation, distribution, and retail markets, six big companies are still in control of the majority of these markets. In order to allow the free market to prevail, the OFGEM will need to continue to work on policies to help distribute market share.


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7.6.1 Outage Management System

The most definitive characteristic of a smart grid is the ability to share near real-time data throughout the enterprise. Then, this gathered information is further shared across other smart grid information systems to deliver operational and business benefits to the utility. The deployment of advanced metering infrastructure is a prime demonstration of smart grid infrastructure that enables this type of interoperability.

Many utilities have already accomplished interfacing AMI with a meter data management (MDM) solution that automatically validates, edits, and estimates meter readings, streamlines billing processes, and supports beneficial rate designs. Now, industries with AMI are looking for ways to integrate MDM with outage management systems (OMS.) By


implementing this, utilities may obtain operational intelligence that allows more efficient and accurate outage detection, restoration, and verification. OUTAGE DETECTION

Prior to smart meters and more advanced technology, the biggest input to OMS was customer phone calls, e.g. “My lights are out.” But in general, less than 20% of affected customers will report an outage for a variety of reasons – for example, not being home, or assuming that the outage has already been reported by others. The integration of AMI and OMS allows utilities to be very accurate in defining the impacts of a power outage, which leads them to employ proactive communications systems – telling the customer about a power problem instead of the customer telling the utility.

This level of customer notification service is taken for granted in industries such as travel (“Your flight is delayed”) and banking (“Your monthly statement is ready.”) Seeing customers translate these same expectations of service to utilities is not surprising. Access to smart devices is expanding rapidly for customers, as is their thirst for information. A customer’s ability to access information during a power outage is increasingly based on channels including text messaging, websites, and smart phone applications. By offering better information on a variety of channels during a power outage, utilities can proactively reach out to all affected customers and provide the latest updates on power problems, while increasing customer satisfaction in the long run.

While consumer-reported events must be tracked and managed by OMS, AMI event reporting is more immediate, reliable, and available. An OMS can quickly leverage this information using the tracing and prediction analysis functions of a real-time operations distribution network model to determine the location and hierarchy of the affected devices and faults. AMI cannot do this on its own since the topologies of AMI communication networks have no knowledge of the power distribution network beyond the relationship of a meter to a customer’s service point and premise. Leveraging the utility’s geographic information systems (GIS), the OMS can accurately maintain the current state of the network and provide users with a geospatial view of network activity. OUTAGE RESTORATION

Smart meter sends a last gasp message to the utility’s OMS system before the meter loses power. Not all last gasp messages make their way to the OMS, but usually enough messages are received to help the utility adequately determine which customers and areas are affected. This outage event data can increase the accuracy of outage predictions and help utility personnel to promptly and accurately react to power failures. The end result is that utilities operate more efficiently, field activities are assigned to the repair crews more accurately, and customers can get back to their normal life more quickly, all at a lower cost.

During major power issues prior to smart meter technology, it was common for utilities to dispatch crews to restore service to a customer whose service had already been

restored or had never had problems that required a field visit. Utilities maximize the value of smart meters for service restoration through automated integration with AMI and OMS. This integration provides utility personnel the ability to visualize the full scope of damage, locate the area, prioritize work order, and then pass information to appropriate crews with essential details before dispatching them for restoration.

In addition, the OMS interfaced with the AMI allows automatic or manual pinging of meters. While the response time of a ping request is variable, utilities using this functionality experience significant savings by validating events, eliminating unnecessary truck rolls, and consequently making more efficient use of crews. OUTAGE VERIFICATION

Another benefit of integration of AMI and OMS is verification of power restoration. Restoration verification is accomplished when a meter reports in with normal usage data after being reenergized. This provides automated and positive verification that affected customers have been restored, no nested outages are detected, and associated outage events as well as work orders are closed before restoration crews leave the area.

Similarly, pinging meters remotely to validate restoration helps identify any residual or nested outages resulting from multiple faults downstream of a specific device. The OMS prediction engine performs the business logic required to create new incidents for the existing nested outages.


Identifying nested outages while restoration crews are on site eliminates the associated customer callbacks, customer service costs, and

most importantly, duplicate trips to the field.

