Choices for Smart Grid Implementation

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1 Choices for Smart Grid Implementation Adrianus G.van Engelen New Hampshire Electric Cooperative Plymouth, NH J. Stephanie Collins, Ph.D. Southern New Hampshire University Manchester, New Hampshire Abstract Utility companies are under pressure to reduce their own operating costs and support energy savings, while providing more services to their customers. These new services will be expected to include better information for customers to help them make decisions about energy use and optimizing current energy availability. This paper describes the use of Advanced Metering Infrastructure (AMI) as a way of monitoring energy usage, increasing operating efficiencies for the utility, and enabling information flows for supporting energy-saving schemes. Several options for implementing AMI are discussed. The impact of recent developments in communications protocol standardization is considered. The discussion includes the criteria and factors that should be used for making a choice among the possible options. The specific case examined here is an electric cooperative utility company in New Hampshire. 1. Introduction The ability to access real-time information is increasingly important in an electric utility s ability to cost effectively deliver reliable power and affects both the profitability of the utility and customer satisfaction. Operational, commercial, and regulatory demands require almost instantaneous access to continuous information as well as the ability to provide customers with up-to-date electric usage data and rate information. Knowing which meter or endpoint, or, in other words, which customer, is without power at any given time is important from an operational and outage management point of view, allowing for better planning, most efficient use of resources, and shorter outage times. From a commercial standpoint, rising operating costs and higher customer expectations with regard to pricing options and quick resolution of power outages require better-quality data in order for a utility to operate as efficient as possible. The Energy Policy Act of 2005 [1] requires the Department of Energy to study the benefits of time-based pricing and demand response programs. Further regulations that require utilities to make these programs available to its customers can be expected in the near future. The Public Interest Energy Research program managed by the California Energy Commission [2], for example, has conducted research into benefits of distribution automation applications and Advanced Metering Infrastructures to electricity and gas rate payers in the state of California. The findings identified benefits such as cost reduction through automated meter reading, more efficient use of utility assets and investments, more accurate billing, more efficient outage restoration, improved pricing and tariff structures, and better electricity usage information for customers. In order for a utility to be able to make timebased pricing and demand response programs available to its customers it needs more timely and detailed electric usage data. This data is needed to create comprehensive load profiles that are the basis for demand response programs. Electric meters must be read every hour as supposed to every month. A traditional door-to-door or drive-by meter reading process is not sufficient to meet these new near-realtime data requirements as it simply does not provide enough data. Consequently, utilities have been exploring cost-effective and reliable alternative technologies that best fit their specific business needs. A significant number of, mostly cooperatively organized, utilities have implemented Automated Meter Reading (AMR) systems and more recently Advanced Metering Infrastructures (AMI) [3]. The five states with the most significant AMI system deployments are Pennsylvania, Wisconsin, Connecticut, Kansas, and Idaho [3]. Many utilities are interested in AMI technology. A 2007 study by Chartwell [4] found that at least 70 percent of utilities are either considering or implementing AMI systems /10 $ IEEE 1

2 The implementation of such systems requires utilities to make significant investments. The total capital cost of implementing an AMI system includes endpoint hardware (i.e. meters), network hardware, installation, project management, and information technology. Most evident is the need to replace the traditional electromechanical meter at each service location with a solid state or Smart Meter in order to enable two-way communication. Considering that the cost of a solid state meter is approximately $76 and the cost related to the communications infrastructure ranges from $125 to $150 per meter, a utility with 100,000 customers would need to invest anywhere from $20.1 million to $22.6 million to implement an AMI system. The selection of and installation of an AMI has many aspects. We will first describe an AMI and the various technologies that are offered to implement such a system as well as some of the functions that each of these technologies make available to a utility and its customers. We will then use the New Hampshire Electric Cooperative and, in particular, the characteristics of its service territory, to illustrate the various issues and alternatives that must be considered before a final decision can be made as to what type of AMI implementation will be the right option in their specific situation. 