With outage causes identified and isolated more quickly, the synergy of integrated AMI and OMS brings all the advanced tools and functions needed to reduce outage duration and cost due to faster response and restoration. AMI LEADS TO INTEGRATION WITH NMS/OMS

Most meters used in advanced metering infrastructure (AMI) systems have a last-gasp capability, which is a high-priority message transmitted by the meter that service is out. With a large outage, the last-gasp functionality can overwhelm an AMI system because of message collisions in the communication network.

New AMI technology is able to overcome such problems. Some AMI systems do not just send a single last-gasp. Rather, they send a series of “power out” status messages, which are device outage events. Some mesh networks also combine outage information. As a result, instead of having countless distinct outage messages, a utility might only have a packet with outage information. The same amount of information makes its way through the network, but more efficiently. Furthermore, some AMI systems have the ability to filter or throttle the amount of outage information that is making its way to the OMS so that it doesn’t overwhelm the OMS. BENEFITS OF INTEGRATION WITH NMS/OMS

Integration with NMS and OMS is revolutionizing how utilities deal with outage activity. Increased customer satisfaction and decreased costs to restore power is the ultimate goal of utilities when it comes to outage management. This goal can be achieved from multiple perspectives.

  • Improved device prediction accuracy by using meters to verify outages in a timely manner. Ideally, the OMS will identify and validate an outage before the first customer calls to report the outage. The interactive voice response (IVR) should notify the customer that the utility is aware of the outage and responding. This leads to improved customer satisfaction.
  • Improved crew management and utilization by reducing the crew effort required to return, repair, and restore nested outages by pinging meters to validate power restoration of all customers affected.
  • Improved outage detection and management process where outage can be verified even without customer intervention. It supports real time outage events, which means when an outage happens to an AMI meter, the meter sends out the outage event to downstream systems, including NMS. So NMS is made aware of an outage reported by smart meters. When power is back and meter is powered up again, it sends a restoration event to NMS. These events with time-stamps make sure customers will not be charged during the outage window. NMS also has the ability to ping a meter to confirm power on at the utility side of the meter base, they are more informed when dealing with customers who have been disconnected for payment arrears.
  • Detection of outages at distribution transformers or other common points of failure can improve response times and reduce restoration costs. This is especially valuable in remote areas where the crew would normally have to spend a significant amount of time patrolling the grid to find the exact fault location.
  • Improved accuracy of distribution network reliability statistics by detecting outages in a timely manner.
  • Prioritizing restoration efforts and managing resources based on defined criteria such as the size of outages and the locations of critical facilities.
  • Validation of liability claims. Detection and recording of outages allows utilities to know which claims attributed to outages actually correlate to an outage and which do not. LIMITATIONS OF NMS/OMS

Like any other systems, NMS or OMS has its own limitations. Utilities need to understand the limitations and prepare additional plans to cover the business process that NMS or OMS does not reach.

  • OMS does not “manage” the utility’s restoration. It is not a substitute for the utility’s emergency restoration plan (ERP).
  • OMS does not provide information about damage.
  • OMS does not directly provide estimated restoration times or other information that would be valuable to customers.
  • An OMS can become overwhelmed in extreme situations and may not be able to deliver promised benefits in all scenarios.



In electrical engineering, a load profile is a graph of the variation in the electrical load versus time. In real life, a load profile will vary according to customer types, temperature, and holiday seasons. Utilities use this information to plan how much electricity they will need to make available at any given time.

In an electricity distribution grid, the load profile of electricity usage is important to the efficiency and reliability of power transmission. The power transformer or battery-to-grid are critical aspects of power distribution; sizing and modelling of batteries or transformers depends on the load profile. The factory specification of transformers for the optimization of load losses versus no-load losses is dependent directly on the characteristics of the load profile, which the transformer is expected to be subjected to. This includes such characteristics as average load factor, diversity factor, utilization factor, and demand factor, which can all be calculated based on a given load profile. LOAD PROFILE FOR UTILITIES

For utility companies with AMI, the data being collected by smart meters can be utilized in many ways. Depending on how the reading is set up, usage data could come in daily, hourly, or even every fifteen minutes or less.

It doesn’t matter whether the data is hosted onsite at utilities or offsite at the AMI metering companies. In order to make good use of this data, it must be correctly analyzed. This data can also be called load profile data. The concept of load profile is not new, and it has been available for many years on the high- end meters for commercial and industrial customers. With the implementation of AMI, now even residential customers can benefit from individual load profile to manage their power consumption more wisely. LOAD PROFILE USE SCENARIO – RESIDENTIAL

Here’s a scenario for a regular residential customer:

Let’s say a customer is complaining that their electricity bill is way too high, and they are not using the amount of electricity the meter says they are. Their AMI watthour meter was setup to report on fifteen minute intervals. By pulling up their load profile data, the customer representative gets a graph of the usage every fifteen minutes of the day. First, look at the graph during times that the customers are sleeping to see if the load is constant. Spikes may occur during the night when the A/C comes on and off and when the water heater comes on and off. These regular spikes can be spotted right away. What takes more attention to discover is whether usage is constant overnight. If usage is constant, then compare it during the day and see if it goes off then. If it does not, then the customer needs to track it down and turn the device off. After all, the customer could be having a problem with an appliance that does not go off, or they kept something plugged which consumes much more electricity than expected. LOAD PROFILE USE SCENARIO – COMMERCIAL AND INDUSTRIAL

Here’s a scenario for commercial and industrial customer:

A customer calls in and complains that their demand charge is way too high, and they want to know how they can lower it. In order to meet commercial and industrial customers’ complicated consumption needs, it requires the utility company to keep a vast array of expensive equipment – transformers, wires, substations, and even generating stations on constant standby. The amount and size of this equipment must be large enough to meet peak consumption periods, i.e., when the need for electricity is highest. Utilities and public service commissions around the country have determined that the most equitable way to cover the cost of this equipment is to have those customers who create this demand and the need for power during these peaks pay for its availability, which translates to a separate charge in their electricity bills. By examining the load profile data for that customer and showing them different spikes throughout the day, they may realize that the cause of high demand is due to coming in first thing in the morning and turning on their machines, lights, and A/C all at once. This naturally resulted in their demand being high, but only for a small amount of time throughout a working day. One of the things that the customer can do to reduce their demand is to stagger when they turn everything on.


7.6.3 GIS

To fully take advantage of the link between AMI and OMS, utilities are exploring opportunities to link the technologies with their supervisory control and data acquisition, customer information systems (CIS), IVR and GIS, all of which can generate additional useful information during outages. For instance, CIS and GIS are base data systems that feed into OMS. They help to determine where all the meters are and which customers are associated with which meters. This doesn’t help the OMS determine outages. However, as AMI data flows into the OMS, it includes a tag, such as the meter or premise ID, so the OMS knows which customer should be assigned the outage. GIS is then needed to analyze the locations of customers and determine work order solutions at different locations. BENEFITS OF INTEGRATION WITH GIS

Further integration with GIS makes turns millions of service locations into a big picture.

  • GIS is widely used to optimize maintenance schedules and daily fleet movements. Typical implementations can result in a savings of 10-30% in operational expenses through reduction in fuel use and staff time, improved customer service, and more efficient scheduling. The cost of fuel and labor is reduced from greater efficiency.
  • GIS is the go-to technology for making better decisions about location. Common examples include real estate site selection, route/corridor selection, evacuation planning, conservation, and natural resource extraction. Making correct decisions about location is critical to the success of an organization.
  • GIS-based maps and visualizations greatly assist in understanding situations and in storytelling. They are a type of language that improves communication between different teams, departments, disciplines, professional fields, organizations, and the public.
  • Many organizations have a primary responsibility of maintaining authoritative records about the status and change of geography. GIS provides a strong framework for managing these types of records with full transaction support and reporting tools.
  • GIS is becoming essential to understanding what is happening and what will happen in geographic space. Once we understand, we can prescribe action. This new approach to management—managing geographically—is transforming the way organizations operate.