1. Advanced Metering Infrastructure (AMI) Systems Implementing an AMI system is fundamentally a telecommunications project. An Advanced Metering Infrastructure, or AMI, can be defined as a comprehensive, integrated collection of devices, a communications network, computer systems, protocols, and organizational processes dedicated to distributing highly accurate information about customer electricity, gas, and water usage throughout the utility for use by the utility and its customers. The key principle is the exchange of information or communication. With the development of new technologies, the AMI is expanding into the home of the customer, allowing for the implementation of, for example, time-based pricing and demand response programs. This has resulted in an AMI being referred to as a Smart Grid. The core business of a utility is to cost effectively deliver reliable power. An AMI delivers the information needed to do that more effectively. It can also provide the information that allows a customer to save energy. AMI systems have evolved from primarily oneway Power Line Carrier (PLC) systems, commonly referred to as Automated Meter Reading (AMR) systems. The functionality of AMR systems is, as the name implies, limited to basic automated meter reading and they were introduced to reduce the cost of reading meters and improve the accuracy of customers bills. The most significant characteristic of an AMI system is that it provides two-way communication as opposed to the limited one-way communication of a typical AMR system. Two major types of AMI systems can be identified: Power Line Carrier and Fixed Wireless Network Power Line Carrier Power Line Communication, or, more commonly referred to as Power Line Carrier (PLC), is a system that uses the existing power or distribution line infrastructure of a utility to send and receive information. The power lines are used to carry the data from the endpoints or meters to a sub-station. The communication from the sub-station to the master station at the headquarters of the utility, referred to as the backhaul, can be implemented by a fiber optic connection. As part of the overall communications infrastructure of a utility, this backhaul can also be used to communicate critical data concerning the status of equipment at the substation. The major vendors that offer PLC systems are Landis+ Gyr, Cannon Technologies, and Aclara. Each of these vendors implements PLC using distinctive modulation and networking technologies resulting in different capabilities of each system due to differences in speed with which the data is transported. PLC systems can be implemented with either one-way or two-way communication. In a PLC system an injector puts a modulated carrier signal onto the power line. The major advantage of a PLC system is that, under normal operating circumstances, all meters can be reached, as opposed to a wireless solution, where 100 percent service territory coverage is not necessarily possible. The obvious disadvantage is that meters cannot be reached when power lines are down. The main concern with PLC systems is that they are generally slow and provide less bandwidth than wireless systems. The PLC system of Cannon Technologies is an exception in that it is considerably faster than the PLC systems of most of its competitors: an ondemand read can be completed in approximately 3 to 6 seconds. 2

3 Different modulation techniques are used. Landis+Gyr, for example, utilize Frequency Division Multiple Access (FDMA) modulation and Cannon Technologies uses Time Division Multiple Access (TDMA) modulation to transmit data Fixed Wireless Network Systems In a Fixed Wireless Network system the endpoints or meters communicate using radio signals, carrying signals and data from meter to meter and subsequently to take-out points. A Fixed Wireless Network is fixed in the sense that the equipment to collect the data (i.e. antennas, towers, repeaters, etc.) is permanently installed. Communication between the take-out points and the headquarters of the utility, referred to as the backhaul, can be implemented in various ways, using a combination of wireless technology (microwave) and fiber optics. The radio signals are affected by the materials they must pass through (i.e. tree foliage, rain, buildings, etc.) and the signal will gradually attenuate. To resolve this issue, repeaters are incorporated in the system to strengthen the signal where meters are at a greater distance than the signal can reach or are used to circumvent an obstruction such as a building or mountain. Fixed Wireless Networks are therefore better suited in an urban setting where meters are closer together than in a rural and mountainous territory where greater distances need to be covered and signals are obstructed by the contours of the terrain. A propagation study can determine how reliable a Fixed Wireless Network will be in a given situation. In such a study, geographic information and meter coordinates (i.e. longitude and latitude) are used to predict the signal strength from the transmitter in a meter to points its vicinity (i.e. other meters). The results from a propagation study allow a utility to determine the feasibility of a Fixed Wireless Network given the characteristics of its service territory. In particular, where greater distances need to be covered between endpoints or the terrain introduces obstacles, the propagation study will identify how many (additional) tower locations and repeaters are needed to be able to cover the entire service territory. This information is vital in determining the cost of a Fixed Wireless Network. Some of the major vendors that offer Fixed Wireless Network solutions to implement an AMI system are Itron, Elster, Landis+Gyr, Sensus, and Tantalus. Each of these vendors combines the various components of a Fixed Wireless Network into their own specific design. Common network topologies that are used are a either a star network or a mesh network. In a star network a meter transmits its data to a central collector and each meter must be preconfigured to establish the communication path from each individual meter to the collector point. Some collectors might also have the capability to transmit or forward data to a central collector. If, due to equipment failure, a communication path is broken, the utility will need to manually re-configure the network to re-establish communication. A key feature of a mesh network is that it is self-configuring and self-healing. The meters themselves in a mesh network act as repeaters and pass data and signals from one meter to the next. Each meter is capable of autonomously finding a nearby meter and collectively the meters establish a path to the collector. If one meter in the network is unable to receive a signal, the transmitting meter will automatically find another meter to re-establish the path. The use of wireless communication is heavily regulated throughout the world. In the United States it is the Federal Communications Commission (FCC) that regulates interstate and international communications by radio, television, wire, satellite and cable. A license is required to operate in certain parts of the spectrum, but, as in most countries, other parts of the spectrum can be used license-free. Most AMI vendors use the license-free Industrial, Scientific, and Medical (ISM) bands to implement a Fixed Wireless Network. This reduces the cost and complexity of implementing an AMI. Some of the frequencies that can be used licensefree in North America are the 900MHz, 2.4 GHz, and 5.7 GHz bands. The 900 MHz band is commonly used for the communication between meters because this frequency has both a reasonable operating distance and enough bandwidth for its particular purpose. The typical operating distance for the 900 MHz band in a line-of-sight application is 15 to 25 miles (using 1W and 6dB gain antennas) and 20 to 60 miles (using 100mW and 16dB antennas). The communication between electric meters is unlikely to be line-of-sight and the reliable operating distance drops to about 500 to 5000 feet in areas with too many obstructions. High gain antennas do not improve the distance because of the amount of interference due to reflected radio signals. In fact, the reliable operating distance between electric meters, typically installed at no more than 5 feet off the 3

4 ground is approximately 600 to 900 feet due to the presence of buildings, trees, and shrubs. Furthermore, the reliable operating distance can vary from season to season: greater distances in the winter but shorter distances in the spring and summer due to tree foliage. The reliable operating distance increases in cases where the meter communicates with a repeater placed on a utility pole. Tantalus uses unlicensed 900 MHz for communication between individual meters (LAN) and licensed 220 MHz (transmitting data from miles) for communication between collectors and towers (WAN) ZigBee Technology Thus far we have looked at the various available technologies that carry data between the meter and the utility. The next, and perhaps most critical, step in the development of an AMI involves enabling communication between the meter and an in-home display and possibly other devices or appliances in the home, such as an electric water heater, the central air conditioning system, and, in the near future, other appliances. The extension of the AMI into the home adds a Home Area Network component to the system, enabling true two-way communication between the utility and the customer. Although in many cases AMI vendors still utilize proprietary technology to enable the communication between the meter and an in-home display, more are now considering using an open protocol, such as ZigBee, to establish that communication. Several major AMI vendors, such as Itron, Elster, and Landis+Gyr, have demonstrated that they offer meters that are interoperable with the ZigBee protocol. For utilities this has the advantage that the Home Area Network component of an AMI is less of a limiting factor in deciding which vendor to select. Each endpoint or meter will need to include a ZigBee module to enable a Home Area Network component to be included in the AMI. However, the wider use of the open protocol among AMI vendors allows for definitive choices as to what services and devices (i.e. in-home display) will be offered. A utility can equip each endpoint or meter with a ZigBee module but postpone selecting in-home devices until more options become available and prices for these devices come down. The open protocol also makes it easier to market specific devices to residential, commercial or industrial customers. As long as new products and devices use the ZigBee protocol for communication, they can easily be incorporated in an AMI. In the case of proprietary technology, a utility would be dependent on what the specific vendor would offer. An important development at the regulatory level further reinforces the position of ZigBee as the Home Area Network communication protocol of choice. The U.S. Department of Energy recently established an Initial Smart Grid Interoperability Standards Framework [6] to encourage the different vendors that develop Smart Grid products and solutions to develop software and hardware components that will work together seamlessly. In this framework, ZigBee is selected as the standard for Home Area Network device communication. This support for the ZigBee standard by the U.S. Department of Energy will encourage more vendors to develop software and hardware devices and solutions using the protocol and provides important long-term assurance for utilities that selecting ZigBee is a sensible and relatively low risk choice for Home Area Network communication in an AMI. Zigbee is a wireless network standard that is specifically designed to work with sensors and control devices that consume little energy, do not need high bandwidth, and communicate over relative short distances. This technology is