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Here is a list of relevant reading material our expert identified as sources for additional information:

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7.5.1 L&G

Landis+Gyr is a “global industry leader in metering solutions for electricity, gas, heating, cooling, and water for energy measurement solutions for utilities. Since 1896, the company has been helping customers overcome operational, regulatory, and consumer-driven challenges by capturing the advantages and benefits of technology. Focused on quality, reliability, and innovation, the group offers a complete portfolio of energy meters and integrated smart metering solutions, enabling utilities and end-users to make better use of scarce resources, save operating costs, and protect the environment by managing energy better – and to build the smart grid.

L&G offers the following Gridstream solutions in addition to numerous products and services:

Advanced Metering Infrastructure (AMI)

Advanced metering goes far beyond the simple reading of a meter. It sends and receives information from every touchpoint on the distribution system – enabling big data for intelligent operation.

Landis+Gyr offerings allow for real-time communication and control of smart meters for electricity, heat, and gas. At the same time, sensing devices and data management software ensure data is available and correct for analysis and billing.

AMI functions include –

  • Measurement and monitoring.
  • Communications network monitoring and management.
  • Command and control.
  • Data collection.
  • Meter data management.
  • Customer connection and tariff management.

Customer Intelligence

In the digital age, utility customers demand more visibility into, insight around, and control over their energy usage. That’s why Landis+Gyr invests in technologies that enable utilities to engage better with their customers and meet end customer needs via software, platforms, and products that help them manage their own energy usage better.

Custom Intelligence functions include:

  • Access to energy usage data.
  • Billing options, prepayment and tariff management.
  • Microgeneration management.
  • Home automation.
  • Consumer engagement programs.

Distribution Intelligence

Distribution Intelligence is about seeing what is happening on the grid and providing utilities with the tools to take action, as needed, to ensure the reliable and efficient delivery of energy in a dynamic environment. In a word, Gridstream will make your distribution system smarter. An increasingly intelligent grid that can model, control, and seamlessly optimize assets is required to manage supply and demand, adjust to two-way power flow from distributed generation, and ensure power quality remains high. Gridstream provides a combination of intelligent sensors, storage, communications and software technologies to get the job done.

Distribution intelligence functions include:

  • Outage and restoration management.
  • Distribution automation.
  • Distributed energy resource management.
  • Distribution grid visualization and optimization.
  • Energy storage.
  • Grid planning, monitoring, and management.
  • Electric vehicle integration.
  • Demand and supply side management.”

7.5.2  ELSTER

Elster is a “leading global provider of gas, electricity, and water meters and related communications, networking, and software solutions.

Elster Group GmbH employs more than 7,000 staff and operates in more than thirty-nine countries. Their diverse portfolio of products and solutions are used to accurately and reliably measure gas, electricity, and water consumption as well as enable energy efficiency and conservation. Elster sells products and solutions to utilities, distributors, and industrial customers across gas, electricity, water, and multi-utility organizations for use in residential, commercial, and industrial settings. Their customers operate in more than 130 countries and include numerous large, medium, and small utilities. Elster meets the expanding needs of utilities by providing advanced metering products and services worldwide. They provide the following electricity solutions in addition to various gas and water metering.

Electricity Solutions

Their solutions bring together an experienced team of people, cutting-edge technologies, and strategic partners to deliver world class products, systems, and services to our utility clients worldwide. The company has two main areas of business – electricity metering products and smart metering and smart grid system solutions. Elster engineers fully interoperable smart electricity metering products through custom-made options for utility customers and award-winning, end-to-end solutions for the smart grid and multi-utility advanced metering infrastructure (AMI) systems for water, gas and electricity around the world.

Energy Management

Energy management solutions from Elster EnergyICT enable utilities to grow and maintain energy efficiency programs with continuous savings. Their solutions provide with the information, the insight, and the intelligence utilities need to control energy consumption across the entire organization.”

7.5.3 ITRON

Itron is the largest manufacturer of smart meters in the world. It is an “American technology company that offers products and services on energy and water resource management. Its headquarters is in Liberty Lake, Washington, United States. Its products and services include technology solutions related to smart grid, smart gas, and smart water that measure and analyze electricity, gas, and water consumption. Its products include electricity, gas, water, and thermal energy measurement devices and control technology, communications systems, software, and managed and consulting services. Itron has over 8,000 customers in more than 100 countries. Itron offers the following solutions in addition to numerous gas and water metering solutions:

  • Advanced Metering Infrastructure (AMI)
  • Smart Grid and Distribution Management
  • Meter Data Management
  • Smart Payment
  • Advanced C&I Solutions
  • Electric Meters and Modules”



GE as it is popularly known is one of the biggest global players in the green industry. General Electric, like other industrial conglomerates such as Siemens, Areva, and others are low-risk players in the green investing sector. GE is strong across most of the green sectors today particularly in the area of smart grid and energy efficiency. GE is not that big in the smart meter market, but with its overarching scale it has quickly won a number of contracts.