based on the IEEE standard for wireless communication, and has a range of typically 50 meters. ZigBee devices operate in the license free 2.4 GHz ISM band. For a utility, the obvious benefit of a wireless connection is that no wires need to be installed between the meter and the in-home device. The in-home device allows the utility to provide the customer with up-to-date electric usage and rate information. Companies such as Comverge and LS Research manufacture ZigBee -compliant in-home devices that are specifically designed to display information from the electric utility. The purpose of all of these devices is to provide information that the customer can use to save energy and lower the monthly electric bill. With pre-arrangement with the customer, they could also be used by the utility to automatically and remotely turn down an air conditioning unit during peak use to lower the overall electric load in order to prevent power blackouts Applications and Functions Utilities do not implement AMI systems to merely automate the process of reading meters. Such systems are simply too expensive to be installed for 4

5 that purpose alone. Automatically reading meters for billing purposes is just one of the many applications or functions that are made available by an AMI. The ability to automatically read meters rather than sending out a meter reader allows a utility to read meters with a much higher frequency. Instead of the usual monthly read, the utility can read meters daily, hourly, or in even smaller intervals. Hourly usage interval data can be used for various applications and functions such as demand response, time-based pricing, and load management. An AMI also supports outage management, remote connect and disconnect, and pre-pay systems. Automated meter reading improves billing accuracy because the actual read can take place on the day that the bill for the customer is generated. Automated meter reading also eliminates the need for estimating usage in cases where the meter reader cannot access the customer s property or meters cannot be read due to adverse weather conditions. Reduction or elimination of estimated bills will improve customer service and reduce related calls to the call center of the utility. An AMI also allows a meter to be read on demand. A customer service representative can use a Customer Information System (CIS) to read a meter while on the phone with a customer. This can be useful when a customer calls to close the account and a bill needs to be prepared so that the customer can immediately pay the final balance. The remote disconnect function will allow the customer service representative to turn of the power at that time as well. Rather than changing the output of a power station, utilities balance the supply of electricity with the demand for electricity, known as Load Management, with the use of Demand Response programs. The objective of these programs is to reduce the demand for power through pricing signals. Using time-of-use pricing, a utility could offer customers a lower rate during off-peak hours and customers could react by doing the laundry in the evening rather than during the day. To prevent blackouts during a hot summer day a utility could motivate customers to turn down their air conditioners by charging a higher rate during the peak hours, using critical-peak-pricing. The in-home device of the AMI makes it possible to inform customers about specific rates and influence behavior. Outage management is in part dependent on customers calling in a power outage. An AMI that provides direct access to the meter and the system can therefore detect power outages at the meter level. The utility does not have to rely on a customer s phone call but can use its Outage Management System (OMS) to pinpoint outages and address them proactively. Knowing the exact location of outages enables the utility to more effectively and efficiently dispatch the line crews and shorten the duration of outages. Access to detailed meter-level outage information is especially important in the event of a large scale outage. It allows for better planning and improved communication to customers and state and local governments. In an AMI system, meters can be equipped with a remote connect/disconnect module. This allows the utility to connect or disconnect the power for a customer from the utility s headquarters. Eliminating the need to send out a crew to the customer s service location to physically connect or disconnect the power results in cost savings in both labor and fuel cost for the utility and it reduces the utility s carbon footprint. Remotely (re-)connecting power will still require a phone call with the customer at the time the power is switched on to avoid inadvertently turning on an appliance or device that could be a safety risk (i.e. the proverbial pizza box left on the stove). Disconnecting and re-connecting a customer is often associated with non-payment of the electric bill. The ability to remotely disconnect a customer does not exempt the utility from following the regulations mandated by a public utilities commission for disconnecting customers for non-payment. Advance notices are still required before power delivery can be discontinued. Additionally, in the state of New Hampshire, customers cannot be disconnected during the winter months [7]. Utilities are increasingly interested in Pre-Pay Systems as more and more electric bills go unpaid [8]. Pre-Pay offers utilities not only another collections tool but it also provides a mechanism for customers to conserve energy. The Salt River Project [9], a utility based in Phoenix, noticed a 12 percent reduction in electric use among its 55,000 pre-pay customers. The in-home device of the AMI informs customers about their energy use as well as their remaining balance. As customers become more aware about their electric use they start to conserve. A Pre- Pay system requires that a remote connect/disconnect module is installed in the meter. 5