One of the largest electrical and energy equipment suppliers in the world, Schneider has been one of the most aggressive in mergers and acquisitions. The company provides energy efficiency solutions to residential markets, buildings, industry, infrastructure, and data centers. The company’s range of services and products is quite awesome and provides a holistic solution to its customers. Though not a major player in the smart meter market yet, the company cannot be underestimated in the future.


If you enjoyed this article, click here to start from the beginning of our Industry 101 Series.

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Here is a list of relevant reading material our expert identified as sources for additional information:

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7.4.1 ENERGY (kWh)

Energy is a measure of how much fuel is contained within something or used by something over a specific period of time.

The kilowatt hour is a unit of energy equivalent to one kilowatt (1 kW) of power sustained for one hour. If the energy is being transmitted or used at a constant rate (power) over a period of time, the total energy in kilowatt hours is the power in kilowatts multiplied by the time in hours.


7.4.2 POWER (kW)

Power is a measure of how fast something is generating or using energy.

The base unit of energy within the international system of units (SI) is the joule. The hour is a unit of time outside the SI, making the kilowatt hour a non-SI unit of energy. The kilowatt hour is not listed among the non-SI units accepted by the BIPM for use with the SI, although the hour, from which the kilowatt hour is derived, is.

Instantaneous Power

The instantaneous power (also known as instantaneous demand or instantaneous load) is the power that something is using (or generating) at any one moment in time. Put your laptop on standby and its instantaneous power will drop immediately. Bring it back to life and its instantaneous power will rise immediately.

If, at any particular moment, everything in an office building is switched on, that office building might be using 42 kW of power. That’s 42 kW of instantaneous power. If, at any particular moment, everything in the office building is switched off, that building should be using 0 kW of power. That’s 0 kW of instantaneous power.

The instantaneous power of most buildings varies constantly. People are constantly switching things on and off, and many items of equipment within the building have instantaneous power that is constantly changing too.

Average Power

The average power represents the power that something uses or generates, on average:

  • Over a specific period of time, e.g. yesterday.
  • Over multiple periods of time,e.g. across all the weekends on record.
  • Throughout a certain type of operation, e.g. typical laptop usage or typical building usage on Monday to Friday 09:00 to 17:00, or typical efficiency for something that’s generating power.

You can easily use these average-kW figures to compare the energy consumption of different periods and even different buildings.



The relationship between energy and power is similar to the relationship between distance and speed:

  • Energy is like distance. The amount of energy that you used over a specific period of time is like the distance that you travelled over a specific period of time, e.g. when driving to work you travelled 2 miles between 08:04 and 08:57.
  • Power is like speed. Your instantaneous power is like your speed at a specific instant in time, e.g. right now. Your average power over a specific period of time is like your average speed over a specific period of time, e.g. when driving to work you travelled at an average speed of 2.26 mph.

Both distance and speed are useful measures; and both are closely related. Sometimes it makes sense to talk in terms of distance, and sometimes it makes sense to talk in terms of speed. It’s the same for energy and power – you need both, but usually one makes more sense than the other.

In many cases, electricity use is metered and charged in two ways by utilities. First, based on total consumption in a given month (kWh). Second, the demand, based on the highest capacity you required during the given billing period (kW).

Depending on your rate structure, peak demand charges can represent up to 30% of your utility bill. Certain industries, like manufacturing and heavy industrial, typically experience much higher peaks in demand. This is largely due to the start up of energy-intensive equipment, making it even more imperative to find ways to reduce this charge. Regardless of the industry, taking steps to reduce demand charges will save money.