6 2. Smart Meter The enabling technology in an AMI is the Smart Meter. The traditional electromechanical meter has evolved into a solid state digital meter that is capable of both receiving and sending data. Other features or functions that are included under the glass are memory modules to store data, error controllers, and an optional remote connect/disconnect module. Either a battery or a capacitor is installed to provide power to the meter while it is not receiving electricity from the distribution line in case of a power outage. 3. Weighing the benefits of AMI for the New Hampshire Electric Cooperative The New Hampshire Electric Cooperative (NHEC) is a member-owned and controlled electric distributor serving approximately 83,800 members in 115 towns and cities. Founded in 1940, with the purpose to bring electricity to rural New Hampshire, the Cooperative maintains roughly 5,500 miles of energized lines that go across nine of the ten counties in New Hampshire. The Cooperative s headquarters is located in Plymouth and it has ten operating districts to serve its members. These districts are Colebrook, Lisbon, Sunapee, Andover, Plymouth, Meredith, Conway, Alton, Ossipee, and Raymond. An elected 11-member Board of Directors runs the cooperative. The Board appoints a President/CEO who oversees the Cooperative s day-to-day operations. The Cooperative employs approximately 200 employees. In 2007 the energy usage totaled 757,906,090 kwh (specifically 455,197,769 kwh for residential members and 302,708,321 kwh for commercial members) with a peak load or demand of 194 MW [10]. Based on the number of members, NHEC is considered a large electric cooperative. The Cooperative s service territory can be characterized as primarily rural and mountainous with pockets of residential areas. The topography of the service territory as well as other characteristics imposed by the natural environment are important, if not critical, factors in the process of determining what AMI technology best fits the cooperative s business requirements and budgetary constraints. The mountainous character of the service territory impedes communication between endpoints, between endpoints and sub-stations, and between substations and the utility s headquarters, increasing the number of repeaters, take-out points, and towers that are needed in a wireless communication scheme. Dense foliage in many areas is another factor that negatively affects wireless communication between devices. The number of customers per mile of power distribution line is significantly less for cooperatively organized utilities than for investor or publiclyowned utilities. Investor and publicly-owned utilities have, on average, 35 and 47 customers per mile of distribution line, respectively, whereas cooperatively organized utilities have on average only seven customers per mile of power line. The distance between single meters in some areas exceeds 700 feet. This is significant in that typical wireless communication between meters does not reach further than 600 feet, up to a maximum, in ideal circumstances, 900 feet. Additional repeaters are needed to carry data from such meters to a take-out point, adding to the cost of the overall system. More towers and repeaters imply higher cost. Additional towers add to the complexity of the implementation of an AMI in that it involves obtaining and leasing the necessary antenna space on existing towers or possibly even building new tower sites. Automated meter reading is of great benefit to the NHEC, particularly during the winter months when adverse weather conditions sometimes make it impossible for meter readers to go out and read meters, forcing the utility to estimate electric usage. Estimated bills often lead to calls from customers with questions as to why the bill is higher than expected. An AMI will greatly reduce or even eliminate the need to estimate electric usage. With automated meter reading, the utility can expect to see a drop in calls to the customer support department related to estimated bills and more accurate billing will lead to increased customer satisfaction. Long-term maintenance of the AMI equipment is a consideration. In a PLC solution, most of the equipment is installed at sub-stations, concentrating maintenance to a limited amount of sites. In a Fixed Wireless Network, the equipment (i.e. repeaters, collectors, and antennas) are installed throughout the utility s service territory. Maintenance can become an issue especially in winter when snow and icy conditions can make it difficult to get to equipment, especially that on towers and mountain tops. 4. Conclusion AMI projects are extremely complex: not only technically, but also from a financial, planning, and organizational point of view. The implementation of 6

7 and AMI touches every aspect of the organization and requires buy-in from all stakeholders. The necessary investments to implement an AMI are significant. This is especially a concern for cooperatively organized utilities that typically have far less revenue per mile of line and likely have higher implementation costs due to the rural characteristics of their service territories. Under the American Recovery and Reinvestment Act of 2009 [11] utilities might, however, be eligible for grants to fund at least part of their AMI projects. A total of $4.5 billion is available for the implementation of a Smart Grid under the Act. The stimulus program allows utilities to receive grant moneys for up to 50 percent of their total project cost. Additionally the Department of Energy increased the maximum grant for Smart Grid investments to $200 million, from $20 million, allowing larger utilities to also profit from the stimulus package. A utility considering the implementation of an AMI system will need to carefully evaluate what cost savings can be achieved by implementing the system in order to offset the long term costs, such as maintenance, licensing, and depreciation. The applications that become available with an AMI, such as load management, demand response, time-basedpricing, pre-pay, and remote connect/disconnect, need to be fully utilized to realize the operating efficiencies and cost savings necessary to justify the investment in an AMI system. Automated meter reading will eliminate the need for meter readers but the reduction in labor cost is less than the annual operating and depreciation cost of an AMI. The possible cost savings gained from remotely connecting or disconnecting power, rather than sending out a crew to the customer, can easily be calculated from historical data. For other applications, the possible cost savings are more difficult to estimate. Additionally, energy savings programs and alternative energy programs, along with some AMI applications, such as time-based pricing and pre-pay, will encourage customers to reduce their electricity use, and consequently reduce a utility s revenue stream in the short term. In the long term, a utility may be able to save by not having to expand capacity or purchase additional power. All departments and divisions of a utility are affected by the implementation of an AMI. For example, reading meters at hourly intervals creates a total of 720 reads per month per customer versus the common single monthly read. For some applications it is suggested to read at 15 minute intervals creating a total of 2880 reads per month per customer. Even for a smaller utility, with 100,000 customers, this translates into several gigabytes of data coming in on a daily basis. All this data must be processed and stored, creating additional need for Information Technology services within the utility in terms of application support, infrastructure and server requirements, and maintenance and backup support. Procedures and processes in departments such as Customer Service Support and Billing will change. The process or procedure for disconnecting and reconnecting a customers power related to bill payment issues or when closing an account will change if remote connect/disconnect is implemented. The implications of remotely disconnecting and connecting power need to be carefully examined and possible regulatory issues need to also be reviewed before a new process can be implemented. The control center of a utility can expect changes in how outages are reported and will need to review how to manage outage reporting at the meter level in existing Outage Management procedures and systems. All these changes will take time to implement and need early buy-in from all stakeholders throughout the utility s organization. The change process starts well before the first Smart Meters are installed. Once the utility has made the decision to implement AMI, the choice of which technology to select remains: Power Line Carrier or Fixed Wireless Network? The industry has experience with Power Line Carrier implementations and in rural service territories this is considered a more reliable option because all meters can be reached. Most of the equipment is at the sub-station, making maintenance easier. However, the fact that Power Line Carrier is slower than wireless solutions and has less available bandwidth to carry data should be an important factor in the decision. There is also the issue whether a Power Line Carrier system will have enough capacity and flexibility to meet the needs of future developments in AMI and Smart Grid technologies. A Fixed Wireless Network solution provides more bandwidth and the communication in such a system is faster than in a Power Line Carrier system, leaving room for growth. AMI and Smart Grid applications and technologies have only just begun to develop. A Fixed Wireless Network places a considerable amount of equipment (repeaters, collectors, antennas, etc.) throughout a utility s service territory. This is a critical factor in rural service territories. A utility will 7

8 have to carefully consider the maintenance effort that is involved to keep all the equipment operational. Additional staff might be needed, partially negating the reduction in labor cost of meter readers. In some cases the decision might be to install a hybrid system: a combination of a Power Line Carrier and a Fixed Wireless Network system, using each specific technology where it best fits the specific service territory characteristics. AMI systems or a Smart Grid provide utilities with exceptional opportunities to operate more efficiently and cost effectively and improve customer service. Each utility will have to consider its territory characteristics, its internal processes, and its customer base in order to make the appropriate decisions. 5. References [1] The Energy Policy Act of 2005, Public Law [2] California Energy Commission, Value of Distribution Automation Applications, April 2007, CED [3] Electric Power Research Institute, Inc., Advanced Metering Infrastructure, April [4] Chartwell, Inc., AMI-Enabled Demand Response, Chartwell, Inc., Atlanta, GA, 2007, pp [5] IEEE Computer Society, (August 31, 2007). IEEE Standard a-2007 [6] U.S. Department of Energy, Locke, Chu Announce Significant Steps in Smart Grid Development, Press Release, May 18, [7] State of New Hampshire Public Utilities Commission, Consumer Rights and Responsibilities, Concord, NH, May [8] Wall Street Journal, More Utility Bills Go Unpaid, November 3, [9] Wall Street Journal, New Ways to Monitor Your Energy Use, June 19, [10] retrieved June 13, 2009 [11] The American Recovery and Reinvestment Act of 2009, Public Law