Reactive power (kVArh) is the difference between working power (active power measured in kW) and total power consumed (apparent power measured in kVA). Some electrical equipment used in industrial and commercial buildings requires an amount of reactive power in addition to active power in order to work effectively. Reactive power generates the magnetic fields which are essential for inductive electrical equipment to operate – especially transformers and motors. This load is measured via the reactive register on your half-hourly meter.

The theoretical definition of the reactive power is difficult to implement in an electronic system at a reasonable cost. It requires a dedicated DSP to process the Hilbert transform necessary to get a constant phase shift of 90° at each frequency.

The power triangle is based on the assumption that the three energies – apparent, active, and reactive – form a right-angle triangle that can then be processed by estimating the active and apparent energies and applying.

The reactive power: Sqrt[(Apparent power)^2-(Active power)^2]

Although this gives excellent results with pure sinusoidal waveforms, noticeable errors appear in presence of harmonics.



Time of use, or TOU as it is commonly called, is the segregation of energy rates based on the time in which the energy is being consumed. TOU is a way in which utility providers attempt to alleviate demand during peak periods by enforcing a tariff structure that charges an increased rate within the typical peak consumption time periods. TOU is broken into three structures or groupings with various names in reference to peak, off peak, and the time of moderate use referred to as shoulder time or mid-peak. These TOU groupings can vary based on region and have become increasingly deployed in utility electricity charges.

TOU has been implemented to change consumer behavior and to ease the strain of energy usage required at its most in-demand time, thus decreasing the likelihood of power outages and overgenerated power. TOU has become an effective way for utilities to manage their production and allow for consumers to take control of their energy bills. This added control has led some savvy consumers to dramatically cut costs by reviewing their cost allocation and making use of tools and practices such as load shedding and running machines at off-peak hours.


Time of Use Power Meter

A time of use power meter is a multifunction power meter equipped with TOU for single- and three-phase circuits. It features a Modbus RS485 serial connection in which the meter can connect to the free data logging software to take advantage of this feature. While connected to the software, the meter is able to segregate up to four different tariffs, twelve seasons, and fourteen schedules.

This option is a cost-effective solution for users monitoring a single circuit that are able to connect the meter to a dedicated computer and are typically featured in smaller applications where TOU billing has been implemented.


Time of Use Power and Energy Meter

A time of use power and energy meter is an intelligent multifunction power meter with TOU enabled for single- and three-phase circuits. The meter features Modbus RS485 communication standard and can be upgraded to include Modbus TCP Ethernet, BACnet, Profibus, and a variety of other communication protocols and I/O expansions for added versatility. The meter can be serially connected to a computer hosting the free software or can be remotely connected to the computer utilizing an ethernet connection.

As this meter has remote metering capabilities, multiple units are able to be connected to the same central computer or system allowing for utilization in larger projects with multiple users such as residential or commercial buildings or for a more granular look at machines and devices in order to take control of operating costs, generate cost allocation, and determine if load shedding is required.



Net metering is a billing mechanism that credits solar energy system owners for the electricity they add to the grid. For example, if a residential customer has a photovoltaic (PV) system on the home’s rooftop, it may generate more electricity than the home uses during daylight hours. If the home is net-metered, the electricity meter will run backwards to provide a credit against what electricity is consumed at night or other periods where the home’s electricity use exceeds the system’s output. Customers are only billed for their net energy use. On average, only 20-40% of a solar energy system’s output ever goes into the grid. Exported solar electricity serves nearby customers’ loads.

While net metering policies vary by state, customers with rooftop solar or other distribution grid systems usually are credited at the full-retail electricity rate for any electricity they sell to electric utilities via the grid. The full-retail electricity rate includes not only the cost of the power, but also all of the fixed costs of the poles, wires, meters, advanced technologies, and other infrastructure that make the electric grid safe, reliable, and able to accommodate solar panels or other DG systems. Through the credit they receive, net-metered customers effectively avoid paying these costs for the grid. BENEFITS OF NET METERING
  • The system is easy and inexpensive. It enables people to get real value for the energy they produce without having to install a second meter or a battery storage system.
  • It allows homeowners and businesses to produce energy, which takes some of the pressure off the grid, especially during periods of peak consumption.
  • Each home can potentially power two or three other homes. If enough homes in a neighborhood use renewable energy and net metering, the neighborhood could potentially become self-reliant.
  • It encourages consumers to play an active role in alternative energy production, which both protects the environment and helps preserve natural energy resources.


  • Homes that use net metering tend to be more aware of, and therefore more conscientious about, their energy consumption.
  • It saves utility companies money on meter installation, reading, and billing costs.
  • The following graph illustrates the benefit of using net metering system for kw demand registers NET METERING GUIDING PRINCIPLES

Established in 1974, the Solar Energy Industries Association is the national trade association of the U.S. solar energy industry. Through advocacy and education, SEIA is working to build a strong solar industry to power America. As the voice of the industry, SEIA works with its 1,100 member companies to make solar a mainstream and significant energy source by expanding markets, removing market barriers, strengthening the industry, and educating the public on the benefits of solar energy. As the national trade association for the solar industry, SEIA continues to advocate equally for all forms of solar energy including residential, commercial, and central-station solar generation as well as solar heating and cooling applications. The following are guiding principles:


Right to self-generate, connect to the grid, and reduce grid electricity use: Every retail electricity customer has the right to install solar generation equipment at the customer’s site, interconnect to the utility grid without discrimination, and reduce his or her grid electricity use. Reductions in customer grid electricity use due to solar generation should not be imputed as a cost to the utility.


Properly valuing solar electricity and adequately compensating solar customers: Customer-sited solar generation offers many benefits to the electric grid system and by extension to non-solar customers, including but not limited to: reduction in utility energy and capacity generation requirements, reduction in system losses, avoidance or deferral of distribution and transmission investments, localized grid support including increased reliability benefits, fuel-price certainty, and reductions in air emissions and water use.  The aforementioned benefits should be quantified, and solar customers should be adequately compensated for the value their solar energy is delivering to the grid.


Non-discriminatory practices within cost of service recovery: In determining cost allocation, net energy metering customers should not be treated unfairly vis-à-vis other ratepayers and all benefits should be accounted for.  Punitive and non-cost based charges should be prohibited.  Consistent with SEIA’s rate design principles, a utility should have the opportunity to recover its costs of providing service and earn a return on investment as determined by regulators.


No net energy metering caps: Consistent with the policies laid out in these guidelines, no aggregate or statewide limit for net energy metering should exist.


Statewide application: Net energy metering rules, regulations, and practices should be standardized statewide.


Transparency, access to data: Customers, or solar companies on customers’ behalf, should have access to data regarding their own electricity consumption, such as load data including hourly profiles, with transparency into the tariffs available to them.  Billing statements from utilities should clearly show the net energy metering consumed from the utility, and any energy or dollar credits carried forward as a result of solar generation in previous billing periods. IMPLEMENTATION BEST PRACTICES

Individual System Capacity: Any individual system size limitation should be based only on the host customer’s annual load or consumption.

REC ownership: The owner of a net energy metered system should retain ownership of renewable-energy credits (RECs) produced by their owned system, unless transferred to the utility or another party in exchange for acceptable compensation.

Restrictions on “rollover”: Indefinite rollover, credited at retail rate, should be an option for customers. The only exception is allowing for payments for annual net excess generation.

Metering equipment: Consistent with all retail applications, the utility shall provide a meter that is capable of net energy metering.  Retail electric customers utilizing net energy metering must not be required to purchase new energy metering equipment.

Customer classes: All customers should be able to participate in net energy metering.

Aggregation: Virtual net energy metering and meter aggregation options should be available to all customers.


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Here is a list of relevant reading material our expert identified as sources for additional information:

As part of our internal training for new hires, Red Clay Consulting provides an A-to-Z introduction to the energy industry. Because our industry is so unique, we know its important for each of our staff to understand all of the components, not just the products and services we provide. So our experts collaborated to compile an introduction to the utilities industry. The purpose was to share this expertise not only as part of our new hire process, but with colleagues, clients and even the general public.

The first edition of this information is focused primarily on the electricity segment and includes thorough explanation of participants, operations, market dynamics, regulation, settlements, smart grid, smart meters, and more. We add to the campaign weekly – click here to see all recent posts or click here to start at the beginning of the series